TIDMVGAS
RNS Number : 7723I
Volga Gas PLC
30 March 2015
30 March 2015
VOLGA GAS PLC
Preliminary results for the year ended 31 December 2014
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 2014.
During 2014 the Group benefitted from a full year's operation at
increased throughput at the Dobrinskoye gas plant which enabled
sustained production from the Group's largest field, Vostochny
Makarovskoye ("VM"). This has enabled the Group to produce at an
average rate of 4,244 barrels of oil equivalent per day ("boepd")
during 2014, an increase of 45% over the average rate for 2013.
This higher rate of production has resulted in record Group
revenues, EBITDA and profits for 2014 and enabled the Group to
increase its net cash position after paying a maiden interim
dividend.
FINANCIALHIGHLIGHTS
-- Revenues up 14% to US$39.4 million (2013: US$34.6 million).
-- EBITDA up 18% to US$17.4 million (2013: US$14.5 million).
-- Profit before tax up 79% to US$16.3 million (2013: US$9.1
million), including other income (mainly foreign exchange gain) of
US$3.3 million (2013: US$1.6 million).
-- Net operating cash flow up 6% to US$16.3 million (2013: US$15.4 million).
-- Net cash increased to US$15.8 million as at 31 December 2014
(31 December 2013: US$8.1 million) after payment of US$3.0 million
maiden interim dividend.
-- Final dividend of US$0.0125 per Ordinary Share recommended.
PRODUCTION & DEVELOPMENT
-- Group average production in 2014 up 45% to 4,244 boepd (2013: 2,958 boepd).
-- VM and Dobrinskoye fields produced steadily from existing
wells at an average of 3,543 boepd (2013: 2,132 boepd), up by
66%.
-- Plan to complete drilling the VM#3 well, to drill a sidetrack
on VM#4 and start drilling the new VM#5 well during 2015.
DOBRINSKOYE GAS PLANT
-- Dobrinskoye gas plant operated successfully during 2014 at
rates of over 500,000 cubic metres per day (17.7 mmcf/d).
-- Completed minor additional modifications to meet regulatory
requirements and improve efficiency.
-- Commenced preliminary feasibility and design work for a major
upgrade to capture and produce liquid petroleum gases ("LPG") from
the gas stream.
-- LPG construction expected to commence in 2016.
CURRENT TRADING AND OUTLOOK
-- Start to 2015 impacted by
- Lower international oil prices and weak Rouble reduce US$ equivalent revenues.
- Production in January and February disrupted by changes in the
domestic market following adjustments to new export tax regime.
- Domestic prices for oil and condensate currently below netback parity.
- Significant increases in Mineral Extraction Tax rates imposed since the start of 2015.
-- The Board is confident that the Group is well positioned with
a strong balance sheet, sustainable production and potential to
increase profitability with the LPG project.
Mikhail Ivanov, Chief Executive of Volga Gas, commented:
"2014 was financially a successful year for Volga Gas with
strong cash generation enabling the Group to strengthen its
liquidity. This will enable the Group to weather the currently
challenging position in the domestic oil and gas markets in Russia
and to continue with the plans to develop its key assets, including
the significant investment represented by the proposed LPG project.
In the light of the current financial conditions prevailing in
Russia and given the Group's requirement to fund the proposed LPG
project and to provide greater flexibility, the Board has decided
that it is in the best interests of the shareholders for dividend
payments to be kept at a level which can be sustained and grown as
the profits increase in the future.
"We remain positive about the potential for growth, both in
reserves and production from our licences. We will also continue
seek value accretive opportunities, beyond our existing licence
areas, building a focused exploration and production business."
For additional information please contact:
Volga Gas plc
Mikhail Ivanov, Chief
Executive Officer +7 (495) 721 1233
Tony Alves, Chief Financial
Officer +44 (0) 20 8622 4451
Stifel Nicolaus Europe
Limited
Michael Shaw
Ashton Clanfield +44 (0)20 7710 7600
FTI Consulting
Ed Westropp +44 (0)20 7831 3113
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. Mikhail Ivanov, 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. Mikhail Ivanov holds a M.S. Degree in Geophysics
from Novosibirsk State University. He also has an MBA degree from
Kellogg School of Management (Northwestern University). He is a
member of the Society of Petroleum Engineers and has more than 20
years of experience in the sector.
Availability of report and accounts and final dividend
The Group's full report and accounts, including notice of the
annual general meeting of the Company will be dispatched to
shareholders as soon as is practicable. Copies will also be
available on the Company's website www.volgagas.com and on request
from the Company at, Ground Floor, 17-19 Rochester Row, London SW1P
1QT.
The final dividend of US$0.0125 proposed by the Board is to be
paid on 10 June 2015, subject to approval at the Company's Annual
General Meeting on 5 June 2015, to shareholders on the register on
15 May 2015.
Chairman's Statement
Dear Shareholder,
2014 was a significant year for Volga Gas, in which the Group
achieved its first full year of gas and condensate production with
its wells producing up to their current capacity. The average
production rate for 2014 was 4,244 barrels of oil equivalent per
day ("boepd"), a 43% increase over the average 2,965 boepd achieved
in 2013. With strong cash generation arising from this production,
it was gratifying to see the financial position strengthen
sufficiently for the Company to make its first interim dividend
payment and still report a significant increase in net cash during
the year.
The Group now faces a number of challenges, not the least of
which is the general economic situation in Russia, where the
dramatic fall in international oil prices are likely to have a
significant impact on the domestic economy at least in the short
term. While the weakness of the Russian Ruble, largely matching the
drop in the oil price, is likely to enable the Group's
profitability to be maintained, our profits for future periods as
reported in US Dollars may be significantly lower than in recent
years. The declining Ruble has also led to a significant shrinking
of the Group balance sheet as assets have been adjusted to the
exchange rate prevailing on 31 December 2014.
Since the year end production based taxes have increased
significantly - especially as applied to condensate, which hitherto
had been taxed at a rate comparable to gas, but is now taxed closer
to the level applied to oil. While there is nothing that can be
done by the Group to change the tax rates, management is
considering ways to optimize the business. A key project that is
currently under consideration is the installation of additional
units at the Dobrinskoye gas plant to extract liquid petroleum
gases ("LPG"). Initial studies suggest that this could be a
rewarding investment for the Group and a significant enhancement to
the value of the reserves.
Most importantly, Volga Gas benefits from low operating costs
and, with its fields based close to market is able to operate
profitability even with significantly reduced oil and gas prices.
The strong balance sheet, with no debt and a liquidity position of
US$15.8 million built up from retained cash flow, provides a solid
foundation for the Group to continue development of its fields and
to maximize its production profile.
The Group holds significant proven reserves in its three
principal fields. These fields form the basis of sustainable and
growing production in the near term. Our fields are advantageously
located and our costs are sufficiently low for us to achieve
positive returns at current oil and gas prices. Most importantly,
these assets provide a strong 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.
In the light of the current financial conditions prevailing in
Russia and given the Group's requirement to fund the proposed LPG
project, which as outlined by the Chief Executive below is expected
to enhance the profitability of the Group's gas and condensate
production, the Board has decided that it is in the best interests
of the shareholders for a final dividend to be at a level which can
be sustained and grown as the profits increase in the future.
Accordingly, the Board is recommending a final dividend of
US$0.0125 per Ordinary Share bringing the total dividend for the
year to US$0.05 per Ordinary Share.
You will be aware that in June 2014 the Board was exploring
strategic options for the business, including seeking potential
offerors for the Company by means of a "formal sale process" under
which the Board of Volga Gas is able to have discussions with third
parties interested in such a transaction on a confidential basis.
Whilst there was some interest received, the subsequent
developments in the external conditions led the Board to conclude
that an acceptable proposal would not be received. The formal sale
process was accordingly concluded in January 2015. The Board
continues to seek to maximize the value of the Company for
shareholders.
Aleksey Kalinin
Chairman
Chief Executive's Report
As the Chairman has noted, 2014 was the first full year in which
Volga Gas produced its gas and condensate wells at capacity with
the gas plant operating fully to expectations and enabling the
Group to record a 43% increase in production compared to 2013. This
increased production combined with steady oil and gas prices - at
least for the first ten months of 2014 - enabled the Group to enjoy
strong cash flow and strengthen its financial position, while
providing the flexibility to manage the effects of the subsequent
downturn in international oil prices.
As detailed in the Operational Review below, the majority of the
work on our producing assets base remained focused on our main
field, Vostochny Makarovskoye ("VM"). On VM, the Group commenced
the drilling of a new producing well, VM#3. Although, as detailed
below, the well was not completed during 2014, we now expect it to
be producing in mid-2015.
Crude oil production, on the other hand, continued to decline.
Production from the Uzenskoye field was further reduced to prevent
a rising water cut. In addition, production from the single well
Sobolevskoye field ceased. While it is now a minor part of the
Group's business, Volga Gas had made very good returns from these
assets and continues to benefit from the cash generation they
provide.
In 2014 as in 2013, exploration activity was limited, although a
number of significant exploration prospects in the Group's
Karpenskiy licence area have been identified for future exploration
drilling.
2015 Objectives - VM Development and LPG Project
The Group's key operational objectives in 2015 are to complete
the drilling of the VM#3 and VM#4 wells on the VM field and to
complete the Front End Engineering and Design work for an LPG
extraction project. The aim is to increase production from the VM
field so as to maximize the utilisation of the 1 million m(3) per
day (35 mmcf/d) processing capacity of the gas plant.
Based on initial studies, the LPG project could enable the Group
to achieve a significant enhancement of the value of the gas plant
output and the investment required for this could be recovered
within three years from the increased income and improved
profitability.
Finance
The Group maintained a strong level of cash generation from
operating activities throughout 2014, enabling it to fund its
capital expenditure for the year from operating cash flow and to
make its maiden interim dividend payment of $0.0375 per Ordinary
Share in October 2014, while increasing its cash balance from
US$8.1 million to US$15.8 million during the year.
Capital expenditure in 2014 was less than originally planned
mainly because the operational difficulties experienced on drilling
the VM#3 well led to a delay in the completion of that well and
deferral of further drilling into 2015.
Although the planned field development expenditures in 2015 and
beyond are expected to be funded from operating cash flow, the
Group may consider a moderate level of borrowing to be appropriate
to fund significant value accretive investments like the LPG
project.
Current trading
As announced on 19 February 2015, during January and February
2015 disruption to the domestic oil market in Russia following the
recently implemented tax changes had an impact on the ability of
purchasers of condensate from Volga Gas to take delivery and
subsequently led to the temporary suspension of production at the
Company's VM and Dobrinskoye gas fields. Consequently for this
period actual production was significantly below the capacity of
the fields. Since 16 February 2015, Group production has resumed at
close to full production capacity of approximately 4,500 barrels of
oil equivalent per day.
The major tax changes implemented at the start of 2015 included
a significant reduction in the rate of export tax coupled with a
rise in Mineral Extraction Taxes on oil and condensate. However the
domestic market prices in Russia, which hitherto reflected full
netback pricing, have not risen to match the drop in export taxes.
Meanwhile MET charges are calculated with reference to export
prices and this has led to the group experiencing higher than
anticipated MET charges relative to income since the start of
2015.
Outlook
It is our current expectation that the VM#3 well will be
completed during H1 2015. In addition, we have mobilized a second
rig to drill a sidetrack to the VM#4 well, which was originally
drilled in 2008 but was not productive. The sidetrack will be
deviated towards the centre of the field where it is expected to
intersect productive reservoir. Further drilling, notably the VM#5
well, is also anticipated for later in 2015. Assuming successful
drilling of the new wells, management expects to increase
production to above 5,000 boepd by the end of 2015.
Clearly with significantly lower oil prices and a sharply
devalued Ruble, the revenues as reported in US dollars would not
reflect this progress. However, with its costs almost entirely in
Rubles, the Group is expected to remain profitable and cash
generative even without a significant recovery in oil prices and in
spite of the increased rate of production taxes that have come into
effect.
The total capital expenditure budgeted for 2015 is approximately
US$14 million. All of this expenditure is discretionary and can be
deferred or cancelled if necessary. Management expects the 2015
capital expenditure to be funded entirely from existing cash
resources and cash generated from operations.
We look forward to delivering a rising stream of production and
further financial growth.
Mikhail Ivanov
Chief Executive Officer
Operational Review
Operations overview
After the Group received formal approval of the upgrade works at
the Dobrinskoye gas processing plant in November 2013, production
of gas and condensate from the Group's VM and Dobrinskoye fields
increased to reflect their existing productive capacity, more than
doubling the production rates achieved hitherto.
The overall level of production in 2014, at 4,244 boepd, was 43%
above the 2,958 boepd achieved in 2013. This was driven by
increased gas and condensate production from the VM and Dobrinskoye
fields partly offset by declines in total oil production.
Average Oil production was lower in 2014 than in 2013, averaging
689 bopd in 2014 compared to 826 bopd in 2013. The reasons for the
decline in oil production are detailed below.
As a consequence of the significant increase in production in
2014, revenues and EBITDA levels in 2014 were well ahead of 2013,
although with the rapidly increasing proportion of gas in the mix,
the revenue growth was not quite as impressive as production
growth.
Gas processing plant
Since November 2013, the Dobrinskoye gas processing plant has
been consistently operating at rates of over 500,000 m(3) per day
(17.7 million cubic feet per day("mmcf/d")) with the exception of
periods of planned shut down for maintenance. During 2014 a number
of minor additional modules, as required by the state construction
agency, Gosstroi, were installed on the plant. During 2014 the
Group incurred approximately US$2.7 million (2013: US$ 3.6 million)
of capital expenditure on the gas plant.
During 2014, the Group has also been investigating means of
enhancing the gas processing by the use of alternative chemicals.
Following successful trials conducted during the year modifications
to the process are beginning to deliver savings on the cost of
chemicals used in the process.
The Group has conducted a preliminary evaluation of the
feasibility of additional processing to extract an LPG stream from
the gas, primarily propane and butane. The initial studies suggest
that there are significant benefits from this project, from the
extraction of additional higher value product that are otherwise
either flared or sent down the gas pipeline with the sales gas. In
addition, consideration is being given to a modification of the
sulphur extraction process that would significantly reduce the cost
of chemicals. The initial economic modelling suggests that the
capital investment on this project can be recovered within three
years from the incremental revenue and cost savings.
In November 2014, the Group commissioned a front end engineering
and design study which will form the basis of a final investment
decision on this project by the Board during 2015.
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. Prior to November 2013 the plant was permitted to operate at
a capacity of 250,000 cubic metres per day (8.8 mmcf/d), so the
fields were not producing at their full capacity. Since November
2013, production increased to levels that more closely reflect the
estimated current production capacity of the wells which is over
500,000 cubic metres per day (17.8 mmcf/d) of gas and 120 tonnes
per day (1,050 barrels per day("bpd") of condensate.
During 2014, production derived from both fields averaged 15.5
mmcf/d of gas and 966 bpd of condensate (2013: 8.7 mmcf/d of gas
and 682 bpd of condensate). In total, there are three producing
wells on VM and two producing wells on Dobrinskoye.
Gas continues to be sold to Trans Nafta under contract at a
fixed Ruble contract gas sales price. With the devaluation of the
Ruble during 2014, the US dollar equivalent of the price declined
during 2014. The average gas sales price for 2014 was the
equivalent of US$2.15 per thousand cubic feet, net of VAT (2013:
US$2.73). During 2014 the average condensate sales price was
US$45.07 per barrel (2013: US$47.00 per barrel).
Average unit production costs on the gas-condensate fields
declined to US$6.49 per boe in 2014 (2013: US$8.27) primarily as
the significant element of fixed plant costs were spread over
higher production rates. Management anticipates further reductions
in unit costs as capacity utilisation rises towards 100%.
During 2014, the main development activity was the drilling of
the VM#3 production well. Following slow progress with the
drilling, it eventually became clear that the drilling contractor
had encountered mechanicals difficulties, with the drill pipe being
stuck at a depth of 2,556 metres. Subsequent attempts by the
drilling contractor to release the stuck drill pipe were not
successful and operations were temporarily suspended in September
2014. The Group subsequently agreed with the drilling contractor a
cost effective means of completing the VM#3 production well.
Operations recommenced in January 2015 with the aim of completing
the well in time to commence production during the first half of
2015. As the well is being drilled on a turnkey contract basis the
cost has not been materially affected.
In January 2015, a second rig was mobilized to drill a sidetrack
to the VM#4 well which is currently not producing. There are, in
addition, contingent plans to drill a further well, VM#5 later in
2015.
Oil production
Having completed its sixth year of full time production, the
Yuzhny Uzenskoye oil field is the Group's longest established
field. It continues to produce under natural reservoir pressure
drive and with minimal water cut. As the oil has been produced, the
oil:water contact in the reservoir has risen and since the start of
2013, wells at the edge of the field have exhibited some water cut
and were shut in. As a consequence, oil production from the field
has been managed at declining production rates. There remains a
shallower undeveloped reservoir which may be brought into
production by re-using existing wells on the field.
In June 2013, following a successful flow test and workover, the
Sobolevskaya #11 well in the Urozhainoye-2 licence was put on
production. However, in August 2014 production from the well
ceased. An undeveloped oil pool has been identified within the
Sobolevskaya field. The 2015 capital budget includes a sidetrack
from the #11 well to develop this resource.
The Group's oil production, whilst of modest scale, remains very
profitable for the Group and a useful contributor of cash flow.
Exploration
The Group has identified a number of exploration targets in the
Karpenskiy Licence Area at shallow horizons of between 1,000 and
2,000 metres depth. These provide low cost opportunities to add
potentially material oil reserves. The Group's current priority is
the development of its gas and condensate fields and a return to
active exploration is to be considered for later in 2015 and
beyond. The Group has fulfilled all its licence commitments on the
Karpenskiy Licence Area and further drilling in the area is
discretionary.
Oil, gas and condensate reserves as of 1 January 2015
During 2012, an independent evaluation of the Company's oil, gas
and condensate reserves was conducted by Miller and Lents Ltd.
The independent assessment of the reserves and net present value
of future net revenue ("NPV") attributable to the Group's three
principal fields, Dobrinskoye, Vostochny Makarovskoye and
Uzenskoye, as at 1 August 2012, was prepared in accordance with
reserve definitions prepared by the Oil and Gas Reserves Committee
of the Society of Petroleum Engineers ("SPE").
The following table shows the Proven and Probable reserves as
evaluated by Miller & Lents as at 1 August 2012, adjusted by
management for subsequent production.
Oil, gas and condensate reserves
Oil & Gas Total
Condensate
(mmbbl) (bcf) (mmboe)
------------------------ ------------ ------ --------
As at 31 December 2013
Proved reserves 14.009 152.8 39.465
Proved plus probable
reserves 15.313 163.7 42.591
------------------------ ------------ ------ --------
Production: 1 January
-31 December 2014 0.581 5.7 1.571
As at 31 December 2014
Proved reserves 13.428 147.1 37.894
Proved plus probable
reserves 14.732 158.0 41.020
------------------------ ------------ ------ --------
Notes:
1. There has been no external reassessment of reserves
subsequent to the Miller and Lents reserve study of 2012.
2. The reserves and production numbers shown above exclude all
volumes related to the Sobolevskoye field which was not included in
the Miller and Lents reserve study of 2012. The numbers for
Sobolevskoye are estimated by management not to be material in the
context of Group reserves.
3. 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. Mikhail Ivanov,
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. Mikhail
Ivanov holds a M.S. Degree in Geophysics from Novosibirsk State
University. He also has an MBA degree from Kellogg School of
Management (Northwestern University). He is a member of the Society
of Petroleum Engineers.
Financial Review
Results for the year
In 2014, the Group generated US$39.4 million in turnover (2013:
US$34.6 million) from the sale of 603,950 barrels of crude oil and
condensate (2013: 547,257 barrels) and 5,671 million cubic feet of
natural gas (2013: 3,128 million cubic feet). Oil and condensate
sales were made into the domestic market during the period. The
average price realised for liquids was the equivalent of US$45.07
per barrel (2013: US$47.63 per barrel). The gas sales price during
2014 averaged US$2.15 per thousand cubic feet (2013: US$2.73 per
thousand cubic feet), the fall being entirely attributable to the
devaluation of the Ruble. With sales made exclusively into the
market in the Volga region at the wellhead, our oil and condensate
sales prices reflect international prices, adjusted for export
taxes and transportation costs. Production activities generated a
gross profit of US$16.9 million in 2014 (2013: gross profit of
US$16.2 million).
In 2014, the total cost of production increased to US$7.8
million (2013: US$5.9 million), with the incremental costs
primarily incurred in volume related costs at the Group's gas
processing plant. Production based taxes were US$8.3 million (2013:
US$8.1 million) reflecting the increase in the proportion of gas in
the Group's production and lower rates of Mineral Extraction Tax
("MET") charged on gas compared to crude oil. MET in 2014
represented 21.2% of revenues (2013: 23.0% of revenues). The gross
profit margin in 2014 was 42.9% (2013: 46.7%).
Operating and administrative expenses in 2014 were US$4.2
million (2013: US$4.0 million).
The Group experienced a significant increase in EBITDA (defined
as operating profit before non-cash charges, including exploration
expense, depletion and depreciation) to US$17.4 million (2013:
US$14.8 million) as a result of the higher revenues partly offset
by higher expenses. As a reflection of the increasing proportion of
gas in the sales mix. EBITDA per barrel of oil equivalent sold in
2014 was US$11.24 (2013: US$13.81).
After recording no exploration and evaluation expense (2013:
US$2.5 million), or other asset impairment expenses (2013: US$ 1.4
million) the Group recorded an operating profit for 2014 of US$12.8
million (2013: US$8.2 million).
After including net interest income of US$0.2 million (2013: net
interest expense of US$0.2 million) and other gains, predominantly
from foreign exchange, of $3.3 million (2013: net other gains of
US$1.6 million), the Group recognised a profit before tax of
US$16.3 million (2013: US$9.6 million) and reported net profit
after tax of US$13.1 million (2013: US$8.6 million) after taking a
deferred tax charge of US$3.3 million (2013: US$1.0 million).
Included in Other income in 2014 was a foreign exchange gain of
US$3.2 million arising from US dollar cash balances held by Russian
subsidiaries which have the Ruble as functional currency (2013:
US$0.3 million loss on foreign exchange).
Cash flow
Group cash inflow from operating activities was US$16.2 million
(2013: US$15.4 million). Net working capital movements contributed
to a cash inflow of US$0.5 million in 2014 (2013: US$1.2 million
outflow from working capital movements). With slightly lower
capital expenditures in 2014, the net outflow from investing
activities was US$5.5 million (2013: US$6.2 million). Net cash
outflow from financing activities was US$3.0 million (2013: outflow
of US$8.1 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. A maiden interim dividend of US$0.0375 per
share was paid on 24 October 2014. In light of the material
reduction in the oil price in recent months, adverse financial
conditions currently prevailing in Russia and the Group's plans for
significant new investment in the LPG project the Board has decided
to restrain the level of dividend payments. Accordingly, the Board
is recommending a final dividend of US$0.0125 per Ordinary share,
bringing the total payment for the year to US$0.05 per Ordinary
Share (2013: nil).
Capital expenditure
During 2014 capital expenditure of US$5.9 million was incurred
(2013: US$5.9 million). In both 2014 and 2013 all of the capital
expenditure was on development and producing assets. The most
significant individual components of the capital expenditure in
2014 relate to the Dobrinskoye gas plant and drilling on the VM
field.
Balance sheet and financing
As at 31 December 2014, the Group held cash and bank deposits of
US$15.8 million (2013: US$8.1 million) with no debt. All of the
Group's cash balances are held in bank accounts in the UK and
Russia and the majority of the Group's cash is held in US
dollars.
As at 31 December 2014, the Group's intangible assets decreased
to US$3.7 million (2013: US$6.4 million). Property, plant and
equipment, decreased to US$57.8 million (2013: US$98.3 million),
primarily reflecting the impact of foreign exchange
adjustments.
On 9 July 2014 the capital reduction approved by shareholders at
the Company's Annual General Meeting on 6 June 2014 became
effective following confirmation by the High Court, the filing of
the Court Order and a Statement of Capital with Companies House and
the fulfilment of certain minor undertakings given to the Court. As
a result, the Share Premium Account of the Company, amounting to
US$165.9 million, was cancelled and the equivalent sum credited to
the Company's Profit and Loss Account, thereby creating
distributable reserves.
The Group's committed capital expenditures are less than
expected cash flow from operations and cash-on-hand and such
expenditures can be managed in light of the sharp reduction in
international oil prices and the devaluation of the Ruble. The
Group may consider additional debt facilities to fund the
longer-term development of its existing licences and operational
facilities as appropriate.
The Group's financial statements are presented on a going
concern basis.
Tony Alves
Chief Financial Officer
Five year financial and operational summary
Sales volumes 2014 2013 2012 2011 2010
--------------------------- ---------------- ---------------- ---------------- ---------------- -----------------
Oil & condensate
(barrels) 603,950 547,257 529,501 546,817 407,050
Gas (mcf) 5,671 3,128 1,193 1,348 -
Total (boe) 1,549,117 1,068,585 728,334 771,479 407,050
Operating Results 2014 2013 2012 2011 2010
(US$ 000)
--------------------------- ---------------- ---------------- ---------------- ---------------- -----------------
Oil and condensate
sales 27,220 26,067 25,526 25,425 13,052
Gas sales 12,203 8,554 2,769 3,146 -
---------------- ---------------- ---------------- ---------------- -----------------
Revenue 39,423 34,621 28,295 28,571 13,052
Production costs (7,805) (5,946) (3,776) (3,126) (436)
Production based
taxes (8,344) (8,095) (8,951) (9,537) (5,254)
Depletion, depreciation
and other (4,656) (2,611) (2,280) (2,641) (1,037)
Other (1,709) (1,799) (1,562) (991) (113)
---------------- ---------------- ---------------- ---------------- -----------------
Cost of sales (22,514) (18,451) (16,569) (16,295) (6,840)
Gross profit 16,909 16,170 11,726 12,276 6,212
Exploration expense - (2,519) (8,475) (200) (23,937)
Provision for VAT - - (2,945) - -
recovery
Operating & administrative
expenses (4,157) (4,029) (6,024) (5,991) (4,773)
Write-off of development
assets - (1,439) (188) (5,612) -
---------------- ---------------- ---------------- ---------------- -----------------
Operating profit/(loss) 12,752 8,183 (5,906) 473 (22,498)
Net realisation 2014 2013 2012 2011 2010
--------------------------- ---------------- ---------------- ---------------- ---------------- -----------------
Oil & condensate
(US$/barrel) 45.07 47.63 48.21 46.50 32.06
Gas (US$/mcf) 2.15 2.73 2.32 2.33 -
Operating data 2014 2013 2012 2011 2010
(US$/boe)
--------------------------- ---------------- ---------------- ---------------- ---------------- -----------------
Production costs 5.04 5.56 5.18 4.05 1.07
Production based
taxes 5.38 7.58 12.29 12.36 12.91
Depletion, depreciation
and other 3.01 2.44 3.13 3.42 2.55
EBITDA calculation 2014 2013 2012 2011 2010
(US$ 000)
--------------------------- ---------------- ---------------- ---------------- ---------------- -----------------
Operating profit/(loss) 12,752 8,183 (5,906) 473 (22,498)
Exploration expense - 2,519 8,475 200 23,937
DD&A and other
non-cash expense 4,656 4,050 5,413 8,253 1,037
---------------- ---------------- ---------------- ---------------- -----------------
EBITDA 17,408 14,752 7,982 8,926 2,476
EBITDA per boe 11.24 13.81 10.96 11.57 6.08
Principal Risks and Uncertainties
The Group is subject to various risks relating to political,
economic, legal, social, industry, business and financial
conditions.
The following risk factors, which are not exhaustive, are
particularly relevant to the Group's business activities:
Volatility of oil prices
The supply, demand and prices for oil are influenced by factors
beyond the Group's control. These factors include global and
regional demand and supply, exchange rates, interest and inflation
rates and political events. A significant prolonged decline in oil
and gas prices could impact the profitability of the Group's
activities. Additionally, the Group's production is predominantly
sold in the domestic Russian markets which are influenced by
domestic supply and demand factors, the level of Russian export
taxes and regional transportation costs.
Substantially 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 production in Russia effectively reduce the
exposure to international market prices for oil.
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 will materially increase the
rates on crude oil, condensate and natural gas.
Exploration and reserve risks
Whilst the Group will seek to apply the latest technology to
assess exploration licences, the exploration for, and development
of, hydrocarbons is speculative and involves a high degree of risk.
These risks include the uncertainty that the Group will discover
sufficient commercially exploitable oil or gas resources in
unproven areas of its licences. Unsuccessful exploration efforts
may result in impairment to the balance sheet value of exploration
assets.
During 2012, the Group commissioned a reserve evaluation based
on reporting standards set by the Society of Petroleum Engineers.
If the actual results of producing the Group's fields are
significantly different to expectations, there may be changes in
the future estimates of reserves. These may impact the balance
sheet values of the Group's Intangible Assets and the Group's
Property, Plant and Equipment.
Environmental risk
The oil and gas industry is subject to environmental hazards,
such as oil spills, gas leaks, ruptures and discharges of petroleum
products and hazardous substances. These environmental hazards
could expose the Group to material liabilities for property
damages, personal injuries, or other environmental harm, including
costs of investigating and remediating contaminated properties.
The Group is subject to stringent environmental laws in Russia
with regards to its oil and gas operations. Failure to comply with
such laws and regulations could subject the Group to material
administrative, civil, or criminal penalties or other liabilities.
Additionally, compliance with these laws may, from time to time,
result in increased costs to the Group's operations, impact
production, or increase the costs of potential acquisitions.
The Group liaises closely with the Federal Service of
Environmental, Technological and Nuclear Resources of the Saratov
and Volgograd Oblasts on potential environmental impact of its
operations and conducts environmental studies both as required by,
and in addition to, its licence obligations to mitigate any
specific risk. The Group's operations are regularly subject to
independent environmental audit.
The Group did not incur any material costs relating to the
compliance with environmental laws during the period.
Risk of operating oil and gas properties
The oil and gas business involves certain operating hazards,
such as well blowouts, cratering, explosions, uncontrollable flows
of oil, gas or well fluids, fires, pollution and releases of toxic
substances. Any of these operating hazards could cause serious
injuries, fatalities, or property damage, which could expose the
Group to liabilities. The settlement of these liabilities could
materially impact the funds available for the exploration and
development of the Group's oil and gas properties. The Group
maintains insurance against many potential losses and liabilities
arising from its operations in accordance with customary industry
practices, but the Group's insurance coverage cannot protect it
against all operational risks.
Foreign currency risk
The Group's capital expenditures and operating costs are
predominantly in Russian rubles ("RUR") while a minority of costs
are also in US dollars. Revenues are predominantly received in RUR
so consequently the operating profitability is not materially
exposed to moderate short-term exchange rate movements. The
functional currency of the Group's operating subsidiaries is the
RUR and the Group's assets and liabilities are predominantly RUR
denominated. As the Group's presentational currency is the US
dollar, the significant devaluation of the RUR against the US
dollar would negatively impact the Group's financial
statements.
Business in Russia
Amongst the risks that face the Group in conducting business and
operations in Russia are:
-- Economic instability, including in other countries or the
global economy that could lead to consequences such as
hyperinflation, currency fluctuations and a decline in per capita
income in the Russian economy.
-- Governmental and political 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.
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 2014 the Group had US$15.8 million of cash and
cash equivalents of which US$8.6 million was held in bank accounts
in Russia. The Group intends to fund its ongoing operations and
development activities from its cash resources and cash generated
by its established operations. At 31 December 2014 the Group has
budgeted capital expenditures of approximately US$14 million
primarily for the continuing development of gas and condensate
production. The Board considers that the Group will have sufficient
liquidity to meet its obligations. All current and planned capital
expenditures are discretionary and may be deferred or cancelled in
the light of the Group's cash generation and liquidity
position.
Through its ordinary course activities, the Group is exposed to
legal, operational and development risk that could delay growth in
its cash generation from operations or may require additional
capital investment that could place increased burden on the Group's
available financial resources.
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. During 2012 management decided that having
established a track record of reliable cash generation it was
appropriate to introduce a modest proportion of debt into the
capital structure and as such a loan of US$10 million was taken and
which was fully repaid by 31 December 2013. Management expects that
the cash generated by the operating fields will be sufficient to
sustain the Group's operations and committed capital investment for
the foreseeable future. Further short term debt facilities may be
arranged to provide financial headroom for future development
activities.
Abbreviated Financial Statements for the year ended 31 December
2014
Group Income Statement
(presented in US$ 000)
Year ended 31 December Notes 2014 2013
CONTINUING OPERATIONS
Revenue 39,423 34,621
Cost of sales 2 (22,514) (18,451)
------------------ ----------------
Gross profit 16,909 16,170
Exploration and evaluation
expense 2 - (2,519)
Operating and administrative
expenses 2 (4,157) (4,029)
Write off of development assets - (1,439)
------------------ ----------------
Operating profit 12,752 8,183
Interest income 245 45
Interest expense - (281)
Other gains and losses - net 3 3,290 1,648
------------------ ----------------
Profit for the year before
tax 16,287 9,595
Deferred income tax (3,229) (1,036)
------------------ ----------------
Profit for the year before
non-controlling interests 13,058 8,559
Attributable to:
The owners of the parent Company 13,058 8,559
================== ================
Basic and diluted profit per
share (in US dollars) 0.16 0.11
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 2014 2013
Profit for the year attributable
to equity shareholders of the
Company 13,058 8,559
Other comprehensive income items that
may be reclassified to profit and loss:
Currency translation differences (48,955) (8,242)
Total comprehensive (expense)/income
for the year (35,897) 317
Attributable to:
The owners of the parent Company (35,897) 317
Group Balance Sheet
(presented in US$ 000)
At 31 December Notes 2014 2013
ASSETS
Non-current assets
Intangible assets 4 3,746 6,438
Property, plant and equipment 5 57,819 98,272
Other non-current assets 6 68 709
Deferred tax assets 706 750
------------------- -------------------
Total non-current assets 62,339 106,169
Current assets
Cash and cash equivalents 7 15,767 8,081
Inventories 8 1,099 1,793
Other receivables 9 918 2,869
------------------- -------------------
Total current assets 17,784 12,743
Total assets 80,123 118,912
=================== ===================
EQUITY AND LIABILITIES
Equity
Share capital 1,485 1,485
Share premium (net of issue
costs) - 165,873
Other reserves (70,816) (21,861)
Accumulated profits/(losses) 10 145,114 (30,779)
Equity attributable to
the shareholders of the
parent 75,783 114,718
Total equity 75,783 114,718
Non-current liabilities
Asset retirement obligation 189 325
Deferred tax liabilities 2,478 -
------------------- -------------------
Total non-current liabilities 2,667 325
Current liabilities
Trade and other payables 11 1,673 3,869
------------------- -------------------
Total current liabilities 1,673 3,869
Total equity and liabilities 80,123 118,912
=================== ===================
Group Cash Flow Statements
(presented in US$ 000)
Year ended 31 December Notes 2014 2013
Profit for the year before
tax 16,287 9,595
Adjustments to loss before
tax:
Depreciation 4,683 2,608
E & E expense - 2,519
Write off of development
assets - 1,188
Other non-cash expenses - 342
Foreign exchange differences (5,297) 310
------------------ ------------------
Operating cash flow prior
to working capital 15,673 16,562
Working capital changes
Increase/(decrease) in
trade and other receivables 1,621 (870)
Decrease in payables (971) 315
Decrease in inventory (77) (644)
------------------ ------------------
Cash flow from operations 16,246 15,363
Income tax paid - -
Net cash flow generated from
operating activities 16,246 15,363
------------------ ------------------
Cash flows from investing
activities
Expenditure on exploration - -
and evaluation
Purchase of property, plant
and equipment (5,520) (6,229)
------------------ ------------------
Net cash used in investing
activities (5,520) (6,229)
------------------ ------------------
Cash flows from financing
activities
Equity dividends paid (3,038) -
Loans repaid - (8,097)
------------------ ------------------
Net cash provided by financing
activities (3,038) (8,097)
------------------ ------------------
Effect of exchange rate changes
on cash (2) (5)
Net increase in cash and
cash equivalents 7,686 1,032
Cash and cash equivalents
at beginning of the year 8,081 7,049
Cash and cash equivalents
at end of the year 15,767 8,081
================== ==================
Notes to the Abbreviated Financial Statements for the year ended
31 December 2014
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 Group's business activities, together with the factors
likely to affect its future development, performance and position
set out in the Strategic Report; the financial position of the
Group, its cash flows, liquidity position and borrowing facilities
are described in the Financial Review. 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
There are no IFRSs or IFRIC interpretations that are effective
for the first time for the financial year beginning on 1 January
2014 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 2014. No modifications of previous conclusions about
control regarding the Group's investees were required.
The Group is yet to assess the full impact of new standards and
amendments that are not yet effective and have not been early
adopted by the Group 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
(a) Subsidiaries
The consolidated financial statements include the financial
statements of the Company and its subsidiaries. The financial
statements of subsidiaries are included in the consolidated
financial statements from the date that control commences until the
date that control ceases. Losses applicable to the non-controlling
interests in a subsidiary are allocated to the non-controlling
interests even if doing so causes the non-controlling interests to
have a deficit balance.
Investments in subsidiaries are accounted for at cost less
impairment. Cost is adjusted to reflect changes in consideration
arising from contingent consideration amendments. Cost also
includes direct attributable costs of investment.
Inter-company transactions, balances and unrealised gains on
transactions between Group companies are eliminated; unrealised
losses are also eliminated unless the cost cannot be recovered.
The Company and its subsidiaries outside the Russian Federation
maintain their financial statements in accordance with IFRSs as
adopted by the EU. The Russian subsidiaries of the Group maintain
their statutory accounting records in accordance with the
Regulations on Accounting and Reporting of the Russian Federation.
The consolidated financial statements are based on these statutory
accounting records, appropriately adjusted and reclassified for
fair presentation in accordance with International Financial
Reporting Standards as adopted by the EU.
1.3 Segment reporting
Segmental reporting follows the Group's internal reporting
structure. 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.
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 2014 were
-- GBP 1.5532: US$ (2013: GBP 1: US$ 1. 6488)
-- EUR 1.2148: US$ (2013: 1.374)
-- US$ 1:56.2584 RUR. (2013: US$ 1: RUR. 32.729)
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$5,000 3-4 years
Vehicles and other 2-7 years
1.7 Inventories
Crude oil inventories are stated at the lower of cost of
production and net realisable value. Materials and supplies
inventories are recorded at average cost and are carried at amounts
which do not exceed the expected recoverable amount from use in the
normal course of business. Cost comprises direct materials and,
where applicable, direct labour plus attributable overheads based
on a normal level of activity and other costs associated in
bringing inventories to their present location and condition.
1.8 Trade and other receivables
Trade and other receivables are recorded initially at fair value
and subsequently measured at amortised cost using the effective
interest method, less provision for impairment. A provision for
impairment of trade receivables is established when there is
objective evidence that the Group will not be able to collect all
amounts due according to the original terms of the receivables. The
amount of the provision is the difference between the asset's
carrying amount and the present value of estimated future cash
flows, discounted at the original effective interest rate.
2. Cost of sales and administrative expenses - Group
Cost of sales and administrative expenses are as follows:
Year ended 31 December 2014 2013
US$ 000 US$ 000
Production expenses 9,530 7,777
Mineral extraction taxes 8,344 8,095
Depletion, depreciation
and amortisation 4,640 2,579
----------------------- --------------------
Cost of Sales 22,514 18,451
======================= ====================
Total expenses are analysed
as follows:
Year ended 31 December 2014 2013
US$ 000 US$ 000
Mineral extraction tax 8,344 8,095
Exploration & evaluation - 2,519
Salaries & staff benefits 2,896 3,048
Depreciation & amortisation 4,656 2,611
Directors' emoluments and
other benefits 810 808
Field operating expenses 7,805 5,946
Audit fees 199 286
Taxes other than payroll
and mineral extraction 82 86
Legal & consulting 909 374
Write-off of development
assets - 1,439
Fines and penalties 99 343
Other 871 883
----------------------- --------------------
Total 26,671 26,438
======================= ====================
3. Other gains and losses - Group
Year ended 31 December 2014 2013
US$ 000 US$ 000
--------------------- ------------------
Foreign exchange gain/(loss) 3,263 (306)
Mineral Extraction Tax refund - 1,939
Other gains 27 15
--------------------- ------------------
Total other gains and losses 3,290 1,648
===================== ==================
Mineral extraction tax refund related to amounts over-charged in
2009, 2010 and 2011.
4. Intangible assets - Group
Intangible assets represent exploration and evaluation assets
such as licenses, studies and exploratory drilling, which are
stated at historical cost.
Work in progress: Exploration Total
exploration and
and evaluation evaluation
At 1 January 2013 350 9,296 9,646
Additions - 17 17
Impairments (67) (2,452) (2,519)
------------------ ----------------- -----------------
At 31 December 2013 283 6,861 7,144
Exchange adjustments (25) (681) (706)
------------------ ----------------- -----------------
At 31 December 2013 258 6,180 6,438
================== ================= =================
Work in progress: Exploration Total
exploration and
and evaluation evaluation
At 1 January 2014 258 6,180 6,438
Movements during
the year - - -
------------------ ----------------- -----------------
At 31 December 2014 258 6,180 6,438
Exchange adjustments (107) (2,585) (2,692)
------------------ ----------------- -----------------
At 31 December 2014 151 3,595 3,746
================== ================= =================
5. Property, plant and equipment - Group
Movements in property, plant and equipment, for the years ended
31 December 2014 and 2013 are as follows:
Development Land Producing Other Total
Cost assets & buildings assets
US$ 000 US$ 000 US$ 000 US$ US$
000 000
At 1 January
2013 13,773 1,262 97,362 808 113,205
Additions 5,579 274 73 - 5,926
Impairments (1,302) - (17) - (1,319)
Transfers (7,872) - 7,872 - -
--------------------- --------------- ------------- ----------- ---------
At 31 December
2013 10,178 1,536 105,290 808 117,812
Accumulated depreciation
At 1 January
2013 - - (9,014) (488) (9,502)
Depreciation - - (2,545) (63) (2,608)
At 31 December
2013 - - (11,559) (551) (12,110)
Exchange adjustments (1,008) (90) (6,309) (23) (7,430)
--------------------- --------------- ------------- ----------- ---------
At 31 December
2013 9,170 1,446 87,422 234 98,272
===================== =============== ============= =========== =========
Impairment of US$1.3 million in 2013 relates to amounts of
Property Plant and Equipment associated with redundant assets.
Cost Development Land Producing Other Total
assets & buildings assets
US$ 000 US$ US$ 000 US$ US$
000 000 000
At 1 January 2014 9,170 1,446 98,439 784 109,839
Additions 5,547 - 82 - 5,629
Transfers (901) - 901 - -
--------------------- --------------- -------------- --------------- -------------
At 31 December
2014 13,816 1,446 99,422 784 115,468
Accumulated depreciation
At 1 January 2014 - - (11,017) (551) (11,568)
Depreciation - - (4,635) (49) (4,684)
--------------------- --------------- -------------- --------------- -------------
At 31 December
2014 - - (15,652) (600) (16,252)
Exchange adjustments (5,293) (604) (35,418) (82) (41,397)
--------------------- --------------- -------------- --------------- -------------
At 31 December
2014 8,523 842 48,353 102 57,819
===================== =============== ============== =============== =============
6. Non-current assets - Group
As at 31 December 2014 2013
US$ 000 US$ 000
-------- --------
VAT recoverable 24 633
Other non-current assets 44 76
-------- --------
Total other non-current assets 68 709
======== ========
Management believes that it may not be able to recover all VAT
specific to license and exploration and evaluation contractors'
payments within the 12 months of the balance sheet date. Therefore
this VAT is classified as a non-current asset.
7. Term deposits, cash and cash equivalents
At 31 December 2014 2013
----------------- ------------
US$ 000 US$ 000
Cash at bank and on
hand 15,767 2,836
Short term bank deposits - 5,245
Total cash and cash
equivalents 15,767 8,081
An analysis of Group deposits, cash and cash equivalents by bank
and currency is presented in the table below:
At 31 December 2014 2013
--------------- ---------------
Bank Currency US$ 000 US$ 000
United Kingdom
Barclays Bank PLC USD 6,943 311
Barclays Bank PLC GBP 180 2
Russian Federation
Unicreditbank RUR 123 206
Unicreditbank USD 3,492 283
ZAO Raiffeisenbank RUR 2,986 6,485
ZAO Raiffeisenbank USD 1,970 629
ZAO Raiffeisenbank EUR 15 17
Other banks and cash
on hand RUR 58 148
Total cash and cash equivalents 15,767 8,081
=============== ===============
8. Inventories
At 31 December 2014 2013
US$ 000 US$ 000
Production consumables
and spare parts 1,060 1,713
Crude oil inventory 39 80
-------------- ------------
Total inventories 1,099 1,793
============== ============
9. Other receivables
Group Company
At 31 December 2014 2013 2014 2013
US$ 000 US$ US$ US$
000 000 000
VAT receivable 81 138 31 29
Prepayments 202 835 - -
Trade receivables 579 1,812 - -
Other accounts
receivable 56 84 - -
-------------- ------------- ----------- -----------
Total other
receivables 918 2,869 31 29
============== ============= =========== ===========
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.
10. Accumulated profit/(loss) - Group and Company
Group
At 31 December 2014 2013
US$ 000 US$ 000
----------- ----------------
Retained losses (30,779) (39,338)
Profit/(loss) for
the year 13,058 8,559
Equity dividends paid (3,038) -
Cancellation of share 165,873 -
premium
----------- ----------------
Accumulated profit/(loss) 145,114 (30,779)
=========== ================
On 9 July 2014 the capital reduction approved by shareholders at
the Company's Annual General Meeting on 6 June 2014 became
effective following confirmation by the High Court, the filing of
the Court Order and a Statement of Capital with Companies House and
the fulfilment of certain minor undertakings given to the Court. As
a result, the Share Premium Account of the Company, amounting to
US$165.9 million, was cancelled and the equivalent sum credited to
the Company's Profit and Loss Account, thereby creating
distributable reserves.
11. Trade and other payables
At 31 December 2014 2013
US$ 000 US$ 000
--------------------- ----------------
Trade payables 268 432
Taxes other than profit
tax 881 2,547
Customer advances 524 890
--------------------- ----------------
Total 1,673 3,869
===================== ================
The maturity of the Group's and of the Company's financial
liabilities are all between 0 to 3 months.
This information is provided by RNS
The company news service from the London Stock Exchange
END
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