Cadogan Petroleum plc (“Cadogan” or the “Company”), an independent oil and gas exploration, development and production company with onshore gas, condensate and oil assets in Ukraine, announces its unaudited results for the six months ended 30 June 2012.
· Continued production from the Zagoryanska, Debeslavetska and Cheremkivska licences at a combined rate of about 51 mcm/day of gas and 5.1 tons/day of condensate
· Joint venture established to develop unconventional shale gas in Lviv western Ukraine announced
· New well at Zagoryanska 11 drilled
· Total capital expenditure of $16.2 million during the first half of 2012 (30 June 2011: $3.0 million)
· Decreased operating costs to $4.9 million (H1 2011: $5.4 million) despite significant increase in activity
· Net cash and cash equivalents at 30 June 2012 of $51.3 million (31 December 2011: $65.0 million)
Commenting on the results, Bertrand des Pallieres Chief Executive Officer said:
“As predicted in 2011 the Company has made significant progress in its strategic alliances with both state companies and major oil companies and is developing exciting opportunities for the business. Although the results of the shale gas initiative will take time to be realised, Cadogan is able to participate in this type of venture without the usual significant levels of capital. A further initiative is being considered in the shallow Black Sea area. These activities continue to demonstrate our aim to become a key player in accelerating the transformation of the energy sector in Ukraine.”
During the first half of 2012 the Group continued to focus on developing its assets in Ukraine, with continuing production from one major asset in eastern Ukraine and from three minor assets in western Ukraine. Although significant increases in production from new assets have yet to be achieved, management has in 2012 run a significantly larger capital investment programme than in previous years, with no corresponding increase in operating costs due to a significant management focus on productivity initiatives.
In June 2012 Cadogan with its joint venture partner, Ukrainian state-owned National Joint Stock Company Nak Nadra Ukrayny (“Nadra”), entered into a Share Purchase Agreement with Eni S.p.A (“Eni”), the Italian integrated energy company, whereby Eni will acquire a stake in the joint venture established by Nadra and Cadogan, Ukrainian company LLC Westgasinvest. LLC Westgasinvest 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.
Under the transaction, Eni will acquire 50.01% of LLC Westgasinvest from the joint venture parties and will fund an initial exploration program. Cadogan had transferred ownership of its two west Ukraine licences, Debeslavetska and Cheremkhivska to the joint venture. Following the conclusion of the transaction Cadogan will retain ownership of 15% of LLC Westgasinvest. The transaction remains conditional on achieving certain conditions precedent including Ukraine anti monopoly clearance and this is on target to occur by the end of September. Cadogan remains the operator for its existing conventional activities at Debeslavetska and Cheremkhivska and will keep the economic benefit from the conventional activities on these two licenses.
During the period to 30 June 2012 the Group continued to operate safely and efficiently.
Since the end of the half year the Group has concluded the drilling activity on its Zagoryanska 11 well and the data acquisition programme is underway. The results will be announced once the full programme and validation has been concluded. Results of the various Zagoryanska workovers of the wells acquired in 2010 that were initially drilled in the Soviet era have not been in accordance with expectations, but the information gathered is being compiled into a further analysis of the Zagoryanska fields and the adjacent Pirkroskvoe field to identify reservoir structures. The rig used on the Zagoryanska 11 drilling project has been moved to another major oil company project in eastern Ukraine, but will remain available to Cadogan for further projects in 2013.
Operations at Pokrovskoe remain temporarily suspended. The Pokrovskoe 2a well was drilled to 4,783 metres into the V22 level of the Upper Visean. The Logs acquired indicated the presence of hydrocarbons in the lower part of the well and a decision was taken to deepen the 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 has not allowed the running tool to be recovered. Management will evaluate the most effective option, amongst those available, to re-enter the well. After analysis of the results for the Pokroskvoe 1 well, deepened in 2011, and the Pokroskvoe 2a wells, Eni advised Cadogan that it did not intend to exercise its option to acquire a further 30% of the share capital of Pokroskvoe Petroleum BV. The option formed part of the transaction entered into with Eni in July 2011.
Production from the Zagoryanska, Debeslavetska and Cheremkivska licences continued at a combined rate of approximately 51 mcm/day of gas and 5.1 tons/day of condensate.
Under the October 2009 settlement with Global Process Systems Inc (GPS), the Group is entitled to a payment of $37.5 million. To date $7.5 million has been received but the remaining $30 million due to the Group in 2011 has not been received. As a consequence of this non-payment the Group rescinded GPS’s exclusive right to sell the plants contained within the settlement agreement and started legal proceedings to recover the amounts due. The Group retains legal title to both plants and management continues to expect to recover value of at least $30 million due to the Group through a sale of the plants and recovery through litigation.
At the date of this report, the Group had cash and cash equivalents of approximately $46.9 million. The Directors believe that the capital available at the date of this report is sufficient for the Company and the Group to continue operations for the foreseeable future.
Changes to the board
On 26 January 2012 Adelmo Schenato was appointed a director of the Company and became the Group’s Chief Operating Officer. On 19 June 2012 Ian Baron resigned as a director of the Company. Mr Alessandro Benedetti resigned as a director of the Company on 27 June 2012.
Cadogan continues to aggressively develop and manage its portfolio of assets in Ukraine in order to fully exploit substantial industry changes taking place there. The Board believes that this strategy will allow the Company to develop into a significant player in the potential rich Ukraine energy sector.
Reserves and resources
As at 30 June 2012 the Group held working interests in nine (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 infrastructure. The Group’s primary focus is on the four licences where the main reserve and resource potential is located, Zagoryanska, Pokrovskoe, and Pirkovskoe in the Dnieper-Donets basin of east Ukraine and Bitlyanska, in the Carpathian Basin of west Ukraine.
|Summary of the Group’s licences held at 30 June 2012
(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 working interest on Debeslavetske and Cheremkhivske licences did not change for the conventional gas as the result of the transaction described in the Board Statement above.
The following are updates to the full Operations Review contained in the Annual Financial Report for 2011:
In 2009 the Zagoryanska 3 well was perforated and commercial flow rates were achieved. Production from the well 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 gross production rates during the first half of 2012 were 30 mcm/day gas (H1 2011: 35 mcm/day) and 5.1 t/day condensate (H1 2011: 8 t/day).
As required by the work programme on the licence, a new well has been drilled to 5,180 metres at Zagoryanska 11. The well has been completed and a data acquisition programme is being carried out, and the results will be available by the end of Q3 2012. The rig used on the Zagoryanska 11 drilling project has been moved to another major oil company project in eastern Ukraine. As required by the licence, further geological and economic estimation of hydrocarbon reserves, seismic interpretation, modelling and geological studies of the field are on-going.
Following the purchase of the Zagoryanska 3 well in 2010, (which it was previously renting), together with four additional wells on the field a work over plan was prepared for three of the four additional wells (Zagoryanska 1, 2 and 8). Zagoryanska 1 and 2 wells have been worked over, and work over operations are concluded and both wells are presently being monitored; the work over of Zagoryanska 8 identified issues within the old well that could not be resolved with the fishing equipment available in country and is temporarily abandoned.
At Pokrovskoe 2a the well was drilled to a casing point at 4,783 metres in 2012 where the logs acquired indicated the presence of hydrocarbons in the lower part of the well and a decision was taken to deepen the well by approximately 250 metres. Whilst pulling out of the hole 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. After analysis of the results for the Pokroskvoe 1 well, deepened in 2011, and the Pokroskvoe 2a wells, Eni advised Cadogan that it did not intend to exercise its option to acquire a further 30% of the share capital of Pokroskvoe Petroleum BV. The option formed part of the transaction entered into with Eni in July 2011.
No activity to report up to the date of this report.
Bitlyanska licence area
No activity to report up to the date of this report.
The Group has a number of minor licence areas located in western Ukraine. These include the following:
· Debeslavetska Production licence area
The field is currently producing 101.4 boepd (full year 2011 was 84.0 boepd). The planned compressor maintenance is under schedule.
· Cheremkhivska Production licence area
This licence is currently producing 23.0 boepd (full year 2011 was 32.8 boepd).
· Monastyretska licence area
After re-entry of the Blazhiv 1 well in 2011, minor oil production was re-established at the rate of 16 bopd. A basic hydraulic formation cleaning on the well was conducted; and present production is averaging 20 – 25 bopd. Well behaviour is being monitored and further actions are being considered.
In the six months ended 30 June 2012 the Group mainly focused on exploration activity at Pokrovskoe and appraisal activity at Zagoryanska fields together with its joint venture partner Eni. In total $16.2 million was spent on capital expenditure, which was a primary reason for the cash position to decrease to $51.3 million as at 30 June 2012 from $65.0 million as at 31 December 2011.
Loss before tax was $7.1 million (30 June 2011: $6.2 million, 31 December 2011: profit – $152.6 million). Revenues of $2.7 million (30 June 2011: $4.4 million, 31 December 2011: $7.0 million) comprised sales of gas from the Debeslavetska, Cheremkhivska fields and Zagoryanska 3 well. Cost of sales, which represents production royalties and taxes, depreciation and depletion of producing wells and direct staff costs amounted to $1.9 million (30 June 2011: $3.5 million, 31 December 2011: $6.3 million) to give a gross profit of $0.8 million (30 June 2011: $0.8 million, 31 December 2011: $0.7 million). In addition, an increase in the gas price in Ukraine enabled gross margin to increase to 30% from 19% for the comparative period in 2011.
· Other administrative expenses of $4.9 million (30 June 2011: $5.4 million, 31 December 2011: $11.6 million) comprise staff costs, professional fees, Directors’ remuneration, depreciation charges on non-producing property, plant and equipment.
· Net impairment charges of $2.0 million (30 June 2011: $0.3 million reversal of impairment, 31 December 2011: $2.8 million) relates to Ukrainian VAT impairment.
· Other operating loss of $1.1 million (30 June 2011: $2.0 million, 31 December 2011: income – $4.6 million) relates to net foreign exchange losses (30 June 2011: $2.0 million, 31 December 2011: gain – $2.4 million) mainly on the translation of the USD denominated monetary assets held by the UK companies whose functional currency is GBP.
Profit on disposal of subsidiaries and other losses for the year ended 31 December 2011 relate to the Eni transaction completed in July 2011 (refer to note 39 to the Consolidated Financial Statements for year ended 31 December 2011).
Cash flow statement
The Condensed Consolidated Cash Flow Statement on page 13 shows expenditure of $6.1 million (30 June 2011: $2.0 million, 31 December 2011: $16.9 million) on intangible Exploration and evaluation assets (E&E) and $10.0 million (30 June 2011: $0.9 million, 31 December 2011: $4.4 million) on Property, plant and equipment (PP&E). In addition, the Group received $4.1 million (30 June 2011: $nil, 31 December 2011: $58.0 million) as a part of deferred consideration from disposal of subsidiaries in 2011.
Net cash outflow from operations has decreased to $2.2 million during six months ended 2012 from $3.5 million in the same period of 2011 mainly due to changes in the working capital.
As at 30 June 2012, the Group had net cash and cash equivalents of $51.3 million (30 June 2011: $30.9 million, 31 December 2011: $65.0 million). Intangible E&E assets of $71.7 million (30 June 2011: $8.4 million, 31 December 2011: $66.0 million) represent the carrying value of the Group’s investment in exploration and appraisal assets, mainly at Pokrovskoe licence. It also includes $40.3 million of fair value uplift recognised in 2011 from the valuation of the 70% jointly-controlled interest in the former subsidiary which holds the licence. The PP&E balance of $107.9 million (30 June 2011: $53.2 million, 31 December 2011: $99.4 million), comprised of the cost of developing fields with commercial reserves and bringing them into production. It includes $40.0 million of fair value uplift recognised in 2011 from the valuation of the 40% jointly-controlled interest in the former subsidiary which holds Zagoryanska licence. Trade and other receivables of $58.5 million (30 June 2011: $35.8 million, 31 December 2011: $66.3 million) include $30.0 million (30 June 2011: $30.0 million, 31 December 2011: $30.0 million) receivables in respect of the settlement with GPS, $24.7 million (30 June 2011: $nil, 31 December 2011: $29.1 million) represent deferred and contingent consideration for the disposal of two of Group’s subsidiaries to Eni in July 2011 and $1.1 million prepayments (30 June 2011: $3.3 million, 31 December 2011: $4.3 million) mostly relate to prepayments made to contractors in Ukraine for the drilling and work over campaign.
Related party transactions
No material transactions have taken place with related parties during the six months to 30 June 2012.
There has not been any change to the commitments and contingencies reported as at 31 December 2011 (refer to page 64 of the Annual Report).
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 Ukrainian hryvnia (‘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.
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 during the six months 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 period/year.
||30 June 2012
||30 June 2011
||31 December 2011
|Average production (working interest basis) (1)
|2P reserves (2)
|Realised price per 1,000 cubic metres (3)
|Basic and diluted (loss)/profit per share (4)
|Lost time incidents (5)
(1) Average production is calculated as the average daily production during the period.
(2) Quantities of 2P reserves as at 30 June 2012 and 31 December 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 until 30 June 2012, 30 June 2011 and 31 December 2011 respectively.
(3) This represents the average price received for gas sold during the period (including VAT).
(4) Basic and diluted (loss)/profit per Ordinary share is calculated by dividing the net (loss)/profit for the period attributable to Ordinary equity holder of the parent by the weighted average number of Ordinary shares during the period.
(5) Lost time incidents relate to injuries where an employee/contractor is injured and has time off work.
Risk and Uncertainties
There are a number of potential risks and uncertainties inherent in the oil and gas sector which could have a material impact on the long-term performance of the Group and which could cause the actual results to differ materially from expected and historical results. The Company has taken reasonable steps to mitigate these where possible. Full details are disclosed on pages 12 to 13 of the 2011 Annual Financial Report. There have been no changes to the risk profile during the first half of the year. These are summarised below:
· Health, safety, and environment
· Drilling operations
· Production and maintenance
· Work over and abandonment
· Subsurface risks
· Recoverability of the Group’s assets
· Liquidity risk, management and going concern assumption
· Regulatory and tax compliance risk
· Fraud risk
· Foreign exchange risk
· Inflation risk
· Credit risk
· Commodity price risk
· Regulatory and licence issues
· Emerging market risk
· Insurance risk
Directors’ Responsibility Statement
We confirm that to the best of our knowledge:
(a) the Condensed set of Financial Statements has been prepared in accordance with IAS 34 ‘Interim Financial Reporting’;
(b) the interim management report includes a fair review of the information required by DTR 4.2.7R (indication of important events during the first six months and description of principal risks and uncertainties for the remaining six months of the year);
(c) the interim management report includes a fair review of the information required by DTR 4.2.8R (disclosure of related parties’ transactions and changes therein); and
(d) the condensed set of financial statements, which has been prepared in accordance with the applicable set of accounting standards, gives a true and fair view of the assets, liabilities, financial position and profit or loss of the issuer, or the undertakings included in the consolidation as a whole as required by DTR 4.2.4R.