30 Apr 2007 07:04
Urals Energy Public Company Limited30 April 2007 Urals Energy Public Company Limited Results for the year ended 31 December 2006 Urals Energy ("Urals Energy", the "Company" or the "Group") (LSE: UEN) a leadingindependent exploration and production company with operations in Russia todayannounces its results for the year ended 31st December 2006 and the latestestimates published by DeGolyer and MacNaughton for its total proven, probableand possible petroleum reserves and value of these reserves as at 31 December2006. Reserves Upgrade • 2P reserves increase of over 400% to 577 mmboe (2005 116 mmbbls); incorporating acquisition of Dulisma and its oil (96 mmboe), condensate (46 mmboe) and gas (322 mmboe) reserves all now fully booked as proved and probable • 152% year on year increase in the PV10 of the Group's 2P reserves to $1,804 million (2005 $717 million) Financial Highlights • 83 % increase in total revenues to $169.6 million (2005 $92.9 million) • Operating profit of $34.1 million (2005 $11.3 million) • Five fold increase in post tax profit to $34.4 million (2005 $6.9 million) • 36% increase in EBITDA to $22.9 million (2005 $16.9 million) • Strengthened financial position following $209 million equity capital raising and $144 million Dulisma project loan and other financing Operational Highlights: • 82% year on year increase in average production to 9,569 bopd (2005: 5,263 bopd) • Production forecasted at 15,000 bopd by 4Q07 and 19,000 bopd by 2Q08 • Dulisma funding in place and development operations commenced with link-up to Transneft's ESPO expected in 2008-09. Dulisma production forecasted to peak at 30,000 bopd and 71,000 mcf sales gas per day in 2013; o Approvals in place to link pipeline to ESPO o Dulisma 2007 development programme underway and all equipment in place including 160 ton mobile drilling rig, gas-electric generator and field camp to spud first development well in July 2007 o Announcement of Dulisma gas strategy to exploit 1.9 tcf 2P reserve base o Commercial agreement to be signed to sell future gas production from Dulisma • Commencement of Mineral Extraction Tax holiday at Dulisma through 2016, saving an estimated $308 million over a 10 year period • Announcement of spudding of Nadezhdinsky No. 1 exploration well in northern Timan Pechora to test 60 million barrel target • 5 year extension of Pogranichnoye offshore exploration licence, Sakhalin Island • Fracture stimulation programme commenced and underway at Petrosakh, Sakhalin Island • Extension of development licence for deeper Permian horizon at Peschanoozersky Field, Arcticneft Corporate • Appointment of Leonid Y. Dyachenko as CEO, reflecting Urals Energy's increasing position and profile in Russia • William R. Thomas remains on the Board as a Non-Executive Director • J. Robert Maguire, most recently the head of the Global Energy Group at Morgan Stanley, to be appointed Non Executive Director • Alexei V. Ogarev, current Urals Energy VP Government Relations and former Deputy Head of Russian Presidential Administration, to be appointed Executive Director • Key Management team strengthened following appointments of o William S. Hayes, Senior Vice President and General Counsel o Maxim V. Bezriadin, Vice President and Business Unit Manager, East Siberia o Stephen D. Kirton, Vice President, Technical Services Acquisitions • Further 2 acquisitions in 2006 o $148 million acquisition of OOO Dulisma and OOO LTK o $1.5 million acquisition of OOO Nizhny Omrynskoye Neft Current Operations and Outlook • Average production for 1Q07 lower than anticipated at 8,900 bopd • Several technical factors impacting production addressed and current production capability of c.10,700 bopd • Ongoing fraccing program, new wells and return to production at Dulisma should allow production targets of 15,000 bopd in Q407 and 19,000 in Q208 to be achieved • Revised Company production target of 50,000 bopd by 2013 per new D&M report. • $93.4 million capex programme in 2007 • Continual appraisal of potential acquisition opportunities Leonid Y. Dyachenko, newly appointed Chief Executive, commented: "Urals Energy made substantial progress last year laying the foundations tobecome a significant producer in Russia over the next five years. With anintense development programme underway and a continued focus on acquisitions Ibelieve we have all the fundamentals in place to achieve strong future growthand become a major Russian independent operator. The Board would like to thankBill Thomas for his significant contributions to the Company's success. As CEO,he has led Urals Energy since our formation in 2003 and was instrumental inpositioning the Company for the next stage of growth and value creation. I amdelighted that Bill will remain with Urals Energy as a Non-Executive Directorgoing forward." 30 April 2007 Pelham PRJames Henderson 020 7743 6673Gavin Davis 020 7743 6677 CEO'S STATEMENT 2006 was an important year of growth for Urals Energy as we completed ourlargest and most important acquisition, OOO Dulisma, and continued toconsolidate and invest in our seven other operating subsidiaries in Russia. TheCompany grew significantly in all respects: reserves, production, cash flow andprofits. As a result, we are well positioned to continue our strategy of growthby both developing our existing assets and making further significant, accretiveacquisitions. Operationally, we invested over $60 million in our properties, almost half indevelopment drilling. This was important in increasing production to an averageof 9,569 BOPD versus 5,263 BOPD in 2005 -- an increase of 82%. Importantly, wehave also purchased and transported to the field site at Dulisminskoye allnecessary equipment to begin drilling operations, including our 160 ton mobiledrilling rig. This provides us the capability to begin development operationsand prepare the field for full-scale production operations as the East SiberianPacific Ocean ("ESPO") pipeline nears completion of its first phase ofconstruction. Since the acquisition of Dulisma in June 2007, we have worked to finalize a newfield development plan for the Dulisminskoye field. With our new drilling rigin place, we expect to spud our first development well in July and drill andcomplete a total of three development wells by the 2nd quarter of 2008.Successful completion of these wells is necessary to achieve our production ratetargets. Production timing is contingent on the pace of development drilling,and the completion of the East Siberia Pacific Ocean pipeline (ESPO) and ourlink-up with this important new export pipeline. Based on the latestinformation regarding the progress of the ESPO's development, our stated goal ofa 2007 year-end production rate of 19,000 BOPD will now shift to the 2nd quarterof 2008. We are announcing today an important increase in our proved and probablereserves as evaluated by DeGolyer & MacNaughton, our independent reserveengineers. Based on our work to monetize the large gas and condensate reservesat Dulisminskoye, we are now upgrading the gas and condensate at Dulisminskoyeto proved and probable from possible. This is a result of our activenegotiations to finalize a long-term gas sales agreement, which we expect tocomplete in the next few months. Year on year and on a barrel of oil equivalentbasis, 2P reserves have increased from 116 million barrels to 577 millionbarrels. Please note that the D&M estimates for both oil and gas atDulisminskoye, and indeed for all of our properties, are less than the Russianstate reserves reported by the Ministry of Natural Resources. Most importantly, the present value of our reserves has also increasedsignificantly. As a result of the now confirmed production tax holiday atDulisma and the incremental value attributable to the development of our gas andcondensate reserves, the Company's 2P reserves now carry a total present valuediscounted at 10% equal to $1.8 billion. We believe this is strong indicationof the underlying asset value of our oil and gas reserves. Financial Results The Group benefited during the year from its increasing production profilegenerating an 83% increase in total revenues to $169.6 million (2005: $92.9million). This contributed to a three-fold increase in operating profits of$34.1 million (2005: $11.3 million) and a five fold rise in post-tax profits of$34.4 million (2005: $6.9 million). EBITDA increased by 36% to $22.9 million.The Group realised a weighted average dollar price of $48.39 per barrel of oilsold in 2006 compared with $44.35 per barrel in 2005. The average net revenuesper barrel for the Group increased slightly for the year at $34.40 compared to$31.57 in 2005. During the course of the year the Group raised a net total of $195 million innew equity through Morgan Stanley. These funds enabled us to complete theacquisition of Dulisma and commence the development work. In January of thisyear we raised a further $130 million through Goldman Sachs under a new debtfinance facility. This financing will give us the required funding to developDulisminskoye's oil reserves, thereby increasing production from that field toits projected peak level of 30,000 bopd by 2011. We also raised an additional$14 million in other debt from BNP Paribas. The Group's cash position at the year end was $33 million. Following the Dulismaproject financing in January, the Group's current cash balance stands atapproximately $80 million. During 2007 our capital expenditure programme is expected to be approximately$93 million. Approximately $42 million will be dedicated to the Dulismadevelopment programme (funded through the Goldman Sachs debt finance facilityreferred to above) and $51 million will be invested in increasing production inour other producing fields. Corporate We have today announced the appointment of Leonid Y. Dyachenko as ChiefExecutive. Mr Dyachenko has been a director of Urals Energy since the Companywas founded and for the last two years has managed the Group's day-to-dayactivities within Russia based in our Moscow office. Over the next few yearsUrals Energy will become an important independent oil and gas producer withinRussia, producing an estimated 50,000 bopd and over 71,000 mcf sales gas per dayby 2013. Leonid Dyachenko's appointment reflects Urals Energy's development intoa prominent Russian oil and gas business. I will continue my involvement with Urals Energy as a non-executive member ofthe board of directors. My resignation is effective immediately but I haveagreed to assist in the transition of management responsibilities through 30June 2007. The Group is also announcing today the appointment of two additional directors:J. Robert Maguire and Alexei V. Ogarev. Bob Maguire is one of the mostexperienced international oil and gas investment banking advisers within theindustry, with over 30 years experience, most recently as head of the GlobalEnergy Group at Morgan Stanley. His expertise will prove invaluable to theCompany through its next stage development. Alex Ogarev is Urals Energy's VP of Government Relations and has an importantrecord of Russian government service including Deputy Head of the PresidentialAdministration, and General Director of Rosvooruzhenie, the Russian arms exportagency. He plays an important role in managing our government relations and willprovide the board a valuable insight to the Russian government and politicalenvironment. We also recently strengthened the management team with the appointments ofWilliam S. Hayes as Senior Vice President and General Counsel and Maxim V.Bezriadin as Vice President and Business Unit Manager, East Siberia, togetherwith Stephen D. Kirton as Vice President, Technical Services. Following theseappointments we are confident we have the right level of management support inplace for the future. Operations Production Update We ended the year at a producing rate of approximately 11,600 bopd. Since thenwe have seen a temporary production decline due to several factors, includingshutting-in wells for the Petrosakh frac program, shut-in production at Dulismadue to pipeline repairs by the pipeline owner, and a decline in reservoirpressure at Dinyu and Petrosakh. As a result, actual production for the firstquarter averaged approximately 8,900 BOPD. However, we have taken steps torestore production and, including the temporarily shut-in production at Dulisma,we now have the capability to produce approximately 10,700 BOPD. During the year, we acquired and refurbished a fleet of fracture stimulationequipment, including three pumping units. Operations commenced at Petrosakh inJanuary 2007 and we are confident of significantly increasing production throughfracture stimulation at Petrosakh and other selected producing subsidiaries. As we bring new wells online and the fraccing program continues, we expect ourproduction level to increase to approximately 15,000 BOPD in the fourth quarterof 2007. Dulisma Following completion of the Dulisma acquisition in June 2006, the Group has beenactively executing its development programme targeting peak production of 30,000bopd by 2011. Progress is being made on all fronts, with all Governmentapprovals for the field development program received. The Group has alsoreceived approval from Transneft to accept oil produced at Dulisma for its ESPOpipeline, thus providing the Dulisma field future permanent export pipelineaccess for its crude oil production. The re-routing of the ESPO to within 75 kmof the Dulisma field, reduced initial cost estimates for construction of thepipeline from the field to the ESPO tie-in by approximately $70 million, andbrings forward our production profile. In January this year we announced that the Irkutsk Tax Inspectorate hadconfirmed the 10 year tax holiday for the Dulisminskoye field for the periodbetween 1 January 2007 and 31 December 2016. This tax holiday is estimated toproduce savings of approximately $308 million over the 10 year period andfurther exemplifies the importance of this asset to Urals Energy. Development activity at Dulisminskoye is moving forward in accordance with ourplans announced last year. The new 160 tonne mobile drilling rig and allassociated equipment are at the field site and rigging-up operations areunderway. The first development well will be spudded in July, with a two furtherdevelopment wells scheduled for the fourth quarter of 2007 and first quarter of2008. Road and pad construction is continuing in the field and we are working tocommission two gas-turbine generators to provide power for drilling andproduction operations. A new 100-man field camp will be installed during thewinter of 2007. Construction of a central processing facility (CPF) and theconnecting pipeline to Kirensk will begin later this year in time for thedelivery of pipeline quality oil when the ESPO is commissioned in 2008-9. Our 2007 CAPEX budget for Dulisma will be approximately $42 million of which $16million is for development drilling and $26 million for pipelines,infrastructure and facilities. We are preparing a gas monetization plan that includes burning associated gas togenerate in-field electricity, stripping liquids to create a separate salesstream of condensate and natural gas liquids, reinjecting certain gas volumes tomaintain reservoir pressure and entering into a long term gas sales agreementwith a large gas end-user. We expect to announce the terms of this agreementover the next few months and provide further details about the gas monetizationplan. Sakhalin Island Production during the year averaged 3,159 bopd compared with 2,524 bopd in 2005.During the year we drilled two development wells and three re-entry wells. Ourfirst offshore exploration well; the Pogranichny No. 1 well, was drilled at thebeginning of 2006 to a depth of approximately 2,100 meters but failed toencounter commercial volumes of oil or gas. This well has been followed up withan intense 3D seismic reprocessing and reinterpretation programme. Offshoredrilling is expected to resume in the summer of 2008. In January 2006 we agreed a five year extension to our offshore explorationlicence in Sakhalin Island with the Ministry of Natural Resources. This willallow us to fully exploit the licence area which has a potential of over 850million barrels in place. In March, we received approval to lift Petrosakhcrude oil using foreign-flagged vessels through 2009. We believe this is a firstfor any oil-exporting company on Sakhalin Island and will enable us to moreefficiently schedule tankers to lift our export cargoes. Fraccing operations commenced at Petrosakh in January 2007 and the first fourwells have been completed. A total of eight wells are planned to be fracturestimulated. Based on the preliminary results of the first four wells, we haveincreased individual well rates by 3-4 times the production rate prior tofraccing. There is no assurance this level of increase will be achieved in everywell, but we are confident of significantly increasing production throughfracture stimulation at Petrosakh and certain of our other producingsubsidiaries. During 2007 six development wells are planned. The results of our most recentwell, PS47, indicate a possible new pool discovery that may open up severaldrilling locations. We are also now commissioning three new oil products storagetanks and constructing two new 10,000 ton crude oil storage tanks for oilexports. Komi Republic During the year production at Komi averaged 3,937 bopd compared with 3,349 bopd2005. In 2006 the Group drilled 8 development and 2 exploration wells in Dinyu.In particular the DN-48 exploration well drilled in third quarter of 2006, totest an extension of the Dinyu field to the Southeast, encountered a previouslyunidentified reef structure with over 60 meters of permeable limestonereservoir. After extensive testing, the well produced only small quantities oflive oil, but has consequently opened up a new potential play within the Dinyulicense area. We are working to identify additional prospects to prove thishypothesis. In the first quarter of 2006 we completed the acquisition of approximately 300kilometres of new 2D seismic over the Dinyu field and continue to identify newdrilling locations with this new data. The potential includes the new reef trendwe encountered while drilling DN-48, and a newly identified eastern lobe thathas excellent potential. In October 2006 we also acquired Nizhny Omrinskoye Neft for $1.5 million in cashfrom Lukoil. This principal licence is a mature producing field that isestimated to have 25 million barrels of C1-C2 reserves. We have reactivated 3wells on this field and have commissioned DeGolyer and MacNaughton tore-evaluate reserves on this licence area. Three to five development wells will be drilled in 2007 at Dinyu with apossibility of an additional exploration well subject to seismic data review. Inthe second half of 2007, we expect to initiate a Komi-wide fraccing programme,as well as continue to workover wells at Nizhny Omrinskoye. Timan Pechora The average production on the Timan Pechora licence areas during 2006 was 1,001bopd compared to 1,078 bopd 2005. In 2006 the Group re-completed five wells anddrilled two development wells at Arcticneft. By mid-year, we expect to initiatedrilling of an important sidetrack to test the deep Permian horizon for which alicense extension was granted by the Ministry of Natural Resources in 2006. At Urals Nord, our first exploration well on the Nadezhdinsky prospect wasspudded in on 18 April 2007 and is expected to reach a target depth of 3,700meters in June of 2007. The prospect is an Upper Devonian reef that may containupwards of 60 million barrels of recoverable reserves. The well is locatedapproximately 60 kilometers southwest of the port of Varendey on the northerncoastline of Russia. Udmurtia Average production at Chepetskoye NGDU in 2006 was 940 bopd compared to 914 bopdin 2005. As part of our 2006 programme we drilled six development wells on thePotapovskoye field and have received pilot production project approval. Inaddition, ZT118 well on Zotovskoye was recompleted and we began a pilot waterinjection scheme. In 2007 we plan to drill five development wells at thePotapovskoye field. Outlook The Company is well positioned to continue its growth as a leading Russianindependent E&P company. I am personally very proud of having played a key rolein the development of Urals Energy - which is in many ways a success because ofits partnership of Russian and western shareholders. With Alex Dyachenkoassuming the role of Chief Executive, the Company will be led by a capableRussian manager, executing a focused Russian strategy. I look forward tocontinuing our partnership as a member of the board of directors. William R. ThomasChief Executive Officer30 April 2007 Financial Results Operating Environment 2006 was characterized by fluctuating world oil prices and the Company's focuson investment in development drilling. Brent oil prices began the year at$61.67 per barrel, reached a peak of $78.69 in August a low of $55.96 in Octoberand ended the year at $56.63 per barrel. The Russian oil industry broadlytracked these movements. Industry average domestic oil prices began 2006 at$59.53 per barrel and averaged approximately $57.72 per barrel for the year.Profit margins were strong in the first half of the year, when the industryrealized the best domestic netbacks ever. However, in the fourth quarter, due torapidly falling export prices combined with the 60-day lag in the reduction ofexport duties, the entire Russian oil industry suffered from a profitabilitysqueeze. The Rouble continued to appreciate against the Dollar, rising 4% in the year,which combined with continued increases in costs for critical items such assteel and labor, translated in higher operating costs. Production and Revenues Crude oil production during the year increased by 13% from 3.0 million barrelsin 2005 to 3.4 million barrels in 2006, with average daily production increasingfrom 5,320 barrels per day in 2005 to 9,200 in 2006. The majority of thisincrease was due to organic development, with only 566 bopd coming from newproperties acquired during the year. During the period the Company's gross revenues totalled $169.6 million versus$92.9 million in 2005. The Group realized a weighted average gross price of$48.39 per barrel of oil sold in 2006 versus $44.35 in 2005. Export salesprices for the Group averaged $61.20 per barrel, and domestic sales pricesaveraged $27.75 per barrel. Domestic refined product prices averaged $50.52 perbarrel. Net revenues increased to $119.2 million from $66.1 million in the prior year.While the weighted average gross price realized per barrel was $3.52 higher thenin 2005, the percentage per barrel paid to the government in the form ofproduction taxes and export duties in 2006 was 50.18% versus 46.94% in 2005. Asa result, the average net revenues per barrel were only modestly higher, $32.81for 2006 versus $30.22 for 2005. Netback prices are defined as, in the case ofexports, gross oil sales price less export duty, customs charges, marketingcosts and transportation; and, in the case of domestic crude sales, gross salesprice net of VAT. The weighted average netback for crude oil sales during 2006was $29.26 versus $29.01 per barrel in 2005. In 2006, netbacks for export saleswere $29.63 per barrel and $28.71 per barrel for domestic sales. Netback pricesfor domestic product sales are defined as gross product sales price minus VAT,transportation, excise tax and refining costs. The average products netback forthe year was $47.64 per barrel. Net revenues minus the cost of production was $25.8 million as compared to $14.1million in 2005, resulting in an operating profit of $34.1 million versus $11.3million in the prior year. Production costs totalled $92.1 million of which$19.8 million represents non-cash items, principally DD&A. Also imbedded inthese costs are $9.3 million of crude purchased from our neighbouring operatoron Kolguyev Island, GUP AMNGR. Urals Energy purchased this oil from AMNGR andresold it together with its own produced oil for a modest profit margin, but alesser profit margin then it would have had Urals Energy produced the oilitself. SG&A costs were $28.9 million. The largest component in SG&A was wages andsalaries which increased year-on-year due to additional personnel fromacquisitions and increased operations. SG&A also includes a number of non-cashexpense items, primarily related to the Company's stock incentive plan,totalling $5.1 million. Interest expense for the period was $9.8 million as compared to $6.9 million in2005, as the Company's average debt outstanding for the period was greater thanin 2005. Net profit for the year attributable to shareholders was $34.3 million ascompared to $7.1 million in 2005. The largest non-cash item affecting thisresult is an extraordinary gain through a negative goodwill charge of $35.9million related to our acquisition of Dulisma. This reflects the excess in fairmarket value of the assets purchased above the price paid. The method forcalculating the fair market value is a conservative discounted cash flowvaluation based on factors known at the time (not including currently knownvalue attributes such as the unified production tax holiday and the commercialsales value of the natural gas). Adjusting for non-recurring costs and other standard non-cash items, theCompany's management-adjusted EBITDA for the period was $22.9 million, or 19% ofnet revenues. During Q406 the financial performance of the Group was affected by a squeezebetween lower prices and high export duties at Petrosakh and Arcticneft. Russianexport duties are regressive and are set according to a fixed formula andincrease as export prices increase, however this adjustment is subject to a60-day time lag. The sharp spike in prices in July and August followed by asteep decline in September and October resulted in high export duties versus lowexport prices at the critical time when, in early December, the Company had tomake its last shipments to clear inventory before the winter sea ice-in atPetrosakh and Arcticneft prevents navigation. The Company estimates that as aresult of this significant price change and the export tax lag, the negativeimpact on EBITDA was approximately $7.3 million. Wide short-term fluctuationssuch as those seen in 2006 represent a risk for the Company, as a large portionof its operating profits are derived from two critical time windows, earlyDecember and late June, when the seas are navigable due to the ice-melt, it mustmake large shipments from these operations regardless of the market conditions 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 total gross revenuesduring 2006 were export duties (28%) and the unified production tax (21%). TheCompany paid a total of $103.3 million in cash taxes for the year. Unifiedproduction taxes are calculated based on production revenues and in 2006 theGroup paid $33.9 million. Looking forward, the proportion of mineral extractiontaxes paid overall by the Company will decline dramatically as production fromDulisma increases, where a holiday for this tax has been granted through 2016.Export duties are set according to a fixed schedule that increases as exportprices rise with a maximum rate of 65% of gross export prices above $25 perbarrel. High export prices in 2006 resulted in an average export duty for theCompany of 41% of gross export revenues, and $48.2 million of cash paid. Asmentioned above, this tax can be particularly punitive in rapidly decliningcrude price scenarios, as happened in the fall of 2006. VAT payments totalled$3.6 million. At 31 December 2006, the Group's deferred tax liability was $111.8 million. Thisis a non-cash liability derived under IFRS methodology by accruing thedifference of the fair market value of the Company's producing reserves versusthe amount actually paid to acquire them. The Company expects this deferred taxliability to be reflected on its balance sheet indefinitely, and to grow furtherin the event that Urals Energy continues to make acquisitions at low entryprices. Cash Flow For the period, operating cash flow before working capital changes was $22.9million. Net cash generated from operating activities improved considerably overthe year, $35.3 million for 2006 versus a loss of $32.2 in 2005. Capitalexpenditures for development in 2006 were $59.5 million of which approximately58% was direct drilling expense. The bulk of the remaining capital expenditureswas for advanced infrastructure investment at Dulisma, where a total of $16.4million was spent. The cost of acquisitions (net cash on hand) during 2006 was$137.3 million, resulting in a total use of cash for investments andacquisitions of $198.6 million. During the course of the year, a net total of $195.1 million in new funds fromthe sale of equity was raised. At 31 December 2005, the Group's short- andlong-term debt was $81.1 million. During 2006, a total of $14.0 million in newdebt was borrowed and $29.9 million in debt principle repaid. As a result, as of31 December 2006, total outstanding debt was $63.8 million. Cash Position The deficit of $163.3 million resulting from the difference of cash generatedthrough operations and cash expenditures for investments in assets andacquisitions was funded by the addition of $164.0 million in cash from netborrowings, the sale of equity and exchange rate changes. This resulted in achange to the cash position of $0.7 million by year end. Hedging The Company does not hedge any of its crude oil or product sales, costs orcurrency conversions. Financing In May of 2006 the Company raised net proceeds of $195.1 million through thesale of $209.0 million worth of equity. The equity was sold to the public at aprice of £3.60 per common share. In January of 2006 the Company refinanced the $12 million loan outstanding toBank Zenith with a subordinated 5-year loan from BNP Paribas in the same amount.The loan is non-amortizing, priced at LIBOR plus 5.00% and had warrants attachedto it, giving the bank the right to purchase up to 2 million shares of commonstock at £3.03 per share. In November, the Company also secured a revolving $2million working capital debt facility from ZAO BNP Paribas. In January of 2007 the Company borrowed $130 million from Goldman Sachs andStandard Bank. The loan is secured against Dulisma as project financing for itsdevelopment, and has limited, subordinated recourse to Urals Energy PublicCompany Limited. It is a four year, non-amortizing loan, priced at LIBOR plus3.25% with an additional 4.00% PIK. It is callable after two years, and theCompany has purchased interest rate swaps for the cash interest over thisperiod. 31 December Note 2006 2005 AssetsCurrent assetsCash and cash equivalents 33,082 32,334Accounts receivable and prepayments 5 24,717 21,465Current income tax prepayments 4,401 1,174Inventories 6 26,679 12,641Total current assets 88,879 67,614 Non-current assetsProperty, plant and equipment 7 595,800 287,485Other non-current assets 8 16,073 3,247Total non-current assets 611,873 290,732 Total assets 700,752 358,346 Liabilities and equityCurrent liabilitiesAccounts payable and accrued expenses 9 10,033 7,932Income tax payable 3,281 6,039Other taxes payable 10 7,253 3,461Other taxes provision 2,367 1,987Short-term borrowings and current 11 22,965 34,117 portion of long-term borrowingsAdvances from customers 9 30,913 523Current liabilities before warrants classified as liabilities 76,812 54,059Warrants classified as liabilities 11 3,516 -Total current liabilities 80,328 54,059 Long-term liabilitiesLong-term borrowings 11 40,844 47,005Long term finance lease obligations 1,192 1,357Dismantlement provision 12 3,327 813Deferred tax liability 10 111,787 51,100Other long term liabilities 298 580Total long-term liabilities 157,448 100,855 Total liabilities 237,776 154,914 EquityShare capital 13 633 460Share premium 13 401,448 201,355Translation difference 22,445 (2,296)Retained earnings 37,022 2,714Equity attributable to shareholders 461,548 202,233of Urals Energy Public Company LimitedMinority interest 1,428 1,199Total equity 462,976 203,432 Total liabilities and equity 700,752 358,346 MEMORANDUM NOTE:Total equity 462,976 203,432Warrants classified as liabilities 11 3,516 - 466,492 203,432 Approved on behalf of the Board of Directors on 27 April 2007 ____________________________ ___________________________ W.R. Thomas S. M. Buscher Chief Executive Officer Chief Financial Officer Year ended 31 December Note 2006 2005 RevenuesGross revenues 14 169,590 92,918Less: excise taxes (2,176) (530)Less: export duties (48,217) (26,253) Net revenues 119,197 66,135 Operating costsCost of production 15 (92,071) (52,034)Selling, general and administrative expenses 16 (28,955) (12,376)Non-recurring mobilization costs 17 - (7,170)Excess of net assets acquired over purchase price 4 35,895 16,793 Total operating costs (85,131) (54,787) Operating profit 34,066 11,348 Interest income 11 1,359 913Interest expense 11 (9,810) (6,911)Foreign currency gains (losses) 7,491 (185)Other non-operating (losses) (202) (669)Change in fair value of warrants classified as liabilities 11 (1,766) - 31,138 4,496 Profit before income taxIncome tax benefit 10 3,284 2,477 Profit for the year 34,422 6,973 Profit for the year attributable to: - Minority interest 114 (82)- Shareholders of Urals Energy Public Company Limited 34,308 7,055 Earnings per share of profit attributable toshareholders of Urals Energy Public Company Limited:- Basic earnings per share (in US dollar per share) 0.3264 0.1178- Diluted earnings per share (in US dollar per share) 0.3175 0.1177 Weighted average shares outstanding- Basic earnings per share 105,099,777 59,915,473- Diluted earnings per share 108,051,649 59,939,038 Year ended 31 December 2006 2005 Cash flows from operating activitiesProfit before income tax 31,138 4,496Adjustments for: Depreciation and depletion 19,335 8,285 Change in fair value of warrants classified as liabilities 1,766 - Share-based payments 5,089 42 Interest income (1,359) (913) Interest expense 9,810 6,911 Loss on disposal of assets 439 254 Excess of net assets acquired over purchase price (35,895) (16,793) Foreign currency (gains) losses (7,491) 185 Other non-cash transactions 56 (1) Operating cash flows before changes in working capital 22,888 2,466 (Increase) decrease in inventories (10,622) 4,343(Increase) in accounts receivables and prepayments (1,257) (11,810)(Decrease) in accounts payable and accrued expenses (116) (22,349)Increase in advances from customers 9 30,390 523Increase (decrease) in other taxes payable 5,622 (785) Cash generated from (used in) operations 46,905 (27,612)Interest received 1,190 913Interest paid (8,900) (2,685)Income tax paid (3,890) (2,862) 35,305 (32,246) Net cash generated from (used in) operating activities Cash flows from investing activitiesAcquisitions of subsidiaries, net of cash acquired 4 (137,299) (106,500)Purchase of property, plant and equipment (59,538) (18,087)Purchase of intangible assets (1,772) - Net cash used in investing activities (198,609) (124,587) Cash flows from financing activitiesProceeds from borrowings 14,000 101,412Repayment of borrowings (29,946) (56,313)Finance lease principle payments (419) (404)Repayment of promissory notes 4 (15,088) -Cash proceeds from exercise of options 13 125 -Cash proceeds from issuance of ordinary shares 13 195,052 143,100Net cash generated from financing activities 163,724 187,795Effect of exchange rate changeson cash and cash equivalents 328 (49) Net increase in cash and cash equivalents 748 30,913Cash and cash equivalentsat the beginning of the year 32,334 1,421 Cash and cash equivalentsat the end of the year 33,082 32,334 Notes Share Share Unpaid Retained Equity Minority Total capital premium capital earnings attributable to interest equity (accumulated Shareholders of deficit) Urals Energy Cumulative Public Company Translation Limited Adjustment Balance at 1 January 209 42,172 (11,324) 1,264 (4,341) 27,980 1,327 29,3072005 Effect of currency (3,560) - (3,560) (46) (3,606)translationProfit for the year - 7,055 7,055 (82) 6,973 Total recognized (3,560) 7,055 3,495 (128) 3,367income (loss) Issuance of shares 13 251 159,141 11,324 - - 170,716 - 170,716Share-based payment 13 - 42 - - - 42 - 42 Balance at 31 December 460 201,355 - (2,296) 2,714 202,233 1,199 203,4322005 Effect of currency 24,741 - 24,741 115 24,856translationProfit for the year - 34,308 34,308 114 34,422 Total recognized 24,741 34,308 59,049 229 59,278income (loss) Issuance of shares 13 173 194,879 - - - 195,052 - 195,052Exercise of options 13 - 125 - - - 125 - 125Share-based payment 13 - 5,089 - - - 5,089 - 5,089 Balance at 31 December 633 401,448 - 22,445 37,022 461,548 1,428 462,9762006 1 Activities Urals Energy Public Company Limited ("Urals Energy" or the "Company" or "UEPCL")was incorporated as a limited liability company in Cyprus on 10 November 2003.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. The Group's primary office is located at 11 OsennayaUl. Moscow, 121609, Russian Federation. The Group comprises the following subsidiaries: Entity Jurisdiction Effective ownership interest at 31 December 2006 2005Exploration and productionZAO Petrosakh ("Petrosakh") Sakhalin 97.2% 97.2%ZAO Arcticneft ("Arcticneft") Nenetsky 100.0% 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% 100.0%OOO Michayuneft ("Michayuneft") Komi 100.0% 100.0%OOO Oil Company Dulisma ("Dulisma") Irkutsk 100.0% -OOO Lenskaya Transportnaya Kompaniya ("LTK") Irkutsk 100.0% -OOO Nizhneomrinskaya Neft Komi 100.0% - Management companyOOO Urals Energy Moscow 100.0% 100.0%Urals Energy (UK) Limited United Kingdom 100.0% 100.0% ExplorationOOO Urals-Nord ("Urals-Nord") Nenetsky 100.0% 100.0% TradingUENEXCO Limited ("UENEXCO") Cyprus 100.0% 100.0% UENEXCO Limited only operated during the first quarter of 2006 after which alltrading operations were transferred to UEPCL. 2 Summary of Significant Accounting 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 as modified by change in fair value of warrantsclassified as liabilities. 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. These policies have beenconsistently applied to all the periods presented, unless otherwise stated.Critical accounting estimates and judgments are disclosed in Note 3. Actualresults could differ from the estimates. These consolidated financial statements also include all disclosures necessaryfor compliance with the relevant sections of the Cyprus Companies Law Cap 133. Functional and presentation currency. The United States Dollar ("US dollar orUS$ or $") is the presentation currency for the Group's operations as themajority of the Company's operations is conducted in US dollars and managementhave used the US dollar accounts to manage the Group's financial risks andexposures, and to measure its performance. Financial statements of the Russiansubsidiaries are measured in Russian Roubles and presented in US dollars inaccordance with IAS 21 (revised 2003), The Effects of Changes in ForeignExchange 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 26.33 and 28.78 as of 31 December2006 and 2005, respectively. Translation to presentation currency. The results and financial position of eachgroup entity (the 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 a manner similar to the successful efforts method. Costs of successfuldevelopment and exploratory wells are capitalised. The Group accounts for exploration and evaluation activities in accordance withIFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizingexploration and evaluation costs until such time as the economic viability ofproducing the underlying resources is determined. Exploration and evaluationcosts related to resources determined to be not economically viable are expensedthrough cost of production in the consolidated income statement. Otherexploration costs are expensed as incurred. Depletion of capitalized costs of proved oil and gas properties is calculatedusing the unit-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 Intangible assets. All of the Group's other intangible assets have definiteuseful lives and primarily include capitalised computer software and licences. Acquired computer software licenses and patents are capitalised on the basis ofthe costs incurred to acquire and bring them to use. Development costs that are directly associated with identifiable and uniquesoftware controlled by the Group are recorded as intangible assets if inflow ofincremental economic benefits exceeding costs is probable. Capitalised costsinclude staff costs of the software development team and an appropriate portionof relevant overheads. All other costs associated with computer software, eg itsmaintenance, are expensed when incurred. Intangible assets are amortised using the straight-line method over their usefullives: Estimated useful lifeSoftware licences 3Capitalised internal software development costs 3Other licences 5 to 7 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 theincome statement. 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.Interest costs on borrowings to finance the construction of property, plantand equipment are capitalised, during the period of time that is required tocomplete and prepare the asset for its intended use. Borrowing costs arerecognised as an expense on a time proportion basis using the effective interestmethod. Loans receivable. The loans advanced by the Group are classified as "loans andreceivables" in accordance with IAS 39 and stated at amortised cost using theeffective 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 income statement before they become deductible for taxpurposes. 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 income statement. 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. Warrants. Warrants issued that allow the holder to purchase shares of theGroup's stock are recorded at fair value at issuance and recorded as liabilitiesunless the number of equity instruments to be issued to settle the warrants andthe exercise price are fixed in the issuing entities' functional currency at thetime of grant, in which case they are recorded within shareholders' equity.Changes in the fair value of warrants recorded as liabilities are recorded inthe income statement. Share capital. Ordinary shares are classified as equity. Incremental costsdirectly attributable to the issue of new shares are shown in equity as adeduction, net of tax, from the proceeds. Any excess of the fair value ofconsideration received over the par value of shares issued is presented in thenotes as a share premium. Share-based payments. The fair value of equity instruments granted is evaluatedat the measurement date, based on market prices if available, taking intoaccount the terms and conditions upon which those equity instruments weregranted. If market prices are not available, the fair value of the equityinstruments granted is estimated using a valuation technique to estimate whatthe price of those equity instruments would have been on the measurement date inan arm's length transaction between knowledgeable, willing parties. Earnings per share. Earnings per share is determined by dividing the profit orloss attributable to equity holders of the Group by the weighted average numberof participating shares outstanding during the reporting year. Adoption of new or revised standards and interpretations. New or amendedstandards and interpretations adopted by the Group from 1 January 2006 arediscussed below. None of the adoptions had a material impact on the Group's financial position orresults of operations. IAS 39 (Amendment), The Fair Value Option; IAS 39 (Amendment), Cash Flow HedgeAccounting of Forecast Intragroup Transactions; IAS 39 (Amendment), FinancialGuarantee Contracts. The amendments to IAS 39 clarified the use of the fairvalue through profit or loss category of financial instruments and clarified theaccounting for financial guarantees as either insurance contracts or financialinstruments. IAS 21 (Amendment), Net Investment in a Foreign Operation. This amendmentrequires foreign exchange gains and losses on monetary items that form part ofnet investment in a foreign operation to be reported in consolidated equity evenif the loans are not in the functional currency of either the lender or theborrower. Previously, such exchange differences were required to be recognisedin consolidated profit or loss. IAS 19 (Amendment), Employee Benefits. The amendment to IAS 19 introduces anadditional recognition option for actuarial gains and losses in post-employmentdefined benefit plans. IFRS 1 (Amendment), First-time Adoption of International Financial ReportingStandards and IFRS 6 (Amendment), Exploration for and Evaluation of MineralResources. The amendments to IFRS 1 and IFRS 6 provided limited relief tofirst-time adopters of IFRS with respect to the provisions of IFRS 6. IFRIC 4, Determining whether an Arrangement contains a Lease ("IFRIC 4"). IFRIC4 provides guidance on how to determine whether an arrangement contains a leaseas defined in IAS 17, Leases, on when the assessment or reassessment of anarrangement should be made and on how lease payments should be separated fromany other elements in the arrangement. IFRIC 5, Rights to Interests arising from Decommissioning, Restoration andEnvironmental Rehabilitation Funds ("IFRIC 5"). IFRIC 5 provides guidance on theaccounting for interests in decommissioning funds. IFRIC 6, Liabilities arising from Participating in a Specific Market - WasteElectrical and Electronic Equipment ("IFRIC 6"). IFRIC 6 addresses theaccounting for liabilities under an EU Directive on waste management for salesof household equipment. New accounting pronouncements. Certain new standards and interpretations havebeen published that are mandatory for the Group's accounting periods beginningon or after 1 January 2007 or later periods and which the entity has not earlyadopted: IFRS 7, Financial Instruments: Disclosures and a complementary Amendment to IAS1 Presentation of Financial Statements - Capital Disclosures (effective from 1January 2007). The IFRS introduces new disclosures to improve the informationabout financial instruments. The volume of disclosures will increasesignificantly with an emphasis on quantitative aspects of risk exposures and themethods of risk management. The quantitative disclosures will provideinformation about the extent to which the entity is exposed to risk, based oninformation provided internally to the entity's key management personnel.Qualitative and quantitative disclosures will cover exposure to credit risk,liquidity risk and market risk including sensitivity analysis to market risk.IFRS 7 replaces IAS 30, Disclosures in the Financial Statements of Banks andSimilar Financial Institutions, and some of the requirements in IAS 32,Financial Instruments: Disclosure and Presentation. The Amendment to IAS 1introduces disclosures about level of an entity's capital and how it managescapital. The Group is currently assessing what impact the new IFRS and theamendment to IAS 1 will have on disclosures in its financial statements. IFRS 8, Operating Segments (effective for annual periods beginning on or after 1January 2009). The Standard applies to entities whose debt or equity instrumentsare traded in a public market or that file, or are in the process of filing,their financial statements with a regulatory organisation for the purpose ofissuing any class of instruments in a public market. IFRS 8 requires an entityto report financial and descriptive information about its operating segments andspecifies how an entity should report such information. Management does notexpect IFRS 8 to affect the Group's financial statements. Other new standards or interpretations. The Group has not early adopted thefollowing other new standards or interpretations: IFRIC 7, Applying theRestatement Approach under IAS 29 (effective for periods beginning on or after 1March 2006, that is from 1 January 2007); IFRIC 8, Scope of IFRS 2 (effectivefor periods beginning on or after 1 May 2006, that is from 1 January 2007);IFRIC 9, Reassessment of Embedded Derivatives (effective for annual periodsbeginning on or after 1 June 2006); IFRIC 10, Interim Financial Reporting andImpairment (effective for annual periods beginning on or after 1 November 2006);IFRIC 11, IFRS 2-Group and Treasury Share Transactions (effective for annualperiods beginning on or after 1 March 2007); IFRIC 12, Service ConcessionArrangements (effective for annual periods beginning on or after 1 January2008). Unless otherwise described above, these new standards andinterpretations are not expected to significantly affect the Group's financialstatements. Reclassifications. Certain reclassifications have been made to 2005 amounts toconform to 2006 presentation. The table below discloses the adjusted amountsbefore and after the reclassifications. Management believes that the currentpresentation is preferable to that presented in prior years. As originally Following reported reclassification At 31 December 2005Other non-current assets 2,098 3,247Accounts receivable and prepayments 23,788 21,465Current income tax prepayments - 1,174Other taxes payable 5,448 3,461Other taxes provision - 1,987 For the year ended 31 December 2005Selling, general and administrative expenses (13,968) (12,376)Cost of production (50,442) (52,034)Other non-operating losses (457) (669)Income tax benefit 2,265 2,477 At 31 December 2005, management reclassified $1.149 million from accountsreceivable and prepayments to other non-current assets, primarily to recordadvances to contractors and suppliers for capital construction projects. Currentincome tax prepayments as of $1.174 million were separated from accountsreceivable and prepayments. At 31 December 2005, other taxes provision as of $1.987 was separated from othertaxes payable. For the year ended 31 December 2005, selling, general and administrativeexpenses was decreased and cost of production was increased by $1.592 million,primarily to record property tax and other taxes of $1.338 and loss on disposalof assets of $0.254 million within cost of production. For the year ended 31 December 2005, reversal of income tax provision as of$0.212 million was reclassified from other non-operating losses to income taxbenefit. 3 Critical Accounting Estimates and Judgments in Applying AccountingPolicies 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. 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 it isprobable that an event will result in outflows of resources from the Group.Significant judgment is used to estimate the amounts of provisions, includingsuch factors as the current overall economic conditions, specific customer,counterparty or industry conditions and the current overall legal and taxenvironment. Changes in any of these conditions may result in adjustments toprovisions 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. Tax legislation. Russian tax, currency and customs legislation is subject tovarying interpretation. Refer to Note 18. 4 Acquisitions Acquisition of OOO Oil Company Dulisma and OOO Lenskaya TransportnayaKompaniya. In April 2006, the Group acquired 100 % stakes in OOO Oil CompanyDulisma ("Dulisma") and OOO Lenskaya Transportnaya Kompaniya ("LTK") for $136million, net of assumed debt of $15.1 million. Dulisma holds exploration andproduction licenses in Irkutsk expiring in 2019. A net loss of $2.4 millionassociated with Dulisma and LTK were included in the Group's results for theyear ended 31 December 2006. The table below presents the fair values of 100 % of Dulisma's and LTK's assetsand liabilities as of the date of acquisition. No information on the IFRScarrying values before the acquisition is available as Dulisma and LTK did notprepare IFRS financial statements prior to acquisition. Fair values at acquisitionCash and cash equivalents 61Accounts receivable and prepayments 2,842Other current assets 1,378Oil and gas properties and equipment 241,711Short-term borrowings and current portion of long-term borrowings (399)Other current liabilities (18,523)Deferred income tax liability, non-current (55,738) Net assets 171,332Excess of the Group's share in (35,448)net assets over purchase considerationPurchase consideration share in net assets acquired 135,884Less: cash and cash equivalents of subsidiaries acquired (61) Outflow of cash and cash equivalents on acquisition 135,823 Included within oil and gas properties and equipment acquired with Dulisma andLTK are property acquisition costs with a fair value of $153.1 million that arenot subject to depletion pending the results of management's assessment of theeconomic viability of the properties. Additionally, included within oil and gasproperties and equipment acquired with Dulisma and LTK are property acquisitioncosts with a fair value of $35.4 million that are being depleted over totalproved reserves. Management attributes the excess of the Group's share in net assets acquiredover purchase consideration to the foreign seller's interest in exiting theRussian market and its lack of interest in investing the required resources todevelop the license as well as uncertainties over the timing and conditions forusing the planned pipeline connecting Dulisma's operations to commercialmarkets. The remaining amount of $0.447 million of excess of net assets acquired overpurchase price relates to the acquisition of OOO Nizhneomrinskaya Neft, anentity extracting crude oil, for a total consideration of $3.532 million. Thecash and cash equivalents of subsidiary acquired is $2.056 million as of thedate of acquisition. Summary combined financial information. The following table sets forth summarycombined financial information for the year ended 31 December 2006 that ispresented to provide information to evaluate the financial effects of theacquisitions of Dulisma and LTK as if they had occurred on 1 January 2006. Group Dulisma Adjustments Summary results And LTK and elimination combined Total revenues 169,590 4,390 (2,968) 171,012Profit (loss) for the year 34,422 (2,904) 2,449 33,967 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 December2006. Total revenues and profit (loss) for the period for Dulisma and LTKcomprise the respective entities' results for the full year, including theperiod prior to acquisition, without adjustments for intercompany transactionsor fair values. Adjustments and eliminations include the following: (a)intercompany eliminations were recorded; (b) adjustments to eliminate results ofthe period included both in the Group results and the respective entities'results for the full year; and (c) corresponding adjustments for income taxeswere recorded. However, no adjustments were made to adjust interest expense forborrowings used to finance these acquisitions. Acquisition of Dinyu. In November 2005, the Group acquired a 100.0 % stake inDinyu from Lonsdacks Investments Limited for $61.5 million, net of debt assumedof $8.5 million, following the approval from the Russian Federal AntimonopolyService. Subsequent to its purchase of Dinyu, in December 2005, the Group purchased the35 % stake owned by third parties in Dinyu's 65 % owned subsidiary, OOOMichayuneft ("Michayuneft") for $0.2 million. Acquisition of Arcticneft. In July 2005, the Group acquired a 100.0 % equityinterest in Arcticneft from OAO LUKoil for $23 million, net of debt assumed of$13 million. Arcticneft holds production licenses in the Nenetsky AutonomousRegion of the Russian Federation. 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 incomestatement for the year ended 31 December 2005. Acquisition of Urals-Nord. In April 2005, the Company acquired the remaining50.0 % interest in OOO Urals-Nord ("Urals-Nord") for $14 million. The Groupincurred $0.84 million of additional cost related to seismic review of thelicense areas. Urals-Nord holds 5 exploration licenses for Beluginisky,Zapadno-Sorokinskiy, Fakelniy, Nadezhdinskiy and Alfinskiy prospects. Urals-Nordhas been consolidated from the date of acquisition. Management believes thatthe purchase price for Urals-Nord approximates the fair value of unproved oiland gas properties acquired. Such unproved oil and gas properties are includedwithin property, plant and equipment in the consolidated balance sheet. Nogoodwill was recognized in the acquisition. 5 Accounts Receivable and Prepayments 31 December 2006 2005Trade accounts and notes receivable (net of allowances of $0.640 million 1,755 7,871and $0.586 million at 31 December 2006 and 2005, respectively)Prepaid taxes 759 3,234Advances to suppliers 4,857 2,723Recoverable taxes including VAT 12,236 3,503Receivables from related parties (Note 20) 2,897 2,805Other 2,213 1,329 Total accounts receivable and prepayments 24,717 21,465 Total accounts receivable and prepayments at amount of $3.91 million and $10.947million at 31 December 2006 and 2005, respectively, are denominated in USdollars. 6 Inventories 31 December 2006 2005Crude oil 6,910 3,252Petroleum products 1,700 1,590Materials and supplies (net of allowances of $1.217 million and $0.854 18,069 7,799million at 31 December 2006 and 2005, respectively) Total inventories 26,679 12,641 7 Property, Plant and Equipment Oil and gas Refinery and Buildings Other Assets under Total properties related Assets construction equipmentCost at 1 January 2005 87,388 8,684 989 3,772 2,458 103,291Translation difference (5,129) (315) (41) (154) (219) (5,858)Business combinations 172,110 615 1,100 650 5,405 179,880Additions 4,697 - - 209 15,812 20,718Capitalised borrowing - - - - 640 640costs (Note 11)Transfers 8,053 - - 964 (9,017) -Changes in estimates of (765) - - - - (765)dismantlementprovision (Note 12)Disposals (217) - - (310) (325) (852) 31 December 2005 266,137 8,984 2,048 5,131 14,754 297,054 Translation difference 35,034 838 330 341 4,837 41,380Business combinations 209,473 - 2,629 1,216 31,437 244,755Additions 5,060 - - - 39,546 44,606Capitalised borrowing - - - - 861 861costs (Note 11)Transfers 28,322 57 59 4,729 (33,167) -Changes in estimates of 146 - - - - 146dismantlementprovision (Note 12)Disposals (2,112) - - (1,055) (1,176) (4,343) 31 December 2006 542,060 9,879 5,066 10,362 57,092 624,459 Oil and gas Refinery and Buildings Other Assets Assets under Total properties related equipment constructionAccumulated Depreciation at 1 January 2005 (519) - - (18) - (537)Translation difference 128 8 4 10 - 150Depreciation, depletion (8,044) (510) (226) (614) - (9,394)and amortizationDisposals 118 - - 94 - 212 (8,317) (502) (222) (528) - (9,569) 31 December 2005 Translation difference (1,312) (64) (33) (71) - (1,480)Depreciation, depletion (16,950) (518) (380) (1,034) - (18,882)and amortizationDisposals 883 - - 389 - 1,272 31 December 2006 (25,696) (1,084) (635) (1,244) - (28,659) Net Book Value at 31 December 2005 257,820 8,482 1,826 4,603 14,754 287,485 31 December 2006 516,364 8,795 4,431 9,118 57,092 595,800 Included within oil and gas properties at 31 December 2006 and 2005 wereexploration and evaluation assets of $322.9 million and $140.5 million,respectively. Additions to exploration and evaluation assets in 2006 and 2005totalled $159.1 million and $135.9 million, respectively, including $153.1million and $129.4 million as a result of business combinations. Transfers fromexploration and evaluation assets to producing properties totalled $4 millionand nil in 2006 and 2005, respectively. The remaining movements in explorationand evaluation assets relate to currency differences. During the years ended 31December 2006 and 2005, no exploration and evaluation costs were recognized inthe Group's consolidated income statement and investing cash flows, other thanbusiness combinations, related to exploration and evaluation assets totalled $6million and $6.5 million respectively. 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 $2.3 million and $0.020million at 31 December 2006 and 2005, 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 2006 and 2005, property, plant and equipment with carrying netbook value of $134.4 million and $90.2 million, respectively, was pledged ascollateral for the Group's borrowings. 8 Other Non-Current Assets 31 December 2006 2005 Advances to contractors and suppliers 12,474 1,177Intangible assets 1,141 -Other deferred costs 2,458 2,070 Total other non-current assets 16,073 3,247 9 Accounts Payable and Accrued Expenses 31 December 2006 2005 Trade payables 5,991 2,809Interest payable 15 833Wages and salaries 1,167 806Advances from and payables to related parties (Note 20) - 74Other payable and accrued expenses 2,860 3,410 Total accounts payable and accrued expenses 10,033 7,932 Total accounts payable and accrued expenses at amount of $3.314 million and$3.582 million at 31 December 2006 and 2005, respectively, are denominated in USdollars. Advances from customers. In December 2006, the Group received an advance of$30.2 million denominated in US dollars from Petraco Oil Company Limited forcrude oil sales volumes from Petrosakh and Arcticneft in June-August 2007. Thisadvance was received to finance the development program in Dulisma during thewinter period. The advance bears interest at LIBOR plus 4% until the date ofbill of lading and LIBOR plus 1% for 30 days from the bill of lading date. 10 Taxes Income taxes for the years ended 31 December 2006 and 2005 comprised thefollowing: Year ended 31 December 2006 2005Current tax (benefit) expense (1,296) 678Deferred tax (benefit) (1,988) (3,155) Income tax (benefit) (3,284) (2,477) Below is a reconciliation of profit before taxation to income tax charge(benefit): Year ended 31 December 2006 2005 Profit before income tax 31,138 4,496 Theoretical tax chargeat the statutory rate of 24 % 7,473 1,079 Excess of net assets acquired over purchase price (8,615) (4,030)Non-recurring mobilization costs - 1,721Tax credits related to seismic surveys (280) (1,047)Losses utilized in the current year - (1,340)Utilisation of previously unrecognised tax loss carry forward (781)Unrecognised tax loss carry forward for the year 396 939Reversal of unused income tax provision (2,835) (161)Effect of tax penalties 164 28Other non-deductible expenses 1,194 334 Income tax (benefit) (3,284) (2,477) The movement in deferred tax assets and liabilities during the year ended 31December 2006 was as follows: 2006 Recognized in Charged Effect of 2005 equity for (credited) to acquisitions translation the income differences statementDeferred tax liabilitiesProperty, plant and equipment 114,388 7,747 (1,792) 55,813 52,620Inventories 124 9 25 - 90Payables 75 19 (238) 3 291Other taxable 39 8 (82) - 113temporary differences Deferred tax assetsReceivables (255) (19) 29 (110) (155)Dismantlement provision (799) (31) (184) (394) (190)Payables (459) (36) (63) - (360)Inventories (130) (12) 87 (91) (114)Other deductible (61) (110) 653 (49) (555)temporary differencesTax losses (1,135) (72) (423) - (640) Net deferred tax liability 111,787 7,503 (1,988) 55,172 51,100 The movement in deferred tax assets and liabilities during the year ended 31December 2005 was as follows: 2005 Recognized in Charged Effect of 2004 equity for (credited) to acquisitions translation the income differences statementDeferred 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 113 (2) 115 - -temporary differences 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 (555) 19 (93) (429) (52)temporary differencesTax losses (640) 16 (365) - (291) Net deferred tax liability 51,100 (1,008) (3,155) 36,873 18,390 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 2006 and 2005,deferred tax assets of $4.9 million and $2.0 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 2006 and 2005, theestimated unrecorded deferred tax liabilities for such differences were $4.4million and $1.4 million, respectively. Other taxes payable at 31 December 2006 and 2005 were as follows: 31 December 2006 2005Unified production tax 5,583 2,259Value added tax 374 367Other taxes payable 1,296 835 Total other taxes payable 7,253 3,461 11 Borrowings Long-term borrowings. Long-term borrowings were as follows at 31 December 2006and 2005: 31 December 2006 2005BNP Paribas Reserve Based Loan Facility 51,054 69,000BNP Paribas Subordinated Loan 10,570 -Bank Zenit - 12,000Other 185 122Subtotal 61,809 81,122Less: current portion of long-term borrowings (20,965) (34,117) Total long-term borrowings 40,844 47,005 BNP Paribas Reserve Based Loan Facility. In November 2005, the Group received afive year, revolving Reserve Based Loan Facility with BNP Paribas, underwrittento a maximum commitment of $100.0 million. At 31 December 2005, the maximumamount then available of $69.0 million was drawn. The facility is divided intoa senior tranche of $59.0 million that bears interest at LIBOR plus 5.0 % and ajunior tranche of $10.0 million priced at LIBOR plus 6.25 %. Both tranches arerepaid on quarterly basis and matured in December 2010. The loan wascollateralized by liens on property, plant and equipment of subsidiaries (Note7). The Group is subject to certain financial and other covenants under thefacility, including the maintenance of a minimum current ratio and a maximumration of total borrowings to EBITDA. Additionally, under the facility, theGroup is required to maintain a designated cash balance equal to the nextquarter's payment of principal and interest ($7.473 million and $1.083 millionat 31 December 2006 and 2005, respectively). At 31 December 2006, the Group wasin compliance with all its covenants under the facility. Subordinated Loan. In January 2006, the Group obtained a $12.0 millionsubordinated loan from BNP Paribas (the "Subordinated Loan"). The SubordinatedLoan bears interest at LIBOR plus 5.0 % and is repayable on 10 November 2010.Attached to the Subordinated Loan were warrants to purchase up to two million ofthe Group's common stock for £3.03. The warrants are exercisable at any timeand expire in November 2010. The Group used the proceeds from the SubordinatedLoan to repay the Bank Zenit loan of $12.0 million. Management estimated the value of the warrants to be $1.75 million at issuance.As the exercise price of the warrants is denominated in a currency other thanthe Group's functional currency, the warrants are classified as a liability andadjusted to fair value at each reporting date, with the change in fair valuerecorded within the income statement. In 2006 the change in fair value ofwarrants resulted in an expense of $1.77 million. As the warrants areexercisable at any time, this amount was originally recorded as currentliabilities in the Group's consolidated balance sheet, with a correspondingreduction in the carrying value of the Subordinated Loan. The differencebetween the carrying value and the face value of the Subordinated Loan isaccreted over the term to maturity as interest expense at the effective interestrate of the debt. Bank Zenit. In March 2005, Chepetskoye and CNPSEI entered into two loanagreements with Bank Zenit totalling $12.0 million. The loans bear interest at11.0 % per annum and scheduled for repayment in March 2010. The loans wererepaid in full in February 2006. BNP Paribas Bank Credit Facility. In June 2005, the Petrosakh entered into a$20.0 million, 18 month pre-export credit facility with BNP Paribas Bank. Thisvariable interest debt facility bore interest at LIBOR plus 5.0% 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 % convertiblepreferred note agreement with RP Capital Group for up to $15.0 million. In theevent of a qualifying initial public offering ("IPO") the notes were convertibleinto ordinary shares at a 20 % discount to the IPO price. In July 2005 theGroup issued $10.0 million of the convertible notes at par. These notes wereconverted into 2,929,651 shares in August 2005. No gain or loss was recognizedon conversion. Scheduled maturities of long-term borrowings outstanding were as follows: Scheduled maturities at 31 December 2006 2005One year 20,965 34,117Two to five years 40,844 47,005Thereafter - - Total long-term borrowings 61,809 81,122 Short-term borrowings. Short-term borrowings were as follows at 31 December2006 and 2005: 31 December 2006 2005BNP Paribas Revolver 2,000 - Total short-term borrowings 2,000 - BNP Paribas $2 million revolving facility. In November 2006, the Group enteredinto a revolving loan agreement with BNP Paribas for a maximum of $2 millionwith a maximum maturity of 3 months and bearing interest of LIBOR plus 4.0%. The effective interest rate. The effective interest rates were 10.47 % and 9.71% as at 31 December 2006 and 2005, respectively. Interest expense and income. Interest expense and income for the years ended 31December 2006 and 2005 comprised the following: Year ended 31 December 2006 2005 Short-term borrowingsAlfa Eco M - 913Related party borrowings (Note 20) - 726Related party borrowings converted into equity (Note 20) - 655Nimir - 478BNP Paribas Pre-export Loan - 961Bank Zenit 129 1,031Other short-term borrowings 44 35 Total interest expense associated with short-term borrowings 173 4,799 Long-term borrowingsBNP Paribas Subordinated Loan- interest at coupon rate 1,125 -- accretion of issuance costs and discount associated with warrants 381 -BNP Paribas Reserve Based Loan Facility- interest at coupon rate 6,521 835- commitments 263 777- accretion of issuance costs 529 88 Total interest expense associated with long-term borrowings 8,819 1,700 Finance leases 162 276Less capitalised borrowing costs (861) (640)Change in dismantlement provision due to passage of time (Note 12) 166 224Interest on advance from Petraco Oil Company Limited 1,181 315Other interest 170 237Total interest expense 9,810 6,911 Interest incomeJP Morgan Liquidity Fund (635) (666)Related party loans issued (Note 20) (130) (84)Bank deposit (571) (163)Other (23) -Total interest income (1,359) (913) Total finance costs 8,451 5,998 12 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 %. Year ended 31 December 2006 2005Opening dismantlement provision 813 950Translation difference 126 (21)Acquisitions 1,643 785Additions 433 20Changes in estimates 146 (1,145)Change due to passage of time 166 224 Closing dismantlement provision 3,327 813 As further discussed in Note 18, 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. 13 Equity At 31 December 2006, authorized ordinary shares were 250 million, each having apar value of 0.0025 Cypriot pounds, of which 118.1 million and 86.9 million wereissued and outstanding at 31 December 2006 and 2005, respectively. 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 shares Share Share premium Unpaid capital (thousands of shares) capitalBalance at 1 January 2005 40,000 209 42,172 (11,324) Conversion of loans as settlement of - - - 11,017unpaid capitalConversion of loans into shares 16,244 86 45,195 -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 - Shares issued for cash 31,089 173 194,879 -Exercise of options 113 - 125 -Share-based payment - - 5,089 -Balance at 31 December 2006 118,113 633 401,448 - Shares issued for cash. In May 2006, the Group completed a private placementfor 31,088,976 of its shares. Proceeds from the issuance totalled $195.1million, net of transaction costs of $14.0 million. In August 2005, the Group completed an initial public offering of its shares.As part of the offering, the Group issued 30,667,050 shares in exchange for$114.1 million, net of transaction costs of $17.0 million. Conversion of loans as settlement of unpaid capital. During 2005, the Groupsettled $11.0 million of loans payable by offsetting the loan amounts againstunpaid capital due the Group from the lenders. Conversion of loans into shares. During 2005, the Group settled $45.3 millionof loans payable by issuing shares to the lenders. Share-based payments. In February 2006, the Board of Directors approved aRestricted Stock Plan (the "Plan") authorizing the Compensation Committee of theBoard of Directors to issue restricted stock of up to 5 % of the outstandingshares of the Group. Upon adoption, the Group issued 1,561,725 shares ofrestricted stock. The vesting schedule for the restricted stock varies byindividual award and, of the February 2006 grant, 1,040,445 shares, 260,625shares and 260,625 shares vest on 1 January 2007, 2008 and 2009, respectively.The Group estimated the total fair value of the share-based payments to be$6.582 million, of which $5.028 million was recognized in 2006. In September 2005, the Group granted options to purchase 20,000 shares at anexercise price of 240 pence per share to one of its directors. These optionswere granted for zero consideration. All of these options remain unexercised.In these consolidated financial statements the fair value of this option wasevaluated at $.007 million. The options vest on 30 September 2006, 2007 and2008 in equal parts and expire on 30 September 2009. During 2005, the Group granted a share-based award to one of its officers.Under the award, the officer shall have the option to purchase a certain numberof the Group's shares at a share price equal to $131 million divided by thenumber of Group shares that are issued and outstanding at both 1 August 2006 and1 August 2007. The option is in two parts comprised of the number of sharesthat can be purchased for a payment of $125,000 on 1 August 2006 and of $125,000on 1 August 2007, which are the respective vesting dates of the two parts of theaward. The officer is required to be continuously employed by the Group throughthe vesting dates. Notification of intent to purchase must be submitted withinthree days of the respective dates, and payment and delivery of shares to theofficer are to occur within 15 days of the respective dates. The Group estimated the total fair value of the award to be $0.120 million, ofwhich $0.057 and $0.042 million were recognized within selling, general andadministrative expenses in 2006 and 2005, respectively, with respect to thisaward. The full amount of the award is being recognized over its vestingperiod. The Black-Scholes option valuation model, used for valuing these awards, wasdeveloped for use in estimating the fair value of traded options that have novesting restrictions and are fully transferable. In addition, this optionvaluation model requires the input of highly subjective assumptions, includingthe expected stock price volatility. As the Group's shares were not publiclytraded at the time of the grant of this award, management estimated thevolatility measure through consultation with independent experts. Changes inthe subjective 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 $0.120 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 14 Revenues Year ended 31 December 2006 2005Crude oil Export sales 117,940 69,177 Domestic sales (Russian Federation) 35,666 13,433Petroleum (refined) products - domestic sales 14,798 9,904Other sales 1,186 404 Total gross revenues 169,590 92,918 Substantially all of the Group's export sales are made to third party traderswith title passing at the Russian border. Accordingly, management does notmonitor the ultimate consumers and geographic markets of its export sales. 15 Cost of Production Year ended 31 December 2006 2005Depreciation and depletion 19,335 8,285Unified production tax 36,067 16,829Cost of purchased products 9,266 12,455Wages and salaries (including payroll taxes of $2.6 million and 15,190 7,341$1.5 million for the years ended 31 December 2006 and 2005, respectively)Materials 4,862 2,276Other taxes 256 1,338Loss on disposal of assets 439 254Other 6,656 3,256 Total cost of production 92,071 52,034 16 Selling, General and Administrative Expenses Year ended 31 December 2006 2005Wages and salaries 9,616 5,162Professional consultancy fees 2,169 1,986Audit fees 843 556Office rent and other expenses 1,556 1,522Transport and storage services 4,537 998Loading services 1,381 845Share based payments 5,089 42Directors' fees 60 17Other expenses 3,704 1,248 Total selling, general and administrative expenses 28,955 12,376 Directors' fees for the years ended 31 December 2006 and 2005 do not include$0.185 million and nil related to share-based payments provided to one of theGroup's directors (Note 13). 17 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 kilometers 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. 18 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 economy. These characteristicsinclude, 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 in 2005 was required to sell 20.0 % of its annual oil production inthe form of petroleum products to the Sakhalin Island region at market prices,no such commitments exist in 2006. 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 2006 and 2005 the Group had no othersignificant contractual commitments for capital expenditures. Taxation. Russian tax 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 authorities. The Russian tax authorities may be taking a more assertive position in theirinterpretation of the legislation and assessments, and it is possible thattransactions and activities that have not been challenged in the past may bechallenged. The Supreme Arbitration Court issued guidance to lower courts onreviewing tax cases providing a systemic roadmap for anti-avoidance claims, andit is possible that this will significantly increase the level and frequency oftax authorities' scrutiny. As a result, significant additional taxes, penalties and interest may beassessed. Fiscal periods remain open to review by the authorities in respect oftaxes for three calendar years proceeding the year of review. Under certaincircumstances reviews may cover longer periods. As at 31 December 2006 and 2005, 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. In August the company insured all of its major assets,including oil in stock, for a total value of $90 million. Also, a liabilityinsurance policy was put in place, including environmental liability, with atotal limit of $7.8 million. 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. Management currently does not believe that any of its significant exploration orproduction licenses are at risk of being withdrawn by the licensing authorities.Additionally, management currently plans to complete all the requiredexploration or development work, as appropriate, within the timetablesestablished in the licenses. 19 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 obtains funds from, and deposits its cashsurpluses with, banks at current market interest rates, and does not utilizehedging instruments to manage its exposure to changes in interest rates. Thedetails of interest rates associated with the Group's borrowings are discussedin Note 11. Fair values. The carrying value of the Group's receivables, payables andborrowings approximate their fair values. Cash and cash equivalents are carried at amortised cost which approximatescurrent fair value. Cash and cash equivalents include $31.5 million and $27.9million as at 31 December 2006 and 2005, respectively, denominated in USdollars. At 31 December 2006 and 2005, 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 2006 and 2005, management believes that the fair values of itsborrowings approximate their respective carrying values. Warrants classified as liabilities are carried at fair value. 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 financialinstitutions, which are considered at time of deposit to have minimal risk ofdefault. 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. 20 Balances and transactions with Related Party. 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 had transactions in theordinary course of business with Urals ARA NV and Nafta (B) NV which all arecontrolled by major shareholders. These transactions included sales andpurchases of crude oil and petroleum products. Such sales ended beginningSeptember 2005. Below are the annual sales, purchases and receivables balancesfor each year presented: As of or for the year ended 31 December 2006 2005Sales of crude oil on export markets - 5,515 Associated volumes, tons - 17,580 Interest expense - 1,381Interest income 130 82Professional consultancy fees (included in selling, general and administrative 424 289expense)Rental fees paid (included in selling, general and administrative expense) 450 306Other expenses 41 790 Accounts and notes receivable 708 1,477Loans receivable 1,983 1,251Interest receivable 206 77Accounts payable to contractors (included in other non-current assets) 863 -Other payables and accrued expenses - 74 Compensation to senior management. The Group's senior management team comprises10 people whose compensation totalled $12.895 million and $4.174 million for theperiods ended 31 December 2006 and 2005, respectively, including salary andbonuses of $7.806 million and $4.132 million respectively, and stockcompensation of $5.089 million and $0.042 million, respectively, and no othercompensation was paid for both years. Additionally, included in loansreceivable at 31 December 2006 and 2005 were loans receivable of $0.955 and nil,from the Group's senior management team. 21 Subsequent Events Goldman Sachs. In January 2007, the Group entered into a new loan agreement tofund the development of the Dulisminskoye field in Irkutsk Region, EasternSiberia. Goldman Sachs, as Arranger, and Standard Bank plc, as the funding bank,are providing a total of US$130 million of debt. The debt facility is secured byOOO "Oil Company Dulisma" as a project-style loan that is non-recourse, exceptin certain limited circumstances, to Urals Energy. This debt financing isexpected to fund Urals Energy's commitment to develop the oil reserves at itsDulisminskoye field. The terms of the loan arranged by Goldman Sachs include an interest rate of 725basis points over LIBOR of which 300 basis points are payable quarterly, withthe remainder accruing until the loan matures in four years or 2011 when allprincipal and accrued interest is due in a single payment. The loan may beprepaid at any time but during the first two years certain penalties for earlyprepayment apply. The credit risk of the debt facility will be sold to Goldman Sachs and StandardBank will act as the funding bank of record and also facility agent. The deal isstructured to fund in two tranches, $45 million and $85 million. The secondtranche is subject only to the approval of Urals Energy's senior bank syndicatein accordance with the terms of a pre-negotiated inter-creditor agreement. Bothtranches were received during first quarter 2007. Unified production tax holiday. In November 2006 the Russian Governmentannounced changes to the "Subsoil law", which provides a production tax holidayfor the unified production tax for the oil fields located in East Siberia inSakha-Ykutia, Irkutsk and Krasnoyarsk regions. In January 2007 OOO Oil CompanyDulisma received a written confirmation from Irkutsk Oblast Tax Inspectorateverifying a ten year production tax holiday for the Dulisminskoye field startingform 1 January 2007 and ending on 31 December 2016. This information is provided by RNS The company news service from the London Stock Exchange
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