TIDMRPO
RNS Number : 3642K
RusPetro plc
16 April 2015
Ruspetro plc
16 April 2015
Ruspetro plc ("Ruspetro" or the "Company")
Preliminary Unaudited Results for the Year Ended 31 December
2014
London, 16 April 2015: Ruspetro plc (LSE: RPO), an independent
oil and gas development and production company with assets in the
Western Siberia region of the Russian Federation, announces today
its results for the full year ended 31 December 2014, and an update
on its operations to date.
Financial Highlights
ü Successful completion of financial restructuring in December
2014. As a result, US$52.3m of new equity was
raised, US$358.1m of existing debt and put option obligations
were refinanced through a US$150m loan with Bank
Otkritie Financial Corporation ("Otkritie"), with the remaining
US$208.1m converted into a 25% equity position
held by Mastin Holdings Limited.
ü Revenues of US$55.1m (down 31% Y-o-Y) due primarily to a 26%
decline in liquids production, and a 9% decline in the realized oil
price Y-o-Y.
ü Full year EBITDA (1) of US$9.5m vs. US$13.0m in 2013, driven
mostly by the decline in production, and oil price, partially
offset by Mineral Extraction Tax ("MET") relief from September
2013. EBITDA per barrel of liquids was US$7.4 in both 2013 and
2014.
ü Strengthened our partnership with Glencore by extending our
export prepayment facility in March 2014 and entering into two
domestic facilities in May 2014 and October 2014.
ü Net loss of US$262.9m vs. net loss of US$74.2m in 2013, driven
mostly by the foreign exchange loss on US dollar denominated loans
to the Group's Russian subsidiaries (US$202.4m). After eliminating
the effect of foreign exchange losses from both years, 2014 loss
was US$60.5m against US$48.6m in 2013. Secured a US$100.0m
development facility and US$44.7m working capital facility from
Otkritie to fund a refocused appraisal and development
programme.
ü Net debt decreased by US$152.3m from US$387.4m at the
beginning of the year to US$235.1m end 2014.
Operational Highlights
ü Oil production in 2014 averaged 3,523 bopd, a 14% decrease
compared to 2013. In January 2014, suspended production of gas and
condensate in the Palyanovo field primarily to conserve gas while
we engage in discussions to commercialise these gas reserves.
ü The production performance of the Group's first two horizontal
wells was encouraging (ten day flow tests averaged 1,350 and 900
bopd for wells 214 and 251, respectively)
o Spudded our first multiple fractured horizontal well (214)
(MFHW) in April 2014.
o in our second well (251), introduced for the first time in
Russia innovative completion technology customized to our
geological environment.
ü Successful focus on safety in our operations including
implementation of the EMEX system to manage HSE performance. One
minor lost time injury in 2014.
ü Extended the subsoil license for the Vostochno-Inginsky block
until 2034.
Post Period End
Since the end of 2014, two MFHW (wells 212 and 216) have been
drilled. Both encountered extensive sands (642m net oil sand within
a horizontal section of 1149m in well 212, and 516m net oil sand
within a horizontal section of 961m in well 216). These will be
completed using our flexible fracturing system which allows us to
optimise the location and size of the hydraulic fractures to the
sand distribution encountered in the well. These two wells will
come on stream in April/May 2015, respectively.
John Conlin, Chief Executive Officer, commented:
"Despite the challenging business environment 2014 has been a
year of important progress for Ruspetro. We have successfully
introduced a new approach to fracturing our new generation
horizontal wells. We have also introduced other key technologies to
extract maximum insight into the subsurface, and hence de-risk our
development programme in the future. Towards the end of the year we
transformed our balance sheet and put in place a credit facility to
fund our development activities. Given the current low and volatile
oil price environment, this will be used cautiously to fund a
modest appraisal and development programme in 2015, as the
springboard for an accelerated push in the medium term."
Enquiries:
Ruspetro plc
John Conlin, Chief Executive Officer +44 (0) 2078 877624
Alexander Betsky, Finance Director +44 (0) 2078 877624
Finlay Thomson, Investor Relations +44 (0) 7976 248471
FTI Consulting
Ben Brewerton, George Parker +44 (0) 2037 271000
About Ruspetro
Ruspetro plc is an independent oil & gas development and
production company, listed on the premium segment of the London
Stock Exchange (LSE: RPO). The Company's operations are located on
three contiguous licence blocks in the middle of the Krasnoleninsk
Arch in Western Siberia. Ruspetro assets include proved and
probable (2P) reserves of over 2.0 bnboe.
Glossary
bopd - barrels of oil per day
Chairman's Statement
In 2014, for a small exploration and production company
operating with a technically challenging portfolio, the business
environment in Russia could hardly have been more difficult.
In the middle of the year, ambiguity about the impact of
sanctions on the business forced Ruspetro into both clarifications
and contingency arrangements to ensure that operations were not
hampered. In due course, that uncertainty was clarified and our
technology has been cleared for use.
Thereafter, what started as a modest decline in the oil price to
below US$100 per barrel in the third quarter became a headlong
plunge, coupled with a slump in the value of the ruble. While some
stability has emerged in recent months in both the oil price and
ruble/dollar exchange rate, the credibility of forecasters has
gone, and we expect to live with both volatility and uncertainty
for the medium term.
This macro-economic business context makes the transformational
restructuring transaction that we competed in December all the more
remarkable. Our liabilities (including debt and put option
obligations) were reduced by US$218.8 million, while we raised
US$52.3 million of new equity, and arranged loan facilities of up
to US$144.7 million, in aggregate, for development and working
capital.
More important perhaps than the numbers is the relationship now
established between Ruspetro and Bank Otkritie Financial
Corporation ("Otkritie"), currently the largest private bank in
Russia by assets. Otkritie and Sergey Gordeev are now our main
lender and largest shareholder, respectively, and we are delighted
that Sergey has joined our Board.
Successfully raising substantial development funds is a major
milestone for the Company, and while the fall in oil prices
impacted our revenues, the weakening of the ruble has driven down
our dollar cost base such that we can drill economically attractive
production wells at current oil prices. Nevertheless, given the
extended period of low and volatile oil prices, the Board has
decided that a cautious capital expenditure programme and a
cautious use of loan facilities in 2015 is in the best interests of
the Company, and that the capital invested should focus on maturing
development opportunities for the medium term. This philosophy is
outlined below in the CEO's review.
It remains unclear how the oil and gas industry in Russia will
respond in the medium term. A material reduction in activity seems
unlikely given the dollar-equivalent cost reduction that all
operators will experience. However, we can expect some
opportunities to drive costs down further as service providers
manage cash flow.
Our focus is on positioning Ruspetro for the medium term:
understanding our reservoirs, managing risk, applying the right mix
of technologies, enhancing our reputation as an innovative company
and creating value from every well that we drill. In the medium
term, this is expected to build substantial shareholder value.
When 2014 started, there was a strong sense of optimism in
Russia, particularly given the Winter Olympics in February. The
dramatic events since, including ruble devaluation and unexpected
crash in oil prices, have caused anxiety, and their consequences
remain to be seen. However, within Ruspetro, we have made
substantial progress in the way that we operate and think. We have
rebuilt our technical core and our technical credibility. On behalf
of the Board, I would like to thank all our staff for their efforts
under difficult circumstances and in particular welcome to the team
those who have come on board in the last 12 months.
I would also like to thank our new partners for the confidence
they have shown in joining the Ruspetro project. We welcome them as
shareholders and in particular welcome Sergey Gordeev to the Board.
We have a highly experienced team of non-executive directors on the
Board and I would like to thank them for their invaluable input and
challenge. Lastly, I thank our shareholders for their support as we
have navigated our way through difficult macroeconomic conditions
affecting the oil industry. The course we have set should position
Ruspetro to make significant progress in 2015.
CEO's Review
The working environment in which Ruspetro staff and our
contractors operate is particularly challenging. Since joining
Ruspetro, it has been one of my top priorities to build upon and
enhance our health, safety and environmental ("HSE") awareness and
performance.
In 2014, we appointed a HSE director to oversee our HSE
practices, improve policies and ensure that we approach HSE issues
in the most direct and effective manner. In addition, we
successfully implemented the EMEX platform as a tool to log,
monitor and action HSE improvements across all operational areas. I
am pleased to report only one minor lost-time incident in 2014
relating to a slip and fall. Our aim is to continue our positive
HSE momentum in the coming year.
Achievements in 2014
In April 2014, we introduced multiple fractured horizontal wells
into our operations. Initially this was rather simplistically
conceived as a way of connecting the discontinuous sands that, with
hindsight, had contributed to the poor outcome of the vertical well
development programme in 2012-13.
However, by the second well, we had introduced a radical change
in fraccing and completion thinking, abandoning the standard
Western Siberian approach of a small number of large fracs, and
moving to a concept based on a larger number of smaller fracs tuned
to the sand distribution seen in the well. This required us to
source technology proven in North America but hitherto unused in
Russia.
Similarly, we have introduced a number of other internationally
established technologies to ensure that we maximise the insight
from these early wells. These include geo-steering in the
horizontal sections to assess sand continuity, and the use of
tracers to assess the effectiveness of the fracs in each well. This
knowledge has been embodied in the design of the wells that are to
be drilled and completed by the second quarter of 2015.
While I am impressed by the progress that we have made with our
first two horizontal wells and the follow-up in early 2015, the
reality is that we are still developing our understanding of the
geology and in particular the possible play types in our acreage.
Our efforts at geological characterisation in the last year have
been hampered by a chronic geological data shortage resulting from
missed data collection opportunities in the first frantic
development campaign in 2012-13. Furthermore, we are only just
beginning to capitalise on the seismic contribution to unlocking
our reserves. The bottom line is that that we have an immature
resource base outside the core area.
Given this blunt assessment, the Board has endorsed a strategy
starting in the second half of 2015 of an appraisal campaign
designed to mature between 25 and 75 development wells. This
programme, which includes both vertical and horizontal wells, will
underpin a resumption of our development well campaign in 2016,
when we believe oil prices may have partly rebounded.
This strategy will have two key additional benefits:
-- With an inventory of de-risked development wells, we will be
able to plan and deliver a sustainable improvement in drilling and
completion performance by driving learning, leveraging the market
for services, and improving our operating practices.
-- It will provide a sound basis for the generation of a
coherent facilities plan based on a more realistic view of our
future production levels and precisely where in our acreage they
are being generated.
Palyanovo
In January 2014, we suspended production of gas and condensate
in the Palyanovo field, primarily to conserve gas while we
evaluated further options to commercialise the gas reserves.
Discussions are progressing with an international counterparty in
this regard. In the meantime, we are taking the opportunity of the
suspension of production to collect key sub-surface data with a
view to updating the gas field development plan in 2015. During
2015, we will also update our Russian reserves for the Palyanovo
licence ahead of its planned renewal by the year-end.
Aims for 2015
Our objectives for 2015 are to:
-- Increase oil production by squeezing our existing stock of
oil production wells and improving water-flood effectiveness in the
core Pottymsko Inginsky ("PI") area.
-- Complete our horizontal development well rollout in the area of pad 23b.
-- Initiate an appraisal campaign to build an inventory of
mature development locations. Four areas are currently targeted in
this campaign.
-- Mature our development toolkit (technology, design, cost,
execution). For example: the application of geosteering, seismic
visualisation, novel well designs, optimised completion technology,
rig strategies, etc.
-- Implement fit-for-purpose infrastructure enhancements to support the programme.
-- Radically improve our understanding of the gas reserves and
production potential of Palyanovo.
Costs and cash management
The restructuring transaction, while transformational for the
longer term, was highly complex and inevitably time-consuming.
Nevertheless, we were able to make a start with our horizontal well
programme, using oil pre-payment facilities and an additional loan
from Limolines Transport Limited ("Limolines"), one of our main
shareholders.
These early wells represent the evolution of our development
thinking and technology application. Perhaps as importantly, they
have driven a fundamental rebuild in our drilling services
contracting strategy and allowed us to deliver a highly competitive
benchmark well cost for the future.
Despite the availability of new funds, a lower oil price is our
reality. We will continue with a highly disciplined approach to
managing our cash. As we have successfully done with our drilling
costs, we will continue our drive to reduce to the greatest extent
possible dollar-denominated services, and perhaps capitalise on the
assumed slowdown in Russia to look for keen bids for any new
capital expenditure.
Operational Review
Production
The Group's total liquid production in 2014 averaged 3,541
boepd, down 26% from the 4,797 boepd in 2013. Average oil
production was 3,523 boepd, 14% lower than the 4,082 boepd in 2013.
Average condensate production from the Group's Palyanovsky licence
area declined from 1,352 boepd in the first quarter of 2013 to 330
boepd in the fourth quarter, down 75%, leading to the decision to
suspend production in February 2014 to conserve gas for future
commercialisation. The Group's oil production in the fourth quarter
of 2014 averaged 3,580 bopd, down 7% from 3,854 boepd in the third
quarter.
In 2014, the Group initiated a horizontal drilling campaign
based on multi-stage fractured horizontal production wells. Three
horizontal wells were spudded in 2014 as part of this campaign
(wells 214, 251 and 212), two of which were successfully completed
within 2014 (wells 214 and 251).
The Group began drilling its first horizontal well, number 214,
in April. The pilot well encountered 19 metres of oil-bearing
sands. Three large fractures were placed in the well's 600-metre
horizontal section and the well came online at the beginning of
July as planned. The 10-day flow test yielded 1,350 barrels of oil
per day (bopd) using an electrical submersible pump. By the end of
2014, the well was producing at 615 bopd, as expected.
The Group's second horizontal well, number 251, was spudded in
June and a pilot well was drilled as planned. This well encountered
eight metres of net oil sand, which was at the low end of
expectations. Two sidetracks were thereafter required to overcome
challenging hole conditions prior to entering the horizontal
section. In this well, the Group employed, for the first time in
Russia, a completion system designed and implemented by NCS Energy
Services, an independent technology and services company
specialising in multistage completions (NCS Mongoose completion
system). The system allows for a larger number of customised
fractures to be placed along the horizontal wellbore than the
completion technology previously available in the country and used
for completion of well 214. It also allows for greater fracturing
speed and flexibility than the completion system previously used by
the Group, as the process eliminates the need for perforation and
the plugging of each section and enables multiple sequential
fracture operations. Eight fractures were successfully placed along
the 890-metre horizontal section of the wellbore, precisely
targeting the reservoir intervals of interest. The planned
installation of an electrical submersible pump was completed in
October. A 10-day flow test for this well averaged 900 bopd at
approximately 25% watercut.
The Group's third horizontal well, number 212, was designed to
have a 1,000-metre horizontal section with 12 fractures. It was
spudded on 17 December and is expected to be completed in the
second quarter of 2015.
The production performance of the Group's first horizontal wells
is encouraging. Equally exciting is the introduction of innovative
yet proven completion technologies into the Group's operations,
which we believe will make a positive contribution to value
creation for our shareholders.
Reservoir management and waterflood
As at the end of 2014, the Group had a stock of 34 producing
wells and seven injector wells. During the year, a comprehensive
review of the response to the waterflood programme was carried out
as part of the ongoing reservoir management plan in the producing
field. One producing well was converted to a water injection well
in the first half of 2014, giving a total of seven active injector
wells in the main production area of the field.
Out of 24 producing wells subject to waterflooding, nine
producing wells show consistently increasing oil production rates
in response to pressure support. A comprehensive tracer campaign
has been initiated to assist in further optimisation of the
waterflood.
The Group's subsurface team set about expanding and refining the
waterflood programme such that crude oil production towards the end
of the year stabilised. The waterflood was more compartmentalised
than had been originally envisaged, in line with the findings from
our 3D-seismic reprocessing.
In 2014, the Group continued to interpret the 3D seismic data
that covers 42% of the field. The results showed structural and
stratigraphic compartmentalisation in our main area of production.
This poses challenges for an effective waterflood programme and
demonstrates why production results from vertical wells can vary
drastically over quite small distances. These findings add to our
knowledge of the field and enable us to be more confident about
selecting drilling locations and appropriate well technologies
going forward.
Resource potential
DeGolyer & MacNaughton ("D&M") conducted a reserve audit
for the Group as at 30 June 2014, based on the horizontal well
development programme for the first time. Proved reserves were 258
million barrels of oil equivalent (boe), up 15% from the previous
estimate of 225 million boe. Mid-year 2014 proved plus probable
reserves were 2.0 billion boe, up 6% from the 2013 year-end
estimate of 1.9 billion boe. Of these reserves, natural gas
comprises 51 million boe of proved reserves and 201 million boe of
proved and probable reserves.
Oil & Condensate Sales Gas Total
------------- --------------------------- --------------------------- ---------------------------
31 December +/- vs 31 December +/- vs 31 December +/- vs
2014, 31 December 2014, 31 December 2014, 31 December
mnbbl 2013, mnbbl 2013, mnbbl 2013,
mnbbl mnbbl mnbbl
------------- ------------ ------------- ------------ ------------- ------------ -------------
Proved
Developed 5.9 -6.8 0.0 -16.1 5.9 -22.9
------------- ------------ ------------- ------------ ------------- ------------ -------------
Total
Proved 206.0 15.3 51.3 17.5 257.3 32.8
------------- ------------ ------------- ------------ ------------- ------------ -------------
Proved
+ Probable 1745.4 79.0 252.0 19.5 1997.4 98.5
------------- ------------ ------------- ------------ ------------- ------------ -------------
The Group has 5.9 million barrels of proved developed oil and
condensate reserves. This compares to 12.7 million barrels as at 31
December 2013. The decrease is primarily attributable to the
reclassification of condensate reserves from proved developed to
proved undeveloped in the Palyanovo licence area. D&M estimated
contingent resources in the Bazhenov oil shale formation at 3.5
billion boe in place.
In line with industry best practices, the Group has decided to
change the independent reserves auditor from D&M to another
international auditing firm. The selection is expected to be made
in the first half of 2015, followed by a full-year report by the
end of 2015.
Macro-environment in 2014
From a macro-environment perspective, 2014 proved a challenge in
several respects. First, Russia experienced a turbulent year due to
the geopolitical crisis in Ukraine, as the economic sanctions
targeted against Russia have been imposed on certain individuals,
financial institutions, state-controlled companies, technologies
and equipment in the financial, defence and energy sectors. Second,
the crude oil price, though averaging almost US$100 per barrel in
2014, compared with US$109 in 2013, dropped dramatically in the
fourth quarter of 2014. Having peaked in June 2014 at US$115, the
Brent crude oil price had dropped to US$57 by the year-end, due to
slower growth in major oil-consuming countries, soaring production
of hard-to-extract crude oil in the US and Canada, and OPEC's
decision to maintain production levels.
At the same time, the difficult macro-environment brought some
significant operational benefits through the devaluation of the
Russian ruble, functional currency of the Group's operating
companies. With oil and gas production generating the majority of
hard-currency revenues of Russian companies and the government, the
decline in the oil price weakened the ruble exchange rate from 32
to the US dollar on 1 January 2014 to a low of 67 on 16 December
2014. While the ruble/dollar exchange rate averaged 35.4 during the
nine months ending 30 September 2014, it plummeted in the fourth
quarter, paralleling the slump in the Brent price. The ruble's
dramatic fall has cushioned the Group's exposure to the oil price
decline, as it is estimated that 90% of its operating expenses, 80%
of capital expenditures and 40% of SG&A in 2015 are denominated
in rubles. The effect of this devaluation is expected to bring
significant savings in 2015 in terms of operating costs, CAPEX and,
to a lesser extent, SG&A.
Sales and marketing
The Group's total production in 2014 was some 1.3 million boe,
or an average of 3,541 boepd. In 2014, the Group exported 448
thousand boe and sold 854 thousand boe of crude oil and 7 thousand
boe of condensate on the domestic market, compared with 261
thousand boe, 1.2 million boe and 258 thousand boe in 2013,
respectively. All export volumes were delivered under the Glencore
export prepayment facility and 49% of domestic volumes were
delivered to Energo Resours, a subsidiary of Glencore, under both
domestic prepayment facilities signed in 2014.
In 2014, export sales revenue was US$40.8 million (US$18.8
million after export duty), domestic crude oil revenue was US$35.0
million, and condensate revenue was US$0.3 million. In 2013, export
sales revenue was US$27.4 million (US$13.3 million after export
duty), domestic crude oil revenue was US$54.0 million, and
condensate revenue was US$11.3 million.
Export deliveries were contracted to Glencore via the Transneft
pipeline system and freight terminal in Primorsk: 80% of domestic
sales volumes were delivered via pipeline (compared with 60% in
2013) and 20% by rail and truck (compared with 40% in 2013).
Financial Review
Financial summary
Revenues were US$55.1 million in 2014, compared with US$79.8
million in 2013, while earnings before interest, tax, depreciation
and amortisation ("EBITDA") were US$9.5 million, compared with
US$13.0 million. The drop in revenues was primarily driven by a 14%
reduction in average oil production, a 9% fall in the average oil
price, and the termination of condensate sales.
The drop in EBITDA was primarily driven by the 14% decline in
crude oil production, a loss of gross margin from the cessation of
condensate sales and a 9% fall in the average oil price. The effect
was offset by a substantial saving from reduced MET following
changes in tax legislation in relation to tight oil reservoirs
available to the Group since September 2013.
Cost of sales
The cost of sales, including depreciation and production-related
taxes was US$51.7 million in 2014, compared with US$65.9 million in
2013. The decrease was primarily driven by a US$20 million
reduction in MET due to a full year's 80% MET relief benefit
conferred to the Group starting September 2013, along with a
marginal benefit from the ruble depreciation towards the end of
2014, and savings of US$1 million in production services. These
savings, however, were offset by a US$6.2 million increase in
depletion expenses in 2014 due to temporary suspension of
operations at Palyanovo, along with a US$1.1 million increase in
repair and maintenance expenses and employee benefit expenses.
Selling and administrative expenses (S&A)
S&A expenses include oil transportation costs, payroll
expenses, rent, professional services, property and land taxes,
depreciation, IT and telephony, and other expenses.
S&A expenses in 2014 amounted to US$20.8 million, down 7%
from US$22.5 million in 2013. The decrease resulted from savings,
mostly in professional services, IT and telephony, travel and
depreciation, offset by increases in payroll expenses (including
severance) and oil transportation expenses as a result of higher
export volumes year-on-year in 2014.
Comprehensive loss for the year and foreign exchange
The Group recorded a loss of US$262.9 million for 2014, compared
with US$74.2 million in 2013. The 2014 result includes a
foreign-exchange loss of US$202.4 million, compared with US$25.6
million in the previous year. The Group's operating companies,
whose functional currency is the Russian ruble, have borrowings in
US dollars. As a result of the ruble devaluation, those borrowings
in ruble terms have substantially increased, resulting in the
accounting recognition of US$202.4 million in foreign-exchange
losses. After deducting the foreign-exchange losses from both
years, the Group's loss would have been US$60.5 million in 2014,
compared with US$48.6 million in 2013.
Balance sheet
The Group's balance sheet has been transformed due to the
completion of the restructuring in December 2014 along with the
effects of the ruble depreciation.
The Group's restructuring comprised the following key
components:
-- A restructuring of the existing US$337.9 million Sberbank
credit facility along with a Sberbank capital put option valued at
around US$20.2 million. These were together exchanged for a new
US$150 million five-year loan from Otkritie, with the conversion of
the remaining US$208.1 million by Mastin Holdings Limited
("Mastin"), a company beneficially owned by Sergey Gordeev, into
25% of the Company's enlarged issued equity share capital.
-- A five-year development facility of up to US$100 million was
entered into with Otkritie for the purposes of financing the
Group's field development.
-- A five-year credit facility of up to US$44.7 million was
entered into with Otkritie for general working capital purposes
with drawdown available until the end of June 2016.
-- The extension of shareholder loans from Makayla Investments
("Makayla") from 2015 to 2016 and Limolines from 2018 to 2020;
US$5.0 million is due to be repaid to Makayla in May 2015.
-- A raising of gross proceeds of GBP32.9 million (around
US$52.3 million) from a placing and open offer. This included the
offset of a US$10.7 million short-term Limolines loan against
Limolines' subscription for the new shares in the placing and open
offer.
As a result of the Restructuring alone, the Group's total debt
decreased by US$198.6 million, current liabilities decreased by
US$20.2 million, total equity increased by US$256.2 million, and
total cash on hand increased by US$41.6 million before
transaction-related fees. Transaction fees totalled US$ 5.7 million
and the Group's net debt decreased by US$240.2 million.
The completion of the restructuring helped to reduce net debt
significantly in 2014. Specifically, net debt decreased by US$152.3
million, from US$387.4 million at the beginning of 2014 to US$235.1
million at the end. Other current and non-current liabilities
decreased by US$74.4 million to US$81.1 million by the year-end,
from US$ 155.5 million at the end of 2013. Among other things, this
reflected the conversion of the Sberbank capital put option, a
decrease in deferred tax liabilities, and a decrease in trade and
other payables. Despite an increase of total equity by US$ 256.2
million as part of the restructuring, the Group's total equity
decreased by US$ 19.6 million in 2014, from US$95.3 million to
US$75.7 million, mainly due to the magnitude of foreign-exchange
losses associated with the ruble depreciation.
Cash flow
In 2014, the Group generated a net cash inflow from operating
activities of US$9.0 million, resulting from positive operating
cash flow of US$7.8 million and a positive cash contribution from
changes in working capital of US$1.2 million. The latter resulted
from the collection of receivables, as well as from the significant
ruble depreciation during 2014, leading to a major decline (when
expressed in US dollars) in ruble-denominated accounts payable
balances.
During the year, the Group spent US$49.6 million on investment
activities. This consisted of US$23.9 million on the construction
of new wells, US$1.9 million on rig mobilisation and
demobilisation, US$10.8 million on infrastructure-related capital
expenditures, US$1.3 million on development studies, US$2.6 million
on the purchase of intangible and other assets, and US$9.2 million
for capital expenditures related to activities before the
initiation of the Group's horizontal well development programme in
2014.
The Group received US$37.4 million (net of costs) from the issue
of new shares in December 2014 through the Company's open offer and
placing. It also received loan proceeds of US$10 million from
Limolines in August 2014. In addition, loan proceeds from Otkritie
totalling US$148.5 million (net of arrangement fees of US$1.5
million) were received in December 2014. The Group utilised these
immediately, as part of the restructuring, to repay the US$150
million outstanding under the Sberbank credit facility then
owned by Mastin.
Financing of Ruspetro's current operations and future
development
Following the restructuring and the extension of shareholder
loans, together with the additional US$100 million development
facility available (subject to continuing to meet the drawdown
conditions), the Group is able to continue the implementation of
its horizontal well programme in the near future. The Group's focus
on production is critical to its success, as the terms for its
restructured debt finance require the Group to achieve certain
annualised EBITDA and production covenants that will be tested
quarterly from January 2016. The Group is required to monitor
closely its ability to meet such covenants throughout the year, and
this will depend largely on the drilling of additional horizontal
wells and on foreign-exchange and oil price movements. Given the
current financial position, the management considers that financial
statements should be prepared on a going concern basis.
Outstanding debt obligations
Debt Principal Accrued Total as at Maturity Annual Interest
Interest 31 Dec 2014 Rate
Nov
Otkritie $147.8 - $147.8 -19 8%pa
Makayla $15.0 8.3 $23.3 Oct-16 Libor +10%
Limolines $48.7 27.1 $75.8 Feb-20 3M Libor +10%
Past
Crossmead $0.3 - $0.3 Due 0%
Ruspetro Plc
PRELIMINARY UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
AS AT AND FOR THE YEAR ENDED 31 DECEMBER 2014
Unaudited Consolidated Statement of Profit or Loss and Other
Comprehensive Income for the year ended 31 December 2014
(presented in US$ thousands, except otherwise stated)
Year ended 31
December
---------------------
2014 2013
---------- ---------
Revenue 55,100 79,849
Cost of sales (51,688) (65,900)
---------- ---------
Gross profit 3,412 13,949
Selling and Administrative
expenses (20,822) (22,468)
Other operating (expenses)
/ income (1,160) (2,086)
---------- ---------
Operating loss (18,570) (10,605)
Finance costs (37,965) (32,996)
Foreign exchange loss (202,410) (25,586)
Other expenses (4,443) (5,062)
---------- ---------
Loss before income tax (263,388) (74,249)
Income tax benefit 495 11
Loss for the period (262,893) (74,238)
========== =========
Other comprehensive (loss)/
income that may be
reclassified subsequently
to (loss)/ profit, net of
income tax
Exchange difference on translation
to presentation currency (9,832) (11,063)
Total comprehensive loss
for the period (272,725) (85,301)
========== =========
The entire amount of loss and total comprehensive
loss for the period are attributable to equity
holders of the Company
Loss per share
Basic and diluted loss per
ordinary share (US$) (0.72) (0.22)
Unaudited Consolidated Statement of Financial Position as at 31
December 2014
(presented in US$ thousands, except otherwise stated)
31 December
2014 2013
---------- ----------
Assets
Non-current assets
Property, plant and
equipment 148,139 234,203
Mineral rights and
other intangibles 231,562 395,533
379,701 629,736
---------- ----------
Current assets
Inventories 584 1,681
Trade and other receivables 6,565 6,660
Income tax prepayment 21 35
Other current assets 5,065 -
Cash and cash equivalents 12,022 15,832
24,257 24,208
---------- ----------
Total assets 403,958 653,944
========== ==========
Shareholders' equity
Share capital 135,493 51,226
Share premium 389,558 220,506
Retained loss (429,752) (153,106)
Exchange difference
on translation to presentation
currency (44,956) (35,124)
Other reserves 25,397 11,759
Total equity 75,740 95,261
---------- ----------
Liabilities
Non-current liabilities
Borrowings 238,801 402,896
Provision for dismantlement 4,238 7,940
Deferred tax liabilities 49,457 83,502
292,496 494,338
---------- ----------
Current liabilities
Borrowings 8,303 303
Trade and other payables 25,447 43,842
Taxes payable other
than income tax 1,550 2,265
Other current liabilities 422 17,935
---------- ----------
35,722 64,345
---------- ----------
Total liabilities 328,218 558,683
---------- ----------
Total equity and liabilities 403,958 653,944
========== ==========
Unaudited Consolidated Statement of Changes in Equity for the
year ended 31 December 2014
(presented in US$ thousands, except otherwise noted)
Exchange
difference
on translation
Share Share Retained to presentation Other Total
capital premium earnings currency reserves equity
Balance as at
1 January 2013 51,226 220,506 (87,741) (24,061) 20,517 180,447
========= ========= ========== ================= ========== ==========
Loss for the period - - (74,238) - - (74,238)
Other comprehensive
loss for the period - - - (11,063) - (11,063)
Total comprehensive
loss for the period - - (74,238) (11,063) - (85,301)
--------- --------- ---------- ----------------- ---------- ----------
Share options
of shareholders - - 8,873 - (8,873) -
Share-based payment
compensation - - - - 115 115
--------- --------- ---------- ----------------- ---------- ----------
Balance as at
31 December 2013 51,226 220,506 (153,106) (35,124) 11,759 95,261
========= ========= ========== ================= ========== ==========
Balance as at
1 January 2014 51,226 220,506 (153,106) (35,124) 11,759 95,261
========= ========= ========== ================= ========== ==========
Loss for the period - - (262,893) - - (262,893)
Other comprehensive
income for the
period - - - (9,832) - (9,832)
Total comprehensive
income/(loss)
for the period - - (262,893) (9,832) - (272,725)
--------- --------- ---------- ----------------- ---------- ----------
Issue of shares 84,202 168,983 - - - 253,185
Share options
of shareholders - - (13,753) - 13,753 -
Share-based remuneration
of Board of Directors 65 69 - - (115) 19
Balance as at
31 December 2014 135,493 389,558 (429,752) (44,956) 25,397 75,740
========= ========= ========== ================= ========== ==========
Unaudited Consolidated Statement of Cash Flows for the year
ended 31 December 2014
(presented in US$ thousands, except otherwise stated)
Year ended 31
December
---------------------
2014 2013
---------- ---------
Cash flows from operating
activities
Loss before income tax (263,388) (74,249)
Adjustments for:
Depreciation, depletion and
amortisation 26,992 21,748
Foreign exchange loss 202,410 25,586
Finance costs 37,965 32,996
Impairment of assets 2,137 -
Impairment of financial instruments 1,285 -
Share-based payment compensation 19 115
Other operating expenses 353 1,909
---------- ---------
Operating cash inflows before
working capital adjustments 7,773 8,105
---------- ---------
Working capital adjustments:
Change in trade and other
receivables 2,254 (1,565)
Change in inventories 1,097 886
Change in trade and other
payables 34 7,140
Change in other taxes receivable/payable (2,170) 12,347
Net cash flows from operating
activities 8,988 26,913
---------- ---------
Cash flows from investing
activities
Purchase of property, plant
and equipment (42,541) (44,106)
Purchase of financial instruments (7,062) -
Net cash used in investing
activities (49,603) (44,106)
---------- ---------
Cash flows from financing
activities
Proceeds from issue of share
capital (net) 37,466 -
Proceeds from loans and borrowings 160,000 -
Repayments of loans and borrowings (150,750) -
Interest paid (690) -
Other financing charges paid (1,500) (1,000)
---------- ---------
Net cash generated from/
(used in) financing activities 44,526 (1,000)
---------- ---------
Net increase/ (decrease)
in cash and cash equivalents 3,911 (18,193)
---------- ---------
Effect of exchange rate changes
on cash and cash equivalents (7,721) (391)
---------- ---------
Cash and cash equivalents
at the beginning of the period 15,832 34,416
---------- ---------
Cash and cash equivalents
at the end of the period 12,022 15,832
========== =========
Refer to Note 11 for the refinancing transaction that did not
require the use of cash and cash equivalents and was excluded from
the cash flow statement.
Notes to the Consolidated Financial Statements for the year
ended 31 December 2014
(all tabular amounts are in US$ thousands unless otherwise
noted)
1. Basis of preparation
These consolidated financial statements of the Group have been
prepared in accordance with International Financial Reporting
Standards (IFRS) as adopted by the EuropeanUnion. The consolidated
financial statements are prepared under the historical cost
convention, modified for fair values under IFRS.
The consolidated financial statements are presented in US
dollars (US$) and all values are rounded to the nearest thousand
unless otherwise indicated.
Sberbank credit facility restructuring
On 5 December 2014 the shareholders of the Company approved a
financial restructuring (the Restructuring) at a general meeting.
The restructuring included the issue of shares under an Open Offer
and Placing, as well as in consideration for the capitalisation of
existing indebtedness as described below.
On 9 December 2014 LLC Sberbank Capital (Sberbank Capital)
transferred its creditor rights and rights under its put option to
Mastin Holdings Limited (Mastin) in total amount of US$358,076
thousand. Part of the debt in the amount of US$150,000 thousand was
repaid by means of a five year term credit facility received on 10
December 2014 from OJSC "Bank Otkritie Financial Corporation"
(Otkritie). The remaining debt was capitalised through the issue of
new ordinary shares to Mastin, which also purchased Sberbank
Capital's shareholding in the Company's capital, resulting in
Mastin having an aggregate 25% shareholding in the Company's
enlarged issued share capital, following the Open Offer and
Placing.
On 11 December 2014 the Company completed a fully underwritten
Open Offer and a Placing at 10 pence per ordinary share, raising
United Kingdom Sterling ("GBP") 32.9 million (approximately US$52.7
million) before expenses.
The Company's obligation to repay a shareholder loan from
Limolines Transport Limited's (Limolines) with principal and
interest amounting to US$10.7 million in February 2015 (the
Limolines Loan) was off-set against Limolines' subscription for new
ordinary shares in the Placing and Open Offer. Additionally, the
Company undertook to pay US$5.0 million in respect of accrued
interest on a shareholder loan from Makayla Investments Limited in
May 2015. Total shareholder outstanding loans as at 31 December
2014 were equal to US$99.1 million.
Following the restructuring, Otkritie has commited to provide a
new development facility for up to US$100.0 million as well as a
new credit facility for up to US$44.7 million.
The guaranteed net proceeds of the Restructuring, comprising the
initial tranche of the development facility of US$50.0 million and
gross proceeds of GBP32.9 million (approximately US$52.7 million)
from the Placing and Open Offer less costs of the Restructuring of
approximately US$7.5 million, comprised approximately US$95.2
million. In addition, the Company will be able to draw down up to
US$44.7 million under the Credit Facility.
The drawdown of the development facility second tranche of
US$50.0 million (expected to be available from July 2015) is
dependent on the Group meeting certain covenants under the
development facility. Should the applicable development facility
covenants not be met or the development facility second tranche is
not drawn down, then the Company will only receive the guaranteed
net proceeds of the Restructuring.
The completion of the Restructuring occurred on 11 December 2014
with the admission of 536,310,294 new ordinary shares to listing on
the premium segment of the Official List of the UK Listing
Authority and to trading on the London Stock Exchange's main market
for listed securities (the Admission). In addition, the Company
issued 420,242 new ordinary shares in lieu of salary to certain
current and former Directors. Following the Admission, and as at
the date of these financial statements, the Company's issued share
capital comprises 870,112,016 ordinary shares.
Going concern
These consolidated financial statements are prepared on a going
concern basis.
At the reporting date the Group had net current liabilities of
US$11,465 thousand, which included cash in hand of US$12,022
thousand.
The Group's continuing operations are dependent upon its ability
to make further investments in field development in order to grow
its hydrocarbon production and sales. In the short term, this field
development is planned to involve, in particular, the drilling of a
number of horizontal wells, the success of which will only be known
with certainty once each well is completed. The first and the
second horizontal wells were drilled and launched into production
in July and October 2014 respectively. In the light of these
results, the nature and extent of the Group's drilling programme
may change over time, with a consequent change in investment
requirements.
Accordingly, the ability of the Group to generate sufficient
cash from operations may be materially affected by the results of
the Group's current appraisal activity and the success of future
drilling activities, as well as by a number of economic factors to
which the Group's financial forecasts are particularly sensitive,
such as crude oil prices, the level of inflation in Russia, and
foreign exchange rates.
The Group finances its exploration and development activities
using a combination of cash in hand, operating cash flow generated
mainly from the sale of crude oil production, prepayments from
forward oil sale agreements and additional debt or equity financing
as required. As further discussed in Note 11, the credit facility
obtained from Otkritie contains certain covenants which the Group
needs to meet to avoid acceleration of the debt repayment schedule.
The two major covenants are EBITDA and production volumes.
The projections prepared by management of the Group for the
purposes of preparation of these financial statements shows that it
is possible that the Group might violate its EBITDA covenant for
the year ending 31 December 2015 and four consecutive quarters
ending 31 March 2016. The main reason for this is a substantial
decline of the oil price, which is beyond the control of the Group.
To mitigate this risk, management has commenced negotiations with
Otkritie to revise the covenants. The Group has also received a
written confirmation that Otkritie has no intention to take any
actions to accelerate repayment of the loans as a result of the
possible violation of covenants for the periods referred to above.
Nevertheless, while negotiations continue, management recognises
that there is an uncertainty as to the Group's ability to continue
as a going concern.
During the reporting period, the Group negotiated a roll-over of
the US$30 million advance financing arrangement with Glencore
Energy UK Ltd. (Glencore) and obtained Russian Rouble ("RUR")
750,000 thousand (US$21,646 thousand) as a forward oil sale
prepayment from LLC EnergoResurs (EnergoResurs). The Group also
secured further shareholder finance of US$10 million in short term
funding, as announced on 26 August 2014, from Limolines, a major
shareholder of the Company.
On 14 November 2014 an extension of existing shareholder loans
was agreed until October 2016 and February 2020.
On the basis of the assumptions and cash flow forecasts
prepared, management has assumed that the Group will continue to
operate within both available and prospective facilities.
Accordingly, the Group financial statements are prepared on the
going concern basis and do not include any adjustments that would
be required in the event that the Group were no longer able to meet
its liabilities as they fall due.
2. Summary of significant accounting policies
Principles of consolidation
Subsidiaries
Subsidiaries are those entities in which the Group has an
interest of more than one half of the voting rights, or otherwise
has power to exercise control over their operations. Subsidiaries
are consolidated from the date on which control is transferred to
the Group and are no longer consolidated from the date that control
ceases.
All intercompany transactions, balances and unrealised gains on
transactions between Group companies are eliminated; unrealised
losses are also eliminated unless the transaction provides evidence
of an impairment of the asset transferred. Where necessary
accounting policies for subsidiaries have been changed to ensure
consistency with the policies adopted by the Group.
The financial statements of the subsidiaries are prepared for
the same reporting year as the Company, using consistent accounting
policies.
Oil and natural gas exploration, evaluation and development
expenditure
Oil and gas exploration activities are accounted for in a manner
similar to the successful efforts method. Costs of successful
development and exploratory wells are capitalised.
Development costs
Expenditure on the construction, installation or completion of
infrastructure facilities such as platforms, pipelines and the
drilling of development wells, including unsuccessful development
or delineation wells, is capitalised within oil and gas
properties.
Property, plant and equipment, Mineral rights and other
intangibles
Oil and gas properties and other property, plant and equipment,
including mineral rights are stated at cost, less accumulated
depletion, depreciation and accumulated impairment losses.
The initial cost of an asset comprises its purchase price or
construction cost, any costs directly attributable to bringing the
asset into operation, the initial estimate of the decommissioning
obligation, and for qualifying assets, borrowing costs. The
purchase price or construction cost is the aggregate amount paid
and the fair value of any other consideration given to acquire the
asset.
Depreciation and Depletion
Oil and gas properties are depreciated on a unit-of-production
basis over proved developed reserves of the field concerned, except
in the case of assets whose useful life is shorter than the
lifetime of the field, in which case the straight-line method is
applied. Mineral rights are depleted on the unit-of-production
basis over proved and probable reserves of the relevant area.
Other property, plant and equipment are generally depreciated on
a straight-line basis over their estimated useful lives as
follows:
years
------
Buildings and constructions 30-50
Other property, plant and equipment 1-6
Major maintenance and repairs
Expenditure on major maintenance refits or repairs comprises the
cost of replacement assets or parts of assets, inspection costs and
overhaul costs. Where an asset or part of an asset that was
separately depreciated and is now written off is replaced and it is
probable that future economic benefits associated with the item
will flow to the Group, the expenditure is capitalised. Where part
of the asset was not separately considered as a component, the
replacement value is used to estimate the carrying amount of the
replaced assets which is immediately written off. Inspection costs
associated with major maintenance programs are capitalised and
amortised over the period to the next inspection. All other
maintenance costs are expensed as incurred.
Intangible assets
Intangible assets are stated at the amount initially recognised,
less accumulated amortisation and accumulated impairment losses.
Intangible assets include computer software.
Intangible assets acquired separately are measured on initial
recognition at cost. The cost of intangible assets acquired in a
business combination is fair value as at the date of acquisition.
Following initial recognition, intangible assets are carried at
cost less any accumulated amortisation and any accumulated
impairment losses. Amortisation is calculated on a straight line
basis over their useful lives, except for mineral rights that are
depleted on the unit-of-production basis as explained above.
Impairment of assets
The Group monitors internal and external indicators of
impairment relating to its tangible and intangible assets.
The recoverable amounts of cash-generating units and individual
assets have been determined based on the higher of value-in-use
(VIU) calculations and fair values less costs to sell (FVLCS).
These calculations require the use of estimates and assumptions. It
is reasonably possible that the oil price assumption may change
which may then impact the estimated life of the field and may then
require a material adjustment to the carrying value of long-term
assets.
Given the shared infrastructure and interdependency of cash
flows related to the three licences the Group holds, the assets are
considered to represent one Cash Generating Unit (CGU), which is
the lowest level where largely independent cash flows are deemed to
exist.
Share option plan
The share option plan, under which the Group has the ability to
choose whether to settle it in cash or equity instruments at the
discretion of the Board of Directors is accounted for as an equity
settled transaction. The fair value of the options granted by the
Company to employees is measured at the grant date and calculated
using the Trinomial option pricing model and recognised in the
consolidated financial statements as a component of equity with a
corresponding amount recognised in selling, general and
administrative expenses over the time share reward vest to the
employee.
Modifications of the terms or conditions of the equity
instruments granted in a manner that reduces the total fair value
of the share-based payment arrangement or is not otherwise
beneficial to the employee, are accounted for as services received
in consideration for the equity instruments granted as if the
modification had not occurred.
Financial instruments
A financial instrument is any contract that gives rise to
financial assets or liabilities.
Financial assets within the scope of International Accounting
Standard (IAS) 39 are classified as either financial assets at fair
value through profit or loss, loans and receivables, held to
maturity investments, or available for sale financial assets, as
appropriate. When financial assets are recognised initially, they
are measured at fair value, plus directly attributable transaction
costs for all financial assets not carried at fair value through
profit or loss.
The Group determines the classification of its financial assets
at initial recognition.
Financial instruments carried on the consolidated statement of
financial position include loans and receivables, cash and cash
equivalent balances, borrowings, accounts payable and put and call
options. The particular recognition and measurement methods adopted
are disclosed in the individual policy statements associated with
each item.
An obligation to acquire own shares is classified as a
liability. The liability to repurchase own shares is initially
recognised at the fair value of consideration payable (being the
net present value of estimated redemption amount) and it is
recorded as deduction of equity. Subsequent changes (revision of
estimate, unwinding of discount) are recognised in profit or loss.
If options are not exercised, the amount recognised as a liability
is transferred to equity.
Rights to acquire own shares are classified as assets. The right
to repurchase own shares is initially recognised at the fair value
of consideration payable, estimated using the Black-Scholes option
pricing model, and it is recorded as increase of equity. Subsequent
changes (revision of estimate) are recognised in profit and
loss.
Loans and receivables
Loans and receivables are non--derivative financial assets with
fixed or determinable payments that are not quoted in an active
market. After initial measurement loans and receivables are
subsequently carried at amortised cost using the effective interest
method less any provision for impairment.
A provision for impairment is recognised when there is an
objective evidence that the Group will not be able to collect all
amounts due according to the original terms of the loans and
receivables. The amount of provision is the difference between the
assets' carrying value and the present value of the estimated
future cash flows, discounted at the original effective interest
rate. The change in the amount of the loan or receivable is
recognised in profit or loss. Interest income is recognised in
profit or loss by applying the effective interest rate.
Cash and cash equivalents
Cash and cash equivalents in the consolidated statement of
financial position comprise cash at banks and on hand and short
term deposits with an original maturity of three months or
less.
For the purpose of the consolidated cash flow statement, cash
and cash equivalents consist of cash and cash equivalents as
defined above, net of outstanding bank overdrafts if any.
Borrowings and accounts payable
The Group's financial liabilities are represented by accounts
payable and borrowings.
Borrowings are initially recognised at fair value of the
consideration received less directly attributable transaction
costs. After initial recognition, borrowings are measured at
amortised cost using the effective interest method; any difference
between the initial fair value of the consideration received (net
of transaction costs) and the redemption amount is recognised as an
adjustment to interest expense over the period of the
borrowings.
A financial liability is derecognised when the obligation under
the liability is discharged or cancelled or expires. Where an
existing financial liability is replaced by another from the same
lender on substantially different terms, or the terms of an
existing liability are substantially modified, such an exchange or
modification is treated as a derecognition of the original
liability and the recognition of a new liability, and the
difference in the respective carrying amounts is recognised in the
profit or loss.
Impairment of financial assets
The Group assesses at the end of each reporting period whether
there is any objective evidence that a financial asset or a group
of financial assets is impaired. A financial asset or a group of
financial assets is deemed to be impaired if, and only if, there is
an objective evidence of impairment as a result of one or more
events that has occurred after the initial recognition of the asset
(an incurred 'loss event') and that loss event has an impact on the
estimated future cash flows of the financial asset or the group of
financial assets that can be reliably estimated. Evidence of
impairment may include indications that the debtors or a group of
debtors is experiencing significant financial difficulty, default
or delinquency in interest or principal payments, the probability
that they will enter bankruptcy or other financial reorganisation
and where observable data indicate that there is a measurable
decrease in the estimated future cash flows, such as changes in
arrears or economic conditions that correlate with defaults.
Inventories
Inventories are stated at the lower of cost and net realisable
value. Cost of inventory is determined on the weighted average
basis. The cost of finished goods and work in progress comprises
raw material, direct labour, other direct costs and related
production overheads (based on normal operating capacity) but
excludes borrowing costs. Net realisable value is the estimated
selling price in the ordinary course of business, less the
estimated cost of completion and selling expenses.
Provisions
General
Provisions are recognised when the Group has a present
obligation (legal or constructive) as a result of a past event, it
is probable that an outflow of resources embodying economic
benefits will be required to settle the obligation and a reliable
estimate can be made of the amount of the obligation. The expense
relating to any provision is presented in profit or loss net of any
reimbursement. If the effect of the time value of money is
material, provisions are discounted using rates that reflect, where
appropriate, the risks specific to the liability. Where discounting
is used, the increase in the provision due to the passage of time
is recognised as finance costs.
Provision for dismantlement
Provision for dismantlement is related primarily to the
conservation and abandonment of wells, removal of pipelines and
other oil and gas facilities together with site restoration
activities related to the Group's licence areas. When a
constructive obligation to incur such costs is identified and their
amount can be measured reliably, the net present value of future
decommissioning and site restoration costs is capitalised within
property plant and equipment with a corresponding liability.
Provisions are estimated based on engineering estimates, licence
and other statutory requirements and practices adopted in the
industry and are discounted to net present value using discount
rates reflecting adjustments for risks specific to the
obligation.
Adequacy of such provisions is periodically reviewed. Changes in
provisions resulting from the passage of time are reflected in
profit or loss each year under finance costs. Other changes in
provisions, relating to a change in the expected pattern of
settlement of the obligation, changes in the discount rate or in
the estimated amount of the obligation, are treated as a change in
accounting estimate in the period of the change and are reflected
as an adjustment to the provision and a corresponding adjustment to
property, plant and equipment. If a decrease in the liability
exceeds the carrying amount of the asset, the excess is recognised
immediately in profit or loss.
Taxes
Income tax
The income tax expense comprises current and deferred taxes
calculated based on the tax rates that have been enacted or
substantively enacted at the end of the reporting period. Current
and deferred taxes are charged or credited to profit or loss except
where they are attributable to items which are charged or credited
directly to equity, in which case the corresponding tax is also
taken to equity.
Current tax is the amount expected to be paid to or recovered
from the taxation authorities in respect of taxable profits or
losses for the current and prior periods.
Deferred tax assets and liabilities are calculated in respect of
temporary differences using the liability method. Deferred taxes
provide for all temporary differences arising between the tax bases
of assets and liabilities and their carrying values for financial
reporting purposes, except where the deferred tax arises from the
initial recognition of an asset or liability in a transaction that
is not a business combination and, at the time of the transaction,
affects neither the accounting profit nor taxable profit or
loss.
A deferred tax asset is recognised for all deductible temporary
differences and carry forward of unused tax credits and unused tax
losses only to the extent that it is probable that taxable profit
will be available against which the deductible temporary
differences or carry forward losses can be utilised.
Unrecognised deferred tax assets are reassessed at the end of
each reporting period and are recognised to the extent that it has
become probable that future taxable profit will allow the deferred
tax asset to be recovered.
Deferred tax assets and liabilities are offset when the Group
has a legally enforceable right to set off current tax assets and
liabilities, when deferred tax balances are referred to the same
governmental body (i.e. federal, regional or local) and the same
subject of taxation and when the Group intends to perform an offset
of its current tax assets and liabilities.
Value added tax
Russian Value Added Tax ('VAT') at a standard rate of 18% is
payable on the difference between output VAT on sales of goods and
services and recoverable input VAT charged by suppliers. Output VAT
is charged on the earliest of the dates: either the date of the
shipment of goods (works, services) or the date of advance payment
by the buyer. Input VAT could be recovered when purchased goods
(works, services) are accounted for and other necessary
requirements provided by the tax legislation are met.
VAT related to sales and purchases is recognised in the
consolidated balance sheet on a gross basis and disclosed
separately as a current asset and liability.
Mineral extraction tax
Mineral extraction tax on hydrocarbons, including natural gas
and crude oil, is due on the basis of quantities of natural
resources extracted. Mineral extraction tax for crude oil is
determined based on the volume produced per fixed tax rate adjusted
depending on the monthly average market prices of the Urals blend
and the RUR/US$ exchange rate for the preceding month. The ultimate
amount of the mineral extraction tax on crude oil depends also on
the depletion and geographic location of the oil field. Mineral
extraction tax on gas condensate is determined based on a fixed
percentage from the value of the extracted mineral resources.
Mineral extraction tax is accrued as a tax on production and
recorded within cost of sales.
Equity
Share capital
Ordinary shares are classified as equity. Incremental costs
directly attributable to the issue of new shares and options are
shown in equity as a deduction, net of tax, from the proceeds. Any
excess of the fair value of shares issued or liabilities
extinguishment over the par value of shares issued is recorded as
share premium.
Other reserves
Other reserves include a reserve on reorganisation of the Group,
the amount of share options of shareholders and an amount related
to fair value of Directors' options.
Revenue recognition
Revenue is measured at the fair value of the consideration
received or receivable for goods provided or services rendered less
any trade discounts, VAT and similar sales-based taxes after
eliminating sales within the Group.
Revenue from sale of crude oil and gas condensate is recognised
when the significant risks and rewards of ownership have been
transferred to the customer, the amount of revenue can be measured
reliably, it is probable that the economic benefits associated with
the transaction will flow to the Group and costs incurred or to be
incurred in respect of this transaction can be measured reliably.
If the Group agrees to transport the goods to a specified location,
revenue is recognised when goods are passed to the customer at the
designated location.
Other revenue is recognised in accordance with contract
terms.
Interest income is accrued on a regular basis by reference to
the outstanding principal amount and the applicable effective
interest rate, which is the rate that exactly discounts estimated
future cash receipts through the expected life of the financial
asset to that asset's net carrying amount. Dividend income is
recognised where the shareholders' right to receive a dividend
payment is established.
Borrowing costs
Borrowing costs directly relating to the acquisition,
construction or production of a qualifying capital project under
construction are capitalised and added to the project cost during
construction until such time the assets are substantially ready for
their intended use i.e. when they are capable of production. Where
funds are borrowed specifically to finance a project, the amount
capitalised represents the actual borrowing costs incurred. Where
surplus funds are available for a short term out of money borrowed
specifically to finance a project, the income generated from such
short term investments is also capitalised and deducted from the
total capitalised borrowing cost. Where the funds used to finance a
project form part of general borrowings, the amount capitalised is
calculated using a weighted average of rates applicable to relevant
general borrowings of the Group during the period. All other
borrowing costs are recognised in the profit or loss account as
finance costs in the period in which they are incurred.
Employee benefits
Wages, salaries, contributions to the Russian Federation state
pension and social insurance funds, paid annual leave and sick
leave, bonuses are expensed as incurred.
Foreign currency translation
Foreign currency transactions are initially recognized in the
functional currency at the exchange rate ruling at the date of
transaction. Monetary assets and liabilities denominated in foreign
currencies are translated at the functional currency rate of
exchange in effect at the end of the reporting period.
The US dollar (US$) is the presentation currency of the Group
and the functional currency of the Company. The functional currency
of subsidiaries operating in the Russian Federation is the Russian
Rouble (RUR). The assets and liabilities of the subsidiaries are
translated into the presentation currency of the Group at the rate
of exchange ruling at the end of each of the reporting periods.
Income and expenses for each income statement are translated at
average exchange rates (unless this average is not a reasonable
approximation of the cumulative effect of the rates prevailing on
the transaction dates, in which case income and expenses are
translated at the rate on the dates of the transactions). All the
resulting exchange differences are recorded in other comprehensive
income.
The US$ to RUR exchange rates were 56.26 and 32.73 as at 31
December 2014 and 31 December 2013, respectively and the average
rates for the year ended 31 December 2014 and 2013 were 38.47 and
31.85, respectively. The US$ to GBP exchange rates were 0.64 and
0.61 as at 31 December 2014 and 31 December 2013, respectively and
the average rates for the year ended 31 December 2014 and 2013 were
0.61 and 0.64, respectively. The increase in the US$ to RUR
exchange rate for the year ended 31 December 2014 has resulted in a
loss of US$202,410 thousand in the consolidated statement of profit
or loss and other comprehensive loss and an adjustment of US$9,292
thousand in other comprehensive loss.
3. Significant accounting judgements, estimates and assumptions
In the application of the Group's accounting policies,
management is required to make judgements, estimates and
assumptions about the carrying amounts of assets and liabilities
that are not readily apparent from other sources.
The estimates and associated assumptions are based on historical
experience and other factors that are considered to be relevant.
Actual results may differ from these estimates. The estimates and
underlying assumptions are reviewed on an on-going basis. Revisions
to accounting estimates are recognised in the period in which the
estimate is revised if the revision affects only that period or in
the period of the revision and future periods if the revision
affects both current and future periods.
The most significant areas of accounting requiring the use of
the Group's management estimates and assumptions relate to oil and
gas reserves; useful economic lives and residual values of
property, plant and equipment; impairment of tangible assets;
provisions for dismantlement; taxation and allowances.
Subsoil Licences
The Group conducts operations under exploration and production
licences which require minimum levels of capital expenditure and
mineral production, timely payment of taxes, provision of
geological data to authorities and other such requirements. The
current periods of the Group's licences expire between December
2015 and June 2034.
Regulatory authorities exercise considerable discretion in
issuing and renewing licences and in monitoring licencees'
compliance with licence terms. The loss of licence would be
considered a material adverse event for the Group.
It is management's judgement that each of the three licences
held by the Group will be renewed for the economic lives of the
fields which are projected to be up to 2040 (two licences held by
INGA) and 2029 (the licence held by Trans-oil). The appraised
economic lives of the fields are used as the basis for reserves
estimation, depletion calculation and impairment analysis. In
making this assessment, management considers that the licence held
by Trans-oil, which was extended for three years to December 2015,
will be further extended. This further extension will be dependent
on management demonstrating to the licencing authorities that
associated petroleum gas produced in the course of oil production
is being utilised.
Useful economic lives of property, plant and equipment and
Mineral rights
Oil and gas properties and mineral rights
The Group's oil and gas properties are depleted over the
respective life of the oil and gas fields using the
unit-of-production method based on proved developed oil and gas
reserves. Mineral rights are depleted over the respective life of
the oil and gas fields using the unit-of-production method based on
proved and probable oil and gas reserves.
Reserves are determined using estimates of oil in place,
recovery factors and future oil prices.
When determining the life of the oil and gas field, assumptions
that were valid at the time of estimation, may change when new
information becomes available. The factors that could affect the
estimation of the life of an oil and gas field include the
following:
-- Changes of proved and probable oil and gas reserves;
-- Differences between actual commodity prices and commodity
price assumptions used in the estimation of oil and gas
reserves;
-- Unforeseen operational issues; and
-- Changes in capital, operating, processing and reclamation
costs, discount rates and foreign exchange rates possibly adversely
affecting the economic viability of oil and gas reserves.
Any of these changes could affect prospective depletion of
mineral rights and oil and gas assets and their carrying value.
Other non-production assets
Property, plant and equipment other than oil and gas properties
are depreciated on a straight-line basis over their useful economic
lives. Management at the end of each reporting period reviews the
appropriateness of the assets useful economic lives and residual
values. The review is based on the current condition of the assets,
the estimated period during which they will continue to bring
economic benefit to the Group and their estimated residual
value.
Estimation of oil and gas reserves
Unit-of-production depreciation, depletion and amortisation
charges are principally measured based on Group's estimates of
proved developed and proved and probable oil and gas reserves.
Estimates of proved and probable reserves are also used in
determination of impairment charges and reversals. Proved and
probable reserves are estimated by an independent international
reservoir engineers, by reference to available geological and
engineering data, and only include volumes for which access to
market is assured with reasonable certainty.
Information about the carrying amounts of oil and gas properties
and the depreciation, depletion and amortisation charged is
provided in Notes 8 and 9.
Estimates of oil and gas reserves are inherently imprecise,
require the application of judgements and are subject to regular
revision, either upward or downward, based on new information such
as from the drilling of additional wells, observation of long-term
reservoir performance under producing conditions and changes in
economic factors, including product prices, contract terms or
development plans. Changes to Group's estimates of proved and
probable reserves affect prospectively the amounts of depreciation,
depletion and amortisation charged and, consequently, the carrying
amounts of mineral rights and oil and gas properties.
Were the estimated proved reserves to differ by 10% from
management's estimates, the impact on depletion would be as
follows:
Effect on loss
before tax for
Increase/decrease in reserves the year ended
estimation 31 December
2014 2013
-------- --------
+ 10% (2,454) (1,977)
- 10% 2,999 2,416
-------- --------
Provision for dismantlement
The Group has a constructive obligation to recognise a provision
for dismantlement for its oil and gas assets. The fair values of
these obligations are recorded as liabilities on a discounted
basis, which is typically at the time when assets are installed.
The Group performs analysis and makes estimates in order to
determine the probability, timing and amount involved with probable
required outflow of resources. Estimating the amounts and timing of
such dismantlement costs requires significant judgement. The
judgement is based on cost and engineering studies using currently
available technology and is based on current environmental
regulations. Provision for dismantlement is subject to change
because of change in laws and regulations, and their
interpretation.
Estimated dismantlement costs, for which the outflow of
resources is determined to be probable, are recognised as a
provision in the Group's financial statements.
Impairment of non-current assets
The Group accounts for the impairment of non-current assets in
accordance with IAS 36 Impairment of Assets. Under IAS 36, the
Group is required to assess the conditions that could cause assets
to become impaired and to perform a recoverability test for
potentially impaired assets held by the Group. These conditions
include whether a significant decrease in the market value of the
assets has occurred, whether changes in the Group's business plan
for the assets have been made or whether a significant adverse
change in the business environment has arisen.
Subsequent to the year end, the Group's shares have been trading
at a level which indicate that the market capitalisation of the
Group is below the carrying value of net assets. This has resulted
in a review of the Group's non-current assets (Oil and Gas
properties and Mineral Rights) to determine whether they are
impaired as at the reporting date.
The recoverable amount was estimated using value in use
approach. The models developed by the management to calculate value
in use involved assumptions as to future hydrocarbon prices, taxes,
production volumes, and inflation. The models also use estimates of
proved developed reserves at 31 December 2014 as calculated by the
management of the Group. Estimated cash flows were discounted with
a risk adjusted discount rate derived as the weighted average cost
of capital (WACC). For the Group's businesses the after tax nominal
discount rate is estimated at 10 percent.
Based on the impairment analysis performed, management does not
consider that the Group's non-current assets are impaired as at 31
December 2014.
Assumptions used in developing cash flow forecasts of the
Group
Assumption Value
-------------------------
Average crude oil price gradual increase from
60 to 80 USD per barrel
by January 2017
Average effective rate of gradual increase from
mineral extraction tax of 3,263 to 7,213 RUB
crude oil per ton by January
2018
Production volume of crude
oil over economic life of
the fields 246,077 thousand barrels
-------------------------
Taxation
The Group is subject to income and other taxes. Significant
judgement is required in determining the provision for income tax
and other taxes due to complexity of the tax legislation of the
Russian Federation. Deferred tax assets are recognised to the
extent that it is probable that it will generate enough taxable
profits to utilise deferred income tax recognised. Significant
management judgement is required to determine the amount of
deferred tax assets recognised, based upon the likely timing and
the level of future taxable profits. Management prepares cash flow
forecasts to support recoverability of deferred tax assets. Cash
flow models are based on a number of assumptions relating to oil
prices, operating expenses, production volumes, etc. These
assumptions are consistent with those, used by independent
reservoir engineers. Management also takes into account
uncertainties related to future activities of the Group and going
concern considerations. When significant uncertainties exist
deferred tax assets arising from losses are not recognised even if
recoverability of these is supported by cash flow forecasts.
Segment reporting
Management views the Group as one operating segment and uses
reports for the entire Group to make strategic decisions. 98% of
total revenues from external customers in 2014 and 2013 were
derived from sales of crude oil and gas condensate. These sales are
made to domestic and international oil traders. Although there are
a limited number of these traders, the Group is not dependent on
any one of them as crude oil is widely traded and there are a
number of other potential buyers of this commodity. The Group's
operations are entirely located in Russia.
The Company's Board of Directors evaluates performance of the
entity on the basis of different measures, including total
expenses, capital expenditures, operating expenses per barrel and
others.
4. Adoption of the new and revised standards
At the date of approval of these consolidated financial
statements the following accounting standards, amendments and
interpretations were issued by the International Accounting
Standards Board and IFRS Interpretations Committee in the year
ended 31 December 2014 or earlier, but are not yet effective and
therefore have not been applied:
(i) Not endorsed by the European Union
New standards and interpretations
-- IFRS 9 - Financial Instruments (effective for annual periods on or after 1 January 2018).
-- IFRS 14 - Regulatory Deferral Accounts (effective for annual
periods on or after 1 January 2016).
-- IFRS 15 - Revenue from Contracts with Customers (effective
for annual periods on or after 1 January 2017)
5. Revenue
Year ended 31
December
2014 2013
------- -------
Revenue from crude oil sales 53,795 67,326
Revenue from gas condensate sales 299 11,267
Other revenue 1,006 1,256
Total Revenue 55,100 79,849
======= =======
Other revenue includes proceeds from third parties for crude oil
transportation.
For the years ended 31 December 2014 and 2013, revenue from
export sales of crude oil amounted to US$18,811 thousand and
US$13,306 thousand, respectively.
Revenues from certain individual customers from sales of crude
oil and gas condensate approximately equalled or exceeded 10% of
total Group revenue.
Year ended 31
December
Customer 2014 2013
------- -------
Customer 1 18,811 13,306
Customer 2 15,936 -
Customer 3 9,406 36,623
Customer 4 3,383 23,368
47,536 73,297
======= =======
6. Other expenses
Other expenses mainly consist of impairment of fixed and other
assets in amount of USD2,137 thousand, impairment of financial
instruments in amount of USD1,285 thousand, and professional fees,
incurred in connection with the cancellation of a previously
proposed financial transaction by the Company, in amount of USD709
thousand.
7. Income tax
The major components of income tax expense for the years ended
31 December 2014 and 2013 were:
Year ended 31
December
2014 2013
-------- ------
Current Income tax expense 22 51
Deferred tax benefit (517) (62)
-------- ------
Total Income tax (expense)/benefit (495) (11)
======== ======
Loss before taxation for financial reporting purposes is
reconciled to the tax calculation for the period as follows:
Year ended 31
December
2014 2013
---------- ---------
Loss before income tax (263,388) (74,249)
Income tax benefit at applicable
tax rate 52,678 14,850
Tax effect of losses for which
no deferred income tax asset was
recognized (48,419) (24,533)
Tax effect of losses utilised - 13,752
Tax effect of share-base payment
compensation (4) (41)
Tax effect interest on shareholders'
loans (1,910) (1,730)
Tax effect of non-deductible expenses (1,850) (2,287)
---------- ---------
Income tax benefit 495 11
========== =========
Differences between IFRS and statutory taxation regulations in
Russia give rise to temporary differences between the carrying
amount of assets and liabilities for financial reporting purposes
and their tax bases. The tax effect of the movements in these
temporary differences is detailed below and is recorded at the rate
of 20% for Group companies incorporated in the Russian
Federation.
The movements in deferred tax assets and liabilities relates to
the following:
Recognised
in the
1 January Income Exchange 31 December
2014 Statement differences 2014
----------- ------------ ------------- ------------
Assets
Tax loss carry-forward 2,682 2,485 (1,907) 3,260
Deferred income
tax assets 2,682 2,485 (1,907) 3,260
Liabilities
Property, plant
and equipment (8,870) (2,060) 3,107 (7,823)
Mineral rights
and intangible
assets (79,050) (441) 33,201 (46,290)
Inventories 21 (60) 32 (7)
Loans and borrowings - (439) 139 (300)
Accounts payable 1,214 943 (806) 1,351
Accounts receivable 501 89 (238) 352
----------- ------------ ------------- ------------
Deferred income
tax liabilities (86,184) (1,968) 35,435 (52,717)
=========== ============ ============= ============
Recognised
in the
1 January Income Exchange 31 December
2013 Statement differences 2013
----------- ------------ ------------- ------------
Assets
Tax loss carry-forward - 2,757 (75) 2,682
Deferred income
tax assets - 2,757 (75) 2,682
Liabilities
Property, plant
and equipment (6,403) (2,870) 403 (8,870)
Mineral rights
and intangible
assets (85,059) (118) 6,127 (79,050)
Inventories - 21 - 21
Accounts payable 1,016 278 (80) 1,214
Accounts receivable 546 (6) (39) 501
----------- ------------ ------------- ------------
Deferred income
tax liabilities (89,900) (2,695) 6,411 (86,184)
=========== ============ ============= ============
The Group recognises deferred tax assets in respect of tax
losses incurred only by INGA, because it is probable that
sufficient taxable profits will be available in the future to
utilise the deductible temporary difference.
The Group did not recognise deferred income tax assets of
US$65,172 thousand and US$39,682 thousand, in respect of losses
that can be carried forward against future taxable income amounting
to US$325,861 thousand and US$198,410 thousand as at 31 December
2014 and 31 December 2013, respectively. As at 31 December 2014,
losses amounting to US$29,230 thousand, US$21,578 thousand,
US$15,139 thousand, US$24,009 thousand, US$25,210 thousand and
US$210,695 thousand expire in 2018, 2019, 2020, 2021, 2023, 2024
respectively. As at 31 December 2013, losses amounting to US$51,087
thousand, US$36,899 thousand, US$26,559 thousand, US$41,400
thousand and US$42,465 thousand expire in 2018, 2019, 2020, 2021,
2023 respectively.
8. Property, plant and equipment
Other
property,
Oil & plant Construction
gas properties and equipment in progress Total
Cost as at 1 January
2014 223,088 11,425 74,258 308,771
Additions - - 38,143 38,143
Transfers to fixed
assets 70,070 1,082 (71,152) -
Change in provision
for dismantlement (1,354) - - (1,354)
Disposals (314) (181) (311) (806)
Effect of translation
to presentation
currency (108,831) (4,501) (18,268) (131,600)
Cost as at 31 December
2014 182,659 7,825 22,670 213,154
---------------- --------------- ------------- ----------
Accumulated depletion
and impairment as
at 1 January 2014 (68,789) (5,779) - (74,568)
Charge for the period (24,487) (2,149) - (26,636)
Impairment (336) (801) (952) (2,089)
Disposals 215 78 - 293
Effect of translation
to presentation
currency 35,095 2,890 - 37,985
Accumulated depletion
and impairment as
at 31 December 2014 (58,302) (5,761) (952) (65,015)
---------------- --------------- ------------- ----------
Net book value as
at 31 December 2014 124,357 2,064 21,718 148,139
================ =============== ============= ==========
Other
property,
Oil & plant Construction
gas properties and equipment in progress Total
Cost as at 1 January
2013 212,417 11,339 61,203 284,959
Additions - - 45,507 45,507
Transfers to fixed
assets 26,268 1,009 (27,277) -
Change in provision
for dismantlement 26 - - 26
Disposals (187) (154) - (341)
Effect of translation
to presentation
currency (15,436) (769) (5,175) (21,380)
Cost as at 31 December
2013 223,088 11,425 74,258 308,771
---------------- --------------- ------------- ---------
Accumulated depletion
and impairment as
at 1 January 2013 (55,177) (3,046) - (58,223)
Charge for the period (18,060) (3,101) - (21,161)
Disposals 119 77 - 196
Effect of translation
to presentation
currency 4,329 291 - 4,620
Accumulated depletion
and impairment as
at 31 December 2013 (68,789) (5,779) - (74,568)
---------------- --------------- ------------- ---------
Net book value as
at 31 December 2013 154,299 5,646 74,258 234,203
================ =============== ============= =========
For the year ended 31 December 2014, additions to construction
in progress are primarily made up of additions to production
facilities, including wells, as well as additions to
infrastructure. As at 31 December 2014, the construction in
progress balance mainly represents production wells and oil
production infrastructure not finalised (e.g. pads, electricity
grids, etc.).
None of the Group's property, plant and equipment was pledged as
at the reporting dates.
9. Mineral rights and other intangibles
Other
Mineral intangible
rights assets Total
Cost as at 1 January 2014 395,779 1,495 397,274
Additions - 2,482 2,482
Effect of translation to presentation
currency (165,526) (1,411) (166,937)
Cost as at 31 December 2014 230,253 2,566 232,819
---------- ------------ ----------
Accumulated depletion and impairment
as at 1 January 2014 (1,587) (154) (1,741)
Charge for the period (255) (101) (356)
Impairment - (48) (48)
Effect of translation to presentation
currency 779 109 888
Accumulated depletion and impairment
as at 31 December 2014 (1,063) (194) (1,257)
---------- ------------ ----------
Net book value as at 1 January
2014 394,192 1,341 395,533
Net book value as at 31 December
2014 229,190 2,372 231,562
========== ============ ==========
Other
Mineral intangible
rights assets Total
Cost as at 1 January 2013 426,490 320 426,810
Additions - 1,231 1,231
Effect of translation to presentation
currency (30,711) (56) (30,767)
Cost as at 31 December 2013 395,779 1,495 397,274
--------- ------------ ---------
Accumulated depletion and impairment
as at 1 January 2013 (1,205) (54) (1,259)
Charge for the period (480) (107) (587)
Effect of translation to presentation
currency 98 7 105
Accumulated depletion and impairment
as at 31 December 2013 (1,587) (154) (1,741)
--------- ------------ ---------
Net book value as at 1 January
2013 425,285 266 425,551
Net book value as at 31 December
2013 394,192 1,341 395,533
========= ============ =========
Intangible assets of the Group are not pledged as security for
liabilities and their titles are not restricted.
10. Shareholders' equity
Share capital
31 December
-----------------
2014 2013
-------- -------
Ordinary share capital 135,493 51,226
======== =======
On 11 December 2014 on completion of the Restructuring
536,730,536 new ordinary shares were issued as follows:
-- 179,061,411 new ordinary shares were issued pursuant to
applications received for Open Offer and Excess shares.
-- 4,298,403 new ordinary shares were taken up by the
underwriting shareholders pursuant to their underwriting commitment
under the Open Offer.
-- 145,890,169 new ordinary shares were taken up by underwriting
shareholders pursuant to the terms of the Placing.
In total 329,249,983 new ordinary shares were issued at par
value of 10 pence per share, with existing shareholders being
offered the right to subscribe for 0.55 new shares for each
existing share held.
Mastin purchased from Sberbank Capital 10,362,632 existing
ordinary shares. Including 20,115,743 new ordinary shares issued to
it to set off the put obligation of the Company, a total
207,060,311 new ordinary shares were issued to Mastin resulting in
it having a 25% holding in the enlarged issued ordinary share
capital as at 31 December 2014.
In addition, on 17 December 2014 a further 420,242 share were
issued to current and former Directors in lieu of salary for the
period from 1 April 2013 to 31 March 2014.
Reflecting these transactions, the issued and paid up share
capital of the Company consisted of 870,112,016 and 333,381,480
ordinary shares with a par value of GBP 0.10 each at 31 December
2014 and 2013 respectively.
11. Borrowings
31 December
--------------
2014 2013
------- -----
Current
Otkritie 3,000 -
Short-term loans from shareholders
of the Company 5,303 303
Total current borrowings 8,303 303
======= =====
31 December
------------------
2014 2013
-------- --------
Non-current
Otkritie 144,750 -
Sberbank - 313,393
Long-term loans from shareholders
of the Company 94,051 89,503
Total long-term borrowings 238,801 402,896
======== ========
Otkritie credit facilities Under the terms of the Restructuring
the Group obtained a loan from Otkritie in the amount of US$150,000
thousand on 8 December 2014, pursuant to a loan agreement dated 14
November 2014. The loan is payable in November 2019, bears interest
at 8% per annum and is subject to certain covenants, including
EBITDA and production targets.
14 November 2014 loan agreements for US$100,000 thousand and
US$44,700 thousand were entered into with Otkritie for the Group's
field development and for general working capital purposes
respectively. As at 31 December 2014 no facilities were drawn down
under these agreements.
Sberbank credit facility On 10 December 2014 an assignment and
transfer agreement was entered into between Ruspetro Russia,
Ruspetro Holding Limited and Mastin. In accordance with the
agreement the creditor rights in relation to the total debt in the
amount of US$337,894 thousand being due to Sberbank as at 10
December 2014 was transferred to Mastin. Part of the loan in the
amount of US$150,000 thousand was repaid through the corresponding
credit facility provided by Otkritie in December 2014. The
remaining part of the loan in the amount of US$187,894 thousand was
settled by the issuance to Mastin of new ordinary shares in the
Company.
Loans from shareholders of the Company The Group has a number of
US$ denominated loans obtained from Shareholders of the Company.
All of these loans are unsecured and the interest rate on most of
these loans is Libor +10% per annum.
14 November 2014, the Group rescheduled the maturity of the main
Shareholders' loans until October 2016 and February 2020 with
US$5,000 thousand payable in accrued interest on 31 May 2015. These
amendments did not substantially alter the terms of these original
loans, and were therefore were not treated as extinguishment of an
existing liability and recognition of a new liability. The present
value difference arising from the renegotiation was recognised over
the remaining life of these loans by adjusting the effective
interest rate.
Foreign exchange losses The Group recognised a net foreign
exchange loss amounting to US$196,084 thousand and US$24,694
thousand during the years ended 31 December 2014 and 2013
respectively on the US$ denominated credit facilities and
outstanding accrued interest thereon.
12. Provision for dismantlement
The provision for dismantlement represents the net present value
of the estimated future obligations for abandonment and site
restoration costs which are expected to be incurred at the end of
the production lives of the oil and gas fields which is estimated
to be in 20 years from 31 December 2014.
2014 2013
-------- ------
As at 1 January 7,940 7,697
Additions for new obligations and
changes in estimates (1,354) 26
Unwinding of discount 807 793
Effect of translation to presentation
currency (3,155) (576)
-------- ------
As at 31 December 4,238 7,940
======== ======
This provision has been created based on the Group's internal
estimates. Assumptions, based on the current economic environment,
have been made which management believes are a reasonable basis
upon which to estimate future dismantlement liability. These
estimates are reviewed regularly to take into account any material
changes to the assumptions. However, actual dismantlement costs
will ultimately depend upon future market prices for the necessary
dismantlement works required which will reflect market conditions
at the relevant time. Furthermore, the timing is likely to depend
on when the fields cease to produce at economically viable levels.
This in turn will depend upon future oil and gas prices and future
operating costs which are inherently uncertain.
13. Loss per share
Basic
Basic earnings per share are calculated by dividing the profit
attributable to equity holders of the Company by the weighted
average number of ordinary shares in issue during the period.
Year ended
31 December
2014 2013
------------ ------------
Loss attributable to equity holders
of the Company 262,893 74,238
============ ============
Weighted average number of ordinary
shares in issue 364,252,656 333,381,480
============ ============
Basic Loss per share (US$) 0.72 0.22
============ ============
Diluted
Diluted earnings per share is calculated by adjusting the
weighted average number of ordinary shares to assume conversion of
all dilutive potential ordinary shares.
The Company has incurred a loss from continuing operations for
the year ended 31 December 2014 and the effect of considering the
exercise of the options on the Company's shares would be
anti-dilutive, that is, it would reduce the loss per share.
(1)Earnings before interest, taxes, depreciation and
amortization for the year ending 31 December 2014 is calculated by
adding finance costs, depletion, depreciation and amortization,
foreign exchange income/loss, other expenses and other operating
expenses. In this calculation other expenses includes but is not
limited to impairment of PPE, financial instruments and advances
paid.
12 Months
Line item of the Consolidated statement 2014
of comprehensive income US$ thousands
(Loss)/profit before income tax (263,388)
Add back:
Finance costs 37,965
Depletion, depreciation and amortization 26,992
Foreign exchange loss 202,410
Other expenses 4,443
Other operating expenses 1,128
EBITDA (unaudited) 9,550
---------------
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR UVSARVAASAUR
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