TIDMCASP
RNS Number : 0019R
Caspian Sunrise plc
25 June 2020
Caspian Sunrise PLC
("Caspian Sunrise" or the "Company")
Annual Report and Financial Statements for the Year Ended 31
December 2019
Caspian Sunrise, the Central Asian oil and gas company with a
focus on Kazakhstan, is pleased to announce its audited final
results for the year ended 31 December 2019.
Highlights for the year:
Operational:
-- Operational (wells drilled at end of year) 2019: 17 (2018: 17)
-- Aggregate production for 2019 was 506,620 barrels (2018:
589,750) a decline of 14.1 per cent.
-- Reserves at 31 December 2019 P1 17.8 mmbls & P2 28.8
mmbls (2018: P1 17.8mmbls & P2 28.8) mmbls
Financial:
-- Revenue: $12.1 million (2018: $10.7 million)
-- Loss for the year $1.4 million (2018: $8.5 million)
-- Cash at bank: $4.1 million (2018: $0.6 million)
-- Total assets: $127.5 million (2018: $65.5 million)
-- CAPEX expenditures:
o Exploration assets $61.8 million (2018: $55.7 million)
o Plant, property & equipment $48.9 million (2018: $ nil)
As at 31 May 2020 production was at the rate of 1,700 bopd, with
a production capacity of 2,000 bopd.
The Report and Accounts and Notice of Annual General Meeting
will shortly be posted to shareholders and available from the
Company's website at
https://www.caspiansunrise.com/investors/reports .
Caspian Sunrise PLC
Clive Carver
Executive Chairman +7 727 375 0202
WH Ireland, Nominated Adviser & Broker
James Joyce
James Sinclair-Ford +44 (0) 207 220 1666
This announcement has been posted to:
www.caspiansunrise.com/investors
The information contained within this announcement is deemed by
the Company to constitute inside information under the Market Abuse
Regulation (EU) No. 596/2014.
CHAIRMAN'S STATEMENT
Introduction
In the past twelve months we have taken several large steps
forward towards our goal of becoming a leading, profitable oil and
gas exploration and production group focused on Kazakhstan.
Operationally we are now significantly better placed in our quest
to deliver real value to our shareholders over the medium / longer
term. However, in the short term we are focused on surviving the
impact of the Covid-19 virus.
Our principal weapon in this fight will be the revenues from be
our MJF production. Since the year end Wells 150 & 153 have
entered production increasing the production capacity from the BNG
Contract Area to approximately 2,000 bopd, the majority of which
may be sold by reference to international rather than domestic
prices.
Our focus until the full impact of Covid-19 virus becomes
clearer will be to continue to conserve cash to better preserve the
medium / longer term value for shareholders. Further details on the
Group's funding position is set out later in this statement.
The contents of the remainder of the statement are presented as
follows:
-- Significant events in the period under review and subsequently
-- Our assets
-- Finance & administration
-- The investment case
-- Outlook
There are separate sections on Kazakhstan and Risk Factors
elsewhere in this Annual Report.
Significant events in the period under review
3A Best
In January 2019, we announced the completion of the acquisition
of 100% of the 3A Best Group JSC, a Kazakh corporation owning an
existing Contract Area of some 1,347 sq. km located near the
Caspian port city of Aktau, for a consideration of $24 million
payable by the issue of 149,253,732 Caspian Sunrise shares issued
at a price of 12p per share.
The Contract Area, which has been designated by the Kazakh
authorities as a strategic national asset, surrounds and goes below
the established shallow field at Dunga, currently owned by Total,
which we believe to be producing at the rate of approximately
15,000 bopd.
In February 2020, we announced amendments to the work programme
inherited with the acquisition, whereby we are obliged to drill
only one well to a depth of 2,500 meters at an expected cost of $2
million. Our approach with 3A Best is to develop the field but also
to recognise its potential M&A value given its proximity to the
successful Dunga field.
Further details of the 3A Best Contract Area are set out later
in this report.
Non-executive director
Also in January 2019, we announced the appointment of Tim Field
as an independent non-executive director.
Tim is a highly experienced international corporate lawyer
specialising in securities law and corporate governance and is the
principal of the specialist corporate and securities law firm
"Field". He is also the equity capital markets consultant to the
law firm Mishcon de Reya, where until recently he led its public
company practice. He has a long and significant track record of
advising AIM companies and Nominated Advisers. His input into the
oversight of the Company and its future direction is much
valued.
Further details are set out in the Corporate Governance
Report.
MJF licence upgrade
In July 2019, we announced the long awaited upgrade to the MJF
licence.
Under Kazakh regulations oil produced during the appraisal phase
of a licence may be sold but only at domestic prices. An upgrade to
a full production licence is required to be able to sell the
majority of the oil produced by reference to international
prices.
Separate changes to the oil laws in Kazakhstan resulted in much
longer delays than expected when we submitted our licence upgrade
application to split the licence and move the MJF structure to a 25
year full production licence with the remainder of the BNG Contract
Area remaining under the appraisal rules.
The principal benefit from the licence upgrade is that the net
price at which production from the MJF structure may be sold, was
broadly double the domestic price previously received.
Following receipt of the licence upgrade we embarked on an up to
18 well infill drilling programme, which after the first two New
Wells 150 and 153, and the spudding of New Well 151, was
temporarily suspended until the impact of the Covid-19 virus became
clearer. Drilling at New Well 151 has now resumed.
Further details of our all our assets and licences are set out
later in this report.
Purchase of equipment
In September 2019, we announced the purchase of drilling
equipment for a consideration of $7 million, payable by the issue
of 58,333,333 shares at an issue price of 10p per share.
With the contraction of medium and smaller scale drilling
activities in Kazakhstan and the consequential retreat of the
larger equipment and services providers, our operations have on
many occasions suffered delays waiting for the required equipment
to be delivered to site. The lack of activity also reduced the
equipment's effective resale value, thereby reducing its
acquisition cost to a point where we concluded it was better to own
and control certain key operational equipment rather than to
continue to rent. We therefore decided to acquire a portfolio of
assets comprising, four drilling rigs, two cranes, pumps,
generators, a blow-out preventor and 12 vehicles, including trucks,
crew buses and pickup trucks.
The largest of the rigs acquired is a 350 tonne G50 rig, with
the capacity to drill to a depth of up to 5,000, meters. Two
further drilling rigs are 225 tonne G40 rigs, each being able to
drill to depths of up to 4,000 meters. The fourth is a workover rig
of 80 tonnes, with a capacity to drill up to 1,500 meters and
perform general workover tasks to a depth of 2,500 meters. The
cranes are used in the assembly and dis-assembly of the rigs with
one able to lift up to 50 tonnes and the other up to 25 tonnes.
The effect of the acquisition has been to provide greater
certainty in the timing of our drilling operations, particularly
with the MJF infill programme, together with a reduction in our
development costs.
Deep Well break through
In early January 2020, we announced that Deep Well A5 had flowed
without interruption or artificial stimulation for four days. Our
priority at that time was to maintain the flow rather than to
maximise production volumes. Accordingly, we quickly switched to
smaller choke sizes than the 12 mm used when the well started to
flow, or the 19 mm we used when the well flowed at the rate of
3,800 bopd in 2017.
This allowed the well to continue to flow without interruption
for 40 days in total, albeit at rates much lower than expected from
a deep high pressure well. In February 2020, the well was closed to
clear excess drilling fluid, which was restricting production
levels and limiting reserves estimates.
Our G50 rig is now in position to replace a broken link in the
tubing before we attempt to re-commence production at rates more
expected of a deep well.
Further details of the performance of each of the deep wells
drilled at our BNG Contract Area are set out later in this
report.
Caspian Explorer
Also in January 2020, we announced the proposed acquisition of
the Caspian Explorer for a consideration of $25 million to be
satisfied by the issue of 160,256,410 shares at an issue price of
12p per share. On 13 February 2020, we announced the acquisition
had been approved by shareholders at a General Meeting. Completion
of the acquisition remains subject to a number of regulatory
consents and filings in Kazakhstan and the UAE.
In parts of the northern Caspian Sea, where the Group's
management believe there are attractive oil producing prospects,
the water levels are extremely shallow and prospects cannot be
explored with traditional deep water rigs.
The principal ways of exploring these properties are either from
a land base or by the use of a specialist shallow drilling vessel.
Land based options typically involve either the creation of
man-made islands from which to drill as if onshore or less commonly
drilling out from an onshore location. Both are expensive compared
to the use of a specialist drilling platform.
The acquisition of the Caspian Explorer will mark the Group's
first step into off-shore exploration, which is typically more
expensive and complicated than on-shore exploration.
Further details of our plans for the Caspian Explorer are set
out later in this report.
Response to the Covid-19 virus
In March 2020, we announced that in response to the impact of
the Covid-19 virus, and in particular the sharp fall in world oil
prices, we would suspend all new drilling activities following the
completion of planned work at New Wells 150 & 153 and Deep
Wells A6, 801 & A8.
The BNG oilfields are typically staffed with two sets of workers
or "crews" each working on a two 12 hours shift basis two weeks on
and two weeks off. In recognition of the risks of contamination at
the time of a crew changeover the decision was taken that there
would be no crew changeover and that the crew then operating would
stay in place for a longer period. To maximise the benefit of their
limited time in the field we decided to focus on projects capable
of quick success being principally the planned acid treatments at
Deep Wells A6, 801 & A8, which do not require rig
movements.
However, border and road closures delayed the specialist acid
reaching BNG. We therefore mobilised one of the G40 rigs acquired
in 2019 to spud New Well 151, the third of infill wells on the MJF
structure and mobilised our G50 rig, previously in use at New Well
153, to continue the work at Deep Well A5.
In a series of announcements from March 2020, we updated the
market with news of action taken to conserve cash, including
reducing staff numbers in the field and in our administrative
offices in Almaty together with deferrals of salary for all but
field workers. In early May 2020, we announced that following
further deferrals the aggregate cash costs of the board had fallen
to 25% of the aggregate entitlement and that we had secured
additional financial support from local oil traders.
New Wells 150 & 153 and 151
At the end of March 2020, we announced the success of New Well
150, the first of the planned infill on the MJF structure. Towards
the end of April we announced the success of New Well 153, the
second planned infill well on the MJF structure.
In early May 2020, we announced that New Well 151 had been
spudded and drilled to a depth of 12 meters but that further
drilling would be dictated by the overall funding position. Since
that announcement additional local funding has been sourced to
continue frilling New Well 151 and following that New Well 152.
Our Assets
BNG Contract Area
The Group's principal asset is its 99% interest in the BNG
Contract Area.
We first took a stake in the BNG Contract Area in 2008, as part
of the acquisition of 58.41% of portfolio of assets owned by Eragon
Petroleum Limited. In 2017, we increased our stake to 99% upon the
completion of the merger with Baverstock GmbH.
Since 2008, approximately $100 million has been spent at
BNG.
The Contract Area is located in the west of Kazakhstan 40
kilometers southeast of Tengiz on the edge of the Mangistau Oblast,
covering an area of 1,561 square kilometers of which 1,376 square
kilometers has 3D seismic coverage acquired in 2009 and 2010. We
became operators at BNG in 2011, since when we have identified and
developed both shallow and deep structures.
Shallow structures
There are two confirmed and producing shallow structures at BNG
with the possibility of a third.
MJF structure
In 2013, we announced the discovery of the MJF structure and
have subsequently drilled 8 wells of which 7 are currently
producing with an aggregate capacity of approximately 1,700
bopd.
The productive Jurassic aged reservoir consists of stacked pay
intervals with most ranging in thickness from two meters to 17
meters. The current mapped lateral extent of the MJF field is now
approximately 13km(2.) The producing wells range in depth from
2,192 meters to 2,450 meters.
In December 2018, we formally applied to move the MJF structure,
which was part of the overall BNG licence, from an appraisal
licence to a full production licence, under which the majority of
the oil produced from the MJF wells may be sold by reference to
world rather than domestic Kazakh prices.
A condition of the licence upgrade is that an amount assessed by
the regulatory authorities on award of the production licence
becomes liable to be repaid quarterly over a 10 year period. We are
challenging the amount assessed on the basis that first it has been
incorrectly calculated and second that despite the MJF structure
accounting for approximately only 1% of the BNG Contract Area it
has been assessed to repay an amount equivalent to 100% what would
be due for the BNG Contract Area as a whole if under a production
licence. On the basis of advice received we believe the basis of
the payments due will be reassessed in accordance with our own
calculations.
The MJF structure licence was upgraded in July 2019, and the
first oil sold by reference to international rather than domestic
prices in August 2019. Following the licence upgrade we have
embarked on an infill drilling programme with the intention of
extending the number of wells to up to 24 wells.
A third infill well, New Well 151, has been spudded and is to be
drilled to a planned Total Depth of 2,500 meters. Assuming no
unforeseen issues we expect this well to start to produce in Q3
2020. Funding has also been sourced to drill a fourth infill well,
New Well 152 following the completion of New Well 151. Drilling at
New Well 151 has now resumed.
As noted elsewhere in these financial statements the pace at
which we undertake this infill drilling programme is dependent on
funding and the international oil price.
We are started to workover existing wells at the MJF structure,
with a view to improving production.
South Yelemes
This structure is the subject of an ongoing licence upgrade
application for a separate 25 year production licence. Until the
application is approved we are unable produce from the four
existing wells on the structure.
The first wells were drilled on the South Yelemes structure
during the Soviet era.
Well 54 was intermittently active between periods of being shut
in to allow pressure to be restored. There are three other wells at
South Yelemes (805, 806 & 807). The production from South
Yelemes was in aggregate approximately 300 bopd. These older wells
are the only wells on the BNG Contract Area which use artificial
lift to assist the oil to flow to the surface.
We believe the structure may have untapped quantities of oil at
higher levels than previously explored making it potentially
suitable for a horizontal drilling campaign. At an appropriate time
we intend to test this theory.
As with the MJF structure, once the South Yelemes structure is
moved onto a full production licence we will be able to sell the
majority of oil produced by reference to world rather than domestic
prices.
Potential New Structure
In April 2017, we drilled Well 808 to a depth of 3,070 meters to
assess whether a new structure similar to the MJF structure
existed. The results of limited testing were inconclusive
indicating oil bearing intervals with high water saturation.
Re-evaluation of the wireline and mudlog data suggests additional
untested potential within two intervals shallower in the well.
While not a prime focus we did test further in the period under
review without yet finding a commercial interval.
Deep structures
We have identified two deep structures at the BNG Contract Area.
The first is the Airshagyl structure and the second is the Yelemes
Deep structure.
Deep wells of the type drilled to date at BNG are typically
drilled by much larger companies and at much greater cost.
A common feature of the two discovered deep structures at BNG
are the extremely high temperature and pressure that exist below
the salt layer. At the Airshagyl structure the salt layer is
typically found at depths between 3,700 -4,000 meters where at the
Yelemes Deep structure the salt layer is typically found at depths
between 3,000 - 3,500 meters.
The extreme pressure below the salt layer requires the use of
high density drilling fluid to maintain control of the well during
drilling. The high density drilling fluid's principal role is to
help prevent dangerous blow-outs.
The attributes of the high density drilling fluid, which allow
the wells to be controlled during the drilling phase, act against
us when we attempt to clear the well for production. To the extent
that drilling fluids, which include solid particles added to
increase density, are not fully recovered they can form a barrier
in the well or in the reservoir preventing or restricting the oil
flow.
Other problem areas encountered in bringing these deep wells
into production have related to drilling through the salt layer,
often in excess of 100 meters thick; cementing the casing below the
salt layer; and with the perforation the wells, where the presence
of extreme pressure requires a much greater explosive force.
Competent third party experience has been difficult to find, as
the exceptional temperature and pressure are unusual for many
international consultancies more used to conventional shallower
exploration. We have however, developed our drilling techniques and
now use drilling fluids with lower density, which we have found
easier to remove once drilling has been completed. Deep Wells A6
& A8, the third and fourth deep wells drilled, encountered
fewer problems during the drilling phase than the earlier
wells.
Our focus remains bringing into production all the deep wells
drilled to date.
Airshagyl
We believe the Airshagyl structure extends to 58 km(2) .
Deep Well A5
Deep Well A5 was spudded in July 2013, and drilled to a total
depth of 4,442 meters with casing set to a depth of 4,077 meters to
allow open-hole testing. Core sampling revealed the existence of a
gross oil-bearing interval of at least 105 meters from 4,332 meters
to at least 4,437 meters.
As noted above the well was difficult to drill with a salt layer
of approximately 130 meters with high temperature and high pressure
encountered at the lower depths. The extremely high-pressure in the
well required the use of drilling fluids with a high density (2.16
g/cm3). Removing this high density drilling fluid to allow testing
was problematic but was eventually completed sufficiently to allow
an extended flow test.
In December 2017, using a choke setting of 19 mm, the well
tested for 15 days at an average rate of 3,800 bopd before the flow
reduced by debris in the well fell to 1,000 bopd leading to the
well test being suspended.
Following two ultimately unsuccessful side-tracks a third
side-track from a depth of 3,976 meters was completed in November
2019. On 31 December 2019, the well started to flow initially at a
rate of 1,500 bopd using a 12 mm choke,
Given our experiences in 2017, our priority was to keep the well
flowing by maintaining a good level of pressure. This required the
choke setting to be reduced to just a few mm, which in turn quickly
reduced the flow of oil. The unrecovered drilling fluid used in the
original well and each of the three side-tracks further restricted
the flow of oil from the well.
Accordingly, in February 2019, after 40 days of unassisted oil
flows, the well was closed to allow work to remove excess drilling
fluid which was restricting the flow rates and therefore any
calculation of reserves. To date some 30 tonnes of excess drilling
fluid has been removed using coil tubing equipment.
Our G50 rig is now on site to replace a cracked link in the
tubing, following which we will once again attempt to get the well
to flow at rates expected of a deep, high pressure well.
Deep Well A6
The second well drilled on the Airshagyl structure was Deep Well
A6, which was spudded in 2015 and drilled to a depth of 4,528
meters.
Repeated problems in perforating the well prevented it being put
on test. Additionally, work at Deep Wells A5 and 801 took
precedence while we were operating with only two rigs and
crews.
Plans to undertake an acid treatment at Deep Well A6 have been
delayed waiting for the required acid to be delivered to the BNG
Contract Area.
Deep Well A8
In November 2018, Deep Well A8 was spudded with a planned Total
Depth of 5,300 meters, initially targeting the same pre-salt
carbonates that were successfully identified in the Deep Well A5 at
depths of 4,342 meters but with a prime target being the deeper
carbonate of the Devonian to Mississippian ages towards the planned
Total Depth of 5,300 meters.
We identified intervals of interest at depths of 4,342 meters.
We then had to decide whether to seek to produce from the intervals
identified or whether to continue to the original Total Depth of
5,300 meters. The arguments in favour of seeking to produce from
the higher interval were short term commercial considerations of
expected significant immediate income. The arguments for continuing
to the original Total Depth were based on the far greater potential
from intervals in the Devonian.
While we favour pressing on to the original Total Depth of 5,300
meters a final decision is yet to be taken. As with Deep Well A6
above the planned acid treatment at Deep Well A8 has been
delayed.
Deep Well A9
The next deep well on the Airshagyl structure will be Deep Well
A9, which, if successful, would extend the perimeter of the
Airshagyl structure. The well has a planned Total Depth of 5,300
meters and will target the same Jurassic prospects as A5 &
A6.
Our intention was to spud Deep Well A9 in the first half of
2020. However, we have delayed drilling the well pending greater
certainty on the lasting impact of the Covid-19 virus.
Summary
Based on results to date we continue to believe the Airshagyl
structure will provide the greatest quantities of oil at the BNG
Contract Area.
Each of the three Deep Wells drilled on the structure has the
potential to flow commercially
Should two or more of the deep wells flow consistently we expect
that the Airshagyl structure will be the first deep structure for
which we apply to move to a full production licence.
Yelemes Deep
We believe the Yelemes Deep structure extends over an area of 36
km2.
Deep Well 801
To date Deep Well 801 is the only deep well drilled at the
Yelemes structure. The well was spudded in December 2014, and was
drilled to a Total Depth of 4,950 meters. The well is located
approximately 8 kilometers from Deep Well A5 and was planned to
target prospects in the Middle and Lower Carboniferous
As with the deep wells drilled on the Airshagyl structure the
blockages in the well preventing an extended flow test are the
result of high temperatures/ pressures and excess drilling fluids.
We have used a variety of techniques including the use of chemicals
and the drilling of a side-track, to establish good reservoir
connectivity.
As at Deep Wells A6 & A8 on the Airshagyl structure our
plans to use an acid treatment on Deep Well 801 have been
delayed.
BNG Infrastructure requirements
We have limited treatment facilities on site and storage of
approximately only 7,000 bbls, which represents less than one weeks
production. Our production is transported using a fleet of heated
tankers, however as production levels from the MJF structure
increase and when production commences from the deep wells already
drilled it will not be practical to rely on these present
arrangements.
At this point a pipeline either to an adjoining Contract Area or
to a treatment facility with access to the main pipeline network
would be required. In addition, we would look to conduct additional
water separation and other treatment activities before selling the
oil produced, increasing the price at which our production could be
sold.
The timing of a decision on how to proceed with a build-out of
the infrastructure for the BNG Contract Area is inevitably linked
to actual production levels. In the event we decide to construct
significant additional storage, treatment and distribution
facilities at the BNG Contract Area we believe the majority of the
costs involved would be capable of being debt funded.
3A Best
In January 2019, the Group acquired 100 per cent of the shares
of 3A Best Group JSC, a company that owns a 1,347 sq. km Contract
Area located close to the Caspian port city of Aktau in the
Mangystau Province of Kazakhstan. The site is located adjacent to
and runs under the commercially successful Dunga field, which was
discovered in 1966 and developed by Maersk Oil. The 3A Best
Contract Area has been designated a national strategic asset by the
Kazakh regulatory authorities.
Whilst the Group has acquired the equity of 3ABest Group JSC,
the acquisition has been recorded as an asset purchase as the
company's sole asset is the exploration stage Contract Area.
The 149,253,732 consideration shares were calculated by
reference to an agreed issue price of 12p per share, which resulted
in a total purchase consideration of $23 million. Before the
acquisition was finalised we agreed with the vendors to reduce the
notional issue price of the shares to 7.0p per share, being the
market price at 21 January 2019, but keeping the number of shares
at 149,253,732 thereby reducing the headline price to $11.8
million.
Based on an assessment of the geology we believe some of the
characteristics of the Dunga Contract Area are also present at 3A
Best. Additionally, we believe the area 2,500 meters and below the
Dunga Contract area, which forms part of the 3A Best Contract Area,
also indicates the likely presence of oil.
490 sq. km of 3D seismic has been shot. 1,327 linear km of 2D
has been digitised and reprocessed. Two wells have been drilled on
the Contract Area in recent years, both encountering water and
signs of oil and gas. Neither was commercially successful.
The current 3A Best licence runs until June 2020. We are in the
final stages of discussions with the Kazakh authorities regarding
an extension of the 3A Best licence, which we expect will entail a
new set of work programme obligations.
Caspian Explorer
Introduction
To date we have focused on exclusively on onshore exploration
and production. To continue with this approach would exclude us
from the very significant potential we see in the Northern Caspian
Sea.
We decided to acquire the Caspian Explorer for two reasons. The
first as a means to become involved in offshore development, which
for a Group of our size would otherwise be difficult. The second as
a conventional source of income when rented to other explorers.
Offshore exploration is traditionally much more expensive than
on shore exploration. Projects therefore tend to go to the larger
operators or more commonly to specially formed consortia of such
companies.
We believe the Caspian Explorer is the only drilling vessel of
its type capable of drilling exploration wells to depths of 6,000
meters in water as shallow as 2.5 meters currently ready to operate
in the Caspian Sea. Further, given the lead times and construction
costs, we do not expect a new competing drilling vessel to enter
the market in the next few years.
Once acquired we will seek to rent out the Caspian Explorer for
both an immediate economic return, in the form of rental payments,
but also where appropriate seek a position in the development
consortia.
Completion of the acquisition of the Caspian Explorer remains
subject to regulatory approvals in Kazakhstan and the UAE.
Background
The Caspian Explorer was conceived of by a consortium of leading
Korean companies including KNOC, Samsung and Daewoo Shipbuilding.
The vessel was assembled in the Ersay shipyard in Kazakhstan
between 2010 and 2011 for a construction cost believed to be
approximately $170 million. The total costs after fit-out are
believed to have been approximately $200 million.
The Caspian Explorer became operational in 2012 at a time of
relatively low oil prices and reduced exploration activity in the
Northern Caspian Sea. In 2017, the Korean consortium decided to
sell the Caspian Explorer by way of a competitive tender with the
buyer being KC Caspian Explorer LLP.
The Caspian Explorer typically operates between May and November
as the Northern Caspian Sea is subject to ice in the winter months,
with a crew of 20 and room to accommodate up to 100.
Commercial potential
We believe there to be two principal drivers for the further
exploration of the Northern Caspian Sea. The first is continued
development of existing projects and the second is following any
awards of new blocks.
Although a big ticket item by our standards spending $25 - $30
million a year hiring a drilling platform such as the Caspian
Explorer is a modest sum for companies often measuring their annual
investment in $ billions.
By way of example, in 2017, the Caspian Explorer was hired out
to a KazMunaiGas / Indian state oil company joint venture for $28
million after costs and drilled one exploration well to a depth of
3.5 km and in 2018, the Caspian Explorer was hired out KazMunaiGas
for up to $24 million drilling one exploration well to a depth of
1.8 km.
The impact on the Group of a contract at these levels even once
every three years would be dramatic. In any year when the Caspian
Explorer is contracted it could fund the majority of the rest of
the Group's annual drilling programme.
The Caspian Explorer did not operate in 2019 and has no
contracts in place for 2020. Following completion our financial
exposure in the event of no external contracts are costs of
approximately $100,000 per month while the Caspian Explorer is in
port.
Licences & Work Programmes
BNG
BNG LLP Ltd holds two contracts for a subsoil use. The first is
the exploration contract, covering the full extent of the BNG
Contract Area (except the MJF structure), originally issued in 2007
and successively extended until 2024. The second is the export
contract covering just the MJF structure which runs to 2043 and
under which the majority of oil produced may be sold by reference
to international rather than domestic prices.
Our 2020 MJF work programme obligation to drill seven
obligations has been reduced to two wells, which are already
completed and producing.
We have also submitted an application to move the South Yelemes
shallow structure to an export licence and look forward to
receiving the regulators consent in the due course.
There are no 2020 work programme obligations at the Airshagyl
structure.
At the Yelemes Deep structure the existing work programme
commitments require us to drill a further deep well, Deep Well 802,
by the end of 2020 and to test it in 2021. In light of the impact
of the Covid-19 virus we have applied to the Kazakh regulatory
authorities to defer that commitment and await their response.
3A Best
The licence is due for renewal in June 2020 and an application
has been made for the licence's renewal and an early response is
expected. Under our current 2020 work programme commitments we are
obliged to drill only one well to a depth of 2,500 meters at an
expected cost of $2 million. However, given the Covid-19 virus and
the measures taken by the Kazakh authorities to mitigates its
impact, we do not expect to be held to this obligation.
Reserves
BNG
In 2011 Gaffney Cline & Associates ("GCA") undertook a
technical audit of the BNG license area and subsequently Petroleum
Geology Services ("PGS") to undertake depth migration work, based
on the 3D seismic work carried out in 2009 and 2010.
The work of GCA resulted in confirming total unrisked resources
of 900 million barrels from 37 prospects and leads mapped from the
3D seismic work undertaken in 2009 and 2010. The report of GCA also
confirmed risked resources of 202 million barrels as well as
Most-Likely Contingent Resources of 13 million barrels on South
Yelemes.
In September 2016 GCA assessed the reserves attributable to the
BNG shallow structures.
Between then and the end of 2019, approximately 2 mmbls of oil
were produced, which under financial reporting rules are deducted
from the assessment of reserves as at 31 December 2019.
As at 31 December As at 31 December 2018
2019
---------------------------
mmbls mmbls
--------------------------- ---- -----------------------
BNG
--------------------------- ---- -----------------------
Shallow P1 16.1 17.8
---- -----------------------
Shallow P2 27.8 28.8
---- -----------------------
Deep P1 Nil Nil
---- -----------------------
Deep P2 Nil Nil
---- -----------------------
The above is based on 100% of each Contract Area.
3A Best
There has been no assessment of the reserve base at the 3A Best
Contract Area.
Financial review
Review of the results to 31 December 2019
Revenue
Revenue in 2019 increased by 13 per cent compared to 2018,
despite production volumes declining by 9 per cent.
We benefited for the final four months of the year by selling
the majority of the oil produced by reference to international
rather than domestic prices.
Production volumes in 2019, were 506,620 barrels compared to
589,750 barrels in 2018. This was the result of choosing to run the
first five producing wells at the MJF structure at or near maximum
capacity to generate income to fund the business without the
customary shut-in's for routine maintenance. Accordingly, we
experienced a higher level of depletion during the period under
review than would have been the case with periodic workovers.
Gross profit
For the first time we report a gross profit of $5.1 million
(2018: nil) This follows different accounting rules for oil sold
under production licences rather than under appraisal licences.
The method of accounting for production sold under an
exploration phase of an appraisal licence differs from the sale of
oil under a full production licence in which commercial production
is considered to have been reached.
Under an appraisal licence revenues are treated as a
contribution to the costs associated with the main objective, which
is to ascertain the productive capabilities of the producing wells
concerned. Therefore, whilst revenue is recorded as an amount
equivalent to the margin amounts derived from the sale of oil are
charged to cost of sale and recorded as a reduction in the
appraisal assets resulting in a zero gross profit.
Under a production licence only the actual costs of production
are recorded as costs of sales so that any excess of receipts over
direct costs is shown as gross profit.
Selling expenses of $2.2 million (2018: nil) relate to export
and customs duties.
A reversal of impairment of $2.4 million (2018: nil) has been
recorded, representing the portion of the historic impairment
provision of c$12 million that relates to the MJF structure that
has now commenced commercial production which enables it to realise
significant economic value.
Other administrative expenses
Other administrative costs at $3.9 million (2018: $2.6 million)
were $1.3 million greater reflecting the increased operational and
corporate activity. We believe we remain a low cost operator, in
comparison to other listed companies and companies operating in
Kazakhstan.
Tax charge
The tax charge for 2019 at approximately $2.3 million (2018:
$0.6 million) includes a provision of $1.9 million for withholding
tax on inter group interest.
Oil and gas assets
The carrying value of unproven oil and gas assets in these
consolidated group accounts increased from $55.7 million to $60.0
million. The increase represented the combination of the
acquisition of the 3A Best exploration assets for $12.6 million and
drilling and other capitalised costs of $8.9 million; before
deductions in respect of sales from test production $5.5 million
and transfers of the MJF assets to proven oil and gas assets within
property, plant and equipment of $12.0 million.
Plant, property and equipment increased during the period under
review from $0.1 million to $51.3 million, comprising principally
the transfer in respect of the MJF structure ($12 million)
following the export licence contract being secured and associated
commercial phase production commencing; an amount of derived from
the current value of the licence payments assessed by the Kazakh
regulatory authorities against the BNG Contract Area ($28.3
million); and the purchase of drilling and other equipment ($8.0
million).
Cash position
Unusually, at the year-end we had cash balances of approximately
$4.1 million (2018: $0.6 million). This resulted principally from
the timings of the cash advances from local oil traders and are
broadly offset by the amounts due to the oil traders recorded in
liabilities.
Liabilities
The move of the MJF structure to an export licence resulted in a
one-off working capital squeeze, which lies behind much of the
higher than usual liabilities at the year end.
For domestic sales we generally receive payment from local oil
traders one month in advance of production. However, for
international sales we typically receive payments two months often
after production once the oil has been delivered to a distant port.
This in effect resulted, for that part of our production sold on
the international markets, in a three month period in Q4 2019, with
much reduced receipts from production.
Rather than raise additional long term equity capital thereby
diluting shareholders we have sought to manage our way through by
conserving cash and managing payments to suppliers. The issue is
working its way through the business and we expect to have returned
to normal trading terms with our suppliers by the end of Q3
2020.
Trade and other payables increased from $6.3 million at 31
December 2018 to $14.8 million at 31 December 2019. This comprises
principally advances from local oil traders ($7.0 million); other
payables ($4.3 million); and tax and social security ($1.8
million).
Additionally, a consequence of the working capital squeeze has
been an increase at 31 December 2019, in the loans provided by the
Oraziman family under the existing framework agreement to $4
million.
As at 31 December 2019, the provision for payments to be made
over the next 10 years as part of the award of the production
licence, termed BNG Licence Payments, has been estimated at $27.4
million. Other current provisions increased primarily due to amount
payable in respect of the 3A Best licence which are matched by a
corresponding receivable as they are indemnified by the
vendors.
Funding
Policy
Our approach to funding the business has not changed in the
period under review or subsequently, despite the recent Covid-19
created fall in world oil prices. It remains to seek to minimise
the issuance of equity and therefore to use other forms of funding
to develop our assets. In this way we seek to preserve the upside
for existing shareholders, even if this is at the expense of higher
costs in the short term.
From time to time we are prepared to issue equity, in particular
in situations where we expect the return to be a multiple of the
price paid, for example with both 3A Best and the Caspian Explorer,
or to fund the purchase of equipment that puts us in control of the
pace at which we develop our shallow structures.
Where we have issued shares we have done so at prices which we
believe more reflects the underlying value in the business rather
than at the conventional 10 per cent discount to the prevailing
share price. The premia achieved for share issues in the period
under review and subsequently have ranged from 3.2 to 27.7
percent.
Going concern
The Board have assessed cash flow forecasts prepared for a
period of at least 12 months from the of approval of the financial
statements and assessed the risks and uncertainties associated with
the operations and funding position, including the potential
further effects of the COVID-19 pandemic.
The pandemic has had a significant impact on the business and
its cash generation through the collapse of international and
domestic oil prices and operational issues at local refineries and
loading stations, whilst operations have also been disrupted
through restrictions which continue to affect the ability of
workers, contractors, supplies and equipment to reach the site.
This was exacerbated in May 2020 when, as a one-off event, with
uncertainty in international demand and prices we had to decide
where to sell our oil. 100% of oil produced was allocated to the
domestic market which coincided with a fall in domestic prices
below $10/bbl due to operational issues at the local refinery. As a
result the income for production delivered in May 2020, was greatly
reduced. However, from June 2020 onwards, we have reverted to our
practice of seeking to sell approximately 60% of production on the
export markets with headline Brent prices currently approximately
$40 per barrel. Additionally, domestic prices are expected to
return to previous levels.
Under the base case forecasts, production is estimated at
1,700bopd with approximately 60% of oil production sold on the
export market at an anticipated $40/bbl and 40% sold on the
domestic market at an anticipated $15/bbl. The forecasts indicate
that the Group will be able to meet its operating expenditures,
taxes, social payment obligations under the licences and certain
licence obligations whilst enabling the Group to gradually pay down
accumulated creditor balances.
However, the Group's liquidity is dependent on a number of key
factors:
-- The Group continues to forward sell its domestic production
and receive advances from oil traders with $4.5m currently advanced
and the continued availability of such arrangements is important to
working capital. Whilst the Board anticipate such facilities
remaining available given its trader relationships and recent
increases, should they be withdrawn or reduced more quickly than
forecast cash flows allow then additional funding would be
required.
-- The forecasts assume that certain material licence
commitments and obligations respect of 3A Best and BNG will be
deferred by the authorities based on applications submitted in May
2020. Additionally, the forecasts assume that quarterly BNG Licence
Payments (refer to note19) will be revised to levels below the
current assessments received from the authorities, based on legal
proceedings initiated. In the event that the authorities refuse one
or more of such applications or the BNG licence payment is not
reduced additional funding will be required.
-- The Group has approximately $0.5m of aged creditors which are
being settled over the coming months from operating cash flows.
Whilst relations are positive with the suppliers, if their support
is withdrawn additional funding may be required.
-- The Group has $4m of loans due on demand or within the
forecast period to its largest shareholder and his connected
companies. Whilst the Board has received assurances that the
facilities will not be called for payment unless sufficient
liquidity exists, there are no binding agreements currently in
place to this effect and if repayment was required additional
funding would be needed.
-- The forecasts remain sensitive to oil prices, which have
shown significant volatility. Independent of the factors above, if
international oil prices fell below c$30/bbl additional actions
would be required including further cost reductions, additional
payment deferrals and raising funds.
The Directors remain confident that additional funding, if
required, could be obtained through a number of sources including:
further advances from local oil traders from the sale of oil yet to
be produced; industry funding in the form of partnerships with
larger industry players; further support from existing
shareholders; and if appropriate, equity funding from financial
institutions. However, there can be no guarantee that such funding
would be available and the terms of any new funding, if required,
may be onerous.
These circumstances indicate the existence of a material
uncertainty which may cast significant doubt about the Group's
ability to continue as a going concern and therefore it may be
unable to realise its assets and discharge its liabilities in the
normal course of business. The financial statements do not include
the adjustments that would result if the Group was unable to
continue as a going concern.
Notwithstanding the material uncertainty described above, after
making enquiries and assessing the progress against the forecast,
projections and the status of the mitigating actions referred to
above, the Directors have a reasonable expectation that the Group
will continue in operation and meet its commitments as they fall
due over the going concern period. Accordingly, the Directors
continue to adopt the going concern basis in preparing the
financial statements.
Low cost operator
We continue to pride ourselves on being a low-cost operator,
both as operators in the field and in controlling our General &
Administrative ("G&A") costs.
We believe our drilling costs, which following the acquisition
of our own rigs are now broadly $1.2 million for shallow wells and
$10 - $12 million (including completion and testing) for deep wells
are among the lowest in the industry. The presence of high pressure
at BNG reduces our lifting, treatment, storage and transport costs
for domestic sales are estimated at approximately $3 per barrel.
For export sales our lifting, treatment storage and transport costs
are estimated to be $7 per barrel.
Employees
Following the suspension of operational drilling the Group now
has 71 employees, including Directors, of whom 68 are based in
Kazakhstan and split principally between the corporate offices in
Almaty and in the field. As ever the board is grateful for their
continued contributions.
For those working in the field oil exploration is potentially
very dangerous with the risk of serious injury ever present. The
work continues on a 24 hour basis with 12 hour shifts and
fortnightly rotations. The work is undertaken often in terrible
weather with temperatures peaking at more than 40 degrees in the
summer and falling to as low as minus 35 degrees in the winter. In
addition the geography the Steppe region results in very strong and
dangerous winds for those working often many meters above the
ground.
During the period under review I had the opportunity for an
extended stay in the field at both assets we own and those we may
have an interest in owning in the future and witnessed first-hand
the difficulties faced by those working at each well location. The
success of the Group is built on the efforts of these key
workers.
Move to the UAE
During the period under review and subsequently we moved the
location of the Group's intermediate holding companies to the UAE.
The UAE is closer to our oilfields and to the corporate offices in
Almaty. The move has allowed the Group to significantly reduce
general & administrative expenditure in the UK and the
Netherlands.
Over time we intend to make the UAE the centre of Group treasury
operations.
Market reporting
Earlier this year we ended the monthly disclosure of prices
achieved in the domestic and export markets for fear of impacting
our commercial position in subsequent months.
However, announcing solely production volumes on a monthly basis
is out of line with market practice and also seems to provoke
suspicion in some of what is not included in such announcements.
Accordingly, we will seek to provide much fuller operational
updates on a quarterly basis but cease the practice of announcing
monthly production numbers. Significant events, operational or
otherwise, will continue to be announced at the appropriate time as
required under the AIM Rules.
The investment case
Even before the recent international oil price fall the
statistics for the smaller AIM Exploration and Production companies
made for depressing reading. The sector was out of favour with few
companies providing positive returns for their investors.
Early stage exploration has always been difficult to fund
through the public markets. With exploration cycles of 7-10 years
and the interest span of investors typically measured in months,
even before the dramatic price decline, the days when interesting
early stage exploration can be funded entirely via the public
markets may be long gone.
The current position
Our immediate objective is to come through the present situation
in good shape to benefit from the medium and longer term
opportunities we believe still exist. In this we have the following
advantages:
We have production.
The base production capacity from our existing shallow wells is
already some 2,000 bopd. To that we hope to be able to add
production from New Wells 151 and 152 and more impactfully from our
already drilled deep wells.
We are a low cost operator
-- we have low lifting costs and transportation costs
-- a large proportion of our costs re in Kazakh Tenge, which has
devalued significantly in recent years
-- we now own four rigs thereby reducing the cash costs of future exploration
We do not have any long term debt
Other than the Oraziman family loan and short term finance
provided by local oil traders, we have no external debt.
Medium / longer term
We continue to be believe that for much of the last decade there
has been a very significant lack of exploration activities leading
to the discovery of meaningful new reserves. Every year a
significant portion of the world's proven reserves are consumed by
production. As demand for oil recovers and with the lack of recent
exploration activity those with proven assets should expect to
attract interest over the medium and longer terms.
The current Covid-19 related problems in the market may well
create new acquisition opportunities for those with access to
funding.
Operating with a low oil price
Operating with a low oil price is nothing new as until August
2019, all our oil sales were at domestic prices, which continue to
be much lower than international prices.
We have reliable production, which we expect will continue to
increase at relatively low risk. In particular, the MJF structure
infill programme already underway should be a succession of easy
wins.
-- The wells are typically only 2,500 meters deep and do not
need to penetrate the salt layer, thereby avoiding any high
temperature / high pressure issues
-- The infill wells are located inside the perimeter of a
structure we already know to contain oil.
-- The oil flows naturally to the surface removing the need for
expensive artificial stimulation
-- With our own rigs we can drill when it suits us and at relatively low cost.
The bulk of the drilling costs of our four existing deep wells
have already been incurred and already paid. In the event these
wells come into meaningful production it will dramatically improve
our cashflows
Once acquired the Caspian Explorer is capable earning up to $25
million per annum in the event it is commissioned for northern
Caspian Sea exploration work.
Outlook
We have confidence in our assets and their value over the medium
/ longer term. To realise this value however, we first need to deal
with the current situation.
Despite market conditions we have sourced additional funding to
continue to develop both our shallow and deep prospects. We further
believe the Group's advantages noted above and the steps already
taken provide the basis to overcome the short term issues and then
when the time is right move forward when we expect there to be
plenty of new opportunities.
While the present situation is undoubtedly difficult, we believe
we are well placed to come through and subsequently prosper.
Clive Carver
Executive Chairman
24 June 2020
Qualified Person & Glossary
Qualified Person
Mr. Assylbek Umbetov, who works in the Group's geological
department, has reviewed and approved the technical disclosures in
this announcement.
Glossary
SPE - the Society of Petroleum Engineers
Bopd - barrels of oil per day
Mmbs - million barrels.
Proven reserves
Proven reserves (P1) are those quantities of petroleum which, by
analysis of geosciences and engineering data, can be estimated with
reasonable certainty to be commercially recoverable, from a given
date forward, from known reservoirs and under defined economic
conditions, operating methods, and government regulations. If
deterministic methods are used, the term reasonable certainty is
intended to express a high degree of confidence that the quantities
will be recovered. If probabilistic methods are used, there should
be at least a 90% probability that the quantities actually
recovered will equal or exceed the estimate.
Probable reserves
Probable reserves are those additional reserves which analysis
of geosciences and engineering data indicate are less likely to be
recovered than proved reserves but more certain to be recovered
than possible reserves. It is equally likely that actual remaining
quantities recovered will be greater than or less than the sum of
the estimated proved plus probable reserves (2P). In this context,
when probabilistic methods are used, there should be at least a 50%
probability that the actual quantities recovered will equal or
exceed the 2P estimate.
Possible reserves
Possible reserves are those additional reserves which analysis
of geosciences and engineering data indicate are less likely to be
recovered than probable reserves. The total quantities ultimately
recovered from the project have a low probability to exceed the sum
of proved plus probable plus possible (3P), which is equivalent to
the high estimate scenario. In this context, when probabilistic
methods are used, there should be at least a 10% probability that
the actual quantities recovered will equal or exceed the 3P
estimate.
Contingent resources
Contingent resources are those quantities of petroleum
estimated, as of a given date, to be potentially recoverable from
known accumulations, but the applied project(s) are not yet
considered mature enough for commercial development due to one or
more contingencies. Contingent resources may include, for example,
projects for which there are currently no viable markets, or where
commercial recovery is dependent on technology under development,
or where evaluation of the accumulation is insufficient to clearly
assess commerciality. Contingent resources are further categorized
in accordance with the level of certainty associated with the
estimates and may be sub-classified based on project maturity
and/or characterized by their economic status.
Prospective resources
Prospective resources are those quantities of petroleum
estimated, as of a given date, to be potentially recoverable from
undiscovered accumulations. Potential accumulations are evaluated
according to their chance of discovery and, assuming a discovery,
the estimated quantities that would be recoverable under defined
development projects.
Directors' report
The Directors present their annual report on the operations of
the Company and the Group, together with the audited financial
statements for the year ended 31 December 2019. The Strategic
report forms part of the business review for this year.
Principal activity
The principal activity of the Group is oil and gas exploration
and production.
Results and dividends
The consolidated statement of profit or loss is set out on page
46 and shows US$1.4 million loss for the year (2018: US$8.5
million). The Directors do not recommend the payment of a dividend
for the year ended 31 December 2019 (2018: US$ nil). The position
and performance of the Group is discussed below and further details
are given in the business review.
Review of the year
The review of the year and the Directors' strategy are set out
in the Chairman's Statement and the Strategic Report.
Events after the reporting period
Other than:
-- The proposed acquisition of the Caspian Explorer
-- The actions taken in response of the Covid-19 virus
-- Operational and financial developments
all as disclosed in this annual report, including notes to the
financial statements, there have been no material events between 31
December 2019, and the date of this report, which are required to
be brought to the attention of shareholders. Please refer to note
27 of these financial statements for further details.
Board changes
In January 2019, Tim Field joined the Board as a non-executive
director. Tim is a highly experienced international corporate
lawyer working in London. His input into the oversight of the
Company and its future direction is much valued.
Employees
Staff employed by the Group are based primarily in Kazakhstan.
The recruitment and retention of staff, especially at management
level, is increasingly important as the Group continues to build
its portfolio of oil and gas assets.
As well as providing employees with appropriate remuneration and
other benefits together with a safe and enjoyable working
environment, the Board recognises the importance of communicating
with employees to motivate them and involve them fully in the
business. For the most part, this communication takes place at a
local level and staff are kept informed of major developments
through email updates. They also have access to the Group's
website.
The Group has taken out full indemnity insurance on behalf of
the Directors and officers.
Health, safety and environment
It is the Group's policy and practice to comply with health,
safety and environmental regulations and the requirements of the
countries in which it operates, to protect its employees, assets
and environment.
Charitable and Political donations
During the year the Group made no charitable or political
donations.
Directors and Directors' interests
The Directors of the Group and the Company who held office
during the period under review and up to the date of the Annual
Report are as follows:
Clive Carver
Kuat Oraziman
Edmund Limerick
Timothy Field (appointed 25 January 2019)
Directors' interests
Number of shares Number of shares
As at 31 December
Director 2019 As at December 2018
------------------ --------------------
Clive Carver nil nil
------------------ --------------------
Kuat Oraziman* 41,485,330 37,285,330
------------------ --------------------
Edmund Limerick** 6,430,000 6,430,00
------------------ --------------------
Timothy Field nil nil
------------------ --------------------
* Taken together Mr Oraziman and his adult children held
807,275,739 shares on 31 December 2019
** includes 1,135,000 shares held by his wife
Biographical details of the current Directors are set out on the
Company's website www.caspiansunrise.com.
Details of the Directors' individual remuneration, service
contracts and interests in share options are shown in the
Remuneration Committee Report.
Financial instruments
Details of the use of financial instruments by the Group and its
subsidiary undertakings are contained in note 24 of the financial
statements.
Statement of disclosure of information to auditors
All of the current Directors have taken all the steps that they
ought to have taken to make themselves aware of any information
needed by the Group's auditors for the purposes of their audit and
to establish that the auditors are aware of that information. The
Directors are not aware of any relevant audit information of which
the auditors are unaware.
Auditors
BDO LLP have indicated their willingness to continue in office
and a resolution concerning their reappointment will be proposed at
the next Annual General Meeting.
Directors' responsibilities
The Directors are responsible for preparing the annual report
and the financial statements in accordance with applicable law and
regulations.
Company law requires the Directors to prepare financial
statements for each financial year. Under that law the Directors
have elected to prepare the Group and Company financial statements
in accordance with International Financial Reporting Standards
(IFRSs) as adopted by the European Union.
Under Company law the Directors must not approve the financial
statements unless they are satisfied that they give a true and fair
view of the state of affairs of the Group and Company and of the
profit or loss of the Group for that period. The Directors are also
required to prepare financial statements in accordance with the
rules of the London Stock Exchange for companies trading securities
on the London Stock Exchange AIM Market.
In preparing these financial statements, the Directors are
required to:
-- select suitable accounting policies and then apply them consistently;
-- make judgements and accounting estimates that are reasonable and prudent;
-- state whether they have been prepared in accordance with
IFRSs as adopted by the European Union, subject to any material
departures disclosed and explained in the financial statements;
-- prepare the financial statements on the going concern basis
unless it is inappropriate to presume that the Company and the
Group will continue in business.
The Directors are responsible for keeping adequate accounting
records that are sufficient to show and explain the Group's and the
Company's transactions and disclose with reasonable accuracy at any
time the financial position of the Group and the Company and enable
them to ensure that the financial statements comply with the
requirements of the Companies Act 2006.
They are also responsible for safeguarding the assets of the
Group and the Company and hence for taking reasonable steps for the
prevention and detection of fraud and other irregularities.
Website publication
The Directors are responsible for ensuring the annual report and
the financial statements are made available on a website. Financial
statements are published on the Group's website in accordance with
legislation in the United Kingdom governing the preparation and
dissemination of financial statements, which may vary from
legislation in other jurisdictions. The maintenance and integrity
of the Group's website is the responsibility of the Directors. The
Directors' responsibility also extends to the ongoing integrity of
the financial statements contained therein.
Clive Carver
Executive Chairman
24 June 2020
INDEPENT AUDITOR'S REPORT TO THE MEMBERS OF
CASPIAN SUNRISE PLC
Opinion
We have audited the financial statements of Caspian Sunrise Plc
(the 'Parent Company') and its subsidiaries (the 'Group') for the
year ended 31 December 2019 which comprise the consolidated
statement of profit or loss, the consolidated statement of other
comprehensive income, the consolidated statement of changes in
equity, the parent company statement of changes in equity, the
consolidated statement of financial position, the parent company
statement of financial position, the consolidated and parent
company statements of cash flows and notes to the financial
statements, including a summary of significant accounting
policies.
The financial reporting framework that has been applied in the
preparation of the Group financial statements is applicable law and
International Financial Reporting Standards (IFRSs) as adopted by
the European Union and, as regards the Parent Company financial
statements, as applied in accordance with the provisions of the
Companies Act 2006.
In our opinion:
-- the financial statements give a true and fair view of the
state of the Group's and of the Parent Company's affairs as at 31
December 2019 and of the Group's loss for the year then ended;
-- the Group financial statements have been properly prepared in
accordance with IFRSs as adopted by the European Union;
-- the Parent Company financial statements have been properly
prepared in accordance with IFRSs as adopted by the European Union
and as applied in accordance with the provisions of the Companies
Act 2006; and
-- the financial statements have been prepared in accordance
with the requirements of the Companies Act 2006.
Basis for opinion
We conducted our audit in accordance with International
Standards on Auditing (UK) (ISAs (UK)) and applicable law. Our
responsibilities under those standards are further described in the
Auditor's responsibilities for the audit of the financial
statements section of our report. We are independent of the Group
and the Parent Company in accordance with the ethical requirements
that are relevant to our audit of the financial statements in the
UK, including the FRC's Ethical Standard as applied to listed
entities, and we have fulfilled our other ethical responsibilities
in accordance with these requirements. We believe that the audit
evidence we have obtained is sufficient and appropriate to provide
a basis for our opinion.
Material uncertainty in relation to going concern
We draw attention to note 1.1 in the financial statements
concerning the Group and the Parent Company's ability to continue
as a going concern. Note 1.1 highlights that Group and Parent
Company's ability to meet its liabilities and commitments as they
fall due without additional funding is sensitive to the oil prices
realised across the forecast period and, separately, it is
dependent upon the deferral of financial obligations and drilling
commitments associated with its licences, continued availability of
oil trader advances and the continued support of certain creditors
together with other matters set out therein. These factors are
outside the control of the Group and the Parent Company and there
is no certainty that any funding that may therefore be required can
be secured within the necessary timescales. These events or
conditions indicate that a material uncertainty exists that may
cast signi cant doubt on the Group and the Parent Company's ability
to continue as a going concern. Our opinion is not modi ed in
respect of this matter.
We consider going concern to be a Key Audit Matter based on our
assessment of the risk and the effect on our audit. Our response to
this key audit matter is shown below:
-- We discussed the potential impact of Covid-19 with management
and the Audit Committee including their assessment of risks and
uncertainties associated with areas such as production disruption,
commodity price volatility and the impact on the availability of
funding. We formed our own assessment of risks and uncertainties
based on our understanding of the business and oil sector.
-- We obtained management's cash flow forecasts and critically
assessed the key inputs. In doing so we compared oil prices to
market data, production levels to recent performance trends and
operating costs to historical data.
-- We evaluated the completeness of forecast license related
expenditure against the license work programs and payments due
under the 3A Best license. We inspected submissions made to the
relevant authorities for deferral of work program commitments and
payments due and held discussions with management and the Audit
Committee regarding the status of such applications.
-- We compared the forecast cash payments in respect of the BNG
production license award against the $32m assessment received from
the Government payable in instalments over 10 years. We discussed
the status of the court process with management and the Audit
Committee which seeks to reduce the payments to the level included
in the forecast and considered the impact of the court process
being unsuccessful.
-- We considered the appropriateness of the Board's judgment
regarding the availability of sufficient oil trader funding through
the forecast period. In doing so, we considered factors such as the
production profile, oil price trends, the terms of the arrangements
and the history of transactions with the oil traders.
-- We assessed the terms of the loans provided from the Group's
largest shareholder and his connected companies, the dependence on
continued support and the Board's conclusion that the loans will
not be called for payment for at least the next 12 months unless
the Group has sufficient liquidity. We obtained written
representation from the Board regarding this assessment.
-- We evaluated management's sensitivity analysis and performed
our own sensitivity analysis in respect of the key assumptions
underpinning the forecasts, including specific scenarios such as
reduced revenue cash flows or the impact of one or more adverse
events such as withdrawal of facilities, withdrawal of creditor
support or license payments or commitments being enforced. We
assessed the validity of any mitigating actions identified by
Management.
-- We reviewed the adequacy and completeness of the disclosure
included within the financial statements in respect of going
concern.
Key audit matters
In addition to the matter described in the material uncertainty
related to going concern section, key audit matters are those
matters that, in our professional judgment, were of most
significance in our audit of the financial statements of the
current period and include the most significant assessed risks of
material misstatement (whether or not due to fraud) we identified,
including those which had the greatest effect on: the overall audit
strategy, the allocation of resources in the audit; and directing
the efforts of the engagement team. These matters were addressed in
the context of our audit of the financial statements as a whole,
and in forming our opinion thereon, and we do not provide a
separate opinion on these matters.
Key audit matter: The risk that the carrying value of the oil
and gas assets require impairment or that previously recorded
impairments should be reversed
As at 31 December 2019, the Group's oil and gas assets related
to BNG and 3A Best were carried at US$103.2m as shown in notes
10 and 11. At each reporting period end, management are required
to assess the oil and gas assets for indicators of impairment
and, where such indicators exist, perform an impairment test.
Additionally, management are required to assess whether circumstances
that gave rise to historical impairment provisions no longer
apply and the impairments should be reversed.
In performing the impairment indicator review for the unproven
oil and gas assets in the exploration phase, management are
required to make a number of judgements as detailed in notes
1.8 and 2.1. In respect of the 3A Best oil and gas assets, as
detailed in note 2.5 management applied significant judgment
in concluding that its application for deferral of the payments
due in July 2020 under the licence will be successful following
application to the Government and that the license will be extended.
As a result, no impairment was considered to be appropriate
by management.
In respect of the MJF production license, as detailed in note
2.3 management recorded a reversal of $2.4m of historical impairment
provision based on the net present value forecasts for the field,
which required estimation and judgment regarding the inputs
to the forecasts and assessing whether the factors that gave
rise to the original impairment no longer applied.
Given the judgment and estimation required by management, we
considered this area to be a key focus for our audit.
How the matter was addressed in our audit
* We considered whether indicators of impairment
existed in respect of the BNG and 3A Best unproven
oil and gas assets. In doing so, we inspected the
licenses to confirm valid title and assessed the
compliance with the license conditions through review
of correspondence with the authorities and inquiries
of management. We inspected budgets and work programs
submitted to the Kazakh authorities to confirm that
further drilling and exploration is planned for the
assets. We considered the results of exploration
activity in the period for indications that the
licenses would be abandoned or that the recoverable
value would be below cost.
* In respect of the 3A Best license, we reviewed
correspondence from the Government which included
payment obligations which, if unfulfilled, would
entitle the Government to withdraw the license. We
discussed management's judgment that the obligations
would be ultimately be deferred and the license be
extended with the Audit Committee. In assessing the
judgment, we inspected applications submitted to the
Government, the history of investment in Kazakh oil
fields by the Group and the previous extensions and
revisions to work program commitments and
obligations.
* In respect of the MJF producing assets we inspected
the production license awarded in the period and
obtained management's net present value forecasts and
critically assessed the inputs. In doing so, we
compared the oil price forecasts as at 31 December
2019 to market consensus forecasts and compared
operational production and cost assumptions to the
2015 Competent Person's Report, historical data and
other third party sources.
* We evaluated the independence and competence of the
Competent Person as a management expert.
* We considered management's judgment that it was
appropriate to record a reversal of previous
impairment associated with the MJF producing assets.
In doing so, we considered the impact of the
production license award on the field economics and
the recoverable value calculated by management. We
evaluated the basis on which management determined
the share of the historic impairment that related to
the MJF structure for consistency with the ratio of
the cost pool transferred into production upon the
commencement of commercial production.
* We assessed the disclosures included in the financial
statements at notes 2.1, 2.3, 2.5, 10 and 11.
Our observations
We found management's conclusion that no impairment exists on
the BNG oil and gas assets and 3A Best oil and gas assets to
be appropriate. We found the judgments made by management to
be appropriately considered and the disclosures in the notes
to be sufficient.
Key audit matter: Accounting for licence payment obligations
triggered by the award of the BNG production contract
Under the terms of the BNG license, on award of the production
contract the Group incurred an obligation for payments under
the licence as detailed in note 2.6, 11 and 19. Whilst the quantum
to be paid has been assessed by the Government authorities it
remains subject to dispute with a legal process ongoing. Management
recorded a provision and increase in the proven oil and gas
asset cost of $28.3m on initial recognition. The determination
of the appropriate accounting treatment and the estimate of
the provision required management to exercise judgment.
Given the judgment required and the material impact of the transaction,
this was considered to be a focus for our audit and a key audit
matter.
How the matter was addressed in our audit
* We reviewed the terms of the license to confirm that
a payment obligation was triggered upon award of the
contract.
* We reviewed correspondence with the relevant
authorities regarding the assessment of the quantum
of the payment due and the terms of payment which
formed the basis for the amounts recorded as a
provision. We inspected court applications which were
consistent with management's assertions that they
were challenging the quantum of the assessment and
discussed the basis for the legal proceedings with
management and the Audit Committee.
* We recalculated the provision and compared the
discount rate to market bond yield data for similar
termed instruments.
* We evaluated that accounting policy established by
management against relevant IFRS literature and the
nature of the transaction. In particular, this
involved assessing the extent to which capitalization
of the cost was appropriate in conjunction with our
technical specialists.
* We assessed the disclosures included in the financial
statements at notes 2.6, 11 and 19.
Our observations
We found the accounting treatment of the transaction to be appropriate.
Key audit matter: Appropriateness of revenue recognition policies
and the appropriateness of cut off for oil revenue
The Group generated revenues of $12.1m which arises both from
the test production and, for the first time in 2019, export
sales at BNG as shown in note 3. We considered there to be a
risk that the accounting policy for export revenues did not
meet the requirements of IFRS 15. In addition, we considered
there to be a risk of revenue being recorded in the incorrect
period for transactions around year end. Given these conditions
we considered revenue recognition to be a focus for our audit
and a key audit matter.
How the matter was addressed in our audit
* We evaluated the group's revenue recognition policies
for each revenue stream (export and domestic) and
assessed their compliance with IFRS 15 and its 5-step
revenue recognition model based around control and
consistency with the contractual arrangements with
its customers.
* We examined the terms of all significant sales
agreements and assessed the impact of such terms of
revenue recognition.
* We performed cut off procedures on revenue around the
year end for each revenue stream, to determine
whether revenue had been recognised in the correct
period. In doing so, we confirmed the appropriateness
of the revenue recognition point against the terms of
contract and delivery documents for items pre and
post year end.
* We verified a sample of oil production revenues to
supporting evidence.
Our observations
We found the revenue recognition policies to be compliant with
accounting standards and found that revenue is recorded in the
appropriate period.
Our application of materiality
Group materiality as at 31 Basis for materiality
December 2019
US$1,900,000 1.5% of total assets
----------------------
We apply the concept of materiality both in planning and
performing our audit and in evaluating the effect of misstatements.
We consider materiality to be the magnitude by which misstatements,
including omissions, could influence the economic decisions of
reasonable users that are taken on the basis of the financial
statements.
Importantly, misstatements below these levels will not
necessarily be evaluated as immaterial as we also take account of
the nature of identified misstatements, and the particular
circumstances of their occurrence, when evaluating their effect on
the financial statements as a whole.
Materiality for the Group financial statements as a whole was
set at $1,900,000, being 1.5% of total assets (2018: $1,000,000).
We consider total assets to be the most relevant consideration of
the Group's financial performance as the Group continues to focus
on oil and gas exploration. Materiality for the Parent Company
financial statements was set at $1,710,000, being 90% of Group
materiality (2018: $800,000 capped at 80% of Group
materiality).
In performing the audit we applied a lower level of performance
materiality of $1,425,000, being 75% of Group materiality (2018:
$750,000), in order to reduce to an appropriately low level the
probability that the aggregate of uncorrected and undetected
misstatements exceeds financial statement materiality. Each
significant component of the Group including the parent company was
audited using a lower level of performance materiality ranging from
$300,000 to $900,000 (2018: $600,000 to $675,000).
We agreed with the Audit Committee that we would report to the
committee all individual audit differences in excess of $70,000
(2018: $50,000). We also agreed to report differences below this
threshold that, in our view, warranted reporting on qualitative
grounds.
An overview of the scope of our audit
Our Group audit was scoped by obtaining an understanding of the
Group and its environment and assessing the risks of material
misstatement in the financial statements at the Group level.
The Group's operations principally comprise oil and gas
exploration and production in Kazakhstan. We assessed there to be 3
significant components comprising BNG, 3A Best and the parent
company.
These locations, which were subject to full scope audit
procedures represent the principal business units.
Non-BDO member firms performed a full scope audit of BNG and 3A
Best in Kazakhstan, under our direction and supervision as Group
auditors. The audit of the Parent Company and the Group
consolidation were performed in the United Kingdom by BDO LLP.
As part of our audit strategy, as Group auditors:
-- Detailed Group reporting instructions were sent to the
component auditors, which included the significant areas to be
covered by the audit.
-- As a result of travel restrictions resulting from the
COVID-19 pandemic, senior members of the group audit team were
unable to visit Kazakhstan to meet with component management and
the component auditors during the audit completion phase as we have
done historically. Accordingly, we performed a remote review of the
component audit files in Kazakhstan using online software platforms
and held regular calls with the component audit teams during the
planning and completion phases of their audit.
-- We reviewed Group reporting submissions received and held
calls and meetings with the component audit team during the
completion phases of their audit to discuss significant findings
from their audit.
-- We held calls and meetings with members of Group and
component management to discuss accounting and audit matters
arising.
-- The Group audit team was actively involved in the direction
of the audits performed by the component auditors, along with the
consideration of findings and determination of conclusions drawn.
We performed our own additional procedures in respect of the
significant risk areas that represented Key Audit Matters in
addition to the procedures performed by the component auditor.
Other information
The Directors are responsible for the other information. The
other information comprises the information included in the Annual
Report and Financial Statements, other than the financial
statements and our auditor's report thereon. Our opinion on the
financial statements does not cover the other information and,
except to the extent otherwise explicitly stated in our report, we
do not express any form of assurance conclusion thereon.
In connection with our audit of the financial statements, our
responsibility is to read the other information and, in doing so,
consider whether the other information is materially inconsistent
with the financial statements or our knowledge obtained in the
audit or otherwise appears to be materially misstated. If we
identify such material inconsistencies or apparent material
misstatements, we are required to determine whether there is a
material misstatement in the financial statements or a material
misstatement of the other information. If, based on the work we
have performed, we conclude that there is a material misstatement
of this other information, we are required to report that fact. We
have nothing to report in this regard.
Opinions on other matters prescribed by the Companies Act
2006
In our opinion, based on the work undertaken in the course of
the audit:
-- the information given in the strategic report and the
Directors' report for the financial year for which the financial
statements are prepared is consistent with the financial
statements; and
the strategic report and the Directors' report have been
prepared in accordance with applicable legal requirements.
Matters on which we are required to report by exception
In the light of the knowledge and understanding of the Group and
the Parent Company and its environment obtained in the course of
the audit, we have not identified material misstatements in the
strategic report or the Directors' report.
We have nothing to report in respect of the following matters in
relation to which the Companies Act 2006 requires us to report to
you if, in our opinion:
-- adequate accounting records have not been kept by the Parent
Company, or returns adequate for our audit have not been received
from branches not visited by us; or
-- the Parent Company financial statements are not in agreement
with the accounting records and returns; or
-- certain disclosures of Directors' remuneration specified by law are not made; or
-- we have not received all the information and explanations we require for our audit.
Responsibilities of Directors
As explained more fully in the Directors' responsibilities
statement set out on page 28, the Directors are responsible for the
preparation of the financial statements and for being satisfied
that they give a true and fair view, and for such internal control
as the Directors determine is necessary to enable the preparation
of financial statements that are free from material misstatement,
whether due to fraud or error.
In preparing the financial statements, the Directors are
responsible for assessing the Group's and the Parent Company's
ability to continue as a going concern, disclosing, as applicable,
matters related to going concern and using the going concern basis
of accounting unless the Directors either intend to liquidate the
Group or the Parent Company or to cease operations, or have no
realistic alternative but to do so.
Auditor's responsibilities for the audit of the financial
statements
Our objectives are to obtain reasonable assurance about whether
the financial statements as a whole are free from material
misstatement, whether due to fraud or error, and to issue an
auditor's report that includes our opinion. Reasonable assurance is
a high level of assurance, but is not a guarantee that an audit
conducted in accordance with ISAs (UK) will always detect a
material misstatement when it exists.
Misstatements can arise from fraud or error and are considered
material if, individually or in the aggregate, they could
reasonably be expected to influence the economic decisions of users
taken on the basis of these financial statements.
A further description of our responsibilities for the audit of
the financial statements is located on the Financial Reporting
Council's website at: www.frc.org.uk/auditorsresponsibilities .
This description forms part of our auditor's report.
Use of our report
This report is made solely to the Parent Company's members, as a
body, in accordance with Chapter 3 of Part 16 of the Companies Act
2006. Our audit work has been undertaken so that we might state to
the Parent Company's members those matters we are required to state
to them in an auditor's report and for no other purpose. To the
fullest extent permitted by law, we do not accept or assume
responsibility to anyone other than the Parent Company and the
Parent Company's members as a body, for our audit work, for this
report, or for the opinions we have formed.
Ryan Ferguson (Senior Statutory Auditor)
For and on behalf of BDO LLP, Statutory Auditor
London,
United Kingdom
24 June 2020
BDO LLP is a limited liability partnership registered in England
and Wales (with registered number OC305127).
Consolidated Statement of Profit or Loss
Notes Year to Year to
31 December 31 December
2019 201 8
-------------------------------------------- -----
US$'000 US$'000
-------------------------------------------- ----- ------------------ ------------------
Revenue 3 12,108 10,747
Cost of sales (6,971) (10,747)
-------------------------------------------- ----- ------------------ ------------------
Gross profit 5,137 -
Selling expense (2,220) -
Impairment reversal of unproven and
proved oil and gas assets 11 2,414 -
-------------------------------------------- ----- ------------------ ------------------
Share-based payments (31) (13)
Other administrative costs (3,907) (2,611)
-------------------------------------------- ----- ------------------ ------------------
Total administrative expenses (3,938) (2,624)
-------------------------------------------- ----- ------------------ ------------------
Operating income / (loss) 4 1,393 (2,624)
Finance cost 7 (452) (348)
Finance income - -
Profit/(Loss) before taxation 941 (2,972)
Tax charge 8 (2,343) (414)
-------------------------------------------- ----- ------------------ ------------------
Loss after taxation from continuing
operations (1,402) (3,386)
-------------------------------------------- ----- ------------------ ------------------
Loss for the year from discontinued
operations 20 - (5,147)
------------------ ------------------
Loss for the year (1,402) (8,533)
------------------ ------------------
Loss attributable to owners of the parent (1,278) (8,366)
Loss attributable to non-controlling
interest (124) (167)
-----
Loss for the year (1,402) (8,533)
-------------------------------------------- ----- ------------------ ------------------
Basic loss per ordinary share (US cents) 9
-------------------------------------------- ----- ------------------ ------------------
From continuing operations (0. 07) (0.19)
-------------------------------------------- ----- ------------------ ------------------
From discontinued operations - (0.31)
-------------------------------------------- ----- ------------------ ------------------
Total loss per share (0. 07) (0.5)
-------------------------------------------- ----- ------------------ ------------------
Diluted loss per ordinary share (US
cents) 9
-------------------------------------------- ----- ------------------ ------------------
From continuing operations (0. 07) (0.19)
-------------------------------------------- ----- ------------------ ------------------
From discontinued operations - (0.31)
-------------------------------------------- ----- ------------------ ------------------
Total loss per share (0. 07) (0.5)
-------------------------------------------- ----- ------------------ ------------------
Consolidated Statement of Comprehensive Income
Year ended Year ended
31 December 31 December
2019 2018
----------------------------------------------
US$000 US$000
---------------------------------------------- ------------- -------------
Loss after taxation (1,402) (8,533)
---------------------------------------------- ------------- -------------
Other comprehensive income:
Exchange differences on translating foreign
operations 268 (10,136)
Recycling of exchange difference on disposal
of subsidiary - 8,305
---------------------------------------------- ------------- -------------
Total comprehensive loss for the year (1,134) (10,364)
---------------------------------------------- ------------- -------------
Total comprehensive loss attributable to:
Owners of parent (1,010) (9,277)
Non-controlling interest (124) (1,087)
---------------------------------------------- ------------- -------------
Consolidated Statement of Changes in Equity
Share Share Deferred Cumulative Other Retained Total Non-controlling Total
capital premium shares translation reserves deficit attributable interests equity
US$'000 US$'000 reserve US$'000 US$'000 to the owner US$'000 US$'000
US$'000 US$'000 of the
Parent
US$'000
Total equity
as at 1
January
2019 25,416 229,020 64,702 (55,911) (2,362) (219,230) 41,635 (5,605) 36,030
--------------- ------- ------- -------- ----------- -------- --------- ------------ --------------- --------
Loss after
taxation - - - - - (1,278) (1,278) (124) (1,402)
Exchange
differences
on
translating
foreign
operations
and recycling
of exchange
differences
on disposal
of
subsidiaries - - - 268 - - 268 - 268
--------------- ------- ------- -------- ----------- -------- --------- ------------ --------------- --------
Total
comprehensive
income/(loss)
for the year - - - 268 - (1,278) (1,010) (124) (1,134)
--------------- ------- ------- -------- ----------- -------- --------- ------------ --------------- --------
Shares issue 2,648 17,115 - - - - 19,763 - 19,763
Share options
exercised 56 164 - - - - 220 - 220
Arising on
employee
share
options - - - - - 31 31 - 31
Total equity
as at 31
December
2019 28,120 246,299 64,702 (55,643) (2,362) (220,477) 60,639 (5,729) 54,910
--------------- ------- ------- -------- ----------- -------- --------- ------------ --------------- --------
Share Share Deferred Cumulative Other Retained Total Non-controlling Total
capital premium shares translation reserves deficit attributable interests equity
US$'000 US$'000 reserve US$'000 US$'000 to the owner US$'000 US$'000
US$'000 US$'000 of the
Parent
US$'000
Total equity
as at 1
January
2018 25,401 228,974 64,702 (55,000) (2,362) (210,877) 50,838 (4,654) 46,184
--------------- ------- ------- -------- ----------- -------- --------- ------------ --------------- --------
Loss after
taxation - - - - - (8,366) (8,366) (167) (8,533)
Exchange
differences
on
translating
foreign
operations
and recycling
of exchange
differences
on disposal
of
subsidiaries - - - (911) - - (911) (920) (1,831)
--------------- ------- ------- -------- ----------- -------- --------- ------------ --------------- --------
Total
comprehensive
income/(loss)
for the year - - - (911) - (8,366) (9,277) (1,087) (10,364)
--------------- ------- ------- -------- ----------- -------- --------- ------------ --------------- --------
Disposal of
subsidiary - - - - - - - 136 136
Share options
exercised 15 46 - - - - 61 - 61
Arising on
employee
share
options - - - - - 13 13 - 13
--------------- ------- ------- -------- ----------- -------- --------- ------------ --------------- --------
Total equity
as at 31
December
2018 25,416 229,020 64,702 (55,911) (2,362) (219,230) 41,635 (5,605) 36,030
--------------- ------- ------- -------- ----------- -------- --------- ------------ --------------- --------
Equity Description and purpose
Share capital The nominal value of shares issued
Share premium Amount subscribed for share capital in excess of
nominal value
Deferred shares The nominal value of deferred shares issued
Cumulative translation reserve Gains/losses arising on
retranslating the net assets of overseas operations into US
Dollars, less amounts recycled on disposal of subsidiaries and
joint ventures
Other reserves Fair value of warrants issued and capital
contribution arising on discounted loans
Retained deficit Cumulative losses recognised in the
consolidated statement of profit or loss, adjustments on the
acquisition of non-controlling interests and transfers in respect
of share based payments
Non-controlling interest The interest of non-controlling parties
in the net assets of the subsidiaries
Parent Company Statement of Changes in Equity
Share Share Deferred Other Retained Total attributable
capital premium shares reserves deficit to the owner
US$'000 US$'000 US$'000 US$'000 US$'000 of the Parent
US$'000
Total equity as at 1 January 2019 25,416 229,020 64,702 14,936 (144,911) 189,163
--------------------------------------- -------- -------- -------- --------- --------- ------------------
Total comprehensive loss for the year - - - - (8,223) (8,223)
Restructuring of Intragroup Debt (see
Note 17) - - - (14,936) 14,936 -
Shares issue 2,648 17,115 - - - 19,763
Stock options exercised 56 164 - - - 220
Arising on employee share options - - - - 31 31
Total equity as at 31 December 2019 28,120 246,299 64,702 - (138,167) 200,954
--------------------------------------- -------- -------- -------- --------- --------- ------------------
Total equity as at 1 January 2018 25,401 228,974 64,702 14,936 (144,073) 189,940
--------------------------------------- ------ ------- ------ ------ --------- -------
Total comprehensive loss for the year - - - - (851) (851)
Stock options exercised 15 46 - - - 61
Arising on employee share options - - - - 13 13
Total equity as at 31 December 2018 25,416 229,020 64,702 14,936 (144,911) 189,163
--------------------------------------- ------ ------- ------ ------ --------- -------
Equity Description and purpose
Share capital The nominal value of shares issued
Share premium Amount subscribed for share capital in excess of
nominal value
Deferred shares The nominal value of deferred shares issued
Other reserves Fair value of warrants issued and capital
contribution arising on discounted loans
Retained deficit Cumulative losses recognised in the profit or
loss
Consolidated Statement of Financial Position
Company number 5966431 Notes Group Group
2019 201 8
US$'000 US$'000
------------------------------------------ ----- --------- ---------
Assets
Non-current assets
Unproven oil and gas assets 10 60,040 55,685
Property, plant and equipment 11 51,326 88
Inventories 1 3 384 132
Other receivables 14 5,745 8,445
Restricted use cash 241 249
------------------------------------------ ----- --------- ---------
Total non-current assets 117,736 64,599
------------------------------------------ ----- --------- ---------
Current assets
Other receivables 14 5,663 364
Cash and cash equivalents 15 4,060 557
------------------------------------------ ----- --------- ---------
Total current assets 9,723 921
------------------------------------------ ----- --------- ---------
Total assets 127,459 65,520
------------------------------------------ ----- --------- ---------
Equity and liabilities
Capital and reserves attributable
to equity holders of the parent
Share capital 16 28,120 25,416
Share premium 246,299 229,020
Deferred shares 16 64,702 64,702
Other reserves (2,362) (2,362)
Retained deficit (220,477) (219,230)
Cumulative translation reserve (55,643) (55,911)
------------------------------------------ ----- --------- ---------
Equity attributable to the owners of the
Parent 60,639 41,635
------------------------------------------ ----- --------- ---------
Non-controlling interests 26 (5,729) (5,605)
------------------------------------------ ----- --------- ---------
Total equity 54,910 36,030
------------------------------------------ ----- --------- ---------
Current liabilities
Trade and other payables 17 14,836 6,259
Short - term borrowings 18 4,050 2,572
Provision for BNG licence payment 19 3,178 -
Other current provisions 19 6,304 3,515
------------------------------------------ ----- --------- ---------
Total current liabilities 28,368 12,346
------------------------------------------ ----- --------- ---------
Non-current liabilities
Deferred tax liabilities 22 7,244 6,733
Provision for BNG licence payment 19 24,216 -
Other non-current provisions 19 428 125
Other payables 17 12,293 10,286
------------------------------------------ ----- --------- ---------
Total non-current liabilities 44,181 17,144
------------------------------------------ ----- --------- ---------
Total liabilities 72,549 29,490
------------------------------------------ ----- --------- ---------
Total equity and liabilities 127,459 65,520
------------------------------------------ ----- --------- ---------
Parent Company Statement of Financial Position
Company number 5966431 Notes Company Company
201 9 201 8
US$'000 US$'000
------------------------------------------ ----- --------- ---------
Assets
Non-current assets
Investments in subsidiaries 12 223,781 211,986
Other receivables 14 10,704 3,066
Total non-current assets 234,485 215,052
------------------------------------------ ----- --------- ---------
Current assets
Other receivables 14 7 6
Cash and cash equivalents 15 87 292
------------------------------------------ ----- --------- ---------
Total current assets 94 298
------------------------------------------ ----- --------- ---------
Total assets 234,579 215,350
------------------------------------------ ----- --------- ---------
Equity and liabilities
Capital and reserves attributable
to equity holders of the parent
Share capital 16 28,120 25,416
Share premium 246,299 229,020
Deferred shares 16 64,702 64,702
Other reserves - 14,936
Retained deficit (138,167) (144,911)
Equity attributable to the owners of the
Parent 200,954 189,163
------------------------------------------ ----- --------- ---------
Total equity 200,954 189,163
------------------------------------------ ----- --------- ---------
Current liabilities
Short - term borrowings 18 1,814 400
Trade and other payables 17 31,811 9,052
Total current liabilities 33,625 9,452
------------------------------------------ ----- --------- ---------
Non-current liabilities
Other payables 17 - 16,735
------------------------------------------ ----- --------- ---------
Total non-current liabilities - 16,735
------------------------------------------ ----- --------- ---------
Total liabilities 33,625 26,187
------------------------------------------ ----- --------- ---------
Total equity and liabilities 234,579 215,350
------------------------------------------ ----- --------- ---------
The Company incurred a loss for the year ended 31 December 2019
in the amount of US$ 8,223,000 (2018: US$ 851,000).
Consolidated and Parent Company Statements of Cash Flows
Group Group Company Company
2019 2018 2019 2018
Notes US$'000 US$'000 US$'000 US$'000
-------- -------- -------- --------
Cash flows from operating activities
Cash received from customers 16,465 9,025 - -
Return of taxes previously paid 8 - 1,013 - 1,013
Payments made to suppliers for
goods and services (6,767) (2,747) (1,128) (1,175)
Payments made to employees (1,226) (1,185) (597) (614)
---------------------------------------- -------- -------- -------- -------- --------
Net cash flow from operating
activities 8,472 6,106 (1,725) (776)
---------------------------------------- -------- -------- -------- -------- --------
Cash flows from investing activities
Purchase of property, plant
and equipment (669) (3) - -
Additions to unproven oil and
gas assets (5,830) (7,733) - -
Transfers from/(to) restricted
use cash 8 - - -
Proceeds from disposal of subsidiaries 20 - 134 - -
Advances repaid by subsidiaries - - 108 180
Advances issued to subsidiaries - - (100) (100)
Net cash flow from investing
activities (6,491) (7,602) 8 80
---------------------------------------- -------- -------- -------- -------- --------
Cash flows from financing activities
Net proceeds from issue of ordinary
share capital 220 61 220 61
Loans repaid 24 (28) (534) - -
Loans provided by subsidiaries - - - 600
Loans received 24 1,330 1,047 1,330 400
Repayment of loans provided
by subsidiaries - - (38) (90)
Net cash flow from financing
activities 1,522 574 1,512 971
---------------------------------------- -------- -------- -------- -------- --------
Net increase/(decrease) in cash
and cash equivalents 3,503 (922) (205) 275
Cash and cash equivalents at
the beginning of the year 557 1,479 292 17
---------------------------------------- -------- -------- -------- -------- --------
Cash and cash equivalents at
the end of the year 15 4,060 557 87 292
---------------------------------------- -------- -------- -------- -------- --------
Significant non-cash transactions include the following and
details can be found in notes 6, 7, 8, 10, 11, 16:
- Acquisition of 100% interest at 3A Best in exchange of issue
of 149,253,732 new Caspian Sunrise shares with the consideration
value of US$ 11,795,000 on the date (2018: US$ 0);
- Acquisition of PP&E in exchange of issue of 58,333,333 new
Caspian Sunrise shares with the value of US$ 7,996,000 (2018: US$
0);
- Share-based payments in the amount of US$ 31,000 (2018: US$ 13,000);
- Withholding tax in the amount of US$ 1,860,000 (2017: US$ 1,375,000);
- Exchange differences on translating foreign operations of US$ 49,000 (2018: US$ 3,154,000);
- Depreciation charge of US$ 148,000 (2018: US$ 31,000);
- Interest expense of US$ 452,000 (2018: US$ 348,000);
- Reversal of impairment on the BNG assets of US$2,414,000 (2018: US$Nil);
- Additions to the BNG proven oil and gas assets of
US$28,335,000 (2018: US$Nil) associated with the provision for
licence payments
* Additions to unproven oil and gas assets contain the amount of
US$ 185,500 in relation to payroll expenses capitalized (2018: US$:
332,000).
Notes to the Financial Statements
General information
Caspian Sunrise plc ("the Company") is a public limited company
incorporated and domiciled in England and Wales. The address of its
registered office is 5 New Street Square, London, EC4A 3TW. These
consolidated financial statements were authorised for issue by the
Board of Directors on 24 June 2020.
The financial information set out herein does not constitute the
Group's statutory financial statements for the year ended 31
December 2019, but is derived from the Group's audited financial
statements. The auditors have reported on the 2019 financial
statements and their report was unqualified and did not contain
statements under s498(2) or (3) Companies Act 2006 but did contain
a material uncertainty in relation to going concern.
The 2019 Annual Report was approved by the Board of Directors on
24 June 2020 The financial information in this statement is audited
but does not have the status of statutory accounts within the
meaning of Section 434 of the Companies Act 2006.
The principal activities of the Group are exploration and
production of crude oil.
1 Principal accounting policies
The principal accounting policies applied in the preparation of
these consolidated financial statements are set out below.
1.1 Basis of preparation
The Group's and Parent's financial statements have been prepared
in accordance with International Financial Reporting Standards as
adopted by the European Union ("IFRSs"), and with those parts of
the Companies Act 2006 applicable to companies reporting under
IFRSs.
The Board have assessed cash flow forecasts prepared for a
period of at least 12 months from the of approval of the financial
statements and assessed the risks and uncertainties associated with
the operations and funding position, including the potential
further effects of the COVID-19 pandemic.
However, the Group's liquidity is dependent on a number of key
factors:
-- The Group continues to forward sell its domestic production
and receive advances from oil traders with $4.5m currently advanced
and the continued availability of such arrangements is important to
working capital. Whilst the Board anticipate such facilities
remaining available given its trader relationships and recent
increases, should they be withdrawn or reduced more quickly than
forecast cash flows allow then additional funding would be
required.
-- The forecasts assume that certain material licence
commitments and obligations respect of 3A Best and BNG will be
deferred by the authorities based on applications submitted in May
2020. Additionally, the forecasts assume that quarterly payments in
respect of the BNG production licence will be revised to levels
below the current assessments received from the authorities, based
on legal proceedings initiated. In the event that the authorities
refuse one or more of such applications or the BNG licence payment
is not reduced additional funding will be required.
-- The Group has approximately $0.5m of aged creditors which are
being settled over the coming months from operating cash flows.
Whilst relations are positive with the suppliers, if their support
is withdrawn additional funding may be required.
-- The Group has $4m of loans due on demand or within the
forecast period to its largest shareholder and his connected
companies. Whilst the Board has received assurances that the
facilities will not be called for payment unless sufficient
liquidity exists, there are no binding agreements currently in
place to this effect and if repayment was required additional
funding would be needed.
-- The forecasts remain sensitive to oil prices, which have
shown significant volatility. Independent of the factors above, if
international oil prices fell below c$30/bbl additional actions
would be required including further cost reductions, additional
payment deferrals and raising funds.
The Directors remain confident that additional funding, if
required, could be obtained through a number of sources including:
further advances from local oil traders from the sale of oil yet to
be produced; industry funding in the form of partnerships with
larger industry players; further support from existing
shareholders; and if appropriate, equity funding from financial
institutions. However, there can be no guarantee that such funding
would be available and the terms of any new funding, if required,
may be onerous.
These circumstances indicate the existence of a material
uncertainty which may cast significant doubt about the Group's
ability to continue as a going concern and therefore it may be
unable to realise its assets and discharge its liabilities in the
normal course of business. The financial statements do not include
the adjustments that would result if the Group was unable to
continue as a going concern.
Notwithstanding the material uncertainty described above, after
making enquiries and assessing the progress against the forecast,
projections and the status of the mitigating actions referred to
above, the Directors have a reasonable expectation that the Group
will continue in operation and meet its commitments as they fall
due over the going concern period. Accordingly, the Directors
continue to adopt the going concern basis in preparing the
financial statements.
The Company has taken advantage of section 408 of the Companies
Act 2006 and has not included its own profit or loss in these
financial statements. The Group loss for the year included a loss
on ordinary activities after tax of US$8,223,000 (2018: US$
851,000) in respect of the Company.
The preparation of financial statements in conformity with IFRSs
requires the Management to make judgements, estimates and
assumptions that affect the application of policies and reported
amounts in the financial statements.
The areas involving a higher degree of judgement or complexity,
or areas where assumptions or estimates are significant to the
financial statements are disclosed in note 2.
1.2 New and revised standards and interpretations applied
The disclosed policies have been applied consistently by the
Group for both the current and previous financial year with the
exception of the new standards adopted.
The European Union ("EU") IFRS financial information has been
drawn up on the basis of accounting policies consistent with those
applied in the financial statements for the year to 31 December
2018, except for the following:
(a) IFRS 16 'Leases'
(b) IFRIC 23 'Uncertainty over Income Tax Positions'
(c) Prepayment Features with Negative Compensation - Amendments to IFRS 9
(d) Long-term Interests in Associates and Joint Ventures - Amendments to IAS 28
(e) Annual Improvements to IFRS Standards 2015 - 2017 Cycle
(f) Plan Amendment, Curtailment or Settlement - Amendments to IAS 19
In respect of IFRS 16 the Group amended accounting policies
applied from 1 January 2019 are disclosed in Note 3 under
'Significant accounting policies'.
IFRS 16 specifies how to recognise, measure, present and
disclose leases. The standard provides a single lessee accounting
model, requiring lessees to recognise right-of-use assets and lease
liabilities for all material leases. It results in almost all
leases being recognised on the balance sheet by lessees, as the
distinction between operating and finance leases was removed. Under
the new standard, an asset (the right to use the leased item) and a
financial liability to pay rentals are recognised. The only
exceptions are short-term and low-value leases. The Group adopted
IFRS 16 from 1 January 2019 using the modified retrospective
approach and accordingly the information presented for 2018 is not
restated. It remains as previously reported under IAS 17 and
related interpretations. The Group undertook an assessment of
contracts to identify potential lease arrangements and following
such analysis determined that the impact was immaterial.
Effective as of 1 January 2019, IFRIC 23 explains how to
recognise and measure deferred and current income tax assets and
liabilities where there is uncertainty over a tax treatment. An
uncertain tax treatment is any tax treatment applied by the Group
where there is uncertainty over whether that treatment will be
accepted by the tax authority. IFRIC 23 applies to all aspects of
income tax accounting where there is an uncertainty regarding the
treatment of an item, including taxable profit or loss, the tax
bases of assets and liabilities, tax losses and credits and tax
rates. refer to note 19 for details of uncertain tax positions.
Standards, amendments and interpretations, which are effective
for reporting periods beginning after the date of this financial
information which have not been adopted early:
Effective for
annual periods
beginning on
or after
Amendments to IFRS 3, 'Business combinations' 01-Jan-20
Amendments to IAS 1 and IAS 8: Definition of Material 01-Jan-20
Amendments to References to the Conceptual Framework 01-Jan-20
in IFRS Standards
IFRS 17, 'Insurance contracts' 01-Jan-21
Management are currently assessing the impact of the amendments
to IFRS 3 vis a vis the proposed acquisition of Caspian Explorer as
detailed in the subsequent events note.
1.3 Basis of consolidation
Subsidiary undertakings are entities that are directly or
indirectly controlled by the Group. Control is achieved when the
Group is exposed, or has rights, to variable returns from its
involvement with the investee and has the ability to affect those
returns through its power over the investee. Generally, there is a
presumption that a majority of voting rights result in control. To
support this presumption and when the Group has less than a
majority of the voting or similar rights of an investee, the Group
considers all relevant facts and circumstances in assessing whether
it has power over an investee. The consolidated financial
statements present the results of the Company and its subsidiaries
("the Group") as if they formed a single entity. Intercompany
transactions and balances between group companies are therefore
eliminated in full.
The purchase method of accounting is used to account for the
acquisition of subsidiary undertakings by the Group. The cost of an
acquisition is measured at the fair value of the assets given,
equity instruments issued and liabilities incurred or assumed at
the date of exchange. Identifiable assets acquired and liabilities
and contingent liabilities assumed in a business combination are
measured initially at their fair values at the acquisition date,
irrespective of the extent of any non-controlling interest. The
excess of the cost of acquisition over the fair value of the
Group's share of the identifiable net assets acquired is recorded
as goodwill.
1.4 Operating Loss
Operating loss is stated after crediting all operating income
and charging all operating expenses, but before crediting or
charging the financial income or expenses.
1.5 Foreign currency translation
1.5.1 Functional and presentational currencies
Items included in the financial statements of each of the
Group's entities are measured using the currency of the primary
economic environment in which the entity operates ("the functional
currency"). The consolidated financial statements are presented in
US Dollars ("US$"), which is the Group's presentational currency.
Beibars Munai LLP, Munaily Kazakhstan LLP, BNG Ltd LLP and Roxi
Petroleum Kazakhstan LLP, 3A_Best Group JSC, and Caspian Technical
Services LLP subsidiary undertakings of the Group during the
period, undertake their activities in Kazakhstan and the Kazakh
Tenge is the functional currency of these entities. The functional
currency for the Company, Beibars BV, Ravninnoe BV, Galaz Energy
BV, BNG Energy BV and Eragon Petroleum FZE is USD as USD reflects
the underlying transactions, conducts and events relevant to these
companies.
1.5.2 Transactions and balances in foreign currencies
In preparing the financial statements of the individual
entities, transactions in currencies other than the entity's
functional currency ("foreign currencies") are recorded at the
rates of exchange prevailing at the dates of the transactions. At
each reporting date, monetary items denominated in foreign
currencies are retranslated at the rates prevailing at the
reporting date. Non-monetary items carried at fair value that are
denominated in foreign currencies are retranslated at the rates
prevailing at the date when the fair value was determined.
Non-monetary items, including the parent's share capital, that are
measured in terms of historical cost in a foreign currency are not
retranslated. Exchange differences are recognised in profit or loss
in the period in which they arise.
1.5.3 Consolidation
For the purpose of consolidation all assets and liabilities of
Group entities with a functional currency that is not US$ are
translated at the rate prevailing at the reporting date. The profit
or loss is translated at the exchange rate approximating to those
ruling when the transaction took place. Exchange difference arising
on retranslating the opening net assets from the opening rate and
results of operations from the average rate are recognised directly
in other comprehensive income (the "cumulative translation
reserve"). On disposal of a foreign operator, related cumulative
foreign exchange gains and losses are reclassified to profit and
loss and are recognised as part of the gain or loss on
disposal.
1.6 Current tax
Current tax is based on taxable profit for the year. Taxable
profit differs from profit as reported in the profit or loss
because it excludes items of income or expense that are taxable or
deductible in other years and it further excludes items that are
never taxable or deductible. The Group's liability for current tax
is calculated using tax rates that have been enacted or
substantively enacted by the reporting date.
In case of the uncertainty of the tax treatment, the Group
assess, whether it is probable or not, that the tax treatment will
be accepted, and to determine the value, the Group use the most
likely amount or the expected value in determining taxable profit
(tax loss), tax bases, unused tax losses, unused tax credits and
tax rates.
Withholding tax payable at Kazakhstan
According to requirements of the Tax Code of Kazakhstan,
withholding taxes payable for non-residents should be withheld from
the total amount of interest income of non-residents and paid to
the government when interest is paid (in cash) to non-residents.
The companies should pay taxes from non-residents' interest income
derived from sources in the Republic of Kazakhstan on behalf of
these non-residents.
1.7 Deferred tax
Deferred tax is provided on temporary differences between the
carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for taxation purposes. The following
temporary differences are not provided for: the initial recognition
of assets or liabilities that affect neither accounting nor taxable
profit other than in a business combination, and differences
relating to investments in subsidiaries to the extent that they
will probably not reverse in the foreseeable future.
The amount of deferred tax provided is based on the expected
manner of realisation or settlement of the carrying amount of
assets and liabilities, using tax rates enacted or substantively
enacted at the reporting date.
Deferred tax liabilities are generally recognised for all
taxable temporary differences. A deferred tax asset is recorded
only to the extent that it is probable that taxable profit will be
available, against which the deductible temporary differences can
be utilised.
1.8 Unproven oil and gas assets
The Group applies the full cost method of accounting for
exploration and unproven oil and gas asset costs, having regard to
the requirements of IFRS 6 'Exploration for and Evaluation of
Mineral Resources'. Under the full cost method of accounting, costs
of exploring for and evaluating oil and gas properties are
accumulated and capitalised by reference to appropriate cost pools.
Such cost pools are based on license areas. The Group currently has
two cost pools.
Exploration and evaluation costs include costs of license
acquisition, technical services and studies, seismic acquisition,
exploration drilling and testing, but do not include costs incurred
prior to having obtained the legal rights to explore an area, which
are expensed directly to the profit or loss as they are
incurred.
Plant and equipment assets acquired for use in exploration and
evaluation activities are classified as property, plant and
equipment. However, to the extent that such asset is consumed in
developing an unproven oil and gas asset, the amount reflecting
that consumption is recorded as part of the cost of the unproven
oil and gas asset.
The amounts included within unproven oil and gas assets include
the fair value that was paid for the acquisition of partnerships
holding subsoil use in Kazakhstan. These licenses have been
capitalised to the Group's full cost pool in respect of each
license area.
Exploration and unproven oil and gas assets related to each
exploration license/prospect are not amortised but are carried
forward until the technical feasibility and commercial feasibility
of extracting a mineral resource are demonstrated.
Commercial reserves are defined as proved oil and gas
reserves.
Proven oil and gas properties
Once a project reaches the stage of commercial production and
production permits are received, the carrying values of the
relevant exploration and evaluation asset are assessed for
impairment and transferred to proven oil and gas properties and
included within property plant and equipment. The costs transferred
comprise direct costs associated with the relevant wells and
infrastructure, together with an allocation of the wider
unallocated exploration costs in the cost pool such as original
acquisition costs for the field.
Proven oil and gas properties are accounted for in accordance
with provisions of the cost model under IAS 16 "Property Plant and
Equipment" and are depleted on unit of production basis based on
commercial reserves of the pool to which they relate.
As part of the Kazakh licencing regime, upon award of a
production contract in respect of the BNG licence area, an
obligation to make a payment to the licencing authority is
triggered, settled over a 10 year period in equal quarterly
instalments. Such payments are considered to form a cost of the
licence and are capitalised to proven oil and gas assets and
subsequently depreciated on a units of production basis in
accordance with the Group's depreciation policy. In circumstances
where the amount assessed by the authorities is contested, the
Group records a provision discounted using a Kazakh government bond
yield with a term approximating the payment profile and the
discount is unwound over the payment term and charged to finance
costs. Payments made are charged against the provision.
Impairment
Exploration and unproven intangible assets are reviewed for
impairments if events or changes in circumstances indicate that the
carrying amount may not be recoverable as at the reporting date.
Intangible exploration and evaluation assets that relate to
exploration and evaluation activities that are not yet determined
to have resulted in the discovery of the commercial reserve remain
capitalised as intangible exploration and evaluation assets subject
to meeting a pool-wide impairment test as set out below.
In accordance with IFRS 6 the Group firstly considers the
following facts and circumstances in their assessment of whether
the
Group's exploration and evaluation assets may be impaired,
whether:
-- the period for which the Group has the right to explore in a
specific area has expired during the period or will expire in the
near future, and is not expected to be renewed;
-- substantive expenditure on further exploration for and
evaluation of mineral resources in a specific area is neither
budgeted nor planned;
-- exploration for and evaluation of hydrocarbons in a specific
area have not led to the discovery of commercially viable
quantities of hydrocarbons and the Group has decided to discontinue
such activities in the specific area; and
-- sufficient data exists to indicate that although a
development in a specific area is likely to proceed, the carrying
amount of the exploration and evaluation assets is unlikely to be
recovered in full from successful development or by sale.
If any such facts or circumstances are noted, the Group perform
an impairment test in accordance with the provisions of IAS 36. The
aggregate carrying value is compared against the expected
recoverable amount of the cash generating unit, being the relevant
cost pool. The recoverable amount is the higher of value in use and
the fair value less costs to sell.
An impairment loss is reversed if the asset's or cash-generating
unit's recoverable amount exceeds its carrying amount.
Impairment of development and production assets and other
property, plant and equipment
At each balance sheet date, the Group reviews the carrying
amounts of its PP&E to determine whether there is any
indication that those assets have suffered an impairment loss. If
any such indication exists, the recoverable amount of the asset is
estimated in order to determine the extent of the impairment loss
(if any). Where the asset does not generate cash flows that are
independent from other assets, the Group estimates the recoverable
amount of the cash-generating unit to which the asset belongs. The
recoverable amount is the higher of fair value less costs to sell
and value in use. Fair value less costs to sell is determined by
discounting the post-tax cash flows expected to be generated by the
cash-generating unit, net of associated selling costs, and takes
into account assumptions market participants would use in
estimating fair value including future capital expenditure and
development cost for extraction of the field reserves. In assessing
value in use, the estimated future cash flows are discounted to
their present value using a pre-tax discount rate that reflects
current market assessments of the time value of money and the risks
specific to the asset for which the estimates of future cash flows
have not been adjusted.
If the recoverable amount of an asset (or cash-generating unit)
is estimated to be less than its carrying amount, the carrying
amount of the asset (cash-generating unit) is reduced to its
recoverable amount. An impairment loss is recognised as an expense
immediately.
Where an impairment loss subsequently reverses, the carrying
amount of the asset (cash-generating unit) is increased to the
revised estimate of its recoverable amount, but so that the
increased carrying amount does not exceed the carrying amount that
would have been determined had no impairment loss been recognised
for the asset (cash-generating unit) in prior years. A reversal of
an impairment loss is recognised as income immediately.
Workovers/Overhauls and maintenance
From time to time a workover or overhaul or maintenance of
existing proven oil and gas properties is required, which normally
falls into one of two distinct categories. The type of workover
dictates the accounting policy and recognition of the related
costs:
Capitalisable costs - cost will be capitalised where the
performance of an asset is improved, where an asset being
overhauled is being changed from its initial use, the assets'
useful life is being extended, or the asset is being modified to
assist the production of new reserves.
Non-capitalisable costs - expense type workover costs are costs
incurred as maintenance type expenditure, which would be considered
day-to-day servicing of the asset. These types of expenditures are
recognised within cost of sales in the statement of comprehensive
income as incurred. Expense workovers generally include work that
is maintenance in nature and generally will not increase production
capability through accessing new reserves, production from a new
zone or significantly extend the life or change the nature of the
well from its original production profile.
1.9 Abandonment
Provision is made for the present value of the future cost of
the decommissioning of oil wells and related facilities. This
provision is recognised when the asset is installed. The estimated
costs, based on engineering cost levels prevailing at the reporting
date, are computed on the basis of the latest assumptions as to the
scope and method of decommissioning. The corresponding amount is
capitalised as a part of the oil and gas asset and, when in
production is amortised on a unit-of-production basis as part of
the depreciation, depletion and amortisation charge. Any adjustment
arising from the reassessment of estimated cost of decommissioning
is capitalised, while the charge arising from the unwinding of the
discount applied to the decommissioning provision is treated as a
component of the interest charge.
1.10 Restricted use cash
Restricted use cash is the amount set aside by the Group for the
purpose of creating an abandonment fund to cover the future
cost
of the decommissioning of oil and gas wells and related
facilities and in accordance with local legal rulings.
Under the Subsoil Use Contracts the Group must place 1% of the
value of exploration costs in an escrow deposit account, unless
agreed otherwise with the Ministry of Energy. At the end of the
contract this cash will be used to return the field to the
condition that it was in before exploration started.
1.11 Property, plant and equipment
All property, plant and equipment assets are stated at cost or
fair value on acquisition less accumulated depreciation.
Depreciation is provided on a straight-line basis, at rates
calculated to write off the cost less the estimated residual value
of each asset over its expected useful economic life. The residual
value is the estimated amount that would currently be obtained from
disposal of the asset if the asset were already of the age and in
the condition expected at the end of its useful life. Expected
useful economic life and residual values are reviewed annually.
The annual rates of depreciation for class of property, plant
and equipment are as follows:
- motor vehicles 4-5 years
- other over 2-4 years
The Group assesses at each reporting date whether there is any
indication that any of its property, plant and equipment has been
impaired. If such an indication exists, the asset's recoverable
amount is estimated and compared to its carrying value.
1.12 Investments (Company)
Investments in subsidiary undertakings are shown at cost less
allowance for impairment. Long-term advances to subsidiaries are
discounted at estimated market rate of interest. Difference between
a fair value and a face value of the advance is recorded within
investments. The loan at amortised cost is assessed for expected
credit loss under IFSR 9.
1.13 Financial instruments
The Group classifies financial instruments, or their component
parts on initial recognition, as a financial asset, a financial
liability or an equity instrument in accordance with the substance
of the contractual agreement.
Financial assets and financial liabilities are recognised when
the Group becomes a party to the contractual provisions of the
financial instrument.
Financial assets
Financial assets are classified as either financial assets at
amortised cost, at fair value through other comprehensive income
("FVTOCI") or at fair value through profit or loss ("FVPL")
depending upon the business model for managing the financial assets
and the nature of the contractual cash flow characteristics of the
financial asset.
A loss allowance for expected credit losses is determined for
all financial assets, other than those at FVPL, at the end of each
reporting period. The Group applies a simplified approach to
measure the credit loss allowance for any trade receivables using
the lifetime expected credit loss provision. The lifetime expected
credit loss is evaluated for each trade receivable taking into
account payment history, payments made subsequent to year end and
prior to reporting, past default experience and the impact of any
other relevant and current observable data. The Group applies a
general approach on all other receivables classified as financial
assets. The general approach recognises lifetime expected credit
losses when there has been a significant increase in credit risk
since initial recognition.
The Group derecognises a financial asset when the contractual
rights to the cash flows from the asset expire, or when it
transfers the financial asset and substantially all the risks and
rewards of ownership of the asset to another party. The Group
derecognises financial liabilities when the Group's obligations are
discharged, cancelled or have expired.
The Group's financial assets consist of cash and other
receivables. Cash and cash equivalents are defined as short term
cash deposits which comprise cash on deposit with an original
maturity of less than 3 months. Other receivables are initially
measured at fair value and subsequently at amortised cost.
The Group's financial liabilities are non-interest bearing trade
and other payables, other interest bearing borrowings. Non-interest
bearing trade and other payables and other interest bearing
borrowings are stated initially at fair value and subsequently at
amortised cost.
Where a loan is renegotiated on substantially different terms,
this is treated as an extinguishment of the original financial
liability and the recognition of a new financial liability with a
gain or loss recorded in the income statement. In accordance with
IFRS 9, following a modification or renegotiation of a financial
asset or financial liability that does not result in
de-recognition, an entity is required to recognise any modification
gain or loss immediately in profit or loss. Any gain or loss is
determined by recalculating the gross carrying amount of the
financial liability by discounting the new contractual cash flows
using the original effective interest rate. The difference between
the original contractual cash flows of the liability and the
modified cash flows discounted at the original effective interest
rate is recorded in the income statement.
Share capital issued to extinguish financial liabilities is fair
valued with any difference to the carrying value of the financial
liability taken to the profit or loss.
1.14 Inventories
Inventories are initially recognised at cost, and subsequently
at the lower of cost and net realisable value. Cost comprises all
costs of purchase and other costs incurred in bringing the
inventories to their present location and condition.
1.15 Other provisions
A provision is recognised when the Group has a present legal or
constructive obligation as a result of a past event, and it is
probable that an outflow of economic benefits will be required to
settle the obligation. If the effect is material, provisions are
determined by discounting the expected future cash flows at a
pre-tax rate that reflects current market assessments of the time
value of money and, where appropriate, the risks specific to the
liability.
1.16 Share capital
Ordinary and deferred shares are classified as equity.
Incremental costs directly attributable to the issue of new shares
or options are shown in equity as a deduction from the
proceeds.
1.17 Share-based payments
The Group has used shares and share options as consideration for
services received from employees.
Equity-settled share-based payments to employees and others
providing similar services are measured at fair value at the date
of grant. The fair value determined at the grant date of such an
equity-settled share-based instrument is expensed on a
straight-line basis over the vesting period, based on the Group's
estimate of the shares that will eventually vest.
Equity-settled share-based payment transactions with other
parties are measured at the fair value of the goods or services
received, except where the fair value cannot be estimated reliably,
in which case they are measured at the fair value of the equity
instruments granted, measured at the date the entity obtains the
goods or the counterparty renders the service. The fair value
determined at the grant date of such an equity-settled share-based
instrument is expensed since the shares vest immediately. Where the
services are related to the issue of shares, the fair values of
these services are offset against share premium where
permitted.
Fair value is measured using the Black-Scholes model. The
expected life used in the model has been adjusted based on the
Management's best estimate, for the effects of non-transferability,
exercise restrictions and behavioural considerations.
1.18 Warrants
Warrants are separated from the host contract as their risks and
characteristics are not closely related to those of the host
contracts. Where the exercise price of the warrants is in a
different currency to the functional currency of the Company, at
each reporting date the warrants are valued at fair value with
changes in fair values recognised through profit or loss as they
arise. The fair values of the warrants are calculated using the
Black-Scholes model. Where the warrant exercise price is in the
same currency as the functional currency of the issuer and involve
the issuance of a fixed number of shares the warrants are recorded
in equity.
1.19 Revenue
Revenue from contracts with customers is recognised when or as
the Group satisfies a performance obligation by transferring a
promised good or service to a customer. A good or service is
transferred when the customer obtains control of that good or
service. The transfer of control of oil sold by the Group usually
coincides with title passing to the customer. The Group satisfies
its performance obligations at a point in time.
Under the terms of domestic oil sales arrangements, the
performance obligation is satisfied when the local refinery
provides the seller and the customer with the act of acceptance of
crude oil of quantity and quality according to the agreement
between the parties.
Under the terms of export sales arrangements, the performance
obligation is satisfied when the Ocean Bill of Lading is issued by
the transport company that reflects the fact of boarding the crude
oil of specified quantity and quality on the tanker.
Revenue is measured at the fair value of the consideration
received, excluding value added tax ("VAT") and other sales taxes
or duty. Royalties are not included in revenue, they are paid on
production and recorded within cost of sales.
Payments in advance by oil traders are recorded initially as
deferred revenue, reflecting the nature of the transaction.
Subsequently, the deferred revenue is reduced and revenue is
recorded, as sales are made under the Group's revenue recognition
policy with the performance obligation satisfied.
1.20 Cost of sales
The Group started to calculate the cost of sales on crude oil
sold during 2019 because its asset BNG has received the production
license on part of its contract territory in July 2019. On the rest
of its territory (%) BNG continues to work under Exploration
license. During test production on Exploration cost of sales cannot
be reliably estimated and therefore a cost of sales equal to
revenue is recognised and credited to the unproven oil and gas
assets.
1.21 Segmental reporting
Operating segments are reported in a manner consistent with the
internal reporting provided to the chief operating decision maker.
The chief operating decision maker, who is responsible for
allocating resources and assessing performance of the operating
segments and making strategic decisions, has been identified as the
Board of Directors. The Group has one operating segment being oil
exploration and production in Kazakhstan and therefore one
reporting segment. The Group has several cost pools divided based
on the different contractual territory of its assets. As the
activity of all cost pools is the same (oil exploration and
production) and all of them operate geographically in Kazakhstan,
the Group reports one segment in its financials.
1.22 Interest receivable and payable
Interest income and expense are reported on an accrual basis
using the effective interest rate method.
1.23 Exchange rates
For reference the year end exchange rate from sterling to US$
was 1.32 and the average rate during the year was 1.28. The
year-end exchange rate from KZT to US$ was 382.6 and the average
rate during the year was 382.8.
2 Critical accounting estimates and judgements
In the process of applying the Group's accounting policies,
which are described in note 1, the Management has made the
following judgements and key assumptions that have the most
significant effect on the amounts recognised in the financial
statements.
2.1 Carrying value of exploration and evaluation costs (note
10)
Under the full cost method of accounting for exploration and
evaluation costs, such costs are capitalised as intangible assets
by reference to appropriate cost pools, and are assessed for
impairment on a concession basis based on the IFRS 6 impairment
indicators detailed in the accounting policy note 1.8. As at 31
December 2019, the Group assessed the exploration and evaluation
assets disclosed in note 10 and determined that no indicators of
impairment existed at a cost pool level in respect of the BNG cost
pool. The Group also considered whether the factors that gave rise
to the original impairment loss no longer existed and reversal of
the impairment is appropriate. In forming this assessment, the
Board considered the oil reserves and resources associated with the
licence area, the results of exploration activity to date, the
status of licences and future plans for the licence areas. In
forming its assessment, the Board considered the Group's
commitments under the licence detailed in note 19 and the impact of
outstanding obligations. Having undertaken this assessment the
Group concluded that no indicators of impairment existed and that
no reversal of previous impairment provisions attributable to the
unproven oil and gas assets of US$9,654,000 was yet appropriate
given the absence of a significant breakthrough on the deep
structures at 31 December 2019.
The Beibars cost pool remains impaired based on the continuance
of the force majeure. The Group has decided to formally relinquish
any interest in Beibars. Currently the Group is in the process of
returning all available information and contract territory to the
Ministry of Energy.
2.2 Transfer of costs to proven oil and gas assets (note 10
& 11)
Judgment has been applied in assessing that the MJF area assets
meets the criteria for reclassification to proven oil and gas
assets under the Group's accounting policy in note 1.8. In
concluding that it was appropriate to transfer the asset to proven
oil and gas assets management took account of the award of a
production licence enabling exports and sales at international
prices together with the production volumes. In August 2019 BNG has
received the required production license for its MJF structure and
got the export permission starting September 2019. According to the
approach above BNG moved the related O&G assets to the
production stage in August 2019 and accordingly started charging
DD&A expense. The Board considers the remaining BNG contract
area to remain in an exploration phase given the level of wells and
production relative to plans for the field, the exploration status
of the licence and the requirement to sell its test oil in the
domestic market which represents a substantial discount to the
international market such that production is primarily a by-product
of continued exploration and appraisal.
2.3 Recoverability of proven oil and gas assets (note 11)
The proven oil and gas assets, representing the MJF structure,
have been assessed for indicators of impairment at 31 December 2019
including assessment of the discounted cash flows indicated by the
Group's field plan. The Group also considered whether the factors
that gave rise to the previously recorded impairment loss
attributable to the MJF structure no longer existed and reversal of
the impairment is appropriate and concluded that the factors no
longer applied, noting the successful exploration activity and the
transition to commercial production. Accordingly, the recoverable
value of the MJF structure was assessed using the discounted cash
flow analysis. This analysis required judgment and estimate in
determining forecast prices as at 31 December 2019 based on
conditions existing at that time, future production and reserves,
operating costs and development costs for the field and the
discount rate. The forecasts demonstrated significant headroom with
prices based on forward prices of $60 adjusted for net back
adjustments, reserves calculated using the most recent Competent
Person's report and discount rates run at 10% and 15%. Having
undertaken this assessment the Group concluded that the previous
impairment attributable to the MJF structure of US$2,414,000 should
be released. The allocation of the historic impairment provision
between proven and unproven oil and gas assets required judgment
and was based on relative costs incurred between the proven and
unproven asset categories as the original impairment arose when the
proven oil and gas assets formed part of the single BNG unproven
oil and gas cost pool.
2.3 Recoverability of VAT (note 14)
The Group holds VAT receivables of $3.3 million (2018:
$3million) as detailed in note 14 which are anticipated to be
primarily recovered through offset of future VAT payable in
accordance with Kazakh legislation. Management have assessed the
recoverability of the asset based on forecast levels of VAT
payables which demonstrate that the balance will be recovered
within 3.5 years (2018: 3.5 years). This required estimates
regarding future production, oil prices and expenditure.
2.4 Decommissioning (note 19)
Provision has been made in the accounts for future
decommissioning costs to plug and abandon wells in note 19. The
costs of provisions have been added to the value of the unproven
oil and gas asset and will be depreciated on a unit of production
basis.
The decommissioning liability is stated in the accounts at
discounted present value and accreted up to the final expected
liability by way of an annual finance charge. The Group has
potential decommissioning obligations in respect of its interests
in Kazakhstan. The extent to which a provision is required in
respect of these potential obligations depends, inter alia, on the
legal requirements at the time of decommissioning, the cost and
timing of any necessary decommissioning works, and the discount
rate to be applied to such costs. Actual costs incurred in future
periods may substantially differ from the amounts of provisions. In
addition, future changes in environmental laws and regulations,
estimates of deposit useful lives and discount rates may affect the
carrying value of this provision
2.5 Acquisition of 3A Best and carrying value (note 21)
Judgment was required in assessing the accounting treatment for
the purchase of 3A Best as an asset purchase rather than a business
combination. In forming this assessment, management note that
whilst the Group acquired legal entities to obtain control the
legal entities held an exploration phase asset and associated
obligations such that the criteria for a business combination were
not met. As such, the fair value of the purchase consideration was
allocated to the assets and liabilities acquired, costs associated
with the transaction capitalised and no deferred tax arose on the
transaction.
Judgment has been applied in assessing whether impairment of the
asset is required at 31 December 2019 noting that the authorities
have the right to withdraw the licence if payments due by July 2020
are not made in respect of obligations arising prior to the
acquisition. The Board considers the risk of the licence being
withdrawn to be remote given the history of investment by the Group
in Kazakhstan, the impact of COVID-19 in 2020 on the Group's cash
generation and ability to undertake work program commitments and
past experience. An application to extend the licence has been
submitted together with an application to defer the obligations and
commitments. However, if the Group is unsuccessful the asset would
be impaired.
2.6 Provision for BNG licence payments (note 11, 19)
As part of the Kazakh licencing regime, upon award of a
production contract in respect of the BNG licence area, an
obligation to make a payment to the licencing authority was
triggered, settled over a 10 year period in equal quarterly
instalments. Judgment was required in assessing the appropriate
accounting policy for the transaction including assessment of the
terms of the arrangement. Such payments are considered to form a
cost of the licence and are capitalised to proven oil and gas
assets. As at 31 December 2019, the Group is contesting the amount
levied by the authorities with a legal process ongoing. As such, a
provision for the amounts due has been made based on the most
recent amount formally assessed although the final outcome may
differ to the amount recorded and the Board is seeking a
significant reduction to the amount. Estimation was also required
in selecting an appropriate discount rate for the provision and a
rate of 2.7% has been applied, based on US dollar Eurobonds yields
in Kazakhstan with a comparable term.
2.7 Uncertain tax positions (note 19)
As detailed in note 19, judgment has been applied in assessing
the extent to which tax treatments adopted by the Group
historically will be accepted or rejected by the relevant tax
authority and the resulting measurement of uncertain tax positions
in circumstances were it is probable that the treatment will be
challenged.
2.8 Indemnity receivables in relation to 3A Best acquisition
(note 21)
Under the terms of the SPA for 3A Best, the vendors provided
indemnities that obligations related to the period prior to
acquisition would be reimbursed. Judgment has been applied in
assessing the recoverability of the indemnity receivables detailed
in note 21, which included assessment of the terms of the SPA, and
assessments of the vendors' ability to meet such payments.
3 Segment reporting & revenue
Operating segments
Operating segments are reported in a manner consistent with the
internal reporting provided to the chief operating decision maker.
The chief operating decision maker, who is responsible for
allocating resources and assessing the performance of the operating
segments and making strategic decisions, has been identified as the
Board of Directors. The Group operates in one operating segment
(exploration for and production of oil in Kazakhstan). All revenues
from test phase and commercial phase production are generated
domestically in Kazakhstan. 100% of the Group's revenue was derived
from two major customers (local market operator - 56% and the
export trader - 44%). The revenue split in 2019 between the
domestic trader (ANK-Energo LLP) and the export trader (Euro-Asian
Oil SA) was US $6,818,000 and $ US $5,290,000 respectively.
Revenue
The Group's revenues are derived from the sale of oil in
Kazakhstan. After moving part of O&G assets into Production
phase The Group started to receive export revenues in September
2019. During the first quarter of sales the Group could receive
cash one month after the delivery of oil. Later, in December 2019
The Group agreed to get a big advance from the export trader
($3.9m). Later, during 2020 The Group managed to repay this advance
in full, mainly by way of delivering the crude oil to the export
trader.
Under the terms of sales on the local market, the performance
obligation is the supply of oil and the performance obligation is
satisfied at a point in time, being the delivery of oil to the
refinery. Control passes to the customer at this point with title
and risk transferred.
Under the terms of export sales control over the oil delivered
is with the Group until the customer confirms it has been shipped
on the board of the tanker.
When advances are received from oil traders for delivery of
future production at specified prices, deferred revenue is recorded
and the liability reduced as oil is delivered.
Where advances are made for future production and the financing
component of such transactions is material, a finance charge is
recorded based on the market rate of interest.
No trade receivables or accrued income was applicable at year
end (2018: $Nil).
4 Operating income/(loss)
Group operating income/(loss) for the year has been arrived after
charging:
------------------------------------------------------------------------
Group Group
201 9 201 8
US$'000 US$'000
--------------------------------------------------- --------- --------
Staff costs (note 6) (1,420) (1,319)
Depreciation of property, plant and equipment
(note 11) (148) (31)
Auditors' remuneration (note 5) (137) (220)
Share based payment remuneration (note 6) (31) (13)
Reversal of impairment (note 11) 2,414 -
5 Group Auditor's remuneration
Fees payable by the Group to the Company's auditor BDO and its
member firms in respect of the year:
Group Group
201 9 2018
US$'000 US$'000
--------------------------------------------- -------- --------
Fees for the audit of the annual financial
statements 94 95
Audit related services 9 11
Other services - tax related 8 88
--------------------------------------------- -------- --------
111 194
--------------------------------------------- -------- --------
Fees payable by the Group to Grant Thornton and its associates
in respect of the year:
Group Group
201 9 2018
US$'000 US$'000
---------------------------------------------- -------- --------
Auditing of accounts of subsidiaries of the
Company 26 26
26 26
---------------------------------------------- -------- --------
6 Employees and Directors
Staff costs during the year Group Company Group Company
201 9 201 9 201 201 8
US$'000 US$'000 8 US$'000
US$'000
--------------------------------- --------- --------- -------- --------
Wages and salaries 1, 420 590 1,319 782
Social security costs 7 6 12 108 32
Pension costs 90 - 73 -
Share-based payments 31 31 13 13
--------------------------------- --------- --------- -------- --------
1, 6 1
7 63 3 1,513 827
--------------------------------- --------- --------- -------- --------
Payroll expenses were capitalized in the amount
of US$185,500 (201 8 : US$33 2 ,000).
Average monthly number of people Group Company Group Company
employed 201 9 201 9 201 8 201 8
(including executive Directors) US$'000 US$'000
---------------------------------- ------ -------- ------ --------
Technical 1 1 1 10 1
Field operations 47 - 47 -
Finance 9 2 9 2
Administrative and support 1 6 2 14 2
---------------------------------- ------ -------- ------ --------
8 3 5 80 5
---------------------------------- ------ -------- ------ --------
Directors' remuneration Group Group
201 9 2018
US$'000 US$'000
-------------------------- -------- --------
Director's emoluments 729 540
Share-based payments 25 -
-------------------------- -------- --------
754 540
-------------------------- -------- --------
The Directors are the key management personnel of the Company
and the Group. Details of Directors' emoluments and interests in
shares are shown in the Remuneration Committee Report. The highest
paid director had emoluments totalling US$425,289 (2018:
US$336,140).
7 Finance cost
Group Group
201 9 201 8
US$'000 US$'000
--------------------------------------------- -------- --------
Loan interest payable 8 2 337
Unwinding of discount on BNG licence payment
provision (note 19) 368 -
Unwinding of discount on other provisions
(note 19) 2 11
--------------------------------------------- -------- --------
452 348
--------------------------------------------- -------- --------
8 Taxation
Analysis of charge for the year Group Group
201 9 2018
US$'000 US$'000
--------------------------------- -------- --------
Current tax charge 1 , 860 414
Deferred tax charge (note 22) 483 -
2,343 414
--------------------------------- -------- --------
Group Group
201 9 201 8
US$'000 US$'000
------------------------------------------------------ -------- --------
Profit/(Loss) before tax 941 (2,972)
------------------------------------------------------ -------- --------
Tax on the above at the standard rate of corporate
income tax in the UK 19% (2018: 19%) 179 (565)
Effects of:
Non-deductible expenses 1,183 23
Return of prior year CIT payment* - (1,013)
Withholding tax on interest expense 1,860 1,375
Utilisation of tax losses not previously recognized (1,888) (2,882)
Unrecognised tax losses carried forward 1,009 3,476
2,343 414
------------------------------------------------------ -------- --------
* During the years ended 31 December 2014 and 2015 the Company
incurred taxation in respect of interest accrued on non-current
advances provided to a subsidiary. Following subsequent analysis of
the agreements it was identified that interest had been incorrectly
accrued under the terms of the agreements. Accordingly, during 2016
the Parent company results were restated. As a result the Company
resubmitted its CIT returns to HMRC. During H1 2018 the amended CIT
returns were proved by HMRC and related tax payment from HMRC has
been received by the Company during August 2018.
9 Earnings/(loss) per share
Basic earnings/(loss) per share is calculated by dividing the
income/(loss) attributable to ordinary shareholders by the weighted
average number of ordinary shares outstanding during the year
including shares to be issued.
There is no difference between the basic and diluted loss per
share as the Group made a loss for the current and prior year.
Dilutive potential ordinary shares include share options granted to
employees and directors where the exercise price (adjusted
according to IAS33) is less than the average market price of the
Company's ordinary shares during the period.
The calculation of earnings/(loss) per share is based on:
2019 2018
------------------------------------------------------ ---------- -------------
The basic weighted average number of ordinary
shares in 1,8 24 ,
issue during the year 955 , 952 1,669,706,698
The earnings / (loss) for the year attributable
to owners of the parent from continuing operations
(US$'000) (1,278) (3,219)
The loss for the year attributable to owners
of the parent from discontinued operations
(US$'000) - (5,147)
------------------------------------------------------ ---------- -------------
There were 3,000,000 potentially dilutive instruments in the
year (2018: 7,200,000).
10 Unproven oil and gas assets
COST Group
US$'000
------------------------------ ---------
Cost at 1 January 201 8 84,838
------------------------------ ---------
Additions 7,479
Sales from test production (10,747)
Foreign exchange difference (13,082)
------------------------------ ---------
Cost at 31 December 2018 68,488
------------------------------ ---------
Additions 8,886
Sales from test production (5,466)
Acquisitions (note 21) 11,293
Reclassification to PP&E (12,000)
Foreign exchange difference (1,507)
------------------------------ ---------
Cost at 31 December 201 9 69,694
------------------------------ ---------
ACCUMULATED IMPAIRMENT Group
US$'000
---------------------------------------------- --------
Accumulated impairment at 1 January 201 8 15,135
---------------------------------------------- --------
Foreign exchange difference (2,334)
---------------------------------------------- --------
Accumulated impairment at 31 December 201 8 12,801
---------------------------------------------- --------
Reclassification to PP&E (2,414)
Foreign exchange difference (733)
Accumulated impairment at 31 December 201 9 9,654
---------------------------------------------- --------
Net book value at 1 January 2017 69,701
Net book value at 31 December 201 8 55,685
Net book value at 31 December 201 9 60,040
---------------------------------------------- --------
Unproven oil and gas assets represent license acquisition costs
and subsequent exploration expenditure in respect of three licenses
held by Kazakh group entities. The carrying values of those assets
at 31 December 2019 were as follows: Beibars Munai LLP US$ nil
(2018: US$ nil), 3A Best-Group JSC US$12,666,000 (2018: US$ nil)
and BNG Ltd LLP US$47,374,000 (2018: US$55,685,000).
The Directors have carried out an impairment review of these
assets on a cost pool level as detailed in note 2.1. No impairment
indicators were identified for the unproven oil and gas assets held
by BNG Ltd LLP or 3A Best-Group JSC.
11 Property, plant and equipment
Following the commencement of commercial production in July 2019
the Group reclassified part of BNG assets from unproven oil and gas
assets to proven oil and gas assets. During 2018 the Group disposed
it Munaily assets.
Proved Motor Other Total
-----------------------------
oil and Vehicles
gas assets
Group US $'000 US $'000 US $'000 US $'000
----------------------------- --------------------- ---------------------- -------------------- ------------------
Cost at 1 January 2018 47 153 313 513
Additions - - 3 3
Disposals (47) (85) (8) (140)
Foreign exchange difference - (12) (42) (54)
----------------------------- --------------------- ---------------------- -------------------- ------------------
Cost at 31 December 2018 - 56 266 322
----------------------------- --------------------- ---------------------- -------------------- ------------------
Additions 564 - 8,071* 8,635
Transferred from unproved
oil and gas assets 12,000** - - 12,000
Additions to Proved O&G
assets
related to BNG licence
payment
provision 28,335*** - - 28,335
Reversal of impairment (note
10) 2,414 - - 2,414
Disposals - - (3) (3)
Foreign exchange difference 5 - - 5
----------------------------- --------------------- ---------------------- -------------------- ------------------
Cost at 31 December 2019 43,318 56 8,334 51,708
----------------------------- --------------------- ---------------------- -------------------- ------------------
Depreciation at 1 January
2018 47 80 221 348
Charge for the year - 9 22 31
Disposals (47) (51) (8) (106)
Foreign exchange difference - (7) (32) (39)
----------------------------- --------------------- ---------------------- -------------------- ------------------
Depreciation at 31 December
2018 - 31 203 234
----------------------------- --------------------- ---------------------- -------------------- ------------------
Charge for the year 130 8 10 148
Disposals - - (3) (3)
Foreign exchange difference - - 3 3
----------------------------- --------------------- ---------------------- -------------------- ------------------
Depreciation at 31 December
2019 130 39 213 382
----------------------------- --------------------- ---------------------- -------------------- ------------------
Net book value at:
----------------------------- --------------------- ---------------------- -------------------- ------------------
01 January 2018 - 73 92 165
----------------------------- --------------------- ---------------------- -------------------- ------------------
31 December 2018 - 24 64 88
----------------------------- --------------------- ---------------------- -------------------- ------------------
31 December 20 1 9 43,189 16 8,122 51,326
----------------------------- --------------------- ---------------------- -------------------- ------------------
*$7,966,000 of $8,071,000 relate to the acquisition during 2019
of drilling rigs and other fixed assets. The Group acquired the
drilling rigs in September 2019 with 58,333,333 shares issued as
consideration with the assets recorded based on the market price of
the shares issued.
**$12,000,000 - the amount of O&G assets transferred from
Unproven O&G to Proved O&G assets at BNG asset for the MJF
structure. Refer to note 2.
*** Refer to notes 19 and 2.
A previous impairment provision amount of US$2,414,000 (US$
1,931,000 net of deferred tax) was reversed in the period (see note
2)
12 Investments (Company)
Investments Company
US$'000
-------------------------- --------
Cost
At 31 December 2018 275,911
Receipts 534
Payments (206)
--------------------------- --------
At 31 December 2018 276,239
--------------------------- --------
Increase in investments 11,795
At 31 December 2019 288,034
--------------------------- --------
Impairment
At 1 January 2018 64,253
Impairment -
At 31 December 2018 64,253
--------------------------- --------
Impairment -
At 31 December 2019 64,253
--------------------------- --------
Net book value at:
-------------------------- --------
31 December 2018 211,986
31 December 2019 223,781
--------------------------- --------
During 2019 the Company acquired 100% interest at 3A-Best group
JSC for US$11,975,000 by means of issuing the Company's shares. The
carrying value of the investments has been assessed by the
Directors including consideration of the discounted cash flows
associated with the proven oil and gas assets, underlying BNG and
3A-Best contract area progress and the continued exploration value
of the assets.
Direct investments
Name of undertaking Country of Effective Effective Registered Nature
incorporation holding and holding and address of business
proportion proportion
of voting of voting
rights held rights held
at 31 December at 31 December
2019 2018
----------------------------- --------------- --------------- --------------- ----------------- ------------
5 New Street
Square
Eragon Petroleum London Holding
Limited United Kingdom 100% 100% EC4A 3TW Company
CN-135789,
Eragon Petroleum Jebel Ali, Management
FZE Dubai 100% 100% Dubai, UAE Company
Utrechtseweg
79
1213 TM
Hilversum Holding
Beibars BV Netherlands 100% 100% The Netherlands Company
Utrechtseweg
79
1213 TM
Hilversum Holding
Ravninnoe BV Netherlands 100% 100% The Netherlands Company
152/140
Karasay
Batyr Str.,
Roxi Petroleum Kazakhstan Almaty, Management
LLP Kazakhstan 100% 100% Kazakhstan Company
Indirect investments held by Eragon Petroleum Limited
Name of undertaking Country of Effective Effective Registered Nature
incorporation holding and holding and address of business
proportion proportion
of voting of voting
rights held rights held
at 31 December at 31 December
2019 2018
---------------------- --------------- --------------- --------------- -------------------- --------------
Utrechtseweg
79
1213 TM Hilversum Holding
Galaz Energy BV Netherlands 100% 100% The Netherlands Company
Utrechtseweg
79
1213 TM Hilversum Holding
BNG Energy BV Netherlands 100% 100% The Netherlands Company
152/140 Karasay
Batyr Str., Oil Production
BNG Ltd LLP Kazakhstan 99% 99% Almaty, Kazakhstan Company
152/140 Karasay
3A-Best Group Batyr Str., Exploration
JSC Kazakhstan 100% 100% Almaty, Kazakhstan Company
152/140 Karasay Drilling
Batyr Str., & Service
CTS LLP Kazakhstan 100% 100% Almaty, Kazakhstan Company
During 2019 Eragon Petroleum FZE has established the subsidiary
with100% interest: Caspian Technical Services LLP (CTS LLP). The
main activity of the new subsidiary is drilling services for the
companies of the group. In December 2019 CTS LLP spuded the well
#150 at BNG field and successfully completed it in March-April
2020. The company is using the rigs and other equipment acquired by
the Group during 2019.
Indirect investments held by Beibars BV
Name of undertaking Country of Effective Effective Registered Nature
incorporation holding and holding and address of business
proportion proportion
of voting of voting
rights held rights held
at 31 December at 31 December
2018 2017
-------------------- --------------- --------------- --------------- ------------------- ------------
152/140 Karasay
Batyr Str., Exploration
Beibars Munai LLP Kazakhstan 50% 50% Almaty, Kazakhstan Company
Beibars Munai LLP is a subsidiary as the Group is considered to
have control over the financial and operating policies of this
entity. Its results have been consolidated within the Group.
13 Inventories
Group Group
2019 2018
US$'000 US$'000
------------------------- ------- -------
Materials and supplies 384 132
------------------------- ------- -------
384 132
------------------------- ------- -------
14 Other receivables
Group Group Company Company
2019 201 8 2019 2018
US$ '000 US$ '000 US$ '000 US$'000
----------------------------- -------- -------- -------- -------
Amounts falling due after
one year:
Prepayments made 2,459 5,516 - 54
VAT receivable 3,286 2,929 69 -
Intercompany receivables - - 10,635 3,012
5,745 8,445 10,704 3,066
----------------------------- -------- -------- -------- -------
Amounts falling due within
one year:
Prepayments made 1,159 119 7 6
Other receivables* 4,504 245 - -
----------------------------- -------- -------- -------- -------
5,663 364 7 6
----------------------------- -------- -------- -------- -------
The VAT receivables relate to purchases made by operating
companies in Kazakhstan and will be recovered through VAT payable
resulting from sales to the local market.
*US$ 3,826,000 out of US$ $ 4,504,000 other receivables at the
Group represent the amounts reimbursable by the vendors of 3A Best
under the indemnities provided on acquisition of the exploration
asset (note 21).
The current intercompany receivables bear interest rates between
LIBOR + 2% and LIBOR + 7%.
Inter-company receivables has been assessed for expected credit
losses considering factors such as the status of underlying
licenses, reserves, financial models and future risks and
uncertainties. The provision substantially refers to balances
considered credit impaired. Inter-company receivables from the
subsidiaries in the table above are shown net of provisions of
US$12.9 million (2018: US$12.2 million). The movement in the
expected credit loss provision related to the inter-company
receivables was as follows:
Group Group Company Company
201 9 201 8 201 9 201 8
Denomination US$'000 US$'000 US$'000 US$'000
------------------ ------- ------- ------- --------
As at 1 January - - 12,212 34,232
Charge - - 701 286
Write-off* - - - (22,306)
As at 31 December - - 12,913 12,212
------------------ ------- ------- ------- --------
*During 2018 the Company wrote off its fully impaired Munaily
receivables following the sale of Munaily and wrote off of its
fully impaired Roxi Petroleum Kazakhstan receivables.
The Company recognised US$ 701 thousand of expected credit loss
provisions in relation to it receivables from subsidiaries in 2019
(2018: US$ 286 thousand).
15 Cash and cash equivalents
Group Group Company Company
201 9 2018 201 9 2018
US$'000 US$'000 US$'000 US$'000
--------------------------------- --------- --------- -------- --------
Cash at bank and in hand 4,060 557 87 292
--------------------------------- --------- --------- -------- --------
Funds are held in US Dollars, Sterling and Kazakh Tenge currency
accounts to enable the Group to trade and settle its debts in
the currency in which they occur and in order to mitigate the
Group's exposure to short-term foreign exchange fluctuations.
All cash is held in floating rate accounts.
Group Group Company Company
201 9 201 8 201 9 201 8
Denomination US$'000 US$'000 US$'000 US$'000
--------------- ------- ------- ------- -------
US Dollar 3,842 448 87 232
Sterling - 6 0 - 60
Kazakh Tenge 218 49 - -
4,060 557 87 292
--------------- ------- ------- ------- -------
16 Called up share capital
Group and Company
Number Number
of ordinary of deferred
shares US$'000 shares US$'000
------------------------ ------------------ ------------------------ -------------------- ------------------------
Balance at 1 January
2018 1,669,673,820 25,401 373,317,105 64,702
Share options
exercised 1,200,000 15 - -
Balance at 31 December
2018 1,670,873,820 25,416 373,317,105 64,702
------------------------ ------------------ ------------------------ -------------------- ------------------------
Share options
exercised 4,200,000 56 - -
Acquisition of 100%
interest
at 3A Best-Group JSC
(note
21) 149,253,732 1,919 - -
Equipment bought
during
2019 (note 11) 58,333,333 729 - -
------------------------ ------------------ ------------------------ -------------------- ------------------------
Balance at 31 December
2019 1,882,660,885 28,120 373,317,105 64,702
------------------------ ------------------ ------------------------ -------------------- ------------------------
Caspian Sunrise Plc has authorised share capital of
GBP100,000,000 divided into 6,640,146,055 ordinary shares of 1p
each and 373,317,105 deferred shares of 9p each.
17 Trade and other payables - current
Group Group Company Company
201 9 201 8 201 9 201 8
US$'000 US$'000 US$'000 US$'000
------------------------------- ------- ------- ------- -------
Trade payables 1,384 861 575 221
Taxation and social security 1,813 180 22 21
Accruals 282 197 172 165
Other payables 4,368 2,235 364 413
Intercompany payables - - 30,678 8,232
Advances received (deferred
revenue) 6,989 2,786 - -
14,836 6,259 31,811 9,052
------------------------------- ------- ------- ------- -------
As at 31 December 2019 and 31 December 2018, the Group has
received a significant amount of prepayments from the oil traders
in relation to increasing production on the BNG oil field. Amounts
included in advances received that was recognised as revenue during
the period: $6.6m (2018: $10.7m). Excess of revenue recognised over
cash being recognised during the period is US$ 7m (2018: excess of
cash recognised over the revenue is US$ 3m).
During 2019 the Company has started restructuring of the
intercompany loans. The result of the transactions should be a
simplified structure of mutual receivable/payable amounts within
the group. As a result of the restructuring and associated loan
assignments, the Company has a payable to Eragon Petroleum Limited,
its 100% subsidiary, of US $30.7 million and other entities reduced
their mutual indebtedness to a minimum. As part of the
restructuring, previous interest free intercompany payables were
extinguished. On initial recognition the liability was discounted
using a market interest rate and US$14,936,000 recorded in other
reserves, On extinguishment of the liability the reserves has been
transferred to retained losses. The restructuring has not resulted
in any cash outflows.
17 Trade and other payables - non-current
Group Group Company Company
201 9 201 8 201 9 201 8
US$'000 US$'000 US$'000 US$'000
------------------------ ------- ------- ------- -------
Intercompany payables - - - 16,735
Taxation 12,293 10,286 - -
------------------------ ------- ------- ------- -------
12,293 10,286 - 16,735
------------------------ ------- ------- ------- -------
Taxation payable relate to withholding tax accrued on the
interest expense at the BNG subsidiary level.
18 Short-term borrowings
Group Group Company Company
201 9 201 8 201 9 201 8
US$'000 US$'000 US$'000 US$'000
----------------------- ------- ------- ------- -------
Mr. Oraziman (a) 2,288 913 727 -
Fosco BV (b) 661 650 - -
Other borrowings (c) 1,101 1,009 1,087 400
----------------------- ------- ------- ------- -------
4,050 2,572 1,814 400
----------------------- ------- ------- ------- -------
a) At the start of the period under review Eragon Petroleum FZE,
a wholly owned subsidiary, had an outstanding loan of US$ 913,000
from Kuat Oraziman. Caspian Sunrise had an outstanding loan of US$
400,000 from Kuat Oraziman. During 2019 Mr. Oraziman provided an
additional US$300,000 to Caspian Sunrise. The total balance of
these loans as at 31 December 2019, including the accrued interest,
was US$ 1,704,000. Additionally, during 2019 a loan due from Roxi
Kazakhstan LLP to KC Caspian Explorer, an entity controlled by
Aibek Oraziman, was assigned to Kuat Oraziman. The balance of the
loan at 31 December 2019 was US$ 584,000.
b) During July 2016 Fosco BV, a company controlled by Mr
Oraziman, therefore a related party of the Group, provided an on
demand loan to BNG LLP in the amount of US$ 0.63 million. The loan
is interest bearing with the rate of Libor+ 1%.
c) The total amount borrowed by the Group at 31 December 2019
US$1,101,000 (2018: US$1,009,000) was payable to Kuat Oraziman and
a legal entities controlled by Mr Oraziman. The loans are interest
bearing with the rate of 7%
and repayable during 2020 with the possibility of further extension.
19 Provisions and contingencies
Group only Employee Liabilities Abandonment 2018
holiday under Social fund Total
provision Development
Program
and historical
cost
----------------------------- ----------- ---------------- ------------ --------
US$'000 US$'000 US$'000 US$'000
----------------------------- ----------- ---------------- ------------ --------
Balance at 1 January 2018 93 4,833 194 5,120
Increase in provision 2 - 9 11
Sale of Munaily (note 20 (8) (795) (49) (852)
Paid in the year - (318) (18) (336)
Unwinding of discount - - 11 11
Foreign exchange difference (12) (280) (22) (314)
----------------------------- ----------- ---------------- ------------ --------
Balance at 31 December
2018 75 3,440 125 3,640
----------------------------- ----------- ---------------- ------------ --------
Non-current provisions - - 125 125
Current provisions 75 3,440 - 3,515
----------------------------- ----------- ---------------- ------------ --------
Balance at 31 December
2018 75 3,440 125 3,640
----------------------------- ----------- ---------------- ------------ --------
Group only BNG licence Employee Liabilities Abandonment 201 9
payments holiday under Social fund Total
* provision Development
Program
and historical
cost
----------------------------- ------------ ----------- ---------------- ------------ ---------
US $'000 US $'000 US $'000 US $'000 US $'000
----------------------------- ------------ ----------- ---------------- ------------ ---------
Balance at 1 January
201 9 - 75 3,440 125 3,640
Increase in provision 28,652 - 3,048 450 32,150
Paid in the year (1,626) (75) (339) - (2.040)
Unwinding of discount 368 - - 2 370
Foreign exchange difference - - 5 1 6
----------------------------- ------------ ----------- ---------------- ------------ ---------
Balance at 31 December
201 9 27,394 - 6,154 578 34,126
----------------------------- ------------ ----------- ---------------- ------------ ---------
Non-current provisions 24,216 - - 428 24,644
Current provisions 3,178 - 6,154 150 9,482
----------------------------- ------------ ----------- ---------------- ------------ ---------
Balance at 31 December
201 9 27,394 - 6,154 578 34,126
----------------------------- ------------ ----------- ---------------- ------------ ---------
*The subsoil use contract held by BNG Ltd for the Yelemes field
stipulates that it must make payments to the Kazakhstan Government
upon award of a production contract after commercial feasibility.
The Kazakhstan Government has assessed the amount payable as a
total of US$32.5m. The sum is paid on a quarterly basis from 1 July
2019 in equal instalments and the final payment is due to be paid
on 1 April 2029. The payments have been discounted to their net
present value. This discounted value has been capitalised as
Property, plant and equipment (note 11) and will be amortised over
the productive period. Any changes in estimated payments and
discount rate are dealt with prospectively and result in a
corresponding adjustment to property plant and equipment. The Group
is currently contesting the value of the amount assessed.
Amounts in relation to Subsoil Use Contracts are included in the
table above and relate to the licence areas disclosed below:
a) Beibars Munai LLP
During 2007 Beibars Munai LLP, a subsidiary undertaking, and the
Ministry of Energy and Mineral Resources of the Republic of
Kazakhstan signed a Contract for oil exploration within the block
XXXVII-10 in Mangistauskaya oblast (Contract #2287). The contract
term expired in January 2012 and the Group has applied to the
Ministry of Oil and Gas for the extension of the Beibars
exploration license, given the force majeure situation. However the
Group was unsuccessful.
In February 2017 the Group decided to formally relinquish any
interest in Beibars. Currently the Group is in the process of
returning all available information and contract territory to the
Ministry of Energy. The Group has fully impaired its Beibars
assets.
b) BNG Ltd LLP
BNG Ltd LLP a subsidiary, signed a contract #2392 dated 7 June
2007 with the Ministry of Energy and Mineral Resources of RK for
exploration at Airshagyl deposit, located in Mangistau region.
Under addendum No.1 dated 17 April 2008, the Contract Area was
increased. The contract was valid for 4 years and expired on 7 June
2011. Addendum No. 6 to the Subsoil Use Contract for extension of
exploration period up to June 2013 was obtained on 13 July 2011. On
16 July 2013 BNG Ltd LLP signed Addendum No. 7 extending the
exploration period for two consecutive years until June 2015. On 22
June 2015 BNG Ltd LLP signed Addendum No. 9 extending the
exploration period for three consecutive years until June 2018. On
24 December 2015 BNG Ltd LLP signed Addendum No.10 according to
which the geological territory was extended by 140.6 sq kilometres.
On 23 September 2016 addendum No.11 was signed that reduced the
penalties for non-fulfilment of the contractual obligations from
30% to 1%. On 20 December 2017 BNG Ltd LLP signed addendum No.12
where amended its contractual obligations increasing the minimal
work program for 2016-2018 from US$16.5 million to US$27.5 million.
All other obligations, including social obligations, remained the
same. In June 2018 BNG Ltd LLP signed the Addendum No.13 with the
Ministry of Energy for the 6 years appraisal period on the BNG
oilfield until June 2024.
In accordance with the terms of the addendum #13, BNG Ltd LLP
remains committed to the following:
-- For the six-year appraisal period US$261,000 per annum should
be invested in the social development of the region starting from
January 2019;
-- To fund minimum cumulative work program during the appraisal period of US$ 28,103,000
-- Investing not less than 1% of total investments in
professional training of Kazakhstani personnel engaged in work
under the contract; and
-- Transferring, on an annual basis, 1% of exploration
expenditures to a liquidation fund through a special deposit
account in a bank located within the Republic of Kazakhstan.
The license commitments are established for the license term as
a whole, with annual schedules contained therein under the license.
Should the company have unfulfilled commitments or outstanding
payments under social programs, a 1% penalty is applied until the
commitments are fulfilled. Refer to table above.
On 11 July 2019, BNG Ltd LLP has signed the Production contract
with the Ministry of Energy of Republic of Kazakhstan on the part
of the territory. The Contract is valid during 25 years till 2043.
To reach the expected production levels the Group will over the 25
year period need to drill approximately 15 wells.
c) 3A-Best Group JSC
As at 31.12.2019 3A-Best had the following debts related to its
SSU contract: US$2,500,000 of social development payment and about
$US 1,000,000 of the debts related to previous years' work program
obligations. According to the Addendum #8 to the Contract signed by
the company on January 20, 2020 3A-Best has agreed the following
schedule of payments related to the social development and the work
program related to previous SSUC extension(s):
-- To make payment of US$580,000 quarterly during 6 quarters till June 2021;
-- To drill 2 shallow wells with the total depth of 5,750 meters
during the period January-June 2020;
-- To make investments of approximately US$2,350,000 during the period January-June 2020.
According to the SPA related to the acquisition of 3A-Best the
Company has been indemnified by the previous owners from any
previous debts (quarterly payments of US$580,000 to discharge the
historic obligations) and they guaranteed to make repayments on a
timely basis. The Group is responsible for the work program
obligations agreed with the Ministry of Energy of Kazakhstan for
the period January-June 2020 (US$2,350,000). The Group has applied
for a deferral of the amounts due and work program commitments.
Management believes that the declaration by the Government of
Kazakhstan of an emergency situation during March-April and partly
in May 2020 as a result of COVID-19 are such that the Kazakhstan
authorities will agree postpone the requirement for works until
2021 without negative consequences.
Contingent liabilities
A subsidiary of the Group is subject to an open tax assessment
in respect of the 2012 tax year. The Group has taken professional
advice and continues to dispute the assessment. If the Group is
unsuccessful in defending its position, the amount payable based on
the assessment would be US$2 million plus potential fines and
penalties. The assessment involves interpretation of contractual
arrangements between companies in the Group. The matter is
considered to represent an uncertain tax position under IFRS and
management have determined that the most likely outcome method of
measurement is most appropriate. Based on professional advice, the
development of the matter over several years and all relevant facts
and circumstances no provision is considered to be applicable.
20 Munaily disposal
During 2018 the Group entered into a sale and purchase agreement
("SPA") with WIX Energy LLP to dispose of 99% of its interest in
Munaily Kazakhstan LLP. Under the terms of the agreement, WIX
Energy LLP agreed to purchase 99% of the equity for a total
consideration of US$134 thousand from the Group.
This transaction completed on 20 December 2018.
The loss on disposal of Munaily Kazakhstan LLP was determined as
follows:
At date of disposal
$'000
----------------------------------------- ----------------------------
Total consideration 134
----------------------------------------- ------
Non-current assets (58)
Trade and other receivables (14)
Trade and other payables 350
Non-current liabilities 2,882
----------------------------------------- ------ --------------------
Net liabilities at date of disposal 3,160
----------------------------------------- ----------------------------
Less: minority share 136
Gain on disposal before the effect
of cumulative translation reserve 3,158
----------------------------------------- ------
Less: Release of cumulative translation
reserve 8,305
--------------------
Loss on disposal (5,147)
----------------------------------------- ----------------------------
The net cash inflow on disposal
comprises:
----------------------------------------- ----------------------------
Cash received 134
Cash disposed of -
----------------------------------------- ----------------------------
Net cash inflow 134
----------------------------------------- ----------------------------
Munaily Kazakhstan LLP had the following results during 2018 and
2017:
201 8 2017
-----------------------
US$'000 US$'000
----------------------- ------- -------
Revenue - 16
Expenses (334) (614)
Loss before taxation (334) (598)
------------------------ ------- -------
Cash movements related to Munaily were negligible.
21 Purchase of 3A-Best Group JSC
On 21 January 2019, the Company acquired 100% of the shares of
3A-Best Group JSC, a company that owns a 1,347 sq km Contract Area
located close to the Caspian port city of Aktau in the Mangystau
Province of Kazakhstan.
The purchase price is satisfied by the issue of 149,253,732 new
Companies shares at the price of 6.15 p per share, that represents
closing price of Company's shares at the date the SPA was signed
and the substantive conditions had been met such that control
passed to the Company, notwithstanding delays in the shares of
3A-Best being legally transferred to the Company and associated
issuance of the Company's shares in consideration owing to
procedural delays. Management have analysed the structure of the
transaction and the underlying activities and concluded that the
transaction represents an asset purchase.
The fair value of the identifiable assets and liabilities of
3ABest as at the date of acquisition were:
US$'000
------------------------------------------ -----------
Exploration assets 6,404
Receivable from sellers recognized
in other non-current receivables* 3,826
Other non-current receivables 502
Total assets 10,732
Current contractual provisions 2,906
Other payables related to contractual
obligations 920
Total liabilities 3,826
Total identifiable net assets at
fair value 6,906
Total value of shares issued as
consideration 11,795
Additional fair value recorded
to unproven oil and gas assets 4,889
* Based on the terms of SPA previous owners of 3A-Best must
compensate the Group for all contractual obligations of 3ABest
incurred in the period up to SPA sign off date under an
indemnification in the SPA. Therefore, the Group has recognized the
receivable equal to the contractual provisions and other payables
related to the contractual obligations in the completion date
balance sheet. The Group have assessed the receivable for expected
credit losses, considering scenarios around the probability of
default by one or more of the vendors and concluded no expected
credit loss is applicable.
22 Deferred tax
Deferred tax liabilities comprise:
Group Group
201 9 2018
---------------------------------------------
US$'000 US$'000
--------------------------------------------- ------- -------
Deferred tax on exploration and evaluation
assets acquired 7,244 6,733
---------------------------------------------- ------- -------
7,244 6,733
--------------------------------------------- ------- -------
The Group recognises deferred taxation on fair value uplifts to
its oil and gas projects arising on acquisition. These liabilities
reverse as the fair value uplifts are depleted or impaired.
The movement on deferred tax liabilities was as follows:
Group Group
201 9 201 8
US$'000 US$'000
---------------------------------------------- ------- ---------------------------
At beginning of the year 6,733 7,784
Deferred tax related to impairment reversal
(note 8) 483 -
Foreign exchange 28 (1,051)
7,244 6,733
---------------------------------------------- ------- ---------------------------
As at 31 December 2019 the Group has accumulated deductible tax
expenditure related to BNG expenditure of approximately US$89
million (31 December 2018 US$97 million) available to carry forward
and offset against future profits. This represents an unrecognised
deferred tax asset of approximately US$17.8 million (31 December
2018: US$19.4 million). Given the uncertainties regarding such
deductions and the developing nature of the relevant tax system no
deferred tax asset is recorded. Beibars have tax losses carried
forward of US$5.1 million (31 December 2018: US$5.1 million). This
asset is fully impaired and there is insufficient certainty of
future profitability to utilise these deductions.
23 Share option scheme and LTIP scheme
During the year the Group and the Company had in issue
equity-settled share-based instruments to its Directors and certain
employees. Equity-settled share-based instruments have been
measured at fair value at the date of grant and are expensed on a
straight-line basis over the vesting period, based on an estimate
of the shares that will eventually vest. Options generally vest in
three equal tranches over the three years following the grant.
Number of Number of Options exercised Total options Weighted
options options expired outstanding average
granted exercise
price in
pence (p)
per share
As at 31 December
2018 88,458,226 (54,810,830) (11,100,000) 22,547,396 13
----------------------- ---------- ---------------- ----------------- ------------- ----------
Directors 2,000,000 (807,396) (4,200,000) (3,007,396) -
Employees and others 1,000,000 (200,000) - 800,000 -
----------------------- ---------- ---------------- ----------------- ------------- ----------
As at 31 December
2019 91,458,226 (55,818,226) (15,300,000) 20,340,000 15
----------------------- ---------- ---------------- ----------------- ------------- ----------
The options were issued to Directors and employees as
follows:
20,340,000 outstanding options as at 31 December 2019 are
exercisable.
The range of exercise prices of share options outstanding at the
yearend is 4p - 20p (2018: 4p - 20p). The weighted average
remaining contractual life of share options outstanding at the end
of the year is 4.3 years (2018: 3.8 years).
The options granted in the year are exercisable at 20p with a
life of 10 years with employment based vesting conditions. The fair
value of the options was determined to be US$ 130,061 using a
Black-Scholes valuation model. The key inputs were: Stock price -
0.12 GBP, Expected life in years - 3, Annualized Volatility - 80%,
Discount Rate, Bond Equivalent Yield - 1.81%.
Long Term Incentive Plan (LTIP) scheme:
On 5 June 2019 the Company made awards under a long term
incentive plan. Clive Carver, Executive Chairman, and Kuat
Oraziman, Chief Executive Officer, are entitled to receive cash
payments to be triggered by the Company's attainment of both
pre-set market capitalisation and share price targets as
follows:
Market cap threshold Share price target Pay-out rate Pay-out amount
(each) (each)
$ billion Pence per share % $' million
0.8 17.23 0.6 3.0
1.3 20.67 0.6 3.0
1.8 24.81 0.6 3.0
2.3 29.77 0.6 3.0
2.8 35.72 0.6 3.0
The scheme continues beyond the numbers in the table such that
with the threshold for market capitalisation increasing at the rate
of $0.5 billion and the corresponding share price threshold
increasing from the earlier threshold by a constant factor of 1.2.
Each threshold must be sustained for at least 30 consecutive days
for the awards to be triggered. Payments shall be made only when
the Company has free cash either in the form of distributable
reserves or as a result of a non interest bearing subordinated
shareholder loan or an equity placing at a price not below the
relevant share price threshold.
There may be only one pay-out for each market capitalisation
threshold crossed no matter how many times it is crossed.
The Group has determined that at inception and 31 December 2019,
the fair value of the cash settled share based payment award is
immaterial based on analysis of the thresholds, historical
volatility rates and the applicable share price and market
capitalisation in the period.
24 Financial instrument risk exposure and management
In common with all other businesses, the Group and Company are
exposed to risks that arise from its use of financial instruments.
This note describes the Group and Company's objectives, policies
and processes for managing those risks and the methods used to
measure them. Further quantitative information in respect of these
risks is presented throughout these financial statements.
The significant accounting policies regarding financial
instruments are disclosed in note 1.
There have been no substantive changes in the Group or Company's
exposure to financial instrument risks, its objectives, policies
and processes for managing those risks or the methods used to
measure them from previous years unless otherwise stated in this
note.
Principal financial instruments
The principle financial instruments used by the Group and
Company, from which financial instrument risk arises, are as
follows:
Group Group Company Company
Financial assets 201 9 2018 2019 2018
US$'000 US$'000 US$'000 US$'000
------------------------------ --------- --------- --------- ---------
Intercompany receivables - - 10,635 3,012
Other receivables 4,504 245 - -
Restricted use cash 241 250 - -
Cash and cash equivalents 4,060 557 87 292
------------------------------ --------- --------- --------- ---------
8,805 1,052 10,722 3,304
------------------------------ --------- --------- --------- ---------
Financial liabilities Group Group Company Company
2019 2018 2019 2018
US$'000 US$'000 US$'000 US$'000
------------------------------ --------- --------- --------- ---------
Trade and other payables 6,606 3,293 1,111 799
Other payables - current - - 30,678 8,232
Other payables - non-current - - - 16,735
Borrowings - current 4,050 2,572 1,814 400
10,656 5,865 33,603 26,166
------------------------------ --------- --------- --------- ---------
Changes in liabilities arising from financial activities
Below is the movement of financial liabilities of the Group for
the years ended 31 December 2019 and 2018:
Foreign
Disposal exchange
1 January Loans Interest of loans difference, 31 December
2019 received accrued Repayment net 2019
--------------- ---------- ---------- --------- ----------- ---------- ------------- ------------
Financial
liabilities
Borrowings 2,572 1,330 160 - (28) 3 4,050
Foreign
Disposal exchange
1 January Loans Interest of loans difference, 31 December
2018 received accrued Repayment net 2018
--------------- ---------- ---------- --------- ----------- ---------- ------------- ------------
Financial
liabilities
Borrowings 2,132 1,047 337 (326) (534) (84) 2,572
Below is the movement of financial liabilities of the Company
for the years ended 31 December 2019 and 2018:
Foreign
Disposal exchange
1 January Loans Interest of loans difference, 31 December
2019 received accrued Repayment net 2019
--------------- ---------- ---------- --------- ----------- ---------- ------------- ------------
Financial
liabilities
Borrowings 400 1,330 84 - - - 1,814
Foreign
Conversion exchange
1 January Loans Interest to equity difference, 31 December
2018 received accrued Repayment net 2018
-------------- ------------ ---------- --------- ------------- ---------- ------------ ------------
Financial
liabilities
Borrowings - 400 - - - - 400
Principal financial instruments
The principal financial instruments used by the Group and
Company, from which financial instrument risk arises, are as
follows:
-- other receivables
-- cash at bank
-- trade and other payables
-- borrowings
General objectives, policies and processes
The Board has overall responsibility for the determination of
the Group and Company's risk management objectives and policies
and, whilst retaining ultimate responsibility for them, it has
delegated the authority for designing and operating processes that
ensure the effective implementation of the objectives and policies
to the Group and Company's finance function. The Board receives
regular reports from the finance function through which it reviews
the effectiveness of the processes put in place and the
appropriateness of the objectives and policies it sets.
The overall objective of the Board is to set policies that seek
to reduce risk as far as possible without unduly affecting the
Group and Company's competitiveness and flexibility. Further
details regarding these policies are set out below:
Credit risk
The maximum exposure to credit risk is represented by the
carrying amount of each financial asset in the balance sheet which
at the yearend amounted to US$ 8.8 million (2018: US$ 1
million).
Credit risk with respect to Group receivables and advances is
mitigated by active and continuous monitoring the credit quality of
its counterparties through internal reviews and assessment. Refer
to note 21 for details of the 3A Best credit risk assessment.
The Company is exposed to credit risk on its receivables from
its subsidiaries. The subsidiaries are exploration and development
companies with no current commercial exploitation sales and
therefore, whilst the receivables are due on demand, they are not
expected to be paid until there is a successful outcome on a
development project resulting in commercial exploitation sales
being generated by a subsidiary. In application of IFRS 9 the
Company has calculated the expected credit loss from these
receivables (Note 15).
The carrying amount of financial assets recorded in the Group
and Company financial statements, which is net of any impairment
losses, represents the Group's and Company's maximum exposure to
credit risk.
Credit risk with cash and cash equivalents is reduced by placing
funds with banks with high credit ratings.
Capital
The Company and Group define capital as share capital, share
premium, deferred shares, other reserves, retained deficit and
borrowings. In managing its capital, the Group's primary objective
is to provide a return for its equity shareholders through capital
growth. Going forward the Group will seek to maintain a gearing
ratio that balances risks and returns at an acceptable level and
also to maintain a sufficient funding base to enable the Group to
meet its working capital and strategic investment needs. In making
decisions to adjust its capital structure to achieve these aims,
either through new share issues or the issue of debt, the Group
considers not only its short-term position but also its long-term
operational and strategic objectives.
The Group's gearing ratio as at 31 December 2019 was 9%
(2018:6%).
There has been no other significant changes to the Group's
Management objectives, policies and processes in the year.
Liquidity risk
Liquidity risk arises from the Group and Company's Management of
working capital and the amount of funding committed to its
exploration programme. It is the risk that the Group or Company
will encounter difficulty in meeting its financial obligations as
they fall due.
The Group and Company's policy is to ensure that it will always
have sufficient cash to allow it to meet its liabilities when they
become due. To achieve this aim, it seeks to raise funding through
equity finance, debt finance and farm-outs sufficient to meet the
next phase of exploration and where relevant development
expenditure.
The Board receives cash flow projections on a periodic basis as
well as information regarding cash balances. The Board will not
commit to material expenditure in respect of its ongoing
exploration programmes prior to being satisfied that sufficient
funding is available to the Group to finance the planned
programmes.
For maturity dates of financial liabilities as at 31 December
2019 and 2018 see table below. The amounts are contractual payments
and may not tie to the carrying value:
On Demand Less than 3 months 3-12 months 1- 5 years Over 5 years Total
---------------------- ---------- ------------------- ------------ ----------- ------------- -------
Group 2019 US$'000 4,050 1,384 5,222 - - 10,656
Group 2018 US$'000 2,572 710 2,583 - - 5,865
Company 2019 US$'000 1,814 575 536 - 30,678 33,603
Company 2018 US$'000 8,632 210 589 - 23,617 33,048
---------------------- ---------- ------------------- ------------ ----------- ------------- -------
Interest rate risk
The majority of the Group's borrowings are at fixed rate. As a
result the Group is not exposed to the significant interest rate
risk.
Currency risk
The Group and Company's policy is, where possible, to allow
group entities to settle liabilities denominated in their
functional currency (primarily US$ and Kazakh Tenge) in that
currency. Where the Group or Company entities have liabilities
denominated in a currency other than their functional currency (and
have insufficient reserves of that currency to settle them) cash
already denominated in that currency will, where possible, be
transferred from elsewhere within the Group.
In order to monitor the continuing effectiveness of this policy,
the Board receives a periodic forecast, analysed by the major
currencies held by the Group and Company.
The Group and Company are primarily exposed to currency risk on
purchases made from suppliers in Kazakhstan, as it is not possible
for the Group or Company to transact in Kazakh Tenge outside of
Kazakhstan. The finance team carefully monitors movements in the
US$/Kazakh Tenge rate and chooses the most beneficial times for
transferring monies to its subsidiaries, whilst ensuring that they
have sufficient funds to continue its operations. The currency risk
relating to Tenge is significant.
In the event that Kazakhstani Tenge devalues against the US$ by
30% the Group would incur foreign exchange losses in the amount of
US$49 million (2018: US$46 million) that would be reflected in
other comprehensive income. The impact of such a devaluation on the
translation of monetary assets and liabilities (predominantly
intercompany loans) held in Kazakhstan and denominated in non-Tenge
currencies would be exchange losses recorded in the statement of
changes in equity of US$49 million (2018: US$46 million).
25 Related party transactions (please see also note 26)
The Company has no ultimate controlling party.
25.1 Loan agreements
The Company has loans outstanding as at 31 December, 2018 and
2018 with Kuat Oraziman and legal entities controlled by him,
details of which have been summarised in note 18.
25.2 3A-Best acquisition
On 1 July 2019 Caspian Sunrise plc acquired 100% interest at
3A-Best Group JSC by the way of exchange of the shares (note 21).
33.33% of the interest at 3A-Best was owned by Mr. Rafik Oraziman,
the member of Oraziman family. As a result of the deal the interest
of Oraziman family at Caspian Sunrise plc at 31.12.2019 increased
to 44%.
25.3 Key management remuneration
Key management comprises the Directors and details of their
remuneration are set out in note 6.
25.4 Purchases
As at year end the Group has no prepayments made (2018: US$2.3
million) and no trade receivables (2018: US$80,000) in relation to
STK Geo LLP, the company registered in Kazakhstan, which is owned
by a member of Kuat Oraziman's family. Major part of the
prepayments to STK Geo LLP has been settled through delivery of
works. The remaining part of the receivable from the company of US
$ 261,000 has been impaired during 2019.
During 2018-2019 the Group had purchased drilling and workover
services from the related party KazSmartEnerKon LLP, a company
registered in Kazakhstan, which is owned by Kuat Oraziman, amounted
US$ 3 million (2018: US$4.2 million). These expenses were
capitalized to unproven oil and gas assets. As at year end the
Group has prepayments made in the amount of US$ 0.5 million (2018:
US$2.9 million) in relation to these drilling services.
25.5 Caspian Explorer
In February 2020, shareholders approved the acquisition of
Prosperity Petroleum FZE, the UAE registered entity that is the
ultimate holding company for the Caspian Explorer, a shallow water
drilling vessel operating in the norther Caspian Sea. The
acquisition remains subject to regulatory approvals in the UAE.
(see note 27)
26 Non-controlling interest
Group Group
201 9 201 8
---------------------------------------
US$'000 US$'000
--------------------------------------- ------- -------
Balance at the beginning of the year (5,605) (4,654)
Share of loss for the year (124) (167)
Exchange differences on translating
foreign operations and recycling on
disposal - (920)
Disposal of Munaily - 136
---------------------------------------- ------- -------
(5,729) (5,605)
--------------------------------------- ------- -------
As at 31 December 2019 non-controlling interest represents
minority share in BNG Ltd LLP and Beibars Munail LLP (as at 31
December 2018: BNG Ltd LLP, Beibars Munai LLP and Munaily
Kazakhstan LLP).
27 Events after the reporting period
Acquisition of the Caspian Explorer
In February 2020, the Shareholders approved the proposed
acquisition of 100% of the shares of Prosperity Petroleum FZE, the
UAE registered holding company of the Caspian Explorer, a drilling
vessel capable drilling exploration wells in the shallow waters of
the northern Caspian Sea. A majority of the shares of Prosperity
Petroleum are owned by members of the Oraziman family and therefore
a related party transaction on completion.
The estimated consideration of $25 million to be satisfied by
the issue of 160,256,410 new Ordinary shares at a price of 12p per
share, a premium of 27.7 per cent to the closing mid-market price
on 20 January 2020. Currently the Company is in a process of
acquiring the related consent from the officials of Kazakhstan, the
Company expects to get all the related permissions during the
second part of 2020.
At the date of approval of these consolidated financial
statements, Covid-19 continues to spread internationally,
contributing to a sharp decline in global financial markets and a
significant decrease in global economic activity. On 11 March 2020,
the Covid-19 outbreak was declared a global pandemic by the World
Health Organization and has since then resulted in numerous
governments and companies, including Caspian Sunrise, introducing a
variety of measures to contain the spread of the virus. The
outbreak has also created significant volatility in financial
markets and is considered to have negatively impacted commodity
prices, including oil prices, which is relevant to financial
performance since year end and may impact future asset values
including the carrying value of proven and unproven oil and gas
assets should they remain depressed for a prolonged period.
This information is provided by RNS, the news service of the
London Stock Exchange. RNS is approved by the Financial Conduct
Authority to act as a Primary Information Provider in the United
Kingdom. Terms and conditions relating to the use and distribution
of this information may apply. For further information, please
contact rns@lseg.com or visit www.rns.com.
END
FR ZZGZVRDVGGZM
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June 25, 2020 02:00 ET (06:00 GMT)
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