TIDMCASP
RNS Number : 0508A
Caspian Sunrise plc
24 May 2019
Caspian Sunrise PLC
("Caspian Sunrise" or the "Company")
Annual Report and Financial Statements for the Year Ended 31
December 2018
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 2018.
Highlights for the year:
Financial
-- Revenue increased by 41% to $10.7m (2017:$7.6m) with a greater quantity of oil sold;
-- Administrative costs fell 11% to $2.6 m (2017: $3.4m),
resulting in a reduced loss from continuing operations of $3.4m
(2017: $4.7m);
-- Loss for the year of $8.5m (2017:$4.7m) includes $5.1m
(2017:$Nil) on discontinued operations at Munaily, mainly due to
historic foreign exchange losses recycled from equity to income
statement on disposal;
-- The carrying value of the Company's oil and gas assets fell
from $69.7m to $55.7m, this movement was related to the value of
oil produced being deducted from the carrying value in accordance
with prevailing accounting conventions and currency devaluations
partly offset by costs capitalised.
Operational
-- Operational wells drilled at end of year 2018 was 17 (2017: 16);
-- Daily production (based on average in December 2018) 1,903
bopd (2017: 2,208 bopd based on average in December 2017), which
reflects the Company's decision to use smaller choke settings to
prolong the productive life of the wells and production from some
of the producing wells being suspended to allow workovers and the
testing of different intervals;
-- Reserves at 31 December 2018: P1 17.8 mmbls and P2 28.8 mmbls
(2017: P1 17.8 mmbls and P2 28.8 mmbls);
-- On 29 May 2018, Caspian Sunrise announced the conditional
acquisition of 3A Best Group JSC ("3A Best"), 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 3A Best Contract
Area surrounds and runs under the successful Dunga Contract Area
(not owned by Caspian Sunrise), which the Directors believe to be
producing some 15,000 bopd;
-- Caspian Sunrise's technical team believe some of the
geological characteristics of the Dunga Contract Area are also
present at 3A Best. Additionally they 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; and
-- In December 2018 the Company applied to move the MJF
structure, which is currently 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 could be sold by
reference to world rather than domestic Kazakh prices.
Post year end highlights:
Financial
-- In January 2019, the Group completed the 100 per cent.
acquisition of 3A Best for an all share consideration of $13.5
million.
Operational
-- The Company believes the horizon found at Deep Well A8
extends across the full 58km2 of the Airshagyl structure
-- This find, together with the finds at Deep Wells A5 and A6,
marks the third of the three deep wells drilled on the Airsghagyl
structure to have shown the presence of oil; and
-- The anticipated receipt the MJF export licence will have a
material effect on income as the Company embarks on a 10 well
infill MJF drilling programme.
Other
-- Timothy Andrew Field was appointed as a non-executive
director of the Company in January 2019; and
-- The Directors ambition is to significantly grow the Company
both by the development of BNG and 3A Best but also by targeted
acquisitions. The Board's focus will remain in Kazakhstan where
several opportunities have been identified and preliminary due
diligence conducted.
Related Party Agreement
-- The Company announces it has entered into an agreement ('the
Framework Agreement') with its CEO, Kuat Orazimanin respect of the
use contractors for drilling or other oil services.
-- Under the Framework agreement, where the Company uses the
services of a company owned or partially owned by a member or
members of the Oraziman family:
o The terms of the contract or services shall first be approved
by the Independent Directors ([1])
o Pricing of such contracts or works shall be at a rate([2]) of
an arms-length transaction
o Where appropriate, competing tenders will be sought and the
opinions of both external and internal experts may be consulted by
the Independent Directors in their assessment of terms.
-- As a result of the shareholdings of the Oraziman family and
the position of Kuat Oraziman as a director of the Company, the
Framework Agreement is considered a related party transaction under
the AIM Rules.
-- The independent directors of the Company in respect of AIM
Rule 13, being Clive Carver, Edmund Limerick, and Tim Field
consider, having consulted with WH Ireland, that the terms of the
Framework Agreement are fair and reasonable insofar as Shareholders
are concerned.
The results are included below and the Report and Accounts will
be posted to the Company's website at:
https://www.caspiansunrise.com/
The Report and Accounts and Notice of Annual General Meeting
will shortly be posted to shareholders. The Company's AGM will be
held at the offices of Fladgate LLP, 16 Great Queen Street, London
WC2B 5DG, at 11am on Friday 21 June 2019.
Clive Carver, Executive Chairman commented on the results:
"While progress was steady rather than dramatic in the period
under review we have recently reported real progress with our deep
wells on the Airshagyl structure.
We continue to look forward to the early award of the licence
upgrade at the MJF structure, which will allow oil to be sold by
reference world rather than domestic prices and broadly double the
receipts from oil produced."
Caspian Sunrise PLC
Clive Carver
Executive Chairman +7 727 375 0202
WH Ireland, Nominated Adviser
& Broker
James Joyce
Jessica Cave
James Sinclair-Ford +44 (0) 207 220 1666
Yellow Jersey PR
Tim Thompson
Henry Wilkinson +44 (0) 203 735 8825
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
Progress in 2018 at our flagship asset BNG in the period under
review was limited. We continued to move forward at a steady pace
with our shallow structures, in particular the MJF, but have not
yet had the breakthrough we expected at any of the deeper
structures.
Nevertheless, we are a Group with reliable production from our
shallow wells, the income from which is sufficient to cover the day
to day operating costs of the Group with additional funding
identified for our planned drilling programme.
We expect our income to grow materially following the
anticipated receipt the MJF export licence and as we embark on a 10
well infill MJF drilling programme.
A significant proportion of the costs of our deep drilling
programme have also been met from the income from our shallow
production boosted from time to time by funds supplied by our CEO
Kuat Oraziman.
As a low-cost producer with strong cash flows, low debt levels
and a huge upside potential the board remains extremely confident
in the Group's successful future.
Background
The Company'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. In 2017 we increased our stake to 99% upon the
completion of the merger with Baverstock GmbH.
Since 2008 more than $95 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.
At that time 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 Gaffney Cline & Associates assessed the
reserves attributable to the BNG shallow structures. Based on these
assessments we set out the year end positions as follows:
As at 31 December As at 31 December
2018 2017
BNG
------------------ ------------------
Shallow P1 (mmbls) 17.8 17.8
------------------ ------------------
Shallow P2 (mmbls) 28.8 28.8
------------------ ------------------
Deep P1 (mmbls) Nil Nil
------------------ ------------------
Deep P2 (mmbs) Nil Nil
------------------ ------------------
The above is based on 100% of each Contract Area.
GCA are working with us on an update to the 2016 estimates and
seeking to confirm the reserves from our shallow structure based on
actual rather than theoretical data. They are also on standby to
update their work when any of the deep wells flow sufficiently for
a reliable flow test.
Shallow structures
There are two confirmed and producing shallow structures at BNG
with the possibility of a third.
MJF
We announced the discovery of the MJF structure in 2013 and have
subsequently drilled 6 wells of which 5 are currently
producing.
We believe the productive 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
approximately 10km(2.) The producing wells range in depth from
2,192 meters to 2,448 meters.
In December 2018 we formally applied to move the MJF structure,
which is currently 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 could be sold by
reference to world rather than domestic Kazakh prices. This would,
in the Board's view, broadly double the income from the same
production levels.
The impact of a combination in a change to the licensing systems
coupled by a long-expected reshuffle of those occupying ministerial
positions has resulted in a much greater delay than we anticipated
or is warranted.
The principal change to the licence systems has been to reduce
the length of an appraisal licence from the previous six years to
the current five years. In return a licence holder's obligations to
make meaningful social payments during the appraisal period has
been significantly reduced.
In the light of these events we understand a backlog of licence
applications has arisen. Nevertheless, we continue to expect an
early award of a full production licence for the MJF structure.
Recent daily production from those MJF wells operating has been
approximately 1,500 bopd and we believe the maximum production
capacity from the wells drilled to date when working to their
optimum is some 2,000 bopd. On receipt of the upgraded MJF licence
we intend to embark on an infill drilling programme of 10 new
shallow wells over a 24 month period at an expected cost of between
$1 and $2.0 million per well. Following completion of the infill
drilling programme we expect the productive capacity of the wells
then drilled at the MJF structure when working optimally should
increase to some 4,000 bopd.
South Yelemes
The first wells were drilled on the South Yelemes structure
during the Soviet era.
Well 54 remains 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) producing in aggregate 140 bopd, which in itself is not
particularly exciting. However, as previously reported we believe
the structure, including Well 54, 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.
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. Recent
re-evaluation of the wireline and mudlog data suggests additional
untested potential within two intervals shallower in the well.
We have now re-completed the bottom of the well to isolate the
water and are set to reperforate the well at intervals between
2,033.5 meters to 2,035.5 meters and between 2,250 meters and 2,253
meters.
Deep structures
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.
The well was difficult to drill with a salt layer of
approximately 130 meters and high temperatures and pressures 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 to allow an extended flow test.
In December 2017, the well tested for 15 days at an average rate
of 3,800 bopd before the flow reduced by debris in the well to
1,000 bopd leading to the well test being suspended. Since that
date we have struggled to clear the well from initially excess
drilling fluid and latterly metal objects.
Despite on occasion being very close to removing the remaining
metal obstruction from the well in May 2019, we decided to suspend
further work on the current side-track and plan to drill a new
side-track from a depth of 3,850 meters to a depth of 4,450
meters.
Discussions with potential contractors have commenced and we
expect to complete the new side-track approximately two months
after work commences.
Deep Well A6
The second well drilled in the Airshagyl structure was Deep Well
A6, which was spudded in 2015 and drilled to a depth of 5,050
meters.
Repeated problems in perforating the well at the interval of
interest prevented the well being put on test and for the period
under review work on A6 waited on the completion of work being
undertaken at both Deep Wells A5 and 801.
Advice has been received from an international consultancy with
expertise in high pressure / high temperature wells and a new
internal work programme agreed upon.
We intend first to re-cement the bottom of the well in order to
isolate the lower portion of the well preventing water encroachment
from below. After cementing, the deeper most prospective portion of
the reservoir; 4479m- 4489m, will be reperforated. Depending upon
results we may also reperforate the upper prospective reservoir
interval.
Recently, oil from behind the casing came to the surface under
its own pressure. The well has now been closed in anticipation of
the planned works.
Deep Well A8
In November 2018 Deep Well A8 was spudded with a planned total
depth of 5,300 meters. To date we have drilled and laid casing to a
depth of 4,100 meters. The well is targeting the same pre-salt
carbonates that were successfully identified in the Deep Well A5.
We also plan to evaluate deeper carbonate targets of Devonian to
Mississippian ages.
Drilling has now reached a depth of 4,391 meters, which is
beyond the salt and clay layers and well into the first of the
expected oil-bearing zones.
We are pleased to report that oil bearing rock has been
recovered, indicating the presence of an oil-bearing interval. A
third-party specialist company engaged to collect core samples
covering the full extent of the interval has reported oil and gas
in a 4 meter core. Drilling and core sampling is set to
continue.
This find together with the finds at Deep Wells A5 and A6 marks
the third of the three deep wells drilled on the Airsghagyl
structure and which has shown the presence of oil. The Company
believes the structure may extend across the full 58 km2 of the
Airshagyl structure
The second reservoir target is of Devonian age anticipated at a
depth of approximately 5,200 meters.
Based on progress to date we continue to expect to reach total
depth in Quarter 3 2019.
Summary
Based on results to date we believe the Airshagyl structure will
provide the greatest quantities of oil at the BNG Contract Area,
with wells potentially consistently flowing at the rate of in
excess of 2,500 bopd.
With oil confirmed from three separate wells on the Airshagyl
structure we expect this structure to be the next we apply to have
moved to a full production licence with the majority of oil
produced sold by reference to world rather than domestic
prices.
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 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
The blockages in the well preventing an extended flow test are
the result of high temperatures/ pressures and excess drilling
fluids. A combination of invasion by the extensive heavy drilling
fluids along with the usual challenge associated with the
completion of high temperature, high pressure wells are believed to
be hampering successful production test. We have used a variety of
techniques including the use of chemicals and the drilling of a
side-track in Q1 2018 to establish good reservoir connectivity.
For a period we allowed the natural pressure inside and outside
the drill pipe to build in the expectation this would over time
reduce the blockage. More recently we have been looking at using
the pressure in the well to stimulate activity inside the well by a
process of reinjection.
Recently, for safety reasons, the well has been opened on an
almost daily basis to relieve the excess pressure build up and on
those occasions water and gas has come to the surface to the
surface. A technical review by leading international consultants
confirmed our plan to conduct a pressurised acid treatment of the
well as the best way forward.
The common problems with the deep wells
We have struggled with our deep wells since the outset. We
believe all the issues in getting our deep wells to test on an
extended basis are from blockages in the well stemming from a
combination of extreme pressure and extreme temperatures.
At Deep Well A5 the pressure has reached 930 ATM and at deep
well 801 the bottom hole pressure has reached 850 ATM. Bottomhole
temperatures are about 128 degree centigrade. These are exceptional
levels when compared to wells of similar depths in other
territories and we have found there to be a lack of skilled
operators capable of first, drilling the wells and second, bringing
such wells into production.
Our specialist blow-out preventers have a certified capacity of
500 ATM. The additional overlying 5,000 meters of hydrostatic
pressure above the open reservoir section provides a total of
approximately 1,000 ATM of pressure control.
Issues with deep wells is not uncommon in the region. The nearby
Tengiz field, which targets the same aged reservoirs at about the
same depths drilled the first discovery well in 1979 but first
production did not happen until 12 years later. The field is now
producing at the rate of 540,000 bopd.
The operators there developed specialist skills and now enjoy
the rewards from operating one of the world's most successful
fields. We are seeking to replicate these skills by using the
knowledge of leading international consultancies.
We have also learnt from the problems of the first wells
drilled. We are now able to drill through the salt levels and below
with far fewer issues than at the outset. More difficult has been
getting the wells once drilled to flow sufficiently long enough to
conduct extended flow tests.
With a history of blow-outs from wells drilled on the Contract
Area in Soviet times every action to allow the wells to flow to
conduct the extended flow tests is taken only after very careful
safety considerations and often after lengthy discussions with the
regulatory authorities.
Infrastructure requirements
We are able to transport our current production using storage
tanks with aggregate capacity of 7,000 bbls and using a fleet of
heated tankers. As production levels from the MJF structure
increase and when production commences from the deep wells drilled
relying on our present arrangements would no longer make commercial
sense.
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.
Services division
We have also decided to establish our own services division.
This reflects the expected increase in operational activities as
the Group develops. We believe significant cost savings would be
available if we owned more of the equipment we currently hire. We
would also avoid often lengthy periods of inactivity when the
required equipment is not available for hire.
We also believe there are significant opportunities to
participate in new projects in part by way of supplying equipment
otherwise difficult to source from the hire sector.
BNG Summary
It is clear to the Board that there is very significant value in
the BNG Contract Area even if we have yet to prove its full extent.
The Board remains confident that it is a matter of time before we
are able to get at least some of the deep wells drilled onto an
extended test, following which we plan to ask Gaffney Cline to
assess a reserve estimate.
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. Whilst the Company
has acquired the equity of 3ABest Group JSC, the acquisition will
be 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 issued 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 $13.5
million.
Based on an assessment of the geology we believe some of the
geological 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, although neither was commercially successful.
Under the terms of the inherited work programme we have the
obligation to drill one well to a depth of 3,000 meters by the end
of 2019 at an anticipated cost of $1.2 million and a second in
March 2020 at a cost of $1.4 million.
Discontinued activities
Munaily
We had for some time been seeking a buyer for our interest in
Munaily following a disappointing outcome of a joint venture with a
Chinese partner.
In December 2018 we sold our interest in Munaily to WIX Energy
LLP for an aggregate consideration of $0.134 million, resulting in
an accounting loss of $5.147 million (note 21) primary due to the
recycling historic foreign exchange losses from equity on
disposal.
Beibars
The force majeure declared in November 2015 in respect of our
50% interest in the Beibars Contract Area prevented any development
work at the large but early stage asset. Given our successes at
BNG, another previously early stage Contract Area and other
opportunities in Kazakhstan we chose in March 2017 to surrender our
50% interest in the Beibars Contract Area for no consideration.
Dilution
Our recent strategy has been to avoid unnecessary dilution both
at the individual asset level and at the shareholder level. With
the exception of shares issued in connection with (1) the
cancelation of the BNG royalty payments (2015); (2) the Baverstock
merger (2017); and (3) the acquisition of 3A Best; there have been
no material issue of new shares in recent years. This is despite
the Company's operational activities being constrained by a lack of
cash. We have therefore been selective in choosing which of our
structures to develop.
Where necessary we have used funding provided by local oil
traders secured on pre sales of oil backed up by periodic advances
under the general loan agreement (referred in note 1.1) with Kuat
Oraziman, our CEO.
Dividends
It is the policy of the Board to work towards an early position
where meaningful dividends can be paid. This requires not only
consistently profitable trading but also in all likelihood a
corporate reorganisation. New corporate subsidiaries have been
incorporated in the UAE, with a view improving and simplifying the
Group structure and easing the future payment of dividends.
The Board believes that with a sustainable dividend policy, the
Group will be valued more highly than at present and will also help
facilitate institutional investment.
Any dividend declared will be set at an affordable level that
does not conflict with the need to fund value enhancing growth,
whether by further investments in our existing fields or by
acquisition.
Further acquisitions
Notwithstanding our approach to dilution and dividends, it is
the Group's intention to make further asset acquisitions where the
board believes the assets in question will add to the Group's
long-term value.
Our ambition is to significantly grow the business both by the
development of BNG and 3A Best but also by targeted
acquisitions.
Our initial focus will remain in Kazakhstan where there are
attractive opportunities, limited local competition and where we
have a competitive advantage being on the ground. We also intend to
bid for new blocks, including offshore blocks, both in our own
right and as part of larger consortia. Where appropriate, we will
also consider the acquisition of allied businesses, including
service businesses and stand-alone equipment, provided the expected
net return to the Company makes any dilution worthwhile.
Several opportunities have been identified and preliminary due
diligence conducted.
Kazakhstan
Since our IPO in 2007 we have focused entirely on Kazakhstan and
in recent years entirely on the pre-Caspian basin located on the
north eastern shore of the Caspian Sea.
Introduction
The Republic of Kazakhstan is the world's largest landlocked
country and the ninth largest in the world, with an area of
2,724,900 square kilometres. Most of the country is in Asia with
only the most western parts being in Europe.
Kazakhstan is the dominant nation of Central Asia economically,
generating approximately 60% of the region's GDP, primarily through
its oil and gas industry. It also has vast mineral resources.
The recent transition to a new President suggests the political
situation is stable.
Oil and gas in Kazakhstan
Super giants
Three of the world's largest oil and gas projects are located in
Kazakhstan, Tengiz, Kashagan and Karachaganak, with Tengiz and
Kashagan being close to BNG.
Tengiz,
Tengiz, which is located just onshore along the northeast edge
of the Caspian Sea is only 40 km from our flagship BNG asset in the
Pre-Caspian basin. Oil in place for the field is estimated to be 25
billion barrels, of which 7 billion barrels are likely to be
recoverable.
The Tengiz field currently produces approximately 540,000 bopd.
Chevron, the lead operator, is spending a reported $37 billion to
increase production by 260,000 bopd by 2022.
Our technical team believe BNG may share a number of important
geological features with Tengiz.
Kashagan
The Kashagan oilfield is located 80km south-east of Atyrau in
the North Caspian Sea, Kazakhstan, and is the largest offshore
field outside the Middle East. The field contains more than 35
billion barrels of oil in total and an estimated recoverable oil
reserve of nine billion barrels. It was discovered in 2000 and
commercial development was announced in 2002.
The field is being developed in phases by the North Caspian Sea
Production Sharing Agreement (NCSPSA) consortium comprised of KMG
(KazMunayGas), Eni, ExxonMobil, Shell, Total, ConocoPhillips and
INPEX.
The total cost of the project is estimated to be more than
$100bn. Initial oil production from Kashagan started in 2013 but
had to be stopped due to faults in onshore section of pipeline.
Production resumed in 2016 with commercial production announced in
October following the first export delivery of 26,500 metric tons.
By mid-2017 production being delivered was over 200,000 barrels a
day. By year end 2017 production capacity was 270,000 barrels of
oil per day with the goal of increasing production capacity to
370,000. Also, at the end of 2017 the Kazakh government approved
early engineering and design work for a further expansion project
which could raise Phase 1 production capacity to 450,000 bopd.
Karachaganak
The Karachaganak oilfield is located onshore, several hundred
kilometres away from BNG, on the northern edge of the ancient
Pre-Caspian basin. Production is from the same Permian and
Carboniferous aged reservoirs that are productive at Tengiz and
Kashagan.
Discovered in 1979, production from Karachaganak began in 1984.
One of the world's largest gas condensate fields, original
hydrocarbons in place are estimated at 9 billion barrels of
condensate and 48 trillion cubic feet of gas; approximately 18
billion barrels of oil equivalent in total. Estimated recoverable
reserves are 2.4 billion barrels of condensate and 16 tcf of
gas.
The field is currently producing about 200,000 barrels of
condensate and 18 million cubic feet of gas per day. Since becoming
operator of the field in 1997, Karachaganak Petroleum Operating
(KPO); Royal Dutch Shell (29.25%), Eni (29.25%), Chevron (18%),
Lukoil (13.5%), KazMunayGas (10%), has invested over $22 billion
dollars in the development.
The rest
Most of the other fields active in Kazakhstan are operated
either by local privately-owned enterprises or by the subsidiaries
of larger, often state-owned enterprises. Few are self-standing
public companies such as Caspian Sunrise.
The gap between the super-giant part of the Kazakh oil scene and
the rest provides us with opportunities for the acquisition of
fields too small for the multinational operators but still
potentially very valuable.
The economy
The steady fall in the value of the Kazakh Tenge against the US
dollar, and the impact of Kazakhstan being in a customs union with
sanctions hit Russia, have resulted in Tenge denominated operating
costs falling for companies operating predominantly in US
dollars.
National infrastructure
As a result of the super-giant projects the oil and gas
infrastructure in Kazakhstan is strong with a network of pipelines
connecting the oil producing regions with the west, Russia and
China.
There is a deep pool of experienced workers and the full array
of international support services.
Licences
As with all oil and gas territories the permission of the state
is required to operate. The first international developments in
Kazakhstan were operated under profit sharing agreements but more
recently licences have been awarded to operators based on an agreed
work programme, with the risk that failure to complete the work
programme could lead to the loss of the licence without
compensation.
Exploration licences
The initial licence to develop a field is typically an
exploration licence where the focus is on completing agreed work
programme.
The work programmes under an exploration licence are typically
two years in duration and it is usual for there to be several
consecutive two-year work programmes agreed during the exploration
phase.
Appraisal licences
In the event the project appears commercial, the exploration
licence is typically upgraded to an appraisal licence. Under an
appraisal licence, oil produced incidentally while exploring and
assessing may be sold but only by reference to domestic prices.
Recently, oil sold from our MJF field has been at $19 per barrel
compared to a world price in the $70's.
Taxation under an appraisal licence is limited with only modest
deductions.
Appraisal licences were generally for six years during which the
holder has the ability to assess all the parts of the Contract Area
it considers interesting. Recent changes to the legislation has
reduced the length of appraisal generally licences to five years,
with a concession of reduced social obligation payments.
Full production licences
To sell oil by reference to world prices requires either the
field as a whole or a particular structure to be upgraded to a full
production licence.
Once under a full production licence there is only limited scope
to develop areas not already drilled. Additionally, a minority
portion of production typically remains priced by reference to
domestic prices although the majority is sold by reference to world
prices.
Under a full production licence the Company is subject to the
full array of taxes and levies, such that oil sold when the world
price is $70 per barrel might result in a net price in the range of
$38 per barrel after a discount to reflect the difference to Brent,
transportation costs and all applicable taxes, but before lifting,
treatment, storage.
Deductions from world selling prices
Operational
The lifting costs at BNG are estimated to be $1 per barrel.
Transportation
The combined costs of treatment, storage and transportation are
estimated to be $4 per barrel and set to rise to $9 per barrel on
moving to a full production licence.
Taxes
Based on a world price of $70 per barrel the aggregate tax
liability is estimated to be $24 per barrel.
Financial review
Review of the results to 31 December 2018
Revenue increased by 41% to $10.7 million with a greater
quantity of oil sold. Despite this and the increased operational
activity administrative costs fell 11% to $2.6 million.
The reduction in the operating loss from $3.4 million to $2.6
million reflects reductions in staff costs, audit and related fees
and in particular a $0.5 million reduction in the accounting charge
relating to share based payments.
The collective impact of the above was to report a $1.3 million
reduction in the loss before tax from continuing operations.
There was also a $0.9 million reduction in the tax charge for
2018 compared to 2017 following the repayment of $1.0 million
overpaid UK corporate tax.
The $5.1 million accounting charge in respect of the sale of
Munaily took the total loss before tax to $8.5 million compared to
$4.7 million in 2017.
The carrying value of our oil and gas assets fell from $69.7
million to $55.7 million, which is after the impact of cumulative
currency related write downs of $74.3 million. The reduction during
the year matches the price achieved from oil produced as required
under the prevailing accounting conventions.
The $0.9 million reduction in cash at the year end reflects our
policy of raising cash for operations from oil traders or our CEO,
Kuat Oraziman, as it needed.
Funding review
As stated elsewhere in these financial statements the Group's
approach to funding has been to wherever possible avoid unnecessary
dilution, either at the individual asset level or in the equity of
the country.
The majority of the funding comes from the sale of oil produced
from our shallow structures, often in the form of advance sales to
local oil traders.
These receipts have funded our operations in the shallow
structures and made significant contributions to the development
costs of our deep wells. This funding has been supplemented by
funds lent to the Group under a master loan agreement by Kuat
Oraziman, the CEO. Currently the total advanced is approximately
$3.0 million.
In recent years the Company's activities have been constrained
by a lack of cash. With increased cash expected from the MJF
structure we will be better placed in future periods to seek to
develop more of our potential structures.
Low cost operator
We pride ourselves on being a low-cost operator, both as
operators in the field and in controlling our General &
Administrative ("G&A") costs.
We have been aided in this by the steady fall of the value of
the Kazakh Tenge compared to the US $ as approximately half of our
G&A costs are denominated in Tenge. However, for both drilling
campaigns and in our day to day activities our approach is to
minimise the amount spent.
We believe our drilling costs, which are broadly $1-2 million
for shallow wells and $10-12 million (including competition and
testing) for deep wells are among the lowest in the industry.
The presence of high pressure at BNG reduces our lifting costs
to $1 per barrel.
For the past 4 years our G&A costs have been below $3
million despite the mounting levels of operational activity and the
increasing regulatory burden of being a public company. Inevitably,
as the scale of the business increase there will be some additions
to the G&A costs but we plan to keep these to a level below
most of the rest of the sector.
Employees
The Group has 80 employees of whom 79 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.
Communications with shareholders
Under the rules we are limited to what can be said and when it
can be said in response to individual shareholder enquiries. Often
therefore we have been unable to make any meaningful response to
perfectly reasonable enquiries.
The delays in getting our deep wells to flow long enough to
conduct flow tests there has from time to time created a news
vacuum as we have sought to avoid using the RNS announcements
system for anything but real changes in the Company's status.
In the absence of hard news it is probably inevitable that
rumours start and spread and in that climate individuals with their
own agendas seek to exploit the situation at the expense of the
Company and individual shareholders. In particular we are aware of
a number of reports circulating which are either entirely false or
based on partial information presented in a way to serve the
individuals with their own agendas. Despite unfounded rumours to
the contrary we have no intention in taking the Company private.
The London listing for our shares is a valuable asset and one we
intend to make more of as we grow.
Our policy remains to only announce news as it happens rather
than to rush announcements out whenever there is an adverse move in
the share price. We consider ourselves to be a Group here for the
long run and in attempting to build lasting shareholder value have
no interest in pandering to those possibly looking to exploit
shareholders for their own short-term benefit.
Our intention is to start paying meaningful dividends at the
first opportunity. This together with the fact we are predominantly
self-funding without the need to access the equity markets for
development capital should deter those tempted to artificially
manipulate the market in the Group's shares for the own
rewards.
Recently we have announced monthly production numbers and
achieved average sale prices and intend to continue to do so. We
will also look to make greater use of the Group's website and
possibly the RNS Reach platform.
We shall also seek to hold further shareholder events and
encourage interested shareholders to attend the Company's Annual
General Meeting on 21 June 2019.
Outlook
The Group is underpinned by steady and growing income from its
MJF production, which on its own justifies a meaningful
valuation.
The Directors continue to regard additional potential arising on
getting any of the four deep wells already drilled or in the course
of completion as being huge.
That coupled with new opportunities under review leads the board
to look to the future with confidence.
Clive Carver
Executive Chairman
Qualified Person & Glossary
Qualified person
Mr. Nurlybek Ospanov, the Company's Chief Geologist &
Technical Director, who is a member of the Society of Petroleum
Engineers ("SPE"), 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
Proved 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 2018. 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 in Kazakhstan.
Results and dividends
The consolidated statement of profit or loss is set out on page
30 and shows US$8.5 million loss for the year (2017: US$4.7
million). The Directors do not recommend the payment of a dividend
for the year ended 31 December 2018 (2017: US$ 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 as disclosed in this annual report, including notes
to the financial statements, there have been no material events
between 31 December 2018 and the date of this report, which are
required to be brought to the attention of shareholders. Please
refer to note 29 of these financial statements for further
details
Board changes
Kairat Satylganov stepped down from the Board as Chief Financial
Officer on 28 February 2018. Following Mr Satylganov's departure
from the Company, Clive Carver assumed the role of Chief Financial
Officer in addition to being Executive Chairman.
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 will be 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 e-mail updates. They also have access to the Company's
website.
The Company 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
Kairat Satylganov (resigned 28 February 2018)
Timothy Field (appointed 25 January 2019)
Directors' interests
Number of shares Number of shares
Director As at 31 December As at December 2017
2018
------------------ --------------------
Clive Carver nil nil
------------------ --------------------
Kuat Oraziman* 37,285,330 37,285,330
------------------ --------------------
Edmund Limerick** 6,430,000 3,210,000
------------------ --------------------
Kairat Satylganov*** n/a 175,682,697
------------------ --------------------
Timothy Field nil nil
------------------ --------------------
* Taken together Mr Oraziman and his adult children hold
745,706,614 shares
** includes 1,135,000 shares held by his wife
*** Mr Satylganov resigned from the Board on 28 February
2018.
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 25 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 Company'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 Company's website is the responsibility of the Directors.
The Directors' responsibility also extends to the on-going
integrity of the financial statements contained therein.
Clive Carver
Executive Chairman
23 May 2019
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 2018 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 2018 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.
Conclusions relating to going concern
We have nothing to report in respect of the following matters in
relation to which the ISAs (UK) require us to report to you
where:
-- the Directors' use of the going concern basis of accounting
in the preparation of the financial statements is not appropriate;
or
-- the Directors have not disclosed in the financial statements
any identified material uncertainties that may cast significant
doubt about the Group's or the Parent Company's ability to continue
to adopt the going concern basis of accounting for a period of at
least twelve months from the date when the financial statements are
authorised for issue.
Key audit matters
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 a material uncertainty existed
over going concern that required disclosure
The Board is required to make an assessment of the Group's and
the Parent Company's ability to continue as a going concern
for at least 12 months from the date the financial statements
are approved. Where a material uncertainty exists in respect
of the going concern assessment, the Board is required to disclose
those matters.
The Board have reviewed cash flow forecasts prepared by management
for the period to June 2020 which indicated that the Group would
have sufficient funding to meet its liabilities as they fell
due as detailed in note 1.1.
This assessment included estimates and judgments regarding assumptions
over future production, oil prices, costs, licence and drilling
expenditure.
The Board exercised judgment regarding the Group's ability to
obtain a full production licence during the period and commence
sales at world oil prices and the timing of such a licence being
awarded.
Further, the Board exercised judgment regarding the continued
availability of funding from oil traders in the form of advances
on oil production and the extent to which additional funding
requirements would be met by the Group's largest shareholder
to undertake the deep well drilling program commitments. This
represented a significant risk for our audit due to the inherent
judgements and estimates required.
How the matter was addressed in our audit
* We obtained management's cash flow forecasts and
critically assessed the key inputs including oil
prices, production levels, operating costs and
planned drilling, licence and exploration
expenditure. We assessed the inputs against recent
empirical data, work programs, contracts, licence
obligations and considered forecast oil market
trends.
* We considered the appropriateness of the Board's
judgment regarding the availability of 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 confirmed that the Group has applied for a
production licence and assessed its impact on
production cash flows. We discussed the status of the
application with the Board and considered the
potential for unforeseen delays.
* We assessed the level of funding required from the
Group's largest shareholder under the forecasts and
reasonable sensitivity scenarios, including a delay
to the planned full production licence. We obtained
management's assessment of mitigating actions in the
event of reasonable sensitivity scenarios and
evaluated the ability of management to take such
actions and the impact on the cash flows.
* We obtained the undrawn loan facility agreement
between the Company and its largest shareholder. We
considered the appropriateness of the Board's
judgment that the funds would be available, as
required. In doing so, we assessed the past history
of funding provided by the shareholder and obtained
evidence regarding the sources of funds available to
the lender.
* We assessed the disclosures included in the financial
statements at note 1.1.
Our observations
Refer to 'Our conclusions relating to going concern' above.
We found the disclosures in note 1 to be appropriate.
Key audit matter: The risk that the carrying value of the unproven
oil and gas assets require impairment
As at 31 December 2018, the Group's unproven oil and gas assets
related to the BNG Contract area cost pool were carried at US$55.7m
as shown in note 11.
At each reporting period end, management are required to assess
the unproven oil and gas assets for indicators of impairment
and, where such indicators exist, perform an impairment test.
In performing the impairment indicator review, management are
required to make a number of estimates and judgements. In particular,
the assessment involves consideration of the standing of the
exploration licence and remaining term, the future planned exploration
activity and results of activity to date.
Following their assessment management concluded that no indicators
of impairment existed in respect of the BNG cost pool. In forming
their conclusion, management particularly considered the potential
impact of the outstanding obligations under the licence detailed
in note 20 and concluded that they remained satisfied that the
outstanding obligations did not present a significant threat
to their exploration rights or give rise to contingencies.
Given the judgment and estimation required by management in
assessing potential impairment indicators, we considered this
area to be a key focus for our audit.
How the matter was addressed in our audit
* We reviewed the existing licence to confirm that the
Group holds a valid right to explore the BNG Contract
area and reviewed correspondence with the Ministry of
Energy of Kazakhstan to confirm that the Group had
been granted an extension to its exploration licence
for a period of 6 years effective 1 July 2018.
* We reviewed Board minutes, made specific inquiries of
management and reviewed budgets and work programs
submitted to the Kazakh authorities to confirm that
further drilling and exploration is planned for the
asset.
* We reviewed the conditions of the licence and
obtained reports submitted to the Kazakh authorities
in respect of expenditure to assess the compliance
with the licence terms. We specifically considered
management's judgment that the unfulfilled licence
conditions set out in note 20 would not reasonably be
expected to result in a loss of the licence. In doing
so, we confirmed that necessary payments were
included in the Group's cash flow forecasts and
considered factors including the history of
expenditure and the recent extension to the licence
which specifies financial penalties that apply to
unfulfilled commitments. We recalculated the relevant
accruals for outstanding obligations and commitments.
* We reviewed the 2015 independent reserves statement
prepared by Gaffney, Cline & Associates ("GCA") for
the shallow reservoir structures and the current
financial model used by the Group in its impairment
indicator review. We compared key inputs to the
financial model to market oil price data and the GCA
report. We considered the additional value associated
with the deep reservoir structures and 3P reserves
and prospective oil and gas resources not included in
financial model.
* We considered the Group's market capitalisation which
demonstrates a significant premium to its net asset
value.
* We assessed the independence and competence of GCA as
a management expert.
* We assessed the disclosures included in the financial
statements at notes 1.8.
Our observations
We found management's conclusion that no impairment exists on
the BNG unproven oil and gas asset to be appropriate. We found
the judgments made by management to be appropriately considered
and the disclosures in the notes to be sufficient.
Our application of materiality
Group materiality as at 31 Basis for materiality
December 2018
US$1,000,000 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 $1,000,000, being 1.5% of total assets (2017: $1,230,000).
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 $800,000, being 1.5% of total
assets, capped at 80% of Group materiality (2017: $1,088,000).
In performing the audit we applied a lower level of performance
materiality of $750,000, being 75% of Group materiality (2017:
$923,000), in order to reduce to an appropriately low level the
probability that the aggregate of uncorrected and undetected
misstatements exceeds financial statement materiality. This was
based on the low level of misstatements in the past and our overall
assessment of the control environment. Each significant component
of the Group including the parent company was audited using a lower
level of performance materiality ranging from $600,000 to $675,000
(2017: $820,000 to $1,032,000).
We agreed with the Audit Committee that we would report to the
committee all individual audit differences in excess of $50,000
(2017: $65,000). 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 exploration &
development of oil and gas assets located in Kazakhstan. We
assessed there to be 2 significant components comprising BNG and
the parent company.
These locations, which were subject to full scope audit
procedures represent the principal business units.
A non-BDO member firm performed a full scope audit of BNG in
Kazakhstan, under our direction and supervision as Group auditors
under ISA 600. 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 auditor, which included the significant areas to be
covered by the audit.
-- We performed a review of the component audit files in
Kazakhstan and held meetings with the component audit team during
the planning and completion phases of their audit.
-- 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.
The remaining components of the Group were considered
non-significant and these components were principally subject to
analytical review procedures to confirm there are no significant
risks of material misstatements within these components.
Other information
The Directors are responsible for the other information. The
other information comprises the information included in the annual
report, 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, 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
23 May 2019
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
2018 2017
-------------------------------------------- -----
US$'000 US$'000
-------------------------------------------- ----- ------------------ ------------------
Revenue 3 10,747 7,575
Cost of sales (10,747) (7,550)
-------------------------------------------- ----- ------------------ ------------------
Gross profit - 25
Share-based payments (13) (476)
Other administrative costs (2,611) (2,925)
Total administrative expenses (2,624) (3,401)
-------------------------------------------- ----- ------------------ ------------------
Operating loss 4 (2,624) (3,376)
Finance cost 7 (348) (167)
Finance income 8 - 194
Loss before taxation (2,972) (3,349)
Tax charge 9 (414) (1,345)
-------------------------------------------- ----- ------------------ ------------------
Loss after taxation from continuing
operations (3,386) (4,694)
-------------------------------------------- ----- ------------------ ------------------
Loss for the year from discontinued
operations 21 (5,147) -
------------------ ------------------
Loss for the year (8,533) (4,694)
------------------ ------------------
Loss attributable to owners of the parent (8,366) (3,928)
Loss attributable to non-controlling
interest (167) (766)
-----
Loss for the year (8,533) (4,694)
-------------------------------------------- ----- ------------------ ------------------
Basic loss per ordinary share (US cents) 10
-------------------------------------------- ----- ------------------ ------------------
From continuing operations (0.19) (0.29)
-------------------------------------------- ----- ------------------ ------------------
From discontinued operations (0.31) -
-------------------------------------------- ----- ------------------ ------------------
Total loss per share (0.5) (0.29)
-------------------------------------------- ----- ------------------ ------------------
Diluted loss per ordinary share (US
cents) 10
-------------------------------------------- ----- ------------------ ------------------
From continuing operations (0.19) (0.29)
-------------------------------------------- ----- ------------------ ------------------
From discontinued operations (0.31) -
-------------------------------------------- ----- ------------------ ------------------
Total loss per share (0.5) (0.29)
-------------------------------------------- ----- ------------------ ------------------
Consolidated Statement of Comprehensive Income
Year ended Year ended
31 December 31 December
2018 2017
----------------------------------------------
US$000 US$000
---------------------------------------------- ------------- -------------
Loss after taxation (8,533) (4,694)
---------------------------------------------- ------------- -------------
Other comprehensive income:
Exchange differences on translating foreign
operations (10,136) 72
Recycling of exchange difference on disposal
of subsidiary 8,305 -
---------------------------------------------- ------------- -------------
Total comprehensive loss for the year (10,364) (4,622)
---------------------------------------------- ------------- -------------
Total comprehensive loss attributable to:
Owners of parent (9,277) (3,922)
Non-controlling interest (1,087) (700)
---------------------------------------------- ------------- -------------
Consolidated Statement of Changes in Equity
Share Share Deferred Cumulative Other Retained Total Non-controlling Total
capital premium shares translation reserves deficit attributable interests equity
US$'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
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
--------------- ------- ------- -------- ----------- -------- --------- ------------ --------------- --------
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
2017 16,000 146,728 64,702 (55,006) (583) (127,343) 44,498 2,617 47,115
----------------- ------- ------- -------- ----------- -------- --------- ------------ --------------- -------
Loss after
taxation - - - - - (3,928) (3,928) (766) (4,694)
Exchange
differences on
translating
foreign
operations - - - 6 - - 6 66 72
----------------- ------- ------- -------- ----------- -------- --------- ------------ --------------- -------
Total
comprehensive
income/(loss)
for the year - - - 6 - (3,928) (3,922) (700) (4,622)
----------------- ------- ------- -------- ----------- -------- --------- ------------ --------------- -------
Purchase of
non-controlling
interest in
subsidiary 8,364 73,183 - - - (81,861) (314) (6,571) (6,885)
Arising on
employee share
options - - - - 476 476 - 476
Lapsed warrants - - - - (1,779) 1,779 - - -
Debts converted
to equity 1,037 9,063 - - - - 10,100 - 10,100
Total equity as
at 31 December
2017 25,401 228,974 64,702 (55,000) (2,362) (210,877) 50,838 (4,654) 46,184
----------------- ------- ------- -------- ----------- -------- --------- ------------ --------------- -------
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 reserves Retained Total attributable
capital premium shares US$'000 deficit to the owner
US$'000 US$'000 US$'000 US$'000 of the Parent
US$'000
Total equity as at 1 January 2018 25,401 228,974 64,702 14,936 (144,073) 189,940
--------------------------------------- -------- -------- -------- -------------- --------- ------------------
Total comprehensive loss for the year - - - - (851) (851)
Stock options exercised 15 46 - - 61
Arising on employee share options - - - - 13 13
Total equity as at 31 December 2018 25,416 229,020 64,702 14,936 (144,911) 189,163
--------------------------------------- -------- -------- -------- -------------- --------- ------------------
Total equity as at 1 January 2017 16,000 146,728 64,702 16,715 (143,775) 100,370
----------------------------------------- ------ ------- ------ ------- --------- -------
Total comprehensive loss for the year - - - - (2,553) (2,553)
Purchase of non-controlling interest in
subsidiary 8,364 73,183 - - - 81,547
Arising on employee share options - - - - 476 476
Forfeited warrants - - - (1,779) 1,779 -
Debts converted to equity 1,037 9,063 - - - 10,100
Total equity as at 31 December 2017 25,401 228,974 64,702 14,936 (144,073) 189,940
----------------------------------------- ------ ------- ------ ------- --------- -------
Equity Description and purpose
Share capital The nominal value of shares issued
Share premium Amount subscribed for share capital in excess of
nominal value
Deferred shares The nominal value of deferred shares issued
Other reserves Fair value of warrants issued and capital
contribution arising on discounted loans
Retained deficit Cumulative losses recognised in the profit or
loss
Consolidated Statement of Financial Position
Company number 5966431 Notes Group Group
2018 2017
US$'000 US$'000
------------------------------------------ ----- --------- ---------
Assets
Non-current assets
Unproven oil and gas assets 11 55,685 69,701
Property, plant and equipment 12 87 165
Inventories 14 132 21
Other receivables 15 8,445 9,255
Restricted use cash 250 263
------------------------------------------ ----- --------- ---------
Total non-current assets 64,599 79,405
------------------------------------------ ----- --------- ---------
Current assets
Other receivables 15 364 832
Cash and cash equivalents 16 557 1,479
------------------------------------------ ----- --------- ---------
Total current assets 921 2,311
------------------------------------------ ----- --------- ---------
Total assets 65,520 81,716
------------------------------------------ ----- --------- ---------
Equity and liabilities
Capital and reserves attributable
to equity holders of the parent
Share capital 17 25,416 25,401
Share premium 229,020 228,974
Deferred shares 17 64,702 64,702
Other reserves (2,362) (2,362)
Retained deficit (219,230) (210,877)
Cumulative translation reserve (55,911) (55,000)
------------------------------------------ ----- --------- ---------
Equity attributable to the owners of the
Parent 41,635 50,838
------------------------------------------ ----- --------- ---------
Non-controlling interests 28 (5,605) (4,654)
------------------------------------------ ----- --------- ---------
Total equity 36,030 46,184
------------------------------------------ ----- --------- ---------
Current liabilities
Trade and other payables 18 6,259 9,538
Short - term borrowings 19 2,572 2,132
Current provisions 20 3,515 4,399
------------------------------------------ ----- --------- ---------
Total current liabilities 12,346 16,069
------------------------------------------ ----- --------- ---------
Non-current liabilities
Deferred tax liabilities 22 6,733 7,784
Non-current provisions 20 125 721
Other payables 18 10,286 10,958
------------------------------------------ ----- --------- ---------
Total non-current liabilities 17,144 19,463
------------------------------------------ ----- --------- ---------
Total liabilities 29,490 35,532
------------------------------------------ ----- --------- ---------
Total equity and liabilities 65,520 81,716
------------------------------------------ ----- --------- ---------
Approved by the Board and authorized for issue:
Clive Carver,
Chairman,
23 May 2019
Company number: 5966431
Parent Company Statement of Financial Position
Company number 5966431 Notes Company Company
2018 2017
US$'000 US$'000
------------------------------------------ ----- --------- ---------
Assets
Non-current assets
Investments in subsidiaries 13 211,986 211,658
Other receivables 15 3,066 2,944
Total non-current assets 215,052 214,602
------------------------------------------ ----- --------- ---------
Current assets
Other receivables 15 6 5
Cash and cash equivalents 16 292 17
------------------------------------------ ----- --------- ---------
Total current assets 298 22
------------------------------------------ ----- --------- ---------
Total assets 215,350 214,624
------------------------------------------ ----- --------- ---------
Equity and liabilities
Capital and reserves attributable
to equity holders of the parent
Share capital 17 25,416 25,401
Share premium 229,020 228,974
Deferred shares 17 64,702 64,702
Other reserves 14,936 14,936
Retained deficit (144,911) (144,073)
Equity attributable to the owners of the
Parent 189,163 189,940
------------------------------------------ ----- --------- ---------
Total equity 189,163 189,940
------------------------------------------ ----- --------- ---------
Current liabilities
Short - term borrowings 19 400 -
Trade and other payables 18 9,052 8,626
Total current liabilities 9,452 8,626
------------------------------------------ ----- --------- ---------
Non-current liabilities
Other payables 18 16,735 16,058
------------------------------------------ ----- --------- ---------
Total non-current liabilities 16,735 16,058
------------------------------------------ ----- --------- ---------
Total liabilities 26,187 24,684
------------------------------------------ ----- --------- ---------
Total equity and liabilities 215,350 214,624
------------------------------------------ ----- --------- ---------
The Company incurred a loss for the year ended 31 December 2018
in the amount of US$ 851,000 (2017: US$ 2,553,000).
Approved by the Board and authorized for issue:
Clive Carver,
Chairman,
23 May 2019
Company number: 5966431
Consolidated and Parent Company Statements of Cash Flows
Group Group Company Company
2018 2017 2018 2017
Notes US$'000 US$'000 US$'000 US$'000
-------- -------- -------- --------
Cash flows from operating activities
Cash received from customers 9,025 10,928 - -
Return of taxes previously paid 9 1,013 - 1,013 -
Payments made to suppliers for
goods and services (2,747) (1,319) (1,175) (872)
Payments made to employees (1,185) (1,548) (614) (692)
---------------------------------------- ----- -------- -------- -------- --------
Net cash flow from operating
activities 6,106 8,061 (776) (1,564)
---------------------------------------- ----- -------- -------- -------- --------
Cash flows from investing activities
Purchase of property, plant
and equipment 12 (3) (5) - -
Additions to unproven oil and
gas assets 11 (7,733) (9,973) - -
Transfers from/(to) restricted
use cash - (20) - -
Proceeds from disposal of joint
venture (net of cash disposed
and taxation) in prior periods - 1,696 - 1,696
Proceeds from disposal of subsidiaries 21 134 - - -
Advances repaid by subsidiaries - - 180 410
Advances issued to subsidiaries - - (100) (535)
Net cash flow from investing
activities (7,602) (8,302) 80 1,571
---------------------------------------- ----- -------- -------- -------- --------
Cash flows from financing activities
Net proceeds from issue of ordinary
share capital 61 - 61 -
Loans repaid 19,25 (534) (7,000) - -
Loans provided by subsidiaries - - 600 -
Loans received 19,25 1,047 8,315 400 -
Repayment of loans provided
by subsidiaries - - (90) -
Net cash flow from financing
activities 574 1,315 971 -
---------------------------------------- ----- -------- -------- -------- --------
Net increase/(decrease) in cash
and cash equivalents (922) 1,074 275 7
Cash and cash equivalents at
the beginning of the year 1,479 405 17 10
---------------------------------------- ----- -------- -------- -------- --------
Cash and cash equivalents at
the end of the year 16 557 1,479 292 17
---------------------------------------- ----- -------- -------- -------- --------
Significant non-cash transactions include the following and
details can be found in notes 6, 7, 8, 9,12, 17, 27:
- Share-based payments in the amount of US$ 13,000 (2017: US$ 476,000);
- Withholding tax in the amount of US$ 1,375,000 (2017: US$ 1,345,000);
- Discounting of receivables in the amount of US$ 0 (2017: US$100,000);
- Exchange differences on translating foreign operations of US$ 3,154,000 (2017: US$ 72,000);
- Depreciation charge of US$ 31,000 (2017: US$ 43,000);
- Conversion of debt to equity of US$ 0 (2017: US$ 10,100,000);
- Interest expense of US$ 348,000 (2017: US$ 167,000);
- Conversion of Loan provided to Baverstock to investments in
Eragon in the amount of US$ 0 (2017: US$ 3,254,000);
- Conversion of Receivable from Baverstock due to royalty to
investments in Eragon in the amount of US$ 0 (2017: US$
3,202,000);
- Non-cash effect from the acquisition of non-controlling
interest in the amount of US $ 0 (2017: US$ 6,885,000)
* Additions to unproven oil and gas assets contain the amount of
US$ 332,000 in relation to payroll expenses capitalized (2017: US$:
330,000).
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 23 May 2019.
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 Directors have prepared cash flow forecasts for the next 12
months which demonstrate that the Group will have sufficient funds
to meet its day to day liabilities, including all expected G&A
expenditure, as they fall due and operate as a going concern,
including completion of its planned shallow structure drilling
program.
The forecasts include growth in revenue including both the
impact of anticipated shallow structure well drilling and increased
pricing associated with BNG production sold at world prices
following the planned conversion of existing wells into a
production licence.
In addition, the Group continues to forward sell its production
and receive advances from oil traders as part of its operations.
The continued availability of such arrangements are important to
working capital and, in the event the Group was unable to continue
to access these arrangements additional funding would be
required.
The Directors are confident that the oil trader funding will
continue, based on the production profile and relationships with
the oil traders.
Whether or not the award of a production licence is further
delayed, the Group expects to require additional working capital
during the period. The Board are confident such funding would be
available from in the first instance additional advances from oil
traders and should that be insufficient further support would be
provided by our CEO, Kuat Oraziman.
In this regard Mr Oraziman has provided a written undertaking to
provide financial support as is required which the Board are
satisfied will be available given the history of financial support
and having considered the shareholder's ability to provide such
funding.
Additional funding, for new deep wells, infrastructure and
assets to accelerate development over and above the level included
in the forecasts, is expected to be available from a number of
sources, including debt funding for much of the infrastructure
spending, 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, such accelerated development is at the Group's
discretion.
On this basis the Directors have therefore concluded that it is
appropriate to prepare the financial statements on a going concern
basis.
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$851,000 (2017: US$
2,553,000) 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 following new standards and amendments to standards are
mandatory for the first time for the Group for financial year
beginning 1 January 2018. The implementation of these standards did
not have a material effect on the Group results, although they
resulted in certain amendments to disclosures.
1.2 New and revised standards and interpretations applied (continued)
Standard Description Effective date
--------- -------------------------------- ---------------
IFRS 9 Financial Instruments 1 Jan 2018
IFRS 15 Revenue from Contracts with 1 Jan 2018
Customers
IFRS 2 Amendment - Classification 1 Jan 2018
and measurement of share based
payment transactions
IFRIC 22 Foreign currency transactions 1 Jan 2018
and advance considerations
IFRS 9 'Financial instruments' addresses the classification and
measurement of financial assets and financial liabilities and
replaces the guidance in IAS 39 that relates to the classification
and measurement of financial instruments. IFRS 9 retains but
simplifies the mixed measurement model and establishes three
primary measurement categories for financial assets: amortised
cost, fair value through other comprehensive income (OCI) and fair
value through profit or loss. The basis of classification depends
on the entity's business model and the contractual cash flow
characteristics of the financial asset. There is now a new expected
credit loss model that replaces the incurred loss impairment model
used in IAS 39. It is noted that VAT receivables and prepayments
are excluded from the scope of IFRS 9. The Group has applied the
modified retrospective approach to transition. The adoption of IFRS
9 did not result in any material change to the consolidated results
of the Group or Parent Company. Following assessment of the
financial assets no changes to classification of those financial
assets was required. The Group has applied the expected credit loss
impairment model to its financial assets and has not recognised any
expected credit loss impairment (note 15). The Company has
recognised $286,000 expected credit loss impairment in relation to
inter-company receivables from subsidiaries (note 15).
IFRS 15 introduced a single framework for revenue recognition
and clarify principles of revenue recognition. This standard
modifies the determination of when to recognise revenue and how
much revenue to recognise. The core principle is that an entity
recognises revenue to depict the transfer of promised goods and
services to the customer of an amount that reflects the
consideration to which the entity expects to be entitled in
exchange for those goods or services. The adoption of IFRS 15 did
not result in any material change to the Group's revenue
recognition following analysis of its contracts. Revenue was
previously recorded on oil sale at the fair value of consideration
received or receivable, net of VAT and sales related taxes at the
point title transferred when significant risks and rewards had
passed to the customer. Using the 5-step method set out in IFRS 15
there was no change required to the revenue recognition reflecting
the simple nature of the arrangements.
Refer to note 1.19 for the Group's revenue recognition policy
and note 3 for details of revenue.
Annual Improvements to IFRSs 2014-2016
Standards, amendments and interpretations, which are effective
for reporting periods beginning after the date of this financial
information which have not been adopted early:
Standard Description Effective date
---------------------- ------------------------------- ---------------
IFRS 16 Leases 1 Jan 2019
IFRS 17 Insurance contracts 1 Jan 2021
IFRIC Interpretation Uncertainty over Income 1 Jan 2019
23 Tax Treatments
1 Jan 2019
Amendments to IFRS Prepayment Features with
9 Negative Compensation
Unknown
Sale or Contribution of
Amendments to IFRS Assets between an Investor
10 and IAS 28 and its Associate 1 Jan 2019
Plan Amendment, Curtailment 1 Jan 2019
Amendments to IAS or Settlement
19
Long-term interests in
associates and joint ventures
Amendments to IAS
28
The Management is currently assessing the impact of IFRS 16 as
whilst there are no material operating leases in the Group it may
be relevant to future operations including service agreements
containing the use of assets.
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, 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 recognized 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.
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.
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.
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.
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. Subsequently loan is accreted up using effective
interest, unless loan is considered credit impaired, while interest
is recorded on unimpaired amount. 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, amounts advances
to subsidiaries 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 recognized 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.
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
During test production 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 1.27 and the average rate during the year was 1.33. The
year-end exchange rate from KZT to US$ was 384.2 and the average
rate during the year was 344.7.
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 Recoverability of exploration and evaluation costs
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 2018, the Group assessed the exploration and evaluation
assets disclosed in note 11 and determined that no indicators of
impairment existed at a cost pool level in respect of the BNG cost
pool. In forming this assessment, the Board considered the results
of the Competent Person report, the economic models associated with
the shallow wells, 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 20.
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 Classification of BNG as an unproven oil and gas asset
The costs capitalised in respect of the BNG contract area are
recorded within unproven oil and gas assets. Judgment has been
applied in assessing whether the asset meets the criteria for
reclassification to proven oil and gas assets under the Group's
accounting policy in note 1.8 given the increased production
volumes and reserves. The Board considers the 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 oil in the domestic
market which represents a substantial discount to the international
market.
2.3 Recoverability of VAT
The Group holds VAT receivables of $3 million (2017:
$3.5million) as detailed in note 15 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 (2017: 3.5 years) . This required estimates
regarding future production, oil prices and expenditure.
2.4 Decommissioning
Provision has been made in the accounts for future
decommissioning costs to plug and abandon wells in note 20. 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 Share-based compensation
In order to calculate the charge for share-based compensation as
required by IFRS 2, the Group makes estimates principally relating
to the assumptions used in its option-pricing model.
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 production are generated domestically in Kazakhstan. 86%
of the Group's revenue was derived from one major customer.
Revenue
The Group's revenues are derived from the sale of oil in
Kazakhstan. The Group usually receives advances for future
production. Under the terms of sale, 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. When advances 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. The level of forward
production sales in the year ranged from 3 to 6 months (2017: 6 to
9 months. The performance obligations in respect of such sales
remain outstanding at year end. No trade receivables or accrued
income was applicable at year end (2017: $Nil).
4 Operating loss
Group operating loss for the year has been arrived after charging:
-------------------------------------------------------------------------
Group Group
2018 2017
US$'000 US$'000
---------------------------------------------------- --------- --------
Depreciation of property, plant and equipment
(note 12) (31) (43)
Auditors' remuneration (note 5) (220) (319)
Staff costs (note 6) (1,319) (1,403)
Share based payment remuneration (note 6) (13) (476)
5 Group Auditor's remuneration
Fees payable by the Group to the Company's auditor BDO and its
member firms in respect of the year:
Group Group
2018 2017
US$'000 US$'000
--------------------------------------------- -------- --------
Fees for the audit of the annual financial
statements 95 99
Audit related services 11 11
Other services - tax related 88 180
--------------------------------------------- -------- --------
194 290
--------------------------------------------- -------- --------
Fees payable by the Group to Grant Thornton and its associates
in respect of the year:
Group Group
2018 2017
US$'000 US$'000
---------------------------------------------- -------- --------
Auditing of accounts of subsidiaries of the
Company 26 29
26 29
---------------------------------------------- -------- --------
6 Employees and Directors
Staff costs during the year Group Company Group Company
2018 2018 2017 2017
US$'000 US$'000 US$'000 US$'000
--------------------------------- --------- --------- -------- --------
Wages and salaries 1,319 782 1,403 794
Social security costs 108 32 135 32
Pension costs 73 - 90 -
Share-based payments 13 13 476 476
--------------------------------- --------- --------- -------- --------
1,513 827 2,104 1,302
--------------------------------- --------- --------- -------- --------
Payroll expenses were capitalized in the amount
of US$ 332,000 (2017: US$ 330,000).
Average monthly number of people Group Company Group Company
employed 2018 2018 2017 2017
(including executive Directors) US$'000 US$'000
---------------------------------- ----- -------- ----- --------
Technical 10 1 13 2
Field operations 47 - 53 -
Finance 9 2 10 2
Administrative and support 14 2 19 2
---------------------------------- ----- -------- ----- --------
80 5 95 6
---------------------------------- ----- -------- ----- --------
Directors' remuneration Group Group
2018 2017
US$'000 US$'000
-------------------------- -------- --------
Director's emoluments 540 524
Share-based payments - 333
-------------------------- -------- --------
540 857
-------------------------- -------- --------
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$336,140 (2017:
US$240,000).
7 Finance cost
Group Group
2018 2017
US$'000 US$'000
------------------------------------------ -------- --------
Loan interest payable 337 165
Unwinding of discount on provisions (note
20) 11 2
------------------------------------------ -------- --------
348 167
------------------------------------------ -------- --------
8 Finance income
Group Group
2018 2017
US$'000 US$'000
----------------------------------------------- -------- --------
Unwinding of discount of loan receivable from
Baverstock - 100
Finance income related to the late receipt
of receivable under SPA - 94
----------------------------------------------- -------- --------
- 194
----------------------------------------------- -------- --------
9 Taxation
Analysis of charge for the year Group Group
2018 2017
US$'000 US$'000
--------------------------------- -------- --------
Current tax charge 414 1,345
Deferred tax charge - -
414 1,345
--------------------------------- -------- --------
Group Group
2018 2017
US$'000 US$'000
------------------------------------------------------ -------- --------
Loss before tax (2,972) (3,349)
------------------------------------------------------ -------- --------
Tax on the above at the standard rate of corporate
income tax in the UK 19% (2017: 19.25%) (565) (645)
Effects of:
Non-deductible expenses 23 545
Return of prior year CIT payment* (1,013) -
Withholding tax on interest expense 1,375 1,345
Utilization of tax losses not previously recognized (2,882) -
Unrecognised tax losses carried forward 3,476 100
414 1,345
------------------------------------------------------ -------- --------
* 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 have been approved by HMRC and related tax payment from
HMRC has been received by the Company during August 2018.
10 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:
2018 2017
------------------------------------------------------ ------------- -------------
The basic weighted average number of ordinary
shares in
issue during the year 1,669,706,698 1,362,172,379
The loss for the year attributable to owners
of the parent from continuing operations (US$'000) (3,219) (3,928)
The loss for the year attributable to owners
of the parent from discontinued operations
(US$'000) (5,147) -
------------------------------------------------------ ------------- -------------
There were 7,200,000 potentially dilutive instruments in the
year (2017: 8,400,000).
11 Unproven oil and gas assets
COST Group
US$'000
------------------------------ ---------
Cost at 1 January 2017 83,223
------------------------------ ---------
Additions 9,158
Sales from test production (7,535)
Foreign exchange difference (10)
------------------------------ ---------
Cost at 31 December 2017 84,836
------------------------------ ---------
Additions 7,479
Sales from test production (10,747)
Foreign exchange difference (13,082)
------------------------------ ---------
Cost at 31 December 2018 68,486
------------------------------ ---------
ACCUMULATED IMPAIRMENT Group
US$'000
--------------------------------------------- --------
Accumulated impairment at 1 January 2017 15,137
--------------------------------------------- --------
Foreign exchange difference (2)
--------------------------------------------- --------
Accumulated impairment at 31 December 2017 15,135
--------------------------------------------- --------
Foreign exchange difference (2,334)
Accumulated impairment at 31 December 2018 12,801
--------------------------------------------- --------
Net book value at 1 January 2017 68,086
Net book value at 31 December 2017 69,701
Net book value at 31 December 2018 55,685
--------------------------------------------- --------
Unproven oil and gas assets represent license acquisition costs
and subsequent exploration expenditure in respect of two licenses
held by Kazakh group entities. The carrying values of those assets
at 31 December 2018 were as follows: Beibars Munai LLP US$ nil
(2017: US$ nil) and BNG Ltd LLP US$55,685,000 (2017:
US$69,701,000).
The Directors have carried out an impairment review of these
assets on a cost pool level as detailed in note 2.1. No impairment
indicators were identified for BNG Ltd LLP.
As a result of military training activities, the Group currently
cannot access the Beibars license area which resulted in a
force-majeure situation and the Group is in the process of
relinquishing its interest in the asset and handing it back to the
Kazakh authorities. Due to this ongoing position the carrying value
remains fully impaired.
12 Property, plant and equipment
Following the commencement of commercial production in December
2012 the Group reclassified its Munaily assets from unproven oil
and gas assets to proven oil and gas assets. The assets were
impaired in 2013. During 2018 the Group has disposed it Munaily
assets (note 21).
Proved Motor Other Total
-----------------------------
oil and Vehicles
gas assets
Group US$'000 US$'000 US$'000 US$'000
----------------------------- --------------------- --------- -------- --------
Cost at 1 January 2017 47 153 328 528
Additions - - 5 5
Disposals - - (21) (21)
Foreign exchange difference - - 1 1
----------------------------- --------------------- --------- -------- --------
Cost at 31 December 2017 47 153 313 513
----------------------------- --------------------- --------- -------- --------
Additions - - 3 3
Disposals (47) (85) (8) (140)
Foreign exchange difference - (12) (42) (54)
----------------------------- --------------------- --------- -------- --------
Cost at 31 December 2018 - 56 266 322
----------------------------- --------------------- --------- -------- --------
Depreciation at 1 January
2017 47 67 191 305
Charge for the year - 13 30 43
Foreign exchange difference - - - -
----------------------------- --------------------- --------- -------- --------
Depreciation at 31 December
2017 47 80 221 348
----------------------------- --------------------- --------- -------- --------
Charge for the year - 9 22 31
Disposals (47) (51) (8) (106)
Foreign exchange difference - (6) (32) (38)
----------------------------- --------------------- --------- -------- --------
Depreciation at 31 December
2018 - 32 203 235
----------------------------- --------------------- --------- -------- --------
Net book value at:
----------------------------- --------------------- --------- -------- --------
01 January 2017 - 86 137 223
----------------------------- --------------------- --------- -------- --------
31 December 2017 - 73 92 165
----------------------------- --------------------- --------- -------- --------
31 December 2018 - 24 63 87
----------------------------- --------------------- --------- -------- --------
13 Investments (Company)
Investments Company
US$'000
------------------------------------------------- --------
Cost
At 1 January 2017 190,595
Acquisition of Eragon non-controlling interest
(note 27) 85,179
Receipts (398)
Payments 535
-------------------------------------------------- --------
At 31 December 2017 275,911
-------------------------------------------------- --------
Receipts 534
Payments (206)
-------------------------------------------------- --------
At 31 December 2018 276,239
-------------------------------------------------- --------
Impairment
At 1 January 2017 64,253
Impairment -
At 31 December 2017 64,253
-------------------------------------------------- --------
Impairment -
At 31 December 2018 64,253
-------------------------------------------------- --------
Net book value at:
------------------------------------------------- --------
31 December 2017 211,658
31 December 2018 211,986
-------------------------------------------------- --------
The carrying value of the investments has been assessed by the
Directors including consideration of the underlying BNG contract
area progress and the implied values of BNG based on the Baverstock
merger occurred in 2017.
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
2018 2017
----------------------------- --------------- --------------- --------------- ----------------- ------------
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
13 Investments
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
2018 2017
----------------------- --------------- --------------- --------------- -------------------- --------------
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., Exploration
BNG Ltd LLP Kazakhstan 99% 99% Almaty, Kazakhstan Company
152/140 Karasay
Munaily Kazakhstan Batyr Str., Oil Production
LLP Kazakhstan 0% 99% Almaty, Kazakhstan Company
During 2018 the Group sold its share in Munaily Kazakhstan LLP
for $134,000 (note 21).
Indirect investments held by Beibars BV
Name of undertaking Country of Effective Effective Registered Nature
incorporation holding and holding and address of business
proportion proportion
of voting of voting
rights held rights held
at 31 December at 31 December
2018 2017
-------------------- --------------- --------------- --------------- ------------------- ------------
152/140 Karasay
Batyr Str., Exploration
Beibars Munai LLP Kazakhstan 50% 50% Almaty, Kazakhstan Company
Beibars Munai LLP is a subsidiary as the Group is considered to
have control over the financial and operating policies of this
entity. Its results have been consolidated within the Group.
14 Inventories
Group Group
2018 2017
US$'000 US$'000
------------------------- ------- -------
Materials and supplies 132 21
------------------------- ------- -------
132 21
------------------------- ------- -------
15 Other receivables
Group Group Company Company
2018 2017 2018 2017
US$ '000 US$ '000 US$ '000 US$'000
----------------------------- -------- -------- -------- -------
Amounts falling due after
one year:
Prepayments made 5,516 5,799 54 98
VAT receivable 2,929 3,456 - -
Intercompany receivables - - 3,012 2,846
8,445 9,255 3,066 2,944
----------------------------- -------- -------- -------- -------
Amounts falling due within
one year:
Prepayments made 119 227 6 5
Other receivables 245 605 - -
----------------------------- -------- -------- -------- -------
364 832 6 5
----------------------------- -------- -------- -------- -------
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 and, after the
commencement of oil production and its export from Kazakhstan,
through cash refunds in accordance with Kazakh tax legislation.
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$12.2 million (2017: US$34.2 million). The movement in the
expected credit loss provision related to the inter-company
receivables was as follows:
Group Group Company Company
2018 2017 2018 2017
Denomination US$'000 US$'000 US$'000 US$'000
------------------ ------- ------- -------- -------
As at 1 January - - 34,232 33,310
Charge - - 286 922
Write-off* - - (22,306) -
As at 31 December - - 12,212 34,232
------------------ ------- ------- -------- -------
*During 2018 the Company wrote off its fully impaired Munaily
receivables following the sale of Munaily (note 21) and wroteoff of
its fully impaired Roxi Petroleum Kazakhstan receivables.
The Company recognised US$ 286 thousand of expected credit loss
provisions in relation to it receivables from subsidiaries in 2018
(2017: US$ 922 thousand).
16 Cash and cash equivalents
Group Group Company Company
2018 2017 2018 2017
US$'000 US$'000 US$'000 US$'000
--------------------------------- --------- --------- -------- --------
Cash at bank and in hand 557 1,479 292 17
--------------------------------- --------- --------- -------- --------
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
2018 2017 2018 2017
Denomination US$'000 US$'000 US$'000 US$'000
--------------- ------- ------- ------- -------
US Dollar 448 1,221 232 11
Sterling 60 6 60 6
Kazakh Tenge 49 252 - -
557 1,479 292 17
--------------- ------- ------- ------- -------
17 Called up share capital
Group and Company
Number Number
of ordinary of deferred
shares US$'000 shares US$'000
---------------------------------------- ------------- --------- ------------ ---------
Balance at 1 January 2017 937,433,077 16,000 373,317,105 64,702
Acquisition of Eragon non-controlling
interest (note 27) 651,436,544 8,364 - -
Debts converted to equity 80,804,199 1,037 - -
Balance at 31 December 2017 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
---------------------------------------- ------------- --------- ------------ ---------
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.
18 Trade and other payables - current
Group Group Company Company
2018 2017 2018 2017
US$'000 US$'000 US$'000 US$'000
------------------------------- ------- ------- ------- -------
Trade payables 861 1,220 221 380
Taxation and social security 180 175 21 38
Accruals 197 225 165 195
Other payables 2,235 2,120 413 318
Intercompany payables - - 8,232 7,695
Advances received (deferred
revenue) 2,786 5,798 - -
6,259 9,538 9,052 8,626
------------------------------- ------- ------- ------- -------
As at 31 December 2018 and 31 December 2017, 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: $10.7 (2017: $7.5m). Excess of revenue recognised over
cash being recognised during the period is $3m (2017: excess of
cash recognized over the revenue is $3.4m).
Other payables relate to the original purchase of Munaily oil
field.
18 Trade and other payables - non-current
Group Group Company Company
2018 2017 2018 2017
US$'000 US$'000 US$'000 US$'000
------------------------------- ------- ------- ------- -------
Intercompany payables - - 16,735 16,058
Taxation and social security 10,286 10,958 - -
------------------------------- ------- ------- ------- -------
10,286 10,958 16,735 16,058
------------------------------- ------- ------- ------- -------
Taxation and social security payable relate to withholding tax
accrued on the interest expense at the BNG subsidiary level.
19 Short-term borrowings
Group Group Company Company
2018 2017 2018 2017
US$'000 US$'000 US$'000 US$'000
Prosperity/Mr Oraziman (a) 913 1,196 - -
Fosco BV (b) 650 639 - -
Other borrowings (c) 1,009 297 400 -
----------------------------- ------- ------- ------- -------
2,572 2,132 400 -
----------------------------- ------- ------- ------- -------
a) During December 2017 Eragon Petroleum FZE (a subsidiary of
the Company) received a US $1.2 million loan from KC Caspian
Explorer (KCCE), a 100% subsidiary of Prosperity Petroleum Ltd
("PPL") under a loan provided by PPL. PPL is a company controlled
by Mr Kuat Oraziman and therefore a related party of the Group. The
loan is interest free and matured in December 2018. During 2018 the
Group has partially repaid the loan. On 21 December 2018 the loan
was extended till 31 December 2019. On 23 December 2018 Eragon
Petroleum FZE has assigned the loan to Mr Oraziman making it
interest bearing with the rate of 7%. The loan extension represents
a substantial modification of the terms of the existing financial
liability and has been accounted for as an extinguishment of the
original financial liability and recognition of a new financial
liability.
b) During July 2016 Fosco BV, a company controlled by Mr
Oraziman, therefore a related party of the Group, provided an on
demand loan to BNG LLP in the amount of US$ 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 2018
US$1,009,000 (2017: US$297,000) was payable to Kuat Oraziman and a
legal entity controlled by Mr Oraziman, KC Caspian Explorer. Loans
are interest free and repayable on demand.
20 Provisions
Group only Employee Liabilities Abandonment 2017
holiday under Social fund Total
provision Development
Program
and historical
cost
----------------------------- ----------- ---------------- ------------ --------
US$'000 US$'000 US$'000 US$'000
----------------------------- ----------- ---------------- ------------ --------
Balance at 1 January 2017 68 4,150 153 4,371
Increase in provision 25 700 39 764
Paid in the year - (19) (6) (25)
Unwinding of discount - - 2 2
Foreign exchange difference - 2 6 8
----------------------------- ----------- ---------------- ------------ --------
Balance at 31 December
2017 93 4,833 194 5,120
----------------------------- ----------- ---------------- ------------ --------
Non-current provisions - 527 194 721
Current provisions 93 4,306 - 4,399
----------------------------- ----------- ---------------- ------------ --------
Balance at 31 December
2017 93 4,833 194 5,120
----------------------------- ----------- ---------------- ------------ --------
Group only Employee Liabilities Abandonment 2018
holiday under Social fund Total
provision Development
Program
and historical
cost
----------------------------- ----------- ---------------- ------------ --------
US$'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 21) (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
----------------------------- ----------- ---------------- ------------ --------
Liabilities and commitments in relation to Subsoil Use Contracts
are 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) Munaily Kazakhstan LLP
Munaily Kazakhstan LLP, a subsidiary, signed a contract # 1646
dated 31 January 2005 with the Ministry of Energy and Mineral
Resources of RK (now the Ministry of Oil and Gas (MOG) for the
exploration and extraction of hydrocarbons on Munaily deposit
located in the Atyrau region.
The contract is valid for 25 years. On 13 July 2011 Munaily
Kazakhstan LLP and a competent authority signed Addendum No. 5 to
the Subsoil Use Contract (SSUC), which stipulates the oil
production period to be 15 years to 2025 and approves the minimum
work program for the production period.
During 2018 the Group decided to dispose its Munaily asset. The
transaction was finalized on December 20, 2018 (note 21)
c) 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 has 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$313,000 per annum should
be invested in the social development of the region starting from
January 2019;
-- To fund minimum cumulative work program during the appraisal period of US$ 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.
21 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
$'000
----------------------------------------- ----------------------------
Total consideration 134
----------------------------------------- ------
Non-current assets (58)
Trade and other receivables (14)
Trade and other payables 350
Non-current liabilities 2,882
----------------------------------------- ------ --------------------
Net liabilities at date of disposal 3,160
----------------------------------------- ----------------------------
Less: minority share 136
Gain on disposal before the effect
of cumulative translation reserve 3,158
----------------------------------------- ------
Less: Release of cumulative translation
reserve 8,305
--------------------
Loss on disposal 5,147
----------------------------------------- ----------------------------
The net cash inflow on disposal
comprises:
----------------------------------------- ----------------------------
Cash received 134
Cash disposed of -
----------------------------------------- ----------------------------
Net cash inflow 134
----------------------------------------- ----------------------------
Munaily Kazakhstan LLP had the following results during 2018 and
2017:
2018 2017
-----------------------
US$'000 US$'000
----------------------- ------- -------
Revenue - 16
Expenses (334) (614)
Loss before taxation (334) (598)
------------------------ ------- -------
Cash movements related to Munaily were negligible.
22 Deferred tax
Deferred tax liabilities comprise:
Group Group
2018 2017
---------------------------------------------
US$'000 US$'000
--------------------------------------------- ------- -------
Deferred tax on exploration and evaluation
assets acquired 6,733 7,784
---------------------------------------------- ------- -------
6,733 7,784
--------------------------------------------- ------- -------
The Group recognises deferred taxation on fair value uplifts to
its oil and gas projects arising on acquisition. These liabilities
reverse as the fair value uplifts are depleted or impaired.
The movement on deferred tax liabilities was as follows:
Group Group
2017 2017
US$'000 US$'000
--------------------------- ------- -------
At beginning of the year 7,784 7,748
Foreign exchange (1,051) 36
6,733 7,784
--------------------------- ------- -------
As at 31 December 2018 the Group has accumulated deductible tax
expenditure related to BNG expenditure of approximately US$97
million available to carry forward and offset against future
profits. This represents an unrecognised deferred tax asset of
approximately 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$5.1m. This asset is fully impaired and there
is insufficient certainty of future profitability to utilise these
deductions.
23 Share option 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
2017 88,458,226 (45,566,215) (9,900,000) 32,992,011 17
----------------------- ------------------ ---------------- ----------------- ------------- ----------
Directors - (2,404,615) (1,200,000) (3,604,615) -
Employees and others - (6,840,000) - (6,840,000) -
----------------------- ------------------ ---------------- ----------------- ------------- ----------
As at 31 December
2018 88,458,226 (54,810,830) (11,100,000) 22,547,396 13
----------------------- ------------------ ---------------- ----------------- ------------- ----------
The options were issued to Directors and employees as
follows:
21,797,396 outstanding options as at 31 December 2018 are
exercisable.
The range of exercise prices of share options outstanding at the
year end is 4p - 20p (2017: 4p - 65p). The weighted average
remaining contractual life of share options outstanding at the end
of the year is 3.8 years (2017: 4.4 years).
24 Warrants
Equity - warrants
The Company had 7.5 million warrants valid until 21 May 2017
that were recognised in equity (other reserves) in the amount of
US$1,779 thousand. During 2017 the warrants expired therefore the
Company reclassified the amount to Retained deficit.
25 Financial instrument risk exposure and management
In common with all other businesses, the Group and Company are
exposed to risks that arise from its use of financial instruments.
This note describes the Group and Company's objectives, policies
and processes for managing those risks and the methods used to
measure them. Further quantitative information in respect of these
risks is presented throughout these financial statements.
The significant accounting policies regarding financial
instruments are disclosed in note 1.
There have been no substantive changes in the Group or Company's
exposure to financial instrument risks, its objectives, policies
and processes for managing those risks or the methods used to
measure them from previous years unless otherwise stated in this
note.
Principal financial instruments
The principle financial instruments used by the Group and
Company, from which financial instrument risk arises, are as
follows:
Group Group Company Company
Financial assets 2018 2017 2018 2017
US$'000 US$'000 US$'000 US$'000
------------------------------ --------- --------- --------- ---------
Intercompany receivables - - 3,012 2,846
Other receivables 245 605 -
Restricted use cash 250 263 - -
Cash and cash equivalents 557 1,479 292 17
------------------------------ --------- --------- --------- ---------
1,052 2,347 3,304 2,863
------------------------------ --------- --------- --------- ---------
Financial liabilities Group Group Company Company
2018 2017 2018 2017
US$'000 US$'000 US$'000 US$'000
------------------------------ --------- --------- --------- ---------
Trade and other payables 3,293 3,565 799 893
Other payables - current - - 8,232 7,695
Other payables - non-current - - 16,735 16,058
Borrowings - current 2,572 2,132 400 -
5,865 5,697 26,166 24,646
------------------------------ --------- --------- --------- ---------
Changes in liabilities arising from financial activities
Below is the movement of financial liabilities of the Group for
the years ended 31 December 2018 and 2017:
Disposal Foreig exchange
1 January Loans Interest of loans difference, 31 December
2018 received accrued (note 21) Repayment net 2018
--------------- ---------- ---------- --------- ------------ ---------- ---------------- ------------
Financial
liabilities
Borrowings 2,132 1,047 337 (326) (534) (84) 2,572
Foreig
Conversion exchange
1 January Loans Interest to equity difference, 31 December
2017 received accrued Repayment net 2017
-------------- ---------- ---------- --------- ------------- ---------- -------------- ------------
Financial
liabilities
Borrowings 10,744 8,315 165 (10,100) (7,000) 8 2,132
Below is the movement of financial liabilities of the Company
for the years ended 31 December 2018 and 2017:
Foreig exchange
1 January Loans Interest Disposal difference, 31 December
2018 received accrued of loans Repayment net 2018
--------------- ----------- ---------- --------- ----------- ---------- ---------------- ------------
Financial
liabilities
Borrowings - 400 - - - - 400
Foreig
Conversion exchange
1 January Loans Interest to equity difference, 31 December
2017 received accrued Repayment net 2017
-------------- ---------- ---------- --------- ------------- ---------- -------------- ------------
Financial
liabilities
Borrowings 9,935 - 165 (10,100) - - -
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$ 1million (2017: US$ 2.3
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.
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 2018 was 6%
(2017:5%).
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
2018 and 2017 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 2018 US$'000 2,572 710 2,583 - - 5,865
Group 2017 US$'000 936 911 3,850 - - 5,697
Company 2018 US$'000 8,632 210 589 23,617 33,048
Company 2017 US$'000 7,695 359 534 - 23,617 32,205
---------------------- ---------- ------------------- ------------ ----------- ------------- -------
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$46 million (2017: US$51 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$46 million (2017: US$51 million).
26 Related party transactions
The Company has no ultimate controlling party.
26.1 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 19.
26.2 Baverstock acquisition
Before 1 June 2017 41% of Company's subsidiary Eragon Petroleum
ltd was owned by Baverstock GmbH and 59% by Caspian Sunrise
plc.
On 1 June 2017 Caspian Sunrise plc acquired an additional 41% in
its subsidiary Eragon Petroleum ltd. After that Company's interest
in BNG and Munaily increased from 58.41% to 99% and interest in
Eragon increased from 59% to 100% (note 27).
26.3 Key management remuneration
Key management comprises the Directors and details of their
remuneration are set out in note 6.
26.4 Purchases
As at year end the Group has prepayments made in the amount of
US$2.3 million (2017: US$2.6 million) and trade receivables in the
amount of US$80,000 (2017: US$92,000) in relation to STK Geo LLP,
the company registered in Kazakhstan, which is owned by a member of
Kuat Oraziman's family. The Group previously purchased drilling
services from STK GEO LLP. No purchases were made during 2018 and
2017. The Group expects that STK GEO LLP will provide drilling
services during 2019 and utilise the major part of the
advances.
During 2017 the Group had purchased drilling and workover
services from the related party KazSmartEnerKon LLP, a company
registered in Kazakhstan, which is owned by Kuat Oraziman, in the
amount of US$ 4.2 million (2017: US$4.6 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$2.9 million (2017:
US$2.8 million) in relation to these drilling service.
27 Acquisition of non-controlling interest
On 1 June 2017 Caspian Sunrise plc acquired an additional 41%
in its subsidiary Eragon Petroleum ltd in exchange of issuance
of 651,436,544 Company's shares and forgiveness of the debt due
from Baverstock fair valued at the level of US$6.5 million. As
part of the transaction the Company incurred acquisition related
costs in the amount of US$0.4 million. Following the transaction,
the Company's interest in BNG and Munaily increased from 58.41%
to 99% and interest in Eragon increased from 59% to 100%. The
related NCI share in net assets of Eragon at the date of acquisition
was equal to US$6.6 million. The difference between the purchase
consideration and net assets was charged directly to the consolidated
statement of changes in equity as the transaction represented
the acquisition of a non-controlling interest.
US$'000
--------------------------------------------------------- --------------
Carrying amount of NCI acquired 6,571
Consideration paid to NCI 88,432
---------------------------------------------------------- --------------
A decrease in equity attributable
to owners of the Company (81,861)
---------------------------------------------------------- --------------
28 Non-controlling interest
Group Group
2018 2017
---------------------------------------
US$'000 US$'000
--------------------------------------- ------- ---------
Balance at the beginning of the year (4,654) 2,617
Share of loss for the year (167) (766)
Exchange differences on translating
foreign operations and recycling on
disposal (920) 66
Purchase of non-controlling interest
in subsidiary (note 27) - (6,571)
Disposal of Munaily (note 21) 136 -
--------------------------------------- ------- ---------
(5,605) (4,654)
--------------------------------------- ------- ---------
As at 31 December 2018 non-controlling interest represents
minority share in BNG Ltd LLP and Beibars Munail LLP (as at 31
December 2017- BNG Ltd LLP, Beibars Munai LLP and Munaily
Kazakhstan LLP).
Notes to the Financial Statements
29 Events after the reporting period
3ABest Group
In January 2018, the Company announced the intention to acquire
100% of the shares of 3ABest 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 of $13 million is satisfied by the issue of
149,253,732 new Companies shares at the afreed price of 7p per
share.
[1] All Directors of Caspian Sunrise PLC not members of the
Oraziman family or others deemed under the AIM Rules to be
non-independent
[2] A commercial rate no better than a rate payable to an
independent third-party contractor
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 PGUMAAUPBGAW
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May 24, 2019 02:00 ET (06:00 GMT)
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