ANNUAL REPORT AND ACCOUNTS 2006
RUSSIAN FEDERATION URALS ENERGY
MOSCOW ANNUAL REPORT AND ACCOUNTS 2006 URALS ENERGY PUBLIC COMPANY LIMITED IS A RUSSIA- FOCUSED OIL AND GAS COMPANY LISTED ON THE LONDON AIM. OUR STRATEGY IS TO CONTINUE GROWING IN RUSSIA BY DEVELOPING OUR CURRENT ASSETS AND ACQUIRING ADDITIONAL OIL AND GAS PROPERTIES. WE ARE INCREASING OUR PRODUCTION AND RESERVES TO BECOME RUSSIA’S LEADING INDEPENDENT OIL COMPANY.
CONTENTS 2 Chairman’s and Chief Executive’s Statement 11 Financial Results 15 Reserves 16 Directors and Management 18 Independent Auditor’s Report 19 Consolidated Financial Statements 23 Notes to the Consolidated Financial Statements 48 Notice of AGM 49 Corporate Information
2006 HIGHLIGHTS INCREASED ASSET BASE Acquired Dulisma and Nizhny Omrynskoye 5x YoY growth in 2P reserves to 577mm at an average cost of $1.44 per barrel 2.5x YoY increase in PV10 to $1,804 million ENHANCED GROWTH POTENTIAL 82% YoY increase in average daily production to 9,569 bopd New forecast peak of 50,000 bopd in 2013 At peak in 2013, 90% of production will be export oil, 72% to Asian markets IMPROVED FINANCIALS Net revenues increased YoY by 80% to $119.2 million EBITDA increased YoY by 36% to $22.8 million 5x YoY increase in net income to $34.3 million BOLSTERED FINANCIAL RESOURCES Raised additional net $195 million in equity capital Secured additional $144 million in debt, including a $130 million Dulisma project loan Reduced spread on senior debt by 50 bps 2P RESERVE VALUE GROWTH (PV10)
$ MM PV10 2,000
1,800
1,600
1,400
1,200
1,000
$1,804 MM
800
600
400 $717 MM
200 $402 MM
0 IPO MAY 2006 APRIL 2007
2P BOE RESERVES GROWTH (MILLION BARRELS) (1)
MMBBLS CAGR 2003-2006: +202% 600 URALS KEY INVESTMENT CRITERIA ¥Existing reserves, production ¥Potential to increase production NIZHNY OMRYNSKAYA NEFT ¥Majority control ¥Preference for higher % of export 500 ¥Potential to leverage existing resources ¥Appropriate risk-adjusted returns
CURRENT YEAR ACQUISITION EXISTING ASSET 400 DULISMA GAS
300
200 DULISMA OIL/CONDENSATE
100 DINYU DINYU ARCTICNEFT ARCTICNEFT
PETROSAKH PETROSAKH PETROSAKH CNPSEI CNPSEI CNPSEI CNGDU CNGDU CNGDU CNGDU 0 2003 2004 2005 2006 1. 2P reserves as per DeGolyer & MacNaughton reports as at 31 December 2006 except for Nizhny Omrynskoye Neft according to Russian C1-C2 classification
Urals Energy Annual Report and Accounts 2006 JANUARY 2006 FEBRUARY MARCH APRIL MAY JUNE JULY AUGUST
CHIEF EXECUTIVE OFFICER’S STATEMENT 2006 WAS AN IMPORTANT YEAR OF GROWTH FOR URALS ENERGY AS WE COMPLETED OUR LARGEST AND Signed Dulisma acquisition with $50 million MOST IMPORTANT ACQUISITION, bridge loan from Morgan Stanley OOO DULISMA, AND CONTINUED TO CONSOLIDATE AND INVEST IN OUR SEVEN OTHER OPERATING SUBSIDIARIES IN RUSSIA.
The Company grew significantly in all respects: reserves, production, cash flow and profits. As a result, we are well positioned to continue our strategy of growth by both developing our existing assets and making further significant, accretive acquisitions.
Operationally, we invested over $60 million in our properties, almost half in development drilling. This was important in boosting production to an In late April, we announced an important average of 9,569 bopd versus 5,263 bopd in increase in our proved and probable reserves as 2005 - an increase of 82%. Importantly, we have evaluated by DeGolyer and MacNaughton, our also purchased and transported to the field site independent reserve engineers. Based on our at Dulisminskoye all necessary equipment to begin work to monetize the large gas and condensate drilling operations, including our 160 ton mobile reserves at Dulisminskoye, we upgraded the gas drilling rig. This provides us the capability to begin and condensate at Dulisminskoye to proved and development operations and prepare the field probable from possible. This is a result of our for full-scale production operations as the East active negotiations to finalize a long-term gas Siberian Pacific Ocean (“ESPO”) pipeline nears sales agreement, which we expect to complete in completion of its first phase of construction. the next few months. Year on year and on a barrel of oil equivalent basis, 2P reserves have increased Since the acquisition of Dulisma in June 2006, we from 116 million barrels to 577 million barrels. have worked to finalize a new field development The D&M estimates for both oil and gas at plan for the Dulisminskoye field. With our new Dulisminskoye, and indeed for all of our properties, drilling rig in place, we expect to spud our first are less than the Russian state reserves development well in July and drill and complete reported by the Ministry of Natural Resources. a total of three development wells by the 2nd quarter of 2008. Successful completion of these Most importantly, the present value of our wells is necessary to achieve our production rate reserves has also increased significantly. As a targets. Production timing is contingent on the result of the production tax holiday at Dulisma pace of development drilling, the completion of and the incremental value attributable to the ESPO and our link-up with this important the development of our gas and condensate new export pipeline. Based on the latest reserves, the Company’s 2P reserves now information regarding the progress of the ESPO carry a total present value discounted at 10% construction, our stated goal of a 2007 year-end equal to $1.8 billion. We believe this is strong production rate of 19,000 bopd will now shift indication of the underlying asset value of our to the 2nd quarter of 2008. oil and gas reserves.
Urals Energy Annual Report and Accounts 2006 SEPTEMBER OCTOBER NOVEMBER DECEMBER JANUARY 2007 FEBRUARY MARCH APRIL
Commercial agreement in progress to sell future gas produced at Dulisma
FINANCIAL RESULTS Morgan Stanley. These funds enabled us to Urals Energy benefited during the year from complete the acquisition of Dulisma and its increasing production profile generating an commence the development work. In January 83% increase in total revenues to $169.6 million of 2007 we raised a further $130 million through (2005: $92.9 million). This contributed to a three- Goldman Sachs under a new debt finance fold increase in operating profits of $34.1 million facility. This financing will give us the required (2005: $11.3 million) and a five fold rise in post-tax funding to develop Dulisminskoye’s reserves, profits of $34.4 million (2005: $6.9 million). EBITDA thereby increasing production from that field increased by 36% to $22.8 million. We realised to its projected peak level of 30,000 bopd by a weighted average dollar price of $48.39 per 2011. We also raised an additional $14 million barrel of oil sold in 2006 compared with $44.35 in 2006 in other debt from BNP Paribas. per barrel in 2005. The average net revenues per barrel for the Company increased slightly for the The Company’s cash position at the year end year at $34.40 compared to $31.57 in 2005. was $33 million. Following the Dulisma project financing in January, the Company’s cash During the course of the year, we raised a net balance stood at approximately $80 million. total of $195 million in new equity through
1. ARCTICNEFT (100%) 3. NIZHNY OMRYNSKOYE NEFT (100%) 5. URALS NORD (100%) 7. DULISMA (100%) •2P Reserves: 33MMBbls •C1-C2 Russian Reserves: •5 exploration licences •2P Reserves: 464MMBOE •1,001 bopd avg 2006 25MMBbls •94MMBbls potential gross •532 bopd avg 2006 •2 Refineries 1,200 bopd capacity unrisked resources 2. DINYU (100%) 4. CNPSEI (100%) 6. CHEPETSKOYE NGDU (100%) 8 PETROSAKH (97%) •2P Reserves: 22MMBbls •2P Reserves: 9MMBbls •2P Reserves: 21MMBbls •2P Reserves: 27MMBbls •2,877 bopd avg 2006 •770 bopd avg 2006 •940 bopd avg 2006 •852MMBbls potential gross unrisked resources •3,159 bopd avg 2006 •Refinery 4,100 bopd capacity
KOMI REPUBLIC RUSSIAN FEDERATION MOSCOW TIMAN PECHORA SAKHALIN EAST SIBERIA 8 UDMURTIA
Urals Energy Annual Report and Accounts 2006 CHIEF EXECUTIVE OFFICER’S STATEMENT JANUARY 2006 FEBRUARY MARCH APRIL MAY JUNE JULY AUGUST
Closing of $148 million acquisition of Dulisma (141 MMBO 2P oil reserves, 323 MMBOE 2P gas reserves)
During 2007 our capital expenditure programme Alexei Ogarev is Urals Energy’s Vice President is expected to be approximately $93 million. of Government Relations and has an important Approximately $42 million will be dedicated to the record of Russian government service including Dulisma development programme (funded through Deputy Head of the Presidential Administration the Goldman Sachs debt finance facility referred and General Director of Rosvooruzhenie, the to above) and $51 million will be invested in Russian arms export agency. He plays an increasing production in our other producing fields. important role in managing our government relations and will provide the directors valuable CORPORATE insight to the Russian government and In late April, we announced the appointment of political environment. Leonid Y. Dyachenko as Chief Executive. Mr. Dyachenko has been a director of Urals Earlier in 2007, we also strengthened the Energy since the Company was founded and for management team with the appointments of the last four years has managed the Company’s William S. Hayes as Senior Vice President and day-to-day activities within Russia based in our General Counsel and Maxim V. Bezriadin as Vice Moscow office. Over the next few years Urals President and Business Unit Manager, East Energy will become an important independent Siberia, together with Stephen D. Kirton as Vice oil and gas producer within Russia, producing President, Technical Services. Following these an estimated 50,000 bopd and over 71,000 mcf appointments we are confident we have the per day in sales gas by 2013. Leonid Dyachenko’s right level of management support in place for appointment reflects Urals Energy’s development the future. into a prominent Russian oil and gas business. OPERATIONS I will continue my involvement with Urals Energy as PRODUCTION UPDATE a non-executive member of the board of directors We ended 2006 at a producing rate of and assist in the transition of management approximately 11,600 bopd. Since then we have responsibilities through June 30, 2007. seen a temporary production decline due to several factors, including shutting-in wells for The Company also announced the appointment the Petrosakh frac program, shut-in production of two additional directors: J. Robert Maguire at Dulisma due to pipeline repairs by the pipeline and Alexei V. Ogarev. Robert Maguire is one of owner, and a decline in reservoir pressure at Dinyu the most experienced international oil and gas and Petrosakh. As a result, actual production for investment banking advisers in the industry, the first quarter of 2007 averaged approximately with over 30 years experience, most recently 8,900 bopd. However, we have taken steps to as head of the Global Energy Group at Morgan restore production and, including the temporarily Stanley. His expertise will prove invaluable to the shut-in production at Dulisma, we have the Company through its next stage of development. capability to produce approximately 10,700 bopd.
Urals Energy Annual Report and Accounts 2006 SEPTEMBER OCTOBER NOVEMBER DECEMBER JANUARY 2007 FEBRUARY MARCH APRIL
ESPO re-routed to within 75 km of Dulisma field
During the year, we acquired and refurbished ESPO to within 75 km of the Dulisma field reduced a fleet of fracture stimulation equipment, the initial cost estimates for construction of including three pumping units. Fracture the pipeline from the field to the ESPO tie-in by stimulation operations commenced at approximately $70 million, and brings forward our Petrosakh in January 2007 and we are confident production profile. of significantly increasing production with fracture stimulation at Petrosakh and other In January 2007 we announced that the Irkutsk selected producing subsidiaries. Tax Inspectorate had confirmed the 10 year tax holiday for the Dulisminskoye field for the period DULISMA between 1 January 2007 and 31 December 2016. Following completion of the Dulisma acquisition This tax holiday is estimated to produce savings in June 2006, the Company has been actively of approximately $308 million over the 10 year executing its development programme, targeting period and further exemplifies the importance peak production of 30,000 bopd by 2011. Progress of this asset to Urals Energy. is being made on all fronts, with all Government approvals for the field development program Development activity at Dulisminskoye is moving received. The Company has also received approval forward in accordance with our plans announced from Transneft to accept oil produced at Dulisma last year. The new 160 tonne mobile drilling rig for its ESPO pipeline, thus providing the Dulisma and all associated equipment are at the field field future permanent export pipeline access site and rigging-up operations are underway. for its crude oil production. The re-routing of the The first development well will spud in July, with
OPERATIONAL TASK COMPLETION DRILLING •18 development wells •3 side track wells •2 exploration wells RIGS PURCHASED •1 mobile rig - 160 ton •1 mobile rig - 100 ton •2 workover rigs - 60/80 ton •1 Frac fleet SEISMIC •2D acquisition – 307 km •3D acquisition - 17 km •3D reprocessing - 517 km STORAGE •2 new 10,000cm storage tanks
Urals Energy Annual Report and Accounts 2006 CHIEF EXECUTIVE OFFICER’S STATEMENT JANUARY 2006 FEBRUARY MARCH APRIL MAY JUNE JULY AUGUST
Sakhalin offshore exploration license extended for five years
EAST SIBERIA Pump Station No.14 Olekminsk Dulisma 2006 Highlights •Commence construction Timpuchikanskoe Tommot Gazpromneft Lensk Average production of CFP facility 2006 = 532 bopd •New 100 man workers Aldan Verkhnechonskoe TNK-BP camp installedPump Station No.17 Pump Station No.10 2007 Program Vitim •Drill first two Talakanskoe •New 160 ton mobile rig horizontal wells Surgutneftegas mobilised to site •2 gas turbine generators Dulisminskoye mobilised to site Pump Station No.8 Gross Reserves Summary (mmboe) Source D&M as at 31 Mar 2007 Kirensk Ust-Ilimsk RUSSIAN 1P 2P 3P(2) 2P PV10% Tinda FEDERATION 221.0 464.0 570.2 $1,013 MM
Ust-kut ESPO Pipeline Route Gas Fields Town Pump Station No.4 Connecting Pipeline Oil and Gas Fields Trans-SiberianPump Station ÒSkovorodinoÓRail Line Oil Fields Pumping Stations Severbaykalsk
Pump Station No.1 ÒTaishetÓ 200Kms Lake Baikal two further development wells scheduled for the pipeline to Kirensk will begin later in 2007 in fourth quarter of 2007 and first quarter of 2008. time for the delivery of pipeline quality oil when Road and pad construction is continuing in the ESPO is commissioned in 2008-9. the field and we are working to commission two gas-turbine generators to provide power Our 2007 CAPEX budget for Dulisma will be for drilling and production operations. A new approximately $42 million, of which $16 million 100-man field camp will be installed during is for development drilling and $26 million for the winter of 2007. Construction of a central pipelines, infrastructure and facilities. processing facility (CPF) and the connecting
DULISMA VALUE CREATION (PV10) 1,200 $181 MM 2P BOE $MMPV10 $167 MM GAS VALUE 1,000 RESERVES $183 MM INCREASE PV10 VALUATION = $1,013 MILLION SAVINGS FROM 800 TAX COST $70 MM $410 MM SAVINGS FROM 600 ORIGINAL D&M PIPELINE COST VALUATION 400
200
0 SPRING 2006 SUMMER 2006 END OF YEAR 2006 END OF YEAR 2006 Q1 2007 ACQUISITION ESPO RE-ROUTING MET HOLIDAY INCREMENTAL RESERVES GAS COMMERCIALISATION INCREASE PLAN
Urals Energy Annual Report and Accounts 2006 SEPTEMBER OCTOBER NOVEMBER DECEMBER JANUARY 2007 FEBRUARY MARCH APRIL
Fracture stimulation work commences at Petrosakh
We are preparing a gas monetization plan that re-entry wells. Our first offshore exploration includes burning associated gas to generate well; the Pogranichny No. 1 well, was drilled at the in-field electricity, stripping liquids to create beginning of 2006 to a depth of approximately a separate sales stream of condensate and 2,100 meters but failed to encounter commercial natural gas liquids, reinjecting certain gas volumes of oil or gas. This well has been followed volumes to maintain reservoir pressure and up with an intense 3D seismic reprocessing and entering into a long term gas sales agreement reinterpretation programme. Offshore drilling is with a large gas end-user. We expect to expected to resume in the summer of 2008. announce the terms of this agreement over the next few months and provide further In January 2006 we agreed a five year extension details about the gas monetization plan. to our offshore exploration licence in Sakhalin Island with the Ministry of Natural Resources. SAKHALIN ISLAND This will allow us to fully exploit the licence area Production during the year averaged 3,159 bopd which has a potential of over 850 million barrels compared with 2,524 bopd in 2005. During the in place. In March 2007, we received approval to year we drilled two development wells and three lift Petrosakh crude oil using foreign-flagged
8 SAKHALIN ISLAND Okha Operations Okha Average production •Offshore: 2006 = 3,159 bopd -1 exploration well -3D seismic reprocess 2006 Highlights & reinterpretation •Onshore: -2 development wells 2007 Program -3 re-entry wells •6 development wells -3D seismic reprocess •Frac 11 wells & reinterpretation •3 new oil products
-20,000 cm new storage tanks Pobedino Pervomaysk
Rall Terminal
TT crude storage tanks T
AA A Poronaisk
TT T
AA Gross Reserves Summary (mmbbl) Source D&M as at 31 Dec 2006 A
RR R
SS Unrisked Potential S TT T
(1) RR 1P 2P 3P 2P PV10 Resources (mmbl) R SAKHALIN AA
II ISLAND TT K 8.7 26.7 50.5 $291.5 MM 852 T S O T K H 1. Calculated DeGolyer & MacNaughton as of 31 March 2005 - O Gross unrisked potential resources have not been adjusted for risk Yuzhno- O F Sakhalinsk A O Sakhalinsk S E Yuzhno- Oil Fields Railroads Pogranichny Licence Area Sakhalinsk Gas Fields Roads Offshore Loading Point Korsakov Prospect Tanker Route Okruzhnoye Field Korsakov Licence Oil Refinery & LNG Plant Petrosakh Refinery Oil Pipeline Sakhalin-1 Sakhalin-2 LNG Plant Gas Pipeline Sakhalin-2
Urals Energy Annual Report and Accounts 2006 CHIEF EXECUTIVE OFFICER’S STATEMENT JANUARY 2006 FEBRUARY MARCH APRIL MAY JUNE JULY AUGUST
Completed $1.5 million acquisition of Nizhny Omrynskoye from LUKoil
vessels through 2009. We believe this is a first Fraccing operations commenced at Petrosakh for any oil-exporting company on Sakhalin in January 2007 and the first four wells have Island and will enable us to more efficiently been completed. A total of eight wells are schedule tankers to lift our export cargoes. planned to be fracture stimulated. Based on the preliminary results of the first four wells, KOMI REPUBLIC we have increased individual well rates by 3-4 times the production rate prior to fraccing. Operations (Dinyu, S. Michayu, CNPSEI, Nizhnyomrynskaya Neft) There is no assurance this level of increase will Average production -Mature field with 2006 = 3,937 bopd development upside be achieved in every well, but we are confident -Possible qualification for 2006 Highlights of significantly increasing production through tax relief •Dinyu fracture stimulation at Petrosakh and certain 2007 Program -8 development wells of our other producing subsidiaries. -2 exploration wells •Dinyu 5 development wells -2D seismic program plus possible exploration well •Nizhnyomrynskaya Neft •Nizhnyomrynskaya Neft During 2007 six development wells are planned. -$1.5 million acquisition work-over wells from LUKoil •Komi-wide fraccing program The results of our most recent well, PS47, -25 million barrels C1-C2 •18 fracture simulations indicate a possible new pool discovery that may Russian standard reserves open up several drilling locations. We recently Gross Reserves Summary (mmbbl) Source D&M as at 31 Dec 2006 commissioned three new oil products storage 1P 2P 3P 2P PV10% tanks and we will soon complete construction 11.8 31.5 59.1 $181.8 MM of two new 10,000 ton crude oil storage tanks Oil Fields Railroads Town for oil exports. Urals Oil Field Roads
Michayu KOMI REPUBLIC KOMI REPUBLIC Dinyu- During 2006, oil production at Komi averaged Savinoborskoe Severnoe Michayu 3,937 bopd compared with 3,349 bopd 2005.
Severo-Savinoborskoe In 2006 the Company drilled 8 development
r
e v
i and 2 exploration wells in Dinyu. In particular,
R
a r
o the DN-48 exploration well drilled in third
h
c
e
Zapadno-Tebukskoe P Vostochno-Savinoborskoe quarter of 2006 to test an extension of the Nizhny Odes Ukhta Dinyu field to the Southeast, encountered a
Yzhno-Tebukskoe previously unidentified reef structure with over
Pashnya 60 meters of permeable limestone reservoir.
Dzhyerskoye Sosnovskoe After extensive testing, the well produced only small quantities of live oil, but has consequently opened up a new potential play within the Verkhne-Omrinskoe Nizhne-Omrinskoe Dinyu license area. We are working to identify Voyvozh additional prospects to prove this hypothesis.
Urals Energy Annual Report and Accounts 2006 SEPTEMBER OCTOBER NOVEMBER DECEMBER JANUARY 2007 FEBRUARY MARCH APRIL
Received license extension at Arcticneft for lower horizons
TIMAN PECHORA Operations (Arcticneft, Urals Nord) Average production •Arcticneft drill 1 side- y e v I s 2006 = 1,001 bopd track exploration well plus 1 g u l a n o l d BARENTS SEA possible exploration well K 2006 Highlights •Urals Nord Tarkskoye •Arcticneft Peschanoozerskoye Field -Drill first exploration well ZAO ARCTICNEFT m -Completed reservoir model a d r -Nadezhnsky prospect e tt -Drilled 2 development wells Bugrino o -R located 60 km south east Ta sk nke an -Received license extension r Route, Murm of port of Varandey for deeper Permian horizon P o m o r s k i S t r a i t Prirazlomnoye -60 mmbbl target at y a B y B a 2007 Program 3,700 meters y a Indiga Kharyaga-Indiga Pipeline o r a k a c h h s Proposed by Transneft P e •Arcticneft 4 development wells e s C h Varandey
Gross Reserves Summary (mmbbl) Source D&M as at 31 Dec 2006 Naryan-Mar
Unrisked Potential Titov 1P 2P 3P 2P PV10 Resources (mmbl) 21.5 33.0 44.4 $218.3 MM 94 Inzyreyskoye Ne Layavozhskoye ne ts Komi Republick A ut Existing Pipeline Production Licence on om ous Vozhyeskaya Intermediate Pump Station Exploration Licence Okr ug Kharyaginskoye
(Planned/proposed) Oilfield Pechora Primary Pump Station (Existing) Town 50Km 0 50Km
In the first quarter of 2006 we completed the 2007 at Dinyu with a possibility of an additional acquisition of approximately 300 kilometres exploration well subject to seismic data review. of new 2D seismic over the Dinyu field and In the second half of 2007, we expect to initiate continue to identify new drilling locations with a Komi-wide fraccing programme, as well as this new data. The potential includes the new continue to workover wells at Nizhny Omrinskoye. reef trend we encountered while drilling DN-48, and a newly identified eastern lobe that has TIMAN PECHORA excellent potential. The average production on the Timan Pechora licence areas during 2006 was 1,001 bopd In October 2006 we also acquired Nizhny compared to 1,078 bopd 2005. In 2006 the Omrinskoye Neft for $1.5 million in cash Company re-completed five wells and drilled from Lukoil. This principal licence is a mature two development wells at Arcticneft. In June producing field that is estimated to have 2007, we will initiate drilling of an important 25 million barrels of C1-C2 reserves. We have sidetrack to test the deep Permian horizon reactivated 3 wells on this field and have for which a license extension was granted by commissioned DeGolyer and MacNaughton to the Ministry of Natural Resources in 2006. The re-evaluate reserves on this licence area. results of this well will be known in August 2007. Three to five development wells will be drilled in
Urals Energy Annual Report and Accounts 2006 CHIEF EXECUTIVE OFFICER’S STATEMENT JANUARY 2006 FEBRUARY MARCH APRIL MAY JUNE JULY AUGUST
$12 million subordinated loan placed with BNP Paribas
At Urals Nord, our first exploration well on the UDMURTIA Nadezhdinsky prospect was spudded on 18 April Average production at Chepetskoye NGDU in 2007 and is expected to reach a target depth 2006 was 940 bopd compared to 914 bopd in of 3,700 meters in June of 2007. The prospect 2005. As part of our 2006 programme we drilled is an Upper Devonian reef that may contain six development wells on the Potapovskoye upwards of 60 million barrels of recoverable field and have received pilot production project reserves. The well is located approximately approval. In addition, ZT118 well on Zotovskoye 60 kilometers southwest of the port of was recompleted and we began a pilot water Varendey on the northern coastline of Russia. injection scheme. In 2007 we plan to drill five development wells at the Potapovskoye field.
UDMURTIA OUTLOOK Operations (Chepetskoye NGDU) The Company is well positioned to continue Average production 2007 Program its growth as a leading Russian independent 2006 = 940 bopd •Drill 5 development wells E&P company. I am personally very proud of 2006 Highlights having played a key role in the development of •Drilled 6 development wells Urals Energy – which is in many ways a success
Gross Reserves Summary (mmbbl) Source D&M as at 31 Dec 2006 because of its partnership of Russian and 1P 2P 3P 2P PV10% western shareholders. With Leonid Dyachenko 8.0 21.2 29.4 $99.5 MM assuming the role of Chief Executive, the
Oil Fields Licence Town Company will be led by a capable Russian manager, executing a focused Russian strategy. Glazov Kezskoye I look forward to continuing our partnership as UDMURT REPUBLIC a member of the board of directors.
Gorlinskoye
ZAO CHEPESTSKOYE Turetskoye NGDU Zotovskoye
Nefedovskoye Polomskoye Pibanshurskoye
Chuboiskoye Potapovskoye William R. Thomas
Krasnogorskoye Vostochno Chief Executive Officer Krasnogorskoe Lozolyuksko-Zurinskoye 30 April 2007
Pionerskoye Shadbegalovskoye Mikhailovskoye Igra
Sundursko- Korobovskoye Nyazinskoye Itinskoye
Chutyrskoye 10Km 0 10Km Kabanovskoye
10 Urals Energy Annual Report and Accounts 2006 SEPTEMBER OCTOBER NOVEMBER DECEMBER JANUARY 2007 FEBRUARY MARCH APRIL
FINANCIAL Confirmation of Mineral Extraction Tax RESULTS holiday at Dulisma through 2016
OPERATING ENVIRONMENT The Group realized a weighted average gross 2006 was characterized by fluctuating world oil price of $48.39 per barrel of oil sold in 2006 prices and the Company’s focus on investment versus $44.35 in 2005. Export sales prices in development drilling. Brent oil prices began for the Group averaged $61.20 per barrel, the year at $61.67 per barrel, reached a peak of and domestic sales prices averaged $27.75 $78.69 in August a low of $55.96 in October and per barrel. Domestic refined product prices ended the year at $56.63 per barrel. The Russian averaged $50.52 per barrel. oil industry broadly tracked these movements. Industry average domestic oil prices began 2006 Net revenues increased to $119.2 million at $59.53 per barrel and averaged approximately from $66.1 million in the prior year. While the $57.72 per barrel for the year. Profit margins weighted average gross price realized per were strong in the first half of the year, when barrel was $3.52 higher then in 2005, the the industry realized the best domestic netbacks percentage per barrel paid to the government ever. However, in the fourth quarter, due to in the form of production taxes and export rapidly falling export prices combined with the duties in 2006 was 50.18% versus 46.94% in 60-day lag in the reduction of export duties, 2005. As a result, the average net revenues per the entire Russian oil industry suffered from barrel were only modestly higher, $32.81 for a profitability squeeze. 2006 versus $30.22 for 2005. Netback prices are defined as, in the case of crude exports, The Rouble continued to appreciate against the gross sales price less export duty, customs Dollar, rising 4% in the year, which combined charges, marketing costs and transportation; with continued increases in costs for critical and, in the case of domestic crude sales, gross items such as steel and labor, translated in sales price net of VAT. The weighted average higher operating costs. netback for crude oil sales during 2006 was $29.26 versus $29.01 per barrel in 2005. In PRODUCTION AND REVENUES 2006, netbacks for export sales were $29.63 Crude oil production during the year increased per barrel and $28.71 per barrel for domestic by 13% from 3.0 million barrels in 2005 to sales. Netback prices for domestic product 3.4 million barrels in 2006, with average daily sales are defined as gross product sales price production increasing from 5,320 barrels per minus VAT, transportation, excise tax and day in 2005 to 9,200 in 2006. The majority of refining costs. The average products netback for this increase was due to organic development, the year was $47.64 per barrel. with only 566 bopd coming from new properties acquired during the year. Net revenues minus the cost of production was $25.8 million as compared to $14.1 million in During the period the Company’s gross revenues 2005, resulting in an operating profit of $34.1 totalled $169.6 million versus $92.9 million in 2005. million versus $11.3 million in the prior year.
Urals Energy Annual Report and Accounts 2006 11 FINANCIAL RESULTS JANUARY 2006 FEBRUARY MARCH APRIL MAY JUNE JULY AUGUST
Sold $209 million worth of stock in public equity offering
Production costs totalled $92.1 million of the commercial sales value of the natural gas). which $19.8 million represents non-cash items, Adjusting for non-recurring costs and other principally DD&A. Also imbedded in these costs standard non-cash items, the Company’s are $9.3 million of crude purchased from our management-adjusted EBITDA for the period neighbouring operator on Kolguyev Island, GUP was $22.8 million, or 19% of net revenues. AMNGR. Urals Energy purchased this oil from AMNGR and resold it together with its own During Q406 the financial performance produced oil for a modest profit margin, but of the Group was affected by a squeeze a lesser profit margin then it would have had between lower prices and high export duties Urals Energy produced the oil itself. at Petrosakh and Arcticneft. Russian export duties are regressive and are set according to SG&A costs were $28.9 million. The largest a fixed formula and increase as export prices component in SG&A was wages and salaries which increase, however this adjustment is subject to increased year-on-year due to additional personnel a 60-day time lag. The sharp spike in prices in from acquisitions and increased operations. SG&A July and August followed by a steep decline in also includes a number of non-cash expense items, September and October resulted in high export primarily related to the Company’s stock incentive duties versus low export prices at the critical plan, totalling $5.1 million. time when, in early December, the Company had to make its last shipments to clear inventory Interest expense for the period was $9.8 million before the winter sea ice at Petrosakh and as compared to $6.9 million in 2005, as the Arcticneft prevents navigation. The Company Company’s average debt outstanding for the estimates that as a result of this significant period was greater than in 2005. price change and the export tax lag, the negative impact on EBITDA was approximately Net profit for the year attributable to $7.3 million. Wide short-term fluctuations such shareholders was $34.3 million as compared as those seen in 2006 represent a risk for the to $7.1 million in 2005. The largest non-cash Company, as a large portion of its operating item affecting this result is an extraordinary profits are derived from two critical time gain through a negative goodwill charge of windows, early December and late June, when $35.9 million related to our acquisition of the seas are navigable due to the ice-melt, Dulisma. This reflects the excess in fair market and it must make large shipments from these value of the assets purchased above the price operations regardless of the market conditions paid. The method for calculating the fair market value is a conservative discounted cash flow TAXES valuation based on factors known at the time Russia has a relatively high cost tax regime and (not including currently known value attributes the Company pays a variety of taxes that are such as the unified production tax holiday and levied as a result of production, exported oil,
12 Urals Energy Annual Report and Accounts 2006 SEPTEMBER OCTOBER NOVEMBER DECEMBER JANUARY 2007 FEBRUARY MARCH APRIL
Secured working capital revolving debt facility from BNP Paribas
assets and profits. The largest taxes for the CASH FLOW Group as a percentage of total gross revenues For the period, operating cash flow before during 2006 were export duties (28%) and the working capital changes was $22.9 million. unified production tax (21%). The Company paid Net cash generated from operating activities a total of $103.3 million in cash taxes for the improved considerably over the year, year. Unified production taxes are calculated $35.3 million for 2006 versus a loss of $32.2 in based on production revenues and in 2006 the 2005. Capital expenditures for development in Group paid $33.9 million. Looking forward, the 2006 were $59.5 million of which approximately proportion of mineral extraction taxes paid 58% was direct drilling expense. The bulk of overall by the Company will decline dramatically the remaining capital expenditures was for as production from Dulisma increases, where a advanced infrastructure investment at Dulisma, holiday for this tax has been granted through where a total of $16.4 million was spent. The 2016. Export duties are set according to a fixed cost of acquisitions (net cash on hand) during schedule that increases as export prices rise 2006 was $137.3 million, resulting in a total use with a maximum rate of 65% of gross export of cash for investments and acquisitions of prices above $25 per barrel. High export prices $198.6 million. in 2006 resulted in an average export duty for the Company of 41% of gross export revenues, During the course of the year, a net total of and $48.2 million of cash paid. As mentioned $195.1 million in new funds from the sale of above, this tax can be particularly punitive equity was raised. At 31 December 2005, the in rapidly declining crude price scenarios, as Group’s short- and long-term debt was happened in the fall of 2006. VAT payments $81.1 million. During 2006, a total of $14.0 million totalled $3.6 million. in new debt was borrowed and $29.9 million in debt principle repaid. As a result, as of At 31 December 2006, the Group’s deferred tax 31 December 2006, total outstanding debt was liability was $111.8 million. This is a non-cash $63.8 million. liability derived under IFRS methodology by accruing the difference of the fair market value CASH POSITION of the Company’s producing reserves versus The deficit of $163.3 million resulting from the amount actually paid to acquire them. The the difference of cash generated through Company expects this deferred tax liability to operations and cash expenditures for be reflected on its balance sheet indefinitely, investments in assets and acquisitions was and to grow further in the event that Urals funded by the addition of $164.0 million in cash Energy continues to make acquisitions at low from net borrowings, the sale of equity and entry prices. exchange rate changes. This resulted in a change to the cash position of $0.7 million by year end.
Urals Energy Annual Report and Accounts 2006 13 FINANCIAL RESULTS JANUARY 2006 FEBRUARY MARCH APRIL MAY JUNE JULY AUGUST
Agreement signed with Transneft for connection of Dulisma to ESPO
HEDGING FINANCIAL RESULTS SUMMARY The Company does not hedge any of its crude oil Operational Highlights or product sales, costs or currency conversions. •Average 2006 Oil •Average 2006 Netback: Production: 9,569 bopd $30.82/bbl FINANCING -Current: 10,700 bopd¹ -Export crude: $29.63 •Percent of 2006 Crude -Domestic crude: $28.71 In May of 2006 the Company raised net Exports: 55% -Domestic products: $47.64 proceeds of $195.1 million through the sale of $209.0 million worth of equity. The equity Financial Highlights was sold to the public at a price of £3.60 per •Acquisition expenditures: -$12.0 million in $137.3 million (net cash) subordinated debt common share. •Funding raised in 2006: •Funding raised in Jan 2007: -$195.0 million in net -$130 million in project In January of 2006 the Company refinanced the equity proceeds financing for Dulisma $12 million loan outstanding to Bank Zenith with a subordinated 5-year loan from BNP Paribas Summary 2006 and 2005 in US $ thousands 2006 2005 in the same amount. The loan is non-amortizing, Production (yearly average bopd) 9,569 5,263 priced at LIBOR plus 5.00% and had warrants Income Statement attached to it, giving the bank the right to Net revenues 119,197 66,135 purchase up to 2 million shares of common stock IFRS EBITDA 22,773 16,913 at £3.03 per share. In November, the Company Operating profit 34,066 11,348 also secured a revolving $2 million working Net profit / (loss) 34,308 7,055 capital debt facility from ZAO BNP Paribas. 1. Includes shut-in Dulisma production
In January of 2007 the Company borrowed $130 million from Goldman Sachs and Standard Bank. The loan is secured against Dulisma as project financing for its development, and has limited, subordinated recourse to Urals Energy Public Company Limited. It is a four year, non- amortizing loan, priced at LIBOR plus 3.25% with an additional 4.00% PIK. It is callable after two years, and the Company has purchased interest rate swaps for the cash interest over this period.
14 Urals Energy Annual Report and Accounts 2006 SEPTEMBER OCTOBER NOVEMBER DECEMBER JANUARY 2007 FEBRUARY MARCH APRIL
RESERVES Closing of $130 million Dulisma THE COMPANIES RESERVE BASE INCREASED FROM 116 MMBL project loan with Goldman Sachs TO 577 MMBOE, PROVIDING A SUBSTANTIAL PLATFORM FOR PRODUCTION GROWTH.
RESERVES MILLIONS OF BARRELS OF OIL TCF OF AND CONDENSATE GAS MMBOE 2P RESERVES COMPANY PROVED PROBABLE POSSIBLE (2P) (2P) NPV 10% ($MM’S)*
DULISMA 46.7 95.2 29.5 1.9 464 1,013.1
PETROSAKH 8.7 18.0 23.7 0 0 291.5
ARCTICNEFT 21.5 11.5 11.4 0 0 218.3
DINYU 6.6 15.7 25.2 0 0 130.5
CHEPETSKOYE NGDU 8.0 13.2 8.2 0 0 99.5
CNPSEI 5.2 3.9 2.4 0 0 51.3
TOTAL URALS ENERGY 96.7 157.5 100.4 1,9 464 1,804.2
Reserves as at 31 December 2006, except Dulisma as at 31 March 2006 * Net present value discounted at 10% in millions of U.S. dollars.
Urals Energy Annual Report and Accounts 2006 15 JANUARY 2006 FEBRUARY MARCH APRIL MAY JUNE JULY AUGUST
DIRECTORS AND SENIOR MANAGEMENT THE DIRECTORS AND SENIOR MANAGEMENT OF THE COMPANY HAVE SUCCESSFULLY MANAGED BUSINESSES IN THE RUSSIAN OIL SECTOR AND HAVE OVER 50 YEARS OF COMBINED EXPERIENCE. THE MANAGEMENT TEAM HAS EXTENSIVE EXPERIENCE OPERATING LARGE PRODUCING PROPERTIES IN BOTH RUSSIA AND KAZAKHSTAN, AND IS FAMILIAR WITH THE TECHNICAL AND OPERATIONAL CHARACTERISTICS OF RUSSIAN-CIS OILFIELDS.
Left to right: Directors, Leonid Y. Dyachenko, Charles J. Pitman, William R. Thomas
DIRECTORS senior positions including managing operations in Egypt, Oman, Qatar and the former Soviet LEONID Y. DYACHENKO Union. Following Amoco’s merger with BP he DIRECTOR AND CHIEF EXECUTIVE OFFICER was Regional President, Caspian/Middle East/ Mr. Dyachenko is a successful entrepreneur Egypt and India. In 2000, Mr. Pitman was elected and businessman who has a diverse range of to the Board of Apache Corporation. He is also interests including trucking and transportation, owner of Shaker Mountain Energy Associates, pharmaceuticals, and oil trading. He manages LLC, a consulting firm. the Moscow office of Urals Energy LLC and is responsible for day-to-day administration WILLIAM R. THOMAS and government relations for the Company’s NON-EXECUTIVE DIRECTOR Russian subsidiaries. Mr. Dyachenko began Mr. Thomas, 51, has over 25 years experience in his career as a technological engineer with the energy industry as both an executive and construction bureau SALUT. In 1992, he investment banker. He began his career as a was seconded to Dresdner Bank, Frankfurt, roughneck working on land and marine drilling rigs where he completed a management training in Australia, West Texas and Brazil. Mr. Thomas programme in corporate finance. Since then, he joined the International Division of Pennzoil has participated in a number of new businesses, Company in 1982 and later served as International primarily related to commercial trading and Negotiator leading new venture negotiations in export finance. He graduated from Moscow the North Sea, Northern Africa and China. In 1986, Aviation Technology Institute with a degree in he entered investment banking with Bankers Technological Engineering. Mr. Dyachenko is a Trust Company where he spent eight years Russian citizen and is 43 years old. advising energy clients, primarily for upstream mergers & acquisitions. For the past 14 years, CHARLES J. PITMAN Mr. Thomas has focused on the Russian and INTERIM CHAIRMAN OF THE BOARD AND CIS exploration and production business. Since NON-EXECUTIVE DIRECTOR 1993, he has been President & CEO of Siberian Mr. Pitman, 65, a former lawyer and diplomat American Oil Company, Vice President – Commercial with the US Department of State, has Development of Amoco Eurasia Petroleum extensive experience in the oil and gas industry, Company, President & CEO of Nations Energy including 24 years at Amoco Corporation and Company Ltd., and Group Managing Director of BP plc. During this time he held a number of Urals Energy N.V. (a predecessor company).
16 Urals Energy Annual Report and Accounts 2006 SEPTEMBER OCTOBER NOVEMBER DECEMBER JANUARY 2007 FEBRUARY MARCH APRIL
Robert Maguire and Alexei Ogarev appointed to the Board Leonid Dyachenko appointed as CEO, William Thomas to remain as non-executive director on the Board
SENIOR MANAGEMENT URALS ENERGY HAS ASSEMBLED AN IMPRESSIVE GROUP OF SENIOR MANAGERS THAT PROVIDE IT WITH THE BREADTH OF EXPERIENCE AND TALENT TO OPERATE AS A FULLY-INDEPENDENT E&P COMPANY IN RUSSIA. DIVIDED BETWEEN FINANCE AND ACCOUNTING, BUSINESS DEVELOPMENT, LEGAL AND CORPORATE ADMINISTRATION, IT COMPRISES RUSSIANS WITH WESTERN PROFESSIONAL EXPERIENCE AND EDUCATION, AND WESTERN PERSONNEL WITH VAST EXPERIENCE IN RUSSIA AND THE CIS.
STEPHEN M. BUSCHER GRIGORY B. KAZAKOV CHIEF FINANCIAL OFFICER VICE PRESIDENT, FINANCE AND ACCOUNTING
WILLIAM S. HAYES STEPHEN D. KIRTON SENIOR VICE PRESIDENT & GENERAL COUNSEL VICE PRESIDENT, TECHNICAL SERVICES
ALEXEI Y. ANTIPOV VIATCHESLAV A. IVANOV SENIOR VICE PRESIDENT, CORPORATE VICE PRESIDENT, BUSINESS SERVICES DEVELOPMENT
HENRY A. WOLSKI DENIS ISAEV SENIOR VICE PRESIDENT, EXPLORATION DIRECTOR, CRUDE OIL MARKETING AND PRODUCTION
Urals Energy Annual Report and Accounts 2006 17 INDEPENDENT AUDITOR’S REPORT TO THE SHAREHOLDERS AND THE BOARD OF DIRECTORS OF URALS ENERGY PUBLIC COMPANY LIMITED
We have audited the accompanying consolidated financial statements of Urals Energy Public Company Limited and its subsidiaries (the “Group”) which comprise the consolidated balance sheet as of 31 December 2006 and the consolidated statements of income, of changes in equity and of cash flow for the year then ended and a summary of significant accounting policies and other explanatory notes.
MANAGEMENT’S RESPONSIBILITY FOR THE FINANCIAL STATEMENTS Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards. This responsibility includes: designing, implementing and maintaining internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error; selecting and applying appropriate accounting policies; and making accounting estimates that are reasonable in the circumstances.
AUDITOR’S RESPONSIBILITY Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit in accordance with International Standards on Auditing. Those Standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
OPINION In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the financial position of the Group as of 31 December 2006, and of its financial performance and its cash flows for the year then ended in accordance with International Financial Reporting Standards.
ZAO PricewaterhouseCoopers Audit Kosmodamianskaya Nab. 52, Bld. 5 27 April 2007 115054 Moscow Moscow, Russian Federation Russia Telephone +7 (495) 967 6000 Facsimile +7 (495) 967 6001 The firm is an authorized licensee of the tradename and logo of PricewaterhouseCoopers. www.pwc.com
18 Urals Energy Annual Report and Accounts 2006 CONSOLIDATED BALANCE SHEETS (presented in US$ thousands)
31 DECEMBER NOTE 2006 2005 ASSETS CURRENT ASSETS Cash and cash equivalents 33,082 32,334 Accounts receivable and prepayments 5 24,717 21,465 Current income tax prepayments 4,401 1,174 Inventories 6 26,679 12,641 TOTAL CURRENT ASSETS 88,879 67,614
NON-CURRENT ASSETS Property, plant and equipment 7 595,800 287,485 Other non-current assets 8 16,073 3,247 Total non-current assets 611,873 290,732 TOTAL ASSETS 700,752 358,346
LIABILITIES AND EQUITY CURRENT LIABILITIES Accounts payable and accrued expenses 9 10,033 7,932 Income tax payable 3,281 6,039 Other taxes payable 10 7,253 3,461 Other taxes provision 2,367 1,987 Short-term borrowings and current portion of long-term borrowings 11 22,965 34,117 Advances from customers 9 30,913 523 Current liabilities before warrants classified as liabilities 76,812 54,059 Warrants classified as liabilities 11 3,516 - TOTAL CURRENT LIABILITIES 80,328 54,059
LONG-TERM LIABILITIES Long-term borrowings 11 40,844 47,005 Long term finance lease obligations 1,192 1,357 Dismantlement provision 12 3,327 813 Deferred tax liability 10 111,787 51,100 Other long term liabilities 298 580 TOTAL LONG-TERM LIABILITIES 157,448 100,855
TOTAL LIABILITIES 237,776 154,914
EQUITY Share capital 13 633 460 Share premium 13 401,448 201,355 Translation difference 22,445 (2,296) Retained earnings 37,022 2,714 EQUITY ATTRIBUTABLE TO SHAREHOLDERS OF URALS ENERGY PUBLIC COMPANY LIMITED 461,548 202,233 MINORITY INTEREST 1,428 1,199 TOTAL EQUITY 462,976 203,432
TOTAL LIABILITIES AND EQUITY 700,752 358,346
MEMORANDUM NOTE: Total equity 462,976 203,432 Warrants 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
Urals Energy Annual Report and Accounts 2006 19 CONSOLIDATED INCOME STATEMENT (presented in US$ thousands)
YEAR ENDED 31 DECEMBER NOTE 2006 2005 REVENUES Gross revenues 14 169,590 92,918 Less: excise taxes (2,176) (530) Less: export duties (48,217) (26,253)
NET REVENUES 119,197 66,135
OPERATING COSTS Cost 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 1,359 913 Interest 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) -
PROFIT BEFORE INCOME TAX 31,138 4,496 Income 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 to shareholders 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 105,099,777 59,915,473 -Diluted 108,051,649 59,939,038
20 Urals Energy Annual Report and Accounts 2006 CONSOLIDATED STATEMENTS OF CASH FLOWS (presented in US$ thousands)
YEAR ENDED 31 DECEMBER 2006 2005 CASH FLOWS FROM OPERATING ACTIVITIES Profit before income tax 31,138 4,496 Adjustments 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 30,390 523 Increase (decrease) in other taxes payable 5,622 (785)
CASH GENERATED FROM (USED IN) OPERATIONS 46,905 (27,612) Interest received 1,190 913 Interest paid (8,900) (2,685) Income tax paid (3,890) (2,862)
NET CASH GENERATED FROM (USED IN) OPERATING ACTIVITIES 35,305 (32,246)
CASH FLOWS FROM INVESTING ACTIVITIES Acquisitions 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 ACTIVITIES Proceeds from borrowings 14,000 101,412 Repayment 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 13 195,052 143,100 NET CASH GENERATED FROM FINANCING ACTIVITIES 163,724 187,795
Effect of exchange rate changes on cash and cash equivalents 328 (49)
NET INCREASE IN CASH AND CASH EQUIVALENTS 748 30,913 Cash and cash equivalents at the beginning of the year 32,334 1,421
CASH AND CASH EQUIVALENTS AT THE END OF THE YEAR 33,082 32,334
Urals Energy Annual Report and Accounts 2006 21 CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY (presented in US$ thousands)
EQUITY ATTRIBUTABLE TO SHAREHOLDERS OF URALS RETAINED ENERGY CUMULATIVE EARNINGS PUBLIC SHARE SHARE UNPAID TRANSLATION (ACCUMULATED COMPANY MINORITY TOTAL NOTES CAPITAL PREMIUM CAPITAL ADJUSTMENT DEFICIT) LIMITED INTEREST EQUITY BALANCE AT 1 JANUARY 2005 209 42,172 (11,324) 1,264 (4,341) 27,980 1,327 29,307
Effect of currency translation (3,560) - (3,560) (46) (3,606) Profit for the year - 7,055 7,055 (82) 6,973
Total recognized income (loss) (3,560) 7,055 3,495 (128) 3,367
Issuance of shares 13 251 159,141 11,324 - - 170,716 - 170,716 Share-based payment 13 - 42 - - - 42 - 42
BALANCE AT 31 DECEMBER 2005 460 201,355 - (2,296) 2,714 202,233 1,199 203,432
Effect of currency translation 24,741 - 24,741 115 24,856 Profit for the year - 34,308 34,308 114 34,422
Total recognized income (loss) 24,741 34,308 59,049 229 59,278
Issuance of shares 13 173 194,879 - - - 195,052 - 195,052 Exercise of options 13 - 125 - - - 125 - 125 Share-based payment 13 - 5,089 - - - 5,089 - 5,089
BALANCE AT 31 DECEMBER 2006 633 401,448 - 22,445 37,022 461,548 1,428 462,976
22 Urals Energy Annual Report and Accounts 2006 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (presented in US$ thousands)
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 and gas exploration and production in the Russian Federation and processing of crude oil for distribution on both the Russian and international markets.
The registered office of Urals Energy is at 31 Evagoras Avenue, Suite 34, CY-1066, Nicosia, Cyprus. The Group’s primary office is located at 11 Osennaya Ul. Moscow, 121609, Russian Federation.
The Group comprises the following subsidiaries: EFFECTIVE OWNERSHIP INTEREST AT 31 DECEMBER ENTITY JURISDICTION 2006 2005 EXPLORATION AND PRODUCTION ZAO 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 COMPANY OOO Urals Energy Moscow 100.0% 100.0% Urals Energy (UK) Limited United Kingdom 100.0% 100.0%
EXPLORATION OOO Urals-Nord (“Urals-Nord”) Nenetsky 100.0% 100.0%
TRADING UENEXCO Limited (“UENEXCO”) Cyprus 100.0% 100.0% UENEXCO Limited only operated during first quarter of 2006 after which all trading operations were transferred to UEPCL.
2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PREPARATION. These consolidated financial statements have been prepared in accordance with, and comply with, International Financial Reporting Standards (“IFRS”). The consolidated financial statements have been prepared under the historical cost convention as modified by change in fair value of warrants classified as liabilities. The preparation of consolidated financial statements in conformity with IFRS requires management to make prudent estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements preparation and the reported amounts of revenues and expenses during the reporting period. These policies have been consistently applied to all the periods presented, unless otherwise stated. Critical accounting estimates and judgments are disclosed in Note 3. Actual results could differ from the estimates.
These consolidated financial statements also include all disclosures necessary for compliance with the relevant sections of the Cyprus Companies Law Cap 133.
FUNCTIONAL AND PRESENTATION CURRENCY. The United States Dollar (“US dollar or US$ or $”) is the presentation currency for the Group’s operations as the majority of the Company’s operations is conducted in US dollars and management have used the US dollar accounts to manage the Group’s financial risks and exposures, and to measure its performance.
Urals Energy Annual Report and Accounts 2006 23 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (presented in US$ thousands)
Financial statements of the Russian subsidiaries are measured in Russian Roubles and presented in US dollars in accordance with IAS 21 (revised 2003), The Effects of Changes in Foreign Exchange Rates.
TRANSLATION TO FUNCTIONAL CURRENCY. Monetary balance sheet items denominated in foreign currencies have been remeasured using the exchange rate at the respective balance sheet date. Exchange gains and losses resulting from foreign currency translation are included in the determination of profit or loss. The US dollar to Russian Rouble exchange rates were 26.33 and 28.78 as of 31 December 2006 and 2005, respectively.
TRANSLATION TO PRESENTATION CURRENCY. The results and financial position of each group entity (the functional currency of none of which is a currency of a hyperinflationary economy) are translated into the presentation currency as follows: (i) Assets and liabilities for each balance sheet presented are translated at the closing rate at the date of that balance sheet. Goodwill and fair value adjustments arising on the acquisitions are treated as assets and liabilities of the acquired entity. (ii) Income and expenses for each income statement are translated at average exchange rates (unless this average is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the dates of the transactions). (iii) All resulting exchange differences are recognised as a separate component of equity.
When a subsidiary is disposed of through sale, liquidation, repayment of share capital or abandonment of all, or part of, that entity, the exchange differences deferred in equity are reclassified to profit or loss.
GROUP ACCOUNTING. Subsidiaries, which are those entities in which the Group has an interest of more than one half of the voting rights, or otherwise has power to exercise control over the operations, are consolidated. Subsidiaries are consolidated from the date on which control is transferred to the Group and are no longer consolidated from the date that control ceases. The purchase method of accounting 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 consideration provided or liabilities incurred or assumed at the date of exchange plus costs directly attributable to the acquisition.
All intercompany transactions, balances and unrealised gains on transactions between group companies are eliminated; unrealised losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred.
Minority interest at the balance sheet date represents the minority shareholders’ portion of the fair values of the identifiable assets, liabilities and contingent liabilities of the subsidiary at the acquisition date, and the minorities’ portion of movements in equity since the date of the combination. Minority interest is presented as a separate component of equity. Where the losses applicable to the minority in a consolidated subsidiary exceed the minority interest in the equity of the subsidiary, the excess and any further losses applicable to the minority are charged against the majority interest except to the extent that the minority has a binding obligation to, and is able to, make good the losses. If the subsidiary subsequently reports profits, the majority interest is allocated all such profits until the minority’s share of losses previously absorbed by the majority has been recovered.
PROPERTY, PLANT AND EQUIPMENT. Property, plant and equipment acquired as part of a business combination is recorded at fair value at the acquisition date. All subsequent additions are recorded at historical cost of acquisition or construction and adjusted for accumulated depreciation, depletion and impairment. Oil and gas exploration and production activities are accounted for in a manner similar to the successful efforts method. Costs of successful development and exploratory wells are capitalised.
24 Urals Energy Annual Report and Accounts 2006 The Group accounts for exploration and evaluation activities in accordance with IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizing exploration and evaluation costs until such time as the economic viability of producing the underlying resources is determined. Exploration and evaluation costs related to resources determined to be not economically viable are expensed through cost of production in the consolidated income statement. Other exploration costs are expensed as incurred.
Depletion of capitalized costs of proved oil and gas properties is calculated using the unit-of-production method for each field based upon proved reserves for property acquisitions and proved developed reserves for exploration and development costs. Oil and gas reserves for this purpose are determined in accordance with Society of Petroleum Engineers definitions and were estimated by DeGolyer and MacNaughton, the Group’s independent reservoir engineers. Gains or losses from retirements or sales of oil and gas properties are included in the determination of profit for the year.
Depreciation of non oil and gas property, plant and equipment is calculated using the straight-line method over their estimated remaining useful lives, as follows:
ESTIMATED USEFUL LIFE Refinery and related equipment 19 Buildings 20 Other assets 6 to 20
INTANGIBLE ASSETS. All of the Group’s other intangible assets have definite useful lives and primarily include capitalised computer software and licences.
Acquired computer software licenses and patents are capitalised on the basis of the costs incurred to acquire and bring them to use.
Development costs that are directly associated with identifiable and unique software controlled by the Group are recorded as intangible assets if inflow of incremental economic benefits exceeding costs is probable. Capitalised costs include staff costs of the software development team and an appropriate portion of relevant overheads. All other costs associated with computer software, eg its maintenance, are expensed when incurred. Intangible assets are amortised using the straight-line method over their useful lives:
ESTIMATED USEFUL LIFE Software licences 3 Capitalised internal software development costs 3 Other licences 5 to 7
PROVISIONS. Provisions are recognised when the Group has a present legal or constructive obligation as a result of past events and when it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation, and a reliable estimate of the amount of the obligation can be made.
Provisions, including those related to dismantlement, abandonment and site restoration, are evaluated and re-estimated annually, and are included in the financial statements at each balance sheet date at their expected net present values using discount rates which reflect the economic environment in which the Group operates.
Urals Energy Annual Report and Accounts 2006 25 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (presented in US$ thousands)
Changes in provisions resulting from the passage of time are reflected in the statement of income each year under financial items. Other changes in provisions, relating to a change in the expected pattern of settlement of the obligation, changes in the discount rate or in the estimated amount of the obligation, are treated as a change in accounting estimate in the period of the change.
The provision for dismantlement liability is recorded on the balance sheet, with a corresponding amount being recorded as part of property, plant and equipment in accordance with IAS 16.
LEASES. Leases of property, plant and equipment where the Group has substantially all the risks and rewards of ownership are classified as finance leases. Finance leases are capitalised at the commencement of the lease at the lower of the fair value of the leased property or the present value of the minimum lease payments. Each lease payment is allocated between the liability and finance charges so as to achieve a constant rate on the finance balance outstanding. The corresponding rental obligations, net of finance charges, are included in other long-term payables. The interest element of the finance cost is charged to the income statement over the lease period. The property, plant and equipment acquired under finance leases are depreciated over the shorter of the useful life of the asset or the lease term, with the comparison being made based on the current annual extraction level.
Leases in which a significant portion of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Payments made under operating leases (net of any incentives received from the lessor) are charged to the income statement on a straight-line basis over the period of the lease.
IMPAIRMENT OF ASSETS. Assets that are subject to depreciation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the 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 sell or value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash-generating units).
INVENTORIES. Inventories of extracted crude oil, materials and supplies and construction equipment are valued at the lower of the weighted-average cost and net realisable value. General and administrative expenditure is excluded from inventory costs and expensed in the period incurred.
TRADE RECEIVABLES. Trade receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method, net of provision for impairment. A provision for impairment of trade receivables is established when there is objective evidence that the Group will not be able to collect all amounts due according to the original terms of receivables. The amount of the provision is the difference between the asset’s carrying amount and the present value of estimated future cash flows, discounted at the effective interest rate. The amount of the provision is recognised in the income statement.
CASH AND CASH EQUIVALENTS. Cash and cash equivalents include cash in hand and deposits held at call with banks. Cash and cash equivalents are carried at amortised cost using the effective interest method.
VALUE ADDED TAX. Value added taxes related to sales are payable to tax authorities upon collection of receivables from customers. Input VAT is reclaimable against sales VAT upon payment for purchases. The tax authorities permit the settlement of VAT on a net basis. VAT related to sales and purchases which have not been settled at the
26 Urals Energy Annual Report and Accounts 2006 balance sheet date (VAT deferred) is recognised in the balance sheet on a gross basis and disclosed separately as a current asset and liability. Where provision has been made against debtors deemed to be uncollectible, an impairment loss is recorded for the gross amount of the debtor, including VAT. The related VAT deferred liability is maintained until the debtor is written off for statutory accounting purposes.
BORROWINGS. Borrowings are recognised initially at the fair value of the liability, net of transaction costs incurred. In subsequent periods, borrowings are stated at amortised cost using the effective yield method; any difference between amount at initial recognition and the redemption amount is recognised as interest expense over the period of the borrowings. Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least 12 months after the balance sheet date. Interest costs on borrowings to finance the construction of property, plant and equipment are capitalised, during the period of time that is required to complete and prepare the asset for its intended use. Borrowing costs are recognised as an expense on a time proportion basis using the effective interest method.
LOANS RECEIVABLE. The loans advanced by the Group are classified as “loans and receivables” in accordance with IAS 39 and stated at amortised cost using the effective interest method.
DEFERRED INCOME TAXES. Deferred income tax is calculated at rates enacted or substantially enacted at the balance sheet date, using the balance sheet liability method, for all temporary differences between the tax bases of assets and liabilities and their carrying values for financial reporting purposes. The principal temporary differences arise from depreciation on property, plant and equipment, provisions, fair value adjustments to long-term items, and expenses which are charged to the income statement before they become deductible for tax purposes.
Deferred income tax assets attributable to deducible temporary differences, unused tax losses and credits are recognised only to the extent that it is probable that future taxable profit or taxable temporary differences will be available against which they can be utilised.
Deferred income tax assets and liabilities are offset when the Group has a legally enforceable right to set off current tax assets against current tax liabilities, when deferred tax balances relate to the same regulatory body, and when they relate to the same taxable entity.
SOCIAL COSTS. The Group incurs employee costs related to the provision of benefits such as health insurance. These amounts principally represent an implicit cost of employing production workers and, accordingly, have been charged to income statement.
PENSION COSTS. The Group makes required contributions to the Russian Federation state pension scheme on behalf of its employees. Mandatory contributions to the governmental pension scheme are expensed or capitalized to inventories on a basis consistent with the associated salaries and wages.
REVENUE RECOGNITION. Revenues are recognised when crude oil or refined products are dispatched to customers and title has transferred. Revenues from non-cash sales are recognised at the fair value of the goods or services received. Gross revenues include export duties and excise taxes but exclude value added taxes.
SEGMENTS. The Group operates in one business segment which is crude oil exploration and production. The Group assesses
Urals Energy Annual Report and Accounts 2006 27 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (presented in US$ thousands) its results of operations and makes its strategic and investment decisions based on the analysis of its profitability 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 the Group’s stock are recorded at fair value at issuance and recorded as liabilities unless the number of equity instruments to be issued to settle the warrants and the exercise price are fixed in the issuing entities’ functional currency at the time of grant, in which case they are recorded within shareholders’ equity. Changes in the fair value of warrants recorded as liabilities are recorded in the income statement.
SHARE CAPITAL. Ordinary shares are classified as equity. Incremental costs directly attributable to the issue of new shares are shown in equity as a deduction, net of tax, from the proceeds. Any excess of the fair value of consideration received over the par value of shares issued is presented in the notes as a share premium.
SHARE-BASED PAYMENTS. The fair value of equity instruments granted is evaluated at the measurement date, based on market prices if available, taking into account the terms and conditions upon which those equity instruments were granted. If market prices are not available, the fair value of the equity instruments granted is estimated using a valuation technique to estimate what the price of those equity instruments would have been on the measurement date in an arm’s length transaction between knowledgeable, willing parties.
EARNINGS PER SHARE. Earnings per share is determined by dividing the profit or loss attributable to equity holders of the Group by the weighted average number of participating shares outstanding during the reporting year.
ADOPTION OF NEW OR REVISED STANDARDS AND INTERPRETATIONS. New or amended standards and interpretations adopted by the Group from 1 January 2006 are discussed below. None of the adoptions had a material impact on the Group’s financial position or results of operations.
IAS 39 (Amendment), The Fair Value Option; IAS 39 (Amendment), Cash Flow Hedge Accounting of Forecast Intragroup Transactions; IAS 39 (Amendment), Financial Guarantee Contracts. The amendments to IAS 39 clarified the use of the fair value through profit or loss category of financial instruments and clarified the accounting for financial guarantees as either insurance contracts or financial instruments.
IAS 21 (Amendment), Net Investment in a Foreign Operation. This amendment requires foreign exchange gains and losses on monetary items that form part of net investment in a foreign operation to be reported in consolidated equity even if the loans are not in the functional currency of either the lender or the borrower. Previously, such exchange differences were required to be recognised in consolidated profit or loss.
IAS 19 (Amendment), Employee Benefits. The amendment to IAS 19 introduces an additional recognition option for actuarial gains and losses in post-employment defined benefit plans.
IFRS 1 (Amendment), First-time Adoption of International Financial Reporting Standards and IFRS 6 (Amendment), Exploration for and Evaluation of Mineral Resources. The amendments to IFRS 1 and IFRS 6 provided limited relief to first-time adopters of IFRS with respect to the provisions of IFRS 6.
IFRIC 4, Determining whether an Arrangement contains a Lease (“IFRIC 4”). IFRIC 4 provides guidance on how to determine whether an arrangement contains a lease as defined in IAS 17, Leases, on when the assessment or reassessment of an arrangement should be made and on how lease payments should be separated from any other elements in the arrangement.
28 Urals Energy Annual Report and Accounts 2006 IFRIC 5, Rights to Interests arising from Decommissioning, Restoration and Environmental Rehabilitation Funds (“IFRIC 5”). IFRIC 5 provides guidance on the accounting for interests in decommissioning funds.
IFRIC 6, Liabilities arising from Participating in a Specific Market – Waste Electrical and Electronic Equipment (“IFRIC 6”). IFRIC 6 addresses the accounting for liabilities under an EU Directive on waste management for sales of household equipment.
NEW ACCOUNTING PRONOUNCEMENTS. Certain new standards and interpretations have been published that are mandatory for the Group’s accounting periods beginning on or after 1 January 2007 or later periods and which the entity has not early adopted:
IFRS 7, Financial Instruments: Disclosures and a complementary Amendment to IAS 1 Presentation of Financial Statements - Capital Disclosures (effective from 1 January 2007). The IFRS introduces new disclosures to improve the information about financial instruments. The volume of disclosures will increase significantly with an emphasis on quantitative aspects of risk exposures and the methods of risk management. The quantitative disclosures will provide information about the extent to which the entity is exposed to risk, based on information 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 and Similar Financial Institutions, and some of the requirements in IAS 32, Financial Instruments: Disclosure and Presentation. The Amendment to IAS 1 introduces disclosures about level of an entity’s capital and how it manages capital. The Group is currently assessing what impact the new IFRS and the amendment to IAS 1 will have on disclosures in its financial statements.
IFRS 8, Operating Segments (effective for annual periods beginning on or after 1 January 2009). The Standard applies to entities whose debt or equity instruments are 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 of issuing any class of instruments in a public market. IFRS 8 requires an entity to report financial and descriptive information about its operating segments and specifies how an entity should report such information. Management does not expect IFRS 8 to affect the Group’s financial statements.
OTHER NEW STANDARDS OR INTERPRETATIONS. The Group has not early adopted the following other new standards or interpretations: IFRIC 7, Applying the Restatement Approach under IAS 29 (effective for periods beginning on or after 1 March 2006, that is from 1 January 2007); IFRIC 8, Scope of IFRS 2 (effective for periods beginning on or after 1 May 2006, that is from 1 January 2007); IFRIC 9, Reassessment of Embedded Derivatives (effective for annual periods beginning on or after 1 June 2006); IFRIC 10, Interim Financial Reporting and Impairment (effective for annual periods beginning on or after 1 November 2006); IFRIC 11, IFRS 2—Group and Treasury Share Transactions (effective for annual periods beginning on or after 1 March 2007); IFRIC 12, Service Concession Arrangements (effective for annual periods beginning on or after 1 January 2008). Unless otherwise described above, these new standards and interpretations are not expected to significantly affect the Group’s financial statements.
Urals Energy Annual Report and Accounts 2006 29 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (presented in US$ thousands)
RECLASSIFICATIONS. Certain reclassifications have been made to 2005 amounts to conform to 2006 presentation. The table below discloses the adjusted amounts before and after the reclassifications. Management believes that the current presentation is preferable to that presented in prior years. AS ORIGINALLY FOLLOWING REPORTED RECLASSIFICATION AT 31 DECEMBER 2005 Other non-current assets 2,098 3,247 Accounts receivable and prepayments 23,788 21,465 Current income tax prepayments - 1,174 Other taxes payable 5,448 3,461 Other taxes provision - 1,987
FOR THE YEAR ENDED 31 DECEMBER 2005 Selling, 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 accounts receivable and prepayments to other non-current assets, primarily to record advances to contractors and suppliers for capital construction projects. Current income tax prepayments as of $1.174 million were separated from accounts receivable and prepayments.
At 31 December 2005, other taxes provision as of $1.987 was separated from other taxes payable.
For the year ended 31 December 2005, selling, general and administrative expenses 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 disposal of 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 tax benefit.
3 CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS IN APPLYING ACCOUNTING POLICIES
The Group makes estimates and assumptions that affect the reported amounts of assets and liabilities. Estimates and judgements are continually evaluated and are based on management’s experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Management also makes certain judgements, apart from those involving estimations, in the process of applying the accounting policies. Judgments that have the most significant effect on the amounts recognised in the financial statements and estimates that can cause a significant adjustment to the carrying amount of assets and liabilities are outlined below.
ACCOUNTING FOR EXTRACTIVE INDUSTRY ACTIVITY. The Group follows the successful efforts method of accounting for oil and gas properties. Under the successful efforts method, property acquisitions, successful exploratory wells, all development costs and support equipment and facilities are capitalised. Unsuccessful exploratory wells are charged to expense at the time the wells are determined to be non-productive. Production costs, overhead and all exploration costs other than exploratory drilling are charged to expense as incurred. Acquisition costs of unproved properties, exploration and evaluation costs are evaluated periodically and any impairment assessed is charged to expense.
30 Urals Energy Annual Report and Accounts 2006 The Group calculates depreciation, depletion and amortisation of capitalised costs of oil and gas properties using the unit-of-production method for each field based upon proved developed reserves for exploration and development costs, and total proved reserves for acquisitions of proved properties. For this purpose, the oil and gas reserves of key fields have been determined based on estimates of mineral reserves determined in accordance with internationally recognised definitions and independently assessed by internationally recognised petroleum engineers. The present value of the estimated costs of dismantling oil and gas production facilities, including abandonment and site restoration costs are recognised when the obligation is incurred and are included within the carrying value of property, plant and equipment, and therefore subject to amortisation thereon using the unit-of-production method. Changes in estimates of reserves can result in significant changes in depletion expense.
RELATED PARTY TRANSACTIONS. In the normal course of business, the Group enters into transactions with its related parties. Judgement is applied in determining if transactions are priced at market or non-market interest rates, where there is no active market for such transactions. The basis for judgement is pricing for similar types of transactions with unrelated parties and effective interest rate analyses.
ASSUMPTIONS TO DETERMINE AMOUNT OF PROVISIONS. In determining amounts of provisions, management uses all information available to determine whether it is probable that an event will result in outflows of resources from the Group. Significant judgment is used to estimate the amounts of provisions, including such factors as the current overall economic conditions, specific customer, counterparty or industry conditions and the current overall legal and tax environment. Changes in any of these conditions may result in adjustments to provisions recorded by the Group.
USEFUL LIVES OF PROPERTY, PLANT AND EQUIPMENT. Items of property, plant and equipment are stated at cost less accumulated depreciation. The estimation of the useful life of an item of property, plant and equipment is a matter of management judgment based upon experience with similar assets. In determining the useful life of an asset, management considers the expected usage, estimated technical obsolescence, physical wear and tear and the physical environment in which the asset is operated. Changes in any of these conditions or estimates may result in adjustments to future depreciation rates.
FAIR VALUES OF ACQUIRED ASSETS AND LIABILITIES. Since its inception, the Group has completed several significant acquisitions (Note 4). IFRS 3 requires that, at the date of acquisition, all identifiable assets (including intangible assets), liabilities and contingent liabilities of an acquired entity be recorded at their respective fair values. The estimation of fair values requires management judgment. For significant acquisitions, management engages independent experts to advise as to the fair values of acquired assets and liabilities. Changes in any of the estimates subsequent to the finalization of acquisition accounting may result in losses in future periods.
TAX LEGISLATION. Russian tax, currency and customs legislation is subject to varying interpretation. Refer to Note 18.
4 ACQUISITIONS
ACQUISITION OF OOO OIL COMPANY DULISMA AND OOO LENSKAYA TRANSPORTNAYA KOMPANIYA. In April 2006, the Group acquired 100% stakes in OOO Oil Company Dulisma (“Dulisma”) and OOO Lenskaya Transportnaya Kompaniya (“LTK”) for $136 million, net of assumed debt of $15.1 million. Dulisma holds exploration and production licenses in Irkutsk expiring in 2019. A net loss of $2.4 million associated with Dulisma and LTK were included in the Group’s results for the year ended 31 December 2006.
Urals Energy Annual Report and Accounts 2006 31 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (presented in US$ thousands)
The table below presents the fair values of 100% of Dulisma’s and LTK’s assets and liabilities as of the date of acquisition. No information on the IFRS carrying values before the acquisition is available as Dulisma and LTK did not prepare IFRS financial statements prior to acquisition.
FAIR VALUES AT ACQUISITION Cash and cash equivalents 61 Accounts receivable and prepayments 2,842 Other current assets 1,378 Oil and gas properties and equipment 241,711 Short-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 171,332 Excess of the Group’s share in net assets over purchase consideration (35,448) PURCHASE CONSIDERATION SHARE IN NET ASSETS ACQUIRED 135,884 Less: 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 and LTK are property acquisition costs with a fair value of $153.1 million that are not subject to depletion pending the results of management’s assessment of the economic viability of the properties. Additionally, included within oil and gas properties and equipment acquired with Dulisma and LTK are property acquisition costs with a fair value of $35.4 million that are being depleted over total proved reserves.
Management attributes the excess of the Group’s share in net assets acquired over purchase consideration to the foreign seller’s interest in exiting the Russian market and its lack of interest in investing the required resources to develop the license as well as uncertainties over the timing and conditions for using the planned pipeline connecting Dulisma’s operations to commercial markets.
The remaining amount of $0.447 million of excess of net assets acquired over purchase price relates to the acquisition of OOO Nizhneomrinskaya Neft, an entity extracting crude oil, for a total consideration of $3.532 million. The cash and cash equivalents of subsidiary acquired is $2.056 million as of the date of acquisition.
SUMMARY COMBINED FINANCIAL INFORMATION. The following table sets forth summary combined financial information for the year ended 31 December 2006 that is presented to provide information to evaluate the financial effects of the acquisitions 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) 171,012 Profit (loss) for the year 34,422 (2,904) 2,449 33,967
The summary combined financial information should not be construed to represent consolidated financial information. Group results include the activities of the acquired entities from the respective acquisition dates through 31 December 2006. Total revenues and profit (loss) for the period for Dulisma and LTK comprise the respective entities’ results for the full year, including the period prior to acquisition, without adjustments for intercompany transactions or fair values. Adjustments and eliminations include the following: (a) intercompany
32 Urals Energy Annual Report and Accounts 2006 eliminations were recorded; (b) adjustments to eliminate results of the period included both in the Group results and the respective entities’ results for the full year; and (c) corresponding adjustments for income taxes were recorded. However, no adjustments were made to adjust interest expense for borrowings used to finance these acquisitions.
ACQUISITION OF DINYU. In November 2005, the Group acquired a 100.0% stake in Dinyu from Lonsdacks Investments Limited for $61.5 million, net of debt assumed of $8.5 million, following the approval from the Russian Federal Antimonopoly Service.
Subsequent to its purchase of Dinyu, in December 2005, the Group purchased the 35% stake owned by third parties in Dinyu’s 65% owned subsidiary, OOO Michayuneft (“Michayuneft”) for $0.2 million.
ACQUISITION OF ARCTICNEFT. In July 2005, the Group acquired a 100.0% equity interest in Arcticneft from OAO LUKoil for $23 million, net of debt assumed of $13 million. Arcticneft holds production licenses in the Nenetsky Autonomous Region of the Russian Federation.
Management’s purchase accounting allocation resulted in an excess of $16.8 million of net identifiable assets and oil and gas properties and equipment over the purchase price. Management believes that this amount is attributed to the seller’s undervaluing of Arcticneft and its desire to dispose of non-core assets. The associated gain was recorded in the Group’s consolidated income statement for the year ended 31 December 2005.
ACQUISITION OF URALS-NORD. In April 2005, the Company acquired the remaining 50.0% interest in OOO Urals-Nord (“Urals-Nord”) for $14 million. The Group incurred $0.84 million of additional cost related to seismic review of the license areas. Urals-Nord holds 5 exploration licenses for Beluginisky, Zapadno-Sorokinskiy, Fakelniy, Nadezhdinskiy and Alfinskiy prospects. Urals-Nord has been consolidated from the date of acquisition. Management believes that the purchase price for Urals-Nord approximates the fair value of unproved oil and gas properties acquired. Such unproved oil and gas properties are included within property, plant and equipment in the consolidated balance sheet. No goodwill was recognized in the acquisition.
5 ACCOUNTS RECEIVABLE AND PREPAYMENTS
31 DECEMBER 2006 2005 Trade accounts and notes receivable (net of allowances of $0.640 million and $0.586 million at 31 December 2006 and 2005, respectively) 1,755 7,871 Prepaid taxes 759 3,234 Advances to suppliers 4,857 2,723 Recoverable taxes including VAT 12,236 3,503 Receivables from related parties (Note 20) 2,897 2,805 Other 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 $10.947 million at 31 December 2006 and 2005, respectively, are denominated in US dollars.
Urals Energy Annual Report and Accounts 2006 33 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (presented in US$ thousands)
6 INVENTORIES 31 DECEMBER 2006 2005 Crude oil 6,910 3,252 Petroleum products 1,700 1,590 Materials and supplies (net of allowances of $1.217 million and $0.854 million at 31 December 2006 and 2005, respectively) 18,069 7,799 TOTAL INVENTORIES 26,679 12,641
7 PROPERTY, PLANT AND EQUIPMENT
REFINERY OIL AND GAS AND RELATED OTHER ASSETS UNDER PROPERTIES EQUIPMENT BUILDINGS ASSETS CONSTRUCTION TOTAL COST AT 1 JANUARY 2005 87,388 8,684 989 3,772 2,458 103,291 Translation difference (5,129) (315) (41) (154) (219) (5,858) Business combinations 172,110 615 1,100 650 5,405 179,880 Additions 4,697 - - 209 15,812 20,718 Capitalised borrowing costs (Note 11) - - - - 640 640 Transfers 8,053 - - 964 (9,017) - Changes in estimates of dismantlement provision (Note 12) (765) - - - - (765) 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 41,380 Business combinations 209,473 - 2,629 1,216 31,437 244,755 Additions 5,060 - - - 39,546 44,606 Capitalised borrowing costs (Note 11) - - - - 861 861 Transfers 28,322 57 59 4,729 (33,167) - Changes in estimates of dismantlement provision (Note 12) 146 - - - - 146 Disposals (2,112) - - (1,055) (1,176) (4,343) 31 DECEMBER 2006 542,060 9,879 5,066 10,362 57,092 624,459
34 Urals Energy Annual Report and Accounts 2006 REFINERY OIL AND GAS AND RELATED OTHER ASSETS UNDER PROPERTIES EQUIPMENT BUILDINGS ASSETS CONSTRUCTION TOTAL ACCUMULATED DEPRECIATION AT 1 JANUARY 2005 (519) - - (18) - (537) Translation difference 128 8 4 10 - 150 Depreciation, depletion and amortization (8,044) (510) (226) (614) - (9,394) Disposals 118 - - 94 - 212 31 DECEMBER 2005 (8,317) (502) (222) (528) - (9,569)
Translation difference (1,312) (64) (33) (71) - (1,480) Depreciation, depletion and amortization (16,950) (518) (380) (1,034) - (18,882) Disposals 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 were exploration and evaluation assets of $322.9 million and $140.5 million, respectively. Additions to exploration and evaluation assets in 2006 and 2005 totalled $159.1 million and $135.9 million, respectively, including $153.1 million and $129.4 million as a result of business combinations. Transfers from exploration and evaluation assets to producing properties totalled $4 million and nil in 2006 and 2005, respectively. The remaining movements in exploration and evaluation assets relate to currency differences. During the years ended 31 December 2006 and 2005, no exploration and evaluation costs were recognized in the Group’s consolidated income statement and investing cash flows, other than business combinations, related to exploration and evaluation assets totalled $6 million and $6.5 million respectively.
The Group’s oil fields are situated in the Russian Federation on land owned by the Russian government. The Group holds licenses and associated mining plots and pays production taxes to extract oil and gas from the fields. The licenses expire between 2008 and 2067, but may be extended. Management intends to renew the licences as the properties are expected to remain productive subsequent to the license expiration date.
Estimated costs of dismantling oil and gas production facilities, including abandonment and site restoration costs, amounting to $2.3 million and $0.020 million at 31 December 2006 and 2005, respectively, are included in the cost of oil and gas properties. The Group has estimated its liability based on current environmental legislation using estimated costs when the expenses are expected to be incurred.
At 31 December 2006 and 2005, property, plant and equipment with carrying net book value of $134.4 million and $90.2 million, respectively, was pledged as collateral for the Group’s borrowings.
8 OTHER NON-CURRENT ASSETS 31 DECEMBER 2006 2005 Advances to contractors and suppliers 12,474 1,177 Intangible assets 1,141 - Other deferred costs 2,458 2,070 TOTAL OTHER NON-CURRENT ASSETS 16,073 3,247
Urals Energy Annual Report and Accounts 2006 35 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (presented in US$ thousands)
9 ACCOUNTS PAYABLE AND ACCRUED EXPENSES 31 DECEMBER 2006 2005 Trade payables 5,991 2,809 Interest payable 15 833 Wages and salaries 1,167 806 Advances from and payables to related parties (Note 20) - 74 Other 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 US dollars.
ADVANCES FROM CUSTOMERS. In December 2006, the Group received an advance of $30.2 million denominated in US dollars from Petraco Oil Company Limited for crude oil sales volumes from Petrosakh and Arcticneft in June-August 2007. This advance was received to mitigate working capital fluctuations during the winter period when oil cannot be sold. The advance bears interest at LIBOR plus 4% until the date of bill 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 the following:
YEAR ENDED 31 DECEMBER 2006 2005 Current tax (benefit) expense (1,296) 678 Deferred 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 charge at 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 - 1,721 Tax 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 396 939 Reversal of unused income tax provision (2,835) (161) Effect of tax penalties 164 28 Other non-deductible expenses 1,194 334 INCOME TAX (BENEFIT) (3,284) (2,477)
36 Urals Energy Annual Report and Accounts 2006 The movement in deferred tax assets and liabilities during the year ended 31 December 2006 was as follows:
RECOGNIZED CHARGED IN EQUITY FOR (CREDITED) TO TRANSLATION THE INCOME EFFECT OF 2006 DIFFERENCES STATEMENT ACQUISITIONS 2005 DEFERRED TAX LIABILITIES Property, plant and equipment 114,388 7,747 (1,792) 55,813 52,620 Inventories 124 9 25 - 90 Payables 75 19 (238) 3 291 Other taxable temporary differences 39 8 (82) - 113
DEFERRED TAX ASSETS Receivables (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 temporary differences (61) (110) 653 (49) (555) Tax 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 31 December 2005 was as follows:
RECOGNIZED CHARGED IN EQUITY FOR (CREDITED) TO TRANSLATION THE INCOME EFFECT OF 2005 DIFFERENCES STATEMENT ACQUISITIONS 2004 DEFERRED TAX LIABILITIES Property, plant and equipment 52,620 (1,066) (1,883) 36,167 19,402 Inventories 90 (3) (1,479) 1,445 127 Payables 291 - 223 68 - Borrowings received - (3) (142) - 145 Other taxable temporary differences 113 (2) 115 - -
DEFERRED TAX ASSETS Receivables (155) 6 5 - (166) Dismantlement provision (190) 7 219 (188) (228) Payables (360) 14 158 (190) (342) Inventories (114) 4 87 - (205) Other deductible temporary differences (555) 19 (93) (429) (52) Tax 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 cannot be 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 against deferred tax liabilities of another subsidiary. At 31 December 2006 and 2005, deferred tax assets of $4.9 million and $2.0 million, respectively, have not been
Urals Energy Annual Report and Accounts 2006 37 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (presented in US$ thousands) recognized for deductible temporary differences for which it is not probable that sufficient taxable profit will be available to allow the benefit of that deferred tax asset to be utilised.
The Group has not recognised deferred tax liabilities for temporary differences associated with investments in subsidiaries as the Group is able to control the timing of the reversal of those temporary differences and does not intend to reverse them in the foreseeable future. At 31 December 2006 and 2005, the estimated unrecorded deferred tax liabilities for such differences were $4.4 million and $1.4 million, respectively.
Other taxes payable at 31 December 2006 and 2005 were as follows:
31 DECEMBER 2006 2005 Unified production tax 5,583 2,259 Value added tax 374 367 Other 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 2006 and 2005:
31 DECEMBER 2006 2005 BNP Paribas Reserve Based Loan Facility 51,054 69,000 BNP Paribas Subordinated Loan 10,570 - Bank Zenit - 12,000 Other 185 122 Subtotal 61,809 81,122 Less: 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 a five year, revolving Reserve Based Loan Facility with BNP Paribas, underwritten to a maximum commitment of $100.0 million. At 31 December 2005, the maximum amount then available of $69.0 million was drawn. The facility is divided into a senior tranche of $59.0 million that bears interest at LIBOR plus 5.0% and a junior tranche of $10.0 million priced at LIBOR plus 6.25%. Both tranches are repaid on quarterly basis and matured in December 2010. The loan was collateralized by liens on property, plant and equipment of subsidiaries (Note 7). The Group is subject to certain financial and other covenants under the facility, including the maintenance of a minimum current ratio and a maximum ration of total borrowings to EBITDA. Additionally, under the facility, the Group is required to maintain a designated cash balance equal to the next quarter’s payment of principal and interest ($7.473 million and $1.083 million at 31 December 2006 and 2005, respectively). At 31 December 2006, the Group was in compliance with all its covenants under the facility.
38 Urals Energy Annual Report and Accounts 2006 SUBORDINATED LOAN. In January 2006, the Group obtained a $12.0 million subordinated loan from BNP Paribas (the “Subordinated Loan”). The Subordinated Loan 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 of the Group’s common stock for £3.03. The warrants are exercisable at any time and expire in November 2010. The Group used the proceeds from the Subordinated Loan 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 than the Group’s functional currency, the warrants are classified as a liability and adjusted to fair value at each reporting date, with the change in fair value recorded within the income statement. In 2006 the change in fair value of warrants resulted in an expense of $1.77 million. As the warrants are exercisable at any time, this amount was originally recorded as current liabilities in the Group’s consolidated balance sheet, with a corresponding reduction in the carrying value of the Subordinated Loan. The difference between the carrying value and the face value of the Subordinated Loan is accreted over the term to maturity as interest expense at the effective interest rate of the debt.
BANK ZENIT. In March 2005, Chepetskoye and CNPSEI entered into two loan agreements with Bank Zenit totalling $12.0 million. The loans bear interest at 11.0% per annum and scheduled for repayment in March 2010. The loans were repaid 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. This variable interest debt facility bore interest at LIBOR plus 5.0% and was originally repayable in December 2006. This facility was repaid in full in November 2005.
RP CAPITAL GROUP. In July 2005, the Group entered into a 10.0% convertible preferred note agreement with RP Capital Group for up to $15.0 million. In the event of a qualifying initial public offering (“IPO”) the notes were convertible into ordinary shares at a 20% discount to the IPO price. In July 2005 the Group issued $10.0 million of the convertible notes at par. These notes were converted into 2,929,651 shares in August 2005. No gain or loss was recognized on conversion.
Scheduled maturities of long-term borrowings outstanding were as follows:
SCHEDULED MATURITIES AT 31 DECEMBER 2006 2005 One year 20,965 34,117 Two to five years 40,844 47,005 Thereafter - - TOTAL LONG-TERM BORROWINGS 61,809 81,122
SHORT-TERM BORROWINGS. Short-term borrowings were as follows at 31 December 2006 and 2005:
31 DECEMBER 2006 2005 BNP Paribas Revolver 2,000 - TOTAL SHORT-TERM BORROWINGS 2,000 -
Urals Energy Annual Report and Accounts 2006 39 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (presented in US$ thousands)
BNP PARIBAS $2 MILLION REVOLVING FACILITY. In November 2006, the Group entered into a revolving loan agreement with BNP Paribas for a maximum of $2 million with 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 31 December 2006 and 2005 comprised the following:
YEAR ENDED 31 DECEMBER 2006 2005 SHORT-TERM BORROWINGS Alfa Eco M - 913 Related party borrowings (Note 20) - 726 Related party borrowings converted into equity (Note 20) - 655 Nimir - 478 BNP Paribas Pre-export Loan - 961 Bank Zenit 129 1,031 Other short-term borrowings 44 35
TOTAL INTEREST EXPENSE ASSOCIATED WITH SHORT-TERM BORROWINGS 173 4,799
LONG-TERM BORROWINGS BNP 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 162 276 Less capitalised borrowing costs (861) (640) Change in dismantlement provision due to passage of time (Note 12) 166 224 Interest on advance from Petraco Oil Company Limited 1,181 315 Other interest 170 237 TOTAL INTEREST EXPENSE 9,810 6,911
INTEREST INCOME JP 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
40 Urals Energy Annual Report and Accounts 2006 12 DISMANTLEMENT PROVISION
The dismantlement provision represents the net present value of the estimated future obligation for dismantlement, abandonment and site restoration costs which are expected to be incurred at the end of the production lives of the oil and gas fields. The discount rate used to calculate the net present value of the dismantling liability was 13.0%. YEAR ENDED 31 DECEMBER 2006 2005 Opening dismantlement provision 813 950 Translation difference 126 (21) Acquisitions 1,643 785 Additions 433 20 Changes 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 enforcement are under development by governmental authorities. Consequently, the ultimate dismantlement, abandonment and site restoration obligation may differ from the estimated amounts and this difference could be significant.
13 EQUITY
At 31 December 2006, authorized ordinary shares were 250 million, each having a par value of 0.0025 Cypriot pounds, of which 118.1 million and 86.9 million were issued and outstanding at 31 December 2006 and 2005, respectively.
Share activity and other capital contributions for the two years ended 31 December 2005 are outlined below. All share amounts have been given retroactive effect for the 400:1 share split executed in July 2005.
NUMBER OF SHARES (THOUSANDS SHARE SHARE UNPAID OF SHARES) CAPITAL PREMIUM CAPITAL BALANCE AT 1 JANUARY 2005 40,000 209 42,172 (11,324)
Conversion of loans as settlement of unpaid capital - - - 11,017 Conversion of loans into shares 16,244 86 45,195 - Shares issued for cash 30,667 165 113,946 - Unpaid capital received in cash - - - 307 Share-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 placement for 31,088,976 of its shares. Proceeds from the issuance totalled $195.1 million, 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 $17.0 million.
Urals Energy Annual Report and Accounts 2006 41 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (presented in US$ thousands)
CONVERSION OF LOANS AS SETTLEMENT OF UNPAID CAPITAL. During 2005, the Group settled $11.0 million of loans payable by offsetting the loan amounts against unpaid capital due the Group from the lenders.
CONVERSION OF LOANS INTO SHARES. During 2005, the Group settled $45.3 million of loans payable by issuing shares to the lenders.
SHARE-BASED PAYMENTS. In February 2006, the Board of Directors approved a Restricted Stock Plan (the “Plan”) authorizing the Compensation Committee of the Board of Directors to issue restricted stock of up to 5% of the outstanding shares of the Group. Upon adoption, the Group issued 1,561,725 shares of restricted stock. The vesting schedule for the restricted stock varies by individual award and, of the February 2006 grant, 1,040,445 shares, 260,625 shares and 260,625 shares vest on 1 January 2007, 2008 and 2009, respectively. 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 an exercise price of 240 pence per share to one of its directors. These options were granted for zero consideration. All of these options remain unexercised. In these consolidated financial statements the fair value of this option was evaluated at $.007 million. The options vest on 30 September 2006, 2007 and 2008 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 number of the Group’s shares at a share price equal to $131 million divided by the number of Group shares that are issued and outstanding at both 1 August 2006 and 1 August 2007. The option is in two parts comprised of the number of shares that can be purchased for a payment of $125,000 on 1 August 2006 and of $125,000 on 1 August 2007, which are the respective vesting dates of the two parts of the award. The officer is required to be continuously employed by the Group through the vesting dates. Notification of intent to purchase must be submitted within three days of the respective dates, and payment and delivery of shares to the officer 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, of which $0.057 and $0.042 million were recognized within selling, general and administrative expenses in 2006 and 2005, respectively, with respect to this award. The full amount of the award is being recognized over its vesting period.
The Black-Scholes option valuation model, used for valuing these awards, was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. In addition, this option valuation model requires the input of highly subjective assumptions, including the expected stock price volatility. As the Group’s shares were not publicly traded at the time of the grant of this award, management estimated the volatility measure through consultation with independent experts. Changes in the subjective input assumptions can materially affect the fair value estimate. Based on the assumptions below, the weighted average fair value of this option was estimated to be $0.120 million. Significant assumptions included in the option valuation model are summarized as follows.
Share price $2.65 Dividend yield - Expected volatility 25.00% Risk-free interest rate 4.00% Expected life 1-2 years
42 Urals Energy Annual Report and Accounts 2006 14 REVENUES YEAR ENDED 31 DECEMBER 2006 2005 Crude oil Export sales 117,940 69,177 Domestic sales (Russian Federation) 35,666 13,433 Petroleum (refined) products – domestic sales 14,798 9,904 Other sales 1,186 404 TOTAL GROSS REVENUES 169,590 92,918
Substantially all of the Group’s export sales are made to third party traders with title passing at the Russian border. Accordingly, management does not monitor the ultimate consumers and geographic markets of its export sales.
15 COST OF PRODUCTION YEAR ENDED 31 DECEMBER 2006 2005 Depreciation and depletion 19,335 8,285 Unified production tax 36,067 16,829 Cost of purchased products 9,266 12,455 Wages and salaries (including payroll taxes of $2.6 million and $1.5 million for the years ended 31 December 2006 and 2005, respectively) 15,190 7,341 Materials 4,862 2,276 Other taxes 256 1,338 Loss on disposal of assets 439 254 Other 6,656 3,256 TOTAL COST OF PRODUCTION 92,071 52,034
16 SELLING, GENERAL AND ADMINISTRATIVE EXPENSES YEAR ENDED 31 DECEMBER 2006 2005 Wages and salaries 9,616 5,162 Professional consultancy fees 2,169 1,986 Audit fees 843 556 Office rent and other expenses 1,556 1,522 Transport and storage services 4,537 998 Loading services 1,381 845 Share based payments 5,089 42 Directors’ fees 60 17 Other 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 $0.185 million and nil related to share-based payments provided to one of the Group’s directors (Note 13).
17 MOBILIZATION COSTS
The Group’s mineral licenses require that the Group perform certain exploration, evaluation and development activities as a condition of maintaining and/or renewing the licenses. During 2005, the Group entered into an agreement with KCA Deutag to provide a specialized drilling rig for the purpose of obligatory exploratory drilling on one of the Group’s properties on Sakhalin Island. As part of the agreement, the Group was required to transport the rig approximately 5,000 kilometers to reach Sakhalin Island. By disclosing the agreements to
Urals Energy Annual Report and Accounts 2006 43 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (presented in US$ thousands) secure and transport the rig, management was able to demonstrate to the licensing authorities its commitment to fulfilling its obligations under the license. However, due to delays in transportation and seasonal weather concerns, the Group was forced to terminate its agreement and abort the transport prior to the rig’s arrival to Sakhalin Island, resulting in mobilization costs of $7.2 million being expensed during 2005.
The Group was subsequently able to modify an existing rig to drill an exploratory well on the property in order to maintain compliance with the license terms.
18 CONTINGENCIES, COMMITMENTS AND OPERATING RISKS
OPERATING ENVIRONMENT OF THE GROUP. Whilst there have been improvements in economic trends in the country, the Russian Federation continues to display certain characteristics of an emerging market economy. These characteristics include, but are not limited to, the existence of a currency that is not freely convertible in most countries outside of the Russian Federation, restrictive currency controls, and relatively high inflation. The tax, currency and customs legislation 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 dependent upon the effectiveness of economic, financial and monetary measures undertaken by the Government, together with tax, legal, regulatory, and political developments.
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 in the 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 Group agreed to pay a perpetual royalty to the previous shareholders of $0.25 per ton of crude oil produced from the currently unproved off-shore licensed area.
EXPLORATION LICENSES – INVESTMENT COMMITMENTS. The Company’s application for an extension of the Pogranichnoye License area offshore Sakhalin Island has been successful. The Russian Federal Agency for Natural Resources granted the license extension in January 2006. The license period was extended to 1 February 2011 and the terms of the amended license now require a total of five exploration wells to be drilled during the period 2005-2010. The East Okruzhnoye No. 1 well spudded in 2005 will qualify as the first of the five exploration wells required by the amended license. Management currently estimate such expenditure 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 drill exploration wells and perform seismic works. Management currently estimate such expenditure to approximate $36 million.
OTHER CAPITAL COMMITMENTS. At 31 December 2006 and 2005 the Group had no other significant contractual commitments for capital expenditures.
TAXATION. Russian tax and customs legislation is subject to varying interpretations, and changes, which can occur frequently. Management’s interpretation of such legislation as applied to the transactions and activity of the Group may be challenged by the relevant authorities.
44 Urals Energy Annual Report and Accounts 2006 The Russian tax authorities may be taking a more assertive position in their interpretation of the legislation and assessments, and it is possible that transactions and activities that have not been challenged in the past may be challenged. The Supreme Arbitration Court issued guidance to lower courts on reviewing tax cases providing a systemic roadmap for anti-avoidance claims, and it is possible that this will significantly increase the level and frequency of tax authorities’ scrutiny.
As a result, significant additional taxes, penalties and interest may be assessed. Fiscal periods remain open to review by the authorities in respect of taxes for three calendar years proceeding the year of review. Under certain circumstances reviews may cover longer periods.
As at 31 December 2006 and 2005, management believes that its interpretation of the relevant legislation is appropriate and the Group’s tax, currency and customs positions will be sustained. Where management believes it is probable that a position cannot be sustained, an appropriate amount has been accrued for in 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 liability insurance policy was put in place, including environmental liability, with a total limit of $7.8 million.
RESTORATION, REHABILITATION AND ENVIRONMENTAL COSTS. The Group companies have operated in the upstream and refining oil industry in the Russian Federation for many years and its activities have had an impact on the environment. The enforcement of environmental regulations in the Russian Federation is evolving and the enforcement posture of government authorities is continually being reconsidered. 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, cannot reasonably be estimated at present, but could be material. Under the current levels of enforcement of existing legislation, management believes there are no significant liabilities in addition to amounts which are already accrued and which would have a material adverse effect on the financial position of the Group.
LEGAL PROCEEDINGS. During the year, the Group was involved in a number of court proceedings (both as a plaintiff and a defendant) arising in the ordinary course of business. In the opinion of management, there are no current legal proceedings or other claims outstanding, which could have a material effect on the result of operations or financial position of the Group and which have not been accrued or disclosed in these consolidated financial statements.
OILFIELD LICENSES. The Group is subject to periodic reviews of its activities by governmental authorities with respect to the requirements of its oil filed licenses. Management of the Group correspond with governmental authorities to agree on remedial actions, if necessary, to resolve any findings resulting from these reviews. Failure to comply with the terms of a license could result in fines, penalties or license limitations, suspension or revocations. The Group’s management believes any issues of non-compliance will be resolved through negotiations or corrective actions without any materially adverse effect on the financial position or the operating results of the Group.
Management currently does not believe that any of its significant exploration or production licenses are at risk of being withdrawn by the licensing authorities. Additionally, management currently plans to complete all the required exploration or development work, as appropriate, within the timetables established in the licenses.
Urals Energy Annual Report and Accounts 2006 45 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (presented in US$ thousands)
19 FINANCIAL RISKS
FOREIGN EXCHANGE RISK. The Group has substantial amounts of foreign currency denominated long-term borrowings and is thus exposed to foreign exchange risk. Foreign currency denominated assets and liabilities give rise to foreign exchange exposure. The Group does not have formal arrangements to mitigate foreign exchange risks.
INTEREST RATE RISK. The Group obtains funds from, and deposits its cash surpluses with, banks at current market interest rates, and does not utilize hedging instruments to manage its exposure to changes in interest rates. The details of interest rates associated with the Group’s borrowings are discussed in Note 11.
FAIR VALUES. The carrying value of the Group’s receivables, payables and borrowings approximate their fair values.
Cash and cash equivalents are carried at amortised cost which approximates current fair value. Cash and cash equivalents include $31.5 million and $27.9 million as at 31 December 2006 and 2005, respectively, denominated in US dollars.
At 31 December 2006 and 2005, the carrying amounts of trade and other receivables, short-term borrowings, trade and other payables, taxes payable and advances from customers approximated their fair values.
The fair values of the Group’s long-term borrowings were estimated based upon rates available to the Group on similar instruments of similar maturities. At 31 December 2006 and 2005, management believes that the fair values of its borrowings approximate their respective carrying values.
Warrants classified as liabilities are carried at fair value.
CREDIT RISK. Financial assets, which potentially subject Group entities to credit risk, consist principally of trade receivables. The Group has policies in place to ensure that sales of products and services are made to customers with an appropriate credit history. The carrying amount of accounts receivable, net of provision for impairment of receivables, represents the maximum amount exposed to credit risk. The Group has no other significant concentrations of credit risk. Although collection of receivables could be influenced by economic factors, management believes that there is no significant risk of loss to the Group beyond the provision already recorded. Cash is placed in financial institutions, which are considered at time of deposit to have minimal risk of default.
COMMODITY AND PRICING RISK. The Group’s operations are significantly affected by the prevailing price of crude oil both in the international oil market and in the Russian Federation. Crude oil prices have historically been highly volatile, dependent upon the balance between supply and demand and particularly sensitive to OPEC production levels. Crude oil prices in the Russian Federation are below international levels primarily due to constraints on the export of crude oil. Also, domestic crude oil prices are contract specific as there is no active market for domestic crude oil and marker prices are not available. There is typically no straight correlation between domestic and international oil prices. The Group’s subsidiary – Petrosakh, operates on Sakhalin Island where the surrounding ocean is not navigateable for several months of the year, this further 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 be related if one party has the ability to control the other party, is under common control, or can exercise significant influence over the other party
46 Urals Energy Annual Report and Accounts 2006 in making financial or operational decisions as defined by IAS 24 Related Party Disclosures. In considering each possible related party relationship, attention is directed to the substance of the relationship, not merely the legal form.
TRADING RELATIONSHIP WITH RELATED PARTIES. The Group had transactions in the ordinary course of business with Urals ARA NV and Nafta (B) NV which all are controlled by major shareholders. These transactions included sales and purchases of crude oil and petroleum products. Such sales ended beginning September 2005. Below are the annual sales, purchases and receivables balances for each year presented:
AS OF OR FOR THE YEAR ENDED 31 DECEMBER 2006 2005 Sales of crude oil on export markets - 5,515 Associated volumes, tons - 17,580
Interest expense - 1,381 Interest income 130 82 Professional consultancy fees (included in selling, general and administrative expense) 424 289 Rental fees paid (included in selling, general and administrative expense) 450 306 Other expenses 41 790
Accounts and notes receivable 708 1,477 Loans receivable 1,983 1,251 Interest receivable 206 77 Accounts 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 comprises 10 people whose compensation totalled $12.895 million and $4.174 million for the periods ended 31 December 2006 and 2005, respectively, including salary and bonuses of $7.806 million and $4.132 million respectively, and stock compensation of $5.089 million and $0.042 million, respectively, and no other compensation was paid for both years. Additionally, included in loans receivable 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 to fund the development of the Dulisminskoye field in Irkutsk Region, Eastern Siberia. 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 by OOO “Oil Company Dulisma” as a project-style loan that is non-recourse, except in certain limited circumstances, to Urals Energy. This debt financing is expected to fund Urals Energy’s commitment to develop the oil reserves at its Dulisminskoye field.
The terms of the loan arranged by Goldman Sachs include an interest rate of 725 basis points over LIBOR of which 300 basis points are payable quarterly, with the remainder accruing until the loan matures in four years or 2011 when all principal and accrued interest is due in a single payment. The loan may be prepaid at any time but during the first two years certain penalties for early prepayment apply.
The credit risk of the debt facility will be sold to Goldman Sachs and Standard Bank will act as the funding bank of record and also facility agent. The deal is structured to fund in two tranches, $45 million and $85 million. The second tranche is subject only to the approval of Urals Energy’s senior bank syndicate in accordance with the terms of a pre-negotiated inter-creditor agreement. Both tranches were received during first quarter 2007.
Urals Energy Annual Report and Accounts 2006 47 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (presented in US$ thousands)
UNIFIED PRODUCTION TAX HOLIDAY. In November 2006 the Russian Government announced changes to the “Subsoil law”, which provides a production tax holiday for the unified production tax for the oil fields located in East Siberia in Sakha-Ykutia, Irkutsk and Krasnoyarsk regions. In January 2007 OOO Oil Company Dulisma received a written confirmation from Irkutsk Oblast Tax Inspectorate verifying a ten year production tax holiday for the Dulisminskoye field starting form 1 January 2007 and ending on 31 December 2016.
NOTICE OF ANNUAL GENERAL MEETING THE ANNUAL GENERAL MEETING OF THE COMPANY WILL BE HELD AT 10:00 AM ON 9 JULY, 2007 AT THE COMPANY’S REGISTERED OFFICES, EVAGORAS BUILDING, 31 EVAGORAS AVENUE, CY-1066 NICOSIA, CYPRUS.
PLEASE REFER TO THE NOTICE AND PROXY FOR DETAILS OF THE MATTERS TO BE VOTED ON AT THE MEETING.
ALL SHAREHOLDERS ARE ENCOURAGED TO PARTICIPATE IN THE MEETING.
48 Urals Energy Annual Report and Accounts 2006 CORPORATE INFORMATION
URALS ENERGY (TRADING NOMINATED ADVISER AND BROKER SYMBOL UEN) LISTED ON AIM, Morgan Stanley & Co. International plc LONDON STOCK EXCHANGE Morgan Stanley Securities Limited 25 Cabot Square Canary Wharf London E14 4QA BOARD OF DIRECTORS Leonid Y. Dyachenko AUDITORS AND REPORTING ACCOUNTANTS Charles J. Pitman ZAO PricewaterhouseCoopers Audit William R. Thomas Kosmodamianskaya Nab. 52 Building 5 REGISTERED OFFICE 115054 Moscow, Russia Evagoras Building Office 34, 3rd Floor PETROLEUM CONSULTANTS 31 Evagoras Avenue DeGolyer and MacNaughton CY-1066, Nicosia, Cyprus One Energy Square, Suite 400 4925 Greenville Avenue MOSCOW OFFICE Dallas, TX 75206 Urals Energy LLC ul. Osennaya 11 LAWYERS AND SOLICITORS TO THE COMPANY Moscow 121609 Akin Gump Strauss Hauer & Feld Russian Federation CityPoint, Level 32 Tel: +7 495 795 0300 One Ropemaker Street Fax: +7 495 795 0301 London EC2Y 9AW
LONDON OFFICE BANKERS Urals Energy (UK) Ltd. BNP Paribas S.A. 3 St. James’s Square 21, Place du Marché Saint-Honoré London 75031 Paris SW1Y 4JU Cedex 01 United Kingdom France
COMPANY SECRETARY Goldman Sachs International Zet Secretarial Limited Peterborough Court 2nd Floor 133 Fleet Street 5 Thermistocles Dervis Street London EC4A 2BB Nicosia, Cyprus England, United Kingdom
TRANSFER AGENT AND DEPOSITARY FINANCIAL RELATIONS Computershare Investor Services PLC Pelham Public Relations P.O. Box 82 No.1 Cornhill The Pavilions London Bridgwater Road EC3V 3ND Bristol BS99 7NH United Kingdom T: +44(0)20 7743 6670 www.uralsenergy.com F: +44(0)20 7743 6671
Urals Energy Annual Report and Accounts 2006 49 Urals Energy Public Company Limited, Evagoras Building, Office 34, 3rd Floor, 31 Evagoras Avenue, CY-1066, Nicosia, Cyprus www.uralsenergy.com
RUSSIAN FEDERATION URALS ENERGY
MOSCOW ANNUAL REPORT AND ACCOUNTS 2006