Cadogan Regulatory News (CAD)

CADOGAN PETROLEUM PLC

Preliminary Results for the Year Ended 31 December 2011

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Cadogan Petroleum plc is an independent oil and gas exploration, development and production company with onshore gas, condensate and oil assets in Ukraine.

The Group has undergone significant management changes during the year, including the appointment of Zev Furst as Chairman and Bertrand Des Pallieres as Chief Executive Officer.

 Other developments during 2011 included the following:

·; The completion of a major transaction with Eni S.p.A ("Eni") resulting in Eni owning 60% of the Group's interest in the Zagoryanska licence and 30% of the Group's interest in the Pokrovskoe licence

·; A $30 million (excluding VAT) drilling programme on the Pokrovskoe field

·; A three-well work-over programme on the Zagoryanska field

·; Total capital expenditure of $21.3 million (2010: $12.1 million) during the year

·; Net cash and cash equivalents at year end of $65.0 million (2010: $36.4 million)

Enquiries

Business Review

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Introduction

2011 has been a significant year for Cadogan Petroleum plc, as it seeks to develop its oil and gas business in Ukraine. On 6 July 2011 we completed a transaction whereby Eni acquired a 60% interest in the Group's Zagoryanska licence for $38 million and acquired a 30% interest in our Pokrovskoe licence by funding a $36 million ($30 million plus VAT) work programme and an option to purchase a further 30% dependent on the results of the drilling programme.

Financial position

At 27 April 2012 the Group had current cash and cash equivalents of approximately $58.0 million. This is more than adequate to fulfil the Group's current work programme.

Operations

The Operations review details the extensive work programme that the Group has undertaken on its assets in the Dnieper-Donets basin in eastern Ukraine. Although results on the Zagoryanska work-overs have been delayed due to technical issues, the Group continues to test Zagoryanska 1 and 2 which were worked over in Q3 and Q4 of 2011. Zagoryanska 8 is also being worked over at present and will be put on test in Q2 of 2012. All of these wells are close to the Zagoryanska 3 well which continues to produce at around 35 mcm/day. In addition the Group spudded a 5,160 metres appraisal well at Zagoryanska 11 on 7 March 2012. Working with Eni's technical staff, considerable analysis of the potential reservoir has been undertaken.

Initial results from our exploratory Pokrovskoe 1 well, which was deepened in 2011, and Pokrovskoe 2a well, which was re-drilled in Q4 of 2011 and Q1 of 2012, were not as positive as hoped. As a consequence Eni have decided not to exercise their option to acquire a further 30% in the licence, a development that was announced on 19 March 2012. This is of course disappointing, but the indications of hydrocarbons throughout the drilling process is of sufficient interest that Cadogan is considering options to re-enter the Pokrovskoe 2a well to assess the potential of the Upper Visean in the future. Should this be successful, the Group would consider options to commercially exploit the field.

Efforts continue to farm-out the Group's highly attractive Bitlyanska asset in western Ukraine. The Group intends to review possible work-over projects for the Pirkrovskoe field in eastern Ukraine. Low cost analysis techniques are being reviewed for use on the Group's shallow gas fields, currently under production, in Debeslevetska aimed at stimulating production increases whilst a borehole formation cleaning programme is underway at Monastyretska to attempt to increase oil production from the existing wells.

Litigation

During the year the Group concluded a settlement with the final main defendant in its litigation against former management and third parties over alleged procurement irregularities. The Group continues to be owed $30 million by Global Process System Inc ('GPS') of Dubai, under the settlement agreement entered into October 2009. The settlement was based on the sale of two gas plants, which were manufactured by GPS that were not required by the Group. Under the agreement GPS undertook to take the plants back into stock and resell them. Cadogan retains title over the plants manufactured. The Board believes that the value of these plants equates to the sum due, and continues to assist GPS in its attempts to sell the plants whilst pursuing legal remedies to recover the outstanding debt.

Business development and strategy

Ukraine, with its significant existing and yet-to-be discovered resources in both conventional and unconventional gas, as well as its significant infrastructure bordering Western Europe, has a tremendous opportunity: it has the potential to offer international energy companies a viable business proposition with reasonable fiscal terms and a stable political and regulatory environment, where many existing fields have been underexploited because of an insufficient exposure to modern field-optimisation techniques. Field rehabilitation and field optimisation would help generate significant increases in production.

The results of the Group's current work programme for 2011-12 will be critical in determining its next steps. Cadogan is very focused on the appraisal of the Zag field with the objective to define a full field development plan by the end of 2012. We will continue to invest in exploration and appraisal of our other existing assets, while starting investment in new areas with an emphasis on offshore activities in the Black Sea. Cadogan also hopes to start preliminary exploration of unconventional gas assets in 2012.

Cadogan is already the most active foreign company in the Ukrainian upstream sector, and the Group intends to bolster this position. Cadogan's ongoing strategy is to focus on acquiring low capital investment positions on Ukraine oil and gas assets, either in joint venture with State companies or not, and developing them in joint venture with international energy companies. We expect the next 12 to 24 months to bring considerable change to Ukraine's E&P sector. While historically only small foreign companies have been active, a number of international oil majors are about to enter Ukraine for the first time. Cadogan is extremely well positioned to support and exploit this transition.

Operations Review

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In 2011 the Group held working interests in nine (2010: nine) gas, condensate and oil exploration and production licences in the east and west of Ukraine. All these assets are operated by the Group and are located in either the Carpathian basin or the Dnieper-Donets basin, in close proximity to the Ukrainian gas distribution infrastructure. The Group's primary focus is on the four licences where the main reserve and resource potential is located, Zagoryanska, Pokrovskoe, and Pirkovskoe in the Dnieper-Donets basin of east Ukraine and Bitlyanska, in the Carpathian Basin of west Ukraine.

(1) E&D = Exploration and Development.

(2) The working interest on the Bitlyanska licence declines on a stepped basis, every five years after the commencement of production on each well. The Joint Activity Agreement ('JAA') also distinguishes working interests on new wells and work over wells with the former offering a higher share to the Group. Effective working interests are shown above.

(3) The licence is in the process of renewal by the Ukraine authorities for further 5 years, from its expiration date in 2011. The renewal process is expected to be completed during the first half of 2012.

Zagoryanska licence

The Group now has a 40 per cent working interest in the Zagoryanksa licence area. The Zagoryanska licences hold 96.4 mmboe of Contingent Resources (2010: 96.4 mmboe of Contingent Resources). The exploration and development licence covers 49.6 square kilometres and the licence was extended in 2009 until April 2014. The remaining work programme includes; (a) the work-over of well Zagoryanska 2 (underway); (b) the drilling of an appraisal well (which is undergoing); and (c) conducting geological and economic estimation of hydrocarbon reserves.

In 2008, the Zagoryanska 3 well had been drilled to a target depth ("TD") of 5,110 metres and was suspended in order to evaluate the data obtained. In 2009 the well was perforated and commercial flow rates were achieved. Production commenced in August 2010 at a flow rate of 55 mcm/day (2 million scf/day) of gas and 15 t/day (120 bpd) of condensate and the well was tied into the Group's Zagoryanska gas treatment plant. Average monthly production rates during 2011 were 36 mcm/day gas and 6.5 t/day condensate. The Group has since purchased the Zagoryanska 3 well, (which it was previously renting), together with four additional wells on the field.

On 6 July 2011 Eni, the major Italian integrated energy company, acquired a 60 per cent interest in the Zagoryanska licence for a payment of $38 million. Following completion of this transaction a work over plan was prepared for three of the four additional wells purchased on the field. Wells Zagoryanska 1 and 2 have been worked over in preparation for rig-less operations (including coiled tubing operations); work over of Zagoryanska 8 is on-going and testing will commence in Q2 2012. These work-overs are designed to allow re-entry of zones that previously produced hydrocarbons in Zagoryanska Field, but were suspended for various technical or commercial reasons in the 1990's.

During the year Cadogan acquired the remaining 10% interest in the Zagoryanska licence from NSJC Nadra Ukraine for a consideration of $1.5 million.

Pokrovskoe licence

The Group now has a 70 per cent working interest in the Pokrovskoe licence which holds 51.1 mmboe (2010: 51.1 mmboe) of Prospective Resources. The exploration licence covers 49.5 square kilometres and the initial licence was extended during the year until August 2016.

Interpretation of the 3D seismic was completed in early 2010 and confirmed the presence of a prospect with four-way closure at the Lower Visean and the deeper Tournasian level, beneath both the Pokrovskoe 1 and Pokrovskoe 2 suspended well locations. The Pokrovskoe 1 well had encountered strong indications of gas during drilling and logging over significant sections in the Lower Visean and was suspended due to equipment limitations at 5,450 metres. Pokrovskoe 2 was drilled to a depth of 5,185 metres and suspended for future evaluation and possible deepening as the Upper Visean formations provided strong indications of gas, supported by well log data.

As part of the Eni transaction, that company acquired a 30 per cent interest in the Group's Pokrovskoe licence, with an option to acquire a further 30 per cent interest in the future. On 9 March 2012 the Group has been advised by Eni, that, after their analysis of the results for the Pokrovskoe 1 and Pokrovskoe 2a wells, Eni do not intend to exercise their option to acquire the additional 30 per cent (refer to note 20 to the Condensed Financial Consolidated Information). Notwithstanding the option not being exercised, Eni will continue with an existing 30 per cent share in Pokrovskoe licence.

The consideration comprised 100 per cent funding of a work programme of approximately $30 million (excluding VAT), which was used to fulfil the work obligations on the licence. This comprised the deepening of Pokrovskoe 1 to test the potential of the Lower Visean and the re-drilling of Pokrovskoe 2 (designated 2a) in order to test the potential of the Upper Visean intervals.

On Pokrovskoe 1, the primary Lower Visean target proved to be water bearing and while preparing to test the secondary zone, mechanical problems prevented completion of operations. As a result, the well was suspended and the Saipem drilling rig was moved to the Pokrovskoe 2a location while remedial operations were considered for Pokrovskoe 1.

On Pokrovskoe 2a, the well was drilled to a casing point at 4,783 metres where the logs acquired indicated the presence of hydrocarbons and a decision was taken to continue drilling after casing the open-hole section. During the casing operation the running string became stuck and the limited fishing equipment available in country prevented the running tool from being recovered. The well has therefore been suspended while future options are considered for the well.

Pirkovskoe licence

The Group has a 100 per cent working interest in the Pirkovskoe licence which holds 2.4 mmboe (2010: 2.4 mmboe) of 2P Reserves, 5.0 mmboe (2010: 5.0 mmboe) of Possible Reserves, and 134.0 mmboe of Contingent Resources (2010: 134.0 mmboe). This exploration and appraisal licence covers 71.6 square kilometres and has been renewed until October 2015. The remaining work programme includes; (a) the testing of Pirkovskoe 1; (b) deepening to 5,450 metres and testing of the suspended Pirkovskoe 2 well; (c) the drilling of a new well (scheduled for 2013); and (d) calculation of the potential hydrocarbon reserves.

Pirkovskoe 1 was the first appraisal well drilled in the northern part of the Pirkovskoe licence. The well was terminated at a TD of 5,723 metres and after testing the Devonian and Lower Carboniferous, the well was temporarily suspended. The testing and subsequent completion of several shallower Carboniferous oil and gas bearing zones was farmed out to a local company at no cost to Cadogan, in return for a share of any future production. This interval produced small volumes of oil and gas and is currently shut-in.

The Pirkovskoe 2 well was drilled to a depth of 4,580 metres, and has been suspended until the results of Pirkovskoe 1 have been reviewed.

The Group owns the Kraznozayarska gas treatment plant located on the Pirkovskoe licence area, which is connected to the UkrTransGas system. Its capacity was upgraded in July 2007 to 300,000 cubic metres per day of gas and 150 tonnes per day of condensate in anticipation of future production.

Bitlyanska licence area

The Bitlyanska exploration and development licence covers an area of 390 square kilometres and the Group's interest ranges from 96.5 per cent to 97.1 per cent, varying with production. There are three hydrocarbon discoveries in this licence area, namely Bitlya, Borynya and Vovchenska. The Borynya and Bitlya fields hold 211.5 mmboe (2010: 211.5 mmboe) and 113.9 mmboe (2010: 113.9 mmboe) of Contingent Resources respectively, while no Reserves and Resources have been attributed to the depleted Vovchenska field.

In the 1970's drilling of the Borynya 1 resulted in a blow out and on Borynya 2 reportedly tested gas at very high rates. Cadogan drilled the Borynya 3 well proximal to these two Soviet era wells and in June 2009, tested gas from one of the secondary reservoir targets at around 3,600 metres at a maximum flow rate of 128,000 cubic metres per day during a limited duration drill stem test. Borynya 3 was terminated at a drilled depth of 5,325 metres and the well was suspended for future evaluation having encountered several deep high-pressure gas bearing intervals that could not be tested with the equipment available at that time.

In 1994 the Bitlya 1 well tested non-commercial gas from several zones down to 3,200 metres. Although this well established the presence of an active hydrocarbon system, the recent 2D seismic data interpretation demonstrates that the well was poorly located in relation to any structural closure.

In 2010 a 2D survey was completed in the southern part of the licence to complement the Soviet era 2D seismic data that had been reprocessed by Cadogan. This integrated data set has been interpreted with the benefit of recent surface geological mapping and balanced section generation, and a series of prospects for future exploration drilling have been identified.

The remaining work obligation for this licence was recently re-negotiated.

Minor fields

The Group has a number of minor licence areas located in western Ukraine. These include the following:

·; Debeslavetska Production licence area

A production licence, containing 0.2 mmboe of Proved, Probable and Possible ('3P') Reserves (2010: 0.3 mmboe). The field is currently producing 84.0 boepd (2010: 100.7 boepd). Production during the year was impacted by a compressor failure that resulted in a period of planned maintenance being bought forward into 2011; equipment optimisation is foreseen during 2012. The Group drilled a series of three shallow wells on the field in 2011 using its own drilling rig which added minor commercial production but also assisted in the geological interpretation of the wider area.

·; Debeslavetska Exploration licence area

An exploration licence surrounding the Debeslavetska Production licence area which has similar shallow gas production potential to the Debeslavetska Field.

·; Cheremkhivska Production licence area

A production licence containing 0.1 mmboe of 3P Reserves (2010: 0.1 mmboe). This licence is currently producing 32.8. boepd (2010: 33.2 boepd).

·; Slobodo-Rungerska licence area

An exploration and development licence, with no booked Reserves and Resources (2010: nil). Seismic data for this area was reprocessed in 2010 and the results indicate a deeper structure underlying the depleted and abandoned Slobodo-Rungerska Field.

·; Monastyretska licence area

An exploration and development licence, with no booked Reserves or Resources (2010: nil). Re-entry of the Blazhiv 1 well was undertaken in the year and minor oil production re-established at the rate of 16 bopd. A hydraulic formation cleaning program on the well is currently under way in the attempt to increase production levels.

Financial Review

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Overview

In 2011 the Group mainly focused on exploration activity at Pokrovskoe and appraisal activity at Zagoryanska fields together with its joint venture partner Eni.

A substantial increase in the gas price in Ukraine has enabled revenue to increase from $5.0 million in 2010 to $7.0 million in 2011. A gain on disposal of two subsidiaries in 2011 of $164.9 million, including revaluation of the remaining jointly-controlled interest of $91.1 million, in the above mentioned subsidiaries that the Group has lost control in, contributed to the profit for the year of $153.1 million (2010: $1.3 million). This profit was reflected by a corresponding increase in the net asset position as at 31 December 2011 to $283.0 million from $131.2 million as at 31 December 2010. The cash position of $65.0 million at 31 December 2011 has increased from $36.4 million at 31 December 2010 mainly as the result of the cash consideration received from the disposal of interest in two subsidiaries to Eni.

Change in the presentation currency of the financial information

The Directors decided to change the Group's presentation currency from sterling to US dollars with effect from 1 January 2011. These are the first financial statements and the accompanying notes to be reported in US dollars (refer to note 2(b) to the Condensed Financial Consolidated Information).

Income statement

Profit before tax was $152.6 million (2010: $0.8 million). Revenues of $7.0 million (2010: $5.0 million) comprised sales of gas from the Debeslavetska, Cheremkivska fields and Zagoryanska 3 well. Cost of sales, which represents production royalties and taxes, depreciation and depletion of producing wells and direct staff costs increased to $6.3 million in 2011 from $4.1 million in 2010 to give a gross profit of $0.7 million (2010: $0.9 million).

·; Other administrative expenses of $11.6 million (2010: $13.0 million) comprise other staff costs, professional fees, Directors' remuneration, depreciation charges on non-producing property, plant and equipment. In addition to recurring administrative expenses, $1.2 million (2010: $2.2 million) of professional costs were incurred in relation to litigation, $0.9 million (2010: $nil) of professional fees were incurred in relation to the transaction with Eni on the two Pokrovskoe and Zagoryanska licences.

·; Profit on disposal of subsidiaries amounted to $164.9 million which represents a difference between $17.6 million of net assets disposed, the sum of $91.4 million consideration received and $91.1 million of net fair value of the residual interest (including a $80.2 million of fair value uplift). At year end the changes in the fair value of financial asset and liability arising from the Eni transaction resulted in net charge to the income statement of $3.3 million (refer to note 18 to the Condensed Financial Consolidated Information).

·; Other operating income of $4.6 million (2010: $11.8 million) includes $2.1 million (2010: $9.3 million) related to recoveries from former management and suppliers and $2.4 million (2010: $2.5 million) related to net foreign exchange gains.

·; Net impairment charges of $2.8 million (2010: $0.9 million reversal of impairment) comprised of $3.2 million impairment (2010: $2.3 million reversal of impairment) of Ukrainian VAT and $0.4 million reversal of provision for inventory (2010: $1.4 million provision).

Cash flow statement

The Condensed Consolidated Cash Flow Statement shows expenditure of $16.9 million (2010: $6.2 million) on intangible Exploration and evaluation assets and $4.4 million (2010: $5.9 million) on Property, plant and equipment. In addition, the Group received $58.0 million (2010: $nil) as a result of disposal of subsidiaries.

Balance sheet

As at 31 December 2011, the Group had net cash and cash equivalents of $65.0 million (2010: $36.4 million, 2009: $48.6 million). Intangible E&E assets of $66.0 million (2010: $6.2 million, 2009: $nil) represent the carrying value of the Group's investment of exploration and appraisal assets as at 31 December 2011, including $40.3 million of fair value uplift on the valuation of the 70% jointly-controlled interest in the former subsidiary which holds Pokrovskoe licence. The PP&E balance of $99.4 million at 31 December 2011 (2010: $53.9 million, 2009: $51.0 million), comprised of the cost of developing fields with commercial reserves and bringing them into production and $40.0 million of fair value uplift on the valuation of the 40% jointly-controlled interest in the former subsidiary which holds Zagoryanska licence. Trade and other receivables of $66.3 million (2010: $38.7 million, 2009: $38.6 million) include $30.0 million (2010: $33 million, 2009: $30.0 million of non-current other receivables and $6.5 million of current other receivables)receivables in respect of the settlement with GPS (refer to note 3(b) to the Condensed Financial Consolidated Information), $29.1 million (2010: $nil, 2009: $nil) represent deferred and contingent consideration for the disposal of two of Group's subsidiaries to Eni (refer to note 18 to the Condensed Financial Consolidated Information) and $4.3 million prepayments (2010: $0.4 million, 2009: $0.6 million) mostly relate to prepayments made to drilling contractor in Ukraine and long lead materials for the drilling and work over campaign.

Key performance indicators

The Group monitors its performance in implementing its strategy with reference to clear targets set out for five key financial and one key non-financial performance indicators ('KPIs'):

·; to increase oil, gas and condensate production measured on number of barrels of oil equivalent produced per day ('boepd');

·; to increase the Group's oil and gas reserves by de-risking possible resources and contingent reserves into 2P Reserves. This is measured in million barrels of oil equivalent ('mmboe');

·; to increase the realised price per 1,000 cubic metres;

·; to decrease the cost per barrel for exploration and acquisition related expenditure;

·; to increase the Group's basic and diluted earnings per share; and

·; to reduce the number of lost time incidents.

The Group's performance in 2011 against these targets is set out in the table below, together with the prior year performance data. No changes have been made to the source of data or calculation used in the year.

(1) Average production is calculated as the average daily production during the year.

(2) Quantities of 2P reserves as at 31 December 2010 and 2011 are based on Gaffney, Cline & Associates' independent reserves report on 2P Reserves as at 31 December 2009, dated 16 March 2010, as adjusted for the actual production during 2010 and 2011 respectively.

(3) This represents the average price received for gas sold during the year (including VAT).

(4) Basic and diluted profit per Ordinary share is calculated by dividing the net profit for the year attributable to Ordinary equity holder of the parent by the weighted average number of Ordinary shares during the year.

(5) Lost time incidents relate to injuries where an employee/contractor is injured and has time off work.

Related party transactions

Related party transactions are set out in note 32 to the Consolidated Financial Statements of the 2011 Annual Report.

Treasury

The Group continually monitors its exposure to currency risk. It maintains a portfolio of cash and cash equivalent balances mainly in US dollars ('USD') held primarily in the UK and holds these mostly in term deposits depending on the Group's operational requirements. Production revenues from the sale of hydrocarbons are received in the local currency in Ukraine ('UAH') and to date funds from such revenues have been held in Ukraine for further use in operations rather than being remitted to the UK. Funds are transferred to the Company's subsidiaries in USD to fund operations at which time the funds are converted to UAH. Some payments are made on behalf of the subsidiaries from the UK.

Statement of Reserves and Resources

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The Group did not commission an independent Reserves and Resources Evaluation of the Group's oil and gas assets in Ukraine, as at 31 December 2011 due to the insufficient new information being obtained from operational activity before the year end. The summary of the Reserves and Resources below are based on the Independent Reserves and Resources Evaluation performed by Gaffney Cline and Associates as at 31 December 2009 adjusted for 2010 and 2011 actual production.

Summary of Reserves

As of 31 December 2011

*During 2011 the Group produced additional 0.6bcf (2010: 0.3 bcf) of natural gas and 0.02mmbl (2010: 0.01 mmbl) of condensate from the Zagoryanska field which were not included by Gaffney Cline and Associates in the Reserves balances at 31 December 2009 provided in the Reserves and Resources Evaluation Report as at that date.

Summary of Contingent Resources

As of 31 December 2011

Reserves are only assigned to Pirkovskoe, Debeslavetska and Cheremkhivska fields.

Although commercial production has been achieved at Zagoryanska field no 2P reserves have been booked as of 31 December 2011 (2010: nil) as the Group did not receive an update CPR to independently confirm the Reserves quantities.

Contingent Resources are assigned to Zagoryanska, Pirkovskoe, Borynya and Bitlya fields, where development is contingent on further appraisal.

Prospective Resources of 165.9 bcf (2010: 237.0 bcf) of gas and 5.9 mmbl (2010: 8.4 mmbl) of condensate are attributed to Pokrovskoe field (Cadogan's working interest), where there has not yet been a production test. The difference between 2011 and 2010 figures is a result of the change in Cadogan's working interest.

Condensed Consolidated Income Statement

For the year ended 31 December 2011

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Condensed Consolidated Statement of Comprehensive Income

For the year ended 31 December 2011

Condensed Consolidated Balance Sheet

As at 31 December 2011

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Condensed Consolidated Cash Flow Statement

For the year ended 31 December 2011

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Condensed Consolidated Statement of Changes in Equity 

For the year ended 31 December 2011

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Notes to the Condensed Consolidated Financial Information

For the year ended 31 December 2011

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1. General information

Cadogan Petroleum plc (the 'Company', together with its subsidiaries the 'Group'), is incorporated in England and Wales under the Companies Act, who began trading on the London Stock Exchange on 23 June 2008.

The financial information set out above does not constitute the Company's statutory accounts for the years ended 31 December 2011, 2010 or 2009, as defined in section 435 of the Companies Act 2006, but is derived from those accounts. Statutory accounts for the years ended 31 December 2010 and 2009 have been delivered to the Registrar of Companies and those for 2011 will be delivered following the Company's Annual General Meeting.

The auditor has reported on those sets of accounts. The reports for the years ended 31 December 2010 and 2009 were qualified in respect of the limitation to obtain sufficient appropriate audit evidence regarding (a) the carrying values of assets as at 31 December 2008 and (b) the completeness and accuracy of the disclosures of related party transactions and directors' remuneration (as set out in note 3(b) to those accounts). In 2010, the qualification extended only to the Consolidated Income Statement, Consolidated Statement of Comprehensive Income, Consolidated and Parent Company Cash Flow Statements, Consolidated and Parent Company Statement of Changes in Equity and related notes for the year ended 31 December 2009 which formed comparative information for the year ended 31 December 2010. The reports contained a statement under sections 498(2) (unable to determine whether adequate accounting records had been kept) and 498(3) (failure to obtain necessary information and explanations) of the Companies Act 2006 in respect of this limitation.

The 2011 and 2010 auditor's reports contained an emphasis of matter in relation to the uncertainty over recoverability of the amounts included within current other receivables in respect of two gas plants being sold by Global Process Systems LLC as set out in note 3(b). The 2009 auditor's report drew attention by way of emphases of matter in relation to the status of legal proceedings surrounding the validity of certain of the Group's licences in Ukraine and to proposed Annual General Meeting resolutions and potential impact on going concern if passed. The Ukrainian licence issue has been resolved as set out in note 3(f) of the 2010 accounts and the resolutions were never put to the meeting.

2. Significant accounting policies

(a) Basis of accounting

The financial information has been prepared in accordance with IFRSs as adopted by the European Union and has been prepared on the basis of the accounting policies set out in the Group's 2011 Annual Report.

Whilst the financial information in this preliminary announcement has been prepared in accordance with IFRS, this announcement does not itself contain sufficient information to comply with IFRS. A copy of the full financial statements prepared in accordance with IFRS has been published and is available on the Company's website.

The preliminary announcement was approved by the Board on 27 April 2012.

(b) Transition to US dollar reporting

The Directors decided to change the Group's presentation currency from sterling to US dollars with effect from 1 January 2011. The 2011 consolidated financial statements are the first financial statements and the accompanying notes to be reported in US dollars together with the financial information contained in this preliminary announcement.

The majority of the Group's earnings and costs are linked to US dollars or US dollar linked currencies. The investing activity of the Company is being conducted in US dollars and the majority of the Group's funds are currently denominated in US dollars. The change of presentation currency from sterling to US dollar will more closely align the Group's external reporting with international oil and gas industry, thus improving investors' ability to compare financial data.

The change of the Group's presentation currency has been accounted for in accordance with IAS 21 'The Effects of Changes in Foreign Exchange Rates'. The change in the presentation currency from sterling to US dollars has been applied retrospectively in accordance with IAS 8 'Accounting Policies, Changes in Accounting Estimates and Errors' and therefore requires comparative information to be restated and consequently, a third balance sheet is required to be presented in the financial statements.

The following methodology was used to re-present the 2010 and 2009 financial information, originally reported in pounds sterling, into US dollars:

a) assets and liabilities were translated into US dollars at the closing rate prevailing at the balance sheet dates;

b) income and expenses were translated into US dollars at the average exchange rate for the relevant period; and

c) equity items were translated at historical exchange rates from 1 January 2006, the date for which the consolidated financial statements were first prepared under IFRS, all resulting exchange rate differences have been recognised in other comprehensive income, within the foreign currency translation reserve.

(c) Going concern

The Group's business activities, together with the factors likely to affect future development, performance and position are set out in the Business Review. The financial position of the Group, its cash flow and liquidity position are described in the Financial Review.

The Group's cash balance at 31 December 2011 was $65.0 million (2010: $36.4 million, 2009: $48.6 million) with no external debt (2010: $0.4 million, 2009: $nil) and the Directors believe that the funds available at the date of the issue of this financial information is sufficient for the Group to manage its business risks successfully.

The Group's forecasts and projections, taking into account reasonably possible changes in operational performance, start dates and flow rates for commercial production and the price of hydrocarbons sold to Ukrainian customers, show that there are reasonable expectations that the Group will be able to operate on funds currently held and those generated internally, for the foreseeable future, without taking into account receivables from litigation and without the requirement to seek external financing.

As the Group engages in oil and gas exploration and development activities, the most significant risk faced by the Group is delays encountered in achieving commercial production from the Group's major fields. The Group also continues to pursue its farm-out campaign, which, if successful, will enable it to farm-out a portion of its interests in its oil and gas licences to spread the risks associated with further exploration and development.

After making enquiries and considering the uncertainties described above, the Directors have a reasonable expectation that the Company and the Group have adequate resources to continue in operational existence for the foreseeable future and consider the going concern basis of accounting to be appropriate. Thus they continue to adopt the going concern basis of accounting in preparing the financial information.

3. Critical accounting judgements

In the application of the Group's accounting policies, which are described in note 2, the Directors are required to make judgements, estimates and assumptions about the carrying amounts of the assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant. Actual results may differ from these estimates.

The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period or in the period of the revision and future periods if the revision affects both the current and future periods.

The following are the critical judgements and estimates that the Directors have made in the process of applying the Group's accounting policies and that have the most significant effect on the amounts recognised in the financial information:

(a) Disposal of subsidiaries and acquisition of jointly-controlled entities - Eni transaction

To calculate the gain on disposal on the loss of control of the subsidiaries sold to Eni (details of the transaction in note 18), it was necessary to determine the fair value of the consideration received and the fair value of any retained interest. In addition, the fair value of the investment retained in the former subsidiary at the date when control was lost has been regarded as the costs on initial recognition of the jointly controlled entities.

Fair value of the consideration received

The consideration received has been measured at the aggregate of the fair values (at the date of exchange) of the assets received and liabilities incurred or assumed, including any asset or liability resulting from a contingent consideration arrangement. All subsequent changes in the fair value of contingent consideration classified as an asset or liability have been accounted for in accordance with relevant IFRSs.

The determination of the fair value of the contingent consideration and liability arising from the option granted to Eni to acquire a further 30% of the share capital of Pokrovskoe Petroleum BV (the "Pok Option") requires the Directors to use their judgement in selecting an appropriate valuation technique for financial instruments not quoted in an active market. Valuation techniques commonly used by market practitioners have been applied. The Group has applied the Black-Scholes Model to value the Pok Option (recognised as a financial liability at FVTPL). As a result, the Group has made assumptions for the expected volatility and the share price of Pokrovskoe Petroleum BV.

The fair value of the consideration received at the date of exchange, including the fair values of the contingent consideration and the Pok Option liability, together with the key assumptions used therein, are shown in note 18.

Fair value of any retained interest

IFRSs require that the value of the Group's retained interests in the joint controlled entities be recognised at the fair value of the assets and liabilities as at the date of acquisition. In accordance with normal industry practice, identifiable assets and liabilities have been ascribed fair values, and the balance of the fair value of the consideration has been allocated to the fair value attributable to the oil and gas properties held by the jointly controlled entities and the related hydrocarbon reserves. The actual value that will be realised, if any, from them is inherently uncertain and reflects a wide range of factors (including, but not limited to, geological and geophysical factors, future costs and commodity prices, the duration of the licence and its terms and the availability of the financial and other resources needed to progress exploration and development activities). Further details of the carrying amount of assets and liabilities acquired with the jointly controlled entities are provided in note 18.

(b) Other receivable recognised in relation to settlement with Global Process Systems LLC ('GPS')

An amount of $30.0 million has been recognised in current other receivables as at 31 December 2011, representing receivables from a settlement agreement reached with GPS (2010: $33.0 million; 2009: $30 million as non-current other receivable and $6.5 million as current other receivable, see note 15).

During October 2009, a settlement was reached with GPS resolving previous disputes which existed between the Group and GPS concerning the manufacture and delivery of two gas treatment plants for a total purchase price of $54.5 million.

The key commercial terms of the settlement provided for GPS exclusively to market the two gas plants for a 10 month period and, if a sale was achieved, for the Group to receive in stage payments an aggregate cash consideration of $38.5 million. If the plants were not sold within this period, then GPS agreed to take the plants to stock and the Group would receive stage payments for an aggregate cash consideration of $37.5 million.

The settlement also provided for the release by GPS of a potential $10.9 million contractual claim against the Group for the unpaid balance of the consideration for the plants. The amounts of $43.5 million paid to GPS in respect of the gas plants had previously been recognised as prepayments, as title to the gas plants was to pass on delivery. As a result of the settlement, these prepayments were then reclassified as receivables included within other receivables at 31 December 2009. An impairment charge of $6.0 million was provided in the year ended to 31 December 2009 to reduce the carrying value of the original prepayments to their fair value, being the expected proceeds from the settlement.

GPS were not able to sell the plants within the stipulated period, and so the stage payments terms apply. During the years to 31 December 2009, 2010 and 2011, $1.0 million, $3.5 million, and $3.0 million were received from GPS respectively.

The first payment of $10.0 million of the remaining $30.0 million was due to be paid to the Group on 14 February 2011 but was not received. A cure period subsequently expired on 18 April 2011 and on 19 July 2011 the Group rescinded the exclusive right of sale of GPS and as such are able to market the gas plants themselves.

In support of the carrying value of the amounts receivable under the settlement agreement with GPS the Board commissioned a desktop study of the plants by an independent third party in April 2011, which included an estimate of value subject to certain assumptions and caveats. In March 2012, the Board commissioned a different independent third party to provide a report estimating cost to build equivalent gas plants at today's prices. Having taken the foregoing into account, the Board considers that the plants are likely to be worth close to the $30.0 million receivable that remains outstanding under the agreement.

The Group retains legal title to the plants until the final payment has been received from GPS, with whom negotiations continue. As such, the Group maintains insurance cover for the gas plants against fire, accidental damage, and theft to the full value of the $30.0 million receivable at the date of this report.

The Directors consider that the amount of $30.0 million due from GPS under the settlement agreement as at 31 December 2011 is likely to be fully recovered, as supported by the value of the plants as described above and claim against GPS, therefore no impairment charge has been recognised in the year then ended. However, given the difficulties experienced to date in collecting the amounts due from GPS, and inherent uncertainty involved in estimating the value of the plants and the market to sell the plants, this is judgemental.

(c) Impairment of E&E and PP&E

At 31 December 2011 the Group reviewed the carrying amounts of its PP&E and E&E assets to determine whether there is any indication that those assets have suffered an impairment loss. No indicators of non-recoverability of the carrying amounts of the above mentioned assets existed at the balance sheet date.

(d) Reserves

Commercial Reserves are proven and probable ('2P') oil and gas reserves, which are defined as the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50 per cent statistical probability that the actual quantity of recoverable Reserves will be more than the amount estimated as proven and probable Reserves and a 50 per cent statistical probability that it will be less.

Commercial Reserves used in the calculation of depreciation and for impairment test purposes are determined using estimates of oil and gas in place, recovery factors and future oil and gas prices. Management base their estimate of oil and gas Reserves and Resources upon the Report provided by independent advisers.

Although as at 31 December 2009 no 2P reserves were identified at Zagoryanska, in August 2010 commercially recoverable gas was identified in that field.

(e) Recoverability of VAT

The Group has significant receivables from the State Budget of Ukraine relating to reimbursement of VAT arising on purchases of goods and services from external service and product providers. Although $2.8 million of Ukrainian VAT was recovered in the year to 31 December 2010, largely through a bond scheme initiated by the Government of Ukraine, the Directors consider that this scheme was one-off in nature. Management anticipates no significant cash settlements of receivables from the State Budget.

The Group therefore recognises recoverable VAT only to the extent that it is probable that VAT payable arising on the sales of gas production will be sufficient to offset the VAT due from the State within a reasonable period. Estimating the recoverability of VAT requires management to make an estimate of the future revenues in order to calculate amounts and timing of the VAT payable available for offset. The Group will continue to use an approach consistent with prior years by impairing Ukrainian VAT and recognising the recovery in the period it has been made. A provision of $18.2 million (2010: $18.9 million, 2009: $22.3 million) against Ukrainian VAT receivable has thus been recognised as at 31 December 2011.

4. Business and geographical segments

The Directors consider there to be only one business segment, the exploration and development of oil and gas revenues and only one geographical segment, being Ukraine.

5. Dividend

The Directors do not recommend the payment of a dividend for the year (2010: $nil).

6. Other operating income

Out of court settlements in 2011 represent $2.1 million (2010: $4.5 million received during the year from Smith Eurasia a former supplier to the Group and $4.8 million from the Group's former executives).

7. (Impairment)/reversal of impairment of other assets

The carrying value of inventory as at 31 December 2011 and 2010 has been impaired to reduce it to net realisable value.

During the year a net impairment of $3.2 million (2010: $2.3 million reversal of impairment) in respect of Ukrainian VAT was provided which comprised of VAT impairment on new program capital expenditure and VAT recovery of historical balances through offset of VAT liabilities arising on sales.

8. Profit for the year

The profit for the year has been arrived at after charging/(crediting):

In addition to the depreciation of PP&E of $2.4million (2010: $1.9 million) in the year ended 31 December 2011, depreciation of $0.7 million (2010: $0.8 million) was capitalised to E&E assets being depreciation of tangible assets used in E&E activities.

9. Tax

The Group's operations are conducted primarily outside the UK. The most appropriate tax rate for the Group is therefore considered to be 23% (2010: 25%), the rate of profit tax in Ukraine which is the primary source of revenue for the Group. Taxation for other jurisdictions is calculated at the rates prevailing in the respective jurisdictions.

The taxation credit for the year can be reconciled to the profit per the condensed consolidated income statement as follows:

10. Profit per Ordinary share

Basic profit per Ordinary share is calculated by dividing the net profit for the year attributable to owners of the Company by the weighted average number of Ordinary shares outstanding during the year. The calculation of the basic and diluted profit per share is based on the following data:

11. Intangible exploration and evaluation assets

Additions during the year include $0.5 million (2010: $0.6 million, 2009: $2.6 million) of capitalised depreciation of development and production assets used in exploration and evaluation activities.

12. Property, plant and equipment

13. Jointly controlled entities

The Group obtained the following interests in jointly controlled entities, as a result of disposal of subsidiaries (refer to note 18) in 2011:

According to the shareholders' agreements, which regulate activities of jointly controlled entities, all key decisions require unanimous approval from the shareholders, therefore these entities are jointly controlled. The following amounts are included in the Group's Condensed Consolidated Financial Information as a result of the proportionate consolidation as at 31 December 2011 (2010: $nil):

14. Inventories

The impairment provision as at 31 December 2011, 2010 and 2009 is made so as to reduce the carrying value of the inventories to net realisable value.

15. Other financial assets

Other non-current receivables

Trade and other receivables

All sales are made on a prepayment basis, so there are no trade debtors.

Out of $61.8 million of other receivables $30.0 million as at 31 December 2011 (2010: $33.0 million, 2009: $30 million and $6.5 million) represent receivables from a settlement agreement with GPS (note 3(b)), $29.1 million (2010: $nil, 2009: $nil) represents deferred and contingent consideration for the disposal of two of Group's subsidiaries to Eni (note 18).

VAT recoverable of $0.1 million (2010: $0.1 million, 2009: $0.5 million) relates to the UK VAT recoverable.

$4.3 million prepayments (2010: $0.4 million, 2009: $0.6 million) mostly relate to prepayments made to drilling contractors in Ukraine and long lead materials for the drilling and work over campaign.

The Directors consider that the carrying amount of the remaining other receivables approximates their fair value and none of which are past due except for the amounts due from GPS (see note 3(b)).

Cash and cash equivalents

Cash and cash equivalents as at 31 December 2011 of $65.0 million (2010: $36.4 million, 2009: $48.6 million) comprise cash held by the Group and the Company. The Directors consider that the carrying amount of these assets approximates to their fair value.

Other financial assets

In 2011, the Group received $0.7 million held in escrow by the Group's lawyers in Cyprus to support a bank guarantee provided to the Cypriot court in relation to obtaining a freezing order in Cyprus associated with the litigation case. In addition, a short-term deposit of $0.4 million which related to the collateral for short-term borrowings was also released in 2011.

16. Deferred tax

The following are the major deferred tax liabilities and assets recognised by the Group and movements thereon during the current and prior reporting period:

At 31 December 2011, temporary differences of $6.0 million (2010: $9.6 million, 2009: $3.5 million) existed in respect of foreign exchange gains arising on net investments in foreign subsidiaries for which deferred tax liabilities have not been recognised. No deferred tax liabilities have been recognised in respect of these differences because the Group is in a position to control the timing of the reversal of the temporary differences and it is probable that such differences will not reverse in the foreseeable future.

At 31 December 2011, the Group had the following unused tax losses available for offset against future taxable profits:

Deferred tax assets have not been recognised in respect of these tax losses owing to the uncertainty that profits will be available in future periods against which they can be utilised.

The Group's unused tax losses of $5.6 million (2010: $2.5 million, 2009: $7.5 million) relating to losses incurred in the UK are available to shelter future non-trading profits arising within Cadogan Petroleum plc. These losses are not subject to a time restriction on expiry.

Unused tax losses incurred by Ukraine subsidiaries amount to $66.4 million (2010: $69.5 million, 2009: $63.8 million). Under general provisions, these losses may be carried forward indefinitely to be offset against any type of taxable income arising from the same company of origination. Tax losses may not be surrendered from one Ukraine subsidiary to another. However, in the past, Ukrainian legislation has been imposed which restricted the carry forward of tax losses. During 2011 a new tax legislation in Ukraine was implemented which resulted in certain ambiguity about the restriction to accumulated losses at 1 April 2011. Tax authorities were disallowing the accumulated tax losses as of 1 April 2011 which resulted in a significant number of disputes for the Ukrainian businesses. The Group has contested the tax authorities' view in respect of the accumulated losses using administrative procedures and court claims where applicable. Therefore out of $66.4 million of accumulated tax losses in Ukraine $58.6 million may potentially not be used.

There are further temporary differences arising on assets in Ukraine for which deferred tax assets of $6.3 million (2010: $15.2 million, 2009: $19.1 million) have not been recognised due to the uncertainty of future recovery.

17. Notes to the condensed consolidated cash flow statement

18. Disposal of subsidiaries and acquisition of jointly-controlled entities

On 6 July 2011 the Group completed the transaction with Eni, selling a 30% interest in the share capital of Pokroskvoe Petroleum BV (the parent company of the holder of the Pokrovskoe licence), and a 60% interest in the share capital of Zagoryanska Petroleum BV (the parent company of the holder of the Zagoryanska licence). Both licences relate to the Group's operations in eastern Ukraine.

The consideration received comprised a cash payment of $38.1 million for its interest in Zagoryanska Petroleum BV and $0.2 million as the working capital adjustment for both the Zagoryanska and Pokrovskoe licences. Eni is also committed to finance the Pokrovskoe appraisal work programme to an amount of up to $36 million (including VAT).

Under the terms of the sale and purchase agreement and subject to successful results from the Pokrovskoe appraisal work programme, Eni also had the option under the agreement to acquire a further 30% of Pokrovskoe Petroleum BV for an additional payment of $40 million (the "Pok Option"). Eni will also pay additional amounts of $15 million and $35 million (the "Contingent Consideration") should the Group successfully acquire production licences on each of the Pokrovskoe and Zagoryanska fields respectively. The Pokrovskoe Contingent Consideration is only payable if the Pok Option is exercised.

As at 6 July 2011, the net assets of the subsidiaries disposed (Pokrovskoe Petroleum BV and Zagoryanska Petroleum BV), together with the net assets acquired on the jointly-controlled entities which are since being proportionately consolidated into the Group's financial information, were as follows:

The consideration received from the Eni has been measured at the aggregate of the cash received, the deferred consideration (of which $20.9 million was received in cash during the second half of the year), the reimbursement payable to Eni in respect to part of Zagoryanska 3 well cost, which is to be transferred to the licence-holder at no cost to Eni, the Contingent Consideration and the fair value of the Pok Option.

The Contingent Consideration was calculated applying probability assumptions for the potential payment, which will be trigger upon successful acquisition of the production licences. A probability of 60% and 90% was applied to Pokrovskoe and Zagoryanska fields respectively based on management's assessment of the appraisal and exploration risks. The Contingent Consideration was discounted using a rate 10% which is management's view that reflects the market assessment of time value of money and the expected timing of the payment.

A financial liability was recognised in relation to the issuance of the Pok Option to Eni. The fair value of the Pok Option was calculated, using the Black-Scholes model. The variables and assumptions used in computing the fair value of the Pok Option are based on the Directors' best estimates. The value of an option varies with different variables of certain subjective assumptions. The inputs into the model were as follows:

The share price was determined on the basis of the price paid by Eni for 30% interest in Pokrovskoe licence, rounded to the nearest half million US dollars.

The exercise price and the expected term of the Pok Option are set out in the terms of the agreement. The expected volatility was determined on the basis of the Company's share price volatility and compared to the shares of comparable companies (companies in evaluation and exploration stage). The risk free rate was determined with reference to the yield on US bonds with duration similar to the expected contractual life of the Pok Option and country premium risk. The expected dividend yield is based on the planned dividend policy of Pokrovskoe Petroleum BV.

The above changes in the fair value of the Pok Option and the Contingent Consideration have been presented in the Other gains and losses line in the Condensed Consolidated Income Statement for the year.

As of 31 December 2011 management consider that there was no indication of Eni's intention to exercise the Pok Option and in March 2012 Eni informed the Group that they will not exercise the Pok Option (refer to note 20). Therefore, management's estimate of the fair value of financial liability, evaluated at $4.2 million at the date of acquisition, decreased to $nil as at 31 December 2011. On the same basis, the fair value of the Contingent Consideration decreased from $7.5 million to $nil as at 31 December 2011, for which the exercise of the Pok Option was a prerequisite.

19. Commitments and contingencies

Joint activity agreements

The Group has interests in nine licences for the conduct of its exploration and development activities within Ukraine. Each licence is held with the obligation to fulfil a minimum set of exploration activities within its term and is summarised on an annual basis, including the agreed minimum amount forecasted expenditure to fulfil those obligations. The activities and proposed expenditure levels are agreed with the government licensing authority.

The minimum required future financing of exploration and development work on fields under the licence obligations are as follow:

A greater level of capital expenditure could, however, be incurred in the above period to achieve the Group's corporate targets. $3.7 million within one year capital commitments (2010: nil, 2009: nil) and $7.4 million between two and five years capital commitments (2010: nil, 2009: nil) relate to joint ventures activities.

20. Events after the balance sheet date

Pokrovskoe update

On 9 March 2012 the Group has been advised by Eni that after analysis of the results for the Pokrovskoe 1 and Pokrovskoe 2a wells that Eni do not intend to exercise their option to acquire a further 30% of the share capital of Pokrovskoe Petroleum BV. The option formed part of the transaction entered into with Eni in July 2011 (note 18).

As advised in the Company's announcement dated 16 February 2012 the logs acquired during the drilling programme indicated the presence of hydrocarbons in the lower part of the well. A decision had been taken to deepen the Pokrovskoe 2a well by approximately 350 metres. Whilst pulling out of the hole the running string became stuck and subsequent fishing operations with the limited equipment available in country did not allow the running tool to be recovered. Cadogan management will continue to evaluate the most effective option, amongst those available, to re-enter the well.