We could not find any results for:
Make sure your spelling is correct or try broadening your search.
Register for streaming realtime charts, analysis tools, and prices.
| Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
|---|---|---|---|---|---|
| Cadogan Energy Solutions Plc | LSE:CAD | London | Ordinary Share | GB00B12WC938 | ORD 3P |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 2.40 | 2.20 | 2.60 | 2.40 | 2.40 | 2.40 | 2,844 | 08:00:00 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| Drilling Oil And Gas Wells | 7.55M | 1.26M | 0.0052 | 4.62 | 5.86M |
From Oct 2019 to Oct 2024
Cadogan Petroleum PLC ANNUAL FINANCIAL REPORT FOR THE YEAR ENDED 31 DECEMBER 2012 The Directors present the Annual Financial Report for the year ended 31 December 2012. The full Annual Report and Accounts will shortly be available via the Company's website at www.cadoganpetroleum.com
KEY POINTS
Cadogan Petroleum plc is an independent oil and gas exploration,development
and production company with onshore gas, condensate and oil assets in Ukraine.
Key developments during 2012:
- The completion of a major transaction between Eni S.p.A("Eni"), NAK Nadra
Hot Features
Premium
and Cadogan Petroleum plc ("Cadogan" or "the Company")resulting in establishment
of LLC Westgasinvest ("WGI"), which holds a portfolio of 10 licences for
unconventional gas covering a total area of 3,795square kilometres, and subsequent
farm-out to Eni of 50.01%. Cadogan retains 15% interest in WGI
- Sale of two gas plants for $29.5 million and settlement of all associated litigation with Global Process Systems ("GPS") completed in April 2013
- Total impairment of $86.3 million mainly related to the Zagoryanska license
- Total capital expenditure of $22.3 million (2011: $21.3 million) during the
year of which $4.1 million was funded by the deferred consideration from the
disposal of 30% of Cadogan's interest in the Pokrovskoe licence to Eni in 2011
- Net cash and cash equivalents at year-end of $42.4 million
(2011: $65.0 million). Cash and cash equivalents at 24 April of $67.2 million
Cadogan Petroleum plc +380 44 584 4979
Bertrand des Pallieres
Chief Executive Officer
Cantor Fitzgerald Europe +44 (0) 20 7894 7000
David Porter
Richard Redmayne
Bankside Consultants +44 (0) 207 367 8888
Simon Rothschild
CHAIRMAN'S STATEMENT
2012 proved a challenging year for Cadogan. Revenue, largely reflecting production
from the Group's Cheremkhivska and Debeslavetska fields decreased to $5.7 million from
$7.0m in 2011. The loss before tax was $92.9 million, after a $83.6 million impairment
taken largely as a result of the unsuccessful drilling and work over programme at
Zagoryanska licence.
At 31 December 2012 the Company had cash of $42.4m. Since the year end this has
significantly improved due to the recently reported settlementwith GPS, leaving
the Company in a strong financial position, with $67.2 million cash and cash
equivalents at 24 April 2013, to achieve the ambitious targets it has set for
itself in 2013.
Operations
As reported in the half year report, in the first half of 2012 the Group finalised
a completeoverhaul of its technical operations and sub-surface explorations teams,
bringing in over 120 years combined experience in major Independent Oil Companies.
Under their supervision, the Group has undertaken a thorough re-evaluation of all
its assets, enabling the Group to revise its list of targets for its short - medium
term plan of activity. Whilst a principal focus for 2013 remains the reduction of
risk and maximization of existing production potential, we have identified new and
economically viable exploration and production potential in most of our existing
licences.
Shale Gas
Within the framework of the Cooperation Agreement with Eni, signed in October 2011,
Cadogan completed its Share Purchase Agreement in October 2012 with Nak Nadra Ukrayny
("Nadra") and Eni, for the exploration and development of unconventional gas in Ukraine,
whereby Eni has acquired a stake in the joint venture company established by Nadra
and Cadogan, Ukrainian company LLC Westgasinvest. Under the transaction, Eni acquires
50.01% of LLC Westgasinvest from the joint venture parties and will fund an
initial
exploration program.
The Board
In January 2012, Adelmo Schenato joined the Board as Chief Operating Officer after
a 35 year career at Eni, the Italian integrated energy business, where he served
in senior global and regional positions. His global roles at Eni included Well
Operations Research and Development ("R&D") and Technical Management, and Vice
President Health Safety, Environment and Sustainability. His regional roles included
General Manager for Tunisia, Gabon and Angola as well as CEO of Eni's Italian gas
storage company. Since joining Cadogan, Adelmo has been responsible for recruiting
a new technical team. The Chief Executive covers this in more detail in his review.
During the year both Alessandro Benedetti and Ian Baron resigned from the Board,
although Mr Benedetti continues to advise the Company in a consulting capacity.
I thank them both for their contribution to the Company.
Litigation
As previously announced, Cadogan has reached a settlement with Global Process Systems ("GPS") by way of an Agreement with GPS for the purchase of two gas
processing plants for the sum of $29.5 million. The completed sale represents a full and final settlement of all claims and liabilities between the two parties, and marks to the final part in a long running litigation around the Company that had proved a substantial distraction for management.
Annual General Meeting
I look forward to meeting shareholders at the Company's Annual General Meeting to be held at 10.30am on Thursday 27 June 2013 at Chandos House, 2 Queen Anne
Street, London W1G 9LQ. Strategy and Prospects
Currently all Cadogan's assets are based in Ukraine. The programme approved for the
current year concentrates on increasing production from existing licenses without
the capital intensity necessitated by the drilling of the major wells have been
identified in Pokrovskoe. Furthermore, potential operations on the shale gas licenses
that form our Joint Venture with Nadra Ukrayny and Eni S.p.A are under evaluation
and whilst the Board continues to assess opportunities both in Ukraine,
where our existing license base continues to prove attractive to companies wishing
to get involved in the sector in Ukraine, and overseas in regions where the Company
has existing relationships and can offer significant, existing expertise.
Zev Furst
Non-executive Chairman
24 April 2013
CHIEF EXECUTIVE'S REVIEW
Since the recruitment of Adelmo Schenato in January 2012, much effort has been
given to the recruitment and indeed overhaul of the Group's technical operations
and sub-surface explorations teams. A review of the Group's past exploration and
drilling campaigns suggests that results would be improved by a deeper understanding
of the geology of our license areas and amore thorough technical preparation by way
of seismic acquisition and interpretation. Taken together this will limit the risk
of futuredisappointing results of the type seen in our most recent drilling activity.
As part of the refocusing of the Group's technical capabilities, Emidio Valmori has
been recruited as Business Development Technical Adviser and Luciano Kovacic as Geology
and Geophysics ("G&G") manager, heading technical teams that will assess future operations.
Emidio headed Eni's geology team in Italy after stints in China, Senegal, Angola and Egypt.
Luciano also comes from Eni with a strong technical background, having worked in Libya,
Algeria and the UK and as part of that Group's R&D activities, introducing 4D technologies
to that company. In addition, Giovanni Ferraro has been recruited as Production and
Development ("P&D") Technical Consultant Advisor. His past experience has included the
start-up of the Beniboye oil field (Nigerian Agip Oil Company Limited ("NAOC")) and
management of 2 large oil fields (one onshore, one offshore) in Libya, with total production
of over 300,000 bopd. Together this represents formidable technical capability at Cadogan as
it seeks to put past frustrations behind it.
Operations at Pokrovskoe are currently suspended following disappointing results on
Pokrovskoe 1 and 2a, the latter afflicted by mechanical problems. However the reassessment of
the area by our new technical teams has identified residual hydrocarbon potential within the
license area and operations might be resumed upon finalisation of a positive re-evaluation.
The Group's Zagoryanska 1, 2 and 3 and 11 wells have all been suspended, with only Zagoryanska 3
having the potential for commercial production. At the Zagoryanska 11 well, a data acquisition
programme is underway, the results of which will be used to re-focus operations on the license.
However, in order to reflect the disappointing outcome of the 2012 activity, the Board has
decided to impair the carrying value of the assets related to the Zagoryanska license to nil.
On the Monastyretska license in Western Ukraine, operations at the Blazhiv 1 well are
showing positiveresults and the re-entry of another two, existing wells is under evaluation.
In the meantime work with our joint venture partner Eni on assessing the Zagoryanska,
Pirkovskoe and Pokrovskoe licences continues.
More generally, Ukrainian operations in 2013 are expected to focus on shallow prospects in our western assets that do not require the capital intensity of our eastern, deep prospects.
Extremely promising gas shows are evident from logging and drilling data at Borynya 3. It is our intention to re-enter the well in June 2013 using the Group's Astro Service rig. Other new and promising areas for investment are already under scrutiny and the Group will report on these in due course. The Group continues to assess opportunities in Ukrainian acreage in the Black Sea. Shale Gas LLC Westgasinvest, in which Cadogan holds a 15% shareholding, currently holds subsoil rights to nine unconventional (shale) gas license areas in the Lviv Basin of Ukraine, totalling approximately 3,800 square kilometres of acreage. The Lviv Basin is considered to be one of the most attractive basins in Europe for the exploration of unconventional gas,being a continuation of the Lublin Basin in Poland which has already attracted substantial interest from the hydrocarbon industry. Studies are ongoing with the aim to defining the best area where to start the operations for the first exploration well. The potential Shell and the Ukrainian government on acreage in the country.
Service Business
The Ukrainian oil & gas sector currently lacks adequate investment in technical services. Partly in order to remedy this, Cadogan has invested limited amounts in oilfield services in Ukraine, in particular in agreementswith Medes in Ukraine on the provision of mud treatment services and an Exclusive Cooperation agreement with AVA (Newpark Group) on drilling fluids services. This initiative is already generating so far limited, but positive,financial benefits and we expect this trend to continue and even increase over time.
Financial Position
Cadogan remains in a strong financial position, despite recent disappointing drilling results and the impairment taken on our Zagoryanska license, with no debt and with substantial cash resources, particularly following the recent finalisation of the litigation with GPS. One feature of the Financial Review is the continuing cutting of costs, with cost of sales decreasing to $4.2 million in 2012 from $6.3 million in 2011 and other administrative expenses decreasing to $10.8 million in 2012 from $11.6 million in 2011. This is a continuing process as the Board seeks to reshape the Group.
Strategy
In my last Chief Executive's Review in the 2011 Annual Report I underlined the potential that Ukraine holds for oil & gas exploration and production, a factor that is being increasingly recognised by the entry of major oil companies to the Country. Not only Eni, with whom Cadogan shares joint ventures, but also Exxon, Chevron, Shell, OMV, Vitol have all entered Ukraine since last year's report. As predicted, it should contribute to a significant re-rating of Ukraine's oil and gas sector and valuations over the next quarters and years. Against this background Cadogan, which is longestablished and highly regarded in Ukraine, is positioned to take advantage also on new ventures both on-shore and off-shore. Bertrand des Pallieres Chief Executive Officer 24 April 2013 OPERATIONS REVIEW
In 2012 the Group held working interests in nine conventional (2011: 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 infrastructures. The Group's primary focus during 2012 was on the four most promising licences in which 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 December 2012)
Working Licence
interest (%) Licence Expiry type (1)
Major licences
40.0 Zagoryanska April 2014 E&D
70.0 Pokrovskoe August 2016 E&D
100.0 Pirkovskoe October 2015 E&D
99.8 Bitlyanska December 2014 E&D
Minor licences
99.2 Debeslavetska (2) November 2026 Production
99.2 Debeslavetska (2) September 2016 E&D
53.4 Cheremkhivska (2) May 2018 Production
100.0 Slobodo-Rungerska April 2016 E&D
99.2 Monastyretska November 2014 E&D
(1) E&D = Exploration and Development.
(2) Debeslavetska and Cheremkhivska licences are held by WGI, in which the Group
has a 15% interest. The Group has 99.2% and 53.4% of economic benefit in
conventional activities in Debeslavetska and Cheremkhivska licences respectively
through Joint Activity Agreements ("JAA").
In addition to above licences the Group has a 15% interest in WGI, which holds the
Reklynetska, Zhuzhelianska, Cheremkhivsko-Strupkivska, Debeslavetska Exploration,
Debeslavetska Production, Baulinska, Filimonivska,Kurinna, Sandugeyivska and
Yakovlivska licences for unconventional activities.
Zagoryanska licence
The Group has a 40 per cent working interest in the Zagoryanska licence area.
The Zagoryanska licence previously reported 96.4 mmboe of Contingent Resources.
In light of the results during 2012 campaign, a thoroughre-evaluation is ongoing.
The exploration and development licence covers 49.6 square kilometres and in
2009 the licence was extended until April 2014. The work obligations have been
fulfilled.
Following the joint venture ("JV") formed with Eni in July 2011, under which Eni
acquired a 60 per cent interest in the Zagoryanska licence, a work-over and drilling
plan was implemented to verify and exploit the potentially productive intervals.
- The Zagoryanska 1 well work-over opened and tested the V19 and V18 intervals; the first
produced no commercial gas and the second was found to be water bearing; the well is
suspended.
- The Zagoryanska 2 well work-over tested the V25, V24 and V23 intervals with no commercial gas produced; the well is suspended.
- The Zagoryanska 8 well work-over, which was intended to test the V20, V18, V17
and V16 intervals, was unable to recover the previous fish-in-hole due to the very
poor casing conditions; the well is suspended.
- Production from Zagoryanska 3 well is tied into the Group's Zagoryanska gas
treatment plant. Average monthly production rates during 2012 were 28 mcm/day gas
and 4.3 t/day condensate. At the end of 2012, the well was worked-over to retrieve
the parted tubing, in order to open the V19 interval and the bottom of the producing
V18 interval. V19 showed some gas but due to poor petro-physical properties production
was not economically sustainable.The well is currently under monitoring to assess the
possibility to recover production from V18.
- The Zagoryanska 11 well was spud-in on 7 March 2012. In spite of severe hole instability
problems and multiple equipment failures, the well operations were successfully completed
in 166 days versus 142 in AuthorisationFor Expenditure ("AFE"). The V24, V23, V19, and
V18 intervals were tested with no commercial gas; the well is suspended.
As at 31 December 2012 the Group assessed the recoverability of the carrying value of the
development and production assets related to the Zagoryanska licence. This has resulted in
the impairment of the mentioned assets to nil (for details refer to Note 4(b) of the
Consolidated Financial Statements).
An extensive revision and reinterpretation of the 3D seismic and Geological and Geophysical
("G&G") studies to value and price all the possible reserves potential is ongoing. Studies
are in an early stage and not yet sufficiently mature to enable the Company
to define future actions. Pokrovskoe licence The Group holds a 70 per cent working interest in the Pokrovskoe licence which holds 51.1 mmboe of Prospective Resources (2011: 51.1 mmboe). The exploration licence covers 49.5 square kilometres and the initial licence was extended until August 2016. The interpretation of the 3D seismic, completed early in 2010 confirmed the presence of a prospect with four-way closure at the Lower Visean and the deeper Tournasian levels, beneath both the Pokrovskoe 1 and Pokrovskoe2 suspended well locations; both wells encountered strong indications of gas during drilling and logging. After the JV with Eni that acquired 30 per cent of the Group's Pokrovskoe licence, the drilling of the Pokrovskoe 2a well indicated the presence of hydrocarbons but due to mechanical problems the well was suspended with a future option of re-entry. On 9 March 2012 the Group was advised by Eni that, following their analysis of the results for the Pokrovskoe 1 and Pokrovskoe 2a wells, they did not intend to exercise the option to acquire the additional 30 per cent. Notwithstanding Eni's decision not to exercise the option, Eni continues to hold a 30 per cent share in the Pokrovskoe licence. On the basis of the results and the clear indication of the presence of a positive hydrocarbons generation and migration system, it was decided to continue the investigation of the area. The preliminary 3D seismic re-interpretation has been successfully concluded. The Pokrovskoe licence shows several interesting objects and encouraging signs for a possible programme of activity that can be defined and eventually proposed for the Board's approval in the final quarter of 2013.
Pirkovskoe licence
The Group has a 100 per cent working interest in the Pirkovskoe licence which holds 2.5 mmboe of Proven and Probable Reserves (2011: 2.4 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; and (d) calculation of the potential hydrocarbon reserves. The Pirkovskoe 1 and Pirkovskoe 2 wells are currently suspended. An extensive revision and reinterpretation of the 3D seismic and G&G studies is ongoing to value and price all the possible reserves potential. Studies are in the early stage and not yet sufficiently mature to define future actions. The Group owns the Krasnozayarska gas treatment plant located in the Pirkovskoe licence area, which is connected to the UkrTransGas system and is temporarily servicing a nearby local operator. Bitlyanska licence area The Bitlyanska exploration and development licence covers an area of 390 square kilometres with the Group's interest at 99.8 per cent. There are three hydrocarbon discoveries in this licence area, namely Bitlyanska, Borynya and Vovchenska. The Borynya and Bitlyanska fields hold 219.2 mmboe (gross) (2011: 219.2 mmboe) and 117.3 mmboe (gross) (2011: 117.3 mmboe) of Contingent Resources respectively, while no Reserves and Resources have been attributedto the depleted Vovchenska field. In the 1970s drilling of the Borynya 1 resulted in a blow out and Borynya 2 reportedly tested gas at very high rates. In 2009 Cadogan drilled the Borynya 3 well, proximal to these two Soviet era wells. Several intervals showed very interesting evidence of gas during drilling which was confirmed by logging. Due to the difficult hole conditions and the increasingly high pore pressure gradient, three very limited open hole drill stem tests were run. Inparticular, from one of the secondary reservoir targets at around 3,600 metres gas was tested at a maximum flow rate of 128,000 cubic metres per day. At a drilled depth of 5,325 metres the well Borynya 3 was suspended for futureevaluation having encounte red several 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, at that time, the presence of an active hydrocarbon system was established, the recent 2D seismic data interpretationdemonstrates that the well was poorly located in relation to any structural closure. In 2010 a 2D survey was completed in the southern part of thelicence area 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.
Based on the new prospect structures model, an internal re-evaluation and estimate of the resources in Bitlyanska and Borynya areas was concluded.
Since the year end, the re-entry and testing of Borynya 3 well has been approved by the Board which also approved the purchase of existing seismic data on the Vovchenska area and the acquisition of 50 linear kilometres of 2D seismic lines to better access and re-estimate the existing potential. 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 (2011: 0.2 mmboe). The field is currently producing 95.0 boepd (2011: 84.0 boepd). The new compressor unit and dehydration facilities for production optimisation have been delivered as per the programme.
- Debeslavetska Exploration licence area
An exploration licence surrounding the Debeslavetska Production licence area which
is considered quite promising in shallow gas production potential. Following the
positive preliminary results (Amplitude Versus Offset ("AVO") and Inversion Analysis),
the purchase of existing seismic data and the acquisition of 80 linear kilometres of
2D seismic lines to assess and estimate the reserves is forecast in 2013; in addition,
one shallow well could be drilled by the year end. The satellite radar waves "InSar"
technology will be applied to understand and predict the gas reservoirs' behaviour.
- Cheremkhivska Production licence area
A production licence containing 0.1 mmboe of 3P Reserves (2011: 0.1 mmboe). This licence is currently producing 23.9 boepd (2011: 32.8 boepd).
Potential gas production from shallow intervals seems to be challenging from this licence. Preliminary studies have not yet been conclusive but a contingent programme to purchase existing seismic data and the acquisition of 30 linear kilometres of 2D seismic lines to assess and estimate the reserves will be considered in 2013.
- Slobodo-Rungerska licence area
An exploration and development licence, with no booked Reserves and Resources (2011: 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. Ongoing re-evaluation is in its preliminary stage.
- Monastyretska licence area
An exploration and development licence, with no booked Reserves or Resources (2011: nil). The Blazhiv 1 well was re-entered and a sucker rod pump was installed; the well is currently producing at a rate of 20-25 boepd and is being monitored to ensure that production is optimised.
FINANCIAL REVIEW
Overview
In 2012 the Group focused on concluding drilling and testing of the Pokrovskoe 2a well on
the Pokrovskoe field and, together with its joint venture partner Eni, the work-over
campaign at the Zagoryanska field. In addition to the ground work on the JV fields
(Zagoryanska and Pokrovskoe), an extensive re-assessment of the Group's assets has
been carried out by the sub-surface team which continues into 2013.
Revenue has decreased from $7.0 million in 2011 to $5.7 million in 2012. The unsuccessful
programme on the Zagoryanska licence has resulted in a $83.6 million (2011: $nil) impairment
of Property, Plant and Equipment ("PP&E") assets and a receivable from Eni that was treated
as contingent consideration, which contributed to the loss for the year of $93.1 million
(2011: $153.1 million profit). This loss was reflected by a corresponding decrease in the net
asset position as at 31 December 2012 to $194.3 million from $283.0 million as at 31 December 2011.
The cash position of $42.4 millionat 31 December 2012 has decreased from $65.0 million at
31 December 2011 mainly as the result of capital expenditure on the Zagoryanska licence and
ongoing costs.
Income statement
Loss before tax was $92.9 million (2011: profit of $152.6 million). Revenues of $5.7 million
(2011: $7.0 million) comprised sales of gas from the Debeslavetska and Cheremkivska fields,
the Zagoryanska 3 well and other revenue from the service business. Of the $1.3 million
decrease in revenues $2.4 million relates to a decrease from the Zagoryanska licence
mainly due to the fact that the Group proportionately consolidated 40% of Zagoryanska
revenues throughout whole of 2012 while revenues were fully consolidated into the Group's
income statement during the first half of 2011. Revenues from sales of hydrocarbons from
other licences have increased by $0.3 million, largely due to the gas price increase in 2012.
In addition, $0.8 million from oil field services provided to third parties by the Group
contributed to 2012 revenue. Cost of sales, which represents production royalties and taxes,
depreciation and depletion of producing wells and direct staff costs decreased to $4.2 million
in 2012 from $6.3 million in 2011 to give a gross profit of $1.5 million (2011: $0.7 million).
- Other administrative expenses of $10.8 million (2011: $11.6 million) comprise other staff costs,
professional fees, Directors' remuneration and depreciation charges on non-producing property,
plant and equipment. In addition to recurring administrative expenses, $0.5 million (2011: $1.2
million) of professional costs were incurred in relation to litigation, $0.1 million of professional
fees were incurred in relation to the transaction with Eni on WGI (2011: $0.9 million in relation
to the transaction with Eni on the Pokrovskoe and Zagoryanska licences).
- Impairment charges amounting to a total of $86.3 million (2011: $2.8 million) comprised:
$58.9 million (2011: $nil) impairment of PP&E assets of which $47.1 million was recorded in respect
of the fair value uplift of the Group's 40% non-controlling interest in Zagoryanskoe recorded after
the disposal of 60% in 2011; $24.7 million (2011: $nil)impairment of contingent consideration from
Eni recorded in 2011 in respect of obtaining the Zagoryanska production licence; and $2.7 million
(2011: $2.8 million) net impairment charges comprised of $2.4 million impairment (2011: $3.2 million)
of Ukrainian VAT and $0.3 million provision for inventory (2011: $0.3 million release of provision).
- Other gains of $5.4 million represents the profit the on contributions of licences, being the
difference between the fair value of the licences contributed in return for the 15% interest in WGI
and nil net book value of the licences in the Group's books at the date of contribution.
- Other operating expenses of $2.9 million (2011: $4.6 million income) includes $0.6 million
income (2011: $2.1 million) related to recoveries from former management and suppliers and
$3.6 million of net foreign exchange losses (2011: $2.4 million gain) related to revaluation
of USD denominated monetary assets of the Group's UK entities which have a GBP as the functional currency.
Cash flow statement
The Consolidated Cash Flow Statement below shows expenditure of $6.2 million (2011: $16.9 million)
on intangible Exploration and Evaluation ("E&E") assets and $15.7 million (2011: $4.4 million)
on PP&E. In addition, the Group received $4.1 million (2011: $58.0 million) deferred consideration
that had been outstanding as at 31 December 2011 in connection with the disposal of interest in
Pokrovskoe BV to Eni in 2011.
Balance sheet
As at 31 December 2012, the Group had net cash and cash equivalents of $42.4 million
(2011: $65.0 million). Intangible E&E assets of $78.2 million (2011: $66.0 million) represent the
carrying value of the Group's investment in exploration and appraisal assets as at 31 December 2012,
including $40.3 million of fair value uplift on the valuation of the 70% jointly-controlled interest
in the former subsidiary which holds the Pokrovskoe licence, and $5.4 million of the associated fair
value of the licences contributed in return for the 15% interest in WGI. The PP&E balance of $46.6
million at 31 December 2012 (2011: $99.4 million, including $40.0 million of the fair value uplift
on the valuation of the 40% jointly-controlled interest in the former subsidiarywhich holds
Zagoryanska licence), reflects the cost of developing fields with commercial reserves and
bringing them into production. Trade and other receivables of $35.5 million (2011: $66.3 million)
includes $30.0 million (2011: $30 million) receivables in respect of the settlement with GPS
(refer to note 4(a) to the Consolidated Financial Statements), $3.1 million (2011: $1.7 million)
as the non-consolidated portion of receivables from jointly controlled entities, and $0.9 million
(2011: $4.3 million) in prepayments.
Key performance indicators
The Group monitors its performance in implementing its strategy with reference to clear targets set out for four 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 increase the Group's basic and diluted earnings per share;and
- to reduce the number of lost time incidents.
The Group's performance in 2012 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 2012 2011
Financial KPIs Average production (working interest basis (1) boepd 181 297 2P reserves (2)
mmboe 2.6 2.6
Realised price per 1,000 cubic metres (3) $ 486.0 395.1 Basic and diluted earnings per share (4) cents (40.3) 65.6 Non-financial KPIs Lost time incidents (5)
Incidents 0 2
(1) Average production is calculated as the average daily production during the year.
(2) Quantities of 2P reserves as at 31 December 2011 and 2012 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 2011 and 2012 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 equity holders of the parent company 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 31 to the Consolidated Financial Statements.
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.
RISKS AND UNCERTAINTIES
There are a number of potential risks and uncertainties, which could have a material impact on the Group's long-term performance and could cause the actual results to differ materially from expected and historical results. Executive management review the potential risks and then classify them as having a high impact, above $5 million, medium impact above $1 million but below $5 million, and low impact below $1 million. They also assess the likelihood of these risks occurring. Risk mitigation factors are reviewed and documented based on the level and likelihood of occurrence. The Audit Committee reviews the risk register and monitors the implementation of improved risk mitigation procedures via Executive management.
The Group has analysed the following categories as key risks:
Risk Mitigation
Operational risks
Health, Safety and Environment
("HSE")
The oil and gas industry by its The Group ensures that there nature conducts activities which is a proper HSE system in can be seriously impacted by place and demands that health, safety & environmental management, staff and incidents. Serious incidents can contractors adhere to it. have not only a financial impact The system ensures that the but can also damage the Group's Group meets Ukraine reputation and the opportunity to legislative standards in undertake further projects. full and achieves
international standards to
the maximum extent possible.
Drilling operations
The technical difficulty of The incorporation of drilling wells in the Group's detailed sub-surface locations and equipment
analysis into a robust
limitations can result in the engineered well design and
unsuccessful completion of the work programme, with
well. appropriate procurement
procedures and on site
management competence aims
to minimise risk.
Production and maintenance
Some of the Group's facilities All plants are operated at
have been inherited, and although standards above the Ukraine
fully checked were not installed minimum legal requirements.
under our supervision and there Operative staff is chosen
is a risk of plant failure. for its experience and
receives supplemental
training to ensure that
facilities are operated and
maintained at a high
standard.
There is a risk that production Service providers are
or transportation facilities can rigorously reviewes at the tender stage
fail due to poor performance of and are monitored during the contract period.
the Group's suppliers and control
of some facilities being with
other governmental or commercial
organisations.
Work over and abandonment
Certain of the Group's wells were Work programmes are designed
drilled by the State and other to assess the status of the
private companies and will be wells and any work that is
worked over. There is a risk that not safe or is not
Cadogan's activities fail because technically feasible will be
of problems inherited with these abandoned. Qualified
sites. professionals will be used
to design a step-by-step
approach to re-entering old
wells.
Any well stock that is not All sites that are abandoned will be restored
considered satisfactory for and re-cultivated to meet or exceed standards
purpose or poses an environmental required by the relevant environmental control
hazard will need to be abandoned. and control authorities and in compliance with recognised
international standards.
Sub-surface risks
The success of the business All externally provided and historic data is
relies on accurate and detailed rigorously examined and discarded when appropriate.
analysis of the sub-surface. This New data acquisition is considered and appropriate
can be impacted by poor quality programmes implemented, but historic data can be reviewed
data, either historic or recently and reprocessed to improve overall knowledge base.
gathered and limited coverage.
Certain information provided by
external sources may not be
accurate.
Some local contractors may not Detailed supervision of local contractors by Cadogan
acquire data accurately, and management is followed. Plans are discussed well in
choice of locally available advance with both local and international contractors in an
equipment or contractors of a effort to ensure that appropriate equipment is available.
desirable standard.
Data can be misinterpreted All analytical outcomes are
leading to the construction of challenged internally and
inaccurate models and subsequent peer reviewed.
plans. Interpretations are carried
out on modern geological
software. A staff training
programme has been put in
place.
Financial risks
The Group may not be successful The Group performs a review in achieving commercial
of its O&G assets for
production from an asset and impairment on annual basis.
consequently the carrying values The Group considers on an
of the Group's oil and gas assets annual basis whether to
may not be recovered through commission a Competent
future revenues. Person's Report (`CPR') from
an independent reservoir
engineer. The CPR provides
an estimate of the Group's
reserves and resources by
field/licence area. As no
new production has been
achieved during 2012,
Management has decided not
to commission new CPR during
2012.
As part of the annual budget
approval process the Board
considers and evaluates
projects for the forthcoming
year and considers the
appropriate level of risk.
The Board has approved a
work programme for 2013.
Further attempts to bring in
partners and mitigate the
Group's risk exposure are
underway.
There is a risk that insufficient The Group manages the risk
funds are available to meet by maintaining adequate cash
development obligations to reserves and by closely
commercialise the Group's major monitoring forecast and
licences. actual cash flow, as well as
short and longer funding
requirements. Management
reviews these forecasts
regularly and updates are
made where applicable and
submitted to the Board for
consideration.
The farm-out campaign to
conserve cash and mitigate
risk will continue through
2013.
The Group could be impacted by These risks are mitigated by failing to meet regulatory employing suitably qualified reporting requirements in the UK, professionals who, working and statutory tax and filing with advisers when needed, requirements in both Ukraine and are monitoring regulatory the UK.
reporting requirements, and
who ensure that timely
submissions are made.
The Group operates primarily in Clear authority levels and Ukraine, an emerging market, robust approval processes where certain inappropriate are in place, with stringent business practices may from time controls over cash to time occur. This includes management and the tendering bribery, theft of Group property and procurement process. and fraud, all of which can lead Adequate office and site to financial loss.
protection is in place to
protect assets. Anti-bribery
policies are in place.
The Group is at risk from changes Revenues are received in UAH
in the economic environment both and expenditure is made in
in Ukraine and globally which can UAH, but funds are
cause foreign exchange movements, transferred in US dollars to
changes in the rate of inflation Ukraine. The Group continues
and interest rates and lead to to hold most of its cash
credit risk in relation to the reserves in the UK in US
Group's key counterparties. dollars with some GBP
deposits. Cash reserves are
placed with leading
financial institutions which
are approved by the Audit
Committee. The Group is
predominantly a US dollar
denominated business.
Foreign exchange risk is
considered a normal and
acceptable business exposure
and the Group does not hedge
against this risk.
Refer to note 29 to the
Consolidated Financial
Statements for detail on
financial risks.
Corporate risks
Should the Group fail to comply The Group designs a work
with licence obligations there is programme and budget to
a risk that its entitlement to ensure that all licence
the licence will be lost. obligations are met. The
Group engages proactively
with government to
re-negotiate terms and
ensure that they are not
onerous.
Ukraine is an emerging market and The Group minimises this
as such the Group is exposed to risk by maintaining the
greater regulatory, economic and funds in international banks
political risks than other outside Ukraine and by
jurisdictions. Emerging economies continuously maintaining a
are generally subject to a working dialogue with the
volatile political environment regulatory authorities.
which could adversely impact on
Cadogan's ability to operate in
the market.
The Group's success depends upon The Group periodically
skilled management, technical and reviews compensation and
administrative staff. The loss of contract terms of its staff.
service of critical members from
the Group's team could have an
adverse effect on the business.
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 2012, due to insufficient new
information arising 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 subsequent actual production.
Summary of Reserves
As of 31 December 2012
Working interest basis
Gas Condensate Oil
bcf mmbbl mmbbl
Proved and Probable Reserves at 1 January 2012 11.1 0.6 - Production
(0.2)* - - Change in working interest 0.4 - -
Proved and Probable Reserves at 31 December 2012 11.3 0.6 - Possible Reserves at 1 January 2012 and 31 19.5 1.5 - December 2012
*During 2012 the Group produced an additional 0.1bcf (2011: 0.6bcf) of natural gas and 0.01mmbl (2011: 0.02 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 2012
Working interest basis
Gas Condensate Oil Total
bcf mmbbl mmbbl mmboe
Contingent Resources at 1
January 2012 2,252.0 92.8 - 498.1
Change in working interest 105.3 5.1 - 24.1
Contingent Resources at 31
December 2012 2,357.3 97.9 - 522.2
Reserves are assigned only to the Pirkovskoe, Debeslavetska and Cheremkhivska fields.
Although commercial production has been achieved at the Zagoryanska field no 2P Reserves
have been booked as at 31 December 2012 (2011: nil) as the Group did not receive an updated
Competent Person's Report ("CPR") to independently confirm the Reserves quantities.
Contingent Resources are assigned to the Zagoryanska, Pirkovskoe, Borynya and Bitlya fields, where development is contingent on further appraisal.
Prospective Resources of 165.9 bcf (2011: 165.9 bcf) of gas and 5.9 mmbl (2011: 5.9 mmbl) of condensate are attributed to the Pokrovskoe field (reflecting Cadogan's working interest), where there has not yet been a production test.
CORPORATE RESPONSIBILITY
The Group considers the sustainability of its business as a key and competitive element of its strategy. Meeting the expectations of our stakeholders is the way in which we secure our licence to operate, and to be recognised in the values we declare is the best added value we can bring in order to profitably prolong our business. The Board recognises that the health and safety of its employees and of the communities and protecting the environment it impacts are the key drivers for the sustainable development of the Company's activity. Our Code of Ethics and the adoption of internationally recognised best practices and standards are our and our employees' references for conducting our operations. Our activities are carried out in accordance with a policy manual, endorsed by the Board, which has been disseminated to all staff. The manual includes policies on business conduct and ethics, anti-bribery, the acceptance of gifts and hospitality, and whistleblowing. The Group's Health, Safety and Environment Manager reports directly to the Chief Operations Officer. His role is to ensure that the Group has developed suitable procedures and that operational management have incorporated them into daily operations, and he has the necessary level of autonomy and authority to discharge his duties effectively and efficiently. The Board believes that health and safety procedures and training across the Group should be to the standard expected in any company operating in the oil and gas sector. Accordingly, it has set up a Committee to review and agree health and safety initiatives and report back on progress. The monthly management report to the Board contains a full report on both health and safety, and environmental issues, and key safety and environmental issues are discussed by the Executive Management. The Health, Safety and Environment Committee report can be found in the Company's full Annual Report and Accounts.
Health, safety and environment
The Group has developed an integrated Health, Safety and Environmental ("HSE") management system.
The system aims, by a continuous improvement programme, to ensure that a safety and environmental
protection culture is embedded in the organisation. The HSE management system ensures that both
Ukrainian and international standards can be met with the Ukrainian HSE legislation requirements
taken as an absolute minimum although the international requirements are in the main met or exceeded.
All the Group's local operating companies in East and West Ukraine have all the necessary documentation
and systems in place to ensure compliance with Ukrainian legislation.
A proactive approach to the prevention of incidents has been in place throughout 2012, which relies
on an observation cards system and reliable near-miss reporting. Staff training on HSE matters
is recognised as the key factor to generate continuous improvement. In-house training is provided
to help staff meet international standards and follow best practice. At present, special attention
is being given to training on risk assessments, incident reporting and investigation, as well as
hazard and operational (`HAZOP') studies to ensure that international standards are maintained even
if they exceed those required by Ukrainian legislation.
The Board monitors lost time incidents as a key performance indicator of the business, to reasonably
verify that the procedures in place are robust. The Board has benchmarked safety performance against
the HSE performance index measured and published annually by the International Association of
Oil & Gas Producers. In 2012, the Group recorded a total of 708,918 man hours worked. There were no
Lost Time Incidents (`LTIs') recorded in 2012 and a total of over one million man hours have been
worked without an LTI since the previous incident was recorded in July 2011.
Vehicle safety and driving conduct remain among the Company's priorities in controlling hazards
and preventing injuries. As of the end of 2012, the Company has a recorded almost 7.5 million
kilometres driven without an LTI.
The European Bank for Reconstruction and Development ("EBRD") was, until February 2013, a
substantial shareholder in the Company and closely monitored the environmental and community
aspects of the Group's activities. An environmental report was submitted to the EBRD each year
summarising the Group's compliance with local HSE regulation and standards. The EBRD required
and reviewed the results of audits undertaken by external consultants which were used to generate
an environmental action plan. The Group remains highly conscious of the need to optimise its
activities in order to reduce their environmental impact of its operations. In 2012, a number
of steps were taken in this direction, such as replacing the old compressor unit at the
Debeslavetske Gas Treatment Facility, which benefitted the environment by decreasing fuel consumption
and air emissions while improving the overall efficiency of the plant.
Starting from 2013, the Company is committed to prepare a baseline to assess and monitor its
environmental performance, namely, the consumption of electricity and industrial water and
fuel consumption by cars, plants and other work sites. At the same time, development of
procedures necessary for improving the Group's environmental performance will begin,
taking into account the requirements of any applicable policies, such as forthcoming UK
regulations on mandatory reporting of greenhouse gas emissions.
Employees
Certain of the Group's operations are undertaken by sub-contractors' specialists having the technical knowledge required for complex wells' drilling operations. Local interest is part of the Company's sustainable development policy and wherever possible local staff is recruited and procedures are in place to ensure that all recruitments are undertaken on a transparent and fair basis with no discrimination between applicants. Each operating company has its own Human Resources staff to ensure that the Group's employment policies are properly implemented and followed. As required by Ukrainian legislation, Collective Agreements are in place with the Group's Ukrainian subsidiary companies which provide an agreed level of staff benefits and other safeguards for employees. The Group's Human Resources policy covers key areas such as equal opportunities, wages, overtime and non-discrimination. All staff are aware of the Group's grievance procedures. Sufficient levels of health insurance are provided by the Group to employees to ensure they haveaccess to good medical facilities. Each employee's training needs are assessed on an individual basis to ensure that their skills are adequate to support the Group's operations, and to help them to develop.
Community
The Group's activities are carried out in rural areas of Ukraine and the Board is aware of its responsibilities to the local communities in which the Group operates and from which some of the employees are recruited. At current operational sites, management works with the local councils to ensure that the impact of operations is as low as practicable by putting in place measures to mitigate their effect. Key projects undertaken include improvement of the road infrastructure in the area, which provides easier access to the operational sites while at the same time minimising inconvenience for the local population and allowing improved road communications in the local communities. Specific charitable activities are undertaken for the direct benefit of local kindergartens, schools, sporting facilities and medical services, as well as other community-focused facilities. All activities are followed and supervised by managers who are given specific responsibility for such tasks. In 2012 the Group spent $37,000 (2011: $153,882) predominantly in contributions for road repairs, purchasing equipment and furniture for schools, local hospitals, housing and public utilities. The Group's local companies see themselves as part of the community and are involved not only with financial assistance, but also with practical help and support. The recruitment of local staff generates additional income for areas that otherwise are predominantly dependent on the agricultural sector.
STATEMENT OF DIRECTORS' RESPONSIBILITIES
The full Annual Report contains the following statements regarding responsibility for the financial statements and business review included therein.
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. The Directors are required under that law to prepare the Group financial statements in accordance with International Financial Reporting Standards (`IFRSs') as adopted by the European Union and Article 4of the IAS regulation and have also elected to prepare the Parent Company financial statements under IFRSs as adopted by the European Union. Under company law, the Directors must not approve the accounts unless they are satisfied that they give a true and fair view of the state of affairs of the Company and Group and of the profit or loss for that period. In preparing the Company and Group's financial statements, International Accounting Standards(`IAS') Regulation requires that Directors:
- properly select and apply accounting policies;
- present information, including accounting policies, in a manner that provides relevant, reliable, comparable and understandable information;
- provide additional disclosures when compliance with the specific requirements in IFRSs are insufficient to enable users to understand the impact of particular transactions, other events and conditions on the entity's financial position and financial performance; and
- make an assessment of the Company's and Group's ability to continue as a going concern.
The Directors are responsible for keeping proper accounting records that are sufficient to show and explain the Company and Group's transactions and disclose with reasonable accuracy at any time the financial position of the Company and Group and enable them to ensure that the financial statements comply with the Companies Act 2006. They are also responsible for taking such steps as are reasonably open to them to safeguard the assets of the Company and Group and to prevent and detect fraud and other irregularities. Under applicable law and regulations, the Directors are also responsible for preparing a Directors' Report (including Business Review), Directors' Remuneration Report and Corporate Governance Statement that comply with that law and those regulations. The Directors are responsible for the maintenance and integrity of the corporate and financial information included on the Company's website, www.cadoganpetroleum.com. Legislation in the United Kingdom governing the preparation and dissemination of the financial statements may differ from legislation in other jurisdictions.
Responsibility Statement of the Directors in respect of the Annual Report
We confirm to the best of our knowledge:
(1) the financial statements, prepared in accordance with International Financial Reporting Standards as adopted by the European Union, give a true and fair view of the assets, liabilities, financial position and profit or loss of the Company and the undertakings included in the consolidation as a whole; and (2) the management report, which is incorporated into the Directors' Report, includes a fair review of the development and performance of the business and the position of the Company and the undertakings included in the consolidation taken as a whole, together with a description of the principal risks and uncertainties that they face.
On behalf of the Board
Zev Furst
Chairman
24 April 2013
NON-STATUTORY ACCOUNTS
The financial information set out below does not constitute the Company's statutory
accounts for the years ended 31 December 2012 and 2011 but is derived from those accounts.
Statutory accounts for 2011 have been delivered to the Registrar of Companies, and those
for 2012 will be delivered in due course.
The Auditors have reported on the accounts for 2012; their report was (i) unqualified,
(ii) did not include a reference to any matters to which the Auditors drew attention by
way of emphasis without qualifying their report and (ii) did not contain a statement under
Section 498 (2) or (3) of the Companies Act 2006. The text of the Auditor's report can be
found in the Company's full Annual Report and Accounts on the Company's website
www.cadoganpetroleum.com
CONSOLIDATED INCOME STATEMENT
For the year ended 31 December 2012
2012 2011
Notes $'000 $'000
CONTINUING OPERATIONS
Revenue 5 5,653 6,981
Cost of sales (4,158) (6,264)
Gross profit 1,495 717
Administrative expenses:
Other administrative expenses (10,783) (11,634)
Impairment of oil and gas assets 8 (83,584) - Impairment of other assets
8 (2,684) (2,818)
(97,051) (14,452)
Gain on acquisition of jointly
controlled entity/disposal of
subsidiaries 28 5,417 164,945
Other losses 28 (3,299)
Other operating (expenses)/income 6 (2,940) 4,552
Operating (loss)/profit (93,079) 152,463
Investment revenue 12 128 155
Finance income/(costs) 13 67 (11)
(Loss)/Profit before tax (92,884) 152,607
Tax (charge)/credit 14 (252) 473
(Loss)/Profit for the year 9 (93,136) 153,080
Attributable to:
Owners of the Company (93,106) 151,549
Non-controlling interest (30) 1,531
(93,136) 153,080
(Loss)/Profit per Ordinary share cents cents
Basic and diluted 15 (40.3) 65.6
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
For the year ended 31 December 2012
2012 2011
$'000 $'000
(Loss)/Profit for the year (93,136) 153,080
Unrealised currency translation differences 4,384 (2,067)
Total comprehensive (loss)/profit for the (88,752) 151,013
year
Attributable to:
Owners of the Company (88,722) 149,482
Non-controlling interest (30) 1,531
(88,752) 151,013
CONSOLIDATED BALANCE SHEET
As at 31 December 2012
2012 2011
Notes $'000 $'000
ASSETS
Non-current assets
Intangible exploration and
evaluation assets 16 78,231 65,972
Property, plant and equipment 17 46,627 99,373
124,858 165,345
Current Assets
Inventories 20 5,177 6,556
Trade and other receivables 21 35,537 66,251
Cash and cash equivalents 21 42,404 65,039
83,118 137,846
Total assets 207,976 303,191
LIABILITIES
Non-current liabilities
Deferred tax liabilities 22 (4,553) (11,538)
Long-term provisions 24 (414) (548)
(4,967) (12,086)
Current liabilities
Trade and other payables 23 (7,793) (7,552)
Current provisions 24 (939) (524)
(8,732) (8,076)
Total liabilities (13,699) (20,162)
NET ASSETS 194,277 283,029
EQUITY
Share capital 25 13,337 13,337
Retained earnings 298,290 389,734
Cumulative translation reserves (119,400)(123,784)
Other reserves 1,682 3,344
Equity attributable to owners of the 193,909 282,631
Company
Non-controlling interest 368 398
TOTAL EQUITY 194,277 283,029
The consolidated financial statements of Cadogan Petroleum plc, registered in England and Wales no. 5718406, were approved by the Board of Directors and authorised for issue on 24 April 2013. They were signed on its behalf by: Bertrand Des Pallieres Chief Executive Officer 24 April 2013
The notes form an integral part of these financial statements.
CONSOLIDATED CASH FLOW STATEMENT
For the year ended 31 December 2012
2012 2011
Note $'000 $'000
Net cash outflow from operating activities 27 (5,609) (7,885)
Investing activities Disposal of subsidiaries (note 28) 4,142 57,954
Purchases of property, plant and equipment (15,749) (4,402) Purchases of intangible exploration and
(6,239) (16,893) evaluation assets Proceeds from sale of property, plant and 688 87
equipment
Interest received 128 155
Net cash (used in)/from investing activities (17,030) 36,901
Financing activities Proceeds from short-term borrowings - (371) Net cash used in financing activities - (371) Net (decrease)/increase in cash and cash (22,639) 28,645
equivalents
Effect of foreign exchange rate changes 4 (25) Cash and cash equivalents at beginning of 65,039 36,419
year
Cash and cash equivalents at end of year 42,404 65,039
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
For the year ended 31 December 2012
Other reserves
Cumulative Share- Non-
Share Retained translation based Reorga- controlling
capital earnings reserves payment nisation interest Total
$'000 $'000 $'000 $'000 $'000 $'000 $'000
As at 1 January 2011 13,337 237,963 (121,717) 1,131 1,589 (1,133) 131,170
Share-based payments (note 26) - 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 1 January 2012 13,337 389,734 (123,784) 1,755 1,589 398 283,029
Share-based payments (note 26) - 1,662 - (1,662) - - -
Net loss for the year - (93,106) - - - (30) (93,136)
Exchange translation differences on
foreign operations - - 4,384 - - - 4,384
As at 31 December 2012 13,337 298,290 (119,400) 93
1,589 368 194,277
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS For the year ended 31 December 2012
1. General information
Cadogan Petroleum plc (the `Company', together with its subsidiaries the `Group'), is registered in England and Wales under the Companies Act. The address of the registered office is Ibex House 42-47 Minories, London EC3N 1DX. The nature of the Group's operations and its principal activities are set out in the Operations Review and the Financial Review above.
2. Adoption of new and revised Standards
In the current year, the following new and revised Standards and Interpretations are effective but have not had any significant impact on the financial statements:
IFRS 3 (amended) Business Combinations
IAS 24 (amended) Related Party Disclosures
IAS 32 (amended) Classification of Rights Issues
IFRIC 19 Extinguishing Financial Liabilities with Equity Instruments
IFRIC 14 (amended) Prepayments of a Minimum Funding Requirement
At the date of authorisation of the financial statements, the following Standards and Interpretations which have not been applied in the financial statements were in issue but not yet effective (and in some cases had not yet been adopted by the EU):
IFRS 1 (amended) Severe Hyperinflation and Removal of Fixed Dates for First-time Adopters
IFRS 7 (amended) Disclosures - Transfers of Financial Assets and offsetting of Financial Assets and Financial Liabilities
IFRS 9 Financial Instruments
IFRS 10 Consolidated Financial Statements
IFRS 11 Joint Arrangements
IFRS 12 Disclosure of Interests in Other Entities
IFRS 13 Fair Value Measurement
IAS 1 (amended) Presentation of Items of Other Comprehensive Income
IAS 12 (amended) Deferred Tax: Recovery of Underlying Assets
IAS 19 (revised) Employee Benefits
IAS 27 (revised) Separate Financial Statements
IAS 28 (revised) Investments in Associates and Joint Ventures
IFRIC 20 Stripping Costs in the Production Phase of a Surface Mine
The Directors do not expect that the adoption of the standards listed above will have a material impact on the financial statements of the Group in future periods, except as follows:
- IFRS 9 will impact both the measurement and disclosures of financial instruments;
- IFRS 10 may impact the amounts reported in the consolidated financial statements as it provides a single basis for consolidation with a new definition of control;
- IFRS 11 may result in changes in the accounting of the Group's jointly-controlled entities that are currently accounted for using proportionate consolidation. Under IFRS 11, a joint arrangement is classified as either a joint operation or a joint venture, and the option to proportionately consolidate joint ventures has been removed. Interests in joint ventures must be equity accounted;
- IFRS 12 will impact the disclosure of interests Cadogan Petroleum plc has in other entities such as subsidiaries, joint arrangements, associates and/or unconsolidated structured entities;
- IFRS 13 will impact the measurement of fair value for certain assets and liabilities as well as the associated disclosures; and
- IAS 1 (amendment) requires to be grouped in other comprehensive income based on whether those items are subsequently reclassified to profit or loss.
Beyond the information above, it is not practicable to provide a reasonable estimate of the effect of these standards until a detailed review has been completed.
3. Significant accounting policies
(a) Basis of accounting
The financial statements have been prepared in accordance with International Financial Reporting Standards (`IFRS') as issued by theInternational Accounting Standards Board (`IASB') and as adopted by the European Union (`EU'), and therefore the Group financial statements comply with Article 4 of the EU IAS Regulation. The financial statements have been prepared on the historical cost convention basis, except for share-based payments, accounting for the WGI transaction, and other financial assets and liabilities, which have been measured at fair values, and using accounting policies consistent with IFRS. The principal accounting policies adopted are set out below:
(b) 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 above. The financial position of the Group, its cash flow and liquidity position are described in the Financial Review above. The Group's cash balance at 31 December 2012 was $42.4 million (2011: $65.0 million) with no external debt (2011: $nil) and the Directors believe that the funds available at the date of the issue of these financial statements 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 annual financial statements.
(c) Basis of consolidation
The consolidated financial statements incorporate the financial statements of the Company and entities controlled by the Company (its subsidiaries) made up to 31 December each year. Control is achieved where the Company has the power to govern the financial and operating policies of an investee entity so as to obtain benefits from its activities. The results of subsidiaries acquired of or disposed of during the year are included in the consolidated income statement from the effective date of acquisition or up to the effective date of disposal, as appropriate. Where necessary, adjustments are made to the financial statements of subsidiaries to bring accounting policies used into line with those used by the Group. All intra-group transactions, balances, income and expenses are eliminated onconsolidation. Non-controlling interests in subsidiaries are identified separately from the Group's equity therein. Those interests of non-controlling shareholders that are present ownership interests entitling their holders to a proportionate share of net assets upon liquidation may be initially measured at fair value or at the non-controlling interests' proportionate share of the fair value of the acquiree's identifiable net assets. The choice of measurement is made on an acquisition-by-acquisition basis. Other non-controlling interests are initially measured at fair value. Subsequent to acquisition, the carrying amount of non-controlling interests is the amount of those interests at initial recognition plus the non-controlling interests' share of subsequent changes in equity. Total comprehensive income is attributed to non-controlling interests even if this results in the non-controlling interests having a deficit balance. Changes in the Group's interests in subsidiaries that do not result in a loss of control are accounted for as equity transactions. The carrying amount of the Group's interests and the non-controlling interests are adjusted to reflect the changes in their relative interests in the subsidiaries. Any difference between the amount by which the non-controlling interests are adjusted and the fair value of the consideration paid or received is recognised directly in equity and attributed to the owners of the Company. When the Group loses control of a subsidiary, the profit or loss on disposal is calculated as the difference between (i) the aggregate of the fair value of the consideration received and the fair value of any retained interest and (ii) the previous carrying amount of the assets (including goodwill), less liabilities of the subsidiary and any non-controlling interests. Amounts previously recognised in other comprehensive income in relation to the subsidiary are accounted for (i.e. reclassified to profit or loss or transferred directly to retained earnings) in the same manner as would be required if the relevant assets or liabilities are disposed of. The fair value of any investment retained in the former subsidiary at the date when control is lost is regarded as the fair value on initial recognition for subsequent accounting under IAS 39 Financial Instruments: Recognition and Measurement or, when applicable, the costs on initial recognition of an investment in an associate or jointly controlled entity.
(d) Business combinations
The acquisition of subsidiaries is accounted for using the acquisition method. The cost of the acquisition is measured at the aggregate of the fair values, at the date of exchange, of assets given, liabilities incurred or assumed, and equity instruments issued in exchange for control of the acquiree. Acquisition-related costs are recognised in profit or loss as incurred. The acquiree's identifiable assets, liabilities and contingent liabilities that meet the conditions for recognition under IFRS 3 Business Combinations are recognised at their fair value at the acquisition date, except for non-current assets (or disposal groups) that are classified as held for resale in accordance with IFRS 5 Non-Current Assets held for sale and Discontinued Operations, which are recognised and measured at fair value less costs to sell.
(e) Investments in jointly-controlled entities
A jointly-controlled entity is an entity in which the Group holds a long-term interest and shares joint control over the operating and financial decisions with one or more other venturers under a contractual arrangement. Jointly-controlled entities are accounted for using proportionate consolidation, which combines the Group's share of the results of the jointly-controlled entity on a line-by-line basis with similar items in the Group's financial statements. When a Group entity transacts with its jointly-controlled entity, profits and losses resulting from the transactions with the jointly-controlled entity are recognised in the Group's consolidated financial statements only to the extent of interests in the jointly-controlled entity that are not related to the Group.
(f) Revenue recognition
Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for hydrocarbon products and services provided in the normal course of business, net of discounts, value added tax (`VAT') and other sales-related taxes.
Sales of hydrocarbons are recognised when the title has passed.
Interest income is accrued on a time basis, by reference to the principal outstanding and at the effective interest rate applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset's net carrying amount on initial recognition.
To the extent that revenue arises from test production during an evaluation
programme, an amount is charged from evaluation costs to cost of sales, so as to reflect a zero net margin.
(g) Foreign currencies
The individual financial statements of each Group company are presented in the currency of the primary economic environment in which it operates (its functional currency). The functional currency of the Company is pounds sterling. For the purpose of the consolidated financial statements, the results and financial position of each Group company are expressed in US dollars, which is the presentation currency for the consolidated financial statements. In preparing the financial statements of the individual companies, transactions in currencies other than the functional currency of each Group company (`foreign currencies') are recorded in the functional currency at the rates of exchange prevailing on the dates of the transactions. At each balance sheet date, monetary assets and liabilities that are denominated in foreign currencies are retranslated into the functional currency at the rates prevailing on the balance sheet date. Non-monetary assets and liabilities carried at fair value that are denominated in foreign currencies are translated at the rates prevailing at the date when the fair value was determined. Non-monetary items that are measured in terms of historical cost in a foreign currency are not retranslated. Exchange differences are recognised in the profit or loss in the period in which they arise except for exchange differences on monetary items receivable from or payable to a foreign operation for which settlement is neither planned nor likely to occur, which form part of the net investment in a foreign operation, and which are recognised in the foreign currency translation reserve and recognised in profit or loss on disposal of the net investment. For the purpose of presenting consolidated financial statements, the results and financial position of each entity of the Group are translated into US dollars as follows:
i. assets and liabilities of the Group's foreign operations are translated at the closing rate on the balance sheet date;
ii. income and expenses are translated at the average exchange rates for the period, unless exchange rates fluctuate significantly during that period, in which case the exchange rates at the date of the transactions are used; and iii. all resulting exchange differences arising, if any, are recognised in other comprehensive income and accumulated equity (attributed to non-controlling interests as appropriate), transferred to the Group's translation reserve. Such translation differences are recognised as income or as expenses in the period in which the operation is disposed of.
Goodwill and fair value adjustments arising on the acquisition of a foreign entity are treated as assets and liabilities of the foreign entity and translated at the closing rate.
The relevant exchange rates used were as follows:
Year ended 31 Dec 2012 1US$ = £
Closing rate 0.6185
Average rate 0.6597
(h) Taxation
The tax expense represents the sum of the tax currently payable and deferred tax.
The tax currently payable is based on taxable profit for the year. Taxable profit differs from net profit as reported in the income statement 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 balance sheet date. Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the balance sheet liability method. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised. Such assets and liabilitiesare not recognised if the temporary difference arises from the initial recognition of goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the taxable profit nor the accounting profit. Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries and associates, and interests in joint ventures, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future. The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered. Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled or the asset is realised. Deferred tax is charged or credited in the income statement, except when it relates to items charged or credited in other comprehensive income, in which case the deferred tax is also dealt with in other comprehensive income. Deferred tax assets and liabilities are offset when there is a legally enforceable right to set off current tax assets against current tax liabilities and when they relate to income taxes levied by the same taxation authority and the Group intends to settle its current tax assets and liabilities on a net basis.
(i) Property, plant and equipment and other intangible assets
Property, plant and equipment (`PP&E') and other intangible assets are carried at cost less accumulated depreciation and any recognised impairment loss.
Depreciation and amortisation is charged so as to write off the cost or valuation of assets, other than land, over their estimated useful lives, using the straight-line method, on the following bases: Buildings 4%
Fixtures and equipment 10% to 30%
The gain or loss arising on the disposal or retirement of an asset is determined as the difference between the sales proceeds and the carrying amount of the asset and is recognised in income.
(j) Impairment of tangible assets excluding goodwill
At each balance sheet date, the Group reviews the carrying amounts of its tangible assets to determine whether there is any indication that those assets have suffered an impairment loss. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment loss (if any). Where the asset does not generate cash flows that are independent from other assets, the Group estimates the recoverable amount of the cash-generating unit to which the asset belongs. The recoverable amount is the higher of fair value less costs to sell and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset for which the estimates of future cash flows have not been adjusted. If the recoverable amount of an asset (or cash-generating unit) is estimated to be less than its carrying amount, the carrying amount of the asset (cash-generating unit) is reduced to its recoverable amount. An impairment loss is recognised as an expense immediately. Where an impairment loss subsequently reverses, the carrying amount of the asset (cash-generating unit) is increased to the revised estimate of its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset (cash-generating unit) in prior years. A reversal of an impairment loss is recognised as income immediately.
(k) Intangible exploration and evaluation assets
The Group applies the full cost method of accounting for intangible exploration and evaluation (`E&E') expenditure as set out in IFRS 6 Exploration for and Evaluation of Mineral Resources. Under the full cost method of accounting, expenditure made on exploring for and evaluating oil and gas properties is accumulated and initially capitalised as an intangible asset, by reference to appropriate cost centres being the appropriate oil or gas property. E&E assets are then assessed for impairment on a cost pool basis as described below. E&E assets comprise costs of (i) E&E activities which are in progress at the balance sheet date, but where the existence of commercial Reserves has yet to be determined (ii) E&E expenditure which, whilst representing part of the E&E activities associated with adding to the commercial Reserves of an established cost pool, did not result in the discovery of commercial Reserves. Costs incurred prior to having obtained the legal rights to explore an area
are expensed directly to the income statement as incurred.
Exploration and Evaluation costs
E&E expenditure is initially capitalised as an E&E asset. Payments to acquire the legal right to explore, costs of technical services and studies, seismic acquisition, exploratory drilling and testing are also capitalised as intangible E&E assets. Tangible assets used in E&E activities (such as the Group's vehicles, drilling rigs, seismic equipment and other property, plant and equipment) are normally classified as PP&E. However, to the extent that such assets are consumed in developing an intangible E&E asset, the amount reflecting that consumption is recorded as part of the cost of the intangible asset. Such intangible costs include directly attributable overheads, including the depreciation of PP&E items utilised in E&E activities, together with the cost of other materials consumed during the exploration and evaluation phases.
E&E assets are not amortised prior to the conclusion of appraisal activities.
Treatment of E&E assets at conclusion of appraisal activities
Intangible E&E assets related to each exploration property are carried forward, until the existence (or otherwise) of commercial Reserves has been determined. If commercial Reserves have been discovered, the related E&E assets are assessed for impairment on a cost pool basis as set out below and any impairment loss is recognised in the income statement. The carrying value, after any impairment loss, of the relevant E&E assets is then reclassified to the development and production assets within PP&E.
Intangible E&E assets that relate to E&E activities that are determined not to have resulted in the discovery of commercial Reserves remain capitalised as
intangible E&E assets at cost less accumulated amortisation, subject to meeting a pool-wide impairment test in accordance with the accounting policy for impairment of E&E assets set out below. Such E&E assets are amortised on a unit-of-production basis over the life of the commercial Reserves of the pool to which they relate. Impairment of E&E assets
E&E assets are assessed for impairment when facts and circumstances suggest
that the carrying amount may exceed its recoverable amount. Such indicators
include, but are not limited to, those situations outlined in paragraph 20 of IFRS 6 Exploration for and Evaluation of Mineral Resources and include the point at which a determination is made as to whether or not commercial Reserves exist. Where there are indications of impairment, the E&E assets concerned are tested for impairment. Where the E&E assets concerned fall within the scope of an established full cost pool, they are tested for impairment together with all development and production assets associated with that cost pool, as a single cash generating unit. The aggregate carrying value of the relevant assets is compared against the expected recoverable amount of the pool, generally by reference to the present value of the future net cash flows expected to be derived from production of commercial Reserves from that pool. Where the E&E assets to be tested fall outside the scope of any established cost pool, there will generally be no commercial Reserves and the E&E assets concerned will generally be impaired in full.
Impairment losses are recognised in the income statement as additional depreciation and amortisation and are separately disclosed.
The Group considers the whole of Ukraine to be one cost pool and therefore aggregates all Ukrainian assets for the purposes of determining whether impairment of E&E assets has occurred.
(l) Development and production assets
Development and production assets are accumulated on a field-by-field basis and represent the cost of developing the commercial Reserves discovered and bringing them into production, together with E&E expenditures incurred in finding commercial Reserves transferred from intangible E&E assets. The cost of development and production assets comprises the cost of acquisitions and purchases of such assets, directly attributable overheads, finance costs capitalised, and the cost of recognising provisions for future restoration and decommissioning.
Depreciation of producing assets
Depreciation is calculated on the net book values of producing assets on a field-by-field basis using the unit of production method. The unit of production method refers to the ratio of production in the reporting year as a proportion of the proved and probable Reserves of the relevant field, taking into account future development expenditures necessary to bring those Reserves into production. Producing assets are generally grouped with other assets that are dedicated to serving the same Reserves for depreciation purposes, but are depreciated separately from producing assets that serve other Reserves.
Impairment of development and production assets
Development and production assets are assessed for impairment whenever events and circumstances arising during both the development and production phase indicate that the carrying value of a development or production asset may exceed its recoverable amount. The carrying value of the asset is compared with its expected recoverable amount of the asset, by reference to the present value of the future cash flows expected to be derived from production of commercial Reserves from it. The cash-generating unit applied for impairment test purpose is normally the field or group of fields if the cash flow of the relevant fields is interdependent.
(m) Inventories
Inventories are stated at the lower of cost and net realisable value. Costs comprise direct materials and, where applicable, direct labour costs and those overheads that have been incurred in bringing the inventories to their present location and condition. Cost is allocated using the weighted average method. Net realisable value represents the estimated selling price less all estimated costs of completion and costs to be incurred in marketing, selling and distribution.
(n) Financial instruments
Recognition of financial assets and financial liabilities
Financial assets and financial liabilities are recognised on the Group's balance sheet when the Group becomes a party to the contractual provisions of the instrument.
Derecognition of financial assets and financial liabilities
The Group derecognises a financial asset only when the contractual rights to cash flows from the asset expire; or it transfers the financial asset and substantially all the risks and rewards of ownership of the asset to another entity. If the Group neither transfers nor retains substantially all the risks and rewards of ownership and continues to control the transferred asset, the Group recognises its retained interest in the asset and an associated liability for the amount it may have to pay. If the Group retains substantially all the risks and rewards of ownership of a transferred financial asset, the Group continues to recognise the financial asset and also recognises a collateralised borrowing for the proceeds received.
The Group derecognises financial liabilities when the Group's obligations are discharged, cancelled or expired.
Financial assets
The Group classifies its financial assets in the following categories: loans and
receivables; available-for-sale financial assets; held to maturity investments;
and financial assets at fair value through profit or loss ("FVTPL"). The classification
depends on the purpose for which the financial assets were acquired. Management determines
the classification of its financial assets at initial recognition and re-evaluates this
designation at every reporting date.
Loans and receivables are non-derivative financial assets with fixed or determinable
payments that are not quoted in an active market. They are included in current assets,
except for those with maturities greater than twelve months after the balance sheet
date which will then be classified as non-current assets. Loans and receivables are
classified as "other receivables" and "cash and cash equivalents" in the balance sheet.
Trade and other receivables
Trade and other receivables are measured at initial recognition at fair value, and are subsequently measured at amortised cost using the effective interest rate method. Cash and cash equivalents Cash and cash equivalents comprise cash on hand, on-demand deposits, and other short-term highly liquid investments that are readily convertible to a known amount of cash with three months or less remaining to maturity and are subject to an insignificant risk of changes in value.
Financial assets at FVTPL
Financial assets at FVTPL are stated at fair value, with any gains or losses arising on remeasurement recognised in proï¬t or loss which is included in the `Other gains and losses' line item in the consolidated income statement. Fair value is determined in the manner described in note 28.
Impairment of financial assets
Financial assets, other than those at FVTPL, are assessed for indicators of impairment at each balance sheet date. Appropriate allowances for estimated irrecoverable amounts are recognised in profit or loss when there is objective evidence that the asset is impaired. The allowance recognised is measured as the difference between the asset's carrying amount of the financial asset and the present value of estimated future cash flows discounted at the effective interest rate computed at initial recognition.
Evidence of impairment could include:
- significant financial difficulty of the issuer or counterparty;
- default or delinquency in interest or principal payments; or
- it becoming probable that the borrower will enter bankruptcy or financial re-organisation.
For certain categories of financial assets, such as trade receivables, assets that are assessed not to be impaired individually are, in addition, assessed for impairment on a collective basis.
The carrying amount of the financial assets is reduced by the impairment loss directly for all financial assets with the exception of trade receivables, where the carrying amount is reduced through the use of an allowance account. Subsequent recoveries of amounts previously written off are credited against the allowance account. Changes in the carrying amount of the allowance account are recognised in profit or loss. If, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognised, the previously recognised impairment loss is reversed through profit or loss to the extent that the carrying amount of the investment at the date the impairment is reversed does not exceed what the amortised cost would have been had the impairment not been recognised. Financial liabilities
Financial liabilities are classiï¬ed as either ï¬nancial liabilities `at FVTPL' or `other ï¬nancial liabilities'.
Financial liabilities at FVTPL
Financial liabilities at FVTPL are stated at fair value, with any resultant gain or loss recognised in profit or loss and is included in the `Other gains and losses' line item in the income statement. Fair value is determined in the manner described in note 28.
Trade payables and short-term borrowings
Trade payables and short-term borrowings are initially measured at fair value, and are subsequently measured at amortised cost, using the effective interest rate method.
(o) Provisions
Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that the Group will be required to settle that obligation and a reliable estimate can be made of the amount of the obligation. The amount recognised as a provision is the best estimate of the consideration required to settle the present obligation at the balance sheet date, taking into account the risks and uncertainties surrounding the obligation. When a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows. (p) Decommissioning A provision for decommissioning is recognised in full when the related facilities are installed. The decommissioning provision is calculated as the net present value of the Group's share of the expenditure expected to be incurred at the end of the producing life of each field in the removal and decommissioning of the production, storage and transportation facilities currently in place. The cost of recognising the decommissioning provision is included as part of the cost of the relevant asset and is thus charged to the income statement on a unit of production basis in accordance with the Group's policy for depletion and depreciation of tangible non-current assets. Period charges for changes in the net present value of the decommissioning provision arising from discounting are included within finance costs.
(q) Leases
Leases are classified as finance leases whenever the terms of the lease transfer substantially all the risks and rewards of ownership to the lessee. All other leases are classified as operating leases.
Rentals payable under operating leases are charged to income on a straight-line basis over the term of the relevant lease.
(r) Share-based payments
The Group issues equity-settled share-based payments to certain parties in return for services or goods. The goods or services received and the corresponding increase in equity are measured directly at the fair value of the goods or services received at the grant date. The fair value of the services or goods received is recognised as an expense except in so far as they relate to the cost of issuing or acquiring its own equity instruments. The costs of an equity transaction are accounted for as a deduction from equity to the extent they are incremental costs directly attributable to the equity transaction that would otherwise have been avoided. The Group also issues equity-settled share-based payments to certain Directors and employees. Equity settled share-based payments are measured at fair value (excluding the effect of non market-based vesting conditions) at the date of grant. The fair value determined at the grant date for each tranche of the equity-settled share-based payments is expensed on a straight-line basis over the vesting period, based on the Group's estimate of shares that will eventually vest and adjusted for the effect of non market-based vesting conditions. At each balance sheet date, the Group revises its estimate of the number of equity instruments expected to vest as a result of the effect of non market-based vesting conditions. The impact of the revision of the original estimates, if any, is recognised in profit or loss such that the cumulative expense reflects the revised estimate, with a corresponding adjustment to the equity-settled employee benefits reserve. For those equity-settled share-based payments with market-based performance conditions, fair value is measured by use of the Stochastic model. For those which are not subject to any market based performance conditions, fair value is measured by use of the Black-Scholes model. The expected life used in the models has been adjusted, based on management's best estimate, for the effects of non-transferability, exercise restrictions, and behavioural considerations. 4. Critical accounting judgements and key sources of estimation uncertainty In the application of the Group's accounting policies, which are described in note 3, 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 statements:
(a) 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 2012, representing receivables from a settlement agreement reached with GPS (2011: $30.0 million).
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 2011 and 2012,
$3.0 million each year 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.
During February 2013 the High Court in London awarded judgment in favour of the Group in the sum of just over US$21,000,000 inclusive of interest (the "Judgment Debt"), to be paid by 4 March 2013. GPS' counterclaim for the sum of approximately US$7,500,000 million was dismissed. At the request of the Group, a decision by the Court on further damages estimated at approximately up to US$10,500,000 was adjourned pending sale of the plants. In the meantime the Company continued to retain legal title to the plants. GPS did not pay by 4 March 2013however on 12 April the Group reached an agreement concerning the purchase of two gas processing plants by GPS for the sum of $29.5 million. The sale completed on 18 April 2013 following receipt in full by Cadogan of the agreed consideration. In accordance with the terms of the settlement documentation, the parties are now taking appropriate steps to dismiss the legal proceedings commenced in England against GPS and all other claims and liabilities have been released.
(b) Impairment of E&E, PP&E and contingent consideration
IAS 36 Impairment of Assets and IFRS 6 Exploration for and Evaluation of Mineral Resources require that a review for impairment be carried out if events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. As a result of the negative results of the drilling and work over programme at Zagoryanska licence, the Directors believed it appropriate to assess the carrying value of the Group's PP&E assets for impairment as at 31 December 2012. The Group assessed the present value of the future cash flows attributable to the Group's PP&E assets as at 31 December 2012 using discounted cash flows method. For PP&E assets the aggregate carrying value of each cash generating unit (`CGU') was compared against the expected recoverable amount of the related asset, by reference to the net present value of the future cash flows expected to be derived from the production of commercial Reserves (2P Reserves) of that unit. On this basis, an impairment of PP&E related to the Zagoryanska license of $66.0 million (2011: $nil) of which $47.1 million relates to the fair value uplift recognised in 2011 as the result of revaluation of non-controlling interest, with the respective decrease in the deferred tax liability of $7.1 million has been provided as at 31 December 2012 resulting in the impairment charge to profit and loss of $58.9 million. In addition $24.7 million ($35.0 million unrisked and undiscounted) of impairment has been charged to the profit and loss which represents the bonus from Eni on obtaining the production licence on Zagoryanska licence which formed part of the consideration on disposal of 60% in the Zagoryanska licence to Eni in 2011 (note 28). The Group considers the whole of Ukraine to be one cost pool and therefore aggregates all Ukrainian assets for the purposes of determining whether impairment of E&E assets has occurred. E&E assets are assessed for impairment when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Such indicators include, but are not limited to, those situations outlined in paragraph 20 of IFRS 6 Exploration for and Evaluation of Mineral Resources and include the point at which a determination is made as to whether or not commercial Reserves exist. In 2012, the Group has performed significant volume of work which it continues in 2013, including the re-interpretation of the existing 3D seismic, in order to evaluate the remaining potential of the full Pokrovskoe licence. The recoverable amounts are determined with reference to value-in-use calculations. The key assumptions for the value in use calculations are those regarding the production flow rates, discount rates, relevant elements of Ukraine fiscal regime for petroleum operators, and expected changes to selling prices and direct cost during the year. These assumptions reflect management's best estimates and have been revised in the year in light of the current economic environment which has resulted in more conservative estimates about the future. Management estimates discount rates that reflect the current market assessments of the time value of money and the risks specific to the CGUs. Changes in selling prices and direct costs are based on past practices and expectations of future changes in the market.
The key assumptions used to forecast cash flows from Ukraine operations are as follows:
- production flow rates confirmed by experienced in-house geologists and engineers, supported by report produced in 2009 by an independent reservoir engineer, Gaffney, Cline & Associates Ltd;
- pre-tax discount rate of 17.86% (post-tax of 15%);
- inclusion of relevant elements of Ukraine fiscal regime for petroleum operators (such as production and royalty tax relevant to each licence and future expected corporate income tax of 16%);
- expected future selling prices based on current and anticipated market conditions for oil, condensate and gas;
-costs based on best estimates with consideration to previous experience and inflation; and
- cash flows projected up to 2033 depending on the field to which they relate and an assumption has been made that the relevant licences will be extended.
(c) 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.
(d) 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 cumulative provision of $20.6 million (2011: $18.2 million) against Ukrainian VAT receivable has thus been recognised as at 31 December 2012.
(e) Accounting for the WGI transaction
As a consequence of the WGI transaction, outlined in note 28, 2 areas of significant
judgement were identified by the Group, being the accounting treatment of the WGI
transaction and the valuation of the Group's contribution of the two licenses to WGI.
After considering the requirements per IAS 31 Interest In Joint Ventures, the Directors
have deemed the criteria under this standard to have been met, and have therefore
accounted for WGI as a joint venture, specifically a jointly controlled entity.
In accounting for the contribution of the licenses, the Group have applied IAS 31
and SIC Interpretation 13 - Jointly Controlled Entities - Non-Monetary Contributions
by Venturers, which states that any profit or loss arising on the contribution of
non-monetary assets in exchange for an equity interest should be recognised to the
extent they are attributable to the equity interests of the other venturers. Whilst
the licenses contributed had a nil NBV in the books of the Group at the date of
contribution, the associated fair value of the licenses contributed in return for the
15.0% interest in WGI has been estimated at $6.4 million. The resultant profit recognised
in the income statement is $5.4 million which represents the un-eliminated 84.9% share
of the gain on contribution of these licenses. The Group has accordingly recognised an
intangible asset of $5.4 million as its share of the licenses.
5. Revenue
2012 2011
$'000 $'000
Sale of hydrocarbons 5,653 6,981
Investment revenue (note 12) 128 155
5,781 7,136
Information about major customers
Included in revenues for the year ended 31 December 2012 are revenues of $3.8 million (2011 - $5.0 million) which arose from sales to the Group's largest customer, which is the only customer that individually accounts for more than 10% of the Group's revenues.
6. Other operating (expenses)/income
2012 2011
$'000 $'000
Out of court settlements 597 2,144
Transactions with JV partner 81 -
Net foreign exchange (losses)/gains (3,618) 2,408
(2,940) 4,552
Out-of-court settlements in the amount of $0.6 million includes recovery of $0.5 million from a supplier who had received prepayment in 2008 and not supplied the goods.
Net foreign exchange loss of $3.6 million mainly relates to the revaluation of the USD-denominated monetary assets of the Group's UK entities which have GBP as a functional currency.
7. Business and geographical segments
The Directors continue to consider there to be only one business segment, the exploration and development of oil and gas revenues and only one geographical segment, being Ukraine.
8. Impairment
2012 2011
$'000 $'000
Impairment of oil and gas assets (note 17) (83,584) -
Inventories (note 20) (291) 344
VAT recoverable (note 4(d)) (2,393) (3,162)
Impairment of other assets (2,684) (2,818)
Total impairment of oil and gas assets of $83.6 million comprises of impairment
of $66.0 million of PP&E with the respective decrease in the deferred tax liability
of $7.1 million and $24.7 million ($35 million undiscounted) impairment of the bonus
to be received from Eni on obtaining the production licence on Zagoryanska licence
which formed part of the consideration on disposal of 60% in the Zagoryanska licence
to Eni in 2011 (note 28).
The carrying value of inventory as at 31 December 2012 and 2011 has been impaired to
reduce it to net realisable value (see note 20). During 2012 the Group gross sales of
inventory to third parties comprised $1.6 million (2011: $0.5 million).
During the year a net impairment of $2.4 million (2011: $3.2 million) in respect of
Ukrainian VAT was provided which comprised VAT impairment on new program capital expenditure
and VAT recovery of historical balances through offset of VAT liabilities arising on sales.
9. (Loss)/Profit for the year
The (loss)/profit for the year has been arrived at after charging/(crediting):
2012 2011
$'000 $'000
Depreciation of property, plant and equipment (1,967) (2,411) Loss on disposal of property, plant and equipment (52) (13) Impairment of other assets (note 8)
(2,684) (2,818)
Impairment of oil and gas assets (note 8) (83,584) - Staff costs
(4,304) (4,587) Net foreign exchange (losses)/gains (3,618) 2,408 In addition to the depreciation of PP&E of $2.0 million (2011: $2.4 million) in the year ended 31 December 2012, depreciation of $0.5 million (2011: $0.7 million) was capitalised to E&E assets being depreciation of tangible assets used in E&E activities.
10. Auditor's remuneration
The analysis of auditor's remuneration is as follows:
2012 2011
$'000 $'000
Audit fees
Fees payable to the Company's auditor and their 232 186
associates for the audit of the Company's annual
accounts
Fees payable to the Company's auditor and their
associates for other services to the Group:
- The audit of the Company's subsidiaries 27 32
Total Audit fees 259 218
Non-audit fees
- Audit-related assurance services 21 53
- Taxation compliance services 101 72
- Other taxation advisory services - 197
Non-audit fees 122 322
11. Staff costs
The average monthly number of employees (including Executive Directors) was:
2012 2011
Number Number
Executive Directors 2 2
Other employees 162 128
164 130
Total number of employees at 31 December 164 148
$'000 $'000
Their aggregate remuneration comprised:
Wages and salaries 5,893 3,196
Loss of office - 144
Other pension costs 36 123
Social security costs 857 749
Share-based payments - 846
6,786 5,058
Within wages and salaries $0.8 million (2011: $0.9 million) relates to amounts paid and accrued to executive Directors for services rendered.
Included within wages and salaries, is $0.4 million (2011: $0.4 million) capitalised to intangible E&E assets and $0.4 million (2011: $0.4 million) capitalised
to development
and production assets.
12. Investment revenue
2012 2011
$'000 $'000
Interest on bank deposits 128 155
No additional investment revenue earned from loan and receivables (including cash and bank balances) have been recognised other than interest on bank deposits.
13. Finance income/(costs)
2012 2011
$'000 $'000
Unwinding of discount on
decommissioning provision 67 (11)
(note 24)
No additional gains or losses have been recognised on financial liabilities measured at
amortised cost. In 2012 inflation rate in Ukraine has decreased. That has positively
influenced the discounting of decommissioning provision resulting in finance income of $67 thousand.
14. Tax
2012 2011
$'000 $'000
Current tax 122 132
Deferred tax (note 22) 130 (605)
252 (473)
The Group's operations are conducted primarily outside the UK. The most appropriate
tax rate for the Group is therefore considered to be 21 per cent (2011: 23 per cent),
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 charge/(credit) for the year can be reconciled to the (loss)/profit per the income statement as follows:
2012 2012 2011 2011
$'000 % $'000 %
(Loss)/Profit before tax
Continuing operations (92,883) 100% 152,607 100
Tax (credit)/charge at Ukraine
corporation tax rate of 21%
(2011: 23%) (19,505) 21 35,100 23.0
Permanent differences 18,499 (20) (34,987) (22.9)
Foreign exchange on operating
activities 733 (0.8) (387) (0.3)
Tax losses generated in the
year not yet recognised 798 (0.8) 128 0.2
Other temporary differences 57 (0.2) (566) (0.4)
Utilisation of deferred tax
asset not previously recognised
on losses 6 - 136 0.1
Effect of different tax rates (336) 0.4 103 0.1 Tax credit and effective tax rate for the year
252 (0.4) (473) (0.3)
15. (Loss)/Profit per Ordinary share
Basic profit per Ordinary share is calculated by dividing the net (loss)/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:
2012 2011
(Loss)/Profit attributable to owners of the $'000 $'000
Company
(Loss)/Profit for the purposes of basic profit per
share being net (loss)/profit attributable to
owners of the Company (93,106) 151,549
2012 2011
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 93 95
Weighted average number of Ordinary shares for the purposes of diluted profit per share
231,185 231,187
2012 2011
Cent Cent
(Loss)/Profit per Ordinary share
Basic (40.3) 65.6
Diluted (40.3) 65.6
Diluted loss (profit in 2011) per Ordinary share equals basic loss per Ordinary share as there is no dilutive effect from the outstanding share warrants.
16. Intangible exploration and evaluation assets
Cost $'000 At 1 January 2011 63,288 Additions 17,387 Acquisition of jointly-controlled entities (note 28) 49,181 Disposal of subsidiaries (note 28) (33,955) Change in estimate of decommissioning assets (note 24) 301 Disposals (9) Exchange differences (280) At 1 January 2012 95,913 Additions 6,745
Fair value of non-monetary assets contributed to jointly 5,454 controlled entity (note 28) Change in estimate of decommissioning assets (note 24)
(92) Transfer to property, plant and equipment (note 17) (38) Disposals (1) Exchange differences 417 At 31 December 2012 108,398 Impairment At 1 January 2011 57,125 Disposal of subsidiaries (note 28) (26,984) Exchange differences (258) At 1 January 2012 29,941 Exchange differences 226 At 31 December 2012 30,167 Carrying amount At 31 December 2012 78,231 At 31 December 2011 65,972 Additions during the year include $0.4 million (2011: $0.5 million) of capitalised depreciation of development and production assets used in exploration and evaluation activities.
17. Property, plant and equipment
Development
and
production
Other assets Total
Cost $'000 $'000 $'000
At 1 January 2011 3,524 67,435 70,959
Additions 465 4,645 5,110
Acquisition of jointly-controlled
entities (note 28) 72 49,522 49,594
Disposal of subsidiaries (note 28) (421) (7,248) (7,669) Transfer between property, plant and equipment
(1) 1 -
Change in estimate of decommissioning
assets (note 24) - 107 107
Disposals (439) (811) (1,250)
Exchange differences (19) (331) (350)
At 1 January 2012 3,181 113,320 116,501
Additions 303 15,704 16,007
Transfer between property, plant and
equipment 34 3 37
Change in estimate of decommissioning
assets (note 24) - 434 434
Disposals (168) (1,855) (2,023)
Exchange differences 40 583 623
At 31 December 2012 3,390 128,189 131,579
Accumulated depreciation and impairment
At 1 January 2011 1,802 15,234 17,036
Disposal of subsidiaries (note 28) (313) (1,955) (2,268)
Charge for the year 583 2,513 3,096
Disposals (365) (279) (644)
Exchange differences (13) (79) (92)
At 1 January 2012 1,694 15,434 17,128
Impairment - 66,017 66,017
Charge for the year 438 2,010 2,448
Disposals (65) (1,034) (1,099)
Exchange differences 32 426 458
As at 31 December 2012 2,099 82,853 84,952
Carrying amount
At 31 December 2012 1,291 45,336 46,627
At 31 December 2011 1,487 97,886 99,373
Total impairment of oil and gas assets of $83.6 million comprises of impairment of
$66.0 million of PP&E with the respective decrease in the deferred tax liability of
$7.1 million and $24.7 million ($35.0 million undiscounted) impairment of the bonus
to be received from Eni on obtaining the production licence on Zagoryanska licence
which formed part of the consideration on disposal of 60% in the Zagoryanska licence
to Eni in 2011 (note 28).
18. Subsidiaries
The Company had investments in the following subsidiary undertakings as at
31 December 2012, which principally affected the profits and net assets of the Group:
Country of Proportion
incorporation of voting
and interest
Name operation % Activity
Directly held Cadogan Petroleum Holdings Ltd UK 100.0 Holding company Ramet Holdings Ltd
Cyprus 100.0 Holding company Indirectly held Rentoul Ltd Isle of Man 100.0 Holding company
Cadogan Petroleum Holdings BV Netherlands 100.0 Holding company Cadogan Bitlyanske BV Netherlands 100.0 Holding company Cadogan Delta BV
Netherlands 100.0 Holding company
Cadogan Astro Energy BV Netherlands 100.0 Holding company
Cadogan Pirkovskoe BV Netherlands 100.0 Holding company
Momentum Enterprise (Europe) Ltd Cyprus 100.0 Holding company
Cadogan Ukraine Holdings Limited Cyprus 100.0 Holding company
Cadogan Momentum Holdings Inc Canada 100.0 Holding company
USENCO International Inc. USA 100.0 Holding company
Radley Investments Ltd UK 100.0 Holding company
LLC AstroInvest - Ukraine Ukraine 100.0 Exploration
LLC Astro Gas Ukraine 100.0 Exploration
DP USENCO Ukraine Ukraine 100.0 Exploration
LLC USENCO Nadra Ukraine 95 Exploration
JV Delta Ukraine 100.0 Exploration
LLC Astro-Service Ukraine 100.0 Service Company
OJSC AgroNaftoGasTechService Ukraine 79.9 Construction
services
LLC Cadogan Ukraine Ukraine 100.0 Corporate services
During the year ended 31 December 2012, the Group structure continued to be rationalised both so as to reduce the number of legal entities inside Ukraine and also to replace the structure of multiple jurisdictions with one based on a series of sub-holding companies incorporated in the Netherlands for each licence area.
19. Jointly controlled entities
The Group holds the following interests in jointly controlled entities in 2012:
Country of
incorporation Ownership
and share
Name operation % Activity
LLC Westgasinvest Ukraine 15 Exploration
LLC Industrial Company Ukraine 70 Exploration
Gazvydobuvannya
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
consolidated financial statements as a result of the proportionate consolidation as at
31 December 2012 and 2011:
2012 2011
$'000 $'000
Intangible exploration and evaluation assets 69,532 63,788 Property, plant and equipment
435 54,206
Non-current assets 69,967 117,994
Inventories 1,686 2,795
Trade and other receivables 714 3,612
Cash and cash equivalents 1,927 745
Current assets 4,327 7,152
Deferred tax liabilities (4,045) (11,543)
Long-term provisions (195) (155)
Non-current liabilities (4,240) (11,698)
Trade and other payables (3,637) (3,958)
Current provisions (486) (388)
Current liabilities (4,123) (4,346)
Net assets 65,931 109,102
2012 2011*
$'000 $'000
Revenue 1,885 1,591
Cost of sales (991) (1,245)
Other administrative expenses (1,019) (691)
Impairment of other assets (3,293) (3,250)
Impairment of property, plant and equipment (note
4(b)) (18,365) -
Investment revenue 10 15
Finance income/(costs) 62 (2)
Loss for the period (21,711) (3,582)
Other comprehensive loss (206) (402)
(21,917) (3,984)
*2011 figures are shown for the period from 6 July to 31 December
20. Inventories
2012 2011
$'000 $'000
Cost 6,309 8,476
Impairment provision (1,132) (1,920)
Carrying amount 5,177 6,556
The impairment provision as at 31 December 2012 and 2011 is made so as to reduce the carrying value of the inventories to net realisable value.
21. Other financial assets
Trade and other receivables
2012 2011
$'000 $'000
Other receivables 34,594 61,816
VAT recoverable 88 127
Prepayments 855 4,308
35,537 66,251
All sales are made on a prepayment basis, so there are no trade debtors. Out of $34.6 million of other receivables $30.0 million as at 31 December 2012 (2011: $30.0 million) represent receivables from the settlement agreement with GPS (note 4(a)). In 2011 the Group recognised in other receivables the bonus to be received from Eni for the receiving production licence on Zagoryanska licence in the amount of $35 million discounted to $24.7 million. As a result of the negative results of the drilling and work over programme at Zagoryanska licence the probability of receiving the bonus has decreased which resulted in full provision of the amount as at 31 December 2012.
VAT recoverable of $0.1 million (2011: $0.1 million) relates to the UK VAT recoverable.
$0.9 million prepayments (2011: $4.3 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 which were settled in April 2013 (see note 4(a)).
Cash and cash equivalents
Cash and cash equivalents as at 31 December 2012 of $42.4 million (2011: $65.0 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
22. 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
Liabilities as at 1 January 2011 982
Acquisition of jointly-controlled entities (note 28) 11,153 Deferred tax credit
(605) Exchange differences 8 Liability as at 1 January 2012 11,538
Impairment of property, plant and equipment (note 17) (7,108) Deferred tax expense
130
Exchange differences (7)
Liability as at 31 December 2012 4,553
At 31 December 2012, temporary differences of $6.3 million (2011: $6.0 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 2012, the Group had the following unused tax losses available for offset against
future taxable profits:
2012 2011
$'000 $'000
UK 9,486 5,557
Ukraine 69,628 66,410
79,114 71,967
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 $9.5 million (2011: $5.6 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 $69.6 million (2011: $66.4 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 the restriction to recognition of accumulated losses at 1 April 2011. Starting 1 January 2012 only 25% of accumulated losses as at this date are allowed to be utilised each year for the period from 2012 till 2015 in the calculation of taxable income of the company. Tax losses accumulated after 1 January 2012 have no restrictions. There are further temporary differences arising on assets in Ukraine for which deferred tax assets of $8.3 million (2011: $6.3 million) have not been recognised due to the uncertainty of future recovery.
23. Other financial liabilities
Trade and other payables
2012 2011
$'000 $'000
Trade creditors 5,206 3,877
Other taxes and social security 31 18
Other creditors and payables 171 258
Accruals 2,385 3,399
7,793 7,552
Trade creditors and accruals principally comprise amounts outstanding for capital work
program purchases and ongoing costs. The average credit period taken for trade purchases
is 55 days (2011: 62 days). The Group has financial risk management policies to ensure
that all payables are paid within the credit timeframe.
The Directors consider that the carrying amount of trade and other payables approximates
to their fair value. No interest is generally charged on balances outstanding.
24. Provisions
Decommissioning Other Total
$'000 $'000 $'000
At 1 January 2011 875 19 894
Change in estimate (note 16 and 17) 408 - 408 Utilisation of provision
- (19) (19) Unwinding of discount on decommissioning provision (note 13) 11 - 11
Disposal of subsidiaries (note 28) (588) - (588) Acquisition of jointly-controlled
entities (note 28) 367 - 367 Exchange differences (1) - (1) At 1 January 2012 1,072 - 1,072
Change in estimate (note 16 and 17) 342 - 342 Unwinding of discount on decommissioning provision (note 13) (67) - (67) Exchange differences
6 - 6 At 31 December 2012 1,353 - 1,353 At 1 January 2011 875 19 894 Included in long-term provisions 548 - 548 Included in current provisions 524 - 524 At 1 January 2012 1,072 - 1,072 Included in long-term provisions 414 - 414 Included in current provisions 939 - 939 At 31 December 2012 1,353 - 1,353 In accordance with the Group's environmental policy and applicable legal requirements, the Group intends to restore the sites it is working on after completing exploration or development activities. A short-term provision of $0.9 million (2011: $0.5 million) has been made for decommissioning costs, which are expected to be incurred within the next year as a result of the demobilisation of drilling equipment and respective site restoration. The long-term provision recognised in respect of decommissioning reflects management's estimate of the net present value of the Group's share of the expenditure expected to be incurred in this respect. This amount has been recognised as a provision at its net present value, using a discount rate that reflects the market assessment of time value of money at that date, and the unwinding of the discount on the provision has been charged to the income statement. These expenditures are expected to be incurred at the end of the producing life of each field in the removal and decommissioning of the facilities currently in place (currently estimated to be between one and 17 years). The effect of discounting on provisions would be immaterial.
25. Share capital
Authorised and issued equity share capital
2012 2011
Number Number
`000 $'000 `000 $'000
Authorised
Ordinary shares of £0.03 1,000,000 57,713 1,000,000 57,713
each
Issued
Ordinary shares of £0.03 231,092 13,337 231,092 13,337
each
Authorised but unissued share capital of £30 million has been translated into US dollars at the average exchange rate of the issued share capital.
The Company has one class of Ordinary shares which carry no right to fixed income.
Issued equity share capital
Ordinary shares
of £0.03
Number
At 31 December 2011 and 2012 231,091,734
26. Share-based payments
Equity-settled share-based payments
Under the terms of an agreement dated 17 February 2006, which was subsequently updated on 20 September 2006 and 8 May 2007, the Company's then broker and financial adviser Fox-Davies Capital (`Fox-Davies') were granted 5.1 million warrant rights, to be exercisable at an average price of £0.82 and £1.23 and to be exercisable at any time within the five year period following completion of the placing. In 2012 $1.0 million (2011: $0.2 million) previously recognised in other reserves in respect of equity-settled share-based payments (2012: 3.6 million, 2011: 1.0 million warrant rights) that have expired during the year were transferred to retained earnings from other reserves. As at 31 December 2012, there were 541,040 outstanding share warrants, exercisable at the subscription price of £1.23.
Equity-settled share option scheme
The Company has two Share Option schemes, the 2007 and 2008 Share Option Plans,
under which options to subscribe for the Company's shares have been granted to
certain Executive Directors and employees of the Group. Options are exercisable at
various prices and vest on achieving certain performance criteria. If the options
remain unexercised after a period of five years from the date of grant, the options
expire. Options are forfeited if the Executive Director or employee leaves the Group
before the options vest. All 2007 share option plans have been restated to Ordinary
shares of £0.03.
Details of the share options outstanding at the end of the year were as follows
2007 Share Option Plan 2008 Share Option Plan Total
Number of Weighted Number of Weighted Number of Weighted
share average share average share average
options price options price options price
`000 £ `000 £ `000 £
Outstanding at 1 January 2011 - - - - - -
Granted during the year - - 1,943 0.35 1,943 0.35
Outstanding at 1 January 2012 - - 1,943 0.35 1,943 0.35
Lapsed during the year - - (1,943) (0.35) (1,943) (0.35)
Outstanding at 31 December 2012 - - - -
- - Exercisable at - - 1 January 2011 - - - - - - 1 January 2012 - - 1,943 0.35 1,943 0.35 31 December 2012 - - - - - -
No share options were exercised during the year (2011: nil).
Options were granted under the 2007 Share Option Plan on 11 September 2007 and 19 February 2008, and under the 2008 Share Option Plan, on 9 October 2008 and 3 February 2011.
The options were split into three tranches with each tranche subject to certain performance conditions. Only the below tranches were outstanding either as at 31 December 2011 and 2012.
Under the 2007 Share Option Plan, options vest immediately upon grant date.
Under the 2008 Share Option Plan, granted in 2011, options vest (but do not become exercisable) if and when the share price of an ordinary share in the Company achieves a mid-market closing price of not less than 50 pence over a continuous period of 10 trading days during the period from the Grant Date of the Option and ending on 3 February 2014. Trading days means the days on which the London Stock Exchange is open for business. The Option shall become exercisable, but only to the extent vested, on 3 February 2014. No options were outstanding at 31 December 2012.
The fair values of the options have been calculated using the following models:
- 2007 Share Option - not subject to any market-based performance conditions, and therefore the Black-Scholes model has been used.
- 2008 Share Option - market-based performance conditions must be included in the calculation of fair value and therefore the Stochastic and Binomial model has been considered the most appropriate.
The inputs into the models were as follows:
2007 Share Option 2008 Share Option
Plan Plan
Black-Scholes Binomial
Year of grant 2007 2011
Weighted average share price (£) 1.23 0.35
Weighted average exercise price (£) 0.82 0.35
Expected volatility (%) 55 70.0
Expected term (years) 2.5 10
Risk free rate (%) 4.99 3.88
Expected dividend yield (%) - -
As the Company has listed shares, the expected volatility was determined by considering the historical volatility of other similar entities. Similar entities have been chosen as the FTSE AIM Oil & Exploration constituents (with a market capitalisation of greater than £100 million) for the 2007 Share Option Plan and the FTSE All Share Oil & Exploration sector (with a market capitalisation between £40 million and £500 million) for the 2008 Share Option Plan at the grant date.
The exercise price was established in accordance with the terms included within the share option scheme.
The aggregate of the estimated fair values of the options granted under the two share option plans at 31 December 2012 is $nil (2011: $0.8 million), all related to 2008 Share Option. Due to certain employees and Directors resigning from their duties to the Company in 2009, share options granted under Option Tranche 1 were forfeited in 2010.
27. Notes to the cash flow statement
2012 2011
$'000 $'000
Operating(loss)/profit (93,078) 152,463
Adjustments for:
Depreciation of property, plant and equipment 1,967 2,411
Impairment of oil and gas assets (note 8) 83,584 -
Share-based payment charge (note 26) - 846
Gain on acquisition of jointly controlled entity
disposal of subsidiaries (note 28) (5,454) (164,945)
Other losses (note 28) - 3,299
Impairment of inventories (note 8) 291 (344)
Impairment of VAT recoverable (note 8) 2,393 3,162
Loss on disposal of property, plant and equipment 52 13
Effect of foreign exchange rate changes 4,014 (1,691)
Operating cash flows before movements in working
capital (6,231) (4,786)
Decrease/(Increase) in inventories 1,269 (2,563)
Increase in receivables (766) (3,027)
Increase in payables and provisions 241 1,589
Decrease in restricted cash - 1,035
Cash used in operations (5,487) (7,752)
Income taxes paid (122) (133)
Net cash outflow from operating activities (5,609) (7,885)
28. Disposal of subsidiaries and acquisition of jointly-controlled entities
2012 transactions: LLC Westgasinvest
In February 2012 the Group set up a joint venture LLC Westgasinvest ("WGI") with a
Ukrainian state-owned company NAK Nadra Ukrainy. As part of the transaction the Group
contributed two unconventional licenses, the Debeslavetske production license and the
Debeslavetske exploration license to WGI, while keeping all the economic benefit from
the existing conventional activities on these licenses.
Whilst the licenses contributed had a nil NBV in the books of the Group at the date of
contribution, the associated fair value of the licenses contributed in return for the
15% interest in WGI has been estimated at $6.4 million. The resultant profit recognised
in the income statement is $5.4 million which represents the un-eliminated 85% share of
the gain on contribution of these licenses. The Group has accordingly recognised
anintangible asset of $5.4 million.
The Group's resultant equity holding, post this transaction was 15%, with Nadra owning the remaining 85%.
On 3 October 2012 50.01% of ownership in WGI was sold by Nadra and Cadogan to ENI completing the current ownership structure of WGI.
2011 transactions: Eni
On 6 July 2011 the Group completed the transaction with Eni, selling a 30% interest in the share capital of Pokrovskoe 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 was also committed to 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 was only payable if the Pok Option is exercised.
A total gain on disposal of $165.0 million was recognised in profit and loss in 2011 relating to the above transaction.
In March 2012 Eni informed the Group that they will not exercise the Pok Option. The exercise of the option was a pre-requisite for the contingent payment of $15.0 million on obtaining the Pokrovksoe production license. In addition, in light of the results of the drilling and work over campaign on the Zagoryanska license in 2012 the probability of obtaining the production license on Zagoryanska field and receiving a contingent payment of $35.0 million ($24.7 million risked and discounted) has significantly decreased and therefore the receivable has been impaired in full as at 31 December 2012.
29. Financial instruments
Capital risk management
The Group manages its capital to ensure that entities in the Group will be able to continue as a going concern, while maximising the return to shareholders. The capital resources of the Group consists of cash and cash equivalents arising from equity attributable to owners of the Company, comprising issued capital, reserves and retained earnings as disclosed in the Consolidated Statement of Changes in Equity.
Externally imposed capital requirement
The Group is not subject to externally imposed capital requirements.
Significant accounting policies
Details of the significant accounting policies and methods adopted, including the criteria for recognition, the basis of measurement, the basis on which income and expenses are recognised, in respect of each class of financial asset, financial liability and equity instrument are disclosed in note 3 to the Consolidated Financial Statements.
Categories of financial instruments
2012 2011
$'000 $'000
Financial assets - loans and receivables (includes cash and cash equivalents) Cash and cash equivalents
42,404 65,039
Other receivables (current and non-current) 34,594 61,816
76,998 126,855
Financial liabilities - measured at amortised cost Trade creditors
5,206 3,877
Other creditors and payables 171 258
5,377 4,135
Financial risk management objectives
Management provides services to the business, co-ordinates access to domestic and international financial markets and monitors and manages the financial risks relating to the operations of the Group in Ukraine through internal risks reports which analyse exposures by degree and magnitude of risks. These risks include commodity price risks, foreign currency risk, credit risk, liquidity risk and cash flow interest rate risk. The Group does not enter into or trade financial instruments, including derivative financial instruments, for speculative purposes. As the Group has no committed borrowings, the Group is not exposed to any significant risks associated with fluctuations in interest rates on loans. A five per cent fluctuation in interest rates applied to cash balances held at the balance sheet date would impact the Group by approximately $2.1 million (2011: $3.3 million) over a twelve month period.
The Audit Committee of the Board reviews and monitors risks faced by the Group through meetings held throughout the year.
Commodity price risk
The commodity price risk related to Ukrainian gas and condensate prices and, to a lesser extent, prices for crude oil are the Group's most significant market risk exposures. World prices for gas and crude oil are characterised by significant fluctuations that are determined by the global balance of supply and demand and worldwide political developments, including actions taken by the Organisation of Petroleum Exporting Countries. These fluctuations may have a significant effect on the Group's revenues and operating profits going forward. The principal factor in the current Ukrainian gas price is bilateral negotiations with Gazprom to establish the price of gas imports from Russia. The price for Ukrainian gas is based on the current price of these gas imports from Russia, which are nonetheless influenced by world prices. Management continues to expect that the Group's principal market for gas will be the Ukrainian domestic market.
The Group does not hedge market risk resulting from fluctuations in gas, condensate and oil prices, and holds no financial instruments which are sensitive to commodity price risk.
Foreign exchange risk and foreign currency risk management
The Group undertakes certain transactions denominated in foreign currencies. Hence, exposures to exchange rate fluctuations arise.
The Group to date has elected not to hedge its exposure to the risk of changes in foreign currency exchange rates.
The carrying amounts of the Group's foreign currency denominated monetary assets and monetary liabilities at the reporting date are as follows:
Liabilities Assets
2012 2011 2012 2011
$'000 $'000 $'000 $'000
US dollars (`$') 162 106 68,297 116,533
Foreign currency sensitivity analysis
The Group is exposed primarily to movements in currencies against the US dollar as this is the presentation currency of the Group. In order to fund operations, US dollar funds are converted to UAH just before being contributed to the Ukrainian subsidiaries. Sensitivity analyses have been performed to indicate how the profit or loss would have been affected by changes in the exchange rate between the GBP and US dollar. The analysis is based on a weakening of the US dollar by 10 per cent against GBP, a functional currency in the entities of the Group which have significant monetary assets and liabilities at the end of each respective period. A movement of 10 per cent reflects a reasonably possible sensitivity when compared to historical movements over a three to five year timeframe. The sensitivity analysis includes only outstanding foreign currency denominated monetary items and adjusts their translation at the period end for a ten per cent change in foreign currency rates. A number below indicates a decrease in profit where US dollar strengthens 10 per cent against the other currencies. For a 10 per cent weakening of the US dollar against the other currencies, there would be an equal and opposite impact on the profit or loss, and the balances would be negative.
The Group is not exposed to significant foreign currency risk in other currencies.
Inflation risk management
The following table details the Group's sensitivity to a 10 per cent decrease in the US
dollar against the GBP.
2012 2011
$'000 $'000
Income statement (8,791) (10,987)
Inflation in Ukraine and in the international market for oil and gas may affect the Group's
cost for equipment and supplies. The Directors expect that the Group's practices of keeping
deposits in US dollar accounts until funds are needed and selling its production in the spot
market, coupled with the linkage of the currency in Ukraine to the US dollar, to enable the
Group to manage the risk of inflation.
Credit risk management
The credit risk on other receivables due from GPS is mostly mitigated as the Company maintains title of the assets throughout the settlement period (refer to note 4(a)).
Credit risk refers to the risk that counterparty will default on its contractual obligations resulting in financial loss to the Group. The Group does not have any significant credit risk exposure on trade receivables as the normal terms for sales of gas and condensate to the Group's customers require payment before delivery.
The Group makes allowances for impairment of receivables where there is an identified event which, based on previous experience, is evidence of a reduction in the recoverability of cash flows.
The credit risk on liquid funds (cash) is considered to be limited because the counterparties are financial institutions with high and good credit ratings, assigned by international credit-rating agencies in the UK and Ukraine respectively.
The carrying amount of financial assets recorded in the financial statements represents the Group's maximum exposure to credit risk.
Liquidity risk management
Ultimate responsibility for liquidity risk management rests with the Board of Directors, which has
built an appropriate liquidity risk management framework for the management of the Group's short,
medium and long-term funding and liquidity management requirements. The Group manages liquidity risk
by maintaining adequate cash reserves and by continuously
monitoring forecast and actual cash flows.
The following tables set out details of the expected contractual maturity of financial liabilities.
Within 3 months to More than 1
3 months 1 year year
$'000 $'000 $'000
At 31 December 2012 7,322 471 -
Trade and other payables 7,322 471 -
At 31 December 2011 7,552 - -
Trade and other payables 7,552 - -
30. Commitments and contingencies
Joint activity agreements
The Group has working 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 required future financing of exploration and development work on fields under the licence
obligations are as follows
2012 2011
$'000 $'000
Within one year 18,717 7,440
Between two and five years 27,601 44,469
46,318 51,909
Licence obligations within one year amounting to $18.7 million include $13.4 million related
to Pirkovskoe licence. The Group currently is in the process of negotiating decrease in the
work programme activities with the licensing authorities.
31. Related party transactions
All transactions between the Company and its subsidiaries, which are related parties, have been eliminated on consolidation and are not disclosed in this note.
Remuneration of key management personnel
The remuneration of the Directors, who are the key management personnel of the Group, is set
out below in aggregate for each of the categories specified in IAS 24 Related Party Disclosures.
Further information about the remuneration of individual Directors is provided in the audited
part of the Directors' Remuneration Report in the full Annual Report and Accounts.
Purchase of Amounts owing
services
2012 2011 2012 2011
$'000 $'000 $'000 $'000
Short-term employee benefits 1,048 852 973 476 Share-based payments
(695) 695 - -
353 1,547 973 476
The total remuneration of the highest paid Director was $0.4 million in the year (2011: $0.5 million).
The amounts outstanding are unsecured and will be settled in cash. No guarantees have been given or received and no provisions have been made for doubtful debts in respect of the amounts owed by related parties.
32. Events after the balance sheet date
GPS
During February 2013 the High Court in London awarded judgment in favour of the Group in the sum of just over US$21,000,000 inclusive of interest (the "Judgment Debt"), to be paid by 4 March 2013. GPS' counterclaim for the sum of approximately US$7,500,000 million was dismissed. At the request of the Group, a decision by the Court on further damages estimated at approximately up to US$10,500,000 was adjourned pending sale of the plants. In the meantime the Company continued to retain legal title to the plants. GPS did not pay by 4 March 2013 however on 12 April the Group reached an agreement concerning the purchase of the two gas processing plants by GPS for the sum of $29.5 million. The sale completed on 18 April 2013 following receipt in full by Cadogan of the agreed consideration. In accordance with the terms of the settlement documentation, the parties are now taking appropriate steps to dismiss the legal proceedings commenced in England against GPS and all other claims and
liabilities have been released. ANNUAL GENERAL MEETING
The Annual General Meeting of the Company held at 10.30am on Thursday 27 June 2013 at Chandos House, 2 Queen Anne Street, London W1G 9LQ.
NATIONAL STORAGE MECHANISM
A copy of the Annual Report and Financial Statements will be submitted shortly to the
National Storage Mechanism ("NSM") and will be available for inspection at the NSM,
which is situated at: www.morningstar.co.uk/uk/nsm
Neither the contents of the Company's website nor the contents of any website accessible
from hyperlinks on this announcement (or any other website) is incorporated into, or
forms part of, this announcement.
Copyright l 24 PR Newswire
1 Year Cadogan Energy Solutions Chart |
1 Month Cadogan Energy Solutions Chart |
It looks like you are not logged in. Click the button below to log in and keep track of your recent history.
Support: +44 (0) 203 8794 460 | support@advfn.com
By accessing the services available at ADVFN you are agreeing to be bound by ADVFN's Terms & Conditions
