TIDMRPO
RNS Number : 1398V
RusPetro plc
14 April 2016
14 APRIL 2016
Ruspetro plc (the "Group" or the "Company")
Preliminary Results Announcement
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 its Preliminary Results for
the year ended 31 December 2015.
Corporate
-- Intention to seek shareholder approval to cancel the listing
of the Company's ordinary shares from the premium segment of the
Official List and re-register the Company as a private limited
company announced (see separate statement issued today at
07.00am)
Operations - Maturing a technical solution for the development
of our assets
-- Comprehensive internal hydrocarbon resource review completed.
Revised 2P oil reserves of 108 mmbbl, 2C oil resources of 223
mmbbl. Appraisal campaign initiated to convert contingent resources
into 2P reserves
-- Encouraging performance from horizontal well 210, which was
drilled and completed at a cost of US$5.4 million. Drilling and
fracturing services contracts put in place to underpin a future
horizontal well cost target of approximately US$4 million
-- Average oil production increased by 13% year on year to 3,989
bpd in 2015. Cash production operating costs reduced from US$16/bbl
to US$12/bbl
-- Following an international tender, two modern mobile
hydraulic rigs sourced and commissioned in the field
-- Extended reach drilling combined with a portfolio of
fracturing technologies successfully field tested
Financial - Positive Operating Cash Flow before working capital
adjustments despite the Low Oil Price Environment
-- 2015 Revenues of US$43.9 million, versus US$55.1 million in
2014. EBITDA of US$2.6 million, versus US$9.6 million in 2014
-- US$63.8 million undrawn facility available as at the date of this release
-- Met the production covenant required to access the second
US$50 million tranche of development funds
-- Revised Loan Covenants agreed with our primary lenders
following a decision to slow the pace of development drilling in
response to the sustained weakness in oil prices
-- Net debt increased by US$64.8 million to US$299.9 million at period end
-- Net loss of US$99.1 million vs. net loss of US$262.9 million
in 2014, with exchange rate related losses contributing to a
significant extent in both years
-- Group current netback per barrel after Mineral Extraction Tax
(MET) is US$19 at a Brent price of US$40 due to the favourable tax
regime applicable to the Group's tight oil reserves
Outlook - Demonstrating an Economically Attractive Growth
Proposition
-- Intention to double production levels in 2016
-- Implement low cost and flexible appraisal campaign to increase 2P reserves
-- Establish a benchmark cost for a horizontal development well
with 10-15 fractures below US$4 million
-- Establish a material production stream from the UK1 (Abalak
formation) capitalising on its zero % MET fiscal regime
-- Continue drive to lower cash production operating costs
-- Continue tight management of cash and obtain the required
refinancing of trade finance lines, in the normal course of
business
John Conlin, Chief Executive Officer of Ruspetro plc,
Commented:
"Improved geological insight coupled with the application of
proven well technologies has, over a programme of only four wells,
led to our most prolific horizontal development well to date. More
importantly, this has been delivered at previously unachievable
cost, which we can already anticipate to lower significantly. We
remain convinced that understanding the geology of the field is the
key to smart investment in building production.
"Following a comprehensive review of our sub-surface data and
field performance, we have completed the first in-house assessment
of our reserves and resources. The headline reserves numbers are
significantly lower than those previously provided by external
consultants and reserves' auditors. The resources remain
substantial but reinforce the need for appraisal to mature areas
for future development. This has been initiated with very
encouraging early results.
"In 2015, we have established the technical and cost building
blocks for a sustainable operating business in a low cost
environment. However, given our balance sheet and development
capital requirements, this in itself will not guarantee the
long-term sustainability of the business. Today therefore, you will
also see the announcement concerning the Company's proposed
delisting and re-registration as a private limited company. This
will give the Group the flexibility to source funding that is not
available in the public equity markets, using the asset base and
production potential of the Group as valuation benchmarks rather
than the market capitalisation of the listed entity. Based on the
achievements of the last two years, and despite the current harsh
macro-environment, we remain positive for the long term prospects
of the Group."
RESOURCES
Approach and methodology
Ruspetro's internal reserves and resources assessment is the
result of a thorough re-examination of all our sub-surface
geological data and a fresh look at the available seismic data,
which has recently been re-processed. All our historical well test
and well performance data has also been re-examined and integrated
into our models.
Our estimates of Proven and Probable (2P) Reserves and 2C
Contingent Resources have been prepared in accordance with
Petroleum Resource Management System guidelines endorsed by the
Society of Petroleum Engineers. We have rebuilt our resource base
with a bottom up technical analysis, incorporating a rigorous
probabilistic approach combined with a modular project appraisal
and development plan.
The Results
Oil and Associated Gas
The 30 June 2014 external reserve audit estimated 2P Oil and
Associated Gas Reserves to be 1727.3 mmbbl and 1171.0 Bcf
respectively.
The current in-house estimates of 2P Oil and Associated Gas
Reserves are 107.9 mmbbl and 152.4 Bcf respectively, and at the 2C
level, Oil and Associated Gas Resources are estimated to be 223.3
mmbbl and 301.5 Bcf respectively.
Clearly, the Company now has a radically different view of the
Group's reserves and resources. Previous external reserve audits
assumed a region-wide deeper oil-water contact, which was neither
supported by wireline interpretation nor by existing production
performance. Our variable oil-water contact interpretation combined
with the low structural dip has caused us to materially reduce the
oil initially in place when compared to previous external reserve
audits. Our geological framework is also somewhat more complex than
previously assessed.
The Company notes that for the 20 year period up to 2035 the
Company's combined estimate of 2P Oil Reserves and 2C Oil Resources
(331 mmbbl) is comparable to the GKZ estimate of C1+C2 recoverable
oil reserves (435 mmbbl).
While the Group's resources are still substantial enough to
build a sizeable EP business, the reality is that a relatively
modest fraction of our resource base is now considered mature for
development. This is the main rationale for the dedicated appraisal
campaign which has been initiated. Early results are encouraging
both in terms of reserve maturation and in the validation of the
geological concepts we are pursuing.
Non-associated Gas (Palyanovo Licence)
For the gas reservoir within the Palyanovo licence, the 30 June
2014 external reserves audit estimated 2P Non Associated Gas and
Condensate Reserves to be 341.0 Bcf and 18.8 mmbbl
respectively.
The current in-house estimate of 2P Non Associated Gas and
Condensate Reserves is 8.3 Bcf and 0.3 mmbbl respectively and at
the 2C level, the Non Associated Gas and Condensate Resources are
estimated to be 10 Bcf and 0.5 mmbbl respectively.
The pressure data obtained following the field shut-in early in
2014 provide highly reliable material balance based estimates of
the connected gas in place and recoverable gas reserves. Previous
estimates were based on unrealistic geo-cellular models with a
significantly greater areal extension of the producible gas
volume.
These non-associated gas reserves are too small for stand-alone
development. Our focus for the future will be to commercialise our
associated gas reserves and where it is economically viable, to
tie-in the Palyanovo gas on an incremental basis.
Resources Summary
Reserve category Oil Reservoirs Gas Reservoirs Total
------------------ ------------------------- ---------------------------- --------
Oil (mmbbl) Associated Non Associated Condensate (mmboe)
Gas (Bcf) (Bcf) (mmbbl)
------------------ ------------ ----------- --------------- ----------- --------
2P Reserves 107.9 152.4 8.3 0.3 134.9
------------------ ------------ ----------- --------------- ----------- --------
2C Contingent 223.3 301.5 10.0 0.5 275.7
------------------ ------------ ----------- --------------- ----------- --------
ENQUIRIES:
Ruspetro plc
John Conlin, Chief Executive Officer +44 (0) 2078 877624
Alexander Betsky, Finance Director +44 (0) 2078 877624
Dominic Manley, Investor Relations +44 (0) 207318 1630
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 Krasnoleninsky
Arch in Western Siberia.
CHAIRMAN'S STATEMENT
(MORE TO FOLLOW) Dow Jones Newswires
April 14, 2016 02:00 ET (06:00 GMT)
Shareholders will also see today's announcement regarding the
Company's intention to seek Shareholder approval to cancel the
listing of the Company's ordinary shares from the premium segment
of the Official List and re-register the Company as a private
limited company.
Since completing the refinancing and restructuring at the end of
2014, we have embarked on a programme to reduce our operating,
administrative and capital costs whilst setting in train an
ambitious appraisal and development programme that will enable us
to build production from current levels. Our focus is on excellent
geological understanding of our assets and the application of well
technologies proven elsewhere in the world but not as yet widely
applied in Western Siberia.
Despite a 13% increase in production from 3,523 bpd in 2014 to
3,989 bpd in 2015, our revenues have declined from US$55.1 million
in 2014 to US$43.8 million in 2015 due to the 46% decline in
average price of Brent in 2015 compared to 2014. While we were able
to achieve a modest EBITDA for the year of US$2.6 million, this is
clearly not sufficient to cover the levels of capital investment
required, interest payments on loans outstanding and loan
repayments due in the future. Our net debt position increased from
US$235.1 million at the start of 2015 to US$299.9 million by the
end of the year. The Board, therefore, has considered at length the
strategic question of how best to raise the substantial funds
necessary to bring the business to the point where it is generating
sufficient free cash flow to meet its financial commitments and
yield a return for shareholders.
The Board are of the considered view that the funding necessary
to achieve our objectives is currently not available in the public
equity markets for Ruspetro, given the current sector sentiment and
strained geopolitical environment in which it operates. We believe
that as a private limited company, Ruspetro will have better
prospects of achieving this goal because the principal valuation
points that will be used by potential investors in a private
company will be the Group's asset base, production and future
production potential rather than the low benchmark of the market
capitalisation of the listed entity. Furthermore, not having a
listing enables us to open discussions with a group of investors
who are able to take a longer term view of the Company's prospects
and those of the oil and gas sector.
In our view, among the many factors affecting our view of the
sustained lack of public equity market sentiment for the Company's
publicly listed shares, is the fact that we have not been able to
restore the Group's free float above the UKLA's 25% threshold for a
premium listed company for well over a year. If the resolutions are
carried at the General Meeting and we enter this next phase in the
development of the Group we look forward to engaging with all our
shareholders and stakeholders to ensure that there is transparency
as to our plans and our results.
As a private limited company, if the resolutions are carried at
the General Meeting, we will reduce our Board from its current
eight members to a Board of six that will include one Independent
Non-Executive Director and the current Chief Executive Officer. I
will continue to serve as Chairman of the new Board.
CEO'S STATEMENT
2015 has been a year in which we have positioned the Company for
future profitable growth. With regard to technology implementation,
project execution capability both surface and sub-surface, and
critically in the current oil price environment, in the dramatic
reduction in our projected well costs, we now have a compelling and
credible economic development plan for our assets. In a separate
section to this report shareholders will see some very impressive
examples of our technology driven approach.
During the year, we have built on the 2014 horizontal drilling
campaign. In the first half of the year, we drilled and completed
two further horizontal multi-stage fractured wells and one deviated
well. Bringing these wells online allowed production to reach a
level of 6,237 bpd at the end of May. The production performance of
the second of the two horizontal wells (well 210) is particularly
encouraging, with cumulative oil production after 10 months of
245,000 bbl, while the capital cost of the well was US$5.4 million
- approximately half the cost of the first horizontal well
completed by the Group in 2014.
The work that the sub-surface team carried out in 2015 confirmed
that a relatively modest fraction of our resource base was mature
for development. This had a major impact on our development
thinking in that a structured appraisal campaign was required, not
just to mature reserves, but to define those areas of the field
where profitable development wells could be drilled. Central to our
revised strategy was the need for drilling units with the potential
for faster rig moves to provide the necessary flexibility to
respond nimbly to appraisal results.
The Board therefore made the conscious decision to delay the
re-start of drilling until we were able to carry out an
international tender for suitable rigs. Drilling re-started in late
2015 using two modern hydraulically driven rigs - one light rig for
the appraisal programme and a heavier rig for our horizontal
development wells. In parallel, we capitalised on the softer
services market to introduce innovative, performance based
contracting strategies for drilling and completion/fracturing
services. These initiatives underpin our expectation to drill and
complete a horizontal development well with 10-15 fractures for
less than US$4 million.
In the current campaign thus far, we have drilled two
multi-fractured horizontal wells (wells 191 and 192) and three
deviated appraisal wells (wells 200, 201 and well 411). The two
horizontal wells had record horizontal sections and encountered
extensive sands (531m net oil sand within a horizontal section of
1269m in well 191, and 435m net oil sand within a horizontal
section of 1100m in well 192). These wells are being 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 wells. These two production wells
are expected to come on stream in May 2016.
The three appraisal wells have successfully proved our "channel
concept" (channel-like distribution of oil-bearing sands), and have
given us the confidence to proceed with planning for a horizontal
well development campaign on pads 20 and 41. Encouragingly, new low
cost benchmarks are being established as each rig moves up the
learning curve.
Due to the decision to reduce drilling activity levels in the
second half of 2015 in response to the sustained low oil price (as
compared to the business plan put forward at the time of the
restructuring at a time of high oil prices), the Company and its
Lenders recognised that the existing loan covenants could not
realistically be met. These were successfully revised such that the
Company now has production only covenants for its three credit
facilities with its primary lender.
In 2015, we have built a robust business with positive
production operating cash flows at current oil prices; however,
this in itself will not guarantee the long-term sustainability of
the business. The Group is not currently able to generate
sufficient cash flow to cover capital investment, or interest and
capital repayments on its outstanding borrowings, and it continues
to draw down on the debt facilities available to it. Net debt
increased from US$235.1 million at the start of 2015 to US$299.9
million by the end of the year.
The Group's future is conditional on securing additional
development funding coupled with successful refinancing of its
principal debt facilities on maturity albeit that the timing and
level depend on the development scenario adopted and the oil price
environment.
This is the primary rationale for the delisting decision,
although there are other cost and management focus benefits. This
is considered to give the Group the flexibility to source funding
that is not available in the public equity markets, using the asset
base and production potential of the Group as valuation benchmarks
rather than the market capitalisation of the listed entity.
We will remain committed to high standards of corporate
governance and communication with our shareholders. If the
resolutions are carried at the general meeting, as anticipated, I
look forward to this next chapter in the Company's history, during
which, I believe, we can build value in the business for all of our
shareholders.
I would like to end by congratulating all our staff and
contractors for contributing to a year when we had no lost time
incidents. This is a tremendous achievement given the challenging
environment in Western Siberia and in a year when our activity
levels have increased significantly from 2014.
Strategy in Action
Geological Insight is the key to our business
Our geology is complex, permeabilities are low and opportunities
have been missed in the past to collect key data. Nevertheless we
have made significant progress. We have gone right back to basics
and have now completed a comprehensive re-assessment of all
available data. This included detailed reservoir re-correlation,
seismic mapping (stratigraphy, channels) and a full fluid contact
and petrophysical review, which culminated in the construction of a
field-wide integrated geo-cellular model.
Making more use of our 3D Data
Importantly, we believed that we could extract more insight from
the existing 3D data sets. This was evidenced by the recent
re-processing of the legacy merged 3D seismic surveys, which has
already delivered very valuable input to well placement. We are
also designing and planning new 3D seismic in order to cover the
Southern portion of the Pottymsko-Inginsky (PI) licence area and
enable further appraisal and development works.
Integrated Teamwork
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April 14, 2016 02:00 ET (06:00 GMT)
Using state-of-the-art software the Ruspetro team has defined
new workflows aiming at integrating all available subsurface data
(well, core, seismic, and production test data) with the regional
geological framework. This immediately paid off by highlighting
several prospective appraisal and development drilling targets. As
an example, well 210H was planned to test a stratigraphic play
located very near older unsuccessful wells. Careful integration of
advanced seismic attributes and well data not only provided an
explanation for the offset well results but also defined a possible
upside stratigraphic play. Well 210H was drilled in H1 2015 to
exploit this, and encountered approximately 750m of net oil sand
along the 1050m horizontal section.
Horizontal appraisal to reduce hydrocarbon finding costs
Well 210H was drilled in the Northwestern part of the PI licence
area to test a candidate stratigraphic play located in the vicinity
of marginal wells. Instead of setting the production casing shoe to
the top of the main reservoir target, the decision was made to
continue to drill and extend this section until the minimum
economic pay would be encountered within a maximum 250m MD section
extension. Should the well not have encountered this minimum pay
within this extended interval, it would then have been sidetracked
to a fallback development target located in a diametrically
opposite direction to the primary target. This fallback option is
only possible by having a sidetrack kick-off point shallow up near
the surface casing. However 210H encountered the targeted pay and
was successfully completed and stimulated. This drilling and
completion strategy is the key enabler to de-risked appraisal.
Driving down the well costs
We continue introducing technology proven elsewhere into our
well construction operations both in drilling and completion, with
the objective of simplifying well designs while extending our
development reach. New elements introduced for the first time
include:
-- 4 inch high torque connection drill pipe for the long horizontal sections
-- Combination of premium connection casing and rotating liner
hanger technology to enhance liner placement and cementation
-- Ultra-long (5700m) 2 inch coil tubing for our fracture plans
Central to our strategy has been the introduction of modern
hydraulically driven rigs with the potential for faster rig moves
to provide greater flexibility to the drilling plan. Our current
fleet comprises one light rig for the appraisal programme and a
heavier rig for our horizontal development wells. Furthermore, we
have capitalised on the softer services market to introduce
innovative, performance based contracting strategies for drilling
and completion/fracturing services.
The result of this suite of initiatives is a set of benchmark
cost targets which in themselves allow us to plan positively even
at the prevailing low oil price.
Maturing the Horizontal well Development Concept
Optimising our horizontal well design concept has been a key
driver for the business in 2015 to ensure maximum productivity and
ultimate total recovery from wells drilled. The key design
parameters for the new wells such as the length, orientation,
hydraulic fracture density and size are continuously scrutinised to
suit our emerging geological insights. Major achievements in 2015
included:
-- Developing a suite of technologies comprising both coiled
tubing and conventional "plug and perf" solutions.
-- Refining our fracture designs and introducing more, much
smaller fractures to optimise oil productivity in our thin oil
rims
-- Refining the relationship between initial well production performance and ultimate recovery
Fit for Purpose Infrastructure
In parallel with the evolution of our sub-surface thinking, we
have completed a rigorous review of in-field infrastructure and
initiated a number of small but important projects both to redress
shortcomings and to prepare for the future. These include:
-- A mix of mobile and permanent pad based test separating systems
-- Network connection between our produced and injection water systems
-- Oil export line
In addition we have two critical growth projects in
progress:
-- A CPF expansion
-- A 6kV overhead power line and substation
Similarly, but to a lesser extent compared to our sub-surface
innovation due to the prevailing legislation, we are challenging
hard the conventional Western Siberian approach to design and
contracting. As an example we have radically reduced civil
engineering costs by introducing regional competition. We have also
restructured and enhanced our procurement and contracting processes
to ensure transparency and rigour in our assessments of tenders. We
have increased our flexibility to respond to appraisal-driven
changes to the drilling sequence by putting in place framework
contracts for construction; pre-ordering standard materials, and
committing early to standard development pad design to obtain
approvals in time.
Financial Review
Revenues
Revenues were US$43.9 million in 2015, compared with US$55.1
million in 2014. The drop in revenues was primarily driven by a 46%
reduction in the average realised oil price, partially offset by a
13% increase in liquids production.
Cost of sales
The cost of sales, including depreciation and production-related
taxes was US$53.9 million in 2015, compared with US$52.7 million in
2014. The increase was driven by various factors, primarily a 13%
increase in liquids production for the period, and a US$3.6 million
increase in Mineral Extraction Tax ("MET") as a result of the "tax
manoeuvre" (an increase of MET with simultaneous decrease of export
duty). The additional volumes produced, as well as the
production-related reduction in the volume of proved developed
reserves, drove a US$1.6 million rise in depletion expense as well
as the production-related reduction in the volume of proved
developed reserves in 2015. Offsetting the above increases to cost
of sales were a US$4.0 million reduction in production-related
operating expenses and direct payroll expenses, partially achieved
due to the devaluation of the Russian Ruble against the US
Dollar.
Selling and administrative expenses (S&A)
S&A expenses include oil transportation costs, payroll
expenses, rent, professional services, depreciation, IT and
telephony, and other expenses.
S&A expenses in 2015 amounted to US$15.6 million, down 21%
from US$19.8 million in 2014. The decrease resulted from savings,
mostly in payroll expenses, professional services, and rent. Almost
all of the above combined savings have been achieved due to the 59%
devaluation of the Russian Ruble from the previous period.
EBITDA
EBITDA was US$2.6 million in 2015, compared with US$9.6 million
in the previous year. The drop in EBITDA was primarily driven by
lower netback (revenues from oil sales less export duty less
transportation expenses) which was a result of the 46% decline in
the average realised oil price, and, to a lesser extent, an
increase in MET. These effects were offset by additional
contributions to gross profit from a 13% increase in liquids
production, a lower export duty, due to the falling trend of oil
prices (as well as the tax manoeuvre as described above), and lower
production-related operating and S&A expenses, partially
achieved through the devaluation of the Russian Ruble.
Comprehensive loss for the year and foreign exchange
The Group recorded a loss of US$99.1 million for 2015, compared
with US$262.9 million in 2014. The 2015 result includes a
foreign-exchange loss of US$57.2 million, compared with US$202.4
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$51.3 million in foreign exchange
losses. After deducting the foreign-exchange losses from both
years, the Group's loss would have been US$41.9 million in 2015,
compared with US$60.5 million in 2014.
Balance sheet
Non-current assets have decreased by US$61.1 million, largely
explained by the devaluation of the Russian Ruble (contributing to
US$85.0 million), partially offset by capital expenditure of
US$41.9 million incurred during the period.
Total equity has fallen by US$115.7 million from US$75.7 million
to negative US$40.0 million as at 31 December 2015. The movement in
total equity was a result mostly of foreign exchange losses as a
result of the devaluation in the Russian Ruble.
In December 2015, the Group signed a loan addendum with Otkritie
which excluded EBITDA covenants, and reset the production covenants
to the Group's revised four year development plan. On 15 January
2016, the Group signed an identical addendum with Trust Bank as
with Otkritie, resetting its production covenants and removing
EBITDA covenants.
Borrowings have increased from the prior year by US$60.3 million
to US$307.4 million, reflecting US$59.6 million drawn down of the
Group's existing bank facilities with Otkritie and Trust Bank and
US$5.3 million net increase of interest accrued on shareholders
loans, partly offset by principal repayments of US$3.7 million and
US$0.9 million related to the payment and amortisation of the
arrangement fees for Otkritie and Trust Bank facilities.
The Group's current liabilities increased by US$13.3 million
primarily due to the reclassification of an existing shareholder
loan from Makayla Investments Limited ("Makayla") in the amount of
US$20.4 million. This was a long-term liability in the prior period
at the previous reporting date. In April 2016 the Group concluded
an addendum to the Makayla loan agreement rescheduling the
principal and accrued interest repayments into two parts, US$3.1
million in October 2016 and US$20.3 million in May 2017.
(MORE TO FOLLOW) Dow Jones Newswires
April 14, 2016 02:00 ET (06:00 GMT)
The Group paid down accrued interest on the Makayla shareholder
loan in the amount of US$5.0 million and decreased its trade and
other payables by US$2.7 million mostly due to a decrease of the
Group's prepayment facility with Glencore. Within current
liabilities between 31 December 2014 and 31 December 2015 there was
a US$2.0 million net decrease in prepayments to Glencore as a
result of the Group's new US$22.5 million export facility, drawn
down in May 2015. US$13.8 million is classified as trade and other
payables, and has been offset by the full repayment of three
prepayment facilities with Glencore and Energo Resurs LLC, (a
Russian company affiliated with Glencore), in the amount of US$14.8
million during the first half of 2015.
Cash flow
In 2015, the Group generated a net cash outflow from operating
activities of US$4.7 million, resulting from a negative cash
contribution from changes in working capital of US$6.1 million
(mostly from a decrease in trade and other payables of US$4.6
million), offset by a positive net cash flow contribution from
operating activities of US$1.4 million.
During the period, the Group spent US$35.2 million on investment
activities. This consisted of US$20.0 million spent on the
construction of new wells, US$10.5 million on
infrastructure-related capital expenditures, US$1.9 million on
development studies, US$1.6 million on the purchase of intangible
and other assets and US$1.2 million in capitalised staff costs.
The Group received loan proceeds of US$59.6 million from
Otkritie and Trust, repaid US$3.7 million in principal and paid
US$14.3 million in interest. Additionally, the Group repaid US$5.0
million of accrued interest on a shareholder loan.
Cash balances at the end of the period were US$7.5 million
compared to US$12.0 million at the end of 2014.
Financing of Ruspetro's current operations and future
development
Following the Group's financial restructuring, the Group is able
to continue the implementation of its horizontal well programme in
the near future. The restructuring was achieved in December of
2014, along with the satisfaction of the 30 June 2015 production
covenants, which was a condition for the Group to draw down the
second US$50.0 million of its US$100.0 million development facility
from Otkritie (subject to continuing to meet the drawdown
conditions), along with the planned raising in 2016 of additional
trade finance lines from its partners.
Under recent addendae signed in December 2015 and January 2016,
the Group must achieve certain annualised production targets that
will be tested quarterly from April 2016. The current projections
prepared by management for the purposes of preparation of these
preliminary unaudited condensed consolidated financial statements
show that the Group will not breach its covenants within one year
of publishing these preliminary unaudited condensed consolidated
financial statements.
Furthermore, in April 2016 the Group signed an additional
agreement with Makayla delaying the Group's obligation to repay the
loan and accrued interest owed to Makayla from October 2016 until
May 2017, with a partial repayment of US$3.1 million due in October
2016, so long as the Group's covenants with Otkritie and Trust Bank
are not be breached.
As at the date of this document, the Group has US$63.8 million
of undrawn facilities available and is confident that it will,
during the course of 2016, secure further domestic and export trade
financing lines necessary to fully finance its development
programme in the near term. The outcome of such negotiations cannot
be certain and, therefore, the directors recognise that this
represents a material uncertainty which may cast significant doubt
over the Group's ability to continue as a going concern.
Taking into account all considerations relevant to the Group's
financial position, management considers it appropriate that the
Group's preliminary unaudited condensed consolidated financial
statements should be prepared on a going concern basis.
Ruspetro plc
Preliminary Unaudited Condensed Consolidated Financial
Statements
As at and for the year ended 31 December 2015
Preliminary Unaudited Consolidated Statement of Profit or Loss
and Other Comprehensive Income for the year ended 31 December
2015
(presented in US$ thousands, except otherwise stated)
Year ended 31 December
-------------------------
2015 2014
------------ -----------
Revenue 43,875 55,100
Cost of sales (53,856) (52,686)
------------ -----------
Gross (loss)/profit (9,981) 2,414
Selling and administrative expenses (15,585) (19,824)
Other operating expenses, net (60) (1,160)
------------ -----------
Operating loss (25,626) (18,570)
Finance costs (24,668) (37,965)
Foreign exchange loss (57,221) (202,410)
Other expenses, net (1,210) (4,443)
------------ -----------
Loss before income tax (108,725) (263,388)
Income tax benefit 9,591 495
Loss for the period (99,134) (262,893)
============ ===========
Other comprehensive loss that may
be
reclassified subsequently to loss,
net of income tax
Exchange difference on translation
to presentation currency (16,558) (9,832)
Total comprehensive loss for the
period (115,692) (272,725)
============ ===========
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$) (0.11) (0.72)
Preliminary Unaudited Consolidated Statement of Financial
Position as at 31 December 2015
(presented in US$ thousands, except otherwise stated)
31 December
2015 2014
---------- ----------
Assets
Non-current assets
Property, plant and equipment 130,978 148,139
Mineral rights and other intangibles 179,833 231,562
Deferred tax assets 7,764 -
318,575 379,701
---------- ----------
Current assets
Inventories 1,445 584
Trade and other receivables 5,836 6,565
Income tax prepayment 16 21
Other current assets 2,533 5,065
Cash and cash equivalents 7,511 12,022
17,341 24,257
---------- ----------
Total assets 335,916 403,958
========== ==========
Shareholders' equity
Share capital 135,493 135,493
Share premium 389,558 389,558
Retained loss (528,886) (429,752)
Exchange difference on translation
to presentation currency (61,514) (44,956)
Other reserves 25,397 25,397
Total equity (39,952) 75,740
---------- ----------
Liabilities
Non-current liabilities
Borrowings 282,544 238,801
Provision for dismantlement 5,707 4,238
Deferred tax liabilities 38,625 49,457
326,876 292,496
---------- ----------
Current liabilities
Borrowings 24,882 8,303
Trade and other payables 22,727 25,447
Taxes payable other than income tax 1,375 1,550
Other current liabilities 8 422
---------- ----------
48,992 35,722
---------- ----------
Total liabilities 375,868 328,218
---------- ----------
Total equity and liabilities 335,916 403,958
========== ==========
Preliminary Unaudited Consolidated Statement of Changes in
Equity for the year ended 31 December 2015
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(presented in US$ thousands, except otherwise noted)
Exchange
difference
on translation
Retained to presentation
Share capital Share premium earnings currency Other reserves Total equity
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
loss for the period - - - (9,832) - (9,832)
Total comprehensive
loss for the period - - (262,893) (9,832) - (272,725)
-------------- -------------- ---------- ----------------- --------------- -------------
Issue of shares 84,202 168,986 - - - 253,188
Share options of
shareholders - - (13,753) - 13,753 -
Share-based payment
compensation 65 66 - - (115) 16
-------------- -------------- ---------- ----------------- --------------- -------------
Balance as at 31
December
2014 135,493 389,558 (429,752) (44,956) 25,397 75,740
============== ============== ========== ================= =============== =============
Balance as at 1
January
2015 135,493 389,558 (429,752) (44,956) 25,397 75,740
============== ============== ========== ================= =============== =============
Loss for the period - - (99,134) - - (99,134)
Other comprehensive
loss for the period - - - (16,558) - (16,558)
Total comprehensive
loss for the period - - (99,134) (16,558) - (115,692)
-------------- -------------- ---------- ----------------- --------------- -------------
Balance as at 31
December
2015 135,493 389,558 (528,886) (61,514) 25,397 (39,952)
============== ============== ========== ================= =============== =============
Preliminary Unaudited Consolidated Statement of Cash Flows for
the year ended 31 December 2015
(presented in US$ thousands, except otherwise stated)
Year ended 31 December
-------------------------
2015 2014
------------ -----------
Cash flows from operating activities
Loss before income tax (108,725) (263,388)
Adjustments for:
Depreciation, depletion and amortisation 28,193 26,992
Foreign exchange loss 57,221 202,410
Finance costs 24,668 37,965
Impairment of financial instruments 1,869 1,285
Insurance claim settlement (1,800) -
Impairment of assets - 2,137
Share-based payment compensation - 16
Other operating expenses - 353
------------ -----------
Operating cash inflows before working
capital adjustments 1,426 7,770
------------ -----------
Working capital adjustments:
Change in trade and other receivables (601) (631)
Change in inventories (1,182) 575
Change in trade and other payables (4,647) (2,461)
Change in other taxes receivable/payable 340 (1,943)
Net cash flows (used in)/from operating
activities (4,664) 3,310
------------ -----------
Cash flows from investing activities
Purchase of property, plant and equipment
and intangibles (35,225) (42,541)
Purchase of financial instruments - (7,062)
Net cash used in investing activities (35,225) (49,603)
------------ -----------
Cash flows from financing activities
Proceeds from issue of share capital
(net) - 37,466
Proceeds from loans and borrowings 59,585 160,000
Repayments of loans and borrowings (3,655) (150,750)
Interest paid (19,307) (690)
Other financing charges paid (1,727) (1,500)
------------ -----------
Net cash generated from/ (used in)
financing activities 34,896 44,526
------------ -----------
Net decrease in cash and cash equivalents (4,993) (1,767)
------------ -----------
Effect of exchange rate changes on
cash and cash equivalents 482 (2,043)
------------ -----------
Cash and cash equivalents at the beginning
of the period 12,022 15,832
------------ -----------
Cash and cash equivalents at the end
of the period 7,511 12,022
============ ===========
Notes to the Preliminary Unaudited Condensed Consolidated
Financial Statements for the year ended 31 December 2015
(all tabular amounts are in US$ thousands unless otherwise
noted)
1. Basis of preparation
These preliminary unaudited condensed consolidated financial
statements of the Group have been prepared in accordance with
International Financial Reporting Standards (IFRS) as adopted by
the European Union. The preliminary unaudited condensed
consolidated financial statements are prepared under the historical
cost convention, modified for fair values under IFRS.
The preliminary unaudited condensed consolidated financial
statements are presented in US dollars (US$) and all values are
rounded to the nearest thousand unless otherwise indicated.
Going concern
These preliminary unaudited condensed consolidated financial
statements are prepared on a going concern basis.
At 31 December 2015 the Group reported net current liabilities
of US$31,651 thousand (2014: US$11,465 thousand), which included
cash in bank of US$7,511 thousand (2014: US$12,022 thousand). The
Group had negative operating cash flow of US$4,664 thousand in the
reporting period (2014: positive operating cash flow of US$3,310
thousand).
The Group's continuing operations are dependent, in particular,
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. 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.
In particular, the Group attained a level of production in the
six-months period ended 30 June 2015 required under the terms of
its credit facilities with Public Joint-Stock Company "Bank
Otkritie Financial Corporation" ("Otkritie") in order to enable it
to access the second US$50 million of its US$100 million
Development Facility with Otkritie.
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In addition, during the reporting period, the Group negotiated
the US$22.5 million advance financing arrangement with Glencore
Energy UK Ltd. ("Glencore"). Prepayments from forward oil sale
agreements are one of the main sources of working capital. The
renewal of such prepayments occurs regularly under normal course of
business, but cannot be certain and, therefore, the directors
recognise that this represents a material uncertainty which may
cast significant doubt over the Group's ability to continue as a
going concern.
However, 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 preliminary unaudited condensed consolidated
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 investees, including structured entities,
that the Group controls because the Group (i) has power to direct
the relevant activities of the investees that significantly affect
their returns, (ii) has exposure, or rights, to variable returns
from its involvement with the investees, and (iii) has the ability
to use its power over the investees to affect the amount of the
investor's returns. 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 depleted 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
depreciation 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.
Operating leases
Where the Group is a lessee in a lease which does not transfer
substantially all the risks and rewards incidental to ownership
from the lessor to the Group, the total lease payments are charged
to profit or loss for the year on a straight-line basis over the
lease term. The lease term is the non-cancellable period for which
the lessee has contracted to lease the asset together with any
further terms for which the lessee has the option to continue to
lease the asset, with or without further payment, when at the
inception of the lease it is reasonably certain that the lessee
will exercise the option.
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 options.
The particular recognition and measurement methods adopted are
disclosed in the individual policy statements associated with each
item.
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
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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
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 statement of financial position on a gross basis and
disclosed separately as a current asset and liability.
Mineral extraction tax
Mineral extraction tax ("MET") 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 Russian ruble (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.
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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.
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 recognised 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$ 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 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 RUR72.88 and RUR56.26 as at
31 December 2015 and 31 December 2014, respectively and the average
exchange rates for the year ended 31 December 2015 and 2014 were
RUR61.29 and RUR38.47, respectively. The US$ to pounds sterling
(GBP) exchange rates were GBP0.68 and GBP0.64 as at 31 December
2015 and 31 December 2014, respectively and the average exchange
rates for the year ended 31 December 2015 and 2014 were GBP0.65 and
GBP0.61, respectively. The increase in the US$ to RUR exchange rate
for the year ended 31 December 2015 has resulted in a loss of
US$57,221 thousand in the preliminary unaudited consolidated
statement of profit or loss and other comprehensive loss and an
adjustment of US$16,558 thousand in other comprehensive loss (refer
to Notes 8 and 9).
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 ongoing 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 June 2017
and December 2165.
The Russian regulatory authorities exercise considerable
discretion in issuing and renewing licences and in monitoring
licensees' 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. 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 INGA will
be further extended.
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 (Note 8). 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 (Note 9).
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 (Note 8). At the end of each reporting period management
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 the 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 the 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 the 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 the year ended
Increase/decrease in reserves estimation 31 December
2015 2014
------------ ------------
+ 10% (2,563) (2,454)
- 10% 3,133 2,999
------------ ------------
Provision for dismantlement
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The Group has a constructive obligation to recognise a provision
for dismantlement for its oil and gas assets (Note 12). 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 preliminary unaudited condensed
consolidated 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 the value in use
approach. The models developed by 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 2015 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 pre-tax nominal
discount rate is estimated at 15.2 percent (2014: 13.2
percent).
Based on the impairment analysis performed, management does not
consider that the Group's non-current assets are impaired as at 31
December 2015.
Assumptions used in developing cash flow forecasts of the
Group
Assumption 31 December 2015 31 December 2014
----------------------------- -------------------------
Average crude oil gradual increase from gradual increase from
price US$40 to US$70 per barrel US$60 to US$80 per
by June 2019 barrel by January 2017
MET on crude oil based on increase in
based on increase in MET MET base rate to RUR919
base rate to RUR919 per per ton in January
ton in January 2017 and 2017 and expiration
expiration of 15 years of 15 years 80% MET
80% MET relief in September relief in September
2028 2028
Production volume 108,770 thousand barrels 246,077 thousand barrels
of crude oil over
economic life of
the fields
----------------------------- -------------------------
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. 99% of
total revenues from external customers in 2015 were derived from
sales of crude oil and gas condensate (2014: 98%). 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 preliminary unaudited condensed
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 2015 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 (amended in July 2014 and
effective for annual periods beginning on or after 1 January
2018).
-- IFRS 14 - Regulatory Deferral Accounts (issued in January
2014 and effective for annual periods beginning on or after 1
January 2016).
-- IFRS 15 - Revenue from Contracts with Customers (issued in
May 2014 and effective for annual periods beginning on or after 1
January 2018).
-- IFRS 16 - Leases (issued in January 2016 and effective for
annual periods beginning on or after 1 January 2019).
Amendments
-- Amendments to IFRS 10, IFRS 12 and IAS 28 - Investment
entities: Applying the Consolidation Exception (issued in December
2014 and effective for annual periods beginning on or after 1
January 2016).
-- Amendments to IFRS 10 and IAS 28 - Sale or Contribution of
Assets between an Investor and its Associate or Joint Venture
(issued on 11 September 2014 and effective for annual periods
beginning on or after 1 January 2016).
-- Amendments to IAS 12 - Recognition of Deferred Tax Assets for
Unrealised Losses (issued in January 2016 and effective for annual
periods beginning on or after 1 January 2017).
-- Amendments to IAS 7 - Disclosure Initiative (issued on 29
January 2016 and effective for annual periods beginning on or after
1 January 2017).
(ii) Endorsed by the European Union
Amendments
-- Amendments to IAS 19 - Defined benefit plans: Employee
Contributions (issued in November 2013 and effective for annual
periods beginning 1 July 2014).
-- Annual Improvements to IFRSs 2012-2013 Cycle (issued in
December 2013 and effective for annual periods beginning on or
after 1 July 2014).
-- Amendments to IFRS 11 - Accounting for Acquisitions of
Interests in Joint Operations (issued on 6 May 2014 and effective
for the periods beginning on or after 1 January 2016).
-- Amendments to IAS 16 and IAS 38 - Clarification of Acceptable
Methods of Depreciation and Amortisation (issued on 12 May 2014 and
effective for the periods beginning on or after 1 January
2016).
-- Amendments to IAS 27 - Equity Method in Separate Financial
Statements (issued on 12 August 2014 and effective for annual
periods beginning 1 January 2016).
-- Annual Improvements to IFRSs 2014 (issued on 25 September
2014 and effective for annual periods beginning on or after 1
January 2016).
-- Amendments to IAS 1 - Disclosure Initiative (issued in
December 2014 and effective for annual periods beginning on or
after 1 January 2016).
Management expects that the adoption of these accounting
standards in future periods will not have a material effect on the
financial statements of the Group.
5. Revenue
Year ended 31 December
2015 2014
------------ -----------
Revenue from crude oil sales 43,254 53,795
Revenue from gas condensate sales - 299
Other revenue 621 1,006
Total revenue 43,875 55,100
============ ===========
Other revenue includes proceeds from third parties for crude oil
transportation.
For the years ended 31 December 2015 and 2014, revenue from
export sales of crude oil amounted to US$12,618 thousand and
US$18,811 thousand, respectively.
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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 2015 2014
------------ -----------
Customer 1 17,366 15,936
Customer 2 12,618 18,811
Customer 3 10,493 9,406
40,477 44,153
============ ===========
6. Other expenses, net
Year ended 31 December
2015 2014
------------ -----------
Insurance claim settlement 1,800 -
------------ -----------
Total other income 1,800 -
------------ -----------
Impairment of financial instruments (1,869) (1,285)
Success fee for legal case with Schlumberger
Logelco Inc. (700) -
Impairment of fixed and other assets - (2,137)
Professional fees related to cancelled project - (709)
Other (441) (312)
Total other expenses (3,010) (4,443)
------------ -----------
Total other expenses, net (1,210) (4,443)
============ ===========
Other expenses, net, mainly consist of an insurance claim
settlement received and an impairment charge of other assets. In
2015 the Group received an insurance claim settlement in total
amount of US$1,800 thousand relating to an incident with damage to
insured property during well construction. Impairment of financial
instruments was recognised in total amount of US$1,869
thousand.
In 2014 other expenses mainly consisted of impairment of fixed
and other assets in amount of US$2,137 thousand, impairment of
financial instruments in amount of US$1,285 thousand, and
professional fees, incurred in connection with the cancellation of
a previously proposed financial transaction by the Company, in
amount of US$709 thousand.
7. Income tax
The major components of income tax benefit for the years ended
31 December 2015 and 2014 were:
Year ended 31 December
2015 2014
-------------- ---------
Current income tax expense - 22
Deferred tax benefit (9,591) (517)
-------------- ---------
Total income tax benefit (9,591) (495)
============== =========
Loss before taxation for financial reporting purposes is
reconciled to the tax calculation for the period as follows:
Year ended 31 December
2015 2014
------------ -----------
Loss before income tax (108,725) (263,388)
Income tax benefit at applicable tax rate 21,745 52,678
Tax effect of losses for which no deferred
income tax asset was recognised (3,837) (48,419)
Tax effect previously not recognised on property, (3,604) -
plant and equipment
Tax effect of losses utilised for which no 1,389 -
deferred income tax asset was previously recognised
Tax effect interest on shareholders' loans (2,057) (1,910)
Tax effect of losses for which deferred income (612) -
tax asset was derecognised
Tax effect of losses expired (416) -
Tax effect of share-base payment compensation - (4)
Tax effect of non-deductible expenses (3,017) (1,850)
------------ -----------
Income tax benefit 9,591 495
============ ===========
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 relate to
the following:
Recognised
1 January in profit Translation 31 December
2015 or loss difference 2015
----------- ------------ ------------ ------------
Tax effect of deductible/(taxable) temporary differences
and tax loss carry forwards
Accounts payable 1,351 499 (387) 1,463
Tax loss carry-forward 3,260 12,413 (2,718) 12,955
Property, plant and
equipment (7,823) (3,713) 1,638 (9,898)
Mineral rights and
intangible assets (46,290) (280) 10,603 (35,967)
Inventories (7) (169) 15 (161)
Loans and borrowings (300) 9,215 (1,397) 7,518
Accounts and notes
receivable 352 (8,374) 1,251 (6,771)
----------- ------------ ------------ ------------
Net deferred tax asset/
(liability) (49,457) 9,591 9,005 (30,861)
Recognised deferred
tax asset - 9,232 (1,468) 7,764
Recognised deferred
tax liability (49,457) 359 10,473 (38,625)
Net deferred tax asset/
(liability) (49,457) 9,591 9,005 (30,861)
=========== ============ ============ ============
Recognised
1 January in profit Translation 31 December
2014 or loss difference 2014
----------- ------------ ------------ ------------
Tax effect of deductible/(taxable) temporary differences
and tax loss carry forwards
Accounts payable 1,214 943 (806) 1,351
Tax loss carry-forward 2,682 2,485 (1,907) 3,260
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 receivable 501 89 (238) 352
----------- ------------ ------------ ------------
Net deferred tax asset/
(liability) (83,502) 517 33,528 (49,457)
=========== ============ ============ ============
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$53,946 thousand and US$65,172 thousand, in respect of losses
that can be carried forward against future taxable income for ten
years from the year of losses recognition, amounting to US$269,879
thousand and US$325,861 thousand as at 31 December 2015 and 31
December 2014, respectively.
Year ended 31 December
2015 2014
------------ -----------
Year of expiration
2016 1,492 -
2017 1,082 -
2018 22,563 29,230
2019 17,053 21,578
2020 11,686 15,139
2021 18,533 24,009
2023 19,460 25,210
2024 161,874 210,695
2025 16,136 -
------------ -----------
Total losses 269,879 325,861
============ ===========
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The Group did not recognise deferred income tax assets in
respect of losses that can be carried forward without limiting the
year of expiration against future taxable income amounting to
US$14,567 thousand and US$21,514 thousand as at 31 December 2015
and 31 December 2014.
8. Property, plant and equipment
Other property,
Oil and plant and Construction
gas properties equipment in progress Total
Cost as at 1 January 2015 184,384 6,100 22,670 213,154
Additions - - 40,278 40,278
Transfers to fixed assets 22,062 1,047 (23,109) -
Change in provision for
dismantlement (Note 12) 2,507 - - 2,507
Disposals (1,094) (570) (43) (1,707)
Effect of translation
to presentation currency (41,602) (1,224) (6,799) (49,625)
Cost as at 31 December
2015 166,257 5,353 32,997 204,607
---------------- ---------------- ------------- ---------
Accumulated depletion
and impairment as at 1
January 2015 (60,027) (4,036) (952) (65,015)
Charge for the period (27,029) (838) - (27,867)
Disposals 1,092 539 - 1,631
Effect of translation
to presentation currency 16,260 1,145 217 17,622
Accumulated depletion
and impairment as at 31
December 2015 (69,704) (3,190) (735) (73,629)
---------------- ---------------- ------------- ---------
Net book value as at 31
December 2015 96,553 2,163 32,262 130,978
================ ================ ============= =========
Other property,
Oil and plant and Construction
gas properties equipment in progress Total
Cost as at 1 January 2014 226,054 8,459 74,258 308,771
Additions - - 38,143 38,143
Transfers to fixed assets 70,070 1,082 (71,152) -
Change in provision for
dismantlement (Note 12) (1,354) - - (1,354)
Disposals (314) (181) (311) (806)
Effect of translation
to presentation currency (110,072) (3,260) (18,268) (131,600)
Cost as at 31 December
2014 184,384 6,100 22,670 213,154
---------------- ---------------- ------------- ----------
Accumulated depletion
and impairment as at 1
January 2014 (71,490) (3,078) - (74,568)
Charge for the period (25,486) (1,150) - (26,636)
Impairment (336) (801) (952) (2,089)
Disposals 215 78 - 293
Effect of translation
to presentation currency 37,070 915 - 37,985
Accumulated depletion
and impairment as at 31
December 2014 (60,027) (4,036) (952) (65,015)
---------------- ---------------- ------------- ----------
Net book value as at 31
December 2014 124,357 2,064 21,718 148,139
================ ================ ============= ==========
For the years ended 31 December 2015 and 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 2015 and 2014, the
construction in progress balance mainly represents production wells
and oil production infrastructure not finalised (e.g. pads,
electricity grids, etc.).
The Group's property, plant and equipment in total amount of
US$7,841 was pledged under the credit facility agreements with
Otkritie as at 31 December 2015 (31 December 2014: nil).
For a better presentation of their nature, several items of
fixed assets, similar to those items of fixed assets classified as
other property, plant and equipment in 2014 with cost of US$2,966
thousand and US$1,725 thousand as at 1 January 2014 and 31 December
2014 respectively, were classified as oil and gas properties. For
comparability, the depreciation of these items for 2014 in total
amount of US$999 thousand was restated and reallocated from
administrative expenses to cost of sales (Note 8 and Note 9).
9. Mineral rights and other intangibles
Other
Mineral intangible
rights assets Total
Cost as at 1 January 2015 230,253 2,566 232,819
Additions - 1,622 1,622
Effect of translation to presentation
currency (52,520) (843) (53,363)
Cost as at 31 December 2015 177,733 3,345 181,078
--------- ------------ ---------
Accumulated depletion and impairment
as at 1 January 2015 (1,063) (194) (1,257)
Charge for the period (164) (162) (326)
Effect of translation to presentation
currency 268 70 338
Accumulated depletion and impairment
as at 31 December 2015 (959) (286) (1,245)
--------- ------------ ---------
Net book value as at 1 January 2015 229,190 2,372 231,562
Net book value as at 31 December 2015 176,774 3,059 179,833
========= ============ =========
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
========== ============ ==========
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
------------------
2015 2014
-------- --------
Ordinary share capital 135,493 135,493
======== ========
Issued and paid up share capital of the Company as at 31
December 2015 and 2014 consisted of 870,112,016 ordinary shares
with a par value of GBP0.10 each.
11. Borrowings
31 December
---------------
2015 2014
------- ------
Current
Short-term loans from shareholders of the
Company 20,709 5,303
Otkritie 3,896 3,000
Trust 277 -
Total current borrowings 24,882 8,303
======= ======
31 December
------------------
2015 2014
-------- --------
Non-current
Otkritie 185,118 144,750
Long-term loans from shareholders of the
Company 83,932 94,051
Trust 13,494 -
Total long-term borrowings 282,544 238,801
======== ========
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Otkritie credit facilities The loan facility from Otkritie in
the amount of US$150,000 thousand obtained and drawn down in full
in December 2014, pursuant to a loan agreement dated 14 November
2014, is repayable in November 2019, bears interest at 8% per annum
and is subject to certain covenants, including production targets.
In December 2015 an addendum to the credit facility agreements was
concluded whereby the applicable covenants were modified and
provided solely for reduced production targets.
14 November 2014 credit facility 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 2015, facilities in total
amount of US$24,400 thousand out of US$100,000 thousand and
US$21,344 thousand out of US$44,700 thousand were drawn down under
these agreements, respectively (31 December 2014: nil).
Trust credit facility On 17 November 2015 the Group entered into
a credit facility agreement with Public Joint-Stock Company
"National Bank Trust" (Trust), a bank affiliated with Otkritie, for
the amount of US$25,600 thousand. This relates to utilisation of
the funding available under the first US$50,000 thousand tranche of
the Development Facility with Otkritie. As at 31 December 2015,
total amount of US$13,841 thousand was drawn down under this
facility.
On 15 January 2016 an addendum to the credit facility with Trust
was concluded, whereby the applicable covenants were modified and
provided solely for reduced production targets.
Loans from shareholders of the Company The Group has a number of
US$ 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. Certain loans of an amount
US$303 thousand have matured by 31 December 2015 and 2014 and are
presented as current liabilities.
In May 2015 interest in total amount of US$5,000 thousand was
repaid under the one of the Shareholders' loan agreements. 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$57,221 thousand and US$202,410
thousand during the years ended 31 December 2015 and 2014
respectively, out of which US$51,322 thousand and US$196,084
thousand relate to the US$ denominated credit facilities and
outstanding accrued interest for the years ended 31 December 2015
and 2014 respectively.
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 23 years from 31 December 2015.
2015 2014
-------- --------
As at 1 January 4,238 7,940
Additions for new obligations and changes
in estimates (Note 8) 2,507 (1,354)
Unwinding of discount 389 807
Effect of translation to presentation currency (1,427) (3,155)
-------- --------
As at 31 December 5,707 4,238
======== ========
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 loss
attributable to equity holders of the Company by the weighted
average number of ordinary shares in issue during the period.
Year ended 31 December
2015 2014
------------ ------------
Loss attributable to equity holders of the Company 99,134 262,893
============ ============
Weighted average number of ordinary shares in
issue 870,112,016 364,252,656
============ ============
Basic Loss per share (US$) 0.11 0.72
============ ============
Diluted
Diluted earnings per share is calculated by adjusting the
weighted average number of ordinary shares to assume conversion of
all dilutive potential ordinary shares.
The Company has incurred a loss from continuing operations for
the year ended 31 December 2015 and the effect of considering the
exercise of the options on the Company's shares would be
anti-dilutive, that is, it would reduce the loss per share.
14. Earnings before interest, taxes, depreciation and
amortisation (EBITDA)
Earnings before interest, taxes, depreciation and amortisation
for the year ending 31 December 2015 is calculated by adding
finance costs, depletion, depreciation and amortisation, foreign
exchange income/loss, other expenses and other operating expenses.
In this calculation other expenses includes but is not limited to
impairment of PPE, financial instruments and advances paid.
12 Months
12 Months 2014
Line item of the preliminary unaudited consolidated 2015 US$
statement of comprehensive income US$ thousands thousands
Loss before income tax (108,725) (263,388)
Add back:
Finance costs 24,668 37,965
Depletion, depreciation and amortisation 28,193 26,992
Foreign exchange loss 57,221 202,410
Other expenses 1,210 4,443
Other operating expenses 60 1,128
EBITDA (unaudited) 2,627 9,550
--------------- -----------
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR UORRRNSASAUR
(END) Dow Jones Newswires
April 14, 2016 02:00 ET (06:00 GMT)
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