Russia’s Natural Gas Frontiers: “Harnessing the Energy of the Far North”
Mark Gyetvay, Chief Financial Officer and Member of the Board Sberbank – The Russia Forum 2013 Moscow 16-17 April 2013 Forward-Looking Statements
Certain statements in this presentation are not historical facts and are “forward-looking”. Examples of such forward-looking statements include, but are not limited to: – projections or expectations of revenues, income (or loss), earnings (or loss) per share, dividends, capital structure or other financial items or ratios; – statements of our plans, objectives or goals, including those related to products or services; – statements of future economic performance; and – statements of assumptions underlying such statements Words such as “believes”, “anticipates”, “expects”, “estimates”, “intends”, “plans”, “outlook” and similar expressions are intended to identify forward-looking statements but are not the exclusive means of identifying such statements
By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks exist that the predictions, forecasts, projections and other forward-looking statements will not be achieved. You should be aware that a number of important factors could cause actual results to differ materially from the plans, objectives, expectations, estimates and intentions expressed in such forward-looking statements
When relying on forward-looking statements, you should carefully consider the foregoing factors and other uncertainties and events, especially in light of the political, economic, social and legal environment in which we operate. Such forward-looking statements speak only as of the date on which they are made, and we do not undertake any obligation to update or revise any of them, whether as a result of new information, future events or otherwise. We do not make any representation, warranty or prediction that the results anticipated by such forward-looking statements will be achieved, and such forward-looking statements represent, in each case, only one of many possible scenarios and should not be viewed as the most likely or standard scenario
2 Main Operational Highlights – 2012
SEC proved reserves increased by 32% to 12.4 billion boe Increased Gross Production: – Natural gas production increased by 7.1% to 57.3 bcm – Liquid hydrocarbons production increased by 4.0% to 4.3 mmt – Total production increased by 6.8% to 411 mmboe Launched new production capacities: – Launch of the fourth stage of Phase Two development at the Yurkharovskoye field, bringing total production at the field to its target plateau. Commissioning of the first stage of a booster compressor station at the field. – The start of commercial production at the Samburgskoye field, which is being developed by SeverEnergia joint venture: launch of the first and second phases. Acquisition of a 49% equity stake in Nortgas, which owns the license for the North- Urengoyskoye field. Acquisition of an 82% interest in Gazprom Mezhregiongas Kostroma, which supplies gas to a broad range of customers in Kostroma Region.
Signing of gas supply agreements with end-users, including contracts with record duration (10-15 years) and contracts with new large customers.
3
SEC Reserve Growth
Reserve replacement ratio from 2004 to 2012 – 486%
mmboe 6,416
(98) 12,394 12,394 12,394 12,394 2010 Termo- (2,127) karstovoye Liquids field Others 2012 West Zapolyarnoye PU Khancheyskoye 4,025 Nortgas Sibneftegaz 2009 South-Tambeyskoye field (51%) SeverEnergia 2010 SeverEnergia 2010 Sibneftegas East-Tarkosalinskoye 2011 South-Tambeyskoye field (29%) Gas 2012 Salmanovskoye, Geofizicheskoye 4,178 2012 Nortgas (49%) Yurkharovskoye Yurkharovkoye field South-Tambeyskoye field PD Olimpiyskiy LA Termokarstovoye field South-Tambeyskoye SeverEnergia
2004 Organic Acquisitions Disposals 1 Production 2012 2012 2012 2012 growth Gas+Liquids PU+PD 2 Fields
Notes: 1. Disposal of a 49% participation interest in Terneftegas 2. Proved undeveloped and proved developed reserves 4 Hydrocarbon Production
Natural Gas Sales Liquids Sales Total Hydrocarbon Production, bcm Production, mmt Production, mmboe
CAGR 13% CAGR 9% CAGR 13% Absolute increase 169% Absolute increase 105% 4.3 Absolute increase 161% 56.5 405 52.9 4.1 381 3.6
3.0 37.3 274 2.6 32.4 2.4 237 30.4 2.3 220 28.6 28.3 2.1 2.1 206 206 25.0 184
20.9 155
2009 2004 2005 2006 2007 2008 2010 2011 2012
2006 2007 2004 2005 2008 2009 2010 2011 2012
2004 2005 2006 2007 2008 2009 2010 2011 2012
Crude oil Gas condensate Liquids Natural Gas
Sustainable production growth
Note 1: Production data for 2012 provided on this slide represent a preliminary assessment only, which can be adjusted after statistical, financial, fiscal and business reporting becomes available. 5 Jan Feb Mar Apr 3,171 3,171 90 2009 Avg.
Gross production (subsidiaries) May
mmcm Jun 2009 bcf Jul Aug /day /day
Sep
Oct Increasing Natural GasProduction Nov Dec Jan Feb Mar
3,655 3,655 103 2010 Avg. Apr May ( mmcm
Jun mmcm day) per bcf 2010 Jul /day
Aug /day
Sep
Oct Equity share thein gross production of our JVs Nov Dec Jan Feb Mar
5,180 5,180 147 2011 Avg. Apr May mmcm bcf 2011 Jun Jul /day
/day Aug
Sep
Oct Nov Dec Jan Feb 5,531 5,531 157 201
5,875 5,875 166 1 4Q Mar Apr 2 mmcm mmcm/day 2
Avg. May
bcf bcf/day 2012 Avg. Jun /day
Jul
/day Aug
Sep Oct Nov
Dec 6
Acquisition of 49% in Nortgas
Nortgas block Other fields of NOVATEK Date of acquisition – November 2012 NOVATEK gas condensate Partner – Gazprom pipeline
North-Urengoyskoye Producing green field with material production upside: North-Urengoyskoye field with proved SEC reserves of 157 bcm of gas and 21 mmt of liquids Production in 2012 4.2 bcm per annum of gas and 0.4 mmt of gas condensate Estimated peak annual production ~9-10 bcm of gas ~1.4 mmt of gas condensate Purovsky Plant
NOVATEK acquires 50% of gas and 100% of gas condensate is processed at the Purovsky plant
7 Natural Gas Sales
Gas Sales Breakdown 100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
2008 2009 2010 2011 2012
Others Ex-field and regional • Contracts concluded with E.ON and Fortum (15 years), MMK (10.5 years), gas distributors Large industrial Mechel (10 years and longer), Severstal (5 years) and Mosenegro (3 years) consumers Power generation • Acquisition of an 82% interest in Gazprom Mezhregiongas Kostroma, which companies supplies gas to a broad range of customers in Kostroma Region 8 Liquids Sales
Liquids Sales Volumes, mmt 4.1 4.2 3.4 3.1
3.5 3.4 2.6 2.8
0.5 0.6 0.6 0.8 2009 2010 2011 2012 Domestic Export 9 Yamal LNG Project
Project for construction of an LNG plant on the Yamal Peninsula
The onshore South-Tambeyskoye field holds 900 bcm of conventional 2P gas reserves
16.5 mmt of LNG per annum (3 trains)
1 mmt of marketable gas condensate per annum
Participants – NOVATEK (80%), TOTAL (20%)
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Concept, surveys, pre-FEED FEED, State expertise review, construction permit Final Investment Decision (FID) Early detailed engineering, EPC LNG plant startup by trains
State support provision International partner selection Off-take agreements (SPAs) Project finance Facts About The Yamal Peninsula
The Yamal Peninsula is located in the north of Western Siberia and is bordered by the Kara Sea to the west and by the Gulf of Ob to the east
The administrative center is Yar-Sale and the peninsula has a total population of 16,100 inhabitants
The Yamal territory is located in a tundra zone, and the peninsula consists of mostly permafrost soil
A large part of the peninsula is covered by swamps and lakes, with the northern part characterized by wetlands and arctic tundra
The peninsula’s relief is characterized as smooth with altitude variations of less than 90 meters. The peninsula’s average altitude is approximately 50 meters above sea level
The Yamal territory has a large concentration of natural gas fields. Currently, total explored reserves constitute more than 16 tcm of natural gas and more than 230 mmt of gas condensate 11 Arctic Climatic Conditions
Subarctic and arctic climate Average annual temperature - minus 9°С Absolute minimum temperature - minus 57°С Strong winds and blizzards with wind speeds of up to 32 meters/second Permafrost with depths of up to 300 to 500 meters Long-lasting ice cover (about 300 days a year) Swamps and lakes cover over 60% of the territory
Average annual temperature Annual wind rose
N NW NE
South - Tambey W E
SW SE S Polar day winter spring summer fall night Polar 12 South-Tambeyskoye Field
Natural gas production1, bcm
30 New plateau Northern 27 (28 bcm) 118Р 3391 115Р
3392 83943393 4392 87Р Old plateau 4391 Dome 2391-2 86Р 24 8392
6391 5392 (25 bcm) 839183933394
116Р 3221 5391 21 82Р
3222
84Р
3223
3224 18 93Р 4221 3225 119Р 83Р
3351
3352 3352-2 7351 4351 15 1351 3353
3354
1352 113Р
43523355 12
3401 73Р 1401 3402 4401
К42 117Р C4422entral1П 3403 7Р К40 1041 4041 1421 9 1402 71Р 4421 4403-2 3404-2 4042 1042 4061 1061 1403 1043 Dome 3404 2411-2 4021 4062-2 1021 3011 79П 5П 7441 91Р 7444 6 1062 4411 5061 4063 2412-2 К44 1022 70П 4Р 72Р 7443 3012 101314Р 3021 5021 6П 80П 8444 1441 К41 3022 8442 8445 8443 5431 2021-2 75Р 21Р 1012 3431 2441-2 2431-2 5022 7445 2014-2 5011 7431 7442 8433 8432 3441 3 8441 3013 84071075 5075707 4441 88007714 4 1431 109Р 8431 8073 8076 7451 Sabetta 2432-2 7073 2071-2 70718072 105Р 1433 2072-2 8451 106Р 5072 7075 110 К43 5074 157Р 432 1071 1 17072072 1451 - 97Р 2П 85Р 8Р 5071 3072 2073-2 2452-2
1073 1453 К45 98Р 3071
4431 4451 3Р 1452 2015F 2016 2017 2018 2019 2020F 8474 94Р 112Р 5471
7471 8471 44715474 88Р 3471 4302 3472 5472 4301 11Р 4291 4262114Р 5302 4472 2471 5473 К47 108Р 3473 3.1 3301 76Р 8472 53017301 8476 7302 2301 4303 81Р6471 4261 5475 • Production plateau level raised from 25 to 28 bcm 5303 4461 2461 54613461 89Р
8464 10Р 4462 100Р 90Р (duration of the plateau - 20 years) К46
8462 8463 3251
101Р 2251-25253 4251
2252
2322Р • New production curve confirmed by 4253
4252 3252 5251 5252 2321П Southern2324Р independent reserve auditor D&M Dome • LNG production level increased from 15 to
Р асп р е д е л е н ие ф о нд а э ксп л уатацио нн ы х скваж и н Ю ТГКМ п о кустам . 16.5 mmt per annum куст количество скважин Купол
1 10 ЦК втомчисле 2 10 ЦК Объект Пласт Кол-воскважин ЮВК ЦК СВК 4 6 ЦК 6 6 ЦК 1 ПК1 26 0 26 0 7 25 ЦК Note 1: 100% of South22 -Tambeyskoye6 ЦК field production volumes 2 ХМ1+ХМ2 28 5 20 3 25 12 ЮВК 1 26 2 ЦК ОАО "НОВАТЭК" 3 ТП1-ТП2 34 7 23 4 29 1 ЦК ОАО "Ямал СПГ" Инв. № экз. 1 30 18 ЮВК 2011 г. Изготовлено 4 ТП3-ТП4 33 10 21 2 35 10 ЦК экземпляров 13 2 39 17 СВК 5 ТП5-ТП12 24 12 10 2 Тюменская 40 11 ЦК область 6 ТП 0-ТП 19 17 0 2 41 3 ЦК ФОНД ЭКСПЛУАТАЦИОННЫХ СКВАЖИН 13 14-15 42 3 ЦК Ямало- Ненецкий 1 43 12 ЦК ЮЖНО-ТАМБЕЙСКОГО МЕСТОРОЖДЕНИЯ 7 ТП17-ТП19 16 3 13 0 автономный 44 15 ЦК округ 45 8 ЦК Масштаб 1 : 100 000 8 ТП20-ТП26 37 17 16 4 46 15 ЮВК 1 0 1 2 км Всегопоместорождению 217 71 129 17 47 27 ЮВК 20 217 250 0 250 500 750 1000 м
Приложение Руководитель договора: Составил: Еринов В.Г. лист , экз. Ответственный исполнитель: Компьютерная графика: Field Development
Optimized drilling and surface facilities Current development parameters Initial Current Max. No. of drilling rigs 8 5 . 208 production wells to be drilled from 19 well pads: No. of well pads 35 19 . 58 wells to feed the 1st train of the LNG plant Gas gathering lines 350 km 288 km . 66 wells to feed the 2nd and 3d trains . 84 wells to keep production at the plateau Drilling rig “Arctic” First rigging up – 60 days . Directional wells (average horizontal displacement Rig move within the field – 30 days Rig move within the pad – 1.5 days ~500 meters)
. Priority is given to reservoirs with optimal condensate flow rate and simultaneous supply of required natural gas volumes to the LNG plant;
. First production drilling to start in April 2013.
Field infrastructure
. 288 km of gas gathering lines
. 121 km of roads and 143 km of high voltage lines
14 Logistics of Material Supplies
Year-round modules Heavy modules transportation delivery • By big lift RoRo vessels • Year round yard-to- transhipment Heavy modules (July to Nov) • Accumulation at storage areas (Kirkines-Murmansk) • July-October storage-to-site transportation
Light modules and bulk
Bulk materials and • Year-round by ice-class vessels light modules to Sabetta with ice breakers (year-round with ice- support breaker support in winter) • July-October by sea and river
Construction cargoes by river (July to October) 15 Port of Sabetta
Seaway and approach channels Port facilities, berths and harbor Government facilities 6 3 1 Administrative Yamal facilities peninsula 3 Ice protection construction 4 2 4 Port harbor Approach 5 channel 1 2 6 Seaway channel 1 5 2 Yamal LNG facilities 3 Administrative and Port facilities 1 warehouse . Design work performed by facilities Berths, jetty and Lenmorniiproekt and Artelia 2 utility systems . Materials Off-loading Berth . Jetty with two (2) berths Channels . LNG loading infrastructure Dredging is required for the passage of LNG tankers with a capacity of 170,000 m3 and with a draft of 11.7 m: . Ice management system . Approach channel – five (5) nautical miles . Tugs and port ice-breakers . Seaway channel - 35 nautical miles
Port and approach channels financed through the federal budget in accordance with an agreement with Rosmorport 16 On-Site Activity
Berth piling construction Arctic drilling rig assembled
Materials offloading (4.5 km offshore the Gulf of Ob) Living quarters
17 Yamal LNG Carrier Concept
Based on existing operational experience and extensive studies and model tests at ice model basin by Aker Arctic Main concept - Double Acting Ship (DAS): • Bow – forward movement in open water and thin ice • Astern – reverse movement through thick ice and ice ridges Ice model tests have validated the Arc-7 170,000 cm LNG Carrier basic design • Moderate ice bow • Three shaft propulsion system (AZIPOD’s) • Ice going capabilities: 2.1 meters • Confirmed speed: 19.5 knots in open water and 5.5 knots in even ice of 1.5 meters 18 LNG Marketing Logistics
10.6 Natural gas spot price1, $/mmbtu Summer transportation route to target markets, liquids & LNG All season transportation route to target markets, liquids & LNG Transportation routes to other markets
10.6 2
USA3 3.4 14.7
12.5
15.4
16.4
Notes: 1. Based on average actual prices (delivery January 2013) from Argus Global LNG and Heren LNG Market Daily 2. Average of: Title Transfer Facility (TTF) spot price (Netherlands) and National Balancing Point (NBP) spot price (UK) 3. Henry Hub 19 Yamal LNG - Key Project Advantages
. Low-cost, long-lived feedstock . Large onshore conventional reserve base with high concentration of reserves . Well known geology and proven development technologies . Very low F&D and lifting costs
. Convenient location . Reserves are located at the coast line and highly concentrated – minimal capital expenditures on gas transportation from the wells to the LNG plant . High efficiency factor of gas liquefaction process due to sub-zero temperatures – relatively low liquefaction capital expenditures per unit of LNG production . Access to both European and Asian markets
. Strong Russian State support . Tax concessions – 12 years . Financing of new strategic arctic port infrastructure
20 2012 Financial Results Another Record Year (RR million)
2012 2011 +/(-) +/(-)% Oil and gas sales 210,246 174,811 35,435 20.3% Total revenues 210,973 175,273 35,700 20.4% Operating expenses (125,775) (96,820) (28,955) 29.9% EBITDA (1 ) 95,106 148,349 (53,243) -35.9% Normalized EBITDA (2 ) 95,166 85,401 9,765 11.4% EBITDA margin 45.1% 84.6% Normalized EBITDA margin 45.1% 48.7% Effective income tax rate (3 ) 19.5% 11.7% Profit attributable to NOVATEK 69,458 119,655 (50,197) -42.0% Normalized profit attributable to NOVATEK (4 ) 69,518 56,707 12,811 22.6% Profit margin 32.9% 68.3% Normalized profit margin 33.0% 32.4% Earnings per share 22.89 39.45 (16.56) -42.0% Normalized earnings per share 22.91 18.69 4.22 22.6% CAPEX (5 ) 43,554 31,161 12,393 39.8% Net debt (6 ) 114,067 71,647 42,420 59.2% Notes: 1. EBITDA represents profit (loss) attributable to shareholders of OAO NOVATEK adjusted for the add-back of net impairment expenses (reversals), income tax expense and finance income (expense) from the Consolidated Statement of Income, income (loss) from changes in fair value of derivative financial instruments from the “Financial instruments and financial risk factors” in the notes to the consolidated financial statements and depreciation, depletion and amortization from the Consolidated Statement of Cash Flows 2. Normalized EBITDA represents EBITDA excluding net gain (loss) on disposal of interest in subsidiaries 3. Effective income tax rates, excluding the effect of application of a reduced income tax rate of 15.5% in respect of the Group’s priority investment project in YNAO in 2012 and excluding the net gain on disposal of Yamal LNG in 2011, were 21.4% and 21.7%, respectively 4. Normalized profit attributable to shareholders of OAO NOVATEK represents profit attributable to shareholders of OAO NOVATEK excluding net gain (loss) on disposal of interest in subsidiaries 5. CAPEX represents additions to property, plant and equipment excluding prepayments for participation in tender for mineral licenses 6. Net debt calculated as long-term debt plus short-term debt less cash and cash equivalents 22 Total Revenues Breakdown
2012
7% 3% Natural gas 22%
Stable gas condensate 68%
2011 8% 2% LPG
27%
Other 63%
23 Market Distribution – Sales Volumes
Natural gas sales volumes, mmcm Liquids sales volumes, mt
58 880 53 667 4,111 4,203
29 332 54.7% 40 806 69.3% 3,528 85.8% 3,449 82.1%
24 335 45.3% 18 074 30.7% 0 0 583 14.2% 754 17.9% 2011 2012 2011 2012 Ex-field End-customer Domestic Export
• Growth in natural gas sales volumes was mainly due to a combination of increased production at our core fields and the commencement of purchases from our • Growth in liquids sales volumes was related party SIBUR Holding effective from 1 January mainly due to the initiation of unstable gas 2012 condensate purchases from the Group’s joint ventures, as well as the increase in • Our proportion of natural gas sold to end-customers crude oil production, which were partially increased Y-o-Y due to higher natural gas deliveries offset by an increase in liquids inventory to the Chelyabinsk region as a result of the balances in 2012 as compared to a acquisition of regional gas trader Gazprom decrease in 2011 mezhregiongas Chelyabinsk in November 2011
24 Stable Gas Condensate in Transit
Yosu
Singapore
“Goods in transit” 30.09.2012 “Goods in transit” 31.12.2012 “Goods in transit” 31.12.2011 ~ 122 thousand tons ~ 217 thousand tons ~ 61 thousand tons
61 mt 61 mt 61 mt 61 mt 60 mt USA South Korea
36 mt 60 mt Singapore South Korea 25 Realized Hydrocarbon Prices (net of VAT, excise and export duties)
2012 2011 +/(-) +/(-)% Domestic prices Natural gas end-customers, RR/mcm 2,821 2,627 194 7.4% Natural gas ex-field, RR/mcm 1,518 1,392 126 9.1% Stable gas condensate, RR/ton 12,489 13,818 (1,329) -9.6% LPG, RR/ton 14,009 13,458 551 4.1% Crude oil, RR/ton 10,985 9,792 1,193 12.2% Methanol, RR/ton 10,659 10,000 659 6.6% Export market Stable gas condensate, RR/ton 16,432 15,676 756 4.8% LPG, RR/ton 20,109 19,199 910 4.7% Crude oil, RR/ton 11,935 10,983 952 8.7%
Note: Prices are shown excluding trading activities and excluding natural gas volumes purchased for resale in the location of end-customers 26 Operating Expenses (RR million and % of Total Revenues)
2012 % of TR 2011 % of TR Transportation expenses 60,848 28.8% 48,329 27.6% Taxes other than income tax 16,846 8.0% 16,559 9.4% Non-controllable expenses 77,694 36.8% 64,888 37.0% Depreciation and amortization 11,185 5.3% 9,277 5.3% General and administrative 10,936 5.2% 8,218 4.7% Materials, services & other 7,216 3.4% 5,947 3.4% Exploration expenses 2,022 1.0% 1,819 1.0% Net impairment expenses 325 n/m 782 n/m Change in natural gas, liquids (1,086) n/m (105) n/m and WIP Subtotal operating expenses 108,292 51.3% 90,826 51.8% Purchases of natural gas and liquid hydrocarbons 17,483 8.3% 5,994 3.4% Total operating expenses 125,775 59.6% 96,820 55.2%
Operating expenses increased by 29.9% due to an increase transportation expenses and purchases of natural gas and liquid hydrocarbons Transportation expenses increased due to a 30.8% increase in natural gas sales volumes to end-customers, for which we incurred transportation costs, as well as a 7% average increase in the natural gas transportation tariff set by the FTS effective from 1 July 2012 Taxes other than income tax increased by 1.7% primarily due to an increase in the UPT expense for natural gas Depreciation, depletion and amortization expense increased by 20.6% due to an increase in our depletable cost base, as well as a 5.8% increase in our total hydrocarbon production in barrels of oil equivalent basis Our hydrocarbon purchases increased due primarily to the commencement of natural gas purchases from our related party SIBUR Holding effective 1 January 2012 and, to a lesser extent, due to the commencement of unstable gas condensate purchases from our joint ventures SeverEnergia and Nortgas from April and November 2012, respectively 27 General and Administrative Expenses (RR million)
Decrease due to the fact, that we did not consolidate compensatory payments of Yamal LNG in 2012 as a result of a disposal of 20% interest in Yamal LNG in October 2011
116 74 53 10,936 2,219 500 (33) (211) Increase largely due to consulting 8,218 services related to our recent acquisitions
Increase due to: • a 6.0% indexation of base salaries effective 1 July 2012; • an increase in average number of employees due to acquisition of regional gas trader in November 2011 and the expansion of activities at Ust-Luga; • an increase in contributions to the non-budget funds due to the change from 1 January 2012 in taxable base and rates for contributions to the Pension Fund of the Russian Federation; • bonuses accrued to key management for the results achieved in 2012 ; • expenses related to defined benefit pension plan
2011 Employee Social expenses Legal, audit & Depreciation – Business trip Repair & Other 2012 compensation & consulting administrative expenses maintenance compensatory services buildings expenses payments 28 Materials, Services and Other Expenses (RR million)
Increase in materials used for repair Increase due to ongoing repair works works of our production assets and own at our wholly owned subsidiaries rail cars used for transportation of LPG
163 34 2 60 7,216 52 855 103
5,947
Increase due to: • a 6.0% indexation of base salaries effective 1 July 2012; • an increase in average number of employees; • expenses related to defined benefit pension plan
2011 Employee Materials & Electricity & Repair & Security Transportation Other 2012 compensation supplies fuel maintenance expenses expenses 29 Condensed Balance Sheet (RR million)
31 December 2012 31 December 2011 +/(-) +/(-)%
Total current assets 58,243 58,316 (73) -0.1% Incl. Cash and cash equivalents 18,420 23,831 (5,411) -22.7% Total non-current assets 404,890 325,116 79,774 24.5% Incl. Net PP&E 197,376 166,784 30,592 18.3%
Total assets 463,133 383,432 79,701 20.8%
Total current liabilities 55,130 50,114 5,016 10.0% Incl. ST debt 34,682 20,298 14,384 70.9% Total non-current liabilities 116,702 91,636 25,066 27.4% Incl. Deferred incom e tax liability 13,969 12,805 1,164 9.1% Incl. LT debt 97,805 75,180 22,625 30.1%
Total liabilities 171,832 141,750 30,082 21.2%
Total equity 291,301 241,682 49,619 20.5%
Total liabilities & equity 463,133 383,432 79,701 20.8%
30 Total Debt Maturity Profile (RR million)
49,852 In February 2013, the Group placed Russian rouble denominated Eurobonds in 34,682 the amount of RR 14 billion with a four-year maturity and an annual coupon rate of 7.75%
In February 2013, the Group repaid a 19,970 RR 15 billion loan from OAO Sberbank ahead 18,146 of its maturity schedule
9,837 In March 2013, the Group repaid a USD 200 million loan from OAO Nordea Bank ahead of its maturity schedule
2013 2014 2015 2016 After 2017
Current portion of long-term debt Long-term debt
Debt repayment schedule: Up to 2013 – Sumitomo Mitsui Banking Corporation Europe Limited, OAO Nordea Bank credit lines, RR denominated bonds, Sberbank loan Up to 2014 – Sberbank loan Up to 2015 – RR denominated bonds Up to 2016 – Eurobonds Five-Year (USD 600 mln) After 2017 – Eurobonds Ten-Year (USD 650 mln) and Eurobonds Ten-Year (USD 1 000 mln)
Note: Current debt maturity profile as of 31 December 2012 with repayments in the 12 months ended 31 December 2013, 2014, 2015, 2016, 2017 and after 2017 31 Debt Structure
Debt structure and maturities Net Debt (cash) evolution, RR million RR million 2012 2011 114,067 Short-term debt 34,682 20,298
Including current portion of 34,682 20,298 61,988 71,647 long-term debt
Long-term debt 97,805 75,180
Scheduled maturities 2010 2011 2012 2013 n/a 35,198 2014 9,837 - During 2012, the Group: 2015 19,970 - repaid a RR 10 billion loan from OAO Gazprombank 2016 18,146 19,206 ahead of its maturity schedule (January)
after 2017 49,852 20,776 repaid the final tranche of loan from ZAO UniCredit Bank aggregating USD 20 million as scheduled (October) Total debt 132,487 95,478 placed on the MICEX Stock Exchange the Russian rouble Cash and cash equivalents 18,420 23,831 Bonds of RR 20 billion (October) issued ten-year USD denominated Eurobonds in the Net debt (cash) 114,067 71,647 amount of USD one billion (December)
32 Internally Funded Investment Program
30 000 5,0
22 500 4,0
15 000 3,0
7 500 2,0 RR millions RR
- 1,0 Operating CF / / CAPEX CFOperating
(7 500) 0,0
(15 000) (1,0) 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 2010 2010 2010 2010 2011 2011 2011 2011 2012 2012 2012 2012 CAPEX Operating CF Operating CF/CAPEX
Core investments in upstream exploration, production and processing facilities funded primarily through internal cash flows 33