TIDMVGAS
RNS Number : 4487B
Volga Gas PLC
04 April 2017
4 April 2017
VOLGA GAS PLC
Preliminary results for the year ended 31 December 2016
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, is pleased to announce its preliminary unaudited
annual results for the year ended 31 December 2016.
During 2016, the Group's operational and financial performance
dramatically improved in comparison with 2015, nearly doubling its
oil, gas and condensate production and revenues while achieving a
return to profitability and a significant strengthening of its
financial position. While the recovery in oil prices and the
Russian Ruble during 2016 were clearly beneficial, the main driver
was in the performance of the Group's assets. In addition, the
commencement of exports of condensate enabled production to
continue uninterrupted through the year.
The successful drilling on the Vostochny Makarovskoye field in
2015 and the workovers on the Uzen oil field early in 2016 allowed
average production from the Group's fields to rise by 99% to 6,507
barrels of oil equivalent per day ("boepd") (2015: 3,278 boepd),
while in December 2016 total production averaged 8,060 boepd.
FINANCIAL RESULTS
-- Gross revenues up 122% to US$39.4 million (2015: US$17.8 million).
-- Netback revenues (after export taxes and transport costs)
were up 102% to US$35.4 million (2015: 17.5 million).
-- Ten-fold increase in EBITDA to US$9.6 million (2015: US$0.9 million).
-- Profit before tax of US$1.9 million (2015: loss of US$4.6
million), after abnormal operating expenses of US$1.8 million
(2015: 3.4 million)
-- Net cash flow from operations of US$13.0 million (2015: US$1.2 million).
-- Total cash, net of borrowings, rose to US$15.8 million as at
31 December 2016 (31 December 2015: US$6.8 million) after utilising
US$4.6 million for capital expenditure (2015: US$8.7 million).
Total borrowings, comprising bank debt, at 31 December 2016 were
US$3.9 million (2015: nil).
-- Resuming distributions to shareholders with a total of
US$0.062 per share of dividends proposed.
PRODUCTION & DEVELOPMENT
-- Group average production in 2016 increased 99% to 6,507 boepd
(2015: 3,278 boepd) and the average rate for December 2016 was a
record, since surpassed in 2017, of 8,060 boepd.
-- Production from VM and Dobrinskoye fields doubled to 5,801
boepd in 2016 (2015: 2,876 boepd). Increased well capacity
following successful development drilling and largely uninterrupted
production were the key drivers.
-- During 2016 48% of condensate sales were exported (2015: 2%),
an initiative started at the end of 2015. While the netback was
less than for domestic sales as a result of having to cover export
taxes and transportation costs, this strategy has enabled
production to continue during periods when the local market is less
active.
-- Successful workovers and the installation of submersible
pumps in the Uzen field enabled a 69% increase in production from
the mature Uzen field to 706 bopd (2015: 418 bopd)
DOBRINSKOYE GAS PLANT
-- Following the completion of the final stages of the upgrade
project, the normal throughput levels of the Dobrinskoye gas plant
was increased in mid 2016 from 750,000 m(3) /d (26.5 mmcf/d) to 1
million m(3) /d (35.3 mmcf/d).
-- Progress has been made for significant reductions in costs by
adopting new gas sweetening processes and more efficient disposal
of waste materials.
-- Completed plans for LPG extraction. Construction of the LPG
modules is to commence in mid-2017.
CURRENT TRADING AND OUTLOOK
-- Since January 2017, normal production has been sustained at
higher levels. During January and February 2017, production
averaged, over 8,100 boepd. However, during March 2017 production
was impacted by planned gas plant maintenance and seasonal
disruption to oil deliveries so the average for January to March
2017 was 7,245 boepd.
-- Oil prices and the Russian Ruble have been relatively stable
during the first three months of 2017. In the current environment,
the Group expects to improve on the financial performance of
2016.
-- With two significant revenue-enhancing projects planned for
2017: the LPG unit at the gas processing plant and the Uzen
horizontal well, capital expenditure in 2017 is expected to total
US$12.3 million and will be key drivers for production growth in
2017.
-- Recently completed independent reserve report confirmed a
2.4% increase in Proved and Probable reserves but a 10.8% reduction
in Proved reserves.
Andrey Zozulya, Chief Executive of Volga Gas, commented:
"We have been really pleased with the sound performance of Volga
Gas main producing assets in 2016 and with the solid improvements
in the financial performance and position of the Group. Management
looks forward to delivering higher production in 2017 than in 2016
and to achieving our targets to improve the profitability and
sustainability of our business for the longer term and to
delivering growing returns for our shareholders.
"I remain 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 to seek value accretive
opportunities, beyond our existing licence areas, building a
focused exploration and production business."
For additional information please contact:
Volga Gas plc
+7 (903) 385
9889
Andrey Zozulya, Chief Executive +7 (905) 381
Officer 4377
Vadim Son, Chief Financial Officer +44 (0)7824
Tony Alves, Investor Relations Consultant 884 342
+44 (0)20 3470
S.P. Angel Corporate Finance LLP 0470
Richard Redmayne, Richard Morrison,
Richard Hail
+44 (0)20 3727
FTI Consulting 1000
Edward Westropp, 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 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, 40 Dukes Place, London EC3A 7NH. 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,
In spite of continuing challenging conditions experienced by the
oil and gas industry worldwide and for Russia generally, 2016 has
been a successful year for Volga Gas. Production has recovered from
the reverses seen in 2015 and has been at the highest rate in the
Group's ten year history. Revenues have more than doubled compared
to 2015 and underlying profitability has been restored. Oil prices,
that started 2016 at levels not seen for over 10 years have
recovered substantially, doubling from the low point seen in
January. The Russian Ruble has also had a similar though less
marked recovery against the US dollar.
On an operational level, the results of 2016 were better than
anticipated by management. Having successfully concluded the
development drilling on the Vostochny Makarovskoye ("VM") field in
2015, this field, the Group's principal producing asset, has been
operating at close to the planned plateau production rate of one
million cubic metres per day of gas plus associated condensate for
most of the second half of 2016. This production is the core of
stable production which provides the main cash generation engine
for the Group. In addition, workover activity conducted during
early 2016 enabled a significant recovery in oil production from
the Uzen oil field such that the production rate in 2016 was more
than twice the level budgeted by management at the start of the
year, even though the contribution to the Group's total output from
this field is modest.
The results of 2016 have also been enhanced by some important
commercial initiatives undertaken by management, notably the
commencement of export sales of condensate, and more recently of
some oil, to customers in the Baltic states neighbouring Russia.
While the netback realisations on export sales, after taking into
account export taxes and transport costs are slightly lower than
for domestic sales, exports have enabled production to be
maintained during periods in which the local domestic market is
less active. There have also been several cost reduction
initiatives, individually not significant, but which have enabled
overall production costs to be lower than budgeted.
As a result of these developments, profitability and cash
generation has increased materially during 2016.
Capital expenditure in 2016 has been modest as the Board decided
to restrain spending while the oil price was low as it was at the
start of the year. Such expenditure that has been undertaken was
directed towards maintenance of the core assets and to projects
able to provide immediate enhancements to the profitability.
Consequently the net cash position has increased by US$9.7 million
since the start of 2016.
The key strategic development under way is the 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. While these projects were first considered in 2015,
further work undertaken in 2016 has enabled modifications to the
plans which will enable the same results to be delivered at
significantly lower capital expenditure than originally
contemplated. The Chief Executive's Report covers both the work
undertaken during the year on this and the plans to be implemented
in 2017.
While the immediate outlook is more positive than it was a year
ago, the finances of the Group will continue to be conservatively
managed. Capital investment will continue to be at a modest level
and focused on enhancing the profits from the gas and condensate
production and on developing the proven oil reserves of the
company.
The Group holds significant reserves in its three principal
fields, confirmed in the recently completed independent report
detailed below in the Operational Review by our Chief Executive
Officer. 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. Meanwhile, in recognition of the strong financial
position of the Group and the confidence in the continued and
sustainable profitability, the Board has decided to resume payment
of dividends to shareholders. The Board is recommending total
dividends of US$0.062per Ordinary Share, comprising US$0.007 per
ordinary share in respect of the profits generated in the year
ended 31 December 2016 and a special dividend of US$0.055 per
ordinary share.
Mikhail Ivanov
Chairman
Chief Executive's Report
As the Chairman has noted, Volga Gas achieved a significant
improvement in its operational and financial performances in 2016
compared to 2015 with overall production increased by 99%, revenues
up by 121% in US dollar terms and a return to profitability. Some
of this was a result of the recovery in oil prices that took place
steadily through the year, but much of this was as a result of the
successful drilling and well workover activity that took place
during 2015 and early in 2016, as well as the efficiency
improvements implemented early in 2016.
The main driver of the performance was the Vostochny
Makarovskoye ("VM") field on which we successfully concluded
development drilling towards the end of 2015. With the necessary
well capacity available through the year and having completed the
required upgrades to the gas plant, we were able to produce at the
full plateau rate of 1 million m(3) per day (35.3 mmcf/d) of gas
plus associated condensate for much of the second half of 2016 -
apart from periods of planned plant maintenance and for testing of
potential new gas sweetening processes, described further
below.
Another important factor in the production performance of 2016
was the commencement of exports of condensate. During 2015, there
were periods in which the regional domestic market was unable to
take our condensate leading to shut-ins at various periods. With
the development of export channels, such market disruptions as
occurred during 2016 had little or no impact on our ability to
continue to sell condensate and therefore keep production going for
the full year.
Another factor in the Group's overall production in 2016 was the
recovery in oil production from the mature Uzenskoye field.
Workovers on existing producing wells done in April and May 2016
led to a 160% increase in daily production rates from this field.
Although this was still a minor part of the Group total, it made a
useful contribution to the profit recovery of the Group.
In line with the Board's financial strategy at the start of
2016, committed capital investment was kept to the minimum levels
in 2016. Nevertheless, the technical teams continued to work on
projects that are expected to have material positive impact on the
short and medium term performance of Volga Gas. These include new
wells on the Uzenskoye field to develop the proven but undeveloped
Albian reservoir in the field and projects that would significantly
improve the output and efficiency of the Dobrinskoye gas processing
plant and with significant reductions in the required capital
expenditure compared to earlier proposals.
2017 objectives and medium term strategy
Management has three key objectives in 2017 relating to the
operation of the Gas Processing Plant:
-- Introduction of a new gas sweetening process using the Redox
process. It is expected that this can be achieved with only minor
modifications to the existing process plant. This should lead to a
significant reduction in the cost of chemicals consumed in the gas
sweetening process and elimination of bulk waste which needs to be
disposed of safely.
-- Construction of additional modules for the capture, storage
and sale of liquid petroleum gases ("LPGs") from the gas and
condensate streams produced from the VM and Dobrinskoye fields.
LPGs, primarily comprising propane and butane, are currently either
included in the sales gas stream or flared. The LPG project will
provide an additional product stream which is expected to increase
total sales volumes by approximately 10% and to enhance
profitability. The construction of the project is expected, subject
to the necessary regulatory approvals, to commence during 2Q 2017
and be completed before the end of 2017. The capital investment in
the project is estimated at US$4.0 million.
-- Disposal of accumulated waste chemicals resulting from the
current gas sweetening process. During 2016 a pilot project for
disposal by injection into a disused gas well was undertaken.
Management expects to receive regulatory approval for this
operation to be undertaken for the waste accumulated on-site.
The other key objective for management in 2017 is the
development of the currently undeveloped crude oil reserves in the
shallow Albian reservoir in the Uzen oil field. A first horizontal
well is to be drilled on the field during 2017. If successful,
further wells may be drilled. The horizontal wells are expected to
add up to 1,000 barrels per day of incremental oil production and
to produce over 2 million barrels of oil over their economic
lives.
Reserves update
A new independent reserve report has recently been completed.
While the new reserve estimates result in a net reduction in Proved
Reserves, there was an overall increase in Proven and Probable
Reserves. Details are contained in the Operational Review
below.
Current trading and outlook
Between January and March 2017, Group production averaged 7,245
barrels of oil equivalent per day, in line with management's plan.
Production in March 2017 was impacted by planned maintenance and
seasonal disruptions, after averaging over 8,100 boepd in January
and February 2017. The gas plant is consistently operating at
planned capacity of one million m(3) per day, with condensate
output running at over 2,000 barrels per day, approximately half of
which is being sold to export markets. International oil prices
have maintained their higher levels reached in December 2016. Oil
production is now a minor part of the Group's output and has
suffered moderate disruption as the mild winter caused difficulties
in collection of oil by our customers.
In the current environment, and at current production rates,
management expects the Group's financial performance in 2017 to
improve further on that of 2016. Meanwhile, new capital expenditure
commitments remain within projected cash generation, permitting a
resumption of a sustainable distribution policy for
shareholders.
Andrey Zozulya
Chief Executive Officer
Operational Review
Operations overview
Group production in 2016, at an average daily rate of 6,507
boepd, was 99% higher than the 3,278 boepd achieved in 2015. Three
were three reasons for this: higher production capacity from the VM
field on which the new wells were put on production at the end of
2015, commencement of condensate exports which allowed production
to remain uninterrupted during periods when the local domestic
market was disrupted and, less materially but also positive, the
recovery in oil production from the Uzen oil field.
Combined with a steady recovery in oil prices through the year
and a rebound in the Ruble, netback revenues in US dollar terms
increased by 102% compared to 2015, taking into account the export
taxes and transportation costs associated with the exports of
condensate. In addition, as a result of more accurate fiscal
metering introduced at the start of 2016, the formula for
calculating Mineral Extraction Tax charged on gas and condensate
was reduced. This combined with various cost reduction measures
contributed in a near 10-fold increase in EBITDA, which was US$9.6
million in 2016 compared to US$0.9 million in 2015 and enabled the
Group to report a profit before tax of US$1.9 million (2015: loss
before tax of US$4.6 million).
In addition to managing higher levels of production, much of the
operational activity in 2016 was directed towards further
enhancements to the gas plant processes, sustaining higher output
from the gas and condensate fields and drilling of new horizontal
wells on the Uzen oil field.
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. During 2015 two production wells on the VM field, VM#3 and
VM#4 were drilled. VM#4 was put on production during November 2015
while the completion and first production from the VM#3 well was
deferred until spring of 2016 when the gas plant upgrades enabled
the higher throughput rates to utilise its full capacity.
With a total of four wells in the principal reservoir, the
Evlano Livinskiy carbonate, and a further well in the secondary
Bobrikovskiy sandstone reservoir, management considers the VM field
to be fully developed and capable of producing at the plateau rate
of 1.0 mmcm/d (35.3 mmcf/d) with associated condensate of 2,000 bpd
- a total of approximately 7,800 boepd.
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.) At the end
of 2015, however, Volga Gas commenced export sales of condensate
and with this channel available it was possible to continue
production steadily throughout 2016 in spite of similar market
disruptions being experienced.
Production during 2016 averaged 25.5 mmcf/d of gas and 1,557 bpd
of condensate (2015: 12.5 mmcf/d of gas and 784 bpd condensate) and
overall increase of 103% in equivalent barrels of oil terms.
Nevertheless, this production rate is below the full capacity of
the existing wells as the gas processing plant's operations
continue to be fine-tuned. This is covered in more detail below.
However, during December 2016, the output averaged 32.2 mmcf/d of
gas and 1,799 bpd of condensate, a total of 7,167 boepd, more
closely reflecting management's estimate of the actual capabilities
of the wells.
During 2016, gas continued to be sold to Trans Nafta under
contract at a fixed Ruble contract gas sales price of RUR 4,201 per
mcm which has been in force since July 2015. However, as of
December 2016, a proportion of the gas sales have been made
directly to Gazprom which has resulted in a modest increase in the
net realisations. In US dollar terms, however, the recovery of the
Ruble has led to the gas sales price rising from US$1.29/mcf in
January to US$1.68/mcf in December. The average gas selling price
for 2016 was US$1.51/mcf (2015: US$1.49).
Prior to late 2015 condensate was sold entirely into the local
domestic market. However, with the periods of low domestic demand
which impacted our business during 2015, channels for exporting
condensate were developed and the first cargoes of condensate were
sold to export customers in the Baltic region during November and
December 2015. During 2016 approximately 48% of total sales of
condensate were to export customers (2015: 2%).
During 2016 the average condensate netback price (after
accounting for export taxes and transportation costs) US$24.83 per
barrel (2015: US$23.89).
Average unit production costs on the gas-condensate fields
increased moderately to US$5.19 per boe in 2016 (2015: US$5.06).
The recovery in the Ruble, in which effectively all the costs are
denominated and higher costs associated with chemicals consumed in
gas processing and higher costs of waste disposal were partly
offset by other cost savings.
Gas processing plant
During the first half of 2016, the Dobrinskoye gas processing
plant was consistently operating at average rates of 750,000 m(3)
per day (26.5 million cubic feet per day). Since August 2016, the
flow rates from the gas fields were increased to test the
capability of the plant to process at the planned higher rate of
one million m(3) /day (35.3 mmcf/d). As a result, management is
confident that the gas plant is capable of sustained throughput at
the rate of 35.3 mmcf/d. This was actually achieved in the month of
December 2016.
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 remains a constraint on the
operations.
During 2016, technical studies and tests were conducted of
alternative sweetening chemical processes. As a result of these
tests, management has decided that a switch to Redox based gas
sweetening would be the optimal solution for the gas plant. The key
advantage of this process is that the chemical used can be easily
re-generated and re-used resulting in significantly lower chemicals
costs and eliminating much of the bulk waste materials. The
existing process units can be used for this with only minor
modification. Full scale trials, of the Redox-based sweetening
process are continuing through April 2017.
As announced on 29 November 2016, the Board has given
preliminary authorisation to a project based at the Group's
Dobrinskoye Gas Processing plant for the capture, storage and sale
of LPG. LPGs, primarily comprising propane and butane, are
currently either included in the sales gas stream or flared.
The LPG project will provide an additional product stream which
is expected to increase total sales volumes by approximately 10%
and to enhance profitability.
The construction of the project is expected, subject to the
necessary regulatory approvals, to commence during 2Q 2017 and be
completed before the end of 2017. The total capital investment in
the project is estimated at US$5.0 million.
Oil production
The Uzen oil field has been producing oil from a cretaceous
Aptian reservoir at a depth of approximately 1,000 metres since
2009. Until 2016 it produced under natural reservoir pressure
drive. As the oil was produced, the oil-water contact in the
reservoir rose and the wells at the edge of the field were shut in
as water cut increased. Consequently by the start of 2016,
production had declined to 300 bopd from three wells. During H1
2016 workovers were conducted on the producing wells to block off
water inflow into the well bores and to install electrical
submersible pumps to provide artificial lift on the wells. As a
result of these activities, the ongoing oil production rate
increased from approximately 450 bpd to over 850 bpd and these
rates were sustained through the rest of 2016.
During November and December 2016, a sidetrack from the
currently non-producing Uzen #4 well was being drilled with the
intention of producing oil from a potentially bypassed "attic" in
the Aptian reservoir. However, during the drilling of a deviated
section from the existing vertical well, the drill bit and certain
directional drilling tools supplied by Schlumberger became stuck in
the well, as a result of a faulty pump interrupting drilling mud
circulation. Various attempts were made to release the stuck drill
bit but without success. Consequently the operation was suspended.
Given the attractiveness of accessing incremental reserves in a
side track well, Volga Gas will recommence drilling a sidetrack
having appointed a new drilling contractor.
Volga Gas has, however, incurred costs of US$1.6 million
primarily for replacement of the directional drilling tools
belonging to Schlumberger.
There remain significant proved undeveloped reserves in the
shallower Albian reservoir. Following a technical study carried out
during 2015, management recommended a development plan for this
reservoir would be to drill up to 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 of $4.00 per barrel of reserves. The
first horizontal well is to commence drilling as soon as Eurasia
Drilling, the newly appointed contractor, has mobilised its rig
onto the prepared location.
The Group's oil production, whilst of modest scale, has been
very profitable for the Group and a useful contributor of cash
flow. With successful development of the Albian reserves, this
would become a more important contributor to future
profitability.
Exploration
During 2016, as a result of the decision to minimise
expenditures, exploration activity was confined to internal
technical studies.
Nevertheless, 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. While
management recognises the potential of these prospects, the
immediate priority is to maximise the value and cash generation
from proven resources.
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 2017
In December 2016, Volga Gas commissioned an independent
evaluation of the Group's oil, gas and condensate reserves. This
has resulted in an overall reduction of Proved Reserves of 3.7
mmboe, or 10.8%, but an overall increase of 0.9 mmboe in Proved and
Probable ("2P") Reserves, a 2.4% increase.
The principal changes to the reserve estimates arose from a
downgrade in reserves from the Dobrinskoye field, accounting for a
3.5 mmboe reduction in Proved Reserves and of 2.7 mmboe in 2P
Reserves. This was offset by increases in reserves at the Uzen
field by 2.3 million barrels of Proved and 1.7 million barrels of
2P Reserves. On the VM field, there was a reduction of 2.8 mmboe in
Proved Reserves but a net increase of 1.7 mmboe in 2P Reserves,
reflecting a more conservative basis of estimation. Within the VM
reserves, a proportion of gas reserves have been reclassified as
LPG to reflect the fact that when LPG extraction takes place a
proportion of gas currently sold down the pipeline will be
converted into LPG.
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 31 December 2016, 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 at
31 December 2016 and changes from previous estimates.
Andrey Zozulya
Chief Executive Officer
Oil, gas and condensate reserves
Oil & Gas LPG Total
Condensate (tonnes)
(mmbbl) (bcf) (000) (mmboe)
------------------------- ------------ ------- ---------- --------
As at 31 December 2015
Proved reserves 12.989 142.6 - 36.698
Proved plus probable
reserves 14.293 153.5 - 39.879
------------------------- ------------ ------- ---------- --------
Production: 1 January
-31 December 2016 0.828 9.3 - 2.382
Revisions to estimates:
Proved reserves (1.210) (34.8) 277 (3.697)
Proved plus probable
reserves (1.312) (12.7) 367 0.908
As at 31 December 2016
Proved reserves 10.951 98.5 277 30.619
Proved plus probable
reserves 12.153 131.5 367 38.405
------------------------- ------------ ------- ---------- --------
Notes:
1. Volga Gas (through its wholly owned subsidiaries PGK and GNS)
is the operator and has a 100% interest in four licences to explore
for and produce oil, gas and condensate in the Volga region.
2. The reserve estimates as at 31 December 2016 were
independently assessed by OOO Geostream Assets Management. The full
reserve report is available on the Company's website:
www.volgagas.com. The estimates at 31 December 2015 were based on
the reserve evaluation conducted by Miller and Lents in 2012
adjusted for subsequent production.
3. 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.
4. 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
In 2016, the Group generated US$39.4 million in turnover (2015:
US$17.8 million) from the sale of 837,837 barrels of crude oil and
condensate (2015: 438,910 barrels) and 9,210 million cubic feet of
natural gas (2015: 4,545 million cubic feet).
The average price realised for liquids sold in the domestic
market was the equivalent of US$30.59 per barrel (2015: US$25.16
per barrel). During 2016, approximately 48% of condensate sales
were to export customers in the Baltic States (2015: 2%). Export
sales incur export taxes and transportation costs, whereas for
domestic sales the selling price is effectively a wellhead netback
price. The average netback price for liquids sales, calculated by
deducting selling expenses from revenue attributed to oil and
condensate sales, in 2016 was US$25.70 (2015: US$24.43).
The gas sales price during 2016 averaged US$1.51 per thousand
cubic feet (2015: US$1.49 per thousand cubic feet), the increase
being entirely attributable to the movement in the Ruble/US dollar
exchange rate. The sales price of gas in Rubles was unchanged in
2016 (increased by 8.1% in July 2015), although in December 2016
the company commenced sales directly to Gazprom which resulted in a
small increase in realised price. Production activities generated a
gross profit of US$13.1 million in 2016 (2015: US$2.2 million).
In 2016, the total cost of production increased to US$11.0
million (2015: US$7.4 million), with variable costs driven by
higher production volumes, some Ruble inflation and the effect of
the recovery in the Ruble on our predominantly Ruble denominated
costs. Unit field operating costs fell to US$3.93 per boe (2015:
US$5.03 per boe), partly as a result of fixed costs shared among
higher volumes and partly from cost efficiencies. Production based
taxes were US$10.3 million (2015: US$5.9 million) reflecting higher
volumes and the impact of oil prices and Ruble exchange rates on
Mineral Extraction Tax ("MET") rates as well as the impact of
further formula changes that came into effect on 1 January 2016.
More accurate metering of unstabilised condensate enabled a
relative reduction of volumes taxed. MET paid in 2016 represented
29% of netback revenues (2015: 35% of revenues).
Operating and administrative expenses in 2016 were US$4.5
million (2014: US$3.4 million).
The Group experienced a ten-fold increase in EBITDA (defined as
operating profit before non-cash charges, including exploration
expense, depletion and depreciation) to US$9.6 million (2015:
US$0.9 million).
Since the Group uses Proved reserves as a basis of calculation
of the annual depletion charge, the unit rate of Depletion,
Depreciation and Amortisation ("DD&A") increased as a result of
the 10.8% reduction in Proved reserves. This combined with the 99%
increase in production led to a DD&A charge in 2016 of US$5.0
million (2015: US$2.4 million).
With exploration and evaluation expenses of US$0.3 million in
2016 (2015: US$0.6 million) and a provision of US$1.8 million for
the write off of development assets, mainly arising from
compensation payable in relation to the stuck hole in the Uzen#4
sidetrack (2015: US$3.0 million) the Group recorded an operating
profit for 2016 of US$2.5 million (2015: operating loss of US$5.0
million).
Including net interest income of US$0.2 million (2015: US$0.1
million) and other net losses of US$0.8 million (2015: net gain of
US$0.3 million), the Group recognised a profit before tax of US$1.9
million (2015: loss before tax of US$4.6 million) and reported net
profit after tax of US$1.2 million (2015: net loss after tax of
US$4.1 million) after a deferred tax charge of US$0.7 million
(2014: deferred tax credit of US$0.6 million).
Cash flow
Group cash flow from operating activities was US$10.4 million
(2015: US$1.2 million). Net working capital movements contributed
cash inflow of US$2.7 million in 2016 (2015: US$0.8 million), which
included movements in prepayments of US$1.9 million from export
customers (2015: US$0.9 million). With lower capital expenditures
in 2016, the net outflow from investing activities was US$4.6
million (2015: US$8.7 million). Net cash inflow from financing
activities was US$3.6 million (2015: outflow of US$1.0
million).
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, no
dividends were paid in 2016. However, in recognition of the
recovery in profitability and the financial position of the Group,
the Board considers it an appropriate time to resume distributions.
Consequently the Board is recommending a dividend of US$0.062 per
ordinary Share in respect of 2016 and in addition a special
dividend of US$0.055 per ordinary share, subject to approval at the
Annual General Meeting on 9 June 2017.
Capital expenditure
During 2016 capital expenditure of US$4.2 million was incurred
(2015: US$10.4 million), of which US$3.9 million was incurred on
development and producing assets (2015: US$9.8 million) and US$0.3
million incurred on exploration (2015: US$0.6 million). Capital
expenditure in 2016 includes final payments for drilling on the VM
field, drilling and workovers on the Uzen oil field and upgrades to
the gas processing plant.
Balance sheet and financing
As at 31 December 2016, the Group held cash and bank deposits of
US$19.7 million (2015: US$6.8 million). 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.
In December 2016, the Group drew down from a RUR 240 million
(US$4.0 million) of bank facility, which is to be utilised to fund
purchases of equipment for the LPG project. Total debt as at 31
December 2016 was US$4.0 million (2015: nil).
As at 31 December 2016, the Group's intangible assets increased
to US$3.5 million (2015: US$2.9 million). Property, plant and
equipment, increased to US$55.9 million (2015: US$48.3 million),
primarily reflecting the impact of foreign exchange adjustments.
The carrying values 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.
For the year ending 31 December 2016, the Group recorded a
currency retranslation income of US$10.5 million (2015: expense of
US$15.3 million) in its Other comprehensive income, relating to the
movement of the Ruble against the US Dollar.
The Group's committed capital expenditures are less than
expected cash flow from operations and cash-on-hand and such
expenditures can be managed in light of the volatility in
international oil prices and the Ruble. The Group may consider
additional debt facilities to fund the longer-term development of
its existing licences and operational facilities as
appropriate.
The Group's financial statements are presented on a going
concern basis.
Vadim Son
Chief Financial Officer
Five year financial and operational summary
Sales volumes 2016 2015 2014 2013 2012
--------------------------- ------------ ------------ ------------ ------------ -------------
Oil & condensate
(barrels '000) 828 439 604 547 530
Gas (mcf) 9,320 4,545 5,671 3,128 1,193
Total (boe '000) 2,381 1,196 1,549 1,068 728
Operating Results 2016 2015 2014 2013 2012
(US$ 000)
--------------------------- ------------ ------------ ------------ ------------ -------------
Oil and condensate
sales 25,380 11,041 27,220 26,067 25,526
Gas sales 14,032 6,786 12,203 8,554 2,769
------------ ------------ ------------ ------------ -------------
Revenue 39,412 17,827 39,423 34,621 28,295
Field operating
costs (9,367) (6,016) (7,805) (5,946) (3,776)
Production based
taxes (10,255) (5,877) (8,344) (8,095) (8,951)
Depletion, depreciation
and amortisation (5,037) (2,345) (4,656) (2,611) (2,280)
Other production
expenses (1,601) (1,352) (1,709) (1,799) (1,562)
------------ ------------ ------------ ------------ -------------
Cost of sales (26,260) (15,589) (22,514) (18,451) (16,569)
Gross profit 13,152 2,238 16,909 16,170 11,726
Selling expenses (4,052) (319) - - -
Exploration expense (265) (635) - (2,519) (8,475)
Write-off of development
assets (1,798) (2,950) - (1,439) (188)
Operating, administrative
& other expenses (4,526) (3,377) (4,157) (4,029) (8,969)
------------ ------------ ------------ ------------ -------------
Operating profit/(loss) 2,511 (5,043) 12,752 8,183 (5,906)
Net realisation 2016 2015 2014 2013 2012
--------------------------- ------------ ------------ ------------ ------------ -------------
Oil & condensate
(US$/barrel) 30.65 25.16 45.07 47.63 48.21
Oil & condensate
netback (US$/barrel) 25.76 24.43 - - -
Gas (US$/mcf) 1.51 1.49 2.15 2.73 2.32
Operating data 2015 2014 2013 2012
(US$/boe) 2016
--------------------------- ------------ ------------ ------------ ------------ -------------
Production and
selling costs 3.93 5.03 5.04 5.56 5.18
Production based
taxes 4.31 4.91 5.39 7.58 12.29
Depletion, depreciation
and other 2.12 1.98 3.01 2.44 3.13
EBITDA calculation 2015 2014 2013 2012
(US$ 000) 2016
--------------------------- ------------ ------------ ------------ ------------ -------------
Operating profit/(loss) 2,511 (5,043) 12,752 8,183 (5,906)
Exploration expense 265 635 - 2,519 8,475
DD&A and other
non-cash expense 6,857 5,319 4,656 4,050 5,413
------------ ------------ ------------ ------------ -------------
EBITDA 9,634 911 17,408 14,752 7,982
EBITDA per boe 4.05 0.76 11.24 13.81 10.96
Netback realisation for oil and condensate is calculated by
deducting Selling expenses from Oil, gas and condensate sales.
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.
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.
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. Since November 2015, the Group has
been selling up to 50% of its 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. In December 2016, the Group commenced sales of gas
directly to Gazprom. 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.
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 and in 2016 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.
In December 2016, the Group commissioned a reserve evaluation
based on reporting standards set by the Society of Petroleum
Engineers. The revisions to the Group's reserve estimates are shown
in the Operational Review on pages 7 and 8. 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 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, including waste materials
generated by the sweetening process currently 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 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 expense 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, 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.
-- The imposition of sanctions upon certain entities in
Russia.
The Group's operations and financial management have not to date
been impacted directly by any sanctions.
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 2016 the Group had US$19.7 million (2015: US$6.8
million) of cash and cash equivalents of which US$16.1 million was
held in bank accounts in Russia (2015: $2.0 million). A significant
proportion of the cash held in Russia is expected to be placed in
the UK during 2017 ahead of proposed dividend payments. As at 31
December 2016, total bank debt was US$4.0 million (2015: nil). The
Group has fully drawn on the debt facilities available as at 31
December 2016. 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 2016 the Group has
budgeted capital expenditures US$12.3 million of which US$4.0
million is allocated to the LPG project and US$5.7 million is for
the Uzen horizontal well. There were approximately US$4.9 million
of accounts payable relating to capital expenditures and other
expenses incurred in the year ended 31 December 2016 (2015: US$1.5
million). The Board considers that the Group will have sufficient
liquidity to meet its obligations after payment of proposed
dividends of US$5.0 million. All current and planned capital
expenditures are discretionary and may be deferred or cancelled in
the light of the Group's cash generation and liquidity
position.
Through its ordinary course activities, the Group is exposed to
legal, operational and development risk that could delay growth in
its cash generation from operations or may require additional
capital investment that could place increased burden on the Group's
available financial resources.
The Group is also exposed to fraudulent transfers of funds from
its bank accounts. During the year ended 31 December 2015, the
Group enhanced its protections and procedures after suffering such
fraudulent transfers.
Capital risk
The Group manages capital to ensure that it is able to continue
as a going concern whilst maximising the return to shareholders.
The Group is not subject to any externally imposed capital
requirements. The Board regularly monitors the future capital
requirements of the Group, particularly in respect of its ongoing
development programme. Management expects that the cash generated
by the operating fields will be sufficient to sustain the Group's
operations and committed capital investment for the foreseeable
future and has a policy of maintaining a minimum level of liquidity
to cover forward obligations. Further short-term debt facilities
may be arranged to provide financial headroom for future
development activities.
Vadim Son
Chief Financial Officer
Abbreviated Financial Statements
for the year ended 31 December 2016
Group Income Statement
(presented in US$ 000)
Year ended 31 December Notes 2016 2015
Revenue 4 39,412 17,827
Cost of sales 5 (26,260) (15,589)
------------- -----------------
Gross profit 13,152 2,238
Selling expenses 5(a) (4,052) (319)
Operating and administrative
expenses 5 (4,526) (3,377)
Exploration and evaluation
expense (265) (635)
Write off of development
assets 5(b) (1,798) (2,950)
------------- -----------------
Operating profit/(loss) 2,511 (5,043)
Interest income 183 117
Interest expense (3) -
Other gains and losses -
net 6 (763) 306
------------- -----------------
Profit/(loss) for the year
before tax 1,928 (4,620)
Deferred income tax (739) 559
Current income tax (2) (3)
------------- -----------------
Profit/(loss) for the year
before 1,187 (4,064)
Basic and diluted profit/(loss)
per share (in US Dollars) 0.0146 (0.050)
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 2016 2015
Profit/(loss) for the year attributable
to equity shareholders of the
Company 1,187 (4,064)
Other comprehensive income items
that may be reclassified to profit
and loss:
Currency translation differences 10,495 (15,301)
Total comprehensive (expense)
for the year 11,682 (19,365)
Attributable to:
The owners of the Parent Company 11,682 (19,365)
Group Balance Sheet
(presented in US$ 000)
At 31 December Notes 2016 2015
ASSETS
Non-current assets
Intangible assets 7 3,460 2,867
Property, plant and equipment 8 55,908 48,290
Other non-current assets 4 155
Deferred tax assets 1,536 1,098
------------- -------------
Total non-current assets 60,908 52,410
Current assets
Cash and cash equivalents 9 19,718 6,769
Inventories 10 981 1,067
Other receivables 11 3,007 1,449
------------- -------------
Total current assets 23,706 9,285
Total assets 84,614 61,695
============= =============
EQUITY AND LIABILITIES
Equity
Share capital 1,485 1,485
Share premium (net of issue - -
costs)
Other reserves (75,622) (86,117)
Accumulated profits 141,224 140,037
------------- -------------
Equity attributable to the
shareholders of the parent 67,087 55,405
Non-current liabilities
Asset retirement obligation 175 146
Deferred tax liabilities 3,429 1,995
Bank loan 13 3,802 -
------------- -------------
Total non-current liabilities 7,406 2,141
Current liabilities
Bank loan 13 158 -
Trade and other payables 12 9,963 4,149
------------- -------------
Total current liabilities 10,121 4,149
Total equity and liabilities 84,614 61,695
============= =============
Group Cash Flow Statements
(presented in US$ 000)
Year ended 31 December Notes 2016 2015
Profit/(loss) for the year
before tax 1,928 (4,620)
Adjustments to profit/(loss)
before tax:
Depreciation 5,060 2,369
E & E expense 265 635
Write off of development
assets 1,749 2,950
Inventory write-off 536 -
Foreign exchange differences 892 (942)
------------ -------------
Operating cash flow prior
to working capital 10,430 392
Working capital changes
(Increase)/decrease in trade
and other receivables (1,091) (1,144)
Increase/(decrease) in payables 3,745 1,893
(Increase)/decrease in inventory 201 22
------------ -------------
Cash flow from operations 13,285 1,163
Income tax paid (2) (3)
Net cash flow generated from
operating activities 13,283 1,160
------------ -------------
Cash flows from investing
activities
Expenditure on exploration
and evaluation (499) (554)
Purchase of property, plant
and equipment (4,534) (8,117)
------------ -------------
Net cash used in investing
activities (5,033) (8,671)
------------ -------------
Cash flows from financing
activities
Bank loans drawn 3,947 -
Equity dividends paid - (1,013)
------------ -------------
Net cash outflow from financing
activities 3,947 (1,013)
------------ -------------
Effect of exchange rate changes
on cash and cash equivalents 752 (474)
Net increase/(decrease) in
cash and cash equivalents 12,949 (8,998)
Cash and cash equivalents
at beginning of the year 9 6,769 15,767
Cash and cash equivalents
at end of the year 9 19,718 6,769
============ =============
Group Statement of Changes in Shareholders' Equity
(presented in US$ 000)
Share Currency Share Accumulated Total
Capital Translation Grant Profit/(Loss) Equity
Reserves Reserve
Opening equity
at 1 January 2016 1,485 (91,350) 5,233 140,037 55,405
Profit for the
year - - - 1,187 1,187
Transactions with - - - - -
owners
Currency translation
differences - 10,495 - - 10,495
----------- ------------------ ------------- ----------------- ---------
Total comprehensive
income - 10,495 - 1,187 11,682
Closing equity
at 31 December
2016 1,485 (80,855) 5,233 141,224 67,087
=========== ================== ============= ================= =========
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
=========== ================== ============= ================= =========
Notes to the Abbreviated Financial Statements
for the year ended 31 December 2016
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.
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 3 to 13; the financial
position of the Group, its cash flows, liquidity position and
borrowing facilities are described in the Financial Review on pages
9 and 10. 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
2016 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 2016. 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 Adopted IFRSs have been issued
but have not been applied by the Group in these financial
statements. Their adoption is not expected to have a material
effect on the financial statements unless otherwise indicated:
-- Amendments to IFRS 2: Classification and Measurement of
Share-based Payment Transactions (effective date to be
confirmed)
-- Amendments to IFRS 4: Applying IFRS 9 Financial Instruments
with IFRS 4 Insurance Contracts (effective date to be
confirmed)
-- IFRS 9 Financial Instruments (effective date 1 January 2018)
-- IFRS 15 Revenue from Contract with Customers (effective date 1 January 2018)
-- IFRS 16 'Leases' (effective date 1 January 2019)
-- Amendments to IAS 7: Disclosure Initiative (effective date 1 January 2017)
-- Amendments to IAS 12: Recognition of Deferred Tax Assets for
Unrealised Losses (effective date 1 January 2017)
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.
1.2 Consolidation
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 2016 were:
-- GBP 1.233: US$ (2015: 1.517)
-- EUR 1.052: US$ (2015: 1.091)
-- US$ 1:60.657 RUR. (2015: 72.883)
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
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 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.
1.9 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.
1.10 Trade payables
Trade payables are recognised initially at fair value and
subsequently measured at amortised cost using the effective
interest method.
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.
The following table shows the currency structure of financial
assets and liabilities:
At 31 December 2016 Rubles US Dollars Euros Sterling Total
US$ US$ US$ US$ US$
000 000 000 000 000
Financial assets
Cash and cash equivalents 6,747 12,810 13 148 19,718
------- ----------- -------------- -------------- ----------
Total financial assets 6,747 12,810 13 148 19,718
Financial liabilities 11,389 - - - 11,389
======= =========== ============== ============== ==========
At 31 December 2015 Rubles US Dollars Euros Sterling Total
US$ US$ US$ US$ US$
000 000 000 000 000
Financial assets
Cash and cash equivalents 1,089 5,622 14 44 6,769
------- ----------- -------------- -------------- ----------
Total financial assets 1,089 5,622 14 44 6,769
Financial liabilities 3,217 - - - 3,217
======= =========== ============== ============== ==========
(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$2.7 million higher or lower (2015:
$1.4 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$19,718,000
and US$6,769,000 at 31 December 2016 and 2015 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 35.6% of Group revenues in
2016 (2015: 38.4%) were made to OOO Trans Nafta. As at 31 December
2016 there were trade receivables of US$2.0million (31 December
2015: US$1.0 million) relating to gas sales. As at 31 December 2016
there was no provision for bad debts (2015: nil).
Rating of financial 31 December 31 December
institution (Fitch) 2016 2015
US$000 US$000
Barclays Bank A 3,627 4,794
ZAO Raiffeisenbank
BBB- 15,840 1,579
Unicreditbank BBB- 214 202
Other 37 194
------------ ---------------
Total bank balance 19,718 6,769
============ ===============
(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 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, benefits from an interest rate subsidy
provided by the regional Government. 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 and
discount rates. Key assumptions and estimates in the impairment
models relate to:
-- International oil prices: flat real prices reflecting the
actual levels pertaining in the period between 31 December 2016 and
1 March 20-7 - Urals oil price of US$53 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 current
applicable official rates and a price differential of $5 per barrel
to reflect transportation costs
-- Gas sales price of RUR 3,898 per mcm excluding VAT.
-- Production profiles based on remaining reserves in the Proved
category and approved field development plans. In the Group's base
case, however, LPG revenues are not assumed although, as indicated
below, the capital expenditures for this project are included.
-- Capital expenditures required to deliver the above production
profiles and to maintain the production assets throughout the field
life. Total development capital expenditure assumed is US$18
million with future maintenance capital expenditure of up to US$1
million per annum. This includes US$5 million for the LPG
extraction project.
-- Cost assumptions are based on current experience and
expectations and are broadly in line with unit costs experienced in
the year ended 31 December 2016. The projections assume that the
current gas sweetening process is maintained. If Redox-based
sweetening is successfully implemented, however, the Group expects
to realise significant cost savings.
-- Export and mineral extraction taxes reflect rates set by current legislation.
-- The model reflects real terms cash flows with no inflationary
escalation of revenues or costs.
-- A real discount rate of 12% per annum is utilised in the models.
-- An exchange rate of RUR60 to US$1.00 is assumed.
In addition to the base case a number of sensitivity cases have
been carried out: varying oil and gas prices by 10%, varying
operating expenditure by 10%, varying capital expenditure by 20%
and using a 15% real discount rate.
As at 31 December 2016, the Group's impairment testing of the
property, plant and equipment related to each CGU indicated that no
impairment was required. In addition, the sensitivities described
above yielded net present values in excess of carrying value for
each CGU. Furthermore, two initiatives planned by the Group in
2017: a switch to Redox-based gas sweetening and construction of an
LPG extraction module, are each expected to result in material
increases in the value in use of the relevant CGU.
(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 12% below the level of
recently revised proved reserves as at 31 December 2016.
An independent assessment of the reserves and net present value
of future net revenues ("NPV") attributable to the Group's fields,
Dobrinskoye, Vostochny Makarovskoye, Sobolevskoye and Uzenskoye, as
at 31 December 2016, was prepared in accordance with reserve
definitions set by the Oil and Gas Reserves Committee of the
Society of Petroleum Engineers ("SPE"). The latest assessment
resulted in revisions that increased the level of proven and
probable reserves as at 31 December 2016 by 2.4% and decreased the
level of proved reserves by 10.8%.
4. Revenue
Year ended 31 December 2016 2015
US$ 000 US$ 000
Oil 7,523 4,081
Condensate 17,857 6,875
Gas 14,032 6,871
-------- --------
Total revenues 39,412 17,827
======== ========
All revenue is generated from the sale of oil and gas in the
ordinary course of the Group's activities.
5. Cost of sales and administrative expenses
Cost of sales and administrative expenses are as follows:
Year ended 31 December 2016 2015
US$ 000 US$ 000
Production expenses 10,968 7,367
Mineral extraction taxes 10,255 5,877
Depletion, depreciation
and amortisation 5,037 2,345
------------------ -------------------
Cost of Sales 26,260 15,589
================== ===================
Total expenses are analysed
as follows:
Year ended 31 December 2016 2015
US$ 000 US$ 000
Export sales related expenses (a) 4,052 319
Field operating expenses 9,367 6,016
Mineral extraction tax 10,255 5,876
Depreciation & amortisation 5,059 2,369
Exploration & evaluation 265 635
Write off of development
assets (b) 1,798 2,950
Inventory write off (c) 529 -
Salaries & staff benefits 3,177 2,471
Directors' emoluments and
other benefits 645 765
Audit fees 314 203
Taxes other than payroll
and mineral extraction 38 44
Legal & consulting 291 480
Other 1,110 742
------------------ -------------------
Total 36,900 22,870
================== ===================
(a) Selling expense: comprise export taxes and costs associated
with delivering gas condensate sales to export customers.
(b) Write-off of development assets: In the year ended 31
December 2016, the principal source of the write off of development
assets was the US$1.650 million compensation payable to
Schlumberger for logging tools stuck in the Uzen #4 well sidetrack.
The write off incurred in the year ended 31 December 2015 was
related mainly to the Sobolevskoye field.
(c) Inventory write-off: In the year ended 31 December 2016,
certain obsolete and unused items of production equipment were
transferred from producing assets to inventory and then written off
(2015: nil).
6. Other gains and losses
Year ended 31 December 2016 2015
US$ 000 US$ 000
------------ ---------------
Foreign exchange (loss)/gain (892) 942
Recovery of/(loss from)
unauthorised bank transfers 37 (727)
Other gains 92 91
------------ ---------------
Total other (losses)/gains (763) 306
============ ===============
7. Intangible assets
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 Exploration Total
progress: and
exploration evaluation
and evaluation
At 1 January 2016 117 2,750 2,867
Additions - 254 254
Write offs and impairments - (240) (240)
---------------- ------------- ------------
At 31 December 2016 117 2,764 2,881
Exchange adjustments 23 556 579
---------------- ------------- ------------
At 31 December 2016 140 3,320 3,460
================ ============= ============
Work in Exploration Total
progress: and
exploration evaluation
and evaluation
At 1 January 2015 151 3,595 3,746
Additions - 606 606
Write offs and impairments - (635) (635)
---------------- ------------- ------------
At 31 December 2015 151 3,566 3,717
Exchange adjustments (34) (816) (850)
---------------- ------------- ------------
At 31 December 2015 117 2,750 2,867
================ ============= ============
8. Property, plant and equipment - Group
Movements in property, plant and equipment, for the years ended
31 December 2016 and 2015 are as follows:
Cost Development Land Producing Other Total
assets & buildings assets
US$ 000 US$ 000 US$ 000 US$ US$
000 000
At 1 January 2016 1,137 650 55,879 498 58,164
Additions 2,341 - 1,564 - 3,905
Write-offs and
impairments (57) - (917) - (974)
Transfers (294) - 294 - -
Exchange adjustments 432 130 11,359 100 12,021
----------------------- ---------------- ------------- ---------- ------------
At 31 December
2016 3,559 780 68,179 598 73,116
Accumulated depreciation
At 1 January 2016 - - (9,399) (475) (9,874)
Adjustment for
assets written
off - - 195 15 210
Depreciation - - (5,028) (32) (5,060)
Exchange adjustments - - (2,387) (97) (2,484)
----------------------- ---------------- ------------- ---------- ------------
At 31 December
2016 - - (16,619) (589) (17,208)
----------------------- ---------------- ------------- ---------- ------------
Net book value
31 Dec 2016 3,559 780 51,560 9 55,908
======================= ================ ============= ========== ============
Cost Development Land Producing Other Total
assets & buildings assets
US$ 000 US$ 000 US$ 000 US$ US$
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 - -
Exchange adjustment (910) (192) (15,330) (152) (16,584)
---------------------- ---------------- -------------- ----------- ------------
At 31 December
2015 1,137 650 55,879 498 58,164
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)
Exchange adjustment - - 2,564 139 2,703
---------------------- ---------------- -------------- ----------- ------------
At 31 December
2015 - - (9,399) (475) (9,874)
---------------------- ---------------- -------------- ----------- ------------
Net book value
31 Dec 2015 1,137 650 46,480 23 48,290
====================== ================ ============== =========== ============
9. Cash and cash equivalents - Group and Company
An analysis of Group cash and cash equivalents by bank and
currency is presented in the table below:
At 31 December 2016 2015
------------- -------------
Bank Currency US$ US$
000 000
United Kingdom
Barclays Bank PLC USD 3,479 4,750
Barclays Bank PLC GBP 148 44
Russian Federation
Unicreditbank RUR 82 70
Unicreditbank USD 131 195
ZAO Raiffeisenbank RUR 6,628 825
ZAO Raiffeisenbank USD 9,200 740
ZAO Raiffeisenbank EUR 13 132
Other banks and
cash on hand RUR 37 13
Total cash and cash equivalents 19,718 6,769
============= =============
10. Inventories - Group
At 31 December 2016 2015
US$ 000 US$ 000
Production consumables
and spare parts 796 704
Crude oil inventory 185 363
------------- -------------
Total inventories 981 1,067
============= =============
11. Other receivables - Group
Group
At 31 December 2016 2015
US$ 000 US$ 000
VAT receivable 154 80
Prepayments 725 298
Trade receivables 2,067 987
Other accounts
receivable 61 84
--------------- --------------
Total other receivables 3,007 1,449
=============== ==============
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.
12. Trade and other payables
Group
At 31 December 2016 2015
US$ 000 US$ 000
----------------- -------------
Trade payables 4,861 2,467
Taxes other than
profit tax 2,266 750
Customer advances 2,836 932
----------------- -------------
Total 9,963 4,149
================= =============
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.
13. Bank loan
At 31 December 2016 2015
US$ 000 US$ 000
Non-current liabilities
Secured bank-loan 3,802 -
Current liabilities
Current portion 158 -
of secured bank
loan
--------------- -----------
Total Bank Loan 3,960 -
=============== ===========
In December 2016, the Group received bank loan in total amount
of RUR 240 million (US$3.96 million), which will be utilised to
fund purchases of equipment for the LPG project and should be fully
repaid by 2019 (repayments in 2017: US$0.16 million; 2018: US$1.9
million; 2019: US$1.9 million). Interest is charged at a fixed rate
of 11.45% per annum. The Bank loan as at 31 December 2016 has been
secured by charges over the shares of the Group's Russian operating
subsidiaries.
This information is provided by RNS
The company news service from the London Stock Exchange
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