Urals Energy Public Company Limited ( Urals Energy or the Company ) 2011 Half Year Results

Transcription

1 30 September, 2011 Urals Energy Public Company Limited ( Urals Energy or the Company ) 2011 Half Year Results Urals Energy (LSE: UEN), the independent exploration and production company with operations in Russia, today announces its half year results for the six months ended 30 June Highlights Operational Total production from Arcticneft increased to 126,780 barrels (121,605 barrels in H1 2010) Total production from Petrosakh of 249,728 barrels (255,655 barrels in H1 2010) Average daily production for the period was 2,080 BOPD (2,084 BOPD H1 2010) Current daily production at Arcticneft increased to 713 BOPD from an average of 700 BOPD for the six months ended 30 June 2011 Current daily levels of production at Petrosakh increased to 1,457 BOPD from an average of 1,380 BOPD for the six months ended 30 June 2011 A successful 12 well workover program at Petrosakh stabilized production decline Ongoing activity in neighbouring blocks may further de-risk Ural s acreage Financial Net profit of US$3.6 million (net loss of US$1.6 million for H1 2010) Net cash position of US$9.1 million at 30 June 2011 (US$2.4 million for H1 2010) Operating loss of US$2.9 million as result of non-cash transactions (H profit of US$1.6 million) Ongoing repayment schedule of payments to Petraco Oil Company Limited ( Petraco ) as per the restructuring agreement Successful implementation of cost reduction programme Ongoing discussions regarding the restructuring of the Taas loan Outlook Continuing focus on repayment of outstanding debts and strengthening of the balance sheet Loading of up to 26,500 metric tons of crude oil for export from Arcticneft scheduled for October 2011 Identifying ways of utilising the upside potential in downstream and marketing opportunities on the existing acreage Expected revision of export duty from early October 2011 to give approximately an additional $5/bbl of netback Urals will continue to consider and evaluate possible acquisition and joint venture targets with a view to expanding and optimising the Company s asset portfolio Commenting on today s announcement, Alexei Maximov, CEO, said; I am pleased to report that over the period the Company has continued its measured advance towards a firm recovery. Operationally, we have been laying the foundations for maximizing production from both Arcticneft and Petrosakh. Financially, we continue to make progress reducing our debt position and fortifying our balance sheet. The Company continues to focus on increasing production and cash generation at both Arcticneft and Petrosakh. With a stronger balance sheet, we expect to succeed in our operational strategy and view the future with greater confidence. Enquiries: Allenby Capital Limited Nominated adviser and broker +44 (0) Nick Naylor Alex Price Pelham PR +44 (0)

2 Mark Antelme Maria Blank CEO STATEMENT In December 2010 the Company completed a successful share placing raising US$9.24million. The placing provided the Company with sufficient funds to begin the process of fulfilling its 2011 strategic objective of increasing production across the asset portfolio, as well as being a positive sign that the company is in recovery mode. The revenues from the production increase will facilitate the ongoing Petraco loan repayment. Urals is also in active discussions regarding the restructuring of the Taas loan and the Board looks forward to updating the market on this matter at the appropriate time. Considerable workovers of the onshore Petrosakh and Arcticneft licenses commenced in 2011, with a view to investigating the potential of the surrounding resources. Production in Petrosakh has increased by 114 BOPD as a result of additional perforation in two wells and a moderate increase is as a result of back pressure reduction and draw down increase. This entire work programme is being performed by existing staff using materials and equipment kept on site, therefore without additional cost to the Company. During the first half of 2011 development well #51 was spudded. Target depth of 1,650 meters was reached in July However, as a result of difficult geological conditions, while preparing to run a production string, drilling equipment jammed the well, which prevented completion. A decision was subsequently made to test the upper horizon and a moderate flow rate of 37 BOPD was recorded, confirming productivity of the well. Consequently, a parallel well was drilled from a depth of 1,370 meters. However, at a depth of 1,460 meters the decision was made to plug and temporarily abandon Well # 51 due to the difficult drilling conditions. Further potential may be identified at Arcticneft, as a result of the planned drilling of a deep exploration well by ArcticMorNefteGazRazvedka ("AMNGR") in the lower Paleozoic horizon of the Peschanoozerskoye field. Since both Arcticneft and AMNGR operate the same field (albeit different blocks), we anticipate that AMNGR s results may provide a strong indication for the potential for Urals to increase its reserves in the same area and formation. We expect to receive a positive result by Q High oil prices in 2011 increased the profitability of the Company s operations, however at the same time this fact has also effected the Company s working capital position, especially at Arcticneft, where oil is produced and production taxes are paid at a higher tax rate. As was recently announced by the Russian government, a change in the export duty tax regime is expected to take place from early October Based on the preliminary information available, an expected decrease in export duty for crude oil may result in approximately $5/bbl of additional net back to the Company at Brent $100 per bbl. Hence, in order to fully benefit from the proposed regime, the Company has a planned delivery of 26,500 metric tons of crude in October. We will also continue to actively pursue possible acquisition targets and/or joint venture opportunities to complement the Company s existing asset portfolio. I would like to take this opportunity to thank our shareholders, employees and partners for their on-going support of the Company and its re-focussed strategy in this new chapter of Urals growth. Financial Results Operating Environment The six months ended 30 June 2011 were characterised by stable crude oil market price at an average level of US$110 per barrel. Domestic prices for light oil products ranged from US$75 to US$90 per barrel thus securing the Company s operating cash flows at a level sufficient to maintain its operations and comply with license requirements at both fields. There were no deliveries of crude oil exported from Arcticneft during the reporting period, resulting in 22,000 metric tons of crude oil that remained in stock. The tanker from Arcticneft is expected in October 2011.

3 At the same time, at Petrosakh, the Company accelerated production and sales of refined products, thus securing the Company s liquidity during the period of non deliveries from Arcticneft. Operating Results $ 000 Period ended 30 June: Gross revenues before excise, export duties 17,139 11,690 Net revenues after excise, export duties and VAT 15,395 11,078 Gross profit 1,513 2,561 Operating (loss)/profit (2,851) 1,554 Management EBITDA Total net finance benefits/(costs) 5,868 (585) Profit for the period 3,607 1,558 Gross Revenues ($ 000) Period ended 30 June: Crude oil 1,807 1,523 Export sales - - Domestic sales (Russian Federation) 1,807 1,523 Petroleum (refined) products domestic sales 14,930 9,779 Other sales Total gross revenues 17,139 11,690 For the six months ended 30 June 2011, total gross revenues increased by US$5.4 million as a result of growth of sales volumes totaling 264,092 barrels for the six months ended 30 June 2011 (compared with 210,385 barrels for the six months ended 30 June 2010) and as a result of raise of average net back prices for petroleum (refined) products of US$47.43 per barrel for the six months ended 30 June 2011 (US$44.11 for the six months ended 30 June 2010). The increase was partially off-set by a lower crude oil net back price of US$35.87 per barrel for the six months ended 30 June 2011 (US$40.33 per barrel for the six months ended 30 June 2010). Netback, in the case of domestic crude oil sales, is the gross sales net of VAT. Netback for domestic product sales is defined as gross product sales minus VAT, transportation, excise tax and refining costs. For the six months ended 30 June 2011 all domestic sales of crude oil and almost all petroleum (refined) products related to Petrosakh. During the six months ended 30 June 2011 Arcticneft sold petroleum (refined) products to FGUP ArcticMorNefteGazRazvedka" ( AMNGR ) for US$302,000 (US$307,000 for the six months ended 30 June 2010). Summary table: Net backs ($/bbl) Period ended 30 June: Crude oil Export sales - - Domestic sales (Russian Federation) Petroleum (refined) products domestic sales Gross profit (net revenues less cost of sales) for the first half of 2011 decreased to US$1.5 million from US$2.6 million for the six months ended 30 June The main driver of the decline was the increase of Depreciation, Amortization and Depletion associated with the impairment release of property, plant and equipment in Arcticneft and Petrosakh in Operating Loss for the first half of 2011 was US$2.9 million, primarily driven by non-cash transactions associated with the Depreciation, Amortization and Depletion and by the release of provisions of US$0.6 million

4 for the first half of 2011, as compared with an Operating Profit of US$1.6 million for the six months ended 30 June. The net finance benefits during the first half of 2011 were US$5.9 million and net interest benefit was US$1.3 million (for the six months ended 30 June 2010: net finance costs of US$0.6 million and net interest benefit of US$1 million). Increase of Finance benefits for the six months ended 30 June 2011 resulted in a Net Profit of US$3.6 million compared with US$1.6 million for the six months ended 30 June Consolidated Management EBITDA in the six months ended 30 June 2011 was US$114,000 as compared with US$79,000 during the six months ended 30 June Management EBITDA ($ 000) - Unaudited Period ended 30 June: Profit for the period 3,607 1,558 Net finance (benefits)/costs (5,868) 585 Income tax (591) (589) Depreciation, depletion and amortization 2,455 1,238 Total non-cash expenses (4,004) 1,234 Share-based payments Resignation fees to top-managers Loss/(gain) from disposal of property, plant and equipment 704 (1,227) Release of provisions (569) (1,869) Other non-cash income (88) - Total non-recurrent and non-cash items 511 (2,713) Normalised EBITDA Cash Flow The Company s cash position for the six months ended 30 June 2011 did not change significantly as compared with the six months ended 30 June The Group used US$3.3 million on operating activities, primarily financing production at Arcticneft and working capital associated with that production (the Company pays operating expenses and production taxes at the time crude is produced, whilst the sales of crude at Arcticneft take place only twice a year due to seasonality of shipments). During the first half of 2011 the Company repaid $4 million of debt to Petraco and used $1.6 million in investing activities. Management believes that with the expected crude oil delivery from Arcticneft and in the event that world crude oil prices do not change significantly as compared with the current prices, the Company will have sufficient funds to make repayment of both tranches due to Petraco ($8 million in aggregate) by the end of November Net debt Position As of 30 June 2011 the Company had net cash of US$9.1 million (calculated as Long-term and Short-term debt plus payables to Finfund less cash in bank, less loan receivable from Taas and less Loans issued to related parties). As at 31 December 2010 net cash was US$13.3 million. The Company repaid the tranche to Petraco which was due at the end of December 2010 in amount of $4.0 million in early January 2011.

5 Accounts payable and accrued expenses of $10.7 million at the period end mainly represented outstanding accounts payable to Finfund with the maximum liability of $4.4 million at 30 June 2011 for the pledge fee. On 2 June 2010 the Company was notified that Finfund Limited had exercised its rights to acquire 13,000,000 existing Urals Energy shares with a nominal value of US$ per share from entities beneficially owned by two directors (Leonid Y. Dyachenko and Aleksey V. Ogarev) and another significant shareholder (Vyacheslav V. Rovneiko) (together the Pledge Shareholders ) pursuant to a share pledge agreement dated 26 November 2007 (the Share Pledge Agreement ). The Share Pledge Agreement was entered into by entities beneficially owned by the Pledge Shareholders and secured various obligations of the Company under the terms of a sale and purchase agreement dated 26 November 2007 (the SPA ) relating to the acquisition by Urals of Taas-YuriakhNeftegazodobycha (the Acquisition ). Such obligations included certain pledge fees which Finfund Limited are now claiming are owed by the Company. Based on the Company s alleged defaults in respect of the payment of such fees, Finfund Limited has chosen to exercise its rights under the Share Pledge Agreement to acquire 13,000,000 shares in the Company from entities beneficially owned by the Pledge Shareholders (the Pledged Shares ). As of 30 June 2011 and 31 December 2010 the Group impaired a loan to a formerly related party by $5.5 million and $5.2 million, respectively. This amount relates to a loan to a shareholder and former member of management of the Group (Vyatcheslav Rovneiko). This loan is overdue and is secured by a pledge on an entity whose primary asset is real estate properties located in Moscow. In October 2010 the management became aware of the fact that the same real estate has been additionally pledged to secure funding from external banks. This fact was divulged to management and was considered to be misconduct on behalf of the related party resulting in a devaluation of the Group s collateral. As a result, the Board immediately informed this related party that it is aware of this fact and demanded repayment of the full amount by 20 May By 20 May 2011 the Company did not received any response from the related party. Taking into account that according to the loan agreement all disputes are subject to final resolution by arbitration under the Rules of Arbitration of the London Court of International Arbitration (the LCIA), the Company filed a claim with the LCIA in June In August 2011 the LCIA notified the appointment of a sole arbitrator to consider the dispute and the Company confirmed that the Request for Arbitration is a Statement of Case. The related party is required to file a statement of defense prior to 10 October 2011 after which the dispute will go into arbitration, which we believe will be resolved in the Company s favor within a few months. The Company had an option to pursue the real estate properties in Moscow, but the Board was of the view that this course of action would ultimately be a longer and less certain course of action. For accounting purposes the management has reassessed the carrying value of the loan and has impaired it fully. However, this does not reduce the validity of the legal claim against this related party. Outlook Looking ahead, as part of the recovery strategy, the ongoing strengthening of the balance sheet remains a key priority and the Company will continue to make further progress with the repayment of its outstanding debts. We are shortly going to be loading up to 26,500 metric tons of crude oil for export from Arcticneft, which is scheduled for October Furthermore, the expected revision of export duty from early October 2011 is expected to give approximately an additional $5/bbl of netback to the Company. The Company continues to focus on increasing production and cash generation at both Arcticneft and Petrosakh. In addition to our existing operations, we are actively looking at new opportunities, be it in identifying ways of utilising the upside potential in downstream and marketing opportunities on the existing acreage, or evaluating possible acquisition and joint venture targets with a view to expanding and optimising the portfolio. With a stronger balance sheet, we expect to succeed in our operational strategy and, with the management and shareholder s interests closely aligned, view the future with greater confidence. Alexei Maximov Chief Executive Officer The accompanying notes are an integral part of these interim condensed consolidated financial information Interim Condensed Consolidated Statement of Financial Position (unaudited) (presented in US$ thousands)

6 Assets Note 30 June December 2010 Current assets Cash in bank and on hand Accounts receivable and prepayments 4,737 14,928 Inventories 7 21,694 12,911 Total current assets 27,261 28,826 Non-current assets Property, plant and equipment 5 135, ,817 Supplies and materials for capital construction 2,852 2,655 Other non-current assets 6 41,263 39,426 Total non-current assets 179, ,898 Total assets 206, ,724 Liabilities and equity Current liabilities Accounts payable and accrued expenses 8 8,742 10,781 Provisions 2,000 2,559 Income tax payable 5,118 5,118 Other taxes payable 8,004 5,151 Short-term borrowings and current portion of long-term borrowings 10 8,127 12,172 Advances from customers 9 3,844 4,259 Total current liabilities 35,835 40,040 Long-term liabilities Long-term borrowings 10 19,356 18,653 Long term finance lease obligations Dismantlement provision 1,422 1,232 Deferred tax liability 12,864 12,387 Total long-term liabilities 34,287 32,601 Total liabilities 70,122 72,641 Equity Share capital 11 1,569 1,543 Share premium , ,444 Translation difference (23,269) (28,858) Retained earnings (499,401) (503,016) Equity attributable to shareholders of Urals Energy Public Company Limited 135, ,113 Minority interest 1, Total equity 136, ,083 Total liabilities and equity 206, ,724 Approved on behalf of the Board of Directors on September 2011 A.D. Maximov Chief Executive Officer G.B. Kazakov Chief Financial Officer Interim Condensed Consolidated Statement of Comprehensive Income (unaudited) (presented in US$ thousands) Six months ended 30 June: Note Revenues Gross revenues 12 17,139 11,690 Less: excise taxes (1,744) (612)

7 Net revenues after excise taxes 15,395 11,078 Cost of sales 13 (13,882) (8,517) Gross profit/(loss) 1,513 2,561 Selling, general and administrative expenses 14 (4,525) (4,647) Other non-operating income, net ,640 Operating loss (2,851) 1,554 Interest income 1,727 2,012 Interest expense (393) (1,043) Foreign currency gains/(losses) 4,534 (1,554) Total net finance benefits/(costs) 5,868 (585) Profit before income tax 3, Income tax benefit Profit for the period 3,607 1,558 Profit for the period attributable to: - Non-controlling interest (8) (24) - Shareholders of Urals Energy Public Company Limited 3,615 1,582 Loss per share of profit attributable to shareholders of Urals Energy Public Company Limited: - Basic loss per share (in US dollar per share) Diluted loss per share (in US dollar per share) Weighted average shares outstanding attributable to: - Basic shares 248,912, ,098,227 - Diluted shares 248,912, ,098,227 Profit for the period 3,607 1,558 Other comprehensive income/(loss): - Effect of currency translation 7 5,785 (768) Total comprehensive profit for the period 9, Attributable to: - Non-controlling interest 75 (24) - Shareholders of Urals Energy Public Company Limited 9, Interim Condensed Consolidated Statements of Cash Flows (unaudited) (presented in US$ thousands) Six months ended 30 June: Note Cash flows from operating activities Profit before income tax 3, Adjustments for: Depreciation, depletion and amortisation 5 5,164 2,317 Decrease of fair value of warrants Share-based payments Interest income 10 (1,727) (2,012) Interest expense ,043 Release of provision for inventory 15 (10) (1,869)

8 Foreign currency losses (4,534) 1,554 Gain from disposal of property, plant and equipment 15 (704) (1,223) Other (59) (154) Operating cash flows before changes in working capital 1,830 1,122 Increase in inventories (6,588) (7,071) (Increase)/decrease in accounts receivables and prepayments (834) 2,089 Decrease in accounts payable and accrued expenses (30) (5,788) (Decrease)/increase in advances from customers (553) 6,474 Increase/(decrease) in other taxes payable 3,124 (107) Cash used in operations (3,051) (3,283) Interest received - - Income tax paid (271) - Net cash used in operating activities (3,322) (3,283) Cash flows from investing activities Purchase of property, plant and equipment (1,565) (789) Proceeds from sale of property, plant and equipment - 1,771 Net cash (used in)/ generated from investing activities (1,565) 98 Cash flows from financing activities Repayments of borrowings (4,000) 565 Finance lease principal payments (104) (396) Cash proceeds from issuance of ordinary shares, net 8,750 - Net cash generated from financing activities 4, Effect of exchange rate changes on cash in bank and on hand 84 7 Net decrease in cash in bank and on hand (157) (2,124) Cash in bank and on hand at the beginning of the period 987 2,361 Cash in bank and on hand at the end of the period

9 Interim Condensed Consolidated Statements of Changes in Shareholders Equity (unaudited) (presented in US$ thousands) Share capital Share premium Difference from conversion of share capital into US$ Cumulative Translation Adjustment Retained earnings (accumulated deficit) Equity attributable to Shareholders of Urals Energy Public Company Limited Noncontrolling interest Total equity Balance at 1 January , ,248 (113) (28,373) (554,976) 61, ,941 Effect of currency translation (768) - (768) - (768) Profit for the period ,582 1,582 (24) 1,558 Total comprehensive income/(loss) (768) 1, (24) 790 Share issue (Note 10) 57 1, ,001-2,001 Share-based payment (Note 11) Balance at 30 June , ,575 (113) (29,141) (553,394) 65,115-65,115 Balance at 1 January , ,557 (113) (28,858) (503,016) 126, ,083 Effect of currency translation ,702-5, ,785 Profit/(loss) for the period ,615 3,615 (8) 3,607 Total comprehensive income ,702 3,615 9, ,392 Share issue 26 (26) Share-based payment Balance at 30 June , ,821 (113) (23,156) (499,401) 135,720 1, ,765

10 Selected Notes to the Interim Condensed Consolidated Financial Information (unaudited) (in US dollars, tabular amounts in US$ thousands, except as indicated) 1 Activities Urals Energy Public Company Limited ( Urals Energy or the Company or UEPCL ) was incorporated as a limited liability company in Cyprus on 10 November Urals Energy and its subsidiaries (the Group ) are primarily engaged in oil and gas exploration and production in the Russian Federation and processing of crude oil for distribution on both the Russian and international markets. The registered office of Urals Energy is at 31 Evagorou Avenue, Suite 34, CY-1066, Nicosia, Cyprus. UEPCL s shares are traded on the AIM (Alternative Investment Market) Market operated by the London Stock Exchange. The Group comprises UEPCL and the following main subsidiaries and joint venture: Entity Jurisdiction 30 June December 2010 Exploration and production ZAO Petrosakh ( Petrosakh ) Sakhalin 97.2% 97.2% ZAO Arcticneft ( Arcticneft ) Nenetsky Region 100% 100% Management company OOO Urals Energy Moscow 100% 100% Urals Energy (UK) Limited (dormant starting from May 2007) 1 United Kingdom 100% 100% 1 As at 5 January 2011 Urals Energy (UK) Limited is considered a liquidated entity. From 6 January 2012 Urals Energy UK will be struck off of Companies House and will be dissolved. 2 Summary of significant accounting policies Basis of preparation. The consolidated interim condensed financial information has been prepared in accordance with International Accounting Standard No. 34, Interim Financial Reporting ( IAS 34 ). This consolidated interim condensed financial information should be read in conjunction with the Company consolidated financial statements as of and for the year ended 31 December 2010 prepared in accordance with International Financial Reporting Standards ( IFRS ). The 31 December 2010 consolidated statement of financial position data has been derived from the audited financial statements. Use of estimates. The preparation of consolidated interim condensed financial information in conformity with IFRS requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities as of the reporting date and during the reporting period. Estimates have principally been made in respect to fair values of financial assets and financial liabilities, impairment provisions, asset retirement obligation and deferred income taxes. Actual results may differ from such estimates. Functional and presentation currency. The United States dollar ( US dollar or US$ or $ ) is the presentation currency for the Group s operations as management have used the US dollar accounts to manage the Group s financial risks and exposures, and to measure its performance. Financial statements of the Russian subsidiaries are measured in Russian Roubles, their functional currency. The functional currency of the Company is the US Dollar as substantially all the cash flows affecting the Company are in US Dollars. Translation to functional currency. Monetary assets and liabilities denominated in foreign currencies are retranslated into the functional currency at the rate of exchange ruling at the reporting date. Any resulting exchange differences are included in the profit or loss component of the consolidated statement of comprehensive income. Non-monetary assets and liabilities that are measured at historical cost and denominated in a foreign currency are translated into the functional currency using the rates of exchange as at the dates of the initial transactions. The US dollar to Russian Rouble exchange rates were and as of 30 June 2011 and 31 December 2010, respectively.

11 Translation to presentation currency. The Group s financial statements are presented in US dollars in accordance with IAS 21 (revised 2003), The Effects of Changes in Foreign Exchange Rates. The results and financial position of each group entity having a functional currency different from the presentation currency (the functional currency of none of which is a currency of a hyperinflationary economy) are translated into the presentation currency as follows: (i) Assets and liabilities for each statement of financial position presented are translated at the closing rate at the date of that statement of financial position. Monetary assets and liabilities denominated in foreign currencies are translated into the functional currency at the rate of exchange ruling at the reporting date. Any resulting exchange differences are included in the profit or loss component of the consolidated statement of comprehensive income. Non-monetary assets and liabilities that are measured at historical cost and denominated in a foreign currency are translated into the functional currency using the rates of exchange as at the dates of the initial transactions. Goodwill and fair value adjustments arising on the acquisitions are treated as assets and liabilities of the acquired entity. (ii) Income and expenses for each statement of comprehensive income are translated at average exchange rates (unless this average is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the dates of the transactions). (iii) All resulting exchange differences are recognised as a separate component of equity. When a subsidiary is disposed of through sale, liquidation, repayment of share capital or abandonment of all, or part of, that entity, the exchange differences deferred in other comprehensive income are reclassified to the profit and loss. Comparatives. Where necessary, comparative figures have been adjusted to conform with changes in presentation in the current year. Income tax. Taxes on income in the interim periods are accrued using the tax rate that would be applicable to expected total annual earnings. Accounting standards adopted during the period. In the current period, the Group has adopted all of the new and revised Standards and Interpretations issued by the International Accounting Standards Board (the IASB) and the International Financial Reporting Interpretations Committee (the IFRIC) of the IASB that are relevant to its operations and effective for reporting periods beginning on 1 January Going concern A significant portion of the Group s consolidated net assets of $136,765 thousand comprises undeveloped mineral deposits requiring significant additional investment. The Group is dependent upon external debt to fully develop the deposits and realise the value attributed to such assets. The Group had net current liabilities of $7.7 million as of 30 June The largest creditor as of 30 June 2011 was Petraco with $27.4 million of principal and interest owed as of 30 June 2011 ($8 million current portion of long-term debt) (Note 10). Management has prepared monthly cash flow projections for periods throughout 2011, 2012 and Judgements with regard to future oil prices and planned production were required for the preparation of the cash flow projections and model. Positive overall cash flows are crucially dependant on future oil prices (a price of $90 per barrel has been used for 2011 and for 2012) and on continued cooperation with Petraco. Despite the above matters, the Group still has funding and liquidity constraints. Management considers that there is a material uncertainty which may cast doubt about the Group s ability to continue as going concern. Despite the uncertainties and based on cash flow projections performed, management considers that the application of the going concern assumption for the preparation of these consolidated financial statements is appropriate. 4 Critical Accounting Estimates and Judgements in Applying Accounting Policies The Group makes estimates and assumptions that affect the reported amounts of assets and liabilities. Estimates and judgements are continually evaluated and are based on management s experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Management also makes certain judgements, apart from those involving estimations, in the process of applying the accounting policies.

12 Judgements that have the most significant effect on the amounts recognised in the condensed consolidated financial information and estimates that can cause a significant adjustment to the carrying amount of assets and liabilities are outlined below. Tax legislation. Russian tax and customs legislation is subject to varying interpretations, and changes, which can occur frequently. Management s interpretation of such legislation as applied to the transactions and activity of the Group may be challenged by the relevant authorities. Estimation of oil and gas reserves. Engineering estimates of hydrocarbon reserves are inherently uncertain and are subject to future revisions. Accounting measures such as depreciation, depletion and amortization charges, impairment assessments and asset retirement obligations that are based on the estimates of proved reserves are subject to change based on future changes to estimates of oil and gas reserves. Proved reserves are defined as the estimated quantities of hydrocarbons which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions. Proved reserves are estimated by reference to available reservoir and well information, including production and pressure trends for producing reservoirs. Furthermore, estimates of proved reserves only include volumes for which access to market is assured with reasonable certainty. All proved reserves estimates are subject to revision, either upward or downward, based on new information, such as from development drilling and production activities or from changes in economic factors, including product prices, contract terms or development plans. In some cases, substantial new investment in additional wells and related support facilities and equipment will be required to recover such proved reserves. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change over time as additional information becomes available. In general, estimates of reserves for undeveloped or partially developed fields are subject to greater uncertainty over their future life than estimates of reserves for fields that are substantially developed and depleted. As those fields are further developed, new information may lead to further revisions in reserve estimates. Reserves have a direct impact on certain amounts reported in the interim condensed consolidated financial information, most notably depreciation, depletion and amortization as well as impairment expenses. Depreciation rates on production assets using the units-of-production method for each field are based on proved developed reserves for development costs, and total proved reserves for costs associated with the acquisition of proved properties. Assuming all variables are held constant, an increase in proved developed reserves for each field decreases depreciation, depletion and amortization expenses. Conversely, a decrease in the estimated proved developed reserves increases depreciation, depletion and amortization expenses. Moreover, estimated proved reserves are used to calculate future cash flows from oil and gas properties, which serve as an indicator in determining whether or not property impairment is present. The possibility exists for changes or revisions in estimated reserves to have a significant effect on depreciation, depletion and amortization charges and, therefore, reported net profit for the year. Impairment provision for receivables. The impairment provision for receivables is based on management s assessment of the probability of collection of individual receivables. Significant financial difficulties of the debtor, probability that the debtor will enter bankruptcy or financial reorganization, and default or delinquency in payments are considered indicators that the receivable is potentially impaired. Actual results could differ from these estimates if there is deterioration in a debtor s creditworthiness or actual defaults are higher than the estimates. When there is no expectation of recovering additional cash for an amount receivable, the expected amount receivable is written off against the associated provision. Future cash flows of receivables that are evaluated for impairment are estimated on the basis of the contractual cash flows of the assets and the experience of management in respect of the extent to which amounts will become overdue as a result of past loss events and the success of recovery of overdue amounts. Past experience is adjusted on the basis of current observable data to reflect the effects of current conditions that did not affect past periods and to remove the effects of past conditions that do not exist currently. Asset retirement obligations. Management makes provision for the future costs of decommissioning hydrocarbon production facilities, pipelines and related support equipment based on the best estimates of future cost and economic lives of those assets. Estimating future asset retirement obligations is complex and requires management to make estimates and judgments with respect to removal obligations that will occur many years in the future. Changes in the measurement of existing obligations can result from changes in estimated timing, future costs or discount rates used in valuation.

13 Useful lives of non-oil and gas properties. Items of non-oil and gas properties are stated at cost less accumulated depreciation. The estimation of the useful life of an asset is a matter of management judgement based upon experience with similar assets. In determining the useful life of an asset, management considers the expected usage, estimated technical obsolescence, physical wear and tear and the physical environment in which the asset is operated. Changes in any of these conditions or estimates may result in adjustments to future depreciation rates. Useful lives applied to oil and gas properties may exceed the licence term where management considers that licences will be renewed. Assumptions related to renewal of licences can involve significant judgment of management. Impairment. Management have estimated the recoverable amount of cash generating units. Changes in the assumptions used can have a significant impact on the amount of any impairment charge. Fair values of acquired assets and liabilities. Since its inception, the Group has completed several significant acquisitions. IFRS 3 requires that, at the date of acquisition, all identifiable assets (including intangible assets), liabilities and contingent liabilities of an acquired entity be recorded at their respective fair values. The estimation of fair values requires management judgement. For significant acquisitions, management engages independent experts to advise as to the fair values of acquired assets and liabilities. Changes in any of the estimates subsequent to the finalisation of acquisition accounting may result in losses in future periods. Going Concern. This interim condensed consolidated financial information has been prepared on the basis that the Group will continue as a going concern. Preparation of the interim condensed consolidated financial information on a basis other than going concern can have a significant impact on the balances recorded in respect of assets and liabilities. 5 Property, Plant and Equipment Cost at Oil and gas properties Refinery and related equipment Buildings Other Assets Assets under construction Total 1 January ,991 5,394 1,207 5,096 3, ,131 Translation difference (2,813) (166) (19) (141) (93) (3,232) Reclassificated as intangible assets (283) (283) Additions Transfers (277) - Disposals (4) - (490) (413) - (906)* 30 June ,409 5, ,546 2, ,891 Oil and gas properties Refinery and related equipment Buildings Other Assets Assets under construction Total Accumulated Depreciation, Amortization and Depletion at 1 January 2010 (38,783) (2,171) (648) (3,005) - (44,607) Translation difference 1, ,426 Depreciation, depletion and amortization (1,871) (99) (8) (203) - (2,181) Disposals June 2010 (39,404) (2,200) (519) (2,880) - (45,003) Oil and gas properties Refinery and related equipment Buildings Other Assets Assets under construction Total Net Book Value at 1 January ,208 3, ,091 3,443 62, June ,005 3, ,666 2,970 57,888

14 *During the six months period ended 30 June 2010 the Group sold property, plant and equipment for the total consideration of $1,771 thousand. The net book value on the date of disposal was $547 thousand. Cost at Oil and gas properties Refinery and related equipment Buildings Other Assets Assets under construction Total 1 January ,611 8, ,010 7, ,084 Translation difference 13, ,154 Additions ,197 1,236 Capitalised borrowing costs Transfers (93) - Impairment Disposals (855) - - (57) - (912) 30 June ,957 9,336 1,008 6,521 9, ,733 Average capitalisation rate of capitalised interest expense for the period ended 30 June 2011 is 3.0%. Oil and gas properties Refinery and related equipment Buildings Other Assets Assets under construction Total Accumulated Depreciation, Amortization and Depletion at 1 January 2011 (42,283) (2,358) (537) (3,089) - (48,267) Translation difference (3,703) (206) (46) (270) - (4,225) Depreciation, depletion and amortization (4,594) (213) (13) (255) - (5,075) Disposals June 2011 (50,267) (2,777) (596) (3,582) - (57,222) Oil and gas properties Refinery and related equipment Buildings Other Assets Assets under construction Total Net Book Value at 1 January ,328 6, ,921 7, , June ,690 6, ,939 9, ,511 Included within oil and gas properties at 30 June 2011and 31 December 2010 were exploration and evaluation assets: Cost at 31 December 2010 Additions Transfers to tangible part of Oil and Gas properties Additions: Impairment reverse Translation difference Total Exploration and evaluation assets Arcticneft 16, ,446 18,355 Petrosakh 30, ,633 33,416 Total cost of exploration and evaluation assets 47, ,079 51,771 The Group s oil fields are situated in the Russian Federation on land owned by the Russian government. The Group holds mining licenses and pays production taxes to extract oil and gas from the fields. The licenses expire

15 between 2012 and 2067, but may be extended. Management intends to renew the licences as the properties are expected to remain productive subsequent to the license expiration date. Estimated costs of dismantling oil and gas production facilities, including abandonment and site restoration costs, amount to $1.4 million and $1.2 million at 30 June 2011 and 31 December 2010, respectively, are included in the cost of oil and gas properties. The Group has estimated its liability based on current environmental legislation using estimated costs when the expenses are expected to be incurred. At 30 June 2011 and 30 December 2010, no property, plant and equipment were pledged as collateral for the Group s borrowings. 6 Other Non-Current Assets 30 June December 2010 Loans receivable 39,482 37,810 Loans issued to related parties (Note 24) Intangible assets Advances to contractors and suppliers for construction in process Total other non-current assets 41,263 39,426 Loans receivable represent US dollar denominated long-term loans (interest inclusive) of $39.5 million and $37.8 million at 30 June 2011 and 31 December 2010, respectively, issued by UEPCL to Taas, as part of the Taas acquisition agreement. The loans were used to pay organisation fees for a $600.0 million project finance loan facility provided by Savings Bank of Russian Federation ( Sberbank ) for the development of the SRB field, financing of interest payments and repayment of third party loans at Taas. The loans bear interest of 12% and mature in February The fair value of the loans approximates the carrying value at the reporting date. These loans are considered to be fully performing as of 30 June 2011 and as of 31 December The loans are unsecured. 7 Inventories 30 June December 2010 Crude oil 13,071 4,629 Oil products 3,721 2,135 Materials and supplies 4,902 6,147 Total inventories 21,694 12,911 Inventory provision 30 June December 2010 At 1 January 1,012 1,924 Provision used (948) - Release of provision - (901) Release of adjustment on net realizable value - 9 Effect of currency translation 87 (20) At 31 December 151 1,012 8 Accounts Payable and Accrued Expenses 30 June December 2010 Payable to Finfund Ltd. 4,431 4,412 Wages and salaries 1,025 1,227 Accounts payable for construction in process Trade payables 412 1,588 Advances from and payables to related parties Other payable and accrued expenses 2,422 2,850 8,742 10,781

16 Total accounts payable and accrued expenses 9 Advances from customers 30 June December 2010 Kresov 1,279 1,855 Melnikov 1,615 1,728 Other Total advances from customers 3,844 4, Borrowings Long-term and short-term borrowings. Long-term and short-term borrowings were as follows at 30 June 2011 and 31 December 2010: 30 June December 2010 Long-term borrowings Petraco - Principal 17,316 17,316 - Interest 2,040 1,337 Total long-term borrowings 19,356 18,653 Short-term borrowings Petraco - Principal 8,000 12,000 - Interest - - Other Total short-term borrowings 8,127 12,172 Total borrowings 27,483 30,825 Petraco. In April 2010 the Company has reached agreement with Petraco relating to the restructuring of the Petraco facility (the Restructuring Agreement ). The principal terms of the Restructuring Agreement are as follows: Total indebtedness owed by the Company to Petraco, as at 31 March 2010, was $34.3 million, made up as follows: - capital amount outstanding (the Capital Outstanding ) of $30.7 million; - accrued interest outstanding (the Accrued Interest ) of $3.6 million. As at 1 April 2010, the Capital Outstanding and Accrued Interest were added together and carried forward as principal ( Principal ). After 1 April 2010 interest will be accrued on the Principal and will not be compounded. All accrued interest from 1 April 2010 will be paid once the Principal has been repaid and all payments made by the Company according to the payment schedule set out below will be applied against the Principal outstanding. Interest will be charged on the Principal at a rate of 6 month LIBOR plus 5% per annum, non-compounding. As part of the restructuring agreement Petraco converted $2 million of the Capital Outstanding into 8,693,006 ordinary shares of the Company (recorded in the interim condensed consolidated statement of changes in shareholders equity) and received an option to acquire additional new ordinary shares in the amount of 12,576,688 for $5 million. The fair value of the option in the amount of $170 thousand as of 30 June 2010 is recorded as liabilities. In June 2010 Company pledged 100% of the shares it currently holds in Arcticneft and 97.2% of shares it currently holds in Petrosakh to Petraco as security against the restructured Petraco facility. The Company and Petraco have reached an agreement to link a repayment of debt to anticipated loadings of crude oil on export from Arcticneft and Petrosakh as disclosed in the repayment schedule below: Payment date (as amended on August 2011) Amount to be paid by UEPCL to Petraco 31 October 2011 $4 million 30 November 2011 $4 million 31 July 2012 $6 million

17 30 November 2012 $5.7 million 31 July 2013 $3 million 30 November 2013 Outstanding balance Weighted average interest rate. The Group s weighted average interest rates on short-term borrowings were 5.75% and 4.9% at 30 June 2011 and at 31 December 2010, respectively. Interest expense and income. Interest expense and income for the six months ended 30 June 2011 and 30 June 2010 comprised the following: Six months ended 30 June: Interest on loan from Petraco Oil Company Limited accrued capitalised into PP&E and finished goods (465) - Finance leases Change in dismantlement provision due to passage of time Total interest expense 393 1,043 Interest income Interest on loan issued to TYNGD 1,672 1,672 Loans issued to the related party (Note 16) Total interest income 1,727 2,012 Net interest income 1, Equity At 30 June 2011 authorised share capital was $1,890 thousand divided into 300 million shares of $ each and issued share capital was $1,569 thousand divided into million shares of $ each. At 31 December 2010 authorised share capital was $1,543 thousand divided into 300 million shares of $ each and issued share capital was $1,131 thousand divided into million shares of $ each. Date of Grant Number of shares (thousand of shares) Share capital Share premium Balance at 1 January ,192 1, ,557 Shares issued under restricted stock plans 4, (26) Share-based payment under restricted stock Balance at 30 June ,251 1, ,821 Restricted stock plan. During the six months ended 30 June 2011 and 30 June 2010, $290 thousand and $383 thousand, respectively, of expense related to share-based payments were recognized in the interim condensed consolidated statement of comprehensive income. At 30 June 2011 and 30 June 2010, restricted stock grants for 4,059,112 shares and 1,432,062 shares were fully issued. As of 30 June 2011, the number of unvested restricted stock grants and their respective vesting dates are presented in the table below. Date of Grant January 2009 January 2010 January 2011 January 2012 Total Total Restricted Stock Granted as of 31 December , ,671 4,356,716 4,059,112 9,086,595 Vested in the six months - - (4,059,112) - (4,059,112)

18 ended 30 June 2011 Total Restricted Stock Granted as of 30 June , , ,604 4,059,112 5,027,483 Profit per share. Profit per share is calculated by dividing the profit attributable to equity holders of the Company by the weighted average number of ordinary shares in issue during the reporting period. The profit per share was calculated as following: Six months ended 30 June: Profit attributable to equity holders of the Company 3,615 1,582 Weighted average number of ordinary shares in issue (thousands) 248, ,098 Basic and diluted profit per share (in US dollar per share) Revenues Six months ended 30 June: Petroleum (refined) products domestic sales 14,930 9,779 Crude oil domestic sales 1,807 1,523 Other sales Total gross revenues 17,139 11, Cost of Sales Six months ended 30 June: Wages and salaries including payroll taxes 6,003 5,186 Unified production tax 7,431 4,823 Depreciation, depletion and amortization 5,164 2,317 Materials 2,601 1,199 Rent, utilities and repair services Other taxes Oil treating, storage, transportation and other services Other Change in finished goods (9,103) (6,824) Total cost of sales 13,882 8, Selling, General and Administrative Expenses Six months ended 30 June: Wages and salaries 1,652 1,503 Transport, loading and storage services Audit, legal and professional consultancy fees Share-based payments (Note 11) Office rent and other expenses Trip expenses and communication services Other Total selling, general and administrative expenses 4,525 4, Other income, net Six months ended 30 June: Release of provision for inventory 10 1,869