TIDMCAD
RNS Number : 2927C
Cadogan Petroleum PLC
30 April 2012
CADOGAN PETROLEUM PLC
Preliminary Results for the Year Ended 31 December 2011
_______________________________________________________________________________________
Cadogan Petroleum plc is an independent oil and gas exploration,
development and production company with onshore gas, condensate and
oil assets in Ukraine.
The Group has undergone significant management changes during
the year, including the appointment of Zev Furst as Chairman and
Bertrand Des Pallieres as Chief Executive Officer.
Other developments during 2011 included the following:
-- The completion of a major transaction with Eni S.p.A ("Eni")
resulting in Eni owning 60% of the Group's interest in the
Zagoryanska licence and 30% of the Group's interest in the
Pokrovskoe licence
-- A $30 million (excluding VAT) drilling programme on the Pokrovskoe field
-- A three-well work-over programme on the Zagoryanska field
-- Total capital expenditure of $21.3 million (2010: $12.1 million) during the year
-- Net cash and cash equivalents at year end of $65.0 million (2010: $36.4 million)
Enquiries
Cadogan Petroleum plc +44 20 7487 8301
Bertrand des Pallieres, Chief Executive
Officer
Stefan Bort, Company Secretary
Bankside
Simon Rothschild +44 20 7367 8888
Business Review
_______________________________________________________________________________________
Introduction
2011 has been a significant year for Cadogan Petroleum plc, as
it seeks to develop its oil and gas business in Ukraine. On 6 July
2011 we completed a transaction whereby Eni acquired a 60% interest
in the Group's Zagoryanska licence for $38 million and acquired a
30% interest in our Pokrovskoe licence by funding a $36 million
($30 million plus VAT) work programme and an option to purchase a
further 30% dependent on the results of the drilling programme.
Financial position
At 27 April 2012 the Group had current cash and cash equivalents
of approximately $58.0 million. This is more than adequate to
fulfil the Group's current work programme.
Operations
The Operations review details the extensive work programme that
the Group has undertaken on its assets in the Dnieper-Donets basin
in eastern Ukraine. Although results on the Zagoryanska work-overs
have been delayed due to technical issues, the Group continues to
test Zagoryanska 1 and 2 which were worked over in Q3 and Q4 of
2011. Zagoryanska 8 is also being worked over at present and will
be put on test in Q2 of 2012. All of these wells are close to the
Zagoryanska 3 well which continues to produce at around 35 mcm/day.
In addition the Group spudded a 5,160 metres appraisal well at
Zagoryanska 11 on 7 March 2012. Working with Eni's technical staff,
considerable analysis of the potential reservoir has been
undertaken.
Initial results from our exploratory Pokrovskoe 1 well, which
was deepened in 2011, and Pokrovskoe 2a well, which was re-drilled
in Q4 of 2011 and Q1 of 2012, were not as positive as hoped. As a
consequence Eni have decided not to exercise their option to
acquire a further 30% in the licence, a development that was
announced on 19 March 2012. This is of course disappointing, but
the indications of hydrocarbons throughout the drilling process is
of sufficient interest that Cadogan is considering options to
re-enter the Pokrovskoe 2a well to assess the potential of the
Upper Visean in the future. Should this be successful, the Group
would consider options to commercially exploit the field.
Efforts continue to farm-out the Group's highly attractive
Bitlyanska asset in western Ukraine. The Group intends to review
possible work-over projects for the Pirkrovskoe field in eastern
Ukraine. Low cost analysis techniques are being reviewed for use on
the Group's shallow gas fields, currently under production, in
Debeslevetska aimed at stimulating production increases whilst a
borehole formation cleaning programme is underway at Monastyretska
to attempt to increase oil production from the existing wells.
Litigation
During the year the Group concluded a settlement with the final
main defendant in its litigation against former management and
third parties over alleged procurement irregularities. The Group
continues to be owed $30 million by Global Process System Inc
('GPS') of Dubai, under the settlement agreement entered into
October 2009. The settlement was based on the sale of two gas
plants, which were manufactured by GPS that were not required by
the Group. Under the agreement GPS undertook to take the plants
back into stock and resell them. Cadogan retains title over the
plants manufactured. The Board believes that the value of these
plants equates to the sum due, and continues to assist GPS in its
attempts to sell the plants whilst pursuing legal remedies to
recover the outstanding debt.
Business development and strategy
Ukraine, with its significant existing and yet-to-be discovered
resources in both conventional and unconventional gas, as well as
its significant infrastructure bordering Western Europe, has a
tremendous opportunity: it has the potential to offer international
energy companies a viable business proposition with reasonable
fiscal terms and a stable political and regulatory environment,
where many existing fields have been underexploited because of an
insufficient exposure to modern field-optimisation techniques.
Field rehabilitation and field optimisation would help generate
significant increases in production.
The results of the Group's current work programme for 2011-12
will be critical in determining its next steps. Cadogan is very
focused on the appraisal of the Zag field with the objective to
define a full field development plan by the end of 2012. We will
continue to invest in exploration and appraisal of our other
existing assets, while starting investment in new areas with an
emphasis on offshore activities in the Black Sea. Cadogan also
hopes to start preliminary exploration of unconventional gas assets
in 2012.
Cadogan is already the most active foreign company in the
Ukrainian upstream sector, and the Group intends to bolster this
position. Cadogan's ongoing strategy is to focus on acquiring low
capital investment positions on Ukraine oil and gas assets, either
in joint venture with State companies or not, and developing them
in joint venture with international energy companies. We expect the
next 12 to 24 months to bring considerable change to Ukraine's
E&P sector. While historically only small foreign companies
have been active, a number of international oil majors are about to
enter Ukraine for the first time. Cadogan is extremely well
positioned to support and exploit this transition.
Operations Review
_______________________________________________________________________________________
In 2011 the Group held working interests in nine (2010: nine)
gas, condensate and oil exploration and production licences in the
east and west of Ukraine. All these assets are operated by the
Group and are located in either the Carpathian basin or the
Dnieper-Donets basin, in close proximity to the Ukrainian gas
distribution infrastructure. The Group's primary focus is on the
four licences where the main reserve and resource potential is
located, Zagoryanska, Pokrovskoe, and Pirkovskoe in the
Dnieper-Donets basin of east Ukraine and Bitlyanska, in the
Carpathian Basin of west Ukraine.
Summary of the Group's licences (as of 31(st) December
2011)
------------------------------------------------------------------------
Working Licence Expiry Licence type((1)
interest
(%)
--------------- ------------------ ---------------- -----------------
Major licences
40.0 Zagoryanska April 2014 E&D
70.0 Pokrovskoe August 2016 E&D
100.0 Pirkovskoe October 2015 E&D
96.5 Bitlyanksa(2) December 2014 E&D
Minor licences
98.3 Debeslavetska October 2026 Production
98.3 Debeslavetska September 2016 Exploration
(3)
49.8 Cheremkhivska May 2018 Production
100.0 Slobodo-Rungerska April 2016(3) E&D
95.0 Monastyretska November 2014 E&D
(1) E&D = Exploration and Development.
(2) The working interest on the Bitlyanska licence declines on a
stepped basis, every five years after the commencement of
production on each well. The Joint Activity Agreement ('JAA') also
distinguishes working interests on new wells and work over wells
with the former offering a higher share to the Group. Effective
working interests are shown above.
(3) The licence is in the process of renewal by the Ukraine
authorities for further 5 years, from its expiration date in 2011.
The renewal process is expected to be completed during the first
half of 2012.
Zagoryanska licence
The Group now has a 40 per cent working interest in the
Zagoryanksa licence area. The Zagoryanska licences hold 96.4 mmboe
of Contingent Resources (2010: 96.4 mmboe of Contingent Resources).
The exploration and development licence covers 49.6 square
kilometres and the licence was extended in 2009 until April 2014.
The remaining work programme includes; (a) the work-over of well
Zagoryanska 2 (underway); (b) the drilling of an appraisal well
(which is undergoing); and (c) conducting geological and economic
estimation of hydrocarbon reserves.
In 2008, the Zagoryanska 3 well had been drilled to a target
depth ("TD") of 5,110 metres and was suspended in order to evaluate
the data obtained. In 2009 the well was perforated and commercial
flow rates were achieved. Production commenced in August 2010 at a
flow rate of 55 mcm/day (2 million scf/day) of gas and 15 t/day
(120 bpd) of condensate and the well was tied into the Group's
Zagoryanska gas treatment plant. Average monthly production rates
during 2011 were 36 mcm/day gas and 6.5 t/day condensate. The Group
has since purchased the Zagoryanska 3 well, (which it was
previously renting), together with four additional wells on the
field.
On 6 July 2011 Eni, the major Italian integrated energy company,
acquired a 60 per cent interest in the Zagoryanska licence for a
payment of $38 million. Following completion of this transaction a
work over plan was prepared for three of the four additional wells
purchased on the field. Wells Zagoryanska 1 and 2 have been worked
over in preparation for rig-less operations (including coiled
tubing operations); work over of Zagoryanska 8 is on-going and
testing will commence in Q2 2012. These work-overs are designed to
allow re-entry of zones that previously produced hydrocarbons in
Zagoryanska Field, but were suspended for various technical or
commercial reasons in the 1990's.
During the year Cadogan acquired the remaining 10% interest in
the Zagoryanska licence from NSJC Nadra Ukraine for a consideration
of $1.5 million.
Pokrovskoe licence
The Group now has a 70 per cent working interest in the
Pokrovskoe licence which holds 51.1 mmboe (2010: 51.1 mmboe) of
Prospective Resources. The exploration licence covers 49.5 square
kilometres and the initial licence was extended during the year
until August 2016.
Interpretation of the 3D seismic was completed in early 2010 and
confirmed the presence of a prospect with four-way closure at the
Lower Visean and the deeper Tournasian level, beneath both the
Pokrovskoe 1 and Pokrovskoe 2 suspended well locations. The
Pokrovskoe 1 well had encountered strong indications of gas during
drilling and logging over significant sections in the Lower Visean
and was suspended due to equipment limitations at 5,450 metres.
Pokrovskoe 2 was drilled to a depth of 5,185 metres and suspended
for future evaluation and possible deepening as the Upper Visean
formations provided strong indications of gas, supported by well
log data.
As part of the Eni transaction, that company acquired a 30 per
cent interest in the Group's Pokrovskoe licence, with an option to
acquire a further 30 per cent interest in the future. On 9 March
2012 the Group has been advised by Eni, that, after their analysis
of the results for the Pokrovskoe 1 and Pokrovskoe 2a wells, Eni do
not intend to exercise their option to acquire the additional 30
per cent (refer to note 20 to the Condensed Financial Consolidated
Information). Notwithstanding the option not being exercised, Eni
will continue with an existing 30 per cent share in Pokrovskoe
licence.
The consideration comprised 100 per cent funding of a work
programme of approximately $30 million (excluding VAT), which was
used to fulfil the work obligations on the licence. This comprised
the deepening of Pokrovskoe 1 to test the potential of the Lower
Visean and the re-drilling of Pokrovskoe 2 (designated 2a) in order
to test the potential of the Upper Visean intervals.
On Pokrovskoe 1, the primary Lower Visean target proved to be
water bearing and while preparing to test the secondary zone,
mechanical problems prevented completion of operations. As a
result, the well was suspended and the Saipem drilling rig was
moved to the Pokrovskoe 2a location while remedial operations were
considered for Pokrovskoe 1.
On Pokrovskoe 2a, the well was drilled to a casing point at
4,783 metres where the logs acquired indicated the presence of
hydrocarbons and a decision was taken to continue drilling after
casing the open-hole section. During the casing operation the
running string became stuck and the limited fishing equipment
available in country prevented the running tool from being
recovered. The well has therefore been suspended while future
options are considered for the well.
Pirkovskoe licence
The Group has a 100 per cent working interest in the Pirkovskoe
licence which holds 2.4 mmboe (2010: 2.4 mmboe) of 2P Reserves, 5.0
mmboe (2010: 5.0 mmboe) of Possible Reserves, and 134.0 mmboe of
Contingent Resources (2010: 134.0 mmboe). This exploration and
appraisal licence covers 71.6 square kilometres and has been
renewed until October 2015. The remaining work programme includes;
(a) the testing of Pirkovskoe 1; (b) deepening to 5,450 metres and
testing of the suspended Pirkovskoe 2 well; (c) the drilling of a
new well (scheduled for 2013); and (d) calculation of the potential
hydrocarbon reserves.
Pirkovskoe 1 was the first appraisal well drilled in the
northern part of the Pirkovskoe licence. The well was terminated at
a TD of 5,723 metres and after testing the Devonian and Lower
Carboniferous, the well was temporarily suspended. The testing and
subsequent completion of several shallower Carboniferous oil and
gas bearing zones was farmed out to a local company at no cost to
Cadogan, in return for a share of any future production. This
interval produced small volumes of oil and gas and is currently
shut-in.
The Pirkovskoe 2 well was drilled to a depth of 4,580 metres,
and has been suspended until the results of Pirkovskoe 1 have been
reviewed.
The Group owns the Kraznozayarska gas treatment plant located on
the Pirkovskoe licence area, which is connected to the UkrTransGas
system. Its capacity was upgraded in July 2007 to 300,000 cubic
metres per day of gas and 150 tonnes per day of condensate in
anticipation of future production.
Bitlyanska licence area
The Bitlyanska exploration and development licence covers an
area of 390 square kilometres and the Group's interest ranges from
96.5 per cent to 97.1 per cent, varying with production. There are
three hydrocarbon discoveries in this licence area, namely Bitlya,
Borynya and Vovchenska. The Borynya and Bitlya fields hold 211.5
mmboe (2010: 211.5 mmboe) and 113.9 mmboe (2010: 113.9 mmboe) of
Contingent Resources respectively, while no Reserves and Resources
have been attributed to the depleted Vovchenska field.
In the 1970's drilling of the Borynya 1 resulted in a blow out
and on Borynya 2 reportedly tested gas at very high rates. Cadogan
drilled the Borynya 3 well proximal to these two Soviet era wells
and in June 2009, tested gas from one of the secondary reservoir
targets at around 3,600 metres at a maximum flow rate of 128,000
cubic metres per day during a limited duration drill stem test.
Borynya 3 was terminated at a drilled depth of 5,325 metres and the
well was suspended for future evaluation having encountered several
deep high-pressure gas bearing intervals that could not be tested
with the equipment available at that time.
In 1994 the Bitlya 1 well tested non-commercial gas from several
zones down to 3,200 metres. Although this well established the
presence of an active hydrocarbon system, the recent 2D seismic
data interpretation demonstrates that the well was poorly located
in relation to any structural closure.
In 2010 a 2D survey was completed in the southern part of the
licence to complement the Soviet era 2D seismic data that had been
reprocessed by Cadogan. This integrated data set has been
interpreted with the benefit of recent surface geological mapping
and balanced section generation, and a series of prospects for
future exploration drilling have been identified.
The remaining work obligation for this licence was recently
re-negotiated.
Minor fields
The Group has a number of minor licence areas located in western
Ukraine. These include the following:
-- Debeslavetska Production licence area
A production licence, containing 0.2 mmboe of Proved, Probable
and Possible ('3P') Reserves (2010: 0.3 mmboe). The field is
currently producing 84.0 boepd (2010: 100.7 boepd). Production
during the year was impacted by a compressor failure that resulted
in a period of planned maintenance being bought forward into 2011;
equipment optimisation is foreseen during 2012. The Group drilled a
series of three shallow wells on the field in 2011 using its own
drilling rig which added minor commercial production but also
assisted in the geological interpretation of the wider area.
-- Debeslavetska Exploration licence area
An exploration licence surrounding the Debeslavetska Production
licence area which has similar shallow gas production potential to
the Debeslavetska Field.
-- Cheremkhivska Production licence area
A production licence containing 0.1 mmboe of 3P Reserves (2010:
0.1 mmboe). This licence is currently producing 32.8. boepd (2010:
33.2 boepd).
-- Slobodo-Rungerska licence area
An exploration and development licence, with no booked Reserves
and Resources (2010: nil). Seismic data for this area was
reprocessed in 2010 and the results indicate a deeper structure
underlying the depleted and abandoned Slobodo-Rungerska Field.
-- Monastyretska licence area
An exploration and development licence, with no booked Reserves
or Resources (2010: nil). Re-entry of the Blazhiv 1 well was
undertaken in the year and minor oil production re-established at
the rate of 16 bopd. A hydraulic formation cleaning program on the
well is currently under way in the attempt to increase production
levels.
Financial Review
_______________________________________________________________________________________
Overview
In 2011 the Group mainly focused on exploration activity at
Pokrovskoe and appraisal activity at Zagoryanska fields together
with its joint venture partner Eni.
A substantial increase in the gas price in Ukraine has enabled
revenue to increase from $5.0 million in 2010 to $7.0 million in
2011. A gain on disposal of two subsidiaries in 2011 of $164.9
million, including revaluation of the remaining jointly-controlled
interest of $91.1 million, in the above mentioned subsidiaries that
the Group has lost control in, contributed to the profit for the
year of $153.1 million (2010: $1.3 million). This profit was
reflected by a corresponding increase in the net asset position as
at 31 December 2011 to $283.0 million from $131.2 million as at 31
December 2010. The cash position of $65.0 million at 31 December
2011 has increased from $36.4 million at 31 December 2010 mainly as
the result of the cash consideration received from the disposal of
interest in two subsidiaries to Eni.
Change in the presentation currency of the financial
information
The Directors decided to change the Group's presentation
currency from sterling to US dollars with effect from 1 January
2011. These are the first financial statements and the accompanying
notes to be reported in US dollars (refer to note 2(b) to the
Condensed Financial Consolidated Information).
Income statement
Profit before tax was $152.6 million (2010: $0.8 million).
Revenues of $7.0 million (2010: $5.0 million) comprised sales of
gas from the Debeslavetska, Cheremkivska fields and Zagoryanska 3
well. Cost of sales, which represents production royalties and
taxes, depreciation and depletion of producing wells and direct
staff costs increased to $6.3 million in 2011 from $4.1 million in
2010 to give a gross profit of $0.7 million (2010: $0.9
million).
-- Other administrative expenses of $11.6 million (2010: $13.0
million) comprise other staff costs, professional fees, Directors'
remuneration, depreciation charges on non-producing property, plant
and equipment. In addition to recurring administrative expenses,
$1.2 million (2010: $2.2 million) of professional costs were
incurred in relation to litigation, $0.9 million (2010: $nil) of
professional fees were incurred in relation to the transaction with
Eni on the two Pokrovskoe and Zagoryanska licences.
-- Profit on disposal of subsidiaries amounted to $164.9 million
which represents a difference between $17.6 million of net assets
disposed, the sum of $91.4 million consideration received and $91.1
million of net fair value of the residual interest (including a
$80.2 million of fair value uplift). At year end the changes in the
fair value of financial asset and liability arising from the Eni
transaction resulted in net charge to the income statement of $3.3
million (refer to note 18 to the Condensed Financial Consolidated
Information).
-- Other operating income of $4.6 million (2010: $11.8 million)
includes $2.1 million (2010: $9.3 million) related to recoveries
from former management and suppliers and $2.4 million (2010: $2.5
million) related to net foreign exchange gains.
-- Net impairment charges of $2.8 million (2010: $0.9 million
reversal of impairment) comprised of $3.2 million impairment (2010:
$2.3 million reversal of impairment) of Ukrainian VAT and $0.4
million reversal of provision for inventory (2010: $1.4 million
provision).
Cash flow statement
The Condensed Consolidated Cash Flow Statement shows expenditure
of $16.9 million (2010: $6.2 million) on intangible Exploration and
evaluation assets and $4.4 million (2010: $5.9 million) on
Property, plant and equipment. In addition, the Group received
$58.0 million (2010: $nil) as a result of disposal of
subsidiaries.
Balance sheet
As at 31 December 2011, the Group had net cash and cash
equivalents of $65.0 million (2010: $36.4 million, 2009: $48.6
million). Intangible E&E assets of $66.0 million (2010: $6.2
million, 2009: $nil) represent the carrying value of the Group's
investment of exploration and appraisal assets as at 31 December
2011, including $40.3 million of fair value uplift on the valuation
of the 70% jointly-controlled interest in the former subsidiary
which holds Pokrovskoe licence. The PP&E balance of $99.4
million at 31 December 2011 (2010: $53.9 million, 2009: $51.0
million), comprised of the cost of developing fields with
commercial reserves and bringing them into production and $40.0
million of fair value uplift on the valuation of the 40%
jointly-controlled interest in the former subsidiary which holds
Zagoryanska licence. Trade and other receivables of $66.3 million
(2010: $38.7 million, 2009: $38.6 million) include $30.0 million
(2010: $33 million, 2009: $30.0 million of non-current other
receivables and $6.5 million of current other
receivables)receivables in respect of the settlement with GPS
(refer to note 3(b) to the Condensed Financial Consolidated
Information), $29.1 million (2010: $nil, 2009: $nil) represent
deferred and contingent consideration for the disposal of two of
Group's subsidiaries to Eni (refer to note 18 to the Condensed
Financial Consolidated Information) and $4.3 million prepayments
(2010: $0.4 million, 2009: $0.6 million) mostly relate to
prepayments made to drilling contractor in Ukraine and long lead
materials for the drilling and work over campaign.
Key performance indicators
The Group monitors its performance in implementing its strategy
with reference to clear targets set out for five key financial and
one key non-financial performance indicators ('KPIs'):
-- to increase oil, gas and condensate production measured on
number of barrels of oil equivalent produced per day ('boepd');
-- to increase the Group's oil and gas reserves by de-risking
possible resources and contingent reserves into 2P Reserves. This
is measured in million barrels of oil equivalent ('mmboe');
-- to increase the realised price per 1,000 cubic metres;
-- to decrease the cost per barrel for exploration and acquisition related expenditure;
-- to increase the Group's basic and diluted earnings per share; and
-- to reduce the number of lost time incidents.
The Group's performance in 2011 against these targets is set out
in the table below, together with the prior year performance data.
No changes have been made to the source of data or calculation used
in the year.
Unit 2011 2010
--------------------------------------------- ----------- ------ ------
Financial KPIs
Average production (working interest basis)
(1) boepd 297 268
2P reserves (2) mmboe 2.6 2.6
Realised price per 1,000 cubic metres (3) $ 395.1 307.3
Basic and diluted earnings per share (4) cent 65.6 0.6
Non-financial KPIs
Lost time incidents (5) incidents 2 -
--------------------------------------------- ----------- ------ ------
(1) Average production is calculated as the average daily production during the year.
(2) Quantities of 2P reserves as at 31 December 2010 and 2011
are based on Gaffney, Cline & Associates' independent reserves
report on 2P Reserves as at 31 December 2009, dated 16 March 2010,
as adjusted for the actual production during 2010 and 2011
respectively.
(3) This represents the average price received for gas sold during the year (including VAT).
(4) Basic and diluted profit per Ordinary share is calculated by
dividing the net profit for the year attributable to Ordinary
equity holder of the parent by the weighted average number of
Ordinary shares during the year.
(5) Lost time incidents relate to injuries where an
employee/contractor is injured and has time off work.
Related party transactions
Related party transactions are set out in note 32 to the
Consolidated Financial Statements of the 2011 Annual Report.
Treasury
The Group continually monitors its exposure to currency risk. It
maintains a portfolio of cash and cash equivalent balances mainly
in US dollars ('USD') held primarily in the UK and holds these
mostly in term deposits depending on the Group's operational
requirements. Production revenues from the sale of hydrocarbons are
received in the local currency in Ukraine ('UAH') and to date funds
from such revenues have been held in Ukraine for further use in
operations rather than being remitted to the UK. Funds are
transferred to the Company's subsidiaries in USD to fund operations
at which time the funds are converted to UAH. Some payments are
made on behalf of the subsidiaries from the UK.
Statement of Reserves and Resources
_______________________________________________________________________________________
The Group did not commission an independent Reserves and
Resources Evaluation of the Group's oil and gas assets in Ukraine,
as at 31 December 2011 due to the insufficient new information
being obtained from operational activity before the year end. The
summary of the Reserves and Resources below are based on the
Independent Reserves and Resources Evaluation performed by Gaffney
Cline and Associates as at 31 December 2009 adjusted for 2010 and
2011 actual production.
Summary of Reserves
As of 31 December 2011
Working interest basis
---------------------------------------------- -----------------------------
Gas Condensate Oil
bcf mmbbl mmbbl
---------------------------------------------- ------- ----------- -------
Proved and Probable Reserves at 1 January
2011 11.3 0.6 -
Production (0.2)* - -
Proved and Probable Reserves at 31 December
2011 11.1 0.6 -
---------------------------------------------- ------- ----------- -------
Possible Reserves at 1 January 2010 and 2011
and 31 December 2011 19.5 1.5 -
---------------------------------------------- ------- ----------- -------
*During 2011 the Group produced additional 0.6bcf (2010: 0.3
bcf) of natural gas and 0.02mmbl (2010: 0.01 mmbl) of condensate
from the Zagoryanska field which were not included by Gaffney Cline
and Associates in the Reserves balances at 31 December 2009
provided in the Reserves and Resources Evaluation Report as at that
date.
Summary of Contingent Resources
As of 31 December 2011
Working interest basis
------------------------------------------ ---------------------------------------
Gas Condensate Oil Total
bcf mmbbl mmbbl mmboe
------------------------------------------ -------- ----------- ------- -------
Contingent Resources at 1 January 2010
and 2011 2,488.0 108.1 - 555.9
------------------------------------------ -------- ----------- ------- -------
Change in working interest (236) (15.3) - (57.8)
------------------------------------------ -------- ----------- ------- -------
Contingent Resources at 31 December 2011 2,252.0 92.8 - 498.1
------------------------------------------ -------- ----------- ------- -------
Reserves are only assigned to Pirkovskoe, Debeslavetska and
Cheremkhivska fields.
Although commercial production has been achieved at Zagoryanska
field no 2P reserves have been booked as of 31 December 2011 (2010:
nil) as the Group did not receive an update CPR to independently
confirm the Reserves quantities.
Contingent Resources are assigned to Zagoryanska, Pirkovskoe,
Borynya and Bitlya fields, where development is contingent on
further appraisal.
Prospective Resources of 165.9 bcf (2010: 237.0 bcf) of gas and
5.9 mmbl (2010: 8.4 mmbl) of condensate are attributed to
Pokrovskoe field (Cadogan's working interest), where there has not
yet been a production test. The difference between 2011 and 2010
figures is a result of the change in Cadogan's working
interest.
Condensed Consolidated Income Statement
For the year ended 31 December 2011
_______________________________________________________________________________________
2011 2010
Notes $'000 $'000
---------------------------------------------- ------ --------- ---------
CONTINUING OPERATIONS
Revenue 6,981 5,027
Cost of sales (6,264) (4,148)
---------------------------------------------- ------ --------- ---------
Gross profit 717 879
Administrative expenses:
Other administrative expenses (11,634) (12,983)
(Impairment)/reversal of impairment of other
assets 7 (2,818) 941
(14,452) (12,042)
Gain on disposal of subsidiaries 18 164,945 -
Other gains and (losses) 18 (3,299) -
Other operating income 6 4,552 11,790
---------------------------------------------- ------ --------- ---------
Operating profit 152,463 627
Investment revenue 155 201
Finance costs (11) (6)
Profit before tax 152,607 822
Tax 9 473 496
---------------------------------------------- ------ --------- ---------
Profit for the year 8 153,080 1,318
---------------------------------------------- ------ --------- ---------
Attributable to:
Owners of the Company 151,549 1,318
Non-controlling interest 1,531 -
---------------------------------------------- ------ --------- ---------
153,080 1,318
Profit per Ordinary share cent cent
Basic and diluted 10 65.6 0.6
---------------------------------------------- ------ --------- ---------
Condensed Consolidated Statement of Comprehensive Income
For the year ended 31 December 2011
2011 2010
$'000 $'000
Profit for the year 153,080 1,318
Unrealised currency translation differences (2,067) (3,323)
Total comprehensive profit/(loss) for
the year 151,013 (2,005)
----------------------------------------------------- -------- --------
Attributable to:
Owners of the Company 149,482 (2,005)
Non-controlling interest 1,531 -
--------------------------------------------- -------- --------
151,013 (2,005)
--------------------------------------------------- -------- --------
Condensed Consolidated Balance Sheet
As at 31 December 2011
_______________________________________________________________________________________
2011 2010 2009
Notes $'000 $'000 $'000
-------------------------------------- ----- --------- --------- ---------
ASSETS
Non-current assets
Intangible exploration and evaluation
assets 11 65,972 6,163 -
Property, plant and equipment 12 99,373 53,923 50,984
Other non-current receivables 15 - - 30,000
Other financial assets 15 - 664 717
-------------------------------------- ----- --------- --------- ---------
165,345 60,750 81,701
Current assets
Inventories 14 6,556 3,985 8,795
Trade and other receivables 15 66,251 38,659 8,585
Other financial assets 15 - 372 -
Cash and cash equivalents 15 65,039 36,419 48,588
137,846 79,435 65,968
-------------------------------------- ----- --------- --------- ---------
Total assets 303,191 140,185 147,669
-------------------------------------- ----- --------- --------- ---------
LIABILITIES
Non-current liabilities
Deferred tax liabilities 16 (11,538) (982) (1,550)
Long-term provisions (548) (453) (280)
-------------------------------------- ----- --------- --------- ---------
(12,086) (1,435) (1,830)
Current liabilities
Short-term borrowings - (372) -
Trade and other payables (7,552) (6,767) (11,527)
Current tax liabilities - - (25)
Current provisions (524) (441) (1,112)
-------------------------------------- ----- --------- --------- ---------
(8,076) (7,580) (12,664)
-------------------------------------- ----- --------- --------- ---------
Total liabilities (20,162) (9,015) (14,494)
-------------------------------------- ----- --------- --------- ---------
NET ASSETS 283,029 131,170 133,175
-------------------------------------- ----- --------- --------- ---------
EQUITY
Share capital 13,337 13,337 13,337
Retained earnings 389,734 237,963 229,292
Cumulative translation reserves (123,784) (121,717) (118,394)
Other reserves 3,344 2,720 10,073
-------------------------------------- ----- --------- --------- ---------
Equity attributable to owners of the
Company 282,631 132,303 134,308
Non-controlling interest 398 (1,133) (1,133)
-------------------------------------- ----- --------- --------- ---------
TOTAL EQUITY 283,029 131,170 133,175
-------------------------------------- ----- --------- --------- ---------
Condensed Consolidated Cash Flow Statement
For the year ended 31 December 2011
_______________________________________________________________________________________
2011 2010
Note $'000 $'000
----------------------------------------------------- ---- -------- --------
Net cash (outflow)/inflow from operating activities 17 (7,885) 34
Investing activities
Disposal of subsidiaries (note 18) 57,954 -
Purchases of property, plant and equipment (4,402) (5,888)
Purchases of intangible exploration and evaluation
assets (16,893) (6,182)
Proceeds from sale of property, plant and equipment 87 629
Interest received 155 201
----------------------------------------------------- ---- -------- --------
Net cash from/(used in) investing activities 36,901 (11,240)
----------------------------------------------------- ---- -------- --------
Financing activities
Proceeds from short-term borrowings (371) 371
----------------------------------------------------- ---- -------- --------
Net cash (used in)/from financing activities (371) 371
----------------------------------------------------- ---- -------- --------
Net increase/(decrease) in cash and cash equivalents 28,645 (10,835)
Effect of foreign exchange rate changes (25) (1,334)
Cash and cash equivalents at beginning of year 36,419 48,588
----------------------------------------------------- ---- -------- --------
Cash and cash equivalents at end of year 65,039 36,419
----------------------------------------------------- ---- -------- --------
Condensed Consolidated Statement of Changes in Equity
For the year ended 31 December 2011
_______________________________________________________________________________________
Other reserves
Share-based
payment
$ '000 Reorganisation
Cumulative $ '000
Share Retained translation Non-controlling
capital earnings reserves interest Total
$ '000 $ '000 $ '000 $ '000 $ '000
As at 1 January
2010 13,337 229,292 (118,394) 8,484 1,589 (1,133) 133,175
Share-based payments - 7,353 - (7,353) - - -
Net income for the
year - 1,318 - - - - 1,318
Exchange translation
differences on
foreign
operations - - (3,323) - - - (3,323)
---------------------- -------- --------- ------------ ----------- ---------------- ---------------- --------
As at 1 January
2011 13,337 237,963 (121,717) 1,131 1,589 (1,133) 131,170
Share-based payments - 222 - 624 - - 846
Net income for the
year - 151,549 - - - 1,531 153,080
Exchange translation
differences on
foreign
operations - - (2,067) - - - (2,067)
---------------------- -------- --------- ------------ ----------- ---------------- ---------------- --------
As at 31 December
2011 13,337 389,734 (123,784) 1,755 1,589 398 283,029
---------------------- -------- --------- ------------ ----------- ---------------- ---------------- --------
Notes to the Condensed Consolidated Financial Information
For the year ended 31 December 2011
_______________________________________________________________________________________
1. General information
Cadogan Petroleum plc (the 'Company', together with its
subsidiaries the 'Group'), is incorporated in England and Wales
under the Companies Act, who began trading on the London Stock
Exchange on 23 June 2008.
The financial information set out above does not constitute the
Company's statutory accounts for the years ended 31 December 2011,
2010 or 2009, as defined in section 435 of the Companies Act 2006,
but is derived from those accounts. Statutory accounts for the
years ended 31 December 2010 and 2009 have been delivered to the
Registrar of Companies and those for 2011 will be delivered
following the Company's Annual General Meeting.
The auditor has reported on those sets of accounts. The reports
for the years ended 31 December 2010 and 2009 were qualified in
respect of the limitation to obtain sufficient appropriate audit
evidence regarding (a) the carrying values of assets as at 31
December 2008 and (b) the completeness and accuracy of the
disclosures of related party transactions and directors'
remuneration (as set out in note 3(b) to those accounts). In 2010,
the qualification extended only to the Consolidated Income
Statement, Consolidated Statement of Comprehensive Income,
Consolidated and Parent Company Cash Flow Statements, Consolidated
and Parent Company Statement of Changes in Equity and related notes
for the year ended 31 December 2009 which formed comparative
information for the year ended 31 December 2010. The reports
contained a statement under sections 498(2) (unable to determine
whether adequate accounting records had been kept) and 498(3)
(failure to obtain necessary information and explanations) of the
Companies Act 2006 in respect of this limitation.
The 2011 and 2010 auditor's reports contained an emphasis of
matter in relation to the uncertainty over recoverability of the
amounts included within current other receivables in respect of two
gas plants being sold by Global Process Systems LLC as set out in
note 3(b). The 2009 auditor's report drew attention by way of
emphases of matter in relation to the status of legal proceedings
surrounding the validity of certain of the Group's licences in
Ukraine and to proposed Annual General Meeting resolutions and
potential impact on going concern if passed. The Ukrainian licence
issue has been resolved as set out in note 3(f) of the 2010
accounts and the resolutions were never put to the meeting.
2. Significant accounting policies
(a) Basis of accounting
The financial information has been prepared in accordance with
IFRSs as adopted by the European Union and has been prepared on the
basis of the accounting policies set out in the Group's 2011 Annual
Report.
Whilst the financial information in this preliminary
announcement has been prepared in accordance with IFRS, this
announcement does not itself contain sufficient information to
comply with IFRS. A copy of the full financial statements prepared
in accordance with IFRS has been published and is available on the
Company's website.
The preliminary announcement was approved by the Board on 27
April 2012.
(b) Transition to US dollar reporting
The Directors decided to change the Group's presentation
currency from sterling to US dollars with effect from 1 January
2011. The 2011 consolidated financial statements are the first
financial statements and the accompanying notes to be reported in
US dollars together with the financial information contained in
this preliminary announcement.
The majority of the Group's earnings and costs are linked to US
dollars or US dollar linked currencies. The investing activity of
the Company is being conducted in US dollars and the majority of
the Group's funds are currently denominated in US dollars. The
change of presentation currency from sterling to US dollar will
more closely align the Group's external reporting with
international oil and gas industry, thus improving investors'
ability to compare financial data.
The change of the Group's presentation currency has been
accounted for in accordance with IAS 21 'The Effects of Changes in
Foreign Exchange Rates'. The change in the presentation currency
from sterling to US dollars has been applied retrospectively in
accordance with IAS 8 'Accounting Policies, Changes in Accounting
Estimates and Errors' and therefore requires comparative
information to be restated and consequently, a third balance sheet
is required to be presented in the financial statements.
The following methodology was used to re-present the 2010 and
2009 financial information, originally reported in pounds sterling,
into US dollars:
a) assets and liabilities were translated into US dollars at the
closing rate prevailing at the balance sheet dates;
b) income and expenses were translated into US dollars at the
average exchange rate for the relevant period; and
c) equity items were translated at historical exchange rates
from 1 January 2006, the date for which the consolidated financial
statements were first prepared under IFRS, all resulting exchange
rate differences have been recognised in other comprehensive
income, within the foreign currency translation reserve.
The relevant exchange rates used were as follows:
Year ended 31 Dec 2010 Year ended 31 Dec 2009 1US$
1US$ = GBP = GBP
Closing rate 0.6465 0.6278
Average rate 0.6467 0.6386
(c) Going concern
The Group's business activities, together with the factors
likely to affect future development, performance and position are
set out in the Business Review. The financial position of the
Group, its cash flow and liquidity position are described in the
Financial Review.
The Group's cash balance at 31 December 2011 was $65.0 million
(2010: $36.4 million, 2009: $48.6 million) with no external debt
(2010: $0.4 million, 2009: $nil) and the Directors believe that the
funds available at the date of the issue of this financial
information is sufficient for the Group to manage its business
risks successfully.
The Group's forecasts and projections, taking into account
reasonably possible changes in operational performance, start dates
and flow rates for commercial production and the price of
hydrocarbons sold to Ukrainian customers, show that there are
reasonable expectations that the Group will be able to operate on
funds currently held and those generated internally, for the
foreseeable future, without taking into account receivables from
litigation and without the requirement to seek external
financing.
As the Group engages in oil and gas exploration and development
activities, the most significant risk faced by the Group is delays
encountered in achieving commercial production from the Group's
major fields. The Group also continues to pursue its farm-out
campaign, which, if successful, will enable it to farm-out a
portion of its interests in its oil and gas licences to spread the
risks associated with further exploration and development.
After making enquiries and considering the uncertainties
described above, the Directors have a reasonable expectation that
the Company and the Group have adequate resources to continue in
operational existence for the foreseeable future and consider the
going concern basis of accounting to be appropriate. Thus they
continue to adopt the going concern basis of accounting in
preparing the financial information.
3. Critical accounting judgements
In the application of the Group's accounting policies, which are
described in note 2, the Directors are required to make judgements,
estimates and assumptions about the carrying amounts of the assets
and liabilities that are not readily apparent from other sources.
The estimates and associated assumptions are based on historical
experience and other factors that are considered to be relevant.
Actual results may differ from these estimates.
The estimates and underlying assumptions are reviewed on an
ongoing basis. Revisions to accounting estimates are recognised in
the period in which the estimate is revised if the revision affects
only that period or in the period of the revision and future
periods if the revision affects both the current and future
periods.
The following are the critical judgements and estimates that the
Directors have made in the process of applying the Group's
accounting policies and that have the most significant effect on
the amounts recognised in the financial information:
(a) Disposal of subsidiaries and acquisition of
jointly-controlled entities - Eni transaction
To calculate the gain on disposal on the loss of control of the
subsidiaries sold to Eni (details of the transaction in note 18),
it was necessary to determine the fair value of the consideration
received and the fair value of any retained interest. In addition,
the fair value of the investment retained in the former subsidiary
at the date when control was lost has been regarded as the costs on
initial recognition of the jointly controlled entities.
Fair value of the consideration received
The consideration received has been measured at the aggregate of
the fair values (at the date of exchange) of the assets received
and liabilities incurred or assumed, including any asset or
liability resulting from a contingent consideration arrangement.
All subsequent changes in the fair value of contingent
consideration classi ed as an asset or liability have been
accounted for in accordance with relevant IFRSs.
The determination of the fair value of the contingent
consideration and liability arising from the option granted to Eni
to acquire a further 30% of the share capital of Pokrovskoe
Petroleum BV (the "Pok Option") requires the Directors to use their
judgement in selecting an appropriate valuation technique for
financial instruments not quoted in an active market. Valuation
techniques commonly used by market practitioners have been applied.
The Group has applied the Black-Scholes Model to value the Pok
Option (recognised as a financial liability at FVTPL). As a result,
the Group has made assumptions for the expected volatility and the
share price of Pokrovskoe Petroleum BV.
The fair value of the consideration received at the date of
exchange, including the fair values of the contingent consideration
and the Pok Option liability, together with the key assumptions
used therein, are shown in note 18.
Fair value of any retained interest
IFRSs require that the value of the Group's retained interests
in the joint controlled entities be recognised at the fair value of
the assets and liabilities as at the date of acquisition. In
accordance with normal industry practice, identifiable assets and
liabilities have been ascribed fair values, and the balance of the
fair value of the consideration has been allocated to the fair
value attributable to the oil and gas properties held by the
jointly controlled entities and the related hydrocarbon reserves.
The actual value that will be realised, if any, from them is
inherently uncertain and reflects a wide range of factors
(including, but not limited to, geological and geophysical factors,
future costs and commodity prices, the duration of the licence and
its terms and the availability of the financial and other resources
needed to progress exploration and development activities). Further
details of the carrying amount of assets and liabilities acquired
with the jointly controlled entities are provided in note 18.
(b) Other receivable recognised in relation to settlement with
Global Process Systems LLC ('GPS')
An amount of $30.0 million has been recognised in current other
receivables as at 31 December 2011, representing receivables from a
settlement agreement reached with GPS (2010: $33.0 million; 2009:
$30 million as non-current other receivable and $6.5 million as
current other receivable, see note 15).
During October 2009, a settlement was reached with GPS resolving
previous disputes which existed between the Group and GPS
concerning the manufacture and delivery of two gas treatment plants
for a total purchase price of $54.5 million.
The key commercial terms of the settlement provided for GPS
exclusively to market the two gas plants for a 10 month period and,
if a sale was achieved, for the Group to receive in stage payments
an aggregate cash consideration of $38.5 million. If the plants
were not sold within this period, then GPS agreed to take the
plants to stock and the Group would receive stage payments for an
aggregate cash consideration of $37.5 million.
The settlement also provided for the release by GPS of a
potential $10.9 million contractual claim against the Group for the
unpaid balance of the consideration for the plants. The amounts of
$43.5 million paid to GPS in respect of the gas plants had
previously been recognised as prepayments, as title to the gas
plants was to pass on delivery. As a result of the settlement,
these prepayments were then reclassified as receivables included
within other receivables at 31 December 2009. An impairment charge
of $6.0 million was provided in the year ended to 31 December 2009
to reduce the carrying value of the original prepayments to their
fair value, being the expected proceeds from the settlement.
GPS were not able to sell the plants within the stipulated
period, and so the stage payments terms apply. During the years to
31 December 2009, 2010 and 2011, $1.0 million, $3.5 million, and
$3.0 million were received from GPS respectively.
The first payment of $10.0 million of the remaining $30.0
million was due to be paid to the Group on 14 February 2011 but was
not received. A cure period subsequently expired on 18 April 2011
and on 19 July 2011 the Group rescinded the exclusive right of sale
of GPS and as such are able to market the gas plants
themselves.
In support of the carrying value of the amounts receivable under
the settlement agreement with GPS the Board commissioned a desktop
study of the plants by an independent third party in April 2011,
which included an estimate of value subject to certain assumptions
and caveats. In March 2012, the Board commissioned a different
independent third party to provide a report estimating cost to
build equivalent gas plants at today's prices. Having taken the
foregoing into account, the Board considers that the plants are
likely to be worth close to the $30.0 million receivable that
remains outstanding under the agreement.
The Group retains legal title to the plants until the final
payment has been received from GPS, with whom negotiations
continue. As such, the Group maintains insurance cover for the gas
plants against fire, accidental damage, and theft to the full value
of the $30.0 million receivable at the date of this report.
The Directors consider that the amount of $30.0 million due from
GPS under the settlement agreement as at 31 December 2011 is likely
to be fully recovered, as supported by the value of the plants as
described above and claim against GPS, therefore no impairment
charge has been recognised in the year then ended. However, given
the difficulties experienced to date in collecting the amounts due
from GPS, and inherent uncertainty involved in estimating the value
of the plants and the market to sell the plants, this is
judgemental.
(c) Impairment of E&E and PP&E
At 31 December 2011 the Group reviewed the carrying amounts of
its PP&E and E&E assets to determine whether there is any
indication that those assets have suffered an impairment loss. No
indicators of non-recoverability of the carrying amounts of the
above mentioned assets existed at the balance sheet date.
(d) Reserves
Commercial Reserves are proven and probable ('2P') oil and gas
reserves, which are defined as the estimated quantities of crude
oil, natural gas and natural gas liquids which geological,
geophysical and engineering data demonstrate with a specified
degree of certainty to be recoverable in future years from known
reservoirs and which are considered commercially producible. There
should be a 50 per cent statistical probability that the actual
quantity of recoverable Reserves will be more than the amount
estimated as proven and probable Reserves and a 50 per cent
statistical probability that it will be less.
Commercial Reserves used in the calculation of depreciation and
for impairment test purposes are determined using estimates of oil
and gas in place, recovery factors and future oil and gas prices.
Management base their estimate of oil and gas Reserves and
Resources upon the Report provided by independent advisers.
Although as at 31 December 2009 no 2P reserves were identified
at Zagoryanska, in August 2010 commercially recoverable gas was
identified in that field.
(e) Recoverability of VAT
The Group has significant receivables from the State Budget of
Ukraine relating to reimbursement of VAT arising on purchases of
goods and services from external service and product providers.
Although $2.8 million of Ukrainian VAT was recovered in the year to
31 December 2010, largely through a bond scheme initiated by the
Government of Ukraine, the Directors consider that this scheme was
one-off in nature. Management anticipates no significant cash
settlements of receivables from the State Budget.
The Group therefore recognises recoverable VAT only to the
extent that it is probable that VAT payable arising on the sales of
gas production will be sufficient to offset the VAT due from the
State within a reasonable period. Estimating the recoverability of
VAT requires management to make an estimate of the future revenues
in order to calculate amounts and timing of the VAT payable
available for offset. The Group will continue to use an approach
consistent with prior years by impairing Ukrainian VAT and
recognising the recovery in the period it has been made. A
provision of $18.2 million (2010: $18.9 million, 2009: $22.3
million) against Ukrainian VAT receivable has thus been recognised
as at 31 December 2011.
4. Business and geographical segments
The Directors consider there to be only one business segment,
the exploration and development of oil and gas revenues and only
one geographical segment, being Ukraine.
5. Dividend
The Directors do not recommend the payment of a dividend for the
year (2010: $nil).
6. Other operating income
2011 2010
$'000 $'000
--------------------------- ------ ------
Out of court settlements 2,144 9,283
Net foreign exchange gains 2,408 2,507
4,552 11,790
--------------------------- ------ ------
Out of court settlements in 2011 represent $2.1 million (2010:
$4.5 million received during the year from Smith Eurasia a former
supplier to the Group and $4.8 million from the Group's former
executives).
7. (Impairment)/reversal of impairment of other assets
2011 2010
$'000 $'000
------------------------------------ ------------- ------- -------
Inventories (note 14) 344 (1,360)
VAT recoverable (note 3(e)) (3,162) 2,301
------------------------------------------------------- ------- -------
(Impairment)/reversal of impairment
of other assets (2,818) 941
------------------------------------------------------- ------- -------
The carrying value of inventory as at 31 December 2011 and 2010
has been impaired to reduce it to net realisable value.
During the year a net impairment of $3.2 million (2010: $2.3
million reversal of impairment) in respect of Ukrainian VAT was
provided which comprised of VAT impairment on new program capital
expenditure and VAT recovery of historical balances through offset
of VAT liabilities arising on sales.
8. Profit for the year
The profit for the year has been arrived at after
charging/(crediting):
2011 2010
$'000 $'000
-------------------------------------------------- -------- -------
Depreciation of property, plant and equipment (2,411) (1,882)
Loss on disposal of property, plant and equipment (13) (160)
(Impairment)/reversal of impairment (note 7) (2,818) 941
Staff costs (4,587) (4,622)
Net foreign exchange gains 2,408 2,507
-------------------------------------------------- -------- -------
In addition to the depreciation of PP&E of $2.4million
(2010: $1.9 million) in the year ended 31 December 2011,
depreciation of $0.7 million (2010: $0.8 million) was capitalised
to E&E assets being depreciation of tangible assets used in
E&E activities.
9. Tax
2011 2010
$'000 $'000
----------------------- ------- -------
Current tax 132 74
Deferred tax (note 16) (605) (570)
----------------------- ------- -------
(473) (496)
----------------------- ------- -------
The Group's operations are conducted primarily outside the UK.
The most appropriate tax rate for the Group is therefore considered
to be 23% (2010: 25%), the rate of profit tax in Ukraine which is
the primary source of revenue for the Group. Taxation for other
jurisdictions is calculated at the rates prevailing in the
respective jurisdictions.
The taxation credit for the year can be reconciled to the profit
per the condensed consolidated income statement as follows:
2011 2011 2010 2010
$'000 % $'000 %
----------------------------------------- --------- ------ -------- -----
Profit before tax
Continuing operations 152,607 100 822 100
----------------------------------------- --------- ------ -------- -----
Tax credit at Ukraine corporation tax
rate of 23% (2010:25%) 35,100 23.0 205 25
Permanent differences (34,987) (22.9) 2,867 349
Foreign exchange on operating activities (387) (0.3) (462) (56)
Tax losses generated in the year not yet
recognised 128 0.2 1,639 200
Other temporary differences (566) (0.4) (2,364) (288)
Utilisation of deferred tax asset not
previously recognised on losses 136 0.1 (2,463) (300)
Effect of different tax rates - - 136 17
Prior year adjustment 35,100 23.0 205 25
Tax credit and effective tax rate for
the year (473) (0.3) (496) (58)
----------------------------------------- --------- ------ -------- -----
10. Profit per Ordinary share
Basic profit per Ordinary share is calculated by dividing the
net profit for the year attributable to owners of the Company by
the weighted average number of Ordinary shares outstanding during
the year. The calculation of the basic and diluted profit per share
is based on the following data:
2011 2010
Profit attributable to owners of the Company $'000 $'000
-------------------------------------------------------- -------- --------
Profit for the purposes of basic profit per share
being net profit attributable to owners of the Company 151,549 1,318
2011 2010
Number Number
Number of shares '000 '000
-------------------------------------------------------- -------- --------
Weighted average number of Ordinary shares for the
purposes of basic profit per share 231,092 231,092
Effect of dilutive potential ordinary shares:
Options and warrants outstanding 95 -
Weighted average number of Ordinary shares for the
purposes of diluted profit per share 237,187 231,092
2011 2010
cent cent
-------------------------------------------------------- -------- --------
Profit per Ordinary share
Basic 65.6 0.6
Diluted 65.6 0.6
-------------------------------------------------------- -------- --------
11. Intangible exploration and evaluation assets
Cost $'000
------------------------------------------------------- --------
At 1 January 2010 88,558
Additions 6,799
Change in estimate of decommissioning assets (82)
Transfer to property, plant and equipment (note 12) (32,517)
Exchange differences 530
------------------------------------------------------- --------
At 1 January 2011 63,288
Additions 17,387
Acquisition of jointly-controlled entities (note 18) 49,181
Disposal of subsidiaries (note 18) (33,955)
Change in estimate of decommissioning assets 301
Disposals (9)
Exchange differences (280)
------------------------------------------------------- --------
At 31 December 2011 95,913
------------------------------------------------------- --------
Impairment
------------------------------------------------------- --------
At 1 January 2010 88,558
Transfer to property, plant and equipment (note 12) (31,963)
Exchange differences 530
------------------------------------------------------- --------
At 1 January 2011 57,125
Disposal of subsidiaries (note 18) (26,984)
Exchange differences (258)
------------------------------------------------------- --------
At 31 December 2011 29,941
------------------------------------------------------- --------
Carrying amount
------------------------------------------------------- --------
At 31 December 2011 65,972
At 31 December 2010 6,163
At 31 December 2009 -
------------------------------------------------------- --------
Additions during the year include $0.5 million (2010: $0.6
million, 2009: $2.6 million) of capitalised depreciation of
development and production assets used in exploration and
evaluation activities.
12. Property, plant and equipment
Development
and
production
Other assets Total
Cost $'000 $'000 $'000
------------------------------------------------- ------ ------------ -------
At 1 January 2010 4,079 63,150 67,229
Additions 204 6,900 7,104
Transfer from intangible exploration and
evaluation (note 11) - 554 554
Transfer between property, plant and equipment (36) 36 -
Change in estimate of decommissioning assets - (400) (400)
Disposals (731) (3,170) (3,901)
Exchange differences 8 365 373
------------------------------------------------- ------ ------------ -------
At 1 January 2011 3,524 67,435 70,959
Additions 465 4,645 5,110
Acquisition of jointly-controlled entities
(note 18) 72 49,522 49,594
Disposal of subsidiaries (note 18) (421) (7,248) (7,669)
Transfer between property, plant and equipment (1) 1 -
Change in estimate of decommissioning assets - 107 107
Disposals (439) (811) (1,250)
Exchange differences (19) (331) (350)
------------------------------------------------- ------ ------------ -------
At 31 December 2011 3,181 113,320 116,501
------------------------------------------------- ------ ------------ -------
Accumulated depreciation and impairment
At 1 January 2010 1,585 14,660 16,245
Charge for the year 653 2,046 2,699
Disposals (436) (1,662) (2,098)
Exchange differences - 190 190
------------------------------------------------- ------ ------------ -------
At 1 January 2011 1,802 15,234 17,036
Disposal of subsidiaries (note 18) (313) (1,955) (2,268)
Charge for the year 583 2,513 3,096
Disposals (365) (279) (644)
Exchange differences (13) (79) (92)
------------------------------------------------- ------ ------------ -------
At 31 December 2011 1,694 15,434 17,128
------------------------------------------------- ------ ------------ -------
Carrying amount
At 31 December 2011 1,487 97,886 99,373
At 31 December 2010 1,722 52,201 53,923
At 31 December 2009 2,494 48,490 50,984
------------------------------------------------- ------ ------------ -------
13. Jointly controlled entities
The Group obtained the following interests in jointly controlled
entities, as a result of disposal of subsidiaries (refer to note
18) in 2011:
Country of incorporation
and operation Ownership
Name share % Activity
-------------------------------------- ------------------------ ---------- ---------------
LLC Industrial Company Gazvydobuvannya Ukraine 70 Exploration
LLC Astroinvest-Energy Ukraine 40 Exploration
Pokrovskoe Petroleum BV Netherlands 70 Holding company
Zagoryanska Petroleum BV Netherlands 40 Holding company
According to the shareholders' agreements, which regulate
activities of jointly controlled entities, all key decisions
require unanimous approval from the shareholders, therefore these
entities are jointly controlled. The following amounts are included
in the Group's Condensed Consolidated Financial Information as a
result of the proportionate consolidation as at 31 December 2011
(2010: $nil):
2011
$'000
-------------------------------------- --------
Intangible exploration and evaluation
assets 63,788
Property, plant and equipment 54,206
Non-current assets 117,994
Inventories 2,795
Trade and other receivables 3,612
Cash and cash equivalents 745
------------------------------------------ --------
Current assets 7,152
Deferred tax liabilities (11,543)
Long-term provisions (155)
------------------------------------------ --------
Non-current liabilities (11,698)
Trade and other payables (3,958)
Current provisions (388)
------------------------------------------ --------
Current liabilities (4,346)
------------------------------------------ --------
Net assets 109,102
------------------------------------------ --------
2011
For the period from 6 July to 31 $'000
December
-------------------------------------- --------
Revenue 1,591
Cost of sales (1,245)
Other administrative expenses (691)
Impairment of other assets (3,250)
Investment revenue 15
Finance costs (2)
Loss for the period (3,582)
Other comprehensive loss (402)
------------------------------------------ --------
(3,984)
----------------------------------------- --------
14. Inventories
2011 2010 2009
$'000 $'000 $'000
--------------------- ------- ------- --------
Cost 8,476 6,093 19,286
Impairment provision (1,920) (2,108) (10,491)
------------------------- ------- ------- --------
Carrying amount 6,556 3,985 8,795
------------------------- ------- ------- --------
The impairment provision as at 31 December 2011, 2010 and 2009
is made so as to reduce the carrying value of the inventories to
net realisable value.
15. Other financial assets
Other non-current receivables
2011 2010 2009
$'000 $'000 $'000
------------------ -------- ------ ------
Other receivables - - 30,000
- - 30,000
--------------------- -------- ------ ------
Trade and other receivables
2011 2010 2009
$'000 $'000 $'000
------------------ ------ ------ ------
Other receivables 61,816 38,085 7,446
VAT recoverable 127 139 535
Prepayments 4,308 435 604
---------------------- ------ ------ ------
66,251 38,659 8,585
--------------------- ------ ------ ------
All sales are made on a prepayment basis, so there are no trade
debtors.
Out of $61.8 million of other receivables $30.0 million as at 31
December 2011 (2010: $33.0 million, 2009: $30 million and $6.5
million) represent receivables from a settlement agreement with GPS
(note 3(b)), $29.1 million (2010: $nil, 2009: $nil) represents
deferred and contingent consideration for the disposal of two of
Group's subsidiaries to Eni (note 18).
VAT recoverable of $0.1 million (2010: $0.1 million, 2009: $0.5
million) relates to the UK VAT recoverable.
$4.3 million prepayments (2010: $0.4 million, 2009: $0.6
million) mostly relate to prepayments made to drilling contractors
in Ukraine and long lead materials for the drilling and work over
campaign.
The Directors consider that the carrying amount of the remaining
other receivables approximates their fair value and none of which
are past due except for the amounts due from GPS (see note
3(b)).
Cash and cash equivalents
Cash and cash equivalents as at 31 December 2011 of $65.0
million (2010: $36.4 million, 2009: $48.6 million) comprise cash
held by the Group and the Company. The Directors consider that the
carrying amount of these assets approximates to their fair
value.
Other financial assets
In 2011, the Group received $0.7 million held in escrow by the
Group's lawyers in Cyprus to support a bank guarantee provided to
the Cypriot court in relation to obtaining a freezing order in
Cyprus associated with the litigation case. In addition, a
short-term deposit of $0.4 million which related to the collateral
for short-term borrowings was also released in 2011.
16. Deferred tax
The following are the major deferred tax liabilities and assets
recognised by the Group and movements thereon during the current
and prior reporting period:
Temporary differences
$'000
------------------------------------------------------- ---------------------
Liability as at 1 January 2010 1,550
Deferred tax expense (570)
Exchange differences 2
------------------------------------------------------- ---------------------
Liability as at 1 January 2011 982
Acquisition of jointly-controlled entities (note 18) 11,153
Deferred tax expense (605)
Exchange differences 8
------------------------------------------------------- ---------------------
Liability as at 31 December 2011 11,538
------------------------------------------------------- ---------------------
At 31 December 2011, temporary differences of $6.0 million
(2010: $9.6 million, 2009: $3.5 million) existed in respect of
foreign exchange gains arising on net investments in foreign
subsidiaries for which deferred tax liabilities have not been
recognised. No deferred tax liabilities have been recognised in
respect of these differences because the Group is in a position to
control the timing of the reversal of the temporary differences and
it is probable that such differences will not reverse in the
foreseeable future.
At 31 December 2011, the Group had the following unused tax
losses available for offset against future taxable profits:
2011 2010 2009
$'000 $'000 $'000
----------- ------ ------ ------
UK 5,557 2,483 7,505
USA - - 5,322
Ukraine 66,410 69,451 63,827
------------------- ------ ------ ------
71,967 71,934 76,654
----------------- ------ ------ ------
Deferred tax assets have not been recognised in respect of these
tax losses owing to the uncertainty that profits will be available
in future periods against which they can be utilised.
The Group's unused tax losses of $5.6 million (2010: $2.5
million, 2009: $7.5 million) relating to losses incurred in the UK
are available to shelter future non-trading profits arising within
Cadogan Petroleum plc. These losses are not subject to a time
restriction on expiry.
Unused tax losses incurred by Ukraine subsidiaries amount to
$66.4 million (2010: $69.5 million, 2009: $63.8 million). Under
general provisions, these losses may be carried forward
indefinitely to be offset against any type of taxable income
arising from the same company of origination. Tax losses may not be
surrendered from one Ukraine subsidiary to another. However, in the
past, Ukrainian legislation has been imposed which restricted the
carry forward of tax losses. During 2011 a new tax legislation in
Ukraine was implemented which resulted in certain ambiguity about
the restriction to accumulated losses at 1 April 2011. Tax
authorities were disallowing the accumulated tax losses as of 1
April 2011 which resulted in a significant number of disputes for
the Ukrainian businesses. The Group has contested the tax
authorities' view in respect of the accumulated losses using
administrative procedures and court claims where applicable.
Therefore out of $66.4 million of accumulated tax losses in Ukraine
$58.6 million may potentially not be used.
There are further temporary differences arising on assets in
Ukraine for which deferred tax assets of $6.3 million (2010: $15.2
million, 2009: $19.1 million) have not been recognised due to the
uncertainty of future recovery.
17. Notes to the condensed consolidated cash flow statement
2011 2010
$'000 $'000
----------------------------------------------------------- --------- ---------
Operating profit 152,463 627
Adjustments for:
Depreciation of property, plant and equipment 2,411 1,882
Share-based payment charge 846 -
Gain on disposal of subsidiaries (note 18) (164,945) -
Other (gain) and losses (note 18) 3,299 -
(Reversal of impairment)/impairment of inventories (344) 1,360
Impairment/(reversal of impairment) of VAT recoverable 3,162 (2,301)
Loss on disposal of property, plant and equipment 13 160
Effect of foreign exchange rate changes (1,691) (91)
----------------------------------------------------------- --------- ---------
Operating cash flows before movements in working
capital (4,786) 1,637
(Increase)/decrease in inventories (2,563) 3,195
(Increase)/decrease in receivables (3,027) 68
Increase/(decrease) in payables and provisions 1,589 (4,426)
Decrease/(increase) in restricted cash 1,035 (339)
Cash (used in)/from operations (7,752) 135
Income taxes paid (133) (101)
----------------------------------------------------------- --------- ---------
Net cash (outflow)/inflow from operating activities (7,885) 34
----------------------------------------------------------- --------- ---------
18. Disposal of subsidiaries and acquisition of
jointly-controlled entities
On 6 July 2011 the Group completed the transaction with Eni,
selling a 30% interest in the share capital of Pokroskvoe Petroleum
BV (the parent company of the holder of the Pokrovskoe licence),
and a 60% interest in the share capital of Zagoryanska Petroleum BV
(the parent company of the holder of the Zagoryanska licence). Both
licences relate to the Group's operations in eastern Ukraine.
The consideration received comprised a cash payment of $38.1
million for its interest in Zagoryanska Petroleum BV and $0.2
million as the working capital adjustment for both the Zagoryanska
and Pokrovskoe licences. Eni is also committed to finance the
Pokrovskoe appraisal work programme to an amount of up to $36
million (including VAT).
Under the terms of the sale and purchase agreement and subject
to successful results from the Pokrovskoe appraisal work programme,
Eni also had the option under the agreement to acquire a further
30% of Pokrovskoe Petroleum BV for an additional payment of $40
million (the "Pok Option"). Eni will also pay additional amounts of
$15 million and $35 million (the "Contingent Consideration") should
the Group successfully acquire production licences on each of the
Pokrovskoe and Zagoryanska fields respectively. The Pokrovskoe
Contingent Consideration is only payable if the Pok Option is
exercised.
As at 6 July 2011, the net assets of the subsidiaries disposed
(Pokrovskoe Petroleum BV and Zagoryanska Petroleum BV), together
with the net assets acquired on the jointly-controlled entities
which are since being proportionately consolidated into the Group's
financial information, were as follows:
Net assets
acquired
by the
Pok Zag Total Group
$'000 $'000 $'000 $'000
----------------------------------------- ---------- ------- -------- -----------
Intangible exploration and evaluation
assets 6,970 - 6,970 49,181
Property, plant and equipment 1,177 4,223 5,400 49,594
Inventories 783 135 918 602
Trade and other receivables 3,463 530 3,993 2,636
Cash and cash equivalents 2,180 703 2,883 1,807
Deferred tax liabilities (3) - (3) (11,153)
Long-term provisions (90) (58) (148) (86)
Trade and other payables (1,223) (728) (1,951) (1,147)
Current provisions (353) (88) (441) (282)
12,904 4,717 17,621 91,152
Gain on disposal 65,012 99,933 164,945
----------------------------------------- ---------- ------- --------
Total consideration 28,624 62,790 91,414
Fair value of residual interest 49,292 41,860 91,152
----------------------------------------- ---------- ------- --------
Consideration satisfied by
Cash and cash equivalents - 38,115 38,115
Deferred consideration received in
cash in 2011 20,915 - 20,915
Deferred consideration/(reimbursement)
outstanding at the balance sheet
date 4,410 (1,572) 2,838
Fair value of the Pok Option (4,200) - (4,200)
Contingent consideration 7,499 26,247 33,746
----------------------------------------- ---------- ------- --------
28,624 62,790 91,414
Net cash inflow arising on disposal
----------------------------------------- ---------- ------- --------
Consideration received in cash and
cash equivalents 20,915 38,115 59,030
Less: net cash and cash equivalents
disposed of (654) (422) (1,076)
----------------------------------------- ---------- ------- --------
20,261 37,693 57,954
The consideration received from the Eni has been measured at the
aggregate of the cash received, the deferred consideration (of
which $20.9 million was received in cash during the second half of
the year), the reimbursement payable to Eni in respect to part of
Zagoryanska 3 well cost, which is to be transferred to the
licence-holder at no cost to Eni, the Contingent Consideration and
the fair value of the Pok Option.
The Contingent Consideration was calculated applying probability
assumptions for the potential payment, which will be trigger upon
successful acquisition of the production licences. A probability of
60% and 90% was applied to Pokrovskoe and Zagoryanska fields
respectively based on management's assessment of the appraisal and
exploration risks. The Contingent Consideration was discounted
using a rate 10% which is management's view that reflects the
market assessment of time value of money and the expected timing of
the payment.
A financial liability was recognised in relation to the issuance
of the Pok Option to Eni. The fair value of the Pok Option was
calculated, using the Black-Scholes model. The variables and
assumptions used in computing the fair value of the Pok Option are
based on the Directors' best estimates. The value of an option
varies with different variables of certain subjective assumptions.
The inputs into the model were as follows:
As at 6 July
2011
Pokrovskoe Petroleum BV's price ($ million) 28.5
Exercise price ($ million) 40.0
Expected volatility (%) 70
Expected term (years) 0.75
Risk free rate (%) 10
Expected dividend yield (%) -
----------------------------------------------------- ------------
The share price was determined on the basis of the price paid by
Eni for 30% interest in Pokrovskoe licence, rounded to the nearest
half million US dollars.
The exercise price and the expected term of the Pok Option are
set out in the terms of the agreement. The expected volatility was
determined on the basis of the Company's share price volatility and
compared to the shares of comparable companies (companies in
evaluation and exploration stage). The risk free rate was
determined with reference to the yield on US bonds with duration
similar to the expected contractual life of the Pok Option and
country premium risk. The expected dividend yield is based on the
planned dividend policy of Pokrovskoe Petroleum BV.
Changes in the fair value of other financial
assets and liabilities
Financial liability Pok Option 4,200
Contingent Consideration (7,499)
--------------------------------------------- --------
(3,299)
--------------------------------------------- --------
The above changes in the fair value of the Pok Option and the
Contingent Consideration have been presented in the Other gains and
losses line in the Condensed Consolidated Income Statement for the
year.
As of 31 December 2011 management consider that there was no
indication of Eni's intention to exercise the Pok Option and in
March 2012 Eni informed the Group that they will not exercise the
Pok Option (refer to note 20). Therefore, management's estimate of
the fair value of financial liability, evaluated at $4.2 million at
the date of acquisition, decreased to $nil as at 31 December 2011.
On the same basis, the fair value of the Contingent Consideration
decreased from $7.5 million to $nil as at 31 December 2011, for
which the exercise of the Pok Option was a prerequisite.
19. Commitments and contingencies
Joint activity agreements
The Group has interests in nine licences for the conduct of its
exploration and development activities within Ukraine. Each licence
is held with the obligation to fulfil a minimum set of exploration
activities within its term and is summarised on an annual basis,
including the agreed minimum amount forecasted expenditure to
fulfil those obligations. The activities and proposed expenditure
levels are agreed with the government licensing authority.
The minimum required future financing of exploration and
development work on fields under the licence obligations are as
follow:
2011 2010 2009
$'000 $'000 $'000
--------------------------- ------ ------ ------
Within one year 7,440 15,700 21,474
Between two and five years 44,469 69,500 52,473
--------------------------- ------ ------ ------
51,909 85,200 73,947
--------------------------- ------ ------ ------
A greater level of capital expenditure could, however, be
incurred in the above period to achieve the Group's corporate
targets. $3.7 million within one year capital commitments (2010:
nil, 2009: nil) and $7.4 million between two and five years capital
commitments (2010: nil, 2009: nil) relate to joint ventures
activities.
20. Events after the balance sheet date
Pokrovskoe update
On 9 March 2012 the Group has been advised by Eni that after
analysis of the results for the Pokrovskoe 1 and Pokrovskoe 2a
wells that Eni do not intend to exercise their option to acquire a
further 30% of the share capital of Pokrovskoe Petroleum BV. The
option formed part of the transaction entered into with Eni in July
2011 (note 18).
As advised in the Company's announcement dated 16 February 2012
the logs acquired during the drilling programme indicated the
presence of hydrocarbons in the lower part of the well. A decision
had been taken to deepen the Pokrovskoe 2a well by approximately
350 metres. Whilst pulling out of the hole the running string
became stuck and subsequent fishing operations with the limited
equipment available in country did not allow the running tool to be
recovered. Cadogan management will continue to evaluate the most
effective option, amongst those available, to re-enter the
well.
This information is provided by RNS
The company news service from the London Stock Exchange
END
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