18 Apr 2006 07:02
Urals Energy Public Company Limited18 April 2006 Urals Energy Public Company Limited Preliminary Results for the year ended 31 December 2005 Urals Energy Public Company Limited (LSE: UEN), the international oil and gasexploration and production company which was admitted to the AlternativeInvestment Market of the London Stock exchange in August 2005, raising US$131million, today announces its preliminary results for the year ended 31 December2005. In a separate announcement today, the Company announced the signing of adefinitive Sales Purchase Agreement for the $148 million acquisition of thesignificant Dulisminskoye oil, condensate and gas field together with the LTKtransportation and treating facilities, all located in the Irkutsk region ofEastern Siberia, close to Transneft's proposed East Siberian Pipeline. TheDulisminskoye Field is currently producing 1,000 bopd and Urals Energy intendsto move rapidly to increase production from this field through infielddevelopment to approximately 12,000 bopd by the end of 2008 and approximately30,000 bopd by 2011. Operating Highlights: • Completion and integration of ZAO Arcticneft, OOO Dinyu and OOO Urals Nord acquisitions • Near fivefold increase in average annual production from 1,146 to 5,263 bopd • Current production increased to 9,000 bopd • 2P reserves rose 31% to 116 million barrels (2004: 89.6 million barrels) • 107% reserve replacement at a cost of $2.50 per barrel due to successful development drilling Financial and Corporate Highlights • Admission to AIM and $131 million equity raising in August 2005 • Turnover increased to $92.9 million (2004: $8.2 million) • Operating profit of $11.3 million (2004: loss of $3.7 million) • Post tax profit of $7.1 million (2004: loss of $3.6 million) • Adjusted EBITDA of $16.9 million Outlook • $40 million capex plan (excluding Dulisma acquisition) across 20 new development wells and 2 high impact exploration wells • Production (excluding Dulisma acquisition) targeted to increase by 33% to approximately 12,000 bopd by end 2006 • Integration and development of Dulisma acquisition projected to add incremental 12,000 bopd to group production by end 2008 • Continued focus on acquiring under exploited assets in Russia and the FSU William R. Thomas, Chief Executive Officer, commented: "2005 was a landmark year which saw Urals Energy establishing a solid productionand operational base in Russia which has delivered strong financial results. The outlook for 2006 is excellent with an intense development and explorationprogramme planned which will further increase production. Today's announcement of the proposed acquisition of the Dulisma Field is animportant development for Urals giving us significant oil and gas reserves at anattractive price and strategically located near the proposed East Siberiapipeline." 18 April 2006 Pelham PRJames Henderson 020 7743 6673Gavin Davis 020 7743 6677 CHAIRMAN'S AND CHIEF EXECUTIVE'S STATEMENT 2005 was a landmark year for Urals Energy - we outperformed our initialobjectives and built on our solid reserve and production base. Our strategy ofgrowing the company through development, exploration and acquisition is alreadygenerating significant returns for shareholders. During the year we made threesuccessful acquisitions (ZAO Arcticneft, OOO Dinyu and OOO Urals Nord), averageyearly production increased almost fivefold from 1,146 to 5,263 bopd and currentproduction increased to 9,000 bopd resulting in an increased target of at least14,000 bopd by the end of 2007. Proved and probable reserves rose significantlyfrom 89.6 to 116 million barrels, or approximately 31%, and we replaced 107% ofour produced reserves through development drilling at a cost of approximately$2.50 per barrel. We also began an important exploration programme offshoreSakhalin Island. Underpinning this growth was the $131 million of new equity capital we raised inour August 2005 IPO on the Alternative Investment Market (AIM) of the LondonStock Exchange. Urals Energy's continued growth is based on a three-pronged strategy of (i)increasing production through low-risk development drilling, (ii) addingreserves by exploring our resource base offshore Sakhalin Island and onshoreTiman Pechora, and (iii) making new and larger acquisitions of Russian oilcompanies. It is a strategy intended to create a balanced portfolio of upstreamassets which is managed and developed in a highly efficient and cost effectivemanner. The cost to acquire and develop our proved and probable reserves todate is approximately $1.73 per barrel, not including the Dulisma acquisitionannounced separately today. We believe this is a proven strategy that willcontinue to deliver significant returns to our shareholders. Financial Results In 2005, Urals Energy focussed on the acquisition and development of newcompanies and assets and their integration into the Group. Our three newacquisitions are consequently reflected in our overall financial results:revenues totalled $93 million, adjusted EBITDA was $17 million, and profitsafter tax were $7 million - all of which were significant increases over 2004'sresults. Prices received for oil and products sold in 2005 averaged $43.24 and$51.89 per barrel respectively while overall netback prices (gross price lessexport taxes, transport and marketing costs and net of VAT) averaged $30.02 perbarrel. The price for domestic oil sold in Russia increased dramatically in2005 from approximately $15 to $30 per barrel. This is the result of increaseddomestic demand and improved margins for Russian refineries, a trend we expectto continue during 2006. Total cash operating costs were approximately $12 million, excluding DD&A,production taxes, and other non-cash items. On a per barrel basis and ascompared to revenues, our cost structure is higher than other more matureproduction operations in Russia. This is the result of acquiring only partiallydeveloped fields and consolidating seven stand-alone companies within two years.As we execute our development plans and production volumes grow, our perbarrel operating costs are expected to decline and profits increasecommensurately. We also expect to lower operating costs in our producingsubsidiaries by reducing headcount and streamlining operations. We ended the year with $32.3 million in cash after having acquired OOO Dinyu for$70 million cash in November 2005. In the same month, we closed a $100 millionrevolving five year reserve-based lending facility with BNP Paribas. The netamount drawn against this facility at year-end was $69 million. We are pleasedby the inherent recognition of creditworthiness this facility provides us. Itis now in syndication and preliminary results are very encouraging. At 31 December 2005, our balance sheet was funded with approximately $200million in shareholders equity and $81 million of bank and subordinated debt.We believe this is a prudent debt to equity ratio for a rapidly growing businesslike Urals Energy. During 2006, we expect to maintain our planned level of capital expenditure ofapproximately $40 million (excluding the proposed development spend on theDulisma acquisition announced today), almost all of which will be invested inincreasing production. By the end of 2006, our plan is to increase productionto approximately 12,000 BOPD from our existing assets. This should result in asustainable core production base that is generating strong cash flow and theopportunity for further growth. Operations Sakhalin Island At ZAO Petrosakh, both exploration and development activity continues at a rapidpace. Testing continues on our first offshore exploration well, East Okruzhnoye No. 1,in the Pogranichny Block offshore Sakhalin Island, and results are expectedshortly. Further planned exploration work during 2006 includes a second exploration well,seismic studies and preparations for a possible marine drilling program in 2007.We recently awarded a tender for the processing and interpretation of a combinedonshore and offshore 3D seismic data set that should further enhance ourunderstanding of both the onshore Okruzhnoye Field and the eleven explorationprospects that lie directly offshore. Following the extension of our offshorelicense for an additional five years, we believe a logical next step is to drillseveral vertical exploration wells to test our best offshore prospects. Thiswill require mobilizing a marine drilling unit, probably a jackup, and extensivepre-drilling preparations. Further details of this program will be announcedlater in 2006. As previously announced, the further development of the onshore Okruzhnoye Fieldhas been deferred until the interpretation of a new 3D seismic program iscompleted. We have acquired a new mobile Russian drilling rig for this fieldand expect development drilling to begin in June 2006. A total of three newdevelopment wells and three re-entries are planned this year for the OkruzhnoyeField. We have also begun preparations for a fracture stimulation program at Petrosakhand our other oil producing subsidiaries. Equipment has been purchased inwestern Canada and is being refurbished prior to shipment to Sakhalin Islandthis summer. Given the reservoir characteristics of the Okruzhnoye Field, weexpect good results from fraccing. After completing the Okruzhnoye Fieldstimulation program, we will move the equipment to Komi and Timan Pechora wherewe also believe we will boost production by fraccing. Komi Republic and Timan Pechora The acquisition of OOO Dinyu helped create a new core area for Urals Energy inthe Komi Republic which sits in the southern half of the prolific Timan Pechorabasin. In Komi, we produce from three fields at Dinyu and CNPSEI. Developmentoperations have continued at Dinyu since its acquisition with the drilling oftwo producing wells, numbers 32 and 51. For Dinyu in 2006, we expect to drill atotal of nine development wells and one exploration well and have set a year-endproduction target of approximately 4,000 BOPD. Further north, the Timan Pechora basin extends to the Nenets Autonomous Okrugwhere we have two operating subsidiaries, Arcticneft and Urals Nord. AtArcticneft, we are now completing a comprehensive geological model to assist inselecting well locations in preparation for our development drilling programmethis summer. During 2006, we expect to drill four development wells atArcticneft. At Urals Nord, we are planning on drilling our first exploration well to testthe Nadezhdinsky prospect. Situated approximately 60 kilometers from the portof Varandey, this prospect has high impact potential and if successful would bedeveloped to deliver oil to the LUKoil terminal now under construction atVarandey. Udmurtia Our production and development operations at Chepetskoye NGDU continue on trackwith the recent completion of the 3D seismic interpretation of the PotaposkvoyeField. Development drilling operations will begin shortly for a planned fourwell program in 2006. Corporate In line with our strategy, we are actively reviewing a number of new acquisitionopportunities, as evidenced by today's announcement of the proposed acquisitionof the Dulisma Field. The number and quality of potential acquisitionopportunities remain strong. Our business model is to acquire under-exploitedassets in Russia and the FSU, invest in development and exploration, andmonetize through either production or divestiture at the appropriate time. Thisconsolidation strategy is a proven business model, and we believe we have thetrack record, highlighted by our acquisition and development costs to date of$1.73 per barrel, to execute such strategies. With a strong track record ofsuccess, Urals Energy is well positioned to take advantage of this attractivemarket opportunity. Outlook The outlook for 2006 is positive. Production volumes are expected to grow toapproximately 12,000 BOPD by year-end as we further develop our oil fieldsacross Russia by drilling 20 new development wells. This development plan alsoincludes the introduction of new, mobile fracture-stimulation equipment designedto quickly enhance production for an attractive cost. Our high-impactexploration program offshore Sakhalin Island is expected to continue withenhanced data and further developed understanding of the geology and petroleumsystem. We also expect to spud our first exploration well in northern TimanPechora. Financially, the Group expects to generate stronger cash flow andprofits. Additionally, we continue to examine a number of potential acquisitionopportunities. The Russian government is considering certain changes to the existing oil taxregime. Should this occur in 2006, it could have a significant financial impacton Urals Energy as we operate in many of the frontier areas that may becomeeligible for tax holidays and other investment incentives. Revenue-based taxesare our single largest cost item, approximately 29% of gross revenues, and weand the industry as a whole continue to maintain an active dialogue with thegovernment on this important issue. Finally, the backbone of our company and its most important advantage are ouremployees. They have helped transform Urals Energy over the past 12 months tobecome a successful international E&P company producing 9,000 BOPD with reservesof 116 million barrels and a current market capitalization of approximately $600million. It is their hard work, enthusiasm and skill that makes Urals Energysuccessful. Viatcheslav V. Rovneiko William R. ThomasChairman of the Board Chief Executive Officer 18 April 2006 FINANCIAL REPORT Operating Environment 2005 was characterized by strong increases in world oil and gas prices and asurge in exploration and production activity and investment. Brent oil pricesbegan the year at $39.50 per barrel, reached a peak of $67.49 per barrel andended the year at $58.21 per barrel. The Russian oil industry was similarlyaffected by this changing price environment. Industry average domestic oilprices began at $13 per barrel and averaged approximately $29 per barrel for theyear. Russian export prices rose with world market prices and resulted insteadily increasing export taxes that absorbed much of the net export revenueavailable to producers. This loss of export revenues was mostly offset by theincrease of domestic prices and resulting netback parity. Increased oil and gas prices, particularly domestic prices, have resulted instronger demand for oilfield services in Russia. Rig availability for certaintypes of specialized drilling is declining. Overall production costs areincreasing due to rising industry demand and the strengthening Rouble. Production and Revenues Crude oil production during the year increased by 359% from 418,000 barrels in2004 to 1.92 million barrels in 2005, with average daily production increasingfrom 1,146 barrels per day in 2004 to 5,263 in 2005. The total productionincrease of 4,117 bopd was the result of both development drilling (740 bopd)and additions from acquisitions (3,377 bopd). During the period the Company's gross revenues totalled $92.9 million versus$8.2 million in 2004. Net revenues increased to $66.1 million from $7.4 millionin the prior year. This revenue increase is the result of both the Group selling2.1 million barrels of additional crude oil and products than in 2004 and highercommodity prices. The Group realized a weighted average price of $43.24 perbarrel of oil sold in 2005. Export sales prices for the Group averaged $49.29per barrel, and domestic sales prices averaged $28.96 per barrel. Domesticrefined product prices averaged $51.89 per barrel. Net revenues received by the Company strengthened during the year as world oilprices increased and the disparity between export and domestic prices narrowed.Net revenues for 2005 totalled $66.1 million as compared to $7.4 million in2004. Netback prices are defined as, in the case of exports, gross oil salesprice less export duty, customs charges, marketing costs and transportation,and, in the case of domestic crude sales, gross sales price net of VAT. Theweighted average netback for crude oil sales during 2005 was $29.38 per barrel.Netbacks for export sales were $31.36 per barrel and $24.15 per barrel fordomestic sales. Netback prices for domestic product sales are defined as grossproduct sales price minus VAT, transportation, excise tax and refining costs.The average products netback for the year was $34.87 per barrel. Gross profit for the year, (net revenues minus the cost of production), was$15.5 million as compared to $3 million in 2004. Production costs totalled$50.4 million but included $20.7 million of non-cash items. These non-cashcharges included $12.5 million of crude oil inventory in place at Arcticneftwhen acquired and subsequently sold at a zero book profit margin. Because ofthese non-cash items included in its cost of production, the Company believesthe strength of the Group's operating performance is not fully reflected in itsgross profit result. SG&A costs increased to $13.9 million as compared to $4.4 million in 2004. Thelargest component increase in SG&A, wages and salaries, reflects a significantlyincreased workforce and management team due to acquisitions and increased scopeof activity. Total audit and professional fees reflected the Company'scontinued growth through acquisitions and related financing activities. Interest expense for the period was $6.9 million as compared to $574 thousand in2004. Increased interest expense primarily reflects the cost of financingacquisitions and capital expenditures. $5.5 million of this was directlyrelated to interest on acquisitions payments. Net profit for the year attributable to shareholders was $7.1 million ascompared to a loss of $3.7 million in 2004. Basic earnings per share were 12cents versus a loss of 19 cents in 2004. Adjusting for the Arcticneft inventory purchase, non-recurring mobilizationcosts and other standard non-cash items, the Company's management-adjustedEBITDA for the period was $16.9 million, or 24.6% of net revenues. Includingthe full-year results of two companies acquired during 2005, Arcticneft andDinyu, pro-forma management-adjusted EBITDA was $22.6 million. At 31 December2005 and based on year-end prices, an additional $3.9 million in potentialrevenues and $1.9 million in EBITDA was held in the crude oil inventories atPetrosakh and Arcticneft and stored for export in 2006. Taxes Russia has a relatively high cost tax regime and the Company pays a variety oftaxes that are levied as a result of production, exported oil, assets andprofits. The largest taxes for the Group as a percentage of revenues during 2005were export duties (29%) and the unified production tax (18%). The Company paida total of $69.6 million in cash taxes for the year. Unified production taxesare calculated based on production revenues and in 2005 the Group paid $24.5million. Export duties are set according to a fixed schedule that increases asexport prices rise with a maximum rate of 65% of gross export prices above $25per barrel. High export prices in 2005 resulted in an average export duty forthe Company of 40%, and $23.2 million of cash paid. VAT payments totalled $12.5million. At 31 December 2005, the Group's deferred tax liability was $51.1 million. Thisis a non-cash liability and is the result of the difference between the Group'sconsolidated IFRS-calculated profit taxes versus actual taxes paid by theGroup's operating subsidiaries. The Company expects this deferred tax liabilityto be reflected on its balance sheet indefinitely. Cash Flow For the period, operating cash flow before working capital changes was $3.9million. Changes in working capital resulted in a negative cash flow fromoperations of $27.6 million. This is primarily due to a combined $12.4 millionincrease in receivables for crude oil sales plus increased tax prepayments, anda decrease in payables to suppliers compared with the start of the year.Capital expenditures for exploration and development in 2005 were $16.4 millionof which $13.2 million was invested at Petrosakh, and $2.5 million atChepetskoye NGDU. The cost of acquisitions during 2005 was $93.7 million,resulting in a total use of cash of $156.8 million. At 31 December 2004, the Group's short and long-term debt was $38.5. During2005, a total of $101.4 million in new debt was borrowed and $82.6 million indebt repaid or converted to equity. As of 31 December 2005, total outstandingdebt was $81.1 million. Through both a private-placement of common stock and the primary sale of sharesin a public offering, the company raised $150.7 million in cash. Thecombination of debt and equity financing activities resulted in a total additionto cash of $187.8 million. Cash Position The combined use of $156.8 million for operations, acquisitions and capitalexpenditures was funded by the net addition of $187.8 million in cash fromborrowings and the sale of equity. This resulted in a change to the cashposition of $30.9 million by year end. Hedging The Company does not hedge any of its crude oil or product sales, costs orcurrency conversions. International Financial Reporting Standards (IFRS) On 23 February 2006, the Company restated the interim results ending 30 June2005. The restated results resulted in a net loss of $800,000 as compared withthe originally announced net loss of $1.145 million. The difference wasprimarily the result of minor adjustments in gross revenues, cost of production,and interest costs and had no material effect on the Company's cash flows. The implementation of IFRS accounting procedures has resulted in a number ofnon-cash adjustments and non-recurring costs in the accounts. Managementbelieves that certain large items distort the actual cash operatingcharacteristics of the business. As previously mentioned, the Company's deferred tax liability of $51.1 millionis a non-cash item and is due to the difference between the Group consolidatedprofit taxes calculated for IFRS purposes versus those actually paid by eachsubsidiary as federal income taxes are accrued. These amounts are not due forpayment by the Company, and are likely to continue to increase in subsequentstatements. Under IFRS purchase accounting, the excess of the purchase price paid for aproperty over the fair market value of its tangible assets must be depleted overtime using a unit of production formula. The result is an increase to theCompany's Depreciation and Depletion, and will adjust depending on the estimateof future proven and producing barrels of oil. IFRS treatment for the excess of the fair market value of the tangible assets atArcticneft over the amount paid for the business by the Company resulted in$16.8 million of negative goodwill for the period. This non-cash item increasedoperating profits by a corresponding amount. Under IFRS methodology, the Company applies successful efforts accounting toexploration and development expenses. Certain expenses have been capitalizedpending the determination of the success of the related exploration ordevelopment program. The non-recurring mobilization costs for the period relateto the cost of mobilizing an exploratory drilling rig that was not ultimatelyused for drilling. This expense item is not included in cost of production. Urals Energy Public Company Limited Consolidated Balance Sheets (presented in US$ thousands) 31 December: Note 2005 2004 Assets Current assetsCash and cash equivalents 32,334 1,395Restricted cash - 26Accounts receivable and prepayments 5 23,788 3,706Inventories 6 12,641 2,773 Total current assets 68,763 7,900 Non-current assetsProperty, plant and equipment 7 287,485 102,754Other non-current assets 2,098 292Total assets 358,346 110,946 Liabilities and equity Current liabilitiesAccounts payable and accrued expenses 8 7,932 3,748Income taxes payable 9 6,039 387Other taxes payable 9 5,448 1,530Short-term borrowings and current 10 34,117 38,486 portion of long-term borrowingsAdvances from customers 523 5,103Amount due for acquisition of ZAO Petrosakh 4 - 9,899 Total current liabilities 54,059 59,153 Long-term liabilitiesLong-term borrowings 10 47,005 -Long-term finance lease obligations 1,357 1,556Dismantlement provision 11 813 950Deferred tax liability 9 51,100 18,390Other long term liabilities 580 1,590 Total long-term liabilities 100,855 22,486Total liabilities 154,914 81,639 EquityShare capital 12 460 209Share premium 12 201,355 42,172Unpaid capital 12 - (11,324)Translation difference (2,296) 1,264Retained earnings (accumulated deficit) 2,714 (4,341) Equity attributable to shareholders 202,233 27,980of Urals Energy Public Company Limited Minority interest 1,199 1,327 Total equity 203,432 29,307Total liabilities and equity 358,346 110,946 Urals Energy Public Company Limited Consolidated Statements of Operations (presented in US$ thousands) Year ended 31 December: Note 2005 2004 RevenuesGross revenues 13 92,918 8,184Less: excise taxes and export duties (26,783) (783) Net revenues 66,135 7,401 Operating costsCost of production 14 (50,442) (4,352)Selling, general and administrative expenses 15 (13,968) (6,825)Non-recurring mobilization costs 16 (7,170) -Excess of net assets acquired over purchase price 4 16,793 - Total operating costs (54,787) (11,177) Operating profit (loss) 11,348 (3,776) Interest income 913 82Interest expense (6,911) (574)Foreign currency gains (losses) (185) 211Other non-operating gains (losses) (457) 222 Income (loss) before income tax 4,708 (3,835)Current income tax 9 (890) (103)Deferred income tax benefit 9 3,155 280 Profit (loss) for the period 6,973 (3,658) Attributable to Minority interest (82) 14 Shareholders of Urals Energy Public Company Limited 7,055 (3,672) Earnings (loss) per share of profit attributable toshareholders of Urals Energy Public Company Limited (adjustedfor share split and expressed in US dollars per share)- Basic earnings per share 0.11 (0.1898)- Diluted earnings per share 0.11 (0.1898) Weighted average shares outstanding- Basic earnings per share 59,915,473 19,344,262- Diluted earnings per share 59,939,038 19,344,262 Urals Energy Public Company Limited Consolidated Statements of Cash Flows (presented in US$ thousands) Year ended 31 December: 2005 2004 Cash flows from operating activitiesProfit (loss) before income tax 4,708 (3,835)Adjustments for:Depreciation and depletion 9,394 522Non-cash expenses 42 1,928Interest income (913) (82)Interest expense 6,911 574Loss on disposal of long-lived assets 640 -Excess of net assets acquired over purchase price (16,793) -Effect of currency translation 185 211Other non-cash transactions (213) - Operating cash flows before 3,961 (682)changes in working capital Decrease (increase) in inventories 3,234 (374)Increase in accounts receivables and prepayments (12,374) (1,097)Increase (decrease) in accounts payable and accrued expenses (18,644) 2,152Decrease in other current assets 178 -Decrease in income and other taxes payable (785) (140)Increase in other liabilities and provisions (3,182) 307 Cash generated from (used in) operations (27,612) 166Interest received 913 52Interest paid (2,685) -Income tax paid (2,862) - Net cash generated from(used in) operating activities (32,246) 218 Cash flows from investing activitiesAcquisitions of subsidiaries, net of cash acquired 4 (106,500) (39,976)Purchase of property, plant and equipment (18,087) (1,146)Acquisition of associates - (264) Net cash used in investing activities (124,587) (41,386) Cash flows from financing activitiesProceeds from borrowings 101,412 28,937Repayment of borrowings (56,313) -Finance lease principle payments (404) -Contributions from shareholders - 871Cash proceeds from issuance of ordinary shares 143,100 12,797 Net cash generated from financing activities 187,795 42,605Effect of exchange rate changes (49) (26)on cash and cash equivalents Net increase in cash and cash equivalents 30,913 1,411Cash and cash equivalents 1,421 10at the beginning of the period Cash and cash equivalentsat the end of the period 32,334 1,421 Urals Energy Public Company Limited Consolidated Statements of Changes in Shareholders' Equity (presented in US$ thousands) Notes Share Share Unpaid Retained Equity Minority Total capital premium capital earnings attributable interest equity (accumulated to deficit) Shareholders Cumulative of Urals Translation Energy Public Adjustment Company Limited Balance at 31 December 20 10 - - (669) (639) - (639)2003 Effect of currency 1,264 - 1,264 1 1,265translationLoss for the year - (3,672) (3,672) 14 (3,658) Total recognized income 1,264 (3,672) (2,408) 15 (2,393)(loss) Acquisitions - - - - - - 1,312 1,312Issuance of shares 12 189 41,291 (11,324) - - 30,156 - 30,156Contribution from 12 - 871 - - - 871 - 871shareholders Balance at 31 December 209 42,172 (11,324) 1,264 (4,341) 27,980 1,327 29,3072004 Effect of currency (3,560) - (3,560) (46) (3,606)translationProfit for the year - 7,055 7,055 (82) 6,973 Total recognized income (3,560) 7,055 3,495 (128) 3,367(loss) Acquisitions - - - - - - -Issuance of shares 12 251 159,141 11,324 - - 170,716 - 170,716Share-based payment 12 - 42 - - - 42 - 42 Balance at 31 December 460 201,355 - (2,296) 2,714 202,233 1,199 203,4322005 Urals Energy Public Company Limited Notes to the Consolidated Financial Statements (in US dollars, tabular amounts in US$ thousands, except as indicated) 1 Activities Urals Energy Public Company Limited ("Urals Energy" or the "Company") wasincorporated as a limited liability company in Cyprus on 10 November 2003. TheCompany was formed to act as a holding company for investments in the Russianoil and gas exploration and production sector. Pursuant to a ShareholderAgreement dated 28 July 2004, certain shareholders contributed certain assetsincluding AO Cheptskoye NGDU to the Company, (Notes 4 and 12). Urals Energy and its subsidiaries (the "Group") are primarily engaged in oil andgas exploration and production in the Russian Federation and processing of crudeoil 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. In July 2005, the Company changed its name to UralsEnergy Public Company Limited. The Group's primary office in Russia is locatedat 6 Oktyabrskaya Ul. Moscow, 127018, Russian Federation. The Group comprises the following subsidiaries: Entity Jurisdiction Effective interest at 31 December: 2005 2004Exploration and productionZAO Petrosakh ("Petrosakh") Sakhalin 97.2% 97.2%ZAO Arcticneft ("Arcticneft") Nenetsky 100.0% -OOO CNPSEI ("CNPSEI") Komi 100.0% 100.0%ZAO Chepetskoye NGDU ("Chepetskoye") Udmurtia 100.0% 100.0%OOO Dinyu ("Dinyu") Komi 100.0% -OOO Michayuneft ("Michayuneft") Komi 100.0% - Management companyOOO Urals Energy Moscow 100.0% 100.0% Service companyUrals Energy (UK) Limited United Kingdom 100.0% 100.0% ExplorationOOO Urals-Nord ("Urals-Nord")* Nenetsky 100.0% 50.0%TradingUENEXCO Limited ("UENEXCO")** Cyprus 100.0% - * Urals-Nord was an equity associate of the Group at 31 December 2004. ** UENEXCO was incorporated during 2005 for trading purposes. 2 Basis of Preparation of the Financial Statements and SignificantAccounting Policies Basis of preparation. These consolidated financial statements have been preparedin accordance with, and comply with, International Financial Reporting Standards("IFRS"). The consolidated financial statements have been prepared under thehistorical cost convention. The preparation of consolidated financial statementsin conformity with IFRS requires management to make prudent estimates andassumptions that affect the reported amounts of assets and liabilities at thedate of the financial statements preparation and the reported amounts ofrevenues and expenses during the reporting period. Critical estimates aredisclosed in Note 3. Actual results could differ from the estimates. Functional and presentation currency. The United States Dollar ("US dollar orUS$") is the presentation currency for the Group's operations as the majority ofthe Company's operations is conducted in US dollars and management have used theUS dollar accounts to manage the Group's financial risks and exposures, and tomeasure its performance. Financial statements of the Russian subsidiaries aremeasured in Russian Roubles and presented in US dollars in accordance with IAS21 (revised 2003), The Effects of Changes in Foreign Exchange Rates. Translation to functional currency. Monetary balance sheet items denominated inforeign currencies have been remeasured using the exchange rate at therespective balance sheet date. Exchange gains and losses resulting from foreigncurrency translation are included in the determination of profit or loss. The USdollar to Russian Rouble exchange rates were 28.78 and 27.75 as of 31 December2005 and 2004, respectively. Translation to presentation currency. The results and financial position of eachgroup entity (functional currency of none of which is a currency of ahyperinflationary economy) are translated into the presentation currency asfollows: (i) Assets and liabilities for each balance sheet presented aretranslated at the closing rate at the date of that balance sheet. Goodwill andfair value adjustments arising on the acquisitions are treated as assets andliabilities of the acquired entity. (ii) Income and expenses for each income statement are translated ataverage exchange rates (unless this average is not a reasonable approximation ofthe cumulative effect of the rates prevailing on the transaction dates, in whichcase income and expenses are translated at the dates of the transactions). (iii) All resulting exchange differences are recognised as a separatecomponent of equity. When a subsidiary is disposed of through sale, liquidation, repayment of sharecapital or abandonment of all, or part of, that entity, the exchange differencesdeferred in equity are reclassified to profit or loss. Group accounting. Subsidiaries, which are those entities in which the Group hasan interest of more than one half of the voting rights, or otherwise has powerto exercise control over the operations, are consolidated. Subsidiaries areconsolidated from the date on which control is transferred to the Group and areno longer consolidated from the date that control ceases. The purchase method ofaccounting is used to account for the acquisition of subsidiaries by the Group.The cost of an acquisition is measured as the fair value of the considerationprovided or liabilities incurred or assumed at the date of exchange plus costsdirectly attributable to the acquisition. All intercompany transactions, balances and unrealised gains on transactionsbetween group companies are eliminated; unrealised losses are also eliminatedunless the transaction provides evidence of an impairment of the assettransferred. Minority interest at the balance sheet date represents the minorityshareholders' portion of the fair values of the identifiable assets, liabilitiesand contingent liabilities of the subsidiary at the acquisition date, and theminorities' portion of movements in equity since the date of the combination.Minority interest is presented as a separate component of equity. Where thelosses applicable to the minority in a consolidated subsidiary exceed theminority interest in the equity of the subsidiary, the excess and any furtherlosses applicable to the minority are charged against the majority interestexcept to the extent that the minority has a binding obligation to, and is ableto, make good the losses. If the subsidiary subsequently reports profits, themajority interest is allocated all such profits until the minority's share oflosses previously absorbed by the majority has been recovered. Property, plant and equipment. Property, plant and equipment acquired as partof a business combination is recorded at fair value at the acquisition date.All subsequent additions are recorded at historical cost of acquisition orconstruction and adjusted for accumulated depreciation, depletion andimpairment. Oil and gas exploration and production activities are accounted forin accordance with the successful efforts method. Under the successful effortsmethod, costs of successful development and exploratory wells are capitalised.Costs of unsuccessful exploratory wells are expensed upon determination that thewell does not justify commercial development. Other exploration costs areexpensed as incurred. Depletion of capitalized costs of proved oil and gas properties is calculatedusing the units-of-production method for each field based upon proved reservesfor property acquisitions and proved developed reserves for exploration anddevelopment costs. Oil and gas reserves for this purpose are determined inaccordance with Society of Petroleum Engineers definitions and were estimated byDeGolyer and MacNaughton, the Group's independent reservoir engineers. Gains orlosses from retirements or sales of oil and gas properties are included in thedetermination of profit for the year. Depreciation of non oil and gas property, plant and equipment is calculatedusing the straight-line method over their estimated remaining useful lives, asfollows: Estimated useful life Refinery and related equipment 19Buildings 20Other assets 6 to 20 Provisions. Provisions are recognised when the Group has a present legal orconstructive obligation as a result of past events and when it is probable thatan outflow of resources embodying economic benefits will be required to settlethe obligation, and a reliable estimate of the amount of the obligation can bemade. Provisions, including those related to dismantlement, abandonment and siterestoration, are evaluated and re-estimated annually, and are included in thefinancial statements at each balance sheet date at their expected net presentvalues using discount rates which reflect the economic environment in which theGroup operates. Changes in provisions resulting from the passage of time are reflected in thestatement of income each year under financial items. Other changes inprovisions, relating to a change in the expected pattern of settlement of theobligation, changes in the discount rate or in the estimated amount of theobligation, are treated as a change in accounting estimate in the period of thechange. The provision for dismantlement liability is recorded on the balance sheet, witha corresponding amount being recorded as part of property, plant and equipmentin accordance with IAS 16. Leases. Leases of property, plant and equipment where the Group hassubstantially all the risks and rewards of ownership are classified as financeleases. Finance leases are capitalised at the commencement of the lease at thelower of the fair value of the leased property or the present value of theminimum lease payments. Each lease payment is allocated between the liabilityand finance charges so as to achieve a constant rate on the finance balanceoutstanding. The corresponding rental obligations, net of finance charges, areincluded in other long-term payables. The interest element of the finance costis charged to the income statement over the lease period. The property, plantand equipment acquired under finance leases are depreciated over the shorter ofthe useful life of the asset or the lease term, with the comparison being madebased on the current annual extraction level. Leases in which a significant portion of the risks and rewards of ownership areretained by the lessor are classified as operating leases. Payments made underoperating leases (net of any incentives received from the lessor) are charged tothe income statement on a straight-line basis over the period of the lease. Impairment of assets. Assets that are subject to depreciation are reviewed forimpairment whenever events or changes in circumstances indicate that thecarrying amount may not be recoverable. An impairment loss is recognised forthe amount by which the asset's carrying amount exceeds its recoverable amount.The recoverable amount is the higher of an asset's fair value less costs to sellor value in use. For the purposes of assessing impairment, assets are groupedat the lowest levels for which there are separately identifiable cash flows(cash-generating units). Inventories. Inventories of extracted crude oil, materials and supplies andconstruction equipment are valued at the lower of the weighted-average cost andnet realisable value. General and administrative expenditure is excluded frominventory costs and expensed in the period incurred. Trade receivables. Trade receivables are recognised initially at fair value andsubsequently measured at amortised cost using the effective interest method, netof provision for impairment. A provision for impairment of trade receivables isestablished when there is objective evidence that the Group will not be able tocollect all amounts due according to the original terms of receivables. Theamount of the provision is the difference between the asset's carrying amountand the present value of estimated future cash flows, discounted at theeffective interest rate. The amount of the provision is recognised in thestatement of operations. Cash and cash equivalents. Cash and cash equivalents include cash in hand anddeposits held at call with banks. Cash and cash equivalents are carried atamortised cost using the effective interest method. Value added tax. Value added taxes related to sales are payable to taxauthorities upon collection of receivables from customers. Input VAT isreclaimable against sales VAT upon payment for purchases. The tax authoritiespermit the settlement of VAT on a net basis. VAT related to sales and purchaseswhich have not been settled at the balance sheet date (VAT deferred) isrecognised in the balance sheet on a gross basis and disclosed separately as acurrent asset and liability. Where provision has been made against debtorsdeemed to be uncollectible, an impairment loss is recorded for the gross amountof the debtor, including VAT. The related VAT deferred liability is maintaineduntil the debtor is written off for statutory accounting purposes. Borrowings. Borrowings are recognised initially at the fair value of theliability, net of transaction costs incurred. In subsequent periods, borrowingsare stated at amortised cost using the effective yield method; any differencebetween amount at initial recognition and the redemption amount is recognised asinterest expense over the period of the borrowings. Borrowings are classifiedas current liabilities unless the Group has an unconditional right to defersettlement of the liability for at least 12 months after the balance sheet date. Loans receivable. The loans advanced by the Group to its shareholder areclassified as "loans and receivables" in accordance with IAS 39 and stated atamortised cost using the effective interest method. Deferred income taxes. Deferred income tax is calculated at rates enacted orsubstantially enacted at the balance sheet date, using the balance sheetliability method, for all temporary differences between the tax bases of assetsand liabilities and their carrying values for financial reporting purposes. Theprincipal temporary differences arise from depreciation on property, plant andequipment, provisions, fair value adjustments to long-term items, and expenseswhich are charged to the statement of operations before they become deductiblefor tax purposes. Deferred income tax assets attributable to deducible temporary differences,unused tax losses and credits are recognised only to the extent that it isprobable that future taxable profit or taxable temporary differences will beavailable against which they can be utilised. Deferred income tax assets and liabilities are offset when the Group has alegally enforceable right to set off current tax assets against current taxliabilities, when deferred tax balances relate to the same regulatory body, andwhen they relate to the same taxable entity. Social costs. The Group incurs employee costs related to the provision ofbenefits such as health insurance. These amounts principally represent animplicit cost of employing production workers and, accordingly, have beencharged to statement of operations. Pension costs. The Group makes required contributions to the Russian Federationstate pension scheme on behalf of its employees. Mandatory contributions to thegovernmental pension scheme are expensed or capitalized to inventories on abasis consistent with the associated salaries and wages. Revenue recognition. Revenues are recognised when crude oil or refined productsare dispatched to customers and title has transferred. Revenues from non-cashsales are recognised at the fair value of the goods or services received. Grossrevenues include export duties and excise taxes but exclude value added taxes. Segments. The Group operates in one business segment which is crude oilexploration and production. The Group assesses its results of operations andmakes its strategic and investment decisions based on the analysis of itsprofitability as a whole. The Group operates within one geographic segment,which is the Russian Federation. Reclassifications. Certain reclassifications have been made to 2004 amounts toconform to 2005 presentation. Additionally, certain adjustments were made to2004 amounts related to the finalization of the Group's purchase accounting for2004 acquisitions. The table below discloses the adjusted amounts before andafter the reclassifications. Management believes that the current presentationis preferable to that presented in prior years. As originally Following reported reclassification At 31 December 2004Inventories 2,247 2,773Property, plant and equipment 100,622 102,754Short-term borrowings and current portion of long-term borrowings 38,815 38,486Accounts payable and accrued expenses 3,019 3,748Deferred tax liability 17,751 18,390Other long-term liabilities - 1,590Translation difference 1,236 1,264 For the year ended 31 December 2004Selling, general and administrative expenses 7,115 6,825Cost of production 4,062 4,352 At 31 December 2004, inventories, property, plant and equipment, accountspayable and accrued expenses, deferred tax liability, other long-termliabilities and translation difference were increased by $0.526 million, $2.132million, $0.400 million, $0.639 million, $1.590 million and $0.028 million,respectively, to reflect the respective fair values after the Group completedits purchase accounting for its acquisition of Petrosakh that occurred inDecember 2004. Also at 31 December 2004, management reclassified $0.329 million from short-termborrowings and current portion of long-term debt to accounts payable and accruedexpenses to conform to current year's presentation of accrued interest andcertain other accruals. For the year ended 31 December 2004, selling, general and administrativeexpenses was decreased and cost of production was increased by $0.290 million,primarily to record salaries of management personnel working at productionlocations within cost of production. New accounting developments. In December 2003, the International AccountingStandards Board ("IASB") released 15 revised International Accounting Standardsand withdrew one IAS standard. The revised standards were all mandatory forperiods starting on or after 1 January 2005. In 2004, the IASB published five new standards, two revisions and two amendmentsto existing standards. In 2005, the IASB published one new standard and sevenamendments of existing standards. In addition, the International FinancialReporting Interpretations Committee issued five new interpretations in 2004 andtwo in 2005. Significant changes relevant to the Group as a result of the neweffective or early adopted IFRSs are: IAS 1 (revised 2003), Presentation of Financial Statements ("IAS 1 (revised)").IAS 1 (revised) requires the classification as current all financial liabilitiesfor which the Group does not have an unconditional right to defer theirsettlement for at least twelve months after the balance sheet date.Additionally, IAS 1 (revised) requires that minority interest be presentedwithin total equity and that profit or loss for the period is allocated between"profit or loss attributable to minority interest" and "profit or lossattributable to shareholders of the parent" on the face of the consolidatedstatements of operations. The revised standard is applied retrospectively inaccordance with IAS 8. IAS 8 (revised 2003), Accounting Policies, Changes in Accounting Estimates andErrors. The Group now applies all voluntary changes in accounting policiesretrospectively. Comparatives are amended in accordance with the new policies.All material errors are now corrected retrospectively in the first set offinancial statements after their discovery. IAS 21 (revised 2003) The Effects of Changes in Foreign Exchange Rates ("IAS 21(revised)"). IAS 21 (revised) clarifies the method of translation of foreigncurrencies to the functional and presentation currency and clarifies thatgoodwill and fair value adjustments to assets and liabilities resulting fromacquisitions are treated as part of the assets and liabilities of the acquiredentity and translated at the exchange rate on the balance sheet date. There wasno significant effect upon the Group's retrospective adoption of IAS 21(revised) on 1 January 2005. IAS 24 (revised 2003) Related Party Disclosures. The definition of relatedparties was extended and additional disclosures required by the revised standardwere made in these financial statements. The revised standard is appliedretrospectively in accordance with IAS 8. IAS 36 (revised 2004) Impairment of Assets ("IAS 36"). The Group now performsimpairment tests of goodwill, intangible asset not yet available for use andintangible assets with indefinite useful life at least annually. The 'bottom-up/top-down' approach to testing goodwill was replaced by a simpler method. Asapplicable, the goodwill is, from the acquisition date, allocated to each of theacquirer's cash-generating units ("CGU"), or groups of CGUs, that are expectedto benefit from the synergies of the business combination. Each unit or groupof units to which the goodwill is allocated represents the lowest level at whichthe goodwill is monitored and is not larger than a segment. Reversals ofimpairment losses of goodwill are now prohibited. The clarifications of certainelements of value in use calculations in the revised IAS 36 did not have animpact on these financial statements. Management now assesses reasonableness ofthe assumptions on which the Group's current cash flow projections are based byexamining the causes of differences between past cash flow projections andactual cash flows. The revised IAS 36 is applied in accordance with thestandard's transitional provisions to goodwill and intangible assets acquired inbusiness combinations for which the agreement date is on or after 31 March 2004and to all other assets prospectively from 1 January 2005. IAS 38 (revised 2004) Intangible Assets ("IAS 38"). The revised IAS 38 isapplied prospectively in accordance with its transitional provisions. Theamended accounting policies apply to intangible assets acquired in businesscombinations for which the agreement date is on or after 31 March 2004 and toall other intangible assets acquired on or after 1 January 2005. Intangibleassets now include assets that arise from contractual or other legal rights,regardless of whether those rights are transferable or separable. Theprobability of inflow of economic benefits recognition criterion is now deemedto be always met for intangibles that are acquired separately or in a businesscombination. The Group's policies were amended to introduce the concept ofindefinite life intangible assets which exist when, based on an analysis of allof the relevant factors, management concludes that there is no foreseeable limitto the period over which the asset is expected to generate net cash inflows.Such intangibles are not amortised but tested for impairment at least annually.The Group has reassessed the useful lives of its intangible assets in accordancewith the transitional provisions of IAS 38. No adjustment resulted from thisreassessment. IFRS 2, Share-based Payment. IFRS 2 requires that the fair value of theemployee services received in exchange for the grant of the equity instrumentsis recognised as an expense over the vesting period. For transactions withparties other than employees, the Group accounts for the transaction based uponthe fair value of goods or services provided, unless the fair values are notreliably estimable. The adoption of IFRS 2 on 1 January 2005 did not have amaterial effect on the Group as the Group had no outstanding share-based awardsupon adoption. IFRS 3, Business Combinations. IFRS 3 requires accounting for all businesscombinations by applying the purchase method and separate recognition, at theacquisition date, of the acquiree's contingent liabilities if their fair valuescan be measured reliably. It also requires that the identifiable assets,liabilities and contingent liabilities are measured at their fair valuesirrespective of the extent of any minority interest. Any resulting goodwill istested for impairment annually, or when there are indications of impairment.The excess of the Group's interest in the net fair value of an acquiree'sidentifiable assets, liabilities and contingent liabilities over the cost ("negative goodwill") is recognized immediately in the consolidated statement ofoperations. The Group applies transitional provisions of IFRS 3 and applies itto all business combinations for which the agreement date is on or after 31March 2004. IFRS 5 (issued 2005) Non-current Assets Held for Sale and DiscontinuedOperations ("IFRS 5"). The Group applies IFRS 5 prospectively in accordancewith its transitional provisions to non-current assets (or disposal groups) thatmeet the criteria to be classified as 'held for sale' and operations that meetthe criteria to be classified as 'discontinued' after 1 January 2005. TheGroup's accounting policies now describe assets 'held for sale' as those thatwill be recovered principally through a sale transaction rather than throughcontinuing use. Subject to certain exceptions, assets or disposal groups thatare classified as 'held for sale' are measured at the lower of carrying amountand fair value less costs to sell. Such assets cease to be depreciated and arepresented separately on the face of the balance sheet. There was no impact ofthe adoption of IFRS 5. IFRS 6, Exploration for and Evaluation of Mineral Resources ("IFRS 6"). IFRS 6was early adopted by the Group, before its effective date. IFRS 6 allows anentity to continue using the accounting policies for exploration and evaluationassets applied immediately before adopting the IFRS, subject to certainimpairment test requirements. As permitted under IFRS 6, the Group capitalizesexploration and evaluation costs until such time as the economic viability ofproducing the underlying resources is determined. IAS 21 (Amendment) - Net Investment in a Foreign Operation. The amendment toIAS 21 was early adopted by the Group, before its effective date. It clarifiestreatment of foreign exchange differences on intercompany loans that form partof a net investment in a foreign operation. The adoption of all the other new or revised standards that are effective for2005 did not have a material impact on the Group's financial position,statements of income or of cash flows. New or revised standards that are not yet effective. Certain new standards andinterpretations have been published that are mandatory for the Group'saccounting periods beginning on or after 1 January 2006 or later periods andwhich the Group has not early adopted: IFRIC 4, Determining whether an Arrangement contains a Lease (effective from 1January 2006); IAS 39 (Amendment) - The Fair Value Option (effective from 1January 2006); IAS 39 (Amendment) - Cash Flow Hedge Accounting of ForecastIntragroup Transactions (effective from 1 January 2006); IAS 39 (Amendment) -Financial Guarantee Contracts (effective from 1 January 2006); IFRS 7,Financial Instruments: Disclosures and a Complementary Amendment to IAS 1Presentation of Financial Statements - Capital Disclosures (effective from 1January 2007); IAS 19 (Amendment) - Employee Benefits (effective from 1 January2006); IFRS 1 (Amendment) - First-time Adoption of International FinancialReporting Standards and IFRS 6 (Amendment) - Exploration for and Evaluation ofMineral Resources (effective from 1 January 2006); IFRIC 5, Rights to Interestsarising from Decommissioning, Restoration and Environmental Rehabilitation Funds(effective from 1 January 2006); IFRIC 6, Liabilities arising fromParticipating in a Specific Market - Waste Electrical and Electronic Equipment(effective for periods beginning on or after 1 December 2005); IFRIC 7,Applying the Restatement Approach under IAS 29 (effective for periods beginningon or after 1 March 2006); IFRIC 8, Scope of IFRS 2 (effective for periodsbeginning on or after 1 May 2006) and IFRIC 9, Reassessment of EmbeddedDerivatives (effective for periods beginning on or after 1 June 2006). 3 Critical Estimates in Applying Accounting Policies These new standards and interpretations are not expected to significantly affectthe Group's financial statements when adopted on 1 January 2006 or later. The Group makes estimates and assumptions that affect the reported amounts ofassets and liabilities. Estimates and judgements are continually evaluated andare based on management's experience and other factors, including expectationsof future events that are believed to be reasonable under the circumstances.Management also makes certain judgements, apart from those involvingestimations, in the process of applying the accounting policies. Judgments thathave the most significant effect on the amounts recognised in the financialstatements and estimates that can cause a significant adjustment to the carryingamount of assets and liabilities are outlined below. Accounting for extractive industry activity. The Group follows the successfulefforts method of accounting for oil and gas properties. Under the successfulefforts method, property acquisitions, successful exploratory wells, alldevelopment costs and support equipment and facilities are capitalised.Unsuccessful exploratory wells are charged to expense at the time the wells aredetermined to be non-productive. Production costs, overhead and all explorationcosts other than exploratory drilling are charged to expense as incurred.Acquisition costs of unproved properties, exploration and evaluation costs areevaluated periodically and any impairment assessed is charged to expense. The Group calculates depreciation, depletion and amortisation of capitalisedcosts of oil and gas properties using the unit-of-production method for eachfield based upon proved developed reserves for exploration and developmentcosts, and total proved reserves for acquisitions of proved properties. Forthis purpose, the oil and gas reserves of key fields have been determined basedon estimates of mineral reserves determined in accordance with internationallyrecognised definitions and independently assessed by internationally recognisedpetroleum engineers. The present value of the estimated costs of dismantling oiland gas production facilities, including abandonment and site restoration costsare recognised when the obligation is incurred and are included within thecarrying value of property, plant and equipment, and therefore subject toamortisation thereon using the unit-of-production method. Changes in estimatesof reserves can result in significant changes in depletion expense. Tax legislation. Russian tax, currency and customs legislation is subject tovarying interpretations as further discussed in Note 17. Deferred income tax asset recognition. Deferred tax assets represent incometaxes recoverable through future deductions from taxable profits. Deferredincome tax assets are recorded on the Group's consolidated balance sheets to theextent that realisation of the related tax benefits is probable. In determiningfuture taxable profits and the amount of tax benefits that are probable in thefuture, management makes judgements and applies estimation based on recentyears' taxable profits and expectations of future taxable income. Related party transactions. In the normal course of business, the Group entersinto transactions with its related parties. Judgement is applied in determiningif transactions are priced at market or non-market interest rates, where thereis no active market for such transactions. The basis for judgement is pricingfor similar types of transactions with unrelated parties and effective interestrate analyses. Assumptions to determine amount of provisions. In determining amounts ofprovisions, management uses all information available to determine whether anasset is recoverable or whether it is probable that an event will result inoutflows of resources from the Group. Significant judgment is used to estimatethe amounts of provisions, including such factors as the current overalleconomic conditions, specific customer, counterparty or industry conditions andthe current overall legal and tax environment. Changes in any of theseconditions may result in adjustments to provisions recorded by the Group. Useful lives of property, plant and equipment. Items of property, plant andequipment are stated at cost less accumulated depreciation. The estimation ofthe useful life of an item of property, plant and equipment is a matter ofmanagement judgment based upon experience with similar assets. In determiningthe useful life of an asset, management considers the expected usage, estimatedtechnical obsolescence, physical wear and tear and the physical environment inwhich the asset is operated. Changes in any of these conditions or estimatesmay result in adjustments to future depreciation rates. Fair values of acquired assets and liabilities. Since its inception, the Grouphas completed several significant acquisitions (Note 4). IFRS 3 requires that,at the date of acquisition, all identifiable assets (including intangibleassets), liabilities and contingent liabilities of an acquired entity berecorded at their respective fair values. The estimation of fair valuesrequires management judgment. For significant acquisitions, management engagesindependent experts to advise as to the fair values of acquired assets andliabilities. Changes in any of the estimates subsequent to the finalization ofacquisition accounting may result in losses in future periods. Going concern. Management assumed that the Group will continue as a goingconcern. Fair values of financial instruments. Fair value is the amount at which afinancial instrument could be exchanged in a current transaction between willingparties, other than in a forced sale or liquidation, and is best evidenced by anactive quoted market price. The estimated fair values of financial instrumentshave been determined by the Group using available market information, where itexists, and appropriate valuation methodologies where no market information isavailable. However, judgement is necessarily required to interpret market datato determine the estimated fair value. Cash and cash equivalents are carried at amortised cost which approximatescurrent fair value. At 31 December 2005 and 2004, the carrying amounts of trade and otherreceivables, short-term borrowings, trade and other payables, taxes payable andadvances from customers approximated their fair values. The fair values of the Group's long-term borrowings were estimated based uponrates available to the Group on similar instruments of similar maturities. At31 December 2005 and 2004, management believes that the fair values of itsborrowings approximate their respective carrying values. 4 Acquisitions Acquisition of Dinyu. In November 2005, the Group acquired a 100.0 percentstake in Dinyu from Lonsdacks Investments Limited for $61.5 million followingthe approval from the Russian Federal Antimonopoly Service. Subsequent to its purchase of Dinyu, on 21 December 2005 the Group purchased the35 percent stake owned by third parties in the 65 percent-owned subsidiary ofDinyu, OOO Michayuneft ("Michayuneft") for $0.2 million. Since the date ofacquisition, Dinyu contributed $0.466 million of net profit to the Group'soperating results. Acquisition of Arcticneft. In July 2005, the Group acquired a 100.0 percentequity interest in Arcticneft from OAO LUKoil for $23 million net of debt.Arcticneft holds production licenses in the Nenetsky Autonomous Region of theRussian Federation. Since the date of acquisition, Arcticneft contributed$0.320 million of net loss to the Group's operating results. Management's purchase accounting allocation resulted in an excess of $16.8million of net identifiable assets and oil and gas properties and equipment overthe purchase price. Management believes that this amount is attributed to theseller's undervaluing of Arcticneft and its desire to dispose of non-coreassets. The associated gain was recorded in the Group's consolidated statementof operations for the year ended 31 December 2005. Acquisition of Urals-Nord. In April 2005, the Company acquired the remaining50.0 percent interest in OOO Urals Nord ("Urals Nord") for $14 million. On thatdate $1.5 million was paid immediately in cash and $12.5 million was paid inOctober 2005. The Group incurred $0.84 million of additional cost related toseismic review of the license areas. Urals Nord holds 5 exploration licensesfor Beluginisky, Zapadno-Sorokinskiy, Fakelniy, Nadezhdinskiy and AlfinskiyProspects. Urals-Nord has been consolidated from the date of acquisition.Management believes that the purchase price for Urals-Nord approximates the fairvalue of unproved oil and gas properties acquired. Such unproved oil and gasproperties are included within property, plant and equipment in the consolidatedbalance sheet. No goodwill was recognized in the acquisition. Since the dateof acquisition, Urals-Nord contributed $0.035 million of net loss to the Group'soperating results. Fair values of acquired companies. The table below discloses the carryingvalues and fair values of the assets and liabilities of the companies acquiredduring 2005 immediately prior to and upon acquisition, respectively. The valuesdisclosed below comprise 100 percent of the assets and liabilities of theacquirees. The IFRS carrying values before the acquisition reported belowrelate to the IFRS carrying values in the separate accounts of the acquirees.Such stakes were revalued to their fair values at the acquisition date forpurposes of these consolidated financial statements. Urals-Nord Arcticneft, Dinyu, including Michayuneft IFRS Fair IFRS Fair IFRS Fair carrying values at carrying values at carrying values at amounts acquisition amounts acquisition amounts acquisition before before before acquisition acquisition acquisitionCash and cash equivalents - - 2,045 2,045 122 122Accounts receivable and - - 1,719 1,719 4,224 4,224prepaymentsOther current assets - - 8,350 12,583 1,243 1,243Oil and gas properties and 840 19,261 34,073 74,040 15,460 86,466equipmentOther non-current assets - - 188 188 857 857Short-term borrowings and 840 840 13,036 13,036 8,653 8,563current portion of long-termborrowingsOther current liabilities - - 20,425 20,425 5,574 5,574Deferred income tax - 4,421 5,934 16,503 - 17,041liability, non-currentOther non-current liabilities - - 784 784 - - Summary combined financial information. The following table sets forth summarycombined financial information for the year ended 31 December 2005 that ispresented to provide information to evaluate the financial effects of theacquisitions of Arcticneft, Dinyu and Urals-Nord as if they had occurred on 1January 2005. Group Urals-Nord Arcticneft Dinyu Adjustments Summary results and eliminations combined Total revenues 92,918 - 22,154 31,831 (27,507) 119,396Profit (loss) for the period 7,055 (35) (1,082) 2,354 (669) 7,623 The summary combined financial information should not be construed to representconsolidated financial information. Group results include the activities of theacquired entities from the respective acquisition dates through 31 December2005. Total revenues and profit (loss) for the period for Urals-Nord,Arcticneft and Dinyu comprise the respective entities' results for the fullyear, including the period prior to acquisition, without adjustments forintercompany transactions or fair values. Adjustments and eliminations includethe following: (a) depreciation, depletion and amortization was adjusted toreflect the higher carrying values of property, plant and equipment followingfair value adjustments; (b) intercompany eliminations were recorded; (c)adjustments to eliminate results of the period included both in the Groupresults and the respective entities' results for the full year; and (d)corresponding adjustments for income taxes were recorded. However, noadjustments were made to adjust interest expense for borrowings used to financethese acquisitions. Acquisition of Petrosakh. In December 2004, the Group acquired a 97.2 percentequity interest in Petrosakh for $46.9 million. Petrosakh is an integrated oiland gas exploration and production company located on Sakhalin Island in theRussian Far East. Petrosakh operates the Okruzhnoye and Pogranichnoye onshoreoil fields licenses and has an exploration license for the off-shore part of thePogranichnoye field. No goodwill was recognized on the acquisition ofPetrosakh. Acquisition of CNPSEI. In November 2004, the Group acquired a 100.0 percentequity interest in CNPSEI for $6.8 million. CNPSEI is an oil and gasexploration and production company located in the Komi region of northernRussia. CNPSEI operates the Sosnovskoye and Yuzhnotebukskoye onshore oil fieldlicenses. No goodwill was recognized on the acquisition of CNPSEI. Acquisition of Chepetskoye. In October 2004, the Group acquired a 100.0 percentinterest in Chepetskoye, from one if its principal shareholders for nominalconsideration. Chepetskoye is an oil and gas exploration and production companylocated in the Udmurtia region of the Russian Federation. Chepetskoye operatesthe Zapadno-Krasnogorsky onshore oil field licenses. This acquisition was contemplated as part of the Urals Energy ShareholderAgreement dated 28 July 2004, whereby shareholders would contribute cash orassets for their equity interests in Urals Energy (Note 12). Chepetskoye wasrecognised initially at its fair value of $5.9 million. Fair values of acquired companies. The table below discloses the carryingvalues and fair values of the assets and liabilities of the companies acquiredduring 2004 immediately prior to and upon acquisition, respectively. The valuesdisclosed below comprise 100.0 percent of the assets and liabilities of theacquirees. The IFRS carrying values before the acquisition reported belowrelate to the IFRS carrying values in the separate accounts of the acquirees.Such stakes were revalued to their fair values at the acquisition date forpurposes of these consolidated financial statements. Petrosakh CNPSEI Chepetskoye IFRS Fair IFRS Fair IFRS Fair carrying values at carrying values at carrying values at amounts acquisition amounts acquisition amounts acquisition before before before acquisition acquisition acquisitionCash and cash equivalents 373 373 1 1 158 158Other current assets 2,540 3,776 1,016 1,016 654 654Properties, plant and equipment 16,517 13,220 1,520 1,520 401 401(excluding oil and gasproperties) Oil and gas properties 6,439 60,698 3,264 7,886 7,529 15,768Other non-current assets 59 59 - - - -Short-term borrowings and 10,478 10,478 - - 8,650 8,650current portion of long-termborrowingsOther current liabilities 2,327 2,266 2,101 2,101 266 266Deferred income tax 2,559 14,915 270 1,417 31 2,008liability, non-currentOther non-current liabilities 2,205 2,205 105 105 155 155 Had these acquisitions been completed on 1 January 2004, consolidated revenuesand net loss would have been $33.7 million and $3.0 million, respectively, forthe year ended 31 December 2004. 5 Accounts receivable and prepayments 31 December: 2005 2004Accounts and notes receivable - trade ($0.586 million and $0.608 7,871 70million provision for impairment at 31 December 2005 and 2004)Prepaid taxes, other than value added tax 4,408 410Advances to suppliers 3,871 453Recoverable taxes including VAT 3,503 1,720Receivables from related parties (Note 19) 2,725 723Other 1,410 330 Total accounts receivable and prepayments 23,788 3,706 6 Inventories 31 December: 2005 2004Crude oil 3,252 1,184Petroleum products 1,590 592Materials and supplies 7,799 997 Total inventories 12,641 2,773 7 Property, Plant and Equipment Activity within property, plant and equipment for the two years ended 31December 2005 is detailed below. Oil and gas Refinery and Buildings Other Assets Assets under Total properties related construction equipmentCostBalance at 31 December 2003 - - - - - -Translation difference 1,933 124 14 57 50 2,178Business combinations 84,876 8,560 975 3,582 1,770 99,763Additions - - - 133 1,217 1,350Transfers 579 - - - (579) - Balance at 31 December 2004 87,388 8,684 989 3,772 2,458 103,291 Translation difference (5,129) (315) (41) (154) (219) (5,858)Business combinations 172,110 615 1,100 650 5,405 179,880Additions 4,697 - - 209 16,452 21,358Transfers 8,053 - - 964 (9,017) -Changes in estimates of (765) - - - - (765)dismantlement provisionDisposals (217) - - (310) (325) (852) Balance at 31 December 2005 266,137 8,984 2,048 5,131 14,754 297,054 Oil and gas Refinery and Buildings Other Assets Assets under Total properties related construction equipmentAccumulated DepreciationBalance at 31 December 2003 - - - - - -Translation difference (14) - - (1) - (15)Depreciation, depletion (505) - - (17) - (522)and amortization Balance at 31 December 2004 (519) - - (18) - (537) Translation difference 128 8 4 10 - 150Depreciation, depletion (8,044) (510) (226) (614) - (9,394)and amortizationDisposals 118 - - 94 - 212 Balance at 31 December 2005 (8,317) (502) (222) (528) - (9,569)Net Book ValueBalance at 31 December 2004 86,869 8,684 989 3,754 2,458 102,754Balance at 31 December 2005 257,820 8,482 1,826 4,603 14,754 287,485 Included within oil and gas properties at 31 December 2005 and 2004 wereexploration and evaluation assets of $140.5 million and $37.5 million,respectively, including property acquisition costs with net book values of$134.0 million and $37.5 million, respectively, not subject to depletion.Additionally, included within oil and gas properties at 31 December 2005 and2004 were property acquisition costs with net book value of $41.6 million and$12.8 million, respectively, that were being depleted over total provedreserves. The Group's oil fields are situated in the Russian Federation on land owned bythe Russian government. The Group holds licenses and associated mining plots andpays production taxes to extract oil and gas from the fields. The licensesexpire between 2008 and 2067, but may be extended. Management intends to renewthe licences as the properties are expected to remain productive subsequent tothe license expiration date. Estimated costs of dismantling oil and gas production facilities, includingabandonment and site restoration costs, amounting to $0.020 million and $0.198million at 31 December 2005 and 2004, respectively, are included in the cost ofoil and gas properties. The Group has estimated its liability based on currentenvironmental legislation using estimated costs when the expenses are expectedto be incurred. At 31 December 2005 and 2004, property, plant and equipment with carrying netbook value of $90.2 million and $1.6 million, respectively, was pledged ascollateral for the Group's borrowings. 8 Accounts Payable and Accrued Expenses 31 December: 2005 2004Trade payables 2,809 236Interest payable 833 224Wages and salaries 806 278Advances from and payables to related parties (Note 19) 77 861Payable under guarantee arrangements (Note 19) - 1,073Other payable and accrued expenses 3,407 1,076 Total accounts payable and accrued expenses 7,932 3,748 Of interest payable, $0.117 million was payable to related parties at 31December 2004. 9 Taxes Income taxes for the periods ended 31 December 2005 and 2004 comprised thefollowing: Year ended 31 December: 2005 2004Current tax expense 890 103Deferred tax charge (benefit) (3,155) (280) Income tax charge (benefit) (2,265) (177) Below is a reconciliation of profit (loss) before taxation to income tax charge(benefit): Year ended 31 December: 2005 2004Profit (loss) before income tax 4,708 (3,835) Theoretical tax charge (benefit) 1,130 (920)at the statutory rate of 24 percent Excess of net assets acquired over purchase price (4,030) -Non-recurring mobilization costs 1,721 -Losses utilized in the current year (1,340) -Tax credits related to seismic surveys (1,047) -Expenses at other tax rates 939 -Other income not assessable for income tax purposes - (10)Other expenses and losses not deductible for income tax purposes 334 748Effect of tax penalties 28 5 Income tax charge (benefit) (2,265) (177) The movement in deferred tax assets and liabilities during the year ended 31December 2005 was as follows: 2005 Recognized in Charged (credited) Effect of 2004 equity for to the statement of acquisitions translation operations differencesDeferred tax liabilitiesProperty, plant and equipment 52,620 (1,066) (1,883) 36,167 19,402Inventories 90 (3) (1,479) 1,445 127Payables 291 - 223 68 -Borrowings received - (3) (142) - 145Other taxable temporary differences 113 (2) 115 - - Deferred tax assetsReceivables (155) 6 5 - (166)Dismantlement provision (190) 7 219 (188) (228)Payables (360) 14 158 (190) (342)Inventories (114) 4 87 - (205)Other deductible temporary (555) 19 (93) (429) (52)differencesTax losses (640) 16 (365) - (291) Net deferred tax liability 51,100 (1,008) (3,155) 36,873 18,390 The movement in deferred tax assets and liabilities during the year ended 31December 2004 was as follows: 2004 Recognized in Charged (credited) Effect of 2003 equity for to the statement of acquisitions translation operations differencesDeferred tax liabilitiesProperty, plant and equipment 19,402 372 (40) 19,070 -Inventories 127 2 - 125 -Borrowings received 145 2 - 143 - Deferred tax assetsReceivables (166) (55) 21 (132) -Dismantlement provision (228) (5) - (223) -Payables (342) (5) - (337) -Inventories (205) (3) - (202) -Other deductible temporary (52) (20) 19 (51) -differencesTax losses (291) (11) (280) - - Net deferred tax liability 18,390 277 (280) 18,393 - There is no concept of consolidated tax returns in the Russian Federation and,consequently, tax losses and current tax assets of different subsidiaries cannotbe set off against tax liabilities and taxable profits of other subsidiaries.Accordingly, taxes may accrue even where there is a net consolidated tax loss.Similarly, deferred tax assets of one subsidiary cannot be offset againstdeferred tax liabilities of another subsidiary. At 31 December 2005 and 2004,deferred tax assets of $2.000 million and $1.754 million, respectively, have notbeen recognized for deductible temporary differences for which it is notprobable that sufficient taxable profit will be available to allow the benefitof that deferred tax asset to be utilised. The Group has not recognised deferred tax liabilities for temporary differencesassociated with investments in subsidiaries as the Group is able to control thetiming of the reversal of those temporary differences and does not intend toreverse them in the foreseeable future. At 31 December 2005 and 2004, theestimated unrecorded deferred tax liabilities for such differences were $1.395million and $0.638 million, respectively. Taxes payable at 31 December 2005 and 2004 were as follows: 31 December: 2005 2004 Income taxes payable 6,039 387Unified production tax 2,257 654Value added tax 1,311 577Other taxes payable 1,880 299 11,487 1,917 Total taxes payable 10 Borrowings All borrowings outstanding at 31 December 2005 were denominated in US Dollars. Short-term borrowings. Short-term borrowings and current portion of long-termborrowings were as follows at 31 December 2005 and 2004. 31 December: 2005 2004Loan from Alfa Eco M - 10,993Related party borrowings - 27,493Current portion of long-term borrowings 34,117 -Total short-term borrowings and 34,117 38,486current portion of long-term borrowings Loan from Alfa Eco M. Alfa Eco M is related to previous shareholders ofPetrosakh (Note 4). The loan was rouble denominated, bore interest at 9.5percent per annum and was fully repaid in June 2005. Related party borrowings. At 31 December 2005 and 2004, outstanding borrowingsfrom related parties totalled nil and $27.5 million, respectively. Theborrowings, which were fully repaid or converted to shares of the Group during2005, were unsecured and from shareholders and companies controlled byshareholders. All borrowings were denominated in US dollars except those fromNafta (B) NV, which were denominated in Euros. The table below outlines all activity on related party borrowings outstanding at31 December 2004. Name of party 31 December 31 December 2004 Date of 2005 repayment/ conversion (2005)Shareholders - settled against unpaid capitalHillsilk Limited - 330 March Shareholders - converted to sharesRadwood Business Inc. - 500 AugustPolaris Business Limited - 300 AugustCitara International Limited - 5,000 AugustFantin Finance Limited - 3,000 August Shareholders - converted to shares and settled against unpaid capitalTexas Oceanic Petroleum LLC - 1,500 August Controlled by shareholders - settled against unpaid capitalUEN Trading Limited - 8,660 March Controlled by shareholders - converted to sharesNafta (B) NV - 6,822 June Other - 1,381 Total related party borrowings - 27,493 Shareholders. During 2005, the $0.330 million loan due to Hillsilk Limited and$1.0 million of the $1.5 million loan due to Texas Oceanic Petroleum LLC wereconverted to equity as settlement of the shareholders' unpaid share capitalbalances (Note 12) and the remaining $0.5 million were converted to additionalshares of the Group (Note 12). In July 2005, the Group amended its loan agreements with Radwood Business Inc.,Polaris Business Limited, Citara International Limited, Fantin Finance Limitedand Texas Oceanic Petroleum LLC (who collectively at 31 December 2004, provided$9.3 million, Libor plus 2.0 percent unsecured notes to the Group), whereby theloan interest was restated to 15.0 percent per annum, effective retroactively tothe origination of the loan. In August 2005, the balance of the loans,including unpaid interest, were extinguished by issuing 3,879,844 shares at aconversion rate of $2.65 per share, the estimated fair value of the Group'sshares at the time the conversion was agreed. In accordance with IAS 39, Financial Instruments, Recognition and Measurement,this modification and conversion comprise an extinguishment of debt.Accordingly, the difference of $0.6 million between the carrying value of theborrowings at the time of the extinguishment and the fair value of theconsideration provided by the Group were recognized as a loss on extinguishmentof debt in the consolidated statement of operations. Controlled by shareholders. During 2005, the $8.660 million loan due to UENTrading Limited was converted to equity as settlement of a portion of UEN CyprusLimited's unpaid share capital balance (Note 12). In June 2005, the Group settled its obligation to Nafta (B) NV by issuing sharesat $2.65 per share (Note 12). Long-term borrowings. Long-term borrowings were as follows at 31 December 2005and 2004. 31 December: 2005 2004 BNP Paribas Reserve Based Loan Facility 69,000 -Bank Zenit 12,000 -Other 122 - Subtotal 81,122 -Less: current portion of long-term borrowings (34,117) - Total long-term borrowings 47,005 - BNP Paribas Reserve Based Loan Facility. In November 2005, the Group closed afive year, revolving Reserve Based Loan Facility with BNP Paribas, underwrittento a maximum commitment of $100.0 million. In November 2005, the maximum amountthen available of $69.0 million was drawn. The facility is divided into asenior conforming tranche of $59.0 million that bears interest at LIBOR plus 5.0percent and a junior non-conforming tranche of $10.0 million priced at LIBORplus 6.25 percent. Both tranches are repayable in full in December 2010. Theloan was collateralized by liens on property, plant and equipment ofsubsidiaries (Note 7). The Group is subject to certain financial and othertechnical covenants under the BNP Paribas Reserve Based Loan Facility includingthe maintenance of a minimum financial ratios. The Group is in compliance withits covenants under the facility at 31 December 2005. Bank Zenit. In March 2005, the Chepetskoye and CNPSEI entered into two loanagreements with Bank Zenit totalling $12.0 million. The loan agreements boreinterest at 11.0 percent per annum and were scheduled to mature in March 2010.The loans contained cross default provisions and were collateralized by liens onproperty, plant and equipment of these subsidiaries (Note 7). This loan wasrepaid in February 2006. BNP Paribas Bank Credit Facility. In June 2005, the Petrosakh entered into a$20.0 million, 18 month per-export credit facility with BNP Paribas Bank. Thisvariable interest debt facility bore interest at LIBOR plus 5.0 percent and wasoriginally repayable in December 2006. This facility was repaid in full inNovember 2005. RP Capital Group. In July 2005, the Group entered into a 10.0 percentconvertible preferred note agreement with RP Capital Group for up to $15.0million. In the event of a qualifying initial public offering ("IPO") the noteswere convertible into ordinary shares at a 20 percent discount to the IPO price.In July 2005 the Group issued $10.0 million of the convertible notes at par.These notes were converted into 2,929,651 shares in August 2005. No gain orloss was recognized on conversion. Scheduled maturities of long-term borrowings outstanding were as follows: Scheduled maturities at 31 December:Year ended 31 December: 2005 2004 One year 34,117 38,486Two to five years 47,005 -Thereafter - - Total long-term borrowings 81,122 38,486 11 Dismantlement Provision The dismantlement provision represents the net present value of the estimatedfuture obligation for dismantlement, abandonment and site restoration costswhich are expected to be incurred at the end of the production lives of the oiland gas fields. The discount rate used to calculate the net present value of thedismantling liability was 13.0 percent. Year ended 31 December: 2005 2004Opening dismantlement provision 950 -Translation difference (21) 20Acquisitions 785 920Additions 20 -Changes in estimates (1,145) -Change due to passage of time 224 10 Closing dismantlement provision 813 950 As further discussed in Note 17, environmental regulations and their enforcementare under development by governmental authorities. Consequently, the ultimatedismantlement, abandonment and site restoration obligation may differ from theestimated amounts and this difference could be significant. 12 Equity At 31 December 2005, the Group's authorized ordinary shares were 100 million,each having a par value of 0.0025 Cypriot pounds, of which 86.9 million wereissued and outstanding shares at 31 December 2005. In January 2006, the Group's shareholders approved a resolution increasing theauthorized shares by 20 million to 120 million. Share activity and other capital contributions for the two years ended 31December 2005 are outlined below. All share amounts have been given retroactiveeffect for the 400:1 share split executed in July 2005. Number of Share Share Unpaid shares capital premium capital (thousands of shares)Balance at 31 December 2003 4,000 20 10 - Share issuance 36,000 189 41,291 (11,324)Contribution from shareholders - - 871 - Balance at 31 December 2004 40,000 209 42,172 (11,324) Partial conversion of - - - 1,000Texas Oceanic Petroleum LLC loanConversion of UEN Trading Limited loan - - - 8,660Conversion of Hillsilk Limited - - - 330Conversion of other related party loans - - - 1,027Issuance of shares to Nafta (B) NV 9,434 50 24,950 -Conversion of shareholder loans 3,880 20 10,261 -Conversion of RP Capital Group loan 2,930 16 9,984 -Shares issued for cash 30,667 165 113,946 -Unpaid capital received in cash - - - 307Share-based payment - - 42 - Balance at 31 December 2005 86,911 460 201,355 - Urals Energy was created on 10 November 2003. Share capital at incorporationcomprised 10,000 authorized and issued ordinary shares with a nominal value ofone Cyprus Pound (CYP). In July 2004, the shareholders signed a ShareholderAgreement (the "Agreement") whereby, the Group issued an additional 90,000ordinary shares for total consideration of $41.5 million. The share issuancewas settled with in-kind contributions with a fair value of $17.5 million(comprising a 100 percent interest in Chepetskoye valued at $5.9 million,shareholder advances to group companies totalling $9.7 million and expensesincurred on behalf of the Group totalling $1.9 million) and cash of $24.0million. At 31 December 2004, $11.3 million of the cash contributions remainedunpaid. In addition to contributions in accordance with the Shareholder's Agreement,during 2004, the shareholders also contributed their equity interest in OOOUrals Energy with a fair value of $0.9 million. This contribution was recordedas additional paid-in capital. Partial conversion of Texas Oceanic Petroleum LLC loan. In May 2005, $1.0million of the $1.5 million loan due to Texas Oceanic Petroleum LLC wasconverted to equity as settlement of Texas Oceanic Petroleum's unpaid sharecapital (Note 10). The remaining balance was converted to shares of the Group. Conversion of UEN Trading Limited loan. In March 2005, the $8.660 million loandue to UEN Trading Limited was converted to equity as settlement of UEN CyprusLimited's unpaid share capital (Note 10). Issuance of shares to Nafta (B) NV. In June 2005, the Group issued 9,434ordinary shares to Nafta (B) NV, a company owned in majority by two of theshareholders, for total consideration of $25.0 million. The share issuance wassettled with a cash contribution of $18.4 million and conversion of $6.6 millionin existing debt of Nafta B. Conversion of shareholder loans. In August 2005, the Group extinguished itsloans from Radwood Business Inc., Polaris Business Limited, Citara InternationalLimited, Fantin Finance Limited and Texas Oceanic Petroleum LLC by issuing3,879,844 shares at a conversion rate of $2.65 per share (Note 10). Conversion of RP Capital Group loan. In August 2005, the Group extinguished$10.0 million of debt outstanding to RP Capital Group by issuing 2,929,651shares (Note 10). Shares issued for cash. In August 2005, the Group completed an initial publicoffering of its shares. As part of the offering, the Group issued 30,667,050shares in exchange for $114.1 million, net of transaction costs. Share-based payments. During 2005, the Group granted a share-based award to oneof its officers. Under the award, the officer shall have the option to purchasea certain number of the Group's shares at a share price equal to $131 milliondivided by the number of Group shares that are issued and outstanding at both 1August 2006 and 1 August 2007. The option is in two parts comprised of thenumber of shares that can be purchased for a payment of $125,000 on 1 August2006 and of $125,000 on 1 August 2007, which are the respective vesting dates ofthe two parts of the award. The officer is required to be continuously employedby the Group through the vesting dates. Notification of intent to purchase mustbe submitted within three days of the respective dates, and payment and deliveryof shares to the officer are to occur within 15 days of the respective dates. During 2005, the Group estimated the total fair value of the award to be $0.067million, of which $0.042 million was recognized during 2005 within selling,general and administrative expenses, with respect to this award. The fullamount of the award is being recognized over its vesting period. TheBlack-Scholes option valuation model, used for valuing this award, was developedfor use in estimating the fair value of traded options that have no vestingrestrictions and are fully transferable. In addition, this option valuationmodel requires the input of highly subjective assumptions, including theexpected stock price volatility. As the Group's shares were not publicly tradedat the time of the grant of this award, management estimated the volatilitymeasure through consultation with independent experts. Changes in thesubjective input assumptions can materially affect the fair value estimate.Based on the assumptions below, the weighted average fair value of this optionwas estimated to be $0.067 million. Significant assumptions included in theoption valuation model are summarized as follows. Share price $2.65Dividend yield -Expected volatility 25.00%Risk-free interest rate 4.00%Expected life 1-2 years 13 Revenues Year ended 31 December: 2005 2004Crude oil Export sales 69,177 2,546 Domestic sales (Russian Federation) 13,433 3,774Petroleum (refined) products - domestic sales 9,904 1,643Other sales 404 221 Total gross revenues 92,918 8,184 14 Cost of Production Year ended 31 December: 2005 2004Depreciation and depletion 8,285 507Unified production tax 16,829 1,394Cost of purchased products 12,455 -Wages and salaries (including payroll taxes of $1.457 million and 7,341 647$0.230 million for the years ended 31 December 2005 and 2004, respectively)Materials 2,276 189Other 3,256 1,615 Total cost of production 50,442 4,352 15 Selling, General and Administrative Expenses Year ended 31 December: 2005 2004Wages and salaries 5,179 1,197Audit and professional consultancy fees 2,542 2,767Office rent and other expenses 1,522 759Other taxes 1,338 312Transport and storage services 998 102Loading services 845 -Loss on disposal of assets 254 14Other expenses 1,290 1,674 Total selling, general and administrative expenses 13,968 6,825 16 Mobilization Costs The Group's mineral licenses require that the Group perform certain exploration,evaluation and development activities as a condition of maintaining and/orrenewing the licenses. During 2005, the Group entered into an agreement withKCA Deutag to provide a specialized drilling rig for the purpose of obligatoryexploratory drilling on one of the Group's properties on Sakhalin Island. Aspart of the agreement, the Group was required to transport the rig approximately5,000 kilometres to reach Sakhalin Island. By disclosing the agreements tosecure and transport the rig, management was able to demonstrate to thelicensing authorities its commitment to fulfilling its obligations under thelicense. However, due to delays in transportation and seasonal weatherconcerns, the Group was forced to terminate its agreement and abort thetransport prior to the rig's arrival to Sakhalin Island, resulting inmobilization costs of $7.2 million being expensed during 2005. The Group was subsequently able to modify an existing rig to drill anexploratory well on the property in order to maintain compliance with thelicense terms. 17 Contingencies, Commitments and Operating Risks Operating environment of the Group. Whilst there have been improvements ineconomic trends in the country, the Russian Federation continues to displaycertain characteristics of an emerging market. These characteristics include,but are not limited to, the existence of a currency that is not freelyconvertible in most countries outside of the Russian Federation, restrictivecurrency controls, and relatively high inflation. The tax, currency and customslegislation within the Russian Federation is subject to varying interpretations,and changes, which can occur frequently. The future economic direction of the Russian Federation is largely dependentupon the effectiveness of economic, financial and monetary measures undertakenby the Government, together with tax, legal, regulatory, and politicaldevelopments. Sales and royalty commitments. In accordance with Petrosakh's license terms,Petrosakh is required to sell 20.0 percent of its annual oil production in theform of petroleum products to the Sakhalin Island region at market prices. In accordance with the sale purchase agreement to acquire Petrosakh, the Groupagreed to pay a perpetual royalty to the previous shareholders of $0.25 per tonof crude oil produced from the currently unproved off-shore licensed area. Exploration licenses - investment commitments. The Company's application for anextension of the Pogranichnoye License area offshore Sakhalin Island has beensuccessful. The Russian Federal Agency for Natural Resources granted thelicense extension in January 2006. The license period was extended to 1 February2011 and the terms of the amended license now require a total of fiveexploration wells to be drilled during the period 2005-2010. The East OkruzhnoyeNo. 1 well spudded in 2005 will qualify as the first of the five explorationwells required by the amended license. Management currently estimate suchexpenditure to approximate $19.0 million. Urals Nord has five geological studies licenses which expire in January 2008.According to the license agreement terms Urals Nord is required to drillexploration wells and perform seismic works. Management currently estimate suchexpenditure to approximate $36 million. Other capital commitments. At 31 December 2005 and 2004 the Group had no othersignificant contractual commitments for capital expenditures. Taxation. Russian tax, currency and customs legislation is subject to varyinginterpretations, and changes, which can occur frequently. Management'sinterpretation of such legislation as applied to the transactions and activityof the Group may be challenged by the relevant regional and federal authorities.Recent events within the Russian Federation suggest that the tax authorities maybe taking a more assertive position in their interpretation of the legislationand assessments, and it is possible that transactions and activities that havenot been challenged in the past may be challenged. As a result, significantadditional taxes, penalties and interest may be assessed. Fiscal periods remainopen to review by the authorities in respect of taxes for three calendar yearspreceding the year of review. Under certain circumstances reviews may coverlonger periods. As at 31 December 2005 and 2004 management believes that its interpretation ofthe relevant legislation is appropriate and the Group's tax, currency andcustoms positions will be sustained. Where management believes it is probablethat a position cannot be sustained, an appropriate amount has been accrued forin these financial statements. Insurance policies. At 31 December 2005, the Group held limited insurancepolicies in relation to its assets, operations, or in respect of publicliability or other insurable risks. Since the absence of insurance alone doesnot indicate an asset has been impaired or a liability incurred, no provisionhas been made in these financial statements. Restoration, rehabilitation and environmental costs. The Group companies haveoperated in the upstream and refining oil industry in the Russian Federation formany years and its activities have had an impact on the environment. Theenforcement of environmental regulations in the Russian Federation is evolvingand the enforcement posture of government authorities is continually beingreconsidered. The Group periodically evaluates its obligation related thereto.The outcome of environmental liabilities under proposed or future legislation,or as a result of stricter enforcement of existing legislation, cannotreasonably be estimated at present, but could be material. Under the currentlevels of enforcement of existing legislation, management believes there are nosignificant liabilities in addition to amounts which are already accrued andwhich would have a material adverse effect on the financial position of theGroup. Legal proceedings. During the year, the Group was involved in a number of courtproceedings (both as a plaintiff and a defendant) arising in the ordinary courseof business. In the opinion of management, there are no current legalproceedings or other claims outstanding, which could have a material effect onthe result of operations or financial position of the Group and which have notbeen accrued or disclosed in these consolidated financial statements. Oilfield licenses. The Group is subject to periodic reviews of its activitiesby governmental authorities with respect to the requirements of its oil filedlicenses. Management of the Group correspond with governmental authorities toagree on remedial actions, if necessary, to resolve any findings resulting fromthese reviews. Failure to comply with the terms of a license could result infines, penalties or license limitations, suspension or revocations. The Group'smanagement believes any issues of non-compliance will be resolved throughnegotiations or corrective actions without any materially adverse effect on thefinancial position or the operating results of the Group. 18 Financial Risks Foreign exchange risk. The Group has substantial amounts of foreign currencydenominated long-term borrowings and is thus exposed to foreign exchange risk.Foreign currency denominated assets and liabilities give rise to foreignexchange exposure. The Group does not have formal arrangements to mitigateforeign exchange risks. Interest rate risk. The Group's income and operating cash flows aresubstantially independent of changes in market interest rates. The Group obtainsfunds from, and deposits its cash surpluses with, banks at current marketinterest rates, and does not utilize hedging instruments to manage its exposureto changes in interest rates. The details of interest rates associated with theGroup's borrowings are discussed in Note 10. The carrying value of the Group'sreceivables, payables and borrowings approximate their fair values (Note 3). Credit risk. Financial assets, which potentially subject Group entities tocredit risk, consist principally of trade receivables. The Group has policiesin place to ensure that sales of products and services are made to customerswith an appropriate credit history. The carrying amount of accounts receivable,net of provision for impairment of receivables, represents the maximum amountexposed to credit risk. The Group has no other significant concentrations ofcredit risk. Although collection of receivables could be influenced by economicfactors, management believes that there is no significant risk of loss to theGroup beyond the provision already recorded. Cash is placed in financial institutions, which are considered at time ofdeposit to have minimal risk of default. Commodity and pricing risk. The Group's operations are significantly affectedby the prevailing price of crude oil both in the international oil market and inthe Russian Federation. Crude oil prices have historically been highlyvolatile, dependent upon the balance between supply and demand and particularlysensitive to OPEC production levels. Crude oil prices in the Russian Federationare below international levels primarily due to constraints on the export ofcrude oil. Also, domestic crude oil prices are contract specific as there is noactive market for domestic crude oil and marker prices are not available. Thereis typically no straight correlation between domestic and international oilprices. The Group's subsidiary - Petrosakh, operates on Sakhalin Island wherethe surrounding ocean is not navigateable for several months of the year, thisfurther increases the exposure to commodity price risk. 19 Related-Party Transactions For the purposes of these financial statements, parties are considered to berelated if one party has the ability to control the other party, is under commoncontrol, or can exercise significant influence over the other party in makingfinancial or operational decisions as defined by IAS 24 Related PartyDisclosures. In considering each possible related party relationship, attentionis directed to the substance of the relationship, not merely the legal form. Trading relationship with related parties. The Group has transactions in theordinary course of business with ZAO NC Urals, ZAO "Chepetskoye" NGDU (throughJuly 2004, when contributed by the Group shareholder to Urals Energy), Urals ARANV and Nafta (B) NV which all are controlled by major shareholders. Thesetransactions include sales and purchases of crude oil and petroleum products.Such sales ended beginning September 2005. Below are the annual sales,purchases and receivables balances for each year presented: As of or for the year ended 31 December: 2005 2004Sales of crude oil on export markets 5,515 2,212 Associated volumes, tons 17,580 9,000 Sales of petroleum products on domestic markets - 212 Associated volumes, tons - Purchases of crude oil - 1,178 Associated volumes, tons - 10,950 Commission revenue 24Interest income - -Interest expense 77 135Management fees received - 208Rental fees paid (included in selling, general and administrative expense) 306 264Other expenses 790 232 Accounts and notes receivable 1,474 -Loans receivable 1,251 723Other payables and accrued expenses 74 61Trade advances received 3 800 Lending relationships with related parties. See Note 10 for details of loansfrom shareholders and from companies controlled by shareholders. Guarantees issued to parties related to previous shareholders of subsidiaries.In September 2004, CNPSEI issued a $1.5 million guarantee to secure borrowingsof OOO Neftegazrazvitiye, a former shareholder. The loan bore interest of 14.0percent per annum. OOO Neftegazrazvitiye defaulted on its obligations andtherefore failed to repay the loan. CNPSEI, as the guarantor repaid a portionof the loan during 2004 and the remainder during 2005. The Group's obligationwas recognised at its fair value in the purchase price adjustment in theaccompanying financial statements. Accordingly, there was no impact on theGroup's statement of operations for the years ended 31 December 2005 and 2004. Compensation to senior management. The Group's senior management team comprises10 people whose compensation totalled $4.174 million and $1.917 million forthe periods ended 31 December 2005 and 2004, respectively, including salary andbonuses of $4.106 million and $1.917 million respectively, and stockcompensation of $0.042 million and nil, respectively, and no other compensationwas paid for both years. 20 Subsequent Events Subordinated loan. In January 2006, the Group obtained a $12.0 millionsubordinated loan from BNP Paribas. The subordinated loan bears interest atLIBOR plus 5.0 percent and is repayable over five years in one payment on 10November 2010. Attached to the subordinated loan were warrants to purchase upto two million of the Group's common stock for £3.03. The warrants areexercisable at any time and expire in November 2010. The Group used theproceeds from the subordinated loan to repay its debt to bank Zenit of $12.0million. Share-based payments. In February 2006, the Group's Board of Directors approveda Restricted Stock Plan (the "Plan") authorizing the Compensation Committee ofthe Board of Directors to issue restricted stock of up to five percent of theoutstanding shares of the Group. Upon adoption, the Group issued 1,561,725shares of restricted stock. The vesting schedule for the restricted stockvaries by individual award and, of the February 2006 grant, 1,040,445 shares,260,625 shares and 260,625 shares vest on 1 January 2007, 2008 and 2009,respectively. This information is provided by RNS The company news service from the London Stock Exchange
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