Russia Oil & Gas Report INCLUDES BMI's FORECASTS

Q2 2011 www.businessmonitor.com

RUssia oil & Gas Report INCLUDES BMI'S FORECASTS

ISSN 1748-4200 Published by Business Monitor International Ltd. RUSSIA OIL & GAS REPORT Q2 2011 INCLUDES 10-YEAR FORECASTS TO 2020

Part of BMI’s Industry Survey & Forecasts Series

Published by: Business Monitor International

Copy deadline: March 2011

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Russia Oil & Gas Report Q2 2011

CONTENTS

Executive Summary ...... 6

SWOT Analysis ...... 8

Russia Political SWOT ...... 8 Russia Economic SWOT ...... 8 Russia Business Environment SWOT ...... 9 Russia Energy Market Overview ...... 10

Global Oil Market Outlook ...... 13

Balancing Act ...... 13 Oil Price Forecasts ...... 14 Table: Oil Price Forecasts ...... 15 Short-Term Demand Outlook ...... 15 Table: Global Oil Consumption (000b/d) ...... 16 Short-Term Supply Outlook ...... 17 Table: Global Oil Production (000b/d)...... 19 Longer-Term Supply And Demand ...... 19 Regional Energy Market Overview ...... 21

Oil Supply And Demand ...... 21 Table: Central/Eastern Europe Oil Consumption (000b/d) ...... 22 Table: Central/Eastern Europe Oil Production (000b/d) ...... 23 Oil: Downstream ...... 24 Table: Central/Eastern Europe Oil Refining Capacity (000b/d) ...... 24 Gas Supply And Demand ...... 25 Table: Central/Eastern Europe Gas Consumption (bcm) ...... 25 Table: Central/Eastern Europe Gas Production (bcm) ...... 26 Table: Central/Eastern Europe LNG Exports/(Imports) (bcm) ...... 27 Business Environment Ratings ...... 28

Central/Eastern Europe Region ...... 28 Composite Scores ...... 29 Table: Regional Composite Business Environment Rating ...... 29 Upstream Scores ...... 30 Table: Regional Upstream Business Environment Rating...... 30 Russia Upstream Rating – Overview ...... 31 Russia Upstream Rating – Rewards ...... 31 Russia Upstream Rating – Risks ...... 31 Downstream Scores ...... 32 Table: Regional Downstream Business Environment Rating ...... 32 Russia Downstream Rating – Overview ...... 33 Russia Downstream Rating – Rewards ...... 33 Russia Downstream Rating – Risks ...... 33 Business Environment ...... 34

Legal Framework ...... 34 Infrastructure ...... 36

Russia Oil & Gas Report Q2 2011

Labour Force ...... 36 Foreign Investment Policy ...... 37 Tax Regime ...... 38 Security Risk ...... 39 Industry Forecast Scenario ...... 40

Oil And Gas Reserves ...... 40 Oil Supply And Demand ...... 40 Gas Supply And Demand ...... 41 LNG ...... 42 Refining And Oil Products Trade ...... 43 Revenues/Import Costs...... 43 Russia Oil And Gas – Historical Data And Forecasts ...... 44 Other Energy ...... 45 Russia Other Energy – Historical Data And Forecasts ...... 48 Key Risks To BMI’s Forecast Scenario ...... 49 Long-Term Oil And Gas Outlook ...... 49 Oil And Gas Infrastructure ...... 50

Oil Refineries ...... 50 Table: Refineries In Russia ...... 54 Oil Terminals/Ports ...... 55 Oil Pipelines ...... 56 LNG Terminals ...... 58 Gas Pipelines ...... 59 Macroeconomic Outlook ...... 62

Russia – Economic Activity ...... 64 Competitive Landscape ...... 65

Executive Summary ...... 65 Table: Key Domestic And Foreign Companies In The Russian Oil And Gas Sector ...... 66 Overview/State Role ...... 67 Licensing And Regulation ...... 67 Government Policy ...... 71 International Energy Relations ...... 72 Gas Transit And Marketing...... 76 Oil Transit ...... 82 Table: Key Upstream Players ...... 84 Key Downstream Players ...... 84 Company Monitor ...... 85

Gazprom ...... 85 Gazprom Neft ...... 94 Rosneft ...... 97 Lukoil ...... 101 TNK-BP ...... 106 Tatneft ...... 112 Total...... 114 Imperial Energy ...... 117 Novatek ...... 120 Russneft...... 124

Russia Oil & Gas Report Q2 2011

Surgutneftegaz – Summary ...... 127 Sistema – Summary ...... 127 Bashneft – Summary ...... 128 Itera – Summary ...... 129 Royal Dutch Shell – Summary ...... 129 ExxonMobil – Summary ...... 130 Transneft – Summary ...... 131 Sakhalin Energy – Summary ...... 131 Wintershall – Summary ...... 132 BP – Summary ...... 132 Lundin Petroleum – Summary ...... 133 Irkutsk Oil Company – Summary ...... 133 Aladdin Oil & Gas – Summary ...... 134 PetroNeft – Summary ...... 134 Alliance Oil – Summary ...... 135 Others – Summary ...... 135 Former IOC Partners – Summary ...... 136 Oil And Gas Outlook: Long-Term Forecasts ...... 138

Regional Oil Demand ...... 138 Table: CEE Oil Consumption (000b/d) ...... 138 Regional Oil Supply ...... 139 Table: CEE Oil Production (000b/d) ...... 139 Regional Refining Capacity ...... 140 Table: CEE Oil Refining Capacity (000b/d) ...... 140 Regional Gas Demand ...... 141 Table: CEE Gas Consumption (bcm) ...... 141 Regional Gas Supply ...... 142 Table: CEE Gas Production (bcm) ...... 142 Russia Country Overview...... 143 Methodology And Risks To Forecasts ...... 143 Glossary Of Terms ...... 144

Oil And Gas Ratings: Revised Methodology ...... 145

Introduction ...... 145 Ratings Overview ...... 145 Table: BMI Oil And Gas Business Environment Ratings: Structure ...... 146 Indicators ...... 147 Table: BMI Oil And Gas Business Environment Upstream Ratings: Methodology ...... 147 Table: BMI Oil And Gas Business Environment Downstream Ratings: Methodology ...... 148 BMI Methodology ...... 150

How We Generate Our Industry Forecasts ...... 150 Energy Industry ...... 150 Cross Checks ...... 151 Sources ...... 151

Russia Oil & Gas Report Q2 2011

Executive Summary

This latest Russia Oil & Gas Report from BMI forecasts that the country will account for 47.95% of Central and Eastern European (CEE) regional oil demand by 2015, while providing 70.33% of supply. CEE regional oil use of 5.42mn barrels per day (b/d) in 2001 rose to an estimated 6.09mn b/d in 2010. It should increase to around 6.93mn b/d by 2015. Regional oil production was 8.89mn b/d in 2001 and in 2010 averaged an estimated 13.78mn b/d. It is set to rise to 15.08mn b/d by 2015. Oil exports are growing steadily, because demand growth is lagging the pace of supply expansion. In 2001, the region was exporting an average of 3.47mn b/d. This total rose to an estimated 7.69mn b/d in 2010 and is forecast to reach 8.15mn b/d by 2015. Azerbaijan and Kazakhstan have the greatest production growth potential, although Russia will remain the most important exporter.

In terms of natural gas, the region in 2010 consumed an estimated 636.3bn cubic metres (bcm), with demand of 736.3bcm targeted for 2015, representing 15.7% growth. Production of an estimated 787.9bcm in 2010 should reach 954.2bcm in 2015, which implies net exports rising from an estimated 151.6bcm in 2010 to 217.9bcm by the end of the period. Russia’s share of gas consumption in 2010 was an estimated 62.16%, while its share of production is put at 71.07%. By 2015, its share of demand is forecast to be 57.90%, with the country accounting for 68.12% of supply.

The 2010 full-year outturn was US$77.45/bbl for OPEC crude, which delivered an average for North Sea Brent of US$80.34/bbl and for West Texas Intermediate (WTI) of US$79.61/bbl. The BMI price target of US$77 was reached thanks to the early onset of particularly cold weather, which drove up demand for and the price of heating oil during the closing weeks of the year.

We set our 2011 supply, demand and price forecasts in early January, targeting global oil demand growth of 1.53% and supply growth of 1.91%. With OECD inventories at the top of their five-year average range, we set a price forecast of US$80/bbl average for the OPEC basket in 2011. The unprecedented wave of popular uprisings in the Middle East and North Africa (MENA) that followed the removal of Tunisian President Ben Ali on January 14 has obviously fundamentally altered our outlook, particularly since the unrest spread to Libya in mid-February.

Taking into account the risk premium that has been added to crude prices in response to actual and perceived threats to supply, we have now raised our benchmark OPEC basket price forecast from US$80 to US$90/bbl for 2011 and from US$85 to US$95/bbl for 2012. Based on our expectations for differentials, this gives a forecast for Brent at US$94/bbl in 2011 and US$99/bbl in 2012. We have kept our long-term price assumption of US$90/bbl (OPEC basket) in place for the time being while we wait to see what path events in the MENA region take. We have also retained our existing supply and demand forecasts until the scheduled quarterly revision at the start of April.

Russia Oil & Gas Report Q2 2011

Russian real GDP is assumed by BMI to have risen by 4.0% in 2010. We are forecasting average annual growth of 4.4% in 2011-2015. State-controlled Gazprom has a virtual monopoly over gas transportation and exports. With it being the main provider, we see gas output rising from an estimated 560bcm in 2010 to 650bcm by 2015. Russian domestic companies control most of Russia’s oil production. Rosneft is the main state-controlled oil producer. The companies delivered 2010 output of crude oil and condensates averaging an estimated 10.28mn b/d. Oil production seems likely to rise only slowly over the next few years. Our 2015 production forecast is for 10.60mn b/d.

Between 2010 and 2020, we are forecasting an increase in Russian oil production of 0.5%, with output rising slowly from an estimated 10.28mn b/d in 2010 to a peak of 11.00mn b/d in 2016/17, before easing to 10.84mn b/d by 2020. Oil consumption during the period is forecast to rise by 28.3%, permitting exports peaking at 7.59mn b/d in 2016. Gas consumption is expected to be up from an estimated 396bcm to 471bcm by 2020, providing export potential peaking at 224bcm in 2015. Details of BMI’s 10-year forecasts can be found in the appendix to this report.

Russia now holds fifth place, below Poland and Turkey, in BMI’s composite Business Environment (BE) ratings table, which combines upstream and downstream scores. It holds fifth place, below Turkey, in BMI’s updated upstream Business Environment ratings, aided by unrivalled hydrocarbons resources. Its oil and gas reserves account for much of the upstream score, but licensing, privatisation and country risk factors are less impressive. Medium-term scope exists for Russia to overtake Turkey and Poland above it, but it is likely to remain behind Azerbaijan and Kazakhstan. Russia is at the top of the league table in BMI’s updated downstream Business Environment ratings, but shares first place with Turkey and is just one point above Poland. There are a few particularly high scores, and there is some risk from Poland over the longer term. There are excellent scores for refining capacity, oil and gas demand, population and nominal GDP.

Russia Oil & Gas Report Q2 2011

SWOT Analysis

Russia Political SWOT

Strengths The Russian government maintains a strong parliamentary majority and overwhelming public support.

Weaknesses A lack of transparency in decision-making, including high levels of behind-the- scenes activity by various power groups, makes for a large element of unpredictability in domestic politics over the long run. The high degree of political authority in the executive poses a risk to further institutional development in the legislative and judicial sectors.

Opportunities President Dmitry Medvedev has expressed a more compromising tone on foreign policy matters and has suggested a new emphasis on the development of civil society. Tight energy markets increase Russia's foreign policy options, especially as regards consumer states.

Threats Russia's moves to increase its regional dominance in the energy sector risk a further deterioration in relations with the Western-leaning countries of the 'Near Abroad'.

Russia Economic SWOT

Strengths Russia maintains enviable external account dynamics, with a robust current account surplus, limited foreign debt and high reserve holdings. This will continue to provide significant stability as the economy recovers from the financial crisis. Russia's large resource base will provide a strong foundation for foreign investments and export growth over the long term.

Weaknesses The economy's dependence on the oil sector makes it particularly vulnerable to a sustained decline in energy prices. The deterioration of Soviet-era infrastructure is a constraint to private sector activity, especially outside major cities.

Opportunities A revitalisation of the structural reform agenda, including support for small and medium-sized businesses, restructuring of the banking sector, administrative reform to tackle red tape and corruption, and a revamp of the 'natural monopolies', would go a long way towards developing the non-oil economy and improving long-term growth prospects. A US$1trn public-private investment plan over the long term will substantially modernise Russia's transport, communications, electricity and utilities infrastructure.

Threats The Russian economy is in a state of transition, with large current account and fiscal surpluses to be eroded significantly. With this will come new challenges to macroeconomic stability. The global financial crisis has created significant volatility in oil prices, which significantly elevates macroeconomic uncertainty.

Russia Oil & Gas Report Q2 2011

Russia Business Environment SWOT

Strengths The post-1998-crisis economic rebound, combined with significant reductions in personal and corporate income tax rates, has made Russia a much more attractive place to do business. In 2010, estimated oil production will have been around 11.5% of the world’s total at 10.36mn b/d, and Russia meets 22% of the world’s gas demand. The June 2010 BP Statistical Review of World Energy attributes 74.2bn bbl of proven oil reserves to Russia, which represents almost 7% of the world’s oil. Gas reserves of 44,376bcm (BP data) account for more than 30% of the world total.

Weaknesses The operating environment remains hazardous on a number of fronts, with many foreign investors put off by poor legal safeguards, high levels of bureaucracy and corruption, and the Kremlin's apparently politically motivated campaign against foreign oil firms. In a March 2010 Moscow Times article, deputy energy minister Sergei Donskoy claimed that the Natural Resources and Environment Ministry believes that Gazprom and Rosneft have insufficient resources to develop Russia's continental shelf on their own.

Opportunities Despite Russia's poor investment image in the West, the benefits of its immense natural resources wealth and large and rapidly growing domestic market are significant incentives for potential foreign direct investors. The government has made fighting corruption a key priority, and we expect sweeping legislative changes to significantly enhance the capacity of corruption fighting institutions in the medium term. Russia may relax rules limiting offshore exploration and production in the country to Rosneft and Gazprom, according to a report by the Moscow Times newspaper. According to the report, the proposal could lead to international oil companies becoming involved. The Russian government has stated that it intends to expand the role of nuclear and hydro-power generation in the future to allow for greater export of fossil fuels.

Threats State influence over business is on the rise. Most recently, foreign operators in the energy sector have come under pressure to allow state-owned firms greater involvement in their projects. Nevertheless, the worst-case scenario of a reversal of the 1990s privatisations appears unlikely. Given very low confidence in the domestic banking industry, the central bank's efforts to restructure the sector could destabilise it further.

Russia Oil & Gas Report Q2 2011

Russia Energy Market Overview

The June 2010 BP Statistical Review of World Energy attributes 74.2bn bbl of proven oil reserves to Russia, which represents almost 7% of the world’s oil. However, the end-2009 Oil & Gas Journal (OGJ) annual survey suggests just 60bn bbl. Large parts of Russia are underexplored, and there appears to be significant reserves potential in its share of the Caspian Sea. Gas reserves of 44,376bcm (BP data) account for more than 30% of the world total.

In 2010, oil production was around 11.5% of the world’s total at an estimated 10.28mn b/d, and Russia meets 22% of the world’s gas demand. Russian Prime Minister Vladimir Putin has said that the country will require investment of more than RUB8.6trn (US$280bn) to keep oil production at the current level until 2020. Energy minister Sergei Shmatko said that without tax reform, the country will see a fall of 20% in production to 8mn b/d.

With a total processing capacity of 5.62mn b/d in 2009, according to the BP Statistical Review, Russia is the world’s third largest refiner after the US and China. Although the vast majority of this capacity dates from Soviet times, the country’s largest players such as Rosneft have invested in upgrading their facilities to meet stringent fuels quality standards, allowing many companies to export refined products, particularly diesel, to the EU. Russia has also followed the EU’s lead in mandating cleaner fuels, introducing Euro-4 standards at the start of 2010 and preparing for the introduction of Euro-5 standards at the start of 2014.

Gas is the dominant fuel in Russia, accounting for an estimated 54.7% of 2010 primary energy demand (PED). It is followed by oil at 20.3%, coal at 13.2%, nuclear at 5.7% and hydro with a 6.3% share of PED. Regional energy demand is forecast to reach 1,518mn toe by 2015, representing 17.00% growth over the period 2010-2015. Russia’s estimated 2010 market share of 50.20% is set to fall to 49.09% by 2015. State gas monopoly Gazprom provides subsidised gas to the power industry through a deal with former monopoly supplier Unified Energy System (UES), meaning that price increases as part of a deregulation programme could make gas too costly for much of the Russian population.

Russian Prime Minister Vladimir Putin has confirmed that 2011 tax breaks for developers of new oil and gas deposits will remain unchanged. The statement came as Russia was considering several fiscal options to reduce budget shortfalls while maintaining spending plans. One such option is a planned rise in the country's mineral extraction tax (MET).

Under legislation passed in 2008, offshore fields in Russia, with the exception of those in the Caspian Sea, can only be developed by companies in which the government owns a stake of 50% or greater. In addition, companies applying to work on the fields must have a five-year record of working on such

Russia Oil & Gas Report Q2 2011

projects, effectively limiting participation to Gazprom and Rosneft. It is arguable that this has damaged Russian investment in offshore areas. In 2008, the two companies invested only RUR56.4bn (US$1.9bn at current rates) in E&P offshore Russia, a rate that energy ministry officials have claimed would mean ministry targets for offshore areas would take 165 years to fulfil.

Russia is the major gas exporter to Europe but the reliability of its supplies in the past few years been causing concern, thanks to pricing disputes with transit states such as Ukraine, frequent pipeline incidents and the capriciousness of the Russian weather. The Kremlin sees Asia the future source of export growth, but gas pipeline projects to the east of the Ural Mountains remain in the planning stages.

The country has an extensive gas export pipeline network bound for the Western markets. Some of the infrastructure, however, has fallen into disrepair, which is most acute in the poorer Former Soviet Union (FSU) countries that now serve as transit states on the way to the EU. In order to diversify its export routes, gain greater security of transport and maintain a closer grip on ex-communist states, Russia has been looking to construct new pipelines bypassing Eastern Europe.

Poor management during the Soviet era and a sharp decline in demand during the early-1990s undermined the coal industry. After a slight decline in 2002, production rebounded in 2003-2009, with 2009 output of 298mn tonnes. According to the government's energy strategy, Russia should produce more than 400mn tonnes by 2020. Russia's adherence to the stipulations of the Kyoto Protocol may lower utility sector demand for coal.

Russia's power sector includes more than 440 thermal and hydro-power plants (approximately 80 of the former are coal-fired), plus 31 nuclear reactors. A few generators in the far-eastern part of the country are not connected to the power grid. The system has a total electric generation capacity of almost 230 gigawatts (GW), with 2010 generation at an estimated 1,018TWh. The collapse of the Soviet Union initially precipitated a dramatic decline in energy generation, (down 18% between 1992 and 1999), followed by a gradual recovery (up 18% between 2000 and 2009).

The Russian government has stated that it intends to expand the role of nuclear and hydro-power generation in the future to allow for greater export of fossil fuels. Russia has an installed nuclear capacity of more than 21GW, distributed across 31 operational nuclear reactors at 10 locations, all west of the Ural Mountains. However, Russia's nuclear power facilities are ageing. Half of the country's nuclear reactors use the RBMK design employed in Ukraine's ill-fated Chernobyl plant. The working life of a reactor is considered to be 30 years – and nine of Russia's plants are between 26 and 30 years old, with a further six approaching 25 years of age.

Russia Oil & Gas Report Q2 2011

The Russian Ministry of Atomic Energy predicts that by 2020 nuclear generation could reach 300TWh, more than double the 2003 level. However, many plants are due for decommissioning, and meeting this target will require between US$5bn and US$10bn per year of investment over the next decade.

Russian state-owned nuclear power companies in March 2010 announced investment plans for 2010, and have earmarked billions of roubles for the sector. Speaking at a meeting of the country's power sector, Prime Minister Putin announced that the federal government will allocate RUB53bn (US$1.77bn) for Energoatom's (formerly Rosenergoatom) 2010 capital investment programme. The state-owned nuclear power operator has a total investment programme of RUB163.3bn (US$5.45bn) for 2010, of which RUB102bn (US$3.4bn) will be allocated for the construction of new stations. According to Russia's nuclear power regulator Rosatom, five existing nuclear power plants will be modernised and have their capacity expanded, reported Czech Business Weekly.

Russia Oil & Gas Report Q2 2011

Global Oil Market Outlook

The oil market activity of late 2010 was entirely as we predicted, with the result that the full-year price outturn of around US$77.40 per barrel (bbl) for the OPEC basket was barely above the BMI assumption. Dramatic winter scenes certainly helped provide an end-year shift in sentiment, even if actual crude consumption levels, as 12 months earlier, end up being little changed by the heating oil effect.

BMI has long held the view that we would see further appreciation in 2011 thanks to demand growth, moderate supply expansion and some room for inventories to ease. As of mid-January 2011, BMI assumptions were that global growth in GDP would exceed 3% in the current year and through to 2014, with a likely 3.2% rise in 2011 accelerating to a 3.7% rate of growth in 2012 and 2013. While this has no direct correlation with oil prices and, in fact, little real relevance to oil consumption trends, it supported our view at the start of the year of a steady increase in crude prices in 2011, reflecting an improved supply/demand balance, greater OPEC influence and falling inventories.

The unprecedented wave of popular uprisings in the Middle East and North Africa (MENA) that followed the removal of Tunisian President Ben Ali on January 14 has obviously fundamentally altered our outlook, particularly since the unrest spread to Libya in mid-February.

Taking into account the risk premium that has been added to crude prices in response to actual and perceived additional threats to supply, we have now raised our benchmark OPEC basket price forecast from US$80 to US$90/bbl for 2011 and from US$85 to US$95/bbl for 2012. Based on our expectations for differentials, this gives a forecast for Brent at US$94/bbl in 2011 and US$99/bbl in 2012. We have kept our long-term price assumption of US$90/bbl (OPEC basket) in place for the time being while we wait to see what path events in the MENA region take. We have also retained our existing supply and demand forecasts until the scheduled quarterly revision at the start of April.

Balancing Act

Oil demand in 2011 will almost certainly increase from 2010 levels. Growth in absolute volumes and in percentage terms is likely to be appreciably lower but should still be significant. This growth is dependent on prices and underlying economic activity.

Countering this positive factor is a list of negatives. First is the fragility of the energy-intensive developed economies where, as in 2008, substantial and sustained fuel cost inflation can cause great harm in terms of oil consumption and economic growth. Much of 2011’s projected oil demand growth can be attributed to the non-OECD states, which may prove more robust. Even here, however, removal or reduction of price subsidies could lead to demand disappointment in a high-price environment.

Russia Oil & Gas Report Q2 2011

Inventories of crude oil and refined products are still healthy. During 2010, in spite of much higher demand, there was little improvement in the global stock position. In spite of the weather and tax-related end-year crude stock draw in the US, inventories at the end of 2010 were still some 75mn bbl above the five-year average, with refined product stocks almost 50mn bbl in excess of the seasonal norm. Europe and Japan actually reported late-year stock builds, so the inventory overhang is substantial. This year needs a widening of the supply/demand gap in order to ensure a meaningful stock drawdown, which is the most necessary step towards sustainable oil price growth.

Excluding Libya, supply is on the rise, with a useful increase in non-OPEC oil production forecast in 2011. This alone could offset much of the forecast demand growth and leave inventories close to current levels. In addition, OPEC members, long frustrated with inadequate quotas, had already begun to place more oil on the market prior to the outbreak of political unrest in MENA. The removal of Libyan crude volumes from the market prompted Saudi Arabia to boost volumes, with reports in March that Nigeria, Kuwait and the UAE were preparing to follow suit. There remain question marks over the likes of Iran and Iraq, but the overall picture is likely to be one of reduced quota compliance and increased volumes.

So far, OPEC has decided against holding an emergency meeting prior to its scheduled summit in June. The more hawkish members of the producers’ club oppose raising quotas, arguing that the oil market remains well supplied despite the lost Libyan volumes, while also enjoying the surge in export revenues that higher prices provide. If the unrest in MENA spreads to other oil producing countries, however, and prices look likely to push beyond US$120/bbl, we expect a meeting to be called urgently and quotas to be raised. No OPEC member wants to see a repeat of the crude price collapse in H208, which crushed the cartel’s revenues. A second half quota increase should not therefore be ruled out.

While the extraordinary rise in prices in January and February has skewed the average price outlook for the year, in order for the oil price gains to be sustained, it is surely necessary for demand to rise more quickly than supply, thus reducing stocks and narrowing the safety margin. Too much oil price strength too early in the recovery will clearly weaken the demand trend, while encouraging suppliers. Bold speculators and charging bulls alone may not manage to create the conditions needed for crude to prosper in the long term.

Oil Price Forecasts

In terms of the OPEC basket of crudes, the average price in Q410 was about US$83.75/bbl, up from the US$73.76 recorded during the previous three months. This was an encouraging, if unsurprising outcome, given the intervention of Arctic weather and growing macroeconomic optimism. In Q409, the OPEC price averaged US$74.32/bbl, so the most recent quarter saw a year-on-year (y-o-y) gain of 12.7%. The 2010 full-year average works out at around US$77.40, compared with about US$60.90/bbl in 2009 (+27.1%).

Russia Oil & Gas Report Q2 2011

In terms of other marker prices, North Sea Brent averaged around US$86.50/bbl during Q4, with WTI achieving a surprisingly low US$85.10. This is another indication that WTI is much more prone to speculative activity and market sentiment than the other crudes, reducing its usefulness as a barometer of underlying fundamentals. Urals (Mediterranean delivery) in Q4 averaged US$85.30/bbl and Dubai realised US$83.40. These averages have been calculated using OPEC data and monthly prices from the International Energy Agency (IEA). The 2010 full-year outturn was US$77.45/bbl for OPEC crude, US$80.34/bbl for Brent and for US$79.61/bbl for WTI.

Taking into account the risk premium that has been added to crude prices in response to the unrest in MENA, we have raised our benchmark OPEC basket price forecast from US$80 to US$90/bbl for 2011 and from US$85 to US$95/bbl for 2012. Based on our expectations for differentials, this gives a forecast for Brent at US$94/bbl in 2011 and US$99/bbl in 2012. We have kept our long-term price assumption of US$90/bbl (OPEC basket) in place for the time being while we wait to see what path events in the MENA region take. The WTI, Brent, Urals and Dubai assumptions are US$92.20, US$92.60, US$91.10 and US$90.70/bbl, respectively. We have also retained our existing supply and demand forecasts until the scheduled quarterly revision at the start of April.

Table: Oil Price Forecasts

2008 2009 2010e 2011f 2012f 2013f 2014f 2015f

Brent (US$/bbl) 96.99 61.51 80.34 94.00 99.00 92.33 92.33 92.33

Urals - Med (US$/bbl) 94.49 61.04 78.45 90.98 96.04 91.22 91.22 91.22

WTI (US$/bbl) 99.56 61.68 79.61 85.00 91.00 92.32 92.32 92.32

OPEC basket (US$/bbl) 94.08 60.86 77.45 90.00 95.00 90.00 90.00 90.00

Dubai (US$/bbl) 93.56 61.69 78.11 90.65 95.70 89.19 89.19 89.19

e/f = estimate/forecast. Source: BMI.

Short-Term Demand Outlook

The BMI oil supply and demand assumptions for 2011 and beyond have once again been revised for all 72 countries forming part of our detailed coverage, reflecting the changing macroeconomic outlook and the impact of environmental initiatives. Investment in exploration, development and new production has continued to rise as a result of relatively stable crude prices, but deepwater activity has been set back by events in the Gulf of Mexico (GoM). Costs associated with oil field development and exploration/appraisal drilling are rising again with commodity and labour prices. Deepwater programmes

Russia Oil & Gas Report Q2 2011

remain particularly vulnerable thanks to equipment shortages, lack of personnel and the post-Macondo regulatory environment.

We have once again made some changes to forecast oil production levels, in line with OPEC output (prior to the MENA unrest) and known project delays, with no clear evidence of large-scale spending changes by international oil companies (IOCs) or national oil companies (NOCs). Even in the US, the backlash from BP’s Macondo disaster has led to only minor revisions to the production outlook. Other deepwater- focused regions appear to be re-examining procedures and legislation, but continuing with most exploration and development programmes.

Table: Global Oil Consumption (000b/d)

2008 2009 2010e 2011f 2012f 2013f 2014f 2015f

Africa 3,762 3,810 3,877 3,959 4,062 4,197 4,333 4,479

Middle East 6,864 7,146 7,395 7,698 7,973 8,230 8,442 8,699

NW Europe 13,545 12,964 13,021 13,051 13,097 13,204 13,197 13,177

N America 21,785 20,881 21,385 21,400 21,420 21,535 21,649 21,763

Asia/Pacific 25,994 26,343 27,547 28,077 28,756 29,511 30,259 31,012

Central/Eastern Europe 6,121 5,792 6,086 6,256 6,381 6,550 6,757 6,929

Latin America 7,724 7,631 7,875 8,070 8,238 8,401 8,555 8,693

Total 85,744 84,510 87,122 88,459 89,868 91,564 93,121 94,678

OECD 43,399 41,509 42,171 42,106 42,017 42,179 42,275 42,394

Non-OECD 42,345 43,001 44,950 46,353 47,851 49,385 50,847 52,284

Demand growth % (0.32) (1.44) 3.09 1.53 1.59 1.89 1.70 1.67

OECD % (3.55) (4.35) 1.59 (0.16) (0.21) 0.38 0.23 0.28

Non-OECD % 3.23 1.55 4.53 3.12 3.23 3.21 2.96 2.83 e/f =estimate/forecast. Source: Historical data: BP Statistical Review of World Energy, June 2010/BMI. All forecasts: BMI.

According to the BMI model, 2011 global oil consumption will increase by 1.53% from the 2010 level. The 2011 forecast represents slight lower OECD demand (-0.16%) and a revised non-OECD increase of 3.12%. The overall increase in demand is estimated at 1.34mn b/d. North America is now expected to see expansion of just 15,000b/d, with OECD European demand set to recover by 30,000b/d. Non-OECD gains are expected to be 1.92% in Asia, 2.48% in Latin America, 2.79% in Central/Eastern Europe, 4.10% in the Middle East and 2.41% in Africa.

Russia Oil & Gas Report Q2 2011

The International Energy Agency (IEA) is slightly more bullish in its January 2011 Oil Market Report (OMR), predicting a rise in 2011 oil demand of 1.6%, or 1.4mn b/d. The organisation’s assumptions suggest a 0.4% decline in 2011 OECD consumption, plus a 3.8% increase in non-OECD oil usage.

January 2011 Energy Information Administration (EIA) estimates suggest that world demand will rise from 86.6mn b/d in 2010 to 88.0mn b/d in 2011, with the 1.4mn b/d increase amounting to a gain of 1.6%. Non-OECD demand is predicted to increase by 3.6% (1.5mn b/d), while OECD demand is expected to slip by 10,000b/d to 45.9mn b/d. Consumption in the US is expected to increase by 160,000b/d (0.8%). With Canadian demand 1.3% higher and that of Europe 0.7% lower, it is in Japan that the US energy body sees the greatest risk of a decline – forecasting a fall of 3.4%.

OPEC’s January 2011 report suggests a likely increase in 2011 global oil consumption of 1.2mn b/d, or 1.4%. OECD demand is forecast to rise by 180,000b/d (0.4%). Non-OECD demand is expected to average 41.2mn b/d, compared with 40.2mn b/d in 2010 (+2.5%).

Short-Term Supply Outlook

According to the revised BMI model, 2011 global oil production will rise by 1.91%, representing an OPEC increase of 2.87% and a non-OPEC gain of 1.19%. The overall increase in supply is estimated at 1.75mn b/d in 2011. We assume that the current OPEC production ceiling will be retained for the first half of 2011, but that actual output will exceed the Q410 level. There is scope for an increased OPEC production ceiling in H2, dependent on demand and prices, but quota adherence is expected to deteriorate even if the theoretical ceiling is retained.

The EIA was in January 2011 forecasting a 170,000b/d y-o-y rise in non-OPEC oil output, representing a gain of just 0.3%. World oil production is predicted to be 87.73mn b/d in 2011, up from 86.40mn b/d (+1.33mn b/d) in 2010. The US organisation expects a 1.2mn b/d (3.3%) upturn in OPEC oil and natural gas liquids (NGLs) output.

OPEC itself sees 2011 non-OPEC supply rising by 410,000b/d to 52.67mn b/d. In 2011, OPEC NGLs and non-conventional oils are expected to increase by 460,000b/d over the previous year to average 5.25mn b/d. The January 2011 OPEC monthly report argues that the call on OPEC crude is expected to average 29.4mn b/d, representing an upwards adjustment of 200,000b/d from its previous assessment and an increase of 400,000b/d from the previous year.

The IEA’s 2011 assumption for non-OPEC oil supply is 53.4mn b/d, representing a rise of 1.1%. This view is based on higher estimated Chinese oil production offset by marginally lower output in the OECD Pacific, the former Soviet Union, Latin America and global biofuels. OPEC production of natural gas liquids (NGLs) is expected to rise sharply from 5.29mn b/d to 5.84mn b/d. Increased biofuels supply

Russia Oil & Gas Report Q2 2011

(+9.9%) and a slight increase in processing gains implies a need for OPEC crude volumes of 29.9mn b/d in 2011. This is above OPEC’s estimated Q410 output of 29.5mn b/d.

Russia Oil & Gas Report Q2 2011

Table: Global Oil Production (000b/d)

2008 2009 2010e 2011f 2012f 2013f 2014f 2015f

Africa 10,197 9,679 9,982 10,372 10,691 11,028 11,409 11,922

Middle East 26,229 24,406 24,901 25,221 25,553 25,966 26,576 27,240

NW Europe 4,912 4,657 4,438 4,288 4,040 3,833 3,693 3,503

N America 11,668 11,912 12,365 12,250 12,450 12,750 13,190 13,750

Asia/Pacific 8,689 8,568 8,827 9,090 9,095 9,174 9,029 8,847

Central/Eastern Europe 13,045 13,417 13,776 13,946 14,157 14,400 14,686 15,078

Latin America 9,857 9,749 10,028 10,288 10,442 10,783 11,220 11,662

OPEC NGL adjustment 4,600 4,660 5,260 5,870 5,970 6,109 6,301 6,553

Processing gains 2,084 2,290 2,200 2,230 2,275 2,320 2,366 2,414

Total 91,274 89,331 92,009 93,762 94,752 96,446 98,626 101,125

OPEC 35,568 33,076 33,924 34,439 35,027 35,845 36,971 38,445

OPEC inc NGLs 40,168 37,736 39,184 40,309 40,998 41,954 43,272 44,998

Non-OPEC 51,106 51,595 52,825 53,452 53,755 54,492 55,354 56,127

Supply growth % 1.55 (2.13) 3.00 1.91 1.06 1.79 2.26 2.53

OPEC % 3.15 (6.05) 3.84 2.87 1.71 2.33 3.14 3.99

Non-OPEC % 0.33 0.96 2.38 1.19 0.57 1.37 1.58 1.40 e/f =estimate/forecast. Source: Historical data: BP Statistical Review of World Energy, June 2010/BMI. All forecasts: BMI.

Longer-Term Supply And Demand

The BMI model predicts average annual oil demand growth of 1.68% between 2011 and 2015, followed by 1.42% between 2015 and 2020. After the assumed 3.09% global demand recovery in 2010, we are assuming 1.53% growth in 2011, followed by 1.59% in 2012, 1.89% in 2013, 1.70% in 2014 and 1.67% in 2015.

OECD oil demand growth is expected to remain relatively weak throughout the forecast period to 2020, reflecting market maturity, the ongoing effects of price-led demand destruction and the greater commitment to energy efficiency. Following the 1.59% rise in 2010 OECD oil consumption, we expect to see a decrease of 0.16% in 2011. On average, OECD demand is forecast to rise by 0.11% per annum in 2011-2015, then fall by 0.19% per annum in 2015-2020.

Russia Oil & Gas Report Q2 2011

For the non-OECD region, the demand trend in 2011-2015 is for 3.07% average annual market expansion, followed by 2.66% in 2015-2020. Demand growth is forecast to ease from 4.53% in 2010 to 3.12% in 2011.

BMI is forecasting global oil supply increasing by an average 1.91% annually between 2011 and 2015, with an average yearly gain of 1.53% predicted in 2015-2020. We expect the trend to be at its weakest towards the end of the 10-year forecast period, with gains of just 0.75% and 0.62% predicted in 2019 and 2020.

Non-OPEC oil production is expected to rise by an annual average of 1.22% in 2011-2015, then just 0.34% in 2015-2020. OPEC volumes are forecast to increase by an annual average of 2.81% between 2011 and 2015, rising to 2.95% per annum in 2015-2020.

In 2012, the EIA is predicting world oil demand growth of 1.6mn b/d. Its current base case sees the world consuming 89.7mn b/d during the year, up around 1.9%. OECD consumption is expected to edge ahead, but the non-OECD countries are tipped to deliver 3.7% growth.

Russia Oil & Gas Report Q2 2011

Regional Energy Market Overview

Although Russia will continue to dominate oil supply in the region, backed by huge and under-exploited reserves, the Caspian states have an important role to play, with Azerbaijan and Kazakhstan an increasingly significant factor. The growth rate in Russian oil supply has slowed appreciably since the beginning of the decade but the acceleration of Caspian expansion means that the region will make a growing contribution to world oil production. Russia’s gas deposits not only dominate regional supply but are also the biggest single source for Western Europe. While consumer countries wish to diversify away from Russia, there are no other regional suppliers of note. LNG is not a major trade for the CEE region, although Russia began exporting gas in March 2009 from the Far Eastern Sakhalin projects into the Asia Pacific markets.

Oil Supply And Demand

Russian 2009/10 production surprised on the upside, with output fighting back after tax adjustments were introduced and modified. The country’s supply had fallen in 2008, ending a strong growth trend that began in 2000. We see little risk of a downturn in 2011, but 2011/12 could emerge as the near-term peak in output. A decline below 10.4mn b/d is thought likely in 2013, before increased investment delivers extra volumes of Russian crude and supply rises towards 10.6mn b/d in 2015 and to 11mn b/d by 2016/2017.

The other regional theme is the Caspian states and their ability to meet production and export targets. The ultimate long-term potential is in little doubt, but a mixture of technical, commercial and political factors looks set hold back the rate of supply expansion. In 2009/10, the previously expected strong growth in output evaporated in the wake of persistent technical and commercial problems. Azerbaijan has some near-term upside. Kazakhstan’s near-term output growth potential is limited thanks to technical problems and the Kashagan field dispute, but longer-term prospects are good once Kashagan becomes a major contributor.

CEE oil production averaged an estimated 13.78mn b/d in 2010. The region's output is expected to be 13.95mn b/d in 2011 and to reach 15.08mn b/d by 2015. In terms of demand, the estimated 2010 average of 6.09mn b/d is set to rise to 6.93mn b/d by 2015. This means that net exports from the region will climb steadily, from an estimated 7.69mn b/d in 2010 to 8.15mn b/d by 2015.

Russia Oil & Gas Report Q2 2011

Table: Central/Eastern Europe Oil Consumption (000b/d)

Country 2008 2009 2010e 2011f 2012f 2013f 2014f 2015f

Azerbaijan 71 70 75 80 86 92 98 105

Bulgaria 103 98 99 101 102 105 107 109

Croatia 106 105 106 108 110 112 114 115

Czech Republic 210 205 207 215 219 223 228 231

Hungary 164 161 162 165 169 172 174 177

Kazakhstan 263 260 265 276 250 263 276 289

Poland 554 553 558 572 581 589 598 607

Romania 221 211 211 217 226 233 240 247

Russia 2,817 2,695 2,930 3,010 3,085 3,162 3,241 3,322

Slovakia 90 83 83 85 87 90 93 96

Slovenia 58 51 53 55 58 60 61 63

Turkey 663 621 640 656 669 689 740 755

Turkmenistan 117 120 124 130 136 143 150 158

Ukraine 336 307 315 323 333 343 353 363

Uzbekistan 101 101 106 111 117 123 129 135

BMI universe 5,874 5,641 5,934 6,104 6,228 6,396 6,602 6,774 other CEE 247 151 151 152 153 154 155 155

Regional total 6,121 5,792 6,086 6,256 6,381 6,550 6,757 6,929

e/f = estimate/forecast. Historical data: BP Statistical Review of World Energy, June 2010/BMI. All forecasts: BMI.

CEE regional oil use of 5.42mn barrels per day (b/d) in 2001 rose to an estimated 6.09mn b/d in 2010. It should increase to around 6.93mn b/d by 2015. Russia accounted for an estimated 48.15% of 2010 regional consumption, with its market share expected to be 47.95% by 2015.

Russia Oil & Gas Report Q2 2011

Table: Central/Eastern Europe Oil Production (000b/d)

Country 2008 2009 2010e 2011f 2012f 2013f 2014f 2015f

Azerbaijan 914 1,033 1,060 1,100 1,215 1,385 1,395 1,425

Bulgaria 3 3 3 3 3 3 3 3

Croatia 22 24 22 22 21 21 20 20

Czech Republic 14 11 9 9 8 8 8 7

Hungary 38 36 35 31 29 28 26 24

Kazakhstan 1,554 1,682 1,765 1,820 1,850 1,900 2,050 2,300

Poland 36 34 35 33 32 30 29 27

Romania 98 93 93 89 85 80 77 71

Russia 9,888 10,032 10,275 10,350 10,400 10,395 10,499 10,604

Slovakia 4 4 4 3 3 3 3 2

Turkey 48 53 55 54 52 50 47 44

Turkmenistan 205 206 220 240 270 310 350 375

Ukraine 107 99 95 92 90 90 86 81

Uzbekistan 114 107 105 100 100 97 95 95

Regional total 13,045 13,417 13,776 13,946 14,157 14,400 14,686 15,078

e/f = estimate/forecast. Historical data: BP Statistical Review of World Energy, June 2010/BMI. All forecasts: BMI.

Regional oil production was 8.89mn b/d in 2001 and in 2010 averaged an estimated 13.78mn b/d. It is set to rise to 15.08mn b/d by 2015. Russia in 2010 contributed an estimated 74.59% to regional production, with a market share of 70.33% forecast for 2015.

Oil exports are growing steadily, because demand growth is lagging the pace of supply expansion. In 2001, the region was exporting an average of 3.47mn b/d. This total rose to an estimated 7.69mn b/d in 2010 and is forecast to reach 8.15mn b/d by 2015. Azerbaijan and Kazakhstan have the greatest production growth potential, although Russia will remain the most important exporter.

Russia Oil & Gas Report Q2 2011

Oil: Downstream

Table: Central/Eastern Europe Oil Refining Capacity (000b/d)

Country 2008 2009 2010e 2011f 2012f 2013f 2014f 2015f

Azerbaijan 442 442 442 442 442 442 442 442

Bulgaria 115 177 177 177 177 177 177 207

Croatia 114 114 250 250 250 250 250 250

Czech Republic 183 183 183 183 183 183 183 183

Hungary 161 161 161 161 161 161 161 161

Kazakhstan 348 348 348 348 348 348 348 348

Poland 493 493 493 493 578 578 578 578

Romania 517 517 537 537 537 537 537 537

Russia 5,596 5,616 5,663 5,663 5,663 5,763 5,763 5,813

Slovakia 115 115 121 121 121 121 121 121

Slovenia na na na na na na na na

Turkey 613 613 613 613 613 613 813 813

Turkmenistan 237 237 237 237 237 275 275 275

Ukraine 880 880 880 880 880 880 880 880

Uzbekistan 222 222 224 224 224 224 224 224

Regional Total 10,036 10,118 10,329 10,329 10,414 10,552 10,752 10,832 e/f = estimate/forecast. na = not applicable. Historical data: BP Statistical Review of World Energy, June 2010/BMI. All forecasts: BMI.

Refining capacity for the region was 10.02mn b/d in 2001, rising gradually to an estimated 10.33mn b/d in 2010. Capacity expansion will lag that in most other emerging regions, although Russia plans a processing boost and the likes of Poland and Kazakhstan should also build new or expand existing facilities. The region’s total capacity is forecast to reach 10.83mn b/d by 2015 – well ahead of oil demand, therefore implying substantial net exports of refined products. Russia’s share of regional refining capacity in 2010 was an estimated 54.83%, and its market share is set to be 53.67% by 2015.

Russia Oil & Gas Report Q2 2011

Gas Supply And Demand

Table: Central/Eastern Europe Gas Consumption (bcm)

Country 2008 2009 2010e 2011f 2012f 2013f 2014f 2015f

Azerbaijan 9.2 7.7 8.1 9.0 10.0 10.5 11.0 11.6

Bulgaria 3.3 2.5 3.0 3.4 4.0 4.5 4.7 5.0

Croatia 3.0 3.0 3.0 3.2 4.0 4.2 4.3 4.5

Czech Republic 8.7 8.2 8.5 9.0 10.0 10.4 11.0 11.4

Hungary 11.8 10.1 10.4 10.8 11.5 12.3 13.0 14.0

Kazakhstan 20.1 19.6 21.0 23.5 26.0 27.3 28.7 30.1

Poland 13.9 13.7 14.0 15.0 16.0 16.5 17.5 18.0

Romania 16.0 13.6 13.6 14.1 14.6 15.1 15.6 16.2

Russia 416.0 389.7 395.5 403.5 411.5 417.0 418.0 426.4

Slovakia 5.7 5.6 5.7 6.0 6.3 6.6 6.7 7.0

Slovenia 1.1 1.0 1.0 1.1 1.2 1.3 1.3 1.4

Turkey 36.0 32.1 34.0 37.0 40.0 42.0 44.5 50.0

Turkmenistan 19.0 19.8 21.3 22.9 24.6 26.4 28.4 30.6

Ukraine 60.0 47.0 47.7 49.1 50.3 51.6 52.9 54.2

Uzbekistan 48.7 48.7 49.5 50.7 52.0 53.3 54.6 56.0

Regional Total 672.5 622.3 636.3 658.3 682.0 698.9 712.3 736.3

e/f = estimate/forecast. Historical data: BP Statistical Review of World Energy, June 2010/BMI. All forecasts: BMI.

Russia Oil & Gas Report Q2 2011

Table: Central/Eastern Europe Gas Production (bcm)

Country 2008 2009 2010e 2011f 2012f 2013f 2014f 2015f

Azerbaijan 14.8 14.8 17.5 21.0 21.0 21.0 21.0 21.0

Bulgaria 0.3 0.2 0.2 0.5 0.8 1.1 1.5 1.4

Croatia 2.0 2.0 2.0 2.0 2.5 3.0 3.0 3.0

Czech Republic 0.3 0.2 0.2 0.2 0.2 0.1 0.1 0.1

Hungary 2.6 2.6 2.5 2.2 2.0 2.0 2.0 2.0

Kazakhstan 29.8 32.2 40.0 44.0 52.0 60.0 64.0 66.0

Poland 4.1 4.1 4.3 4.4 4.6 4.5 4.5 4.3

Romania 11.4 10.9 10.5 10.0 9.0 8.8 8.6 8.3

Russia 601.7 527.5 560.0 574.0 605.0 620.0 635.0 650.0

Slovakia na na na na na na na na

Slovenia 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

Turkey 1.1 0.8 0.6 0.7 1.0 1.2 2.0 2.0

Turkmenistan 66.1 36.4 65.0 66.0 70.0 74.0 90.0 90.0

Ukraine 19.0 19.3 20.0 22.0 22.0 21.0 21.0 20.0

Uzbekistan 62.2 64.4 65.0 71.5 75.0 81.0 83.5 86.0

Regional total 815.5 715.5 787.9 818.6 865.2 897.9 936.4 954.2 e/f = estimate/forecast. na = not applicable. Historical data: BP Statistical Review of World Energy, June 2010/BMI. All forecasts: BMI.

In terms of natural gas, the region in 2010 consumed an estimated 636.3bcm, with demand of 736.3bcm targeted for 2015, representing 15.7% growth. Production of an estimated 787.9bcm in 2010 should reach 954.2bcm in 2015, which implies net exports rising from an estimated 151.6bcm in 2010 to 217.9bcm by the end of the period. Russia’s share of gas consumption in 2010 was an estimated 62.16%, while its share of production is put at 71.07%. By 2015, its share of demand is forecast to be 57.90%, with the country accounting for 68.12% of supply.

Russia Oil & Gas Report Q2 2011

Liquefied Natural Gas

Table: Central/Eastern Europe LNG Exports/(Imports) (bcm)

Country 2008 2009 2010e 2011f 2012f 2013f 2014f 2015f

Russia na 6.6 12.0 15.0 20.0 20.0 20.0 25.0

Croatia na na na na na na na na

Turkey (5.3) (5.7) (6.5) (6.5) (6.5) (12.0) (12.0) (12.0)

Poland na na na na na na (2.0) (4.0)

Regional total (5.3) 0.9 5.5 8.5 13.5 8.0 6.0 9.0 e/f = estimate/forecast. na = not applicable. Historical data: BP Statistical Review of World Energy, June 2010/BMI. All forecasts: BMI.

Land boundaries mean pipeline transportation of gas is the favoured option, particularly from Russia through the CEE region into Western Europe. However, Russia became an LNG exporter in 2009 as Gazprom/Shell’s Sakhalin-II project entered production. Also, Poland is planning medium- to long-term LNG imports as a means of diversifying supply away from Russia, while proposals are being discussed for a Croatian LNG terminal on the Adriatic coast, with imports possible by 2017.

Russia Oil & Gas Report Q2 2011

Business Environment Ratings

Central/Eastern Europe Region

The CEE region comprises 15 countries, including the new EU member states, Russia and the four leading Central Asian hydrocarbons producers. State influence remains very high, and is arguably increasing in both Russia and Kazakhstan. There has been widespread privatisation progress in the EU states, but far less movement in the other key states. Kazakhstan’s moves to take a bigger share of the Kashagan project and to modify licensing laws are, we hope, an isolated example, although Russian tax tweaks, environmental claims and attempted asset re-nationalisation have undermined its already unattractive licensing and regulatory regime.

Oil production growth for the period to 2015 ranges from a negative 31% for Hungary to a positive 70% in Turkmenistan, while oil demand growth ranges from 9% to 40% across the region. Gas output is forecast to fall by 21% in Romania, but to rise 65% in Kazakhstan. The range for forecast gas consumption growth is from 13% to 65%. The political and economic environment varies, depending partly on market maturity and EU membership. Russia and the Caspian states are viewed as more volatile and less stable than the recent EU entrants.

Russia Oil & Gas Report Q2 2011

Composite Scores

Composite Business Environment scores are calculated using the average of individual upstream and downstream ratings. Kazakhstan and Azerbaijan continue to dominate the top of the regional league table, taking first and second places with respective scores of 59and 58 points out of a possible 100. Slovenia takes the final place in the rankings, with a composite upstream and downstream score of 41 points out of the 100 available. The points spread in the CEE region is considerably narrower than elsewhere, with the lowest-ranked country having 69% of the score allocated to the highest-ranked. Russia now holds fifth place below Poland and Turkey, with a medium-term chance of catching those immediately above, but little hope of challenging the two leading Central Asian energy powerhouse states. Turkey is likely to remain in a close fight with Poland for position, while Romania and Ukraine are closely matched just above the middle of the league table, ahead of the Czech Republic, Hungary and Bulgaria with their limited upstream resource potential. Turkmenistan and Uzbekistan are tied near the bottom and have the potential to challenge the trio immediately above them. Croatia and Slovakia are struggling to keep clear of Slovenia in last place.

Table: Regional Composite Business Environment Rating

Upstream Rating Downstream Rating Composite Rating Rank

Kazakhstan 71 46 59 1

Azerbaijan 67 49 58 2

Poland 54 60 57 3=

Turkey 53 61 57 3=

Russia 51 61 56 5

Romania 49 54 52 6

Ukraine 43 58 50 7

Czech Republic 44 51 47 8=

Hungary 45 49 47 8=

Bulgaria 50 43 47 8=

Turkmenistan 48 44 46 11=

Uzbekistan 48 43 46 11=

Croatia 48 41 45 13

Slovakia 45 42 44 14

Slovenia 37 44 41 15

Source: BMI. Scores are out of 100 for all categories, with 100 the highest.

Russia Oil & Gas Report Q2 2011

Upstream Scores

Kazakhstan and Slovenia remain the best and worst performers in this segment, showing that the overall pecking order is somewhat different from that for combined scores. Azerbaijan is second, itself having a very useful 13-point lead over Poland. Turkmenistan’s hydrocarbons resources mean it is nearing the mid-point of the league table, challenging Croatia and having overtaken Uzbekistan. Bulgaria and Romania are squabbling over sixth and seventh places, while Slovakia and Hungary are tied for 11th – just ahead of the Czech Republic. Both it and Ukraine should be able to keep clear of bottom-ranked Slovenia.

Table: Regional Upstream Business Environment Rating

Rewards Risks

Industry Country Industry Country Upstream Rewards Rewards Rewards Risks Risks Risks Rating Rank

Kazakhstan 79 75 78 65 38 56 71 1

Azerbaijan 65 85 70 75 34 61 67 2

Poland 34 80 45 75 76 75 54 3

Turkey 43 65 48 70 51 63 53 4

Russia 68 30 58 30 38 33 51 5

Bulgaria 50 50 50 45 58 50 50 6

Romania 39 55 43 65 61 63 49 7

Croatia 34 55 39 70 66 69 48 8=

Turkmenistan 70 45 64 40 23 34 48 8=

Uzbekistan 44 40 43 45 22 37 48 8=

Hungary 24 80 38 60 70 63 45 11=

Slovakia 25 70 36 65 69 66 45 11=

Czech Republic 25 70 36 55 74 62 44 13

Ukraine 41 50 43 45 37 42 43 14

Slovenia 21 60 31 40 75 52 37 15

Scores are out of 100 for all categories, with 100 the highest. The Upstream BE Rating is the principal rating. It comprises two sub- ratings ‘Rewards’ and ‘Risks’, which have a 70% and 30% weighting respectively. In turn, the ‘Rewards’ Rating comprises Industry Rewards and Country Rewards, which have a 75% and 25% weighting respectively. They are based upon the oil and gas resource base/growth outlook and sector maturity (Industry) and the broader industry competitive environment (Country). The ‘Risks’ rating comprises Industry Risks and Country Risks which have a 65% and 35% weighting respectively and are based on a subjective evaluation of licensing terms and liberalisation (Industry) and the industry’s broader Country Risks exposure (Country), which is based on BMI’s proprietary Country Risk Ratings. The ratings structure is aligned across the 14 Industries for which BMI provides Business Environment Ratings methodology, and is designed to enable clients to consider each rating individually or as a composite, with the choice depending on their exposure to the industry in each particular state. For a list of the data/indicators used, please consult the appendix. Source: BMI.

Russia Oil & Gas Report Q2 2011

Russia Upstream Rating – Overview

Russia holds fifth place below Turkey in BMI’s updated upstream Business Environment ratings, aided by unrivalled hydrocarbons resources. Its oil and gas reserves account for much of the upstream score, but licensing, privatisation and country risk factors are less impressive. Medium-term scope exists for Russia to overtake Turkey and Poland above it, but it is likely to remain behind Azerbaijan and Kazakhstan.

Russia Upstream Rating – Rewards

Industry Rewards: On the basis of upstream data alone, Russia is the third most attractive state in the CEE region, just behind Turkmenistan. This reflects the highest-placed oil and gas reserves, fifth-ranked oil production growth outlook and gas reserves to production ratio (RPR).

Country Rewards: Influencing Russia’s fourth-highest position in the Rewards section is its unenviable country rewards rating, which takes last place, behind even Uzbekistan. The state has greater ownership of upstream assets than elsewhere in the region – and the industry features relatively few non-state concerns.

Russia Upstream Rating – Risks

Industry Risks: Russia is ranked last, behind even Turkmenistan, in the Risks section of our ratings. Its last position for industry risks is attributable to a poor licensing environment, and limited near-term privatisation prospects.

Country Risks: Russia’s broader country risks environment is unattractive and is ranked equal 10th alongside Kazakhstan. The best, and only respectable, score is for long-term policy continuity. Physical infrastructure is below the regional average, while corruption is a key risk for private companies. Furthermore, their ability to operate is weakened by the country’s rule of law.

Russia Oil & Gas Report Q2 2011

Downstream Scores

Russia/Turkey and Croatia now bracket the remaining 12 CEE states in the downstream rankings, with Turkey having again caught Russia, in spite of the size of Russia’s fuels market and refining capacity etc. Turkey’s risk profile is substantially better and it may be able to retain a share of regional leadership over the medium term. Poland is now holding third place and is also a potential regional leader. Ukraine is now two points behind Poland, and is unlikely to challenge it during the next few quarters. Romania has overtaken the Czech Republic to take fifth place. Turkmenistan has remained clear of Uzbekistan, with the latter still tied with Bulgaria. Slovakia is just a point clear of Croatia at the foot of the table.

Table: Regional Downstream Business Environment Rating

Rewards Risks

Industry Country Industry Country Downstream Rewards Rewards Rewards Risks Risks Risks Rating Rank

Turkey 57 68 60 80 40 64 61 1=

Russia 72 74 73 20 52 33 61 1=

Poland 46 76 53 85 64 77 60 3

Ukraine 60 56 59 65 40 55 58 4

Romania 51 52 51 70 50 62 54 5

Czech Republic 30 52 36 100 65 86 51 6

Azerbaijan 60 40 55 25 52 36 49 7=

Hungary 33 42 36 95 60 81 49 7=

Kazakhstan 54 44 52 20 52 33 46 9

Turkmenistan 52 28 46 40 41 40 44 10=

Slovenia 28 34 29 85 65 77 44 10=

Bulgaria 37 40 38 60 52 57 43 12=

Uzbekistan 46 34 43 40 50 44 43 12=

Slovakia 24 38 28 85 60 75 42 14

Croatia 32 36 33 65 54 61 41 15

Scores are out of 100 for all categories, with 100 the highest. The Downstream BE Rating comprises two sub-ratings ‘Rewards’ and ‘Risks’, which have a 70% and 30% weighting respectively. In turn, the ‘Rewards’ Rating comprises Industry Rewards and Country Rewards, which have a 75% and 25% weighting respectively. They are based upon the downstream refining capacity/product growth outlook/import dependence (Industry) and the broader socio-demographic and economic context (Country). The ‘Risks’ rating comprises Industry Risks and Country Risks which have a 60% and 40% weighting respectively and are based on a subjective evaluation of regulation and liberalisation (Industry) and the industry’s broader Country Risks exposure (Country), which is based on BMI’s proprietary Country Risk Ratings. The ratings structure is aligned across the 14 Industries for which BMI provides Business Environment Ratings methodology, and is designed to enable clients to consider each rating individually or as a composite, with the choice depending on their exposure to the industry in each particular state. For a list of the data/indicators used, please consult the appendix. Source: BMI.

Russia Oil & Gas Report Q2 2011

Russia Downstream Rating – Overview

Russia is at the top of the league table in BMI’s updated downstream Business Environment ratings, but shares first place with Turkey and is just one point above Poland. There are a few particularly high scores, and there is some risk from Poland over the longer term. There are excellent scores for refining capacity, oil and gas demand, population and nominal GDP.

Russia Downstream Rating – Rewards

Industry Rewards: On the basis of downstream data alone, Russia ranks first among the region’s 15 countries, above Kazakhstan. This is attributable to the country’s first-placed refining capacity and oil/gas demand, and third-ranked refining capacity growth potential.

Country Rewards: Russia ranks first in terms of the Rewards section, and its country rewards rating has second place in the region, behind only Poland. Growth in GDP per capita is the second-highest for the entire region. Population and nominal GDP rank first. There is still considerable state ownership of downstream assets, and the downstream industry is only moderately competitive.

Russia Downstream Rating – Risks

Industry Risks: In the Risks section of our ratings, Russia is ranked equal last, alongside Kazakhstan. Its joint lowest score with Kazakhstan for industry risks reflects the harsh regulatory regime and stagnant privatisation trend.

Country Risks: Its broader country risks environment is ranked equal seventh alongside Azerbaijan, Kazakhstan and Bulgaria. The scores for rule of law and short-term economic growth risk let the country down, and it fares little better in terms of physical infrastructure and legal framework. Operational risks for private companies are reduced by the state’s reasonable scores for short-term economic external risk and short-term policy continuity.

Russia Oil & Gas Report Q2 2011

Business Environment

Legal Framework

Russia's judicial system remains in a nascent stage of development and as a result impartial dispute resolution mechanisms are not well established. Political pressures can influence decisions, especially at the regional and local court levels, while the myriad of shifting laws and overlapping regulatory frameworks can make understanding the legal system difficult. Moreover, enforcement of decisions is inconsistent as the bailiffs, whose responsibility it is to follow up on judgements, are not administratively part of the court system and lack in trained personnel. That said, there are signs that the capacity, independence and clarity of the system is improving, albeit slowly. In the meantime, there are federal- level options for corporate arbitration including the Arbitration Court of the Russian Federation and the International Commercial Arbitration Court. In the case of the former, the court has special powers to seize property before a trial to prevent premature disposal of assets, as well as enforcement authority in the banking sector for financial compensation.

The legal market in Russia has long been penetrated by major Western multinational firms, which have invested significantly in establishing bases, mainly in Moscow and St. Petersburg. Considering that the majority of major mergers and acquisition deals are international in scope and conducted under English law, these firms tend to dominate the corporate law sector and their fees reflect international standards. Fees for a partner of one of the major firms will range from EUR400 to EUR750 per hour. Cheaper rates can generally be found at local firms, though they will tend to specialise in intellectual property and litigation as opposed to large-scale corporate transactions. That said, domestic firms are gaining ground in corporate experience and are likely to gain market share over the long term.

The existing legal framework in Russia guarantees private property rights for citizens as well as the rights of foreign entities to purchase and sell businesses within the country. By law, the nationalisation of foreign investment projects is prohibited, though exceptions can be made if prompted by legislative action in a sector deemed of national interest. In these cases, appeals may be made to the federal court system and full compensation is to be paid in a prompt fashion.

This potential for expropriation under politically defined criteria, which is less than clearly elucidated, is an issue for foreign investors, especially for those involved in sectors such as natural resources, transport, energy and communications. The most publicised case of the government pushing out an existing foreign investment position was when Anglo-Dutch firm Royal Dutch Shell was forced to sell a controlling share in its US$22.5bn Sakhalin-2 oil and gas project to Gazprom in 2006. In a related matter, US firm Exxon was banned from selling its natural gas from the Sakhalin-1 project to China. In addition to these high-

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profile incidents, smaller cases of politically motivated expropriation have been known to occur at the regional level.

The Russian government has made sincere efforts to improve intellectual property rights in the country, especially as part of its effort to enter into the WTO. As part of its accession process, Moscow has amended and drafted new laws that coordinate intellectual property rights protection with the WTO's Agreement on Trade-Related Aspects of Intellectual Property Rights (TRIPS). That said, media piracy and the counterfeiting of patented and copyright protected goods remains a major issue and the judiciary has yet to vigorously crack down on intellectual property violations. Sentences for prosecutions remain relatively small, often resulting in fines or suspended prison sentences. However, the situation is improving and there are signs that the courts are increasingly willing to hand out full prison sentences for copyright violations. The federal customs service also has a new focus on intellectual property rights concerns, working more closely with foreign firms in suspected cases of trademark infringements.

Corruption is a serious problem in Russia, with bribery seen as endemic throughout the country's government agencies. Reflecting this, Russia was ranked in the bottom quintile of 179 countries in the latest Transparency International 'Corruption Perceptions Index'. At 143rd, Russia was ranked below most other emerging European states, with only the Central Asian countries, Belarus and Azerbaijan, maintaining a poorer record. Part of the problem has been the lack of political initiative from the top-end of the federal government. While Russia is a signatory of the UN Convention Against Corruption, it has yet to ratify the Organization for Economic Co-operation and Development (OECD)'s Anti-Bribery Convention, nor has it established a fully independent anti-corruption agency as several other countries have done when facing widespread abuses of government authority. Indeed, currently the fight against corruption is conducted by the Ministry of Internal Affairs and the Federal Security Service who are both part of government mechanisms that are reported to have significant corrupt elements themselves.

The government's perception of the issue is starting to shift though, and we are encouraged by the increasing number of statements from high government officials expressing concern about the situation. President Dmitry Medvedev has declared that he would make fighting corruption a 'national priority project'. This announcements followed rising poll evidence indicating that corruption has become worse over the past several years and that it is considered by most Russians as one of the most pressing issues facing the country. Though there has yet to be any concrete action, we believe that these statements will presage a more concerted government effort to stamp down on corruption, especially at the administrative level. We do not expect changes overnight, however, and caution that any positive changes will likely take place over the long term.

Russia Oil & Gas Report Q2 2011

Infrastructure

Russia is currently facing a massive infrastructure deficit following decades of underinvestment after the collapse of the Soviet Union. According to government estimates, the electricity, transport and telecommunications networks will all require capital infusions in the hundreds of billions of dollars over the next 10 years to catch up with physical deterioration as well as absorb the increased demand from the increasingly mobile population. While transport networks are well established, particularly in the western parts of the country and in and around the major metropolitan centres of Moscow and St. Petersburg, the age of the system is noticeable, with severe traffic jams and delays in rail transport common. Beyond the major city centres, transportation is even more problematic, with road and rail connections severely undeveloped beyond the continental European part of the country. Access to territories east of the Ural mountain range is restricted by the lack of road connections and even the roads between secondary cities west of the Urals tend to be small and poorly maintained.

The domestic air network is also a major concern, with one of the worst regional safety records in the world. The breakup of flag carrier Aeroflot has led to the creation of multiple small, domestic carriers, which has exacerbated the problem of maintenance regulation. Despite the poor condition of domestic travel, connecting internationally to the country is relatively easy. Major international airports at St. Petersburg and Moscow maintain regularly scheduled direct services on mainline carriers to most major centres in Europe and Asia as well as to selected cities in North America, the Middle East and Africa. Moscow, especially, remains an important hub for international travellers for onward travel throughout the Commonwealth of Independent States (CIS). That said, business travellers have long complained about the queues and delays at Russian customs and immigration desks at the main Sheremetyevo-2 international airport. Furthermore, transferring to domestic connector flights is made difficult by the fact that most non-international flights operate out of separate airports (Sheremetyevo-1 and Domodedovo) and heavy traffic and the lack of public transit makes connecting between the airports problematic.

Despite the current problems, we are positive about the outlook for Russian infrastructure, alongside government plans to invest upwards of US$1.0trn in housing, transport and electricity grids over the next 10 years. Specific plans have yet to be released, however, and we caution that delays owing to construction are likely to exacerbate problems within the medium term, before they improve in the long term.

Labour Force

The Russian labour market is heavily differentiated by the difference between the situation in Moscow/St. Petersburg and that in those rural regions that have yet to benefit from the recent economic boom. Part of the problem in Russia is the lack of trans-regional labour mobility. The maintenance of residency permits, a housing shortage in major metropolitan cities and the lack of a developed mortgage market makes

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moving to the job centres particularly difficult for an average Russian labourer. Developments to boost government spending on housing and the increasing sophistication of the banking sector should help to alleviate these factors, but not for several years to come.

Foreign Investment Policy

Russia's foreign investment policy is anchored by the 1991 Investment Code and 1999 Law on Foreign Investment, both of which guarantee equal treatment for foreign and domestic investors. These reflect the government's generally favourable disposition to foreign investments, which Moscow sees as a key driver of economic growth and facilitator of market liberalisation. That said, the government's official policy belies the actual on-the-ground situation for foreign investors, which remains hampered by red tape, restrictions in the energy sector, protectionism and creeping state involvement in several sectors of the economy.

The government requires approval by the respective ministry or state agency responsible for any foreign investment project that exceeds RUB100mn, uses assets of existing Russian firms or defence industries, involves the exploitation of natural resources, or where it involves the foreign entity controlling a majority stake of the enterprise. There are also foreign ownership restrictions for several industries and firms deemed to be of strategic importance. Foreigners may control a maximum of 25% of firms in the aerospace industry and of Unified Energy System (UES), the electricity company, which is currently under a massive privatisation initiative. Ownership of agricultural land is also restricted to 49-year leases and land on an international border is prohibited from any foreign control.

Beyond the formal regulations in place, the government tends to favour joint venture projects and has been known to deter investors from majority stakes in major projects. This has become a particularly acute problem in the energy industry, where the government has forced the sale of major interests of foreign firms to domestic companies. Notably, while Production Sharing Agreement (PSA) legislation is in place, amendments in 2003 have effectively restricted the potential for new PSAs. There is a marked displeasure from Moscow on the conditions of existing foreign investment agreements in the energy sector, and we could see further attempts to rewrite agreements in future along the lines of the Sakhalin-2 natural gas project.

While there are significant drawbacks to Russia's foreign investment policy, it is important to recognise that liberalisation is still occurring and the government remains particularly open to investment in the service and manufacturing industries. Majority ownership of insurers by a foreign firm (so long as the parent firm has offices in the EU) has been allowed since 2003, and the reduction of customs tariffs on automotive parts imports destined for assembly plants in Russia, has substantially improved the attractiveness of the country as a location for transport production.

Russia Oil & Gas Report Q2 2011

Currently, Russia's free-trade regime is restricted only to discussion with Belarus, Ukraine and the Central Asian states to create a 'Common Economic Space'. The country lacks any substantive free trade pact with major trading partners in the EU or East Asia. That said, the government is aggressively pushing forward on entering the WTO, which we believe will be successfully accomplished some time by 2013. Entry into the WTO will substantially improve the country's trade dynamics, lowering tariff barriers, harmonising regulations to international standards and entering Russia into a trusted dispute resolution mechanism.

In the meantime though, Russia has made progress in creating special economic zones (SEZs) in Zelenograd (near Moscow), Dubna (near Moscow), St. Petersburg, Tomsk, Lipetsk and Yelabuga. The zones focus on promoting industrial production, with companies operating within them benefiting from reduced land and property taxes and a full waiver of customs duties on both imports and exports. We expect more SEZs to be created in the coming years, targeting a wide variety of industries. Already, special technology parks have been promoted for five cities while special tourist economic zones have been opened in a further seven.

Tax Regime

Russia's tax system was overhauled in 2001, with a view to simplifying and easing the fiscal load on companies and individuals. The corporate tax standard rate is 24% (reduced from 35%). This comprises a regional tax of 17%, federal tax of 5% and local tax of 2%. Banks and financial corporations may pay up to 27%.

Income tax on resident individuals is currently charged at a flat rate of 13% for most income and most individuals. The non-resident flat rate is 30%. Foreign residents pay tax only on income earned in Russia. The standard rate of capital gains tax for a corporation is the same as the tax on its regular income. A capital loss on the sale of a fixed asset can be offset against income in following years.

Capital gains tax for an individual is payable on proceeds of the sale of real estate owned for less than five years, or the sale of another asset held for less than three years, less certain deductions. The maximum deduction on a real estate sale is RUB1mn; for the sale of another asset it is RUB125,000. Profits on the sale of real estate owned for more than five years, or on other assets that have been owned for three years, are tax-exempt. Withholding taxes on payments in Russia are: for dividends, 9% (increased from 6% in January 2005), or 15% when a foreign payer/recipient is involved; for interest, 20%; and for royalties, 20%. VAT is generally 18% with plans for a further lowering to 15% or 16%. An exception is children's products and food, which carry a rate of 10%. VAT is charged on assets and services, as well as on imports. Medications and medical products and technological products are exempt from VAT on being imported. Exports are not subject to VAT.

Russia Oil & Gas Report Q2 2011

Despite the seemingly simple distribution of tax rates, Russia's tax regime remains complex and this makes for subjective interpretations of tax legislation and disputes with revenue authorities commonplace. Indeed, in a recent report by Ernst and Young it was reported that 63% of corporate respondents felt that the tax regime negatively affected the investment climate. Moreover, 84% of a group of 58 international and Russian companies reported having ongoing disputes with the government, of which 82% had sought litigation to resolve the matter. The primary problem is that the tax authorities in Russia lack independence from political influence, which has created a situation where conflicts of interest between businesses and politicians with vested competing business interests have led to unfair application of tax laws. A concern for investors in the energy sector is the current tax regime in place for the oil sector.

Oil exports are taxed at 80% when oil is priced above US$27/bbl and, with little sign that oil prices will drop below their historic high levels and forecast to remain well above US$50/bbl through to 2012, this tax bracket has effectively become permanent. Despite calls from major domestic and international oil firms operating in the country to lower the rate, the political leadership in Russia has shown no sign of backing down from the existing tax regime, suggesting that the 80% bracket is unlikely to be reduced in the medium term.

Security Risk

Street crime is a serious issue in Russia and caution must be taken when out in public. Racially motivated harassment and assault has become a particular problem amid an increase in nationalist sentiment and xenophobia. Minority groups from other CIS countries have reported being targeted by local 'skinhead' groups who have also been known to attack foreign students, government officials and business people operating in the country. The crimes are by no means random. Moscow police arrested four Russian teenagers in February 2010, charging them with the murder of 20 foreigners as part of an organised gang.

While foreigners have not been the targets of large-scale politically motivated terrorism in Russia, bombings and hostage-takings have taken place in the major metropolitan centres over the past decade. Targets have included major public facilities and government buildings. Persisting tension with separatist groups in Chechnya mean that the risk of further terrorist attacks is likely to remain elevated over the long term. Indeed, ongoing disputes in the Caucasus make travel to specific parts of the region particularly hazardous from a security risk perspective. Civil unrest combined with a lack of government control means that visiting Chechnya, for instance, is not recommended, with kidnappings of foreigners and Russians commonplace.

Russia Oil & Gas Report Q2 2011

Industry Forecast Scenario

Oil And Gas Reserves

Proven oil reserves are estimated at around 74.2bn bbl (BP data) but, with insufficient investment in domestic exploration and development activity, we expect to see a steady decline over the forecast period to just 70bn bbl by 2015. The OGJ currently attributes just 60bn bbl to Russia. However, an independent and up-to-date audit of Russian hydrocarbons potential could show considerable upside to existing estimates. Gas reserves of an estimated 44,376bcm could also dwindle without higher investment, although Shell believes Russia’s Yamal peninsula and the Kara Sea region could hold more than 30,000bcm of gas.

Oil Supply And Demand

Russian Prime Minister Vladimir Putin Russia Oil Production, has said that the country will require Consumption And Imports investments worth more than RUB8.6trn 2000-2015 (US$280bn) to keep oil production at the 700 700 current level until 2020. Energy minister 600 600 Sergei Shmatko said that without tax 500 500 reform the country will see a fall of 20% 400 400 300 300 in production to 8mn b/d. In February 200 200 2011 Putin said that the country should 100 100 0 0 aim over the long term to produce 505mn 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2011f 2012f 2013f 2014f 2015f

tpa of oil, equivalent to just around 2010e 10.2mn b/d, adding that this is the ideal gas production, bcm gas consumption, bcm gas exports, bcm (RHS) production volume for Russia. e/f = estimate/forecast; Source: Historical data - BP Statistical Review of World Energy, June 2010; Value data - BMI; Forecasts - According to preliminary data, Russian BMI oil production rose in January 2011 to around 10.5mn b/d, following a weather‐related dip in December 2010.

The Vankor field, which started up in the spring of 2009, averaged around 250,000b/d in 2010. Peak production capacity of 500,000b/d is expected to be reached in 2014. Lukoil has now brought into play its Yuri Korchagin field, one of the first to be developed in Russia’s section of the Caspian Sea. It is forecast to reach peak capacity of 50,000b/d in early 2011. BMI is assuming average production of 10.35mn b/d in 2011, with scope for an increase to 10.60mn b/d by 2015.

Russia Oil & Gas Report Q2 2011

TNK-BP is pushing ahead with further development of the Uvat oil project in the Tyumen region of West Siberia. The company expects to reach peak output of around 220,000b/d in 2015-2016.

The economy ministry’s latest long-term production forecast sees output stable at 10.6mn b/d in 2015- 2020. From 2011 onwards, Russian oil consumption can be expected to rise at a rate of up to 2.5% per annum, probably ahead of supply expansion. Oil consumption, which in 2010 hit an estimated 2.93mn b/d, should therefore edge towards 3.32mn b/d by 2015 – providing export potential of 7.28mn b/d.

Starting up in late-2010 and officially opening in January 2011, the Skovorodino-Daqing spur of the ESPO pipeline has opened up a new market for Russian crude. From January 2011, the Skovorodino- Daqing spur has been transporting 300,000b/d of ESPO crude under an oil-for-loans deal signed by Moscow and Beijing in mid-2009.

Gas Supply And Demand

In 2009, Russian gas production was Russia Gas Production, lower at 528bcm as the global economic Consumption And Imports crisis drove down energy demand in 2000-2015 Russia and Europe. BMI’s latest projections call for production of an 12000 12000 10000 10000 estimated 560bcm in 2010 to rise to 8000 8000 574bcm in 2011 and 650bcm by 2015. 6000 6000 4000 4000 Gazprom has said that it plans to move 2000 2000 forward the start of production at its 0 0

Kirinskiy field in the Sakhalin-III project. 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2011f 2012f 2013f 2014f 2015f 2010e The field, which was initially expected to oil production, 000 b/d oil consumption, 000 b/d come onstream in 2014, is now scheduled oil exports, 000 b/d (RHS)

to start at the end of 2011 or the e/f = estimate/forecast; Source: Historical data - BP Statistical beginning of 2012. Speaking in October Review of World Energy, June 2010; Value data - BMI; Forecasts - BMI 2009, Gazprom spokesperson Alexander Mendel told reporters that the schedule for the project had been moved forwards. The announcement followed news that Gazprom had signed a preliminary non-binding agreement to supply China with around 70bcm of gas.

The Kirinskiy gas and condensate field, discovered in 1992, is part of the Sakhalin-III project. Under the Russian system of reserves classification, it is estimated that the field holds 75.4bcm of gas and 8.6mn tonnes of condensate. In June 2009, the field was awarded to Gazprom, and exploration drilling started in July 2009. There are several options for exporting gas from the field. One possibility is that the field

Russia Oil & Gas Report Q2 2011

could be linked to the Sakhalin-II project and exported via the Sakhalin-II LNG terminal, which began operations in February 2009.

Another export route could be the Sakhalin-Khabarovsk-Vladivostok (SKV) pipeline, which is expected to commence operations in Q311. It was originally expected to transport gas from Sakhalin-I, but the operator of the Sakhalin-I project, US major ExxonMobil, wants to export the gas to China at higher prices. In June 2009, South Korea and Russia signed an MoU to study the options for delivering Russian gas to South Korea. Kogas is interested in extending the SKV pipeline to South Korea.

LNG

Russia became an LNG exporter when the Sakhalin-II project exported its first cargo in March 2009. Japanese utilities are the principal recipients of LNG shipped from the Sakhalin-II project; the rest is earmarked for Korea Gas (Kogas, 1.6mn tpa) and Sempra Energy's Baja California terminal (1.8mn tpa). More LNG terminals are planned around the Sakhalin Island and the Pacific coast. In April 2010, Gazprom signed a second deal with Sempra Energy to supply the North American market with LNG from the Sakhalin-II project. Gazprom announced that it would supply Sempra's wholly owned Cameron LNG terminal near Lake Charles in Louisiana with up to two cargoes a year, roughly equivalent to 220,000tpa of LNG. The long-term arrangement began in June 2010. Neither the duration of the deal nor the financial details were disclosed.

The second major area for LNG is north-western Russia: the Barents Sea and the Yamal-Nenets Autonomous Region. Until 2011 the most advanced project was the arguably the Shtokman field in the Barents Sea. Plans for LNG exports from the field, however, are under threat owing to falling LNG demand in the US, the project’s target market. The flagship Arctic LNG project now appears to be Yamal LNG, a JV between Gazprom and gas independent Novatek, which was joined in early 2011 by French major Total. The other significant Arctic project is Pechora LNG led by Russian investment company Alltech Group. All three projects are in the early stages and output is unlikely until the second half of the 2010s.

The Japanese and Russian governments signed a preliminary agreement to build an LNG export terminal in Vladivostok, according to a July 2010 Nikkei report. Few details of the plan have been disclosed, though the facility is expected to have a liquefaction capacity of 5mn tpa, or 6.9bn bcm, which will be delivered by pipeline from eastern Russia. First deliveries could come as early as 2017, according to the report. It is as yet unclear where gas for the project will be sourced, but Japanese companies Mitsubishi and Mitsui already have interests in the Sakhalin II project and have reportedly expressed an interest in joining the Sakhalin III project, both located in eastern Russia.

Russia Oil & Gas Report Q2 2011

Shell is reportedly in the process of selecting overseas assets that could be offered to Gazprom for investment, including in 'areas of strategic interest' such as the Asia-Pacific region, one source said. The Anglo-Dutch major is attempting to convince Gazprom to add a third liquefaction train to the producing Sakhalin-II LNG project, in which Shell holds a 27.5% interest and Gazprom has a 50% operating stake. Bloomberg's sources revealed that Shell may also gain access to new blocks offshore Sakhalin Island in order to locate more feedstock gas to supply this train, whose construction would boost the plant's 13.2bcm output by 50%.

Refining And Oil Products Trade

The current 5.66mn b/d of refining capacity is set for modest expansion, with 5.81mn b/d expected to be available by end-2015. As with most Russian investment plans there is a high degree of uncertainty. However, Russia could have the capability to export more than 1.0mn b/d of refined products by the end of the forecast period. The country’s largest players, such as Rosneft, have invested in upgrading their facilities to meet stringent fuels quality standards, allowing many companies to export refined products, particularly diesel, to the EU. Russia has also followed the EU’s lead in mandating cleaner fuels, introducing Euro-4 standards at the start of 2010 and preparing for the introduction of Euro-5 standards at the start of 2014. These upgrades will help ensure Russia’s status as a major refined products exporter to the EU market.

In October 2009, TNK-BP announced its intention to invest US$1.3bn in upgrading its refineries, following a meeting of its board of directors. The refinery upgrade reflects the company's need to comply with European emissions standards, which are being introduced in stages in Russia.

Rosneft has allocated US$3bn to upgrade its refineries in the Samara region, according to remarks made by the region's Governor Vladimir Artyakov in October 2010. The upgrades are part of a broader trend of companies in the Volga Federal District, one of Russia's main refining areas, seeking to meet increasingly stringent Russian fuels standards.

Revenues/Import Costs

Using the BMI base case oil price assumption of US$90/bbl in 2011, US$95/bbl for 2012, and an average US$90/bbl in 2013-2015 (OPEC basket), crude export revenues for 2011-2015 should range from US$241bn to US$239bn. Gas export revenues for 2015 are estimated at US$88bn, taking the combined end-period crude and gas revenue total to around US$327bn.

Russia Oil & Gas Report Q2 2011

Russia Oil And Gas – Historical Data And Forecasts

2008 2009 2010e 2011f 2012f 2013f 2014f 2015f

Proven Reserves, bn bbl 74.3 74.2 74.2 74.0 74.0 73.0 71.5 70.1

Oil Production, 000b/d 9,888 10,032 10,275 10,350 10,400 10,395 10,499 10,604

Oil Consumption, 000b/d 2,817 2,695 2,930 3,010 3,085 3,162 3,241 3,322

Oil Refinery Capacity, 000b/d 5,596 5,616 5,663 5,663 5,663 5,763 5,763 5,813

Oil Exports, 000b/d 7,071 7,337 7,345 7,340 7,315 7,233 7,258 7,281

Value of Oil Exports, US$mn (BMI base case) 242,800 162,990 207,439 241,119 253,639 237,592 238,409 239,196

Value of petroleum exports, US$mn (BMI base case) 308,358 208,321 261,186 306,908 333,602 316,706 322,463 327,467

Average Oil Price (OPEC basket), US$/bbl 94.1 60.9 77.4 90.0 95.0 90.0 90.0 90.0

Value of oil exports at constant US$50/bbl - US$mn 129,046 133,900 134,046 133,955 133,494 131,995 132,450 132,887

Value of oil exports at constant US$100/bbl - US$mn 258,092 267,801 268,093 267,910 266,988 263,991 264,899 265,773

Value of Petroleum exports at constant US$50/bbl - US$mn 162,649 169,474 168,777 170,505 175,580 175,948 179,146 181,926

Value of Petroleum exports at constant US$100/bbl - US$mn 325,298 338,949 337,555 341,009 351,160 351,896 358,292 363,853

Refined products exports, 000b/d 1,380 1,517 1,317 1,237 1,162 1,160 1,081 1,037

Gas: Proven Reserves, bcm 43,302 44,376 44,376 45,000 45,000 45,000 45,000 44,100

Gas Production, bcm 601.7 527.5 560.0 574.0 605.0 620.0 635.0 650.0

Gas Consumption, bcm 416.0 389.7 395.5 403.5 411.5 417.0 418.0 426.4

Gas Exports, bcm (BMI) 185.7 183.0 164.5 170.5 193.5 203.0 217.0 223.6

Value of Gas Exports, US$mn (BMI base case) 65,559 45,331 53,747 65,789 79,963 79,115 84,053 88,271

Value of Gas Exports at constant US$50/bbl – US$mn 33,603 35,574 34,731 36,550 42,086 43,953 46,696 49,040

Value of Gas Exports at constant US$100/bbl – US$mn 67,207 71,148 69,462 73,099 84,171 87,905 93,393 98,079

LNG Exports, bcm (BMI) na 6.6 12.0 15.0 20.0 20.0 20.0 25.0

LNG Price US$/mn BTU 12.55 9.06 11.52 13.40 14.14 13.40 13.40 13.40

LNG Revenues, US$mn (BMI) na 1,674 3,870 5,627 7,919 7,503 7,503 9,378 e/f = estimate/forecast; na = not applicable. Source: Historical data, BP Statistical Review of World Energy, June 2010, Forecast, BMI.

Russia Oil & Gas Report Q2 2011

Other Energy

The country’s power consumption is expected to increase from an estimated 715TWh in 2010 to 881TWh by the end of the forecast period. After power industry usage and system losses, we see an estimated net surplus of up to 14-20TWh during the period, assuming 3.2% annual average growth in generation in 2010-2015.

Russian power generation in 2010 will have been an estimated 1,018TWh, having risen 2.5% from the 2009 level. BMI is forecasting an average 3.2% annual increase to 1,197TWh between 2010 and 2015, although investment levels look set to come under pressure. Russia’s thermal generation in 2010 will have been an estimated 667TWh, or 51.89% of the regional total. By 2015, the country is expected to account for 49.00% of thermal generation. In order to free up fossil fuels for export, Russia is expected to concentrate on expansion of nuclear and hydro-electric generating capacity.

According to the US-based Energy Information Administration (EIA), Russian net generation should rise from 959TWh in 2007 to 1,038TWh in 2015 and to 1,134TWh by 2020. Gas-fired generation is expected to increase from 385TWh to 420TWh in 2007-2020, with nuclear power rising from 148TWh to 258TWh and coal-fired generation up from 221TWh to 228TWh. Hydro-electric generation is forecast to increase from 175TWh to 201TWh over the same period.

In November 2009, the government's ‘Energy Strategy 2030’ was published, projecting investments for the next two decades. It envisaged a possible doubling of generation capacity from 225GW in 2008 to 355-445GW in 2030. A revised scheme in mid-2010 projected 1,288TWh of power demand in 2020 and 1,553TWh by 2030, requiring 78GW of new plant by 2020 and 178GW by 2030. The scheme envisages decommissioning 68GW of capacity by 2030. New investment by 2030 of RUR9,800bn in power plants and RUR10,200bn in transmission will be required.

Coal-fired generation will have accounted for 17.9% of the country’s total output in 2010, according to BMI estimates. We expect the fuel’s market share to be 17.1% by 2015, firing a projected 205TWh at the end of the forecast period. Russian coal consumption is forecast to rise from the estimated 2010 level of 86mn toe to 97mn toe by 2015. This equates to an increase in demand from 129mn to 145mn tonnes of hard coal. According to the government's energy strategy, Russia should produce more than 400mn tonnes of coal by 2020.

According to the World Nuclear Association (WNA), Russia has 31 operating reactors totalling 21.7GW capacity. It estimates that 2009 nuclear production was 163.3TWh, which is in line with the BP Statistical Review (June 2010) data used in our model. Half of the reactors use the RBMK design employed in Ukraine's ill-fated Chernobyl plant. The working life of a reactor is considered to be 30 years – nine of Russia's plants are between 26 and 30 years old, with a further six approaching 25 years of age.

Russia Oil & Gas Report Q2 2011

The WNA argues that nuclear electricity output has been rising strongly because of better performance from the reactors, with utilisation rising from 56% to 76% during 1998-2003, and then on to 79.5% in 2008. Energoatom is aiming for 90% capacity utilisation by 2015. Nuclear generating capacity is planned to grow more than 50% from 23GW in 2006 to 35GW in 2016, and to at least double to 5 GW by 2020.

According to the US-based EIA, Russian net nuclear generation should rise from 148TWh in 2007 to 258TWh by 2020.

In 2006, Rosatom announced a target of nuclear providing 23% of electricity by 2020 and 25% by 2030, but 2007 plans approved by the government have scaled this back, and in 2009 it was reduced further. The most recent federal target programme envisages a 25-30% nuclear share in electricity supply by 2030, 45-50% in 2050 and 70-80% by end of century.

The Russian Ministry of Atomic Energy predicts that by 2020 nuclear generation could reach 300TWh, almost twice the current level. We are assuming 230TWh of nuclear generation (19.7% of total generation) by 2014, which is broadly consistent with the government’s target. However, many plants are due for decommissioning and meeting this target will require between US$5bn and US$10bn per annum of investment over the next decade.

Atomstroyexport will begin building on the second phase of the Tianwan nuclear power plant in China in 2011. The company signed an agreement on March 2010 for the work with its Chinese partner Jiangsu Nuclear Power Corporation (JNPC), according to Sergei Kiriyenko, the head of Russian state company Rosatom.

The two companies signed a deal to build two VVER-1000 reactors with 1,000 megawatts (MW) of power output. China will pay EUR1.3bn (US$1.8bn) to Russia to build the second stage of the power plant.

The Russian government has also made hydro-electric generation a priority alongside nuclear, particularly in the Russian Far East, where provision and delivery of electricity supply can be problematic. Companies of former national generator UES are believed to be investing US$14bn in the development of Russia's hydro-electric sector, particularly in Siberia and the Far East. Hydro generation in 2010 will have been an estimated 180TWh and BMI is forecasting an increase to 230TWh by 2015, taking the hydro market share from 17.7% to at least 19.2%.

According to Interfax reports early in 2009, UC Russian Aluminum (RusAl) and RusHydro were aiming to cut spending on construction work and equipment at the Boguchansk Hydro-power Plant project by 40% in 2009-2010, which would help save around RUB8bn (US$0.3bn).

Russia Oil & Gas Report Q2 2011

Reports in August 2009 suggested that RusAl has paid RUB897mn (US$31mn) for the construction of the 3GW Boguchansk plant in Serbia. This brings its investment in the project level with that of its partner, RusHydro, according to Bloomberg. Both the partners will share further financing equally. The company has also stated that its creditors are thinking of a reorganisation plan that will help it pay for the plant. April 2009 reports from Reuters stated that RusAl was planning to defer the completion of the half- built Siberian plant until after 2010. However, the proposed delay would cost RusHydro around RUB9bn.

May 2009 press reports suggest that RusHydro is planning to build a hydro-power plant in Russia's Far East in collaboration with Japan's Mitsui. Together the two companies are planning to construct the Nizhne-Bureyskaya hydro-electric facility, with both having an equal stake in the venture, according to the Moscow Times, which quotes Mitsui project manager, Natalya Derevtsova. The estimated cost of the 320MW power plant is RUB22bn (US$704mn). The plant will be located in the Amur region, close to Russia's border with China. RusHydro is also looking to develop another hydro-power project in the region: the 400MW Nizhne-Zeyskaya plant, for which it is seeking investors, according to the Moscow Times.

Rushydro in October 2009 announced that it was to seek a loan of RUB7bn (US$235mn) in 2010 to partly finance repairs to its Sayano-Shushenskaya hydro-power plant in Siberia, reported Reuters. The plant was damaged during an accident in August 2009. Vasily Zubakin, the acting CEO of the utility, has stated that the company is in talks to secure the loan. The company expects repairing the Sayano- Shushenskaya dam to cost at least RUB40bn (US$1.34bn).

French power generator Alstom Hydro has signed a memorandum of understanding (MoU) with Russian power generation company RusHydro for cooperation in the development of Russian hydropower plants, reports People Daily. The French company will participate in reconstruction and modernising work, as well as hydropower research and development with RusHydro.

Russian state-owned bank Vnesheconombank (VEB) has agreed to invest RUB28.1bn (US$930.81mn) in the development of the Boguchany hydro-power power plant, said Prime Minister Vladimir Putin. The power plant will have an installed capacity of 3GW. The first unit of the plant was scheduled to be commissioned in 2010 and the plant will become fully operational by 2013.

Apart from the substantial hydro-power sector, Russia has paid little attention to developing a renewables-based generating capability. Our forecasts suggest that non-hydro renewables will account for just 2.3% of electricity generation by 2015.

According to the Barents Observer, Russia's biggest hydro-power generator Rushydro is considering investing RUB4bn (US$0.17bn) in a tidal power plant in Murmansk Oblast on the Barents Sea coast. The

Russia Oil & Gas Report Q2 2011

construction of the Northern Tidal Power Plant in the Dolgaya-Vostochnaya Bay, west of Murmansk city, is expected to take three years.

Russian state nanotechnology firm Rusnano and energy conglomerate Renova have outlined plans for the construction of Russia's first solar power plant. The plant, to be built in the spa town of Kislovodsk on the Black Sea by Khevel, a joint venture between the two companies, will have a 12.3MW capacity. Khevel's CEO, Evgeny Zagordny, and Stavropol region's governor, Valery Gayevsky, signed the US$97mn deal for the project. According to Zagordny, the plant is expected to come online by 2012.

Russia Other Energy – Historical Data And Forecasts

2008 2009 2010e 2011f 2012f 2013f 2014f 2015f

Coal Reserves, mn tonnes 157,010 157,010 155,440 153,886 152,347 150,823 149,315 147,822

Coal Production, mn tonnes 328.6 298.1 313.0 328.7 345.1 362.3 380.5 399.5

Coal Consumption, mn toe 100.4 82.9 85.7 87.1 91.4 96.6 96.6 96.6

Thermal Power Generation, TWh 702.2 654.4 666.5 675.0 689.0 705.0 710.0 710.0

Hydro-electric Power Generation, TWh 166.4 175.8 180.0 185.0 190.0 199.5 210.0 230.0

Electricity Generation, TWh 1,040 993 1,018 1,048 1,090 1,134 1,168 1,197

Hydro-electric Energy Consumption, TWh 166.4 175.8 180.0 185.0 190.0 199.5 210.0 230.0

Nuclear Energy Consumption, TWh 163.1 163.6 165.0 180.0 200.0 215.0 230.0 230.0

Primary Energy Consumption, mn toe 680.9 635.3 651.2 670.7 690.8 711.6 729.0 745.0

e/f = estimate/forecast. Source: Historical data, BP Statistical Review of World Energy, June 2010, Forecast, BMI.

Russia Oil & Gas Report Q2 2011

Key Risks To BMI’s Forecast Scenario

Using a flat OPEC basket oil price assumption of US$50/bbl to 2015, Russian oil and gas export revenues would be around US$181bn at the end of the period, compared with US$326bn in the BMI base case scenario and US$362bn assuming a US$100/bbl OPEC basket price. The other major risks associated with Russian energy forecasts are the country’s ability to deliver higher oil and gas volumes.

Long-Term Oil And Gas Outlook

Details of BMI’s 10-year forecasts can be found in the appendix to this report. Between 2010 and 2020, we are forecasting an increase in Russian oil production of .5%, with output rising slowly from an estimated 10.28mn b/d in 2010 to a peak of 11.00mn b/d in 2016/17, before easing to 10.84mn b/d by 2020. Oil consumption during the period is forecast to rise by 28.3%, permitting exports peaking at 7.59mn b/d in 2016. Gas consumption is expected to be up from an estimated 396bcm to 471bcm by 2020, providing export potential peaking at 224bcm in 2015.

Russia Oil & Gas Report Q2 2011

Oil And Gas Infrastructure

Oil Refineries

With a total processing capacity of 5.66mn b/d in 2010, Russia is the world’s third largest refiner after the US and China. Although the vast majority of this capacity dates from Soviet times, the country’s largest players, such as Rosneft, have invested in upgrading their facilities to meet stringent fuels quality standards, allowing many companies to export refined products, particularly diesel, to the EU. Russia has also followed the EU’s lead in mandating cleaner fuels, introducing Euro-4 standards at the start of 2010 and preparing for the introduction of Euro-5 standards at the start of 2014.

Central Federal District Located close to major population centres including Moscow, Russia’s Central region is also able to service export markets farther west. As a result, it plays host to some of the country’s largest and most complex refineries, which are able to produce high standard fuels that meet both Russian and EU specifications. The region is home to four refineries with a total capacity of around 900,000b/d.

Ryazan (Active): TNK-BP’s 340,000b/d Ryazan refinery is the company’s largest and most up-to-date refinery, with a nameplate capacity of 340,000b/d. As part of its wider downstream expansion plans, the company is investing US$150mn in building an isomerisation unit at the plant. Following the introduction of tighter regulation of road bitumen in 2010, TNK-BP looks likely to increase investment at the plant, which can produce the company’s polymer-modified TNK Alfabit brand of premium bitumen.

Yanos (Active): The 305,368b/d Yanos refinery in Yaroslavl is one of two in Russia owned by TNK- BP/Gazprom JV Slavneft. The refinery, completed in 1961, has been extensively upgraded in recent years allowing it to produce Euro-4 and Euro-5 diesel among a slate of more than 100 products, including fuels, specialist products such as paraffin waxes and intermediate petrochemical feedstocks.

North West Federal District The large North West Federal District contains only one large refinery: Surgutneftegaz’s 335,900b/d Kinef plant in Kirishi in Leningrad Oblast. A smaller, low-complexity refinery of 70,000b/d belonging to Lukoil also exists in the Komi Republic, giving the region a total active capacity of around 420,000b/d.

Southern Federal District The Southern Federal District is well supplied with refineries thanks to the availability of local crude production, a domestic market that is large by Russian standards and good transport links to major consuming regions. In 2010 the region had a refining capacity of around 410,000b/d.

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Volga Federal District The Volga Federal District is Russia’s refining heartland with numerous large, complex plants backed by the country’s major downstream players. The region has a total capacity of around 2.39mn b/d, equivalent to over 40% of Russia’s total 2009 capacity, and is supplied with crude from local fields, with many of its refineries producing fuels compatible with EU standards. Those companies unable to produce higher quality fuels are pushing forward upgrades to meet increasingly strict Russian fuels standards. The fact that several of these projects aim to meet EU requirements rather than the lower Russian standards suggests that a divide is emerging between producers for the domestic market and those that can export to the EU.

Rosneft currently has three refineries in the Samara region, which it acquired in 2007 from Yukos. The largest, in Syzran in the west of the region, has capacity of 214,076b/d, while the other two are located in the city of Samara: Novokubishevsk (160,720b/d) and Samara-Kubishev (130,585b/d). The refineries process crude from Rosneft units in the broader Volga Federal District including Udmurtneft and Samaraneftegaz, as well as crudes from north-west Kazakhstan supplied via the Atyrau-Samara pipeline. Rosneft has allocated US$3bn to upgrade its refineries in the Samara region, according to the region's Governor Vladimir Artyakov on October 29 2010.

Rosneft's plans are in line with a broader trend by large integrated oil companies in the Volga Federal District. In October 2009 TNK-BP announced that it was investing US$1.3bn to upgrade its refineries, including its 130,000b/d Saratov plant. In September 2010 the Governor of Bashkortostan announced that Sistema's local unit Bashneft would spend US$3.24bn upgrading its three refineries in the region. In October 2010 Tatneft started up the first new refinery since Soviet times, at Nizhnekamsk, with the potential to produce EU-standard fuels.

Nizhnekamsk (Active): The first phase of Tatneft’s new refinery was launched on October 26 2010 as part of President Medvedev's visit to the Tatarstan Republic, according to a Reuters report. The refinery, which cost almost US$6bn, will process 140,000b/d during its first phase. The second phase of the three- phase refinery, which will include two Russian-built hydrocrackers, is still under construction and is due to be completed in late-2010 or 2011. When complete, the plant will be able to process local heavy sour crudes. Tatneft said that the plant will operate at a conversion rate of 97%, compared with a Russian average of 72%.

Urals Federal District Refining is not a major industry in the Urals, with a total capacity of only 100,000b/d, dominated by TNK-BP’s 84,000b/d Nizhnevartovsk refinery on the Siberian side of the mountain range. Mini refineries make up the remainder of the capacity.

Russia Oil & Gas Report Q2 2011

North Caucasus Federal District Although the North Caucasus has historically been an important oil producing and processing region, the main 240,000b/d Grozny refinery was destroyed in December 1994 following Russian bombing during the First Chechen War. Since that time, refining capacity is limited to a 4,000b/d mini refinery that was bought from US refiner Silver Eagle and shipped to Dagestan in 1996. Additional, if unofficial, capacity is reportedly available through a number of micro-refineries that illegally process crude siphoned from the region’s numerous oil pipelines, according to a September 2009 Bloomberg report. This limited processing capacity could be set to change, however, thanks to Rosneft’s decision in November 2010 to sanction a new refinery in the North Caucasian republic of Chechnya. The plant, to be located in the regional capital Grozny, will have a capacity of up to 1mn tpa, equivalent to around 20,000b/d.

Siberia Federal District Siberia’s status as an oil producing hub is reflected in its refining capacity, which totals around 820,000b/d. The region has three large refineries, in Angarsk, Omsk and Achinsk, with two mini refineries located in Tomsk. The three largest plants are all located next to pipelines running along the Trans-Siberian railway, which provides access to a wider market for refined products. The two small Tomsk refineries are linked to the same markets by the railway’s northern spur.

Omsk (Active): Gazprom Neft’s 370,000b/d Omsk refinery, completed in 1955, was the first to be built in Siberia and is by far the region’s largest plant. As with many other larger plants in Russia, is currently making the transition towards improved diesel standards, with Euro-4 fuels expected to become standard by 2012 and Euro-5 due in 2015. The refinery has undergone a major series of upgrades to achieve these targets, including installing Russia’s largest isomerisation plant.

Far East Federal District Despite its low population, Russia’s Far Eastern region is well served with refineries thanks to large-scale crude production and its proximity to East Asian export markets. The region’s total capacity of around 220,000b/d is spread across two medium sized refineries and at least two mini-refineries. In addition, a 200,000b/d greenfield refinery is currently planned by Rosneft to process ESPO crude and serve the East Asia export market.

Khabarovsk (Active): The 70,000b/d Khabarovsk refinery, the oldest in Russia’s Far East, is owned and operated by Alliance Oil. Built in 1935 to supply maritime fuel to Russia’s Pacific fleet, the facility has a low complexity and refining depth, even by Russian standards, and these problems are exacerbated by a lack of access to Transneft’s pipeline network, which forces the plant to receive crude by rail. Products are also sent by rail, as well as by barge along the Amur River, allowing the plant to supply the Far East region’s domestic market. Alliance Oil is currently in the process of improving the plant’s complexity to a Nelson index of 9.9, with completion due in 2012.

Russia Oil & Gas Report Q2 2011

Komsomolsk (Active): Currently, Rosneft's only refinery in Russia's Far East is the Komsomolsk facility, which is supplied with crude by rail from Western Siberia, over 2,000km away, as well as by pipeline from Sakhalin from the company’s Sakhalinmorneftegaz subsidiary. The motor and jet fuels produced by the refinery are exported to Japan, South Korea and Vietnam via the Nakhodka and Vanino tanker terminals.

Nakhodka (Planned): In November 2010 Rosneft approved the construction of a 200,000 b/d refinery and petrochemical complex in the Far Eastern port city of Nakhodka at a board meeting. The refinery, to be managed by a new subsidiary known as the Eastern Petrochemical Company (EPC), will be designed to process ESPO crude and will be integrated with a petrochemicals plant, to which it will supply feedstock.

Russia Oil & Gas Report Q2 2011

Table: Refineries In Russia

Refinery Capacity (b/d) Owner Completed Details

Omsk 369,656 Gazprom Neft 1955

Kirishi (Kinef) 347,557 Surgutneftegaz 1966

Kstovo 341,530 Lukoil 1958

Ryazan 340,000 TNK BP 1960

Yaroslavl (Yanos) 305,368 Slavneft

Novo Ufa 285,000 Bashneftekhim 1951

Perm 261,170 Lukoil 1958

Moscow 240,000 Sibir Energy 1938 Operating at 200,000b/d

Ufa 234,962 Bashneftekhim 1937

Angarsk 220,990 Rosneft 1955 Uses West Siberian Crude

Volgograd 220,990 Lukoil 1957

Syzran 214,076 Rosneft 1942

Ufaneftekhim 184,200 Bashneftekhim

Salavat 168,300 Gazprom 1954

Novokubishevsk 160,720 Rosneft 1951

Komsomolsk 146,657 Rosneft 1942

Achinsk 140,630 Rosneft 1982

Nizhnekamsk 140,000 TAIF Group 2002

Orsk 132,594 TNK BP 1935

Samara-Kubishev 130,585 Rosneft 1945 Uses Rosneft crudes

Saratov 130,000 TNK BP 1934

Tuapse 104,468 Rosneft 1929 Specialises in motor fuels

Nizhnevartovsk 84,000 TNK BP 1998

Ukhta 74,333 Lukoil

Khabarovsk 70,000 Alyans Group

Krasno 60,270 RussNeft 1911

Others 87,276 14 sub-50,000b/d refineries

Total Capacity 5,195,332

Planned Additional Capacity

Primorsk 240,000 Rosneft 2014 With Surgutneftegaz

Grozny 20,000 Rosneft

Source: BMI

Russia Oil & Gas Report Q2 2011

Oil Terminals/Ports

The country's biggest Baltic Sea port is located in Primorsk, with additional ports in St. Petersburg and Vysotsk. Additional export capacity is located at the Black Sea port of Novorossiysk, Russia’s second largest oil export facility. The Pacific port of Kozmino was completed in December 2009, to become Russia's third largest oil export facility.

Primorsk Primorsk, near St Petersburg, was completed in 2001 and exports around 1.5mn b/d, according to the EIA, although it claims export capacity of around 3mn b/d. The terminal exports refined products as well as crude, with Transnefteproduct beginning shipments in 2008.

Novorossiysk The port of Novorossiysk is Russia’s main Black Sea port for oil, exporting Russian crude and oil delivered by pipeline from Kazakhstan and Azerbaijan. According to the EIA, around 1mn b/d of Russian crude is exported via the Black Sea (mainly through Novorossiysk), then sent through the Bosphorus to the Mediterranean. In June 2010, Transneft claimed that two plans had been developed to reduce or cease oil exports via the Bosphorus in order to provide customers for the Samsun-Ceyhan oil pipeline.

Kozmino Russia's newest crude oil export terminal, the port of Kozmino, began operations in December 2009. The port sent its first cargo to Hong Kong, underlining its focus on catering for Asian demand. Kozmino exports East Siberian crude that is transported from the Meget railway terminal in the Irkutsk region to the Skovorodino oil terminal, which started operations in October 2009. The Kozmino terminal, which is operated by national oil midstream monopoly Transneft, is intended to be the terminus of the Eastern Siberia-Pacific Ocean (ESPO) pipeline, which is due to be completed in 2014-2015. The Skovorodino oil terminal is the endpoint of Phase 1 of the ESPO pipeline, but Kozmino will receive oil delivered by rail from Skovorodino until the second phase has been completed. Each railway oil cargo will hold 4,600- 4,800 tonnes (33,700-35,200bbl), according to ESPO's website.

The port of Kozmino is a vital part of Russia's Asia Pacific economic strategy. Located in the Sea of Japan, it offers links to the main regional consumers: Japan, South Korea and China. The port will provide an outlet to oil producers in East Siberia, including Rosneft, Surgutneftegaz and TNK-BP. Once the ESPO pipeline is extended to Kozmino, the port will play a major role in Russia's energy export sector.

Russia Oil & Gas Report Q2 2011

Oil Pipelines

East Siberia Pacific Ocean (ESPO) On November 1, Transneft began test shipments to the Chinese city of Daqing via a spur of the East Siberia Pacific Ocean (ESPO) pipeline. From January 2011, the Skovorodino-Daqing spur will transport 300,000b/d of ESPO crude under an oil-for-loans deal signed by Moscow and Beijing in mid-2009.

The 4,700km ESPO pipeline overtakes the Europe-bound Druzhba (Friendship) as the world’s longest oil pipeline. It is the first Russian pipeline transporting oil to Asia. The pipeline experienced serious delays due to construction difficulties, environmental concerns and price disputes, but received a much-needed boost from a US$10bn Chinese loan in February 2009.

It is understood that the majority of the overland deliveries to China will come from Rosneft, with the company committing itself to supplying 70% of the feedstock for the planned 260,000b/d refinery in the northern Chinese city of Tianjin. The project will give Rosneft its first foothold in international refining, underlining growing energy links between Russia and China.

ESPO is being built in two stages. The first 2,757km stage will link Taishet in the Irkutsk region to Skovorodino in the Amur region and has capacity of 600,000b/d. From Skovorodino, ESPO will branch out to China, via a 70km connector, which will supply northern China with 300,000b/d from 2011. The first section of the pipeline had to be moved to 400km away from the ecologically sensitive Lake Baikal, missing the end-2008 deadline by a year and coming online in late-2009.

The second leg of ESPO will cover 2,100km from Skovorodino to Kozmino on the Pacific and will increase the capacity of the entire pipeline to 1.6mn b/d. The second phase is not expected to be completed until 2014/2015. ESPO will be supplied primarily by Russian oil companies Rosneft, TNK- BP and Surgutneftegaz from untapped fields in East Siberia. It is hoped that this will allow Russia to replace dwindling output from West Siberia. Until ESPO Phase 2 comes online, oil from Skovorodino is transported by rail to the Pacific port of Kozmino for export.

On August 29 2010, Vladimir Putin officially inaugurated the Russian section of the ESPO pipeline spur from Skovorodino to the Chinese city of Daqing. The 70km pipeline will run to the Chinese border, where it will connect with the 927km Chinese section of the spur, whose construction was completed in June 2010. The pipeline is expected onstream by October 31 2010, and will supply CNPC with 300,000b/d in 2011-2030.

Purpe-Samotlor Transneft began constructing a new major link from the Yamal Autonomous District in March 2009. The

Russia Oil & Gas Report Q2 2011

430km Purpe-Samotlor pipeline will provide a better export route from crude volumes from the giant Vankor oil field and will speed up the development of other deposits in the Yamal and north-western Krasnoyarsk regions. The pipeline will run from the village of Purpe to the Samotlor oil field in the Khanty-Mansiysk region further south. The link will cost US$1.34bn and is due to be commissioned in 2012. Initial capacity will be 500,000b/d, which could be expanded at a later date.

The Purpe-Samotlor pipeline will replace the longer and smaller-diameter lines for transporting Vankor crude. The new link will cut about 100km from Vankor's route to ESPO trunkline. As well as providing transit capacity for further expansion at Vankor, it will benefit TNK-BP's Suzun, Tagul and Russkoe field developments on the Yamal peninsula.

Baltic Pipeline System The Baltic Pipeline System (BPS) has two phases: BPS-1 and BPS-2. The pipelines transport oil from West Siberia and the far north of the country to the Baltic Sea terminal of Primorsk. The pipeline system began operations in 2001 and reached its full design capacity in 2006. Construction of a second phase of the network, known as BPS-2, started in June 2009. The pipeline was designed to expand the existing system and bypass Belarus, which was involved in oil transit disputes with Russia in 2006 and 2010. The 1,016km-long BPS-2 pipeline will transport some 1mn b/d of oil from Unecha, close to the border with Belarus, to Ust-Luga and from there the crude will be transported on by tanker. The construction of the pipeline is expected to be completed in 2012 at a cost of around US$3.9bn.

The construction of the new pipeline demonstrates Russia's strategy of diversifying its oil and gas export infrastructure, bypassing its traditional transit countries – Belarus, Poland and Ukraine. The pipeline's construction was not welcomed by these transit countries, whose positions will be weakened as the new pipeline allows Russia to supply more oil directly to Western Europe. Once the BPS-2 pipeline becomes operational, Russia is likely to reduce supplies through the Druzhba oil pipeline.

Druzhba The Druzhba pipeline, one of Russia’s main oil export routes, was completed in 1964 and currently has a capacity of around 1.4mn b/d. The Russian section of the pipeline begins in the Republic of Tatarstan, which serves as a gathering point for oil from other regions and from Kazakhstan. The pipeline runs west to Unecha in Bryansk Province where it splits into two.

A spur known as the Northern Druzhba continues north through Belarus and Lithuania where it formerly supplied the Novopolotsk and Orlen Lietuva (Mažeikių) refineries and the Ventspils and Butinge oil terminals. The Northern Druzhba pipeline was closed in 2006 when Russia claimed it had been damaged. It has not yet been repaired. The main Druzhba pipeline continues to Mozyr in Belarus, where it splits into the Western Druzhba, with a capacity of up to 1mn b/d, and the 1.2mn b/d Southern Druzhba.

Russia Oil & Gas Report Q2 2011

Western Druzhba crosses Poland and then runs into Germany, while Southern Druzhba leads into Ukraine and from there into central and south-eastern Europe. The presence of a large number of transit countries has led to risks of disruption to supply, particularly in Belarus, which has been in dispute with Russia over energy imports several times.

LNG Terminals

Sakhalin-II Russia’s first LNG export terminal, Sakhalin-II, came onstream in March 2009. The second major area for LNG is the Barents Sea and the Yamal-Nenets Autonomous Region. The most advanced project is the offshore Shtokman field, which is being developed by Gazprom in partnership with French major Total and Norway’s Statoil. The project, which will supply pipeline gas to Europe and LNG to Europe and North America, has estimated costs of US$30bn. Some 70-80% of the LNG will be sold under long-term contracts, with Spain a likely buyer. A consortium led by Norway’s Aker Solutions won the EUR25mn FEED contract for the floating production unit (FPU) at Shtokman in February 2009. Italy’s Technip is undertaking the FEED for the onshore gas facilities including the LNG plant.

Shtokman LNG (Planned) With an estimated 3.2tcm of gas reserves, Shtokman is believed to be the biggest undeveloped offshore gas field in the world. The field is being developed by SDC, in which Norway's Statoil holds a 24% stake, France's Total has 25% and Gazprom the remaining 51%. Gas produced in the third development phase of the Shtokman gas field will be exported solely as LNG, while about half the gas produced at the field during phases one and two will be exported via pipelines and half as LNG. First gas is expected to be exported via pipeline to Europe in 2013, with LNG exports to follow in 2014. Increasing the proportion of gas that is exported in the form of LNG will provide more export options.

Total announced in May 2011 that its plans for the development of the Shtokman natural gas field in the Barents Sea in Russia are on course, and an FID is due in 2011. The investment decision will be made in March 2011 and a decision on the gas liquefaction plans will be made by the end of the same year.

Yamal LNG (Planned) Yamal LNG, a JV between Gazprom, Novatek, and Total, is the operator of the LNG project aiming to commercialise the Tambeyskoe group of fields. Through its controlling stake in the Yamal LNG operating vehicle, Novatek is the operator of the South (Yuzhno)-Tambeyskoe gas field onshore the Yamal-Nenets region, which is expected to begin exporting gas by around 2018. Although no firm project timetable has been set, Gazprom has previously said that it aims to start producing the first 15bcm of gas in Yamal by 2011 and then to gradually boost volumes to an ambitious 250bcm per year.

Russia Oil & Gas Report Q2 2011

In March 2011 Total signed a US$4bn cooperation deal with Novatek. Under the deal, Total will become the main international partner at Novatek's 15mn tpa Yamal LNG project and will initially buy a 12.1% stake in the company, which it plans to increase to 19.4% within three years. The deal fulfils a longstanding ambition for Total, which tried to acquire a 25% stake in Novatek in 2005, and will significantly increase the company's Russian reserves and production. For Novatek, the agreement provides it with a strategic partner with technological capability and access to funding.

Pechora LNG (Planned) Russian investment company Alltech Group is considering building an LNG export plant in the Nenets district. The plant, dubbed Pechora LNG, would have an initial capacity of 2.6mn tpa and is expected onstream in Q415, Alltech’s oil arm, CH-Oil & Gaz, stated in December 2009. The plant would commercialise gas reserves at the Kumzhinskoe and Korovinskoe fields in the Timan-Pechora Basin, the licence for which Alltech acquired in 2007.

Vladivostock LNG (Planned) Japan and Russia are considering building a 6.9bcm LNG export terminal in the Russian port of Vladivostok, according to a report by Japan's Yomiuri Shimbun newspaper on December 12 2010. The project will involve the construction of a 5mn tpa LNG liquefaction terminal, according to the report, with the possibility of adding a chemical plant at the same site. Under current plans, the facility will source gas from the Chayanda gas field in Eastern Siberia via a gas pipeline to Khabarovsk, and then onwards by another pipeline to Vladivostok. The facility is scheduled for completion in 2017.

A preliminary agreement to conduct a feasibility study on the terminal was signed in July 2010. According to a report at the time by Japanese news source Nikkei, an official agreement on construction of the plant was expected to be signed in November during Russian President Medvedev's visit to Japan. Although a trade ministry official cited by Reuters on December 13 said that the two countries had been holding regular meetings since the agreement, the construction agreement has not yet been signed. The Yomiuri Shimbun claimed, however, that a deal will be signed by end-2010 [update?] between Gazprom, Japanese trading house Itochu and Japan's Economy, Trade and Industry Ministry.

For Russia the Vladivostok terminal would increase its export options for gas from Eastern Siberia and the country's Far East Economic Regions. By increasing its export routes to Asia, Russia hopes to reduce its dependence on the stagnant gas markets of Europe. With discussions continuing with China over a pipeline gas price formula, Russia is evidently determined to reorient its gas customer base eastwards.

Gas Pipelines

Blue Stream Russia’s first post-Soviet westbound pipeline system is Blue Stream, which carries gas directly to Turkey

Russia Oil & Gas Report Q2 2011

under the Black Sea. Blue Stream is a JV between Gazprom and Italy’s Eni. The US$3.4bn system consists of two pipelines that run for 1,213km from southern Russia to Ankara in Turkey. The 385km subsea sections of the pipelines run from the Beregovaya compressor station in Russia to a gas terminal outside the Turkish port of Samsun. The pipelines were completed in 2004 and were officially inaugurated in 2005, since when they have been gradually ramped up to their maximum capacity of 16bcm per annum. It is the world's deepest underwater pipeline system and reaches a maximum depth of 2,150m below the surface of the Black Sea.

There has since been much talk of expanding the pipeline both geographically and in terms of capacity, including branches to Italy and the Middle East. In February 2006, Turkish energy ministry officials claimed that talks were under way between Gazprom and Turkish state-run gas distributor Botaş about extending the pipeline through Turkey to Syria, Lebanon, Israel and Cyprus in a project known as Blue Stream II. Speaking during an official visit to Turkey in June 2010, however, Putin said Israel is now likely to be excluded from the Blue Stream II project. Putin said that gas discoveries in recent years in Israel have reduced the country's future gas import projections, making an extension of the pipeline to Israel unnecessary.

South Stream Emboldened by Blue Stream’s success, in November 2007 Gazprom and Eni agreed to construct a new trans-European gas pipeline that will cost the companies EUR10bn by the time it comes onstream in 2013/14. The 900km South Stream pipeline is routed via the Black Sea to south-eastern Europe. In Bulgaria, the pipeline will split into a northern route going to Austria via Romania and Hungary, and a southern route crossing the Balkan Peninsula to Italy. The northern route passes through the same countries as the 30bcm Nabucco pipeline from Turkey to Austria, which the EU is promoting in order to reduce dependence on Russia.

Government officials of Bulgaria, Greece, Italy and Russia met in May 2009 to sign transit agreements for South Stream, creating separate JVs between Gazprom and the countries’ gas distribution companies. These JVs will be responsible for the design, construction and operation of the pipeline within their respective territories. Slovenia joined the project later that year, while Turkey agreed to let the pipeline pass under its territorial waters in return for a transit fee in August 2009. A deal between Gazprom and Eni has been signed under which the two companies have agreed to double the pipeline's capacity to 63bcm. Following the signing of agreements with the Austrian government and oil company OMV on April 24 2010, there are no expectations of further delays to the project, with Putin having said that South Stream was on course for start-up in H215.

The South Stream was originally a 50:50 JV between Gazprom and Eni, but France’s EdF signed an MoU in November 2009 to take at least a 10% stake. Under the agreement, EdF can buy as much as 6bcm per year. However, in April 2010, it was announced that EdF may be awarded a 20% stake in the pipeline

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project. The 20% stake would be taken equally from the two existing South Stream project partners, Gazprom and Eni. The decision was announced following discussions between Vladimir Putin and his Italian counterpart Silvio Berlusconi on April 26, according to a report by the Moscow Times. Putin, who declared the granting of a 20% stake to EdF, said that a partnership deal would be signed between EdF, Gazprom and Eni during the St. Petersburg International Economic Forum in June 2010. However, the deal was not finalised. In early-2011 it was reported that EdF would take at least a 10% stake in the pipeline, with the finalisation of the deal expected by end-2011. In March 2011, the Wallstreet Journal quoted Eni’s CEO Paola Scaroni as saying that Germany’s Wintershall would also join the project.

Nord Stream Russia’s second major export pipeline project is Nord Stream. The 1,200km pipeline is designed to carry an eventual 55bcm annually under the Baltic Sea from Vyborg to Greifswald in Germany. The project is 51% owned by Gazprom along with German partners E.ON Ruhrgas and Wintershall, each with 20%, and later Dutch entrant Gasunie with 9%. In December 2008, French energy group GDF Suez signalled its intention to participate in Nord Stream as a minority partner. After more than a year of negotiations, GDF Suez is expected to receive 4.5% each from Nord Stream's two German partners, under a letter of intent (LoI) signed in March 2010.

Construction of the onshore segment began in 2005 and was completed by early-2010, while construction of the underwater segment stalled owing to ongoing environmental concerns, rising costs, technical obstacles and political objections from neighbouring states. The project, however, made major breakthroughs in late-2009, securing final approvals from transit states Sweden, Finland and Denmark. The undersea construction is now set to begin on April 1 2010. At its start-up in 2011, the pipeline will have a capacity of 27.5bcm. The second 27.5bcm phase is planned to come onstream in 2012.

Russia-South Korea Gas Interconnector South Korea and Russia are expected to begin a new round of talks on a gas interconnector between the countries, the head of foreign projects at Russia's state-run Gazprom, Stanislav Tsygankov, told industry data provider Platts in April 2010. Two potential gas pipeline options between Russia and South Korea are on the table: an overland pipeline via North Korea and a direct undersea pipeline. The first option suffers from severe geopolitical risks while the second option presents formidable technological and financial challenges. In November 2008, state-run Korea Gas (Kogas) announced its intention to team up with Gazprom to build an undersea gas pipeline from Russia if plans for an overland transit through North Korea fail. With the erratic Pyongyang government under Kim Jong-il announcing periodically that it will end all political and military agreements with Seoul, the latter option seems unfeasible, despite the north's opportunity to earn up to US$100mn a year in transit fees.

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Macroeconomic Outlook

Motoring On Into 2011

BMI View: We hold to our forecast for the Russian economy to grow by 4.3% in 2011, slightly above consensus, driven by elevated oil prices, strong investment, government spending and an increase in consumption by the second half of the year. Over the long run, we continue to expect investment and consumption to become increasingly important drivers of growth.

The Russian State Statistics Service (Rosstat) released a report on January 31 showing that GDP grew by 4% in 2010, broadly in line with our expectations. While a full breakdown of the numbers is as yet unavailable, private consumption and investment were the main drivers, growing by 2.7% and 3.5% respectively. Government spending rose by 0.7%, its slowest rate of growth since 2001, while net exports fell as import growth outpaced that of exports. Going into 2011, our core views for Russia growth remain firmly in play, and we continue to expect the economy to expand by 4.3% (vs. consensus 4.2%).

Private Consumption: Inflation A Concern Though we remain bullish on the long-term prospects for the Russian consumer, we reiterate our view that the outlook for H111 at least is relatively unfavourable. Leading indicator data show that inflation is continuing to weigh on spending, with real growth for wages and retail sales hitting 11- and nine-month lows respectively in December, as inflation spiked to 8.8% y-o-y in the same month. While we forecast monetary tightening to begin in Q111, we do not expect inflationary pressures to abate until H211, and as such believe that household consumption will be weak in the first half of the year. This view is reinforced by latest consumer confidence data, with a report issued by the Credit Suisse Research Institute in January showing that Russian consumers were the second most pessimistic of the countries covered after Egypt (the others were Brazil, India, China, Indonesia and Saudi Arabia).

That said, we believe that the conditions for a more pronounced improvement in private spending exist, and that this should start to kick in from the second half of the year as inflationary pressures moderate and households become more sure about the sustainability of the economic recovery. Despite a recent spike, unemployment remained near a multi-year low at 7.2% in December, down from 9.2% as recently as January 2010. Moreover, we reiterate our positive view on the Russian banking sector, which remains well placed to extend credit to households and businesses. Upcoming World Trade Organisation accession and planned privatisations should bode well for the likes of VTB and Sberbank. As a result, we forecast real household spending growth of 4.3% over the course of the year.

Investment: Strong Year Ahead With gross fixed capital formation (GFCF) having already had a good 2010, we forecast this component

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of GDP to again perform well in 2011, growing by 7.5%. Leading indicator data show that the outlook for GFCF remains strong. Investment in productive capacity grew by 10.1% y-o-y in December, while industrial production continues to grow at a healthy rate, expanding by 6.3% y-o-y in the same month.

Net Exports: Imports Over Exports We expect the rate of import growth to be higher than that of exports in 2011, albeit to a lesser extent as was the case in 2010. We forecast import growth of 7.3%, compared with 7.2% for exports. Much of the growth in exports will be at the start of the year, given elevated oil prices on the back of unrest in the MENA region. Indeed, we forecast an average price for Brent crude of US$94/bbl over the course of 2011, well down from current levels. However, further growth will be provided by the non-oil export sector, which we expect to benefit strongly from World Trade Organisation accession. While the scale of import outperformance will be less, as favourable base effects wear off, strong investment and rising consumption from H211 should ensure that imports remain strong.

Government Spending: Eyes On Elections We expect government spending to post robust growth of 2.6% in 2011, for two key reasons. First, the Kremlin has one eye on presidential elections in March 2011, which will ensure ongoing loose fiscal policy in a bid to shore up votes. A poll by the Levada Centre released on February 2 showed support for Prime Minister Vladimir Putin's United Russia party at 35%, compared with 45% in December 2010. Second, the government is likely to continue investing fairly strongly in infrastructure, both on repairing the damage of the summer 2010 wildfires, and longer-term projects such as the 2014 Sochi Winter Olympics and the 2018 World Cup.

Medium-Term Investment Implications Over the medium term, we forecast real GDP growth to settle at an average of 4.4%, well down from the average 7% seen in the five years leading up to the global financial crisis. Despite this, we stress that the fact that consumption and investment will drive this growth will present opportunities for investors, and reiterate our bullish outlook for Russian equities over a multi-year time horizon. The lack of domestic penetration creates opportunities in banking, while we also like consumption and retail stocks over a multi-year time horizon, despite the fact that many valuations in this sector look overstretched at present. Moreover, while the business environment will remain an impediment to greater investment, WTO accession and upcoming sporting events should provide opportunities in construction.

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Russia – Economic Activity

2008 2009 2010e 2011f 2012f 2013f 2014f 2015f Nominal GDP, RUBbn 1 39853.4 39098.9 44647.1 50409.5 56559.5 63015.8 69829.7 77385.6 Nominal GDP, US$bn 2 1603.3 1232.6 1470.0 1709.7 2077.5 2447.2 2765.5 3095.4 Real GDP growth, % change y-o-y 1 5.6 -7.9 4.0 4.3 4.5 4.7 4.3 4.3 GDP per capita, US$ 2 11295 8690 10370 12108 14772 17470 19821 22275 Population, mn 3 141.9 141.8 141.8 141.2 140.6 140.1 139.5 139.0 Industrial production index, % y-o-y, ave 1 0.8 -9.2 8.3 6.2 6.0 6.0 5.5 5.0 Unemployment, % of labour force, eop 1 7.7 8.2 6.0 5.5 5.0 4.5 4.0 4.0 e/f = estimate/forecast. Sources: 1 Federal State Statistics Service. 2 Federal State Statistics Service/BMI Calculation; 3 World Bank/BMI calculation/BMI.

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Competitive Landscape

Executive Summary

The Russian gas industry is dominated by Gazprom, which is effectively a downstream gas monopoly that also accounts for around 84% of upstream production. In 2009, Gazprom produced 462bcm, the lowest level in its history, although preliminary company estimates suggest production may have rebounded to 509bcm in 2010.

Gazprom’s oil arm, Gazprom Neft, is now a major producer and refiner, following the acquisition of Yukos’ assets in 2007-2009. It has also begun an expansion into Africa, taking stakes in Equatorial Guinea and Libya.

The oil sector is more diversified than gas. State-run Rosneft is the main producer, but privately owned Surgutneftegaz, Lukoil, TNK-BP and large regional producers such as Tatneft and Bashneft, are not too far behind. The degree of private companies’ connections with the Kremlin varies, but overall inter- company competition is more limited than it would initially appear.

Rosneft announced a 64% rise in profits in 2010 to US$10.67bn, on the back on increased oil production which rose 6.4% to 2.32mn b/d. With 1.13mn b/d of crude distillation capacity, Rosneft is also Russia’s largest refiner. In July 2010 the Finance Ministry included Rosneft in the list of nine companies earmarked for partial privatisation in 2011-2013. Up to 24.16% of Rosneft could be sold, leaving the state with the 51% controlling stake.

A US$16bn share swap and exploration deal between Rosneft and BP promises to be one of the largest oil and gas deals of 2011. Under the deal, BP will gain 10% of Rosneft, which will in turn receive 5% of BP. The two companies will then jointly explore three blocks in the South Kara Sea in the Russian Arctic. The deal has, however, been set back by the opposition of TNK-BP.

Following a period of relative rapprochement, relations between BP and its Russian JV TNK-BP have soured yet again, this time over BP’s proposed share-swap and Arctic exploration deal with Rosneft. AAR, which owns half of TNK-BP, claims that BP is to pursue its Russian activities solely through the Russian joint venture.

Many leading domestic independents, such as Russneft and Urals Energy, have been fashioned by high- profile businessmen in the wake of the state asset sell-off in the 1990s. Consolidation of these independents has already started, with an early victim being Sibir Energy, which was taken over by Gazprom Neft in mid-2009.

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Lukoil’s oil output in 2009 totalled around 1.97mn b/d, of which 1.86mn b/d or around 94% came from Russian operations. More than 50% of the country’s oil production comes from Western Siberia. The group has an estimated 18% share of refining capacity and 1,815 service stations in Russia.

Surgutneftegaz’s 2009 crude production was 59.6mn tonnes, roughly equivalent to around1.20mn b/d, while gas output totalled 13.6bcm. Downstream assets are led by the 350,000b/d Kirishi refinery in the Leningrad Region, which regularly processes at far above capacity, and around 300 service stations in north-western Russia.

French major Total has signed a US$4bn cooperation deal with private Russian gas company Novatek. Under the deal, Total will become the main international partner at Novatek's Yamal LNG project and will initially buy a 12% stake in the company, which it plans to increase to 19.4% within three years.

Shell is reportedly considering offering equity stakes in its Asia-Pacific region assets to Gazprom, according to a February 2011 Bloomberg report. as part of a deal to persuade Gazprom to add a third liquefaction train to the producing Sakhalin-II LNG project, in which Shell holds a 27.5% interest and Gazprom has a 50% operating stake.

Rosneft has joined forces with US majors ExxonMobil and Chevron in two separate deals to explore for oil and gas in the Russian section of the Black Sea. Rosneft and Gazprom are the only two companies which currently meet stringent laws on offshore drilling in Russia, although the Caspian Sea is open to a broader competition.

Table: Key Domestic And Foreign Companies In The Russian Oil And Gas Sector

% share Total 2009 Sales of total No. of Year Assets Company (US$bn) sales employees established (US$mn) Ownership (%)

91.1% state; 2.5% Gazprom 116.1* na 445,000 1992 na E.ON Ruhrgas

20.6% V. Alekperov; Lukoil 107.7* na 150,000 1991 59,632 12.06% Other mngt;

TNK-BP 34.7 na 90,300 2003 11,093 50:50 BP, ARR

Surgutneftegaz 18.0* na 86,108 1993 na Employee-owned

Gazprom Neft 24.2 na 55,000 1995 8,342 100% Gazprom

Rosneft 46.8 na 74,000 1993 59,837 75.2% state

Tatneft 7.5 na 104,000 1955 na 36% Tatarstan govt

Russneft 4.5* 30e na na na 75% Basel

e = estimate, na = not available/applicable. Source: Company data 2009, BMI; *2008 figures

Russia Oil & Gas Report Q2 2011

Overview/State Role

The oil sector is concentrated in the hands of several domestic companies, with limited direct IOC involvement. The biggest crude producers, exporters and refiners are state-run Rosneft and Gazprom Neft, plus privately owned Lukoil, Surgutneftegaz, TNK-BP and Tatneft. Following US major ConocoPhillips’ divestment of its 20% stake in Lukoil in 2010, BP is the only foreign player with a large interest in Russian oil producers through the TNK-BP JV. The oil pipeline system is managed by state- run Transneft. Foreign upstream oil ventures traditionally have been carried out through the Zarubezhneft state vehicle, although the main Russian producers are increasingly venturing abroad directly.

Gas activities are controlled by national giant Gazprom, which dominates production and holds a monopoly on exports and, in practice, distribution. Restructuring has been discussed for years with little progress, although domestic gas prices are being very gradually adjusted to international levels, a process that started in the mid-2000s. The main gas pipelines are managed by Gazprom, although the company does not enjoy an official monopoly on gas transportation. There were plans to merge Gazprom with Rosneft in the early 2000s, but the deal was abandoned in 2005.

Licensing And Regulation

There are several proposed changes to Russia's tax structure. First, from the beginning of 2011, Russia intends to increase the mineral extraction tax (MET) for both oil and gas production, with the increase in the gas MET having been set at 61%. The MET rate is currently RUB419/tonne, adjusted according to the price of Urals crude, the field depletion rate, and the US$/RUB exchange rate. The proposed MET increases will be inflation-adjusted. Second, Russia has proposed increasing the tax on refined products exports, by an amount equivalent to 60% of the crude export duty. A further measure being considered is an increase in the gasoline excise tax by RUB1 per litre over 2011-2013.

Export Duty On December 1 2009, the Kremlin scrapped export duty on 13 main East Siberian projects and all projects in the Black and Okhotsk seas. Rosneft said in November 2009 that it expects the tax holiday for East Siberian fields, which includes Vankor, Verknechonsk and Talakan, to last until 2013-2015, bringing significant savings to the industry. The government currently plans to end the duty in 2011. Meanwhile, the tax exemptions for Black Sea production have been granted for up to 15 years or until 20mn tonnes (146.7mn bbl) of oil have been produced, while tax exemptions for producers in the Sea of Okhotsk in the Far East would be granted for up to 15 years or until 30mn tonnes (220mn bbl) of oil have been produced. The oil export duty for fields elsewhere in Russia increased by 17% in December 2009 to US$271/tonne, equivalent to US$37.10/bbl.

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According to anonymous government and industry sources cited by Vedomosti in March 2010, the export duty holiday on the main East Siberian oil fields remained in place in 2010 but may be revoked in 2011. According to Vedomosti's sources, the re-introduction of export duties on East Siberian crude would cost the major producers in the region, namely Rosneft, Surgutneftegaz and TNK-BP, over US$2bn in total. While the policy shift would reduce the profitability of the fields, it is unlikely to have an impact on the progress of East Siberian upstream developments in the short term.

Despite these initial signs that tax incentives would be kept in place, in September 2009 Russian Finance Ministry ruled out extending or increasing tax breaks for Rosneft's Vankor oil field in East Siberia, following requests from company officials. On September 16, Russian daily Vedomosti reported that Rosneft chairman and Russian deputy Prime Minister Igor Sechin had asked Prime Minister Vladimir Putin to extend this reduced level of tax for Vankor until end-2013. The next day, Rosneft's new president, Eduard Khudainatov, asked the Russian government to reduce the crude oil export duty for the Vankor field to US$100/tonne, equivalent to US$14/bbl. He said that if the government was willing to do so, then Rosneft would be able to go ahead with investments in the field that he claimed would lead to an increase in annual tax revenues from the field of RUB250bn (US$8bn).

On the same day, however, Deputy Finance Minister Sergei Shatalov told Reuters that there was no reason for the government to change its position on the matter. He told the Moscow Times that the internal rate of return for the Vankor field was 17%, which he said was a sufficient premium. However Shatalov did not rule out the possibility of introducing a zero export duty for the smaller Yurubcheno- Tokhomskoye field. This appears to reflect the fact that although the commerciality of large producing fields such as Vankor does not depend on tax incentives, such inducements could be a major factor in companies' investment decisions for smaller fields.

Lukoil has, however, secured a long-sought-after tax break for its North Caspian projects in a move that should boost investment in the high-potential region. According to Russian news agency Interfax, on September 23 2010 the Kremlin approved a reduction of export duties on Caspian oil, without specifying the exact amount. Earlier in September 2010 Russian energy minister Sergei Shmatko said the discount will be the same as those seen in the East Siberian fields. According to a July 2010 report in Russian business newspaper RBK, the alignment of Caspian export duties with those in East Siberia would save Lukoil US$460mn in 2011.

Mineral Extraction Tax (MET) To stimulate projects in the Caspian Sea, Russia has exempted the first 730mn bbl of oil produced in the region from mineral extraction tax. However, Lukoil's president, Vagit Alekperov, has also been calling for an export tax holiday for offshore fields, the fiscal incentive currently enjoyed by operators in East Siberia. At the Yuriy Korchagin opening ceremony, Prime Minister Vladimir Putin said he would consider Alekperov's request and in July 2010 Lukoil said that it had reached a preliminary agreement

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with the finance ministry to halve export duties on North Caspian oil. Any lasting fiscal concessions, however, are unlikely. First, the Russian finance ministry is strongly opposed to any further loss of state revenue through concessions to oil companies. Second, the shallow waters in the North Caspian do not present the same logistical and technological challenges as the remote East Siberian deposits. Third, Lukoil, which would stand to be the main beneficiary of any further tax breaks, does not enjoy the same influence in the Kremlin as its state-connected rivals Rosneft and Surgutneftegaz, both of which are big East Siberian players.

On January 1 2009, the Russian government reduced MET to encourage the reinvestment of corporate profits into E&P. The amendment to the tax code, agreed in May 2008, increased the tax-free MET threshold from US$9/bbl to US$15/bbl. According to the country’s Finance Minister Alexei Kudrin, this would allow oil producers to save over US$4bn annually.

According to the Ministry of Natural Resources and Environment (MNRE), the MET and export duties account for about 95% of oil producers’ tax payments, with the tax burden exceeding 68% of their gross revenue. Such a revenue-based system is effective for rent collection and works well for mature projects with low finding, development and lifting costs but fails to encourage new developments. The ministry estimates that if Russia implements the new fiscal measures, the country could increase production to a sustainable 10.2mn b/d by 2013. If it does not reform its tax framework, however, its own projections show production falling to 9mn b/d by 2013. The structure of the tax regime was partly responsible for the fall in the country's oil production in 2008, the first annual decline in eight years, which occurred despite a 30% increase in upstream capex.

In the past, Gazprom has successfully managed to fend off attempts by the Finance Ministry to increase its tax burden by arguing that it already faces extremely high new-generation E&P costs. This time, Gazprom has suggested that rather than increasing tax on production and exports, an import tariff should be introduced. Taxing the gas that Gazprom purchases from Central Asia (and resells to Europe) would likely cost the company less as the volumes it buys from abroad are significantly lower than its domestic output. Putin has responded to Gazprom's proposal saying that as the introduction of import tariffs were 'not just an economic question', the government would look into the issue at a later stage.

Production Sharing Contracts ExxonMobil, Total, Statoil and Royal Dutch Shell all signed PSCs with the Russian government in the 1990s, at a time when Russia was warmly welcoming foreign investment in its upstream segment. The oil-price boom of the mid-2000s led to a substantial change of regulatory direction, however, as the state, under then-president Vladimir Putin, began to exert itself vigorously in this 'strategic' sector. In 2007, after a long-running dispute involving allegations of environmental malfeasance, Shell was forced to hand over operatorship of the Sakhalin-II project to Gazprom. While ExxonMobil managed to hold on to its

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operatorship of the Sakhalin-I project, Total and Statoil each transferred 10% stakes in their Kharyaga gas field PSCs to state-run Zarubezhneft in 2009.

However, as a result of the substantial fall in crude oil and gas prices since the 2008 financial crisis, Russia's budgetary position has gone from surplus to deficit. Furthermore, with substantial investment required to achieve its lofty production goals, Russia has been forced by circumstances to soften its tone. As a result, the country has revived the prospect of forming PSCs with IOCs, after nearly a decade of state revanchism in the oil and gas sector. Russian energy minister Sergei Shmatko spoke of the possibility of resurrecting PSCs in statements to the Russian parliament on December 8 2010. Shmatko said that PSCs would enjoy a 'renaissance' in Russia as they would attract funds necessary for further exploration and allow producers to accept greater risk.

The prospect of PSC revivals and a more attractive tax structure fits into this broader trend of increased openness in the Russian upstream segment, as the country looks to foreign investors to help sustain its 10mn b/d production. Moscow remains keen to solicit foreign participation in its technology and capital- intensive offshore and Arctic fields, but as the award in December 2010 of the Trebs and Titov fields to Bashneft demonstrates, 'safer' onshore plays will remain the province of state-run enterprises.

Arctic Exploration The Russian government is planning changes to the upstream regulatory framework to attract foreign investors to its offshore Arctic region, where the state has traditionally been reluctant to loosen its grip. Under proposed laws, foreign companies that make commercial oil and gas discoveries will be either guaranteed a stake in their development or receive financial compensation comprising costs incurred and an additional 'reward' for exploration risk, Upstream reported on December 1 2010, citing Denis Khramov, the director of the Department for State Policy and Regulation of Russia's Ministry of Natural Resources. Additionally, Russia is looking to implement new regulatory procedures regarding drilling permits and the installation of offshore structures, artificial islands and subsea pipelines. No further details were made available.

Offshore Exploration Russia may relax rules effectively limiting offshore E&P in the country to Rosneft and Gazprom, according to a report by the Moscow Times newspaper in March 2010. The report, which cited deputy energy minister Sergei Donskoy, said the proposal would allow subsidiaries of the two companies to join them in offshore exploration and could lead to IOCs also becoming involved.

In the Moscow Times article Donskoy claimed that the NREM believes Gazprom and Rosneft have insufficient resources to develop Russia's continental shelf on their own. Under a plan drafted by the ministry, the companies would be allowed to share access with their subsidiaries and could farm out a stake of up to 50% in offshore projects to foreign companies. The proposal would also allow any of the

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subsidiaries to develop offshore fields on their own or in partnership with other companies. However, the newspaper also reported that it is unclear whether the proposal has been submitted to the Russian cabinet.

Under legislation passed in 2008, offshore fields in Russia can only be developed by companies in which the government owns a stake of 50% or greater. In addition, companies applying to work on the fields must have a five-year record of working on such projects, effectively limiting participation to Gazprom and Rosneft. It is arguable that this has damaged Russian investment in offshore areas. The two companies invested only RUR56.4bn (US$1.9bn at 2010 rates) in E&P offshore Russia in 2008, a rate that Donskoy claimed would mean ministry targets for offshore areas would take 165 years to fulfil.

Government Policy

Under the Energy Strategy 2030, Russia is expecting to sustain its oil output at roughly 2009 levels and dramatically boost gas production. The plan, drafted in August and approved in November 2009, calls for annual production of 10.6-10.7mn b/d of oil and 885-940bcm of gas by 2030. Exports of crude and oil products are expected to rise to 6.6mn b/d while gas sales abroad are to reach 349-368bcm by that year. Most of the extra gas exports are expected to be absorbed by Asia. To achieve the set output growth, the government wants an annual investment of US$28.4bn (late 2009 exchange rate) in the oil sector and US$27bn in the gas sector. The oil output target is theoretically achievable, especially after a downward revision of the August 2009 draft. The level of capex outlined in the plan, however, is unlikely to be sufficient. Gas production goals look extremely ambitious outright given the current volumes and dynamics of the global supply and demand.

The government is moving forward plans to privatise a larger share of Rosneft. In July 2010, the Finance Ministry included the country's largest oil producer in the list of nine companies earmarked for partial privatisation in 2011-2013 in an attempt to eliminate the budget deficit. Up to 24.16% of Rosneft could be sold, leaving the state with the 51% controlling stake. As the jewel in the Russian state sector's crown, the Rosneft stake could provide around RUB500bn (US$16.5bn) for the treasury, or half the overall divestment target. A non-controlling stake in Transneft may also be sold, although government officials have been given conflicting signals.

In July 2008, Russia’s state market regulator, the Federal Financial Markets Service (FFMS), put a 25% cap on the proportion of shares domestic mineral resources companies, and other ‘strategic’ industries, can list abroad. Moreover, under the new rules, only 5% of the energy companies’ total sales are allowed to come from operations in foreign countries. This will push Russian companies to raise finance at home, in line with President Dmitry Medvedev’s plans to turn Moscow into a major financial centre by 2020. The head of the FFMS said at the time that the companies’ shares can, and therefore must, be traded in roubles in Russia, adding that all the necessary conditions to enable that process were in place. The ruling is the most explicit recent step in the Kremlin’s programme of consolidating control over Russia’s

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mineral resources and suggests further downside risks to an investment climate already marred by a poor licensing, privatisation and regulatory structure.

As the extent of the global economic meltdown became clear in September 2008, Russia's main producers collectively approached the Kremlin for assistance. The CEOs of Lukoil, TNK-BP and Rosneft plus Gazprom’s Deputy Chairman Alexander Ananenkov wrote to Prime Minister Vladimir Putin asking for state credit ‘to pay for foreign debts’. Although the companies did not specify the required sum, they argued that the overall debt volume of the Russian energy sector was around US$80bn and required state action. The companies also requested Putin to order the finance ministry and the central bank to work out a mechanism of financing strategic projects with the help of 'state targeted credits'.

The government has signalled its intention to provide US$50bn from Russia's gold and foreign exchange reserves to help refinance domestic corporations' foreign debt and grant selected tax holidays. Although these moves will be supportive, they may not be enough on their own to help Russia's major oil producers ride out the current crisis. Each of the major companies is therefore also adopting its own strategies to minimise the negative repercussions of the economic downturn.

International Energy Relations

South Korea Gazprom and its South Korean counterpart Kogas signed an MoU in June 2009 to jointly study the options for delivering Russian gas to South Korea. In particular, the MoU will look at ways of supplying South Korea with gas from the Sakhalin projects. According to Platts, under the terms of a previous agreement signed by Kogas and Gazprom in September 2008, the Korean company plans to import 10bcm per annum of Russian gas between 2015 and 2045.

Following the launch of the Gazprom-led Sakhalin-II project in April 2009, Kogas began receiving Russian LNG under a 2.2bcm (1.6mn tpa) supply contract. Kogas, one of the world’s largest gas buyers, is now looking to boost these Russian gas imports significantly by expanding the regional LNG export capacity and/or ensuring the extension of the planned Sakhalin-Khabarovsk-Vladivostok gas pipeline into the Korean peninsula. An MoU on jointly constructing an LNG terminal on Russia’s Pacific coast was signed by Gazprom and Kogas in September 2009. Additionally, two pipeline options between Russia and South Korea are currently being evaluated: the overland pipeline via North Korea and the direct undersea pipeline. The first option suffers from severe geopolitical risks while the second option presents partners with formidable technological and financial challenges.

In April 2010 Gazprom’s head of foreign projects, Stanislav Tsyganov, said that South Korea and Russia were expected to begin a new round of talks in mid-April on a gas interconnector between the countries. However, it is unclear what route the gas interconnector could now take, following a marked deterioration

Russia Oil & Gas Report Q2 2011

in relations between the two Koreas in mid-2010. Tsyganov also poured cold water on the subsea route plans, claiming that the shallowness and uneven surface of the seabed in the area makes the project highly challenging from a technical perspective. The numerous difficulties with both pipeline options suggest to us that no concrete decision will be reached during this round of talks. Longer term, we believe the pipeline will not be built until the political unification of the Korean peninsula.

China In February 2009, Moscow and Beijing signed a major energy agreement that will see the Russian state oil sector receive US$25bn in Chinese loans in return for a commitment to sell China 15mn tpa of crude (300,000b/d) between 2011 and 2030. The agreement was made up of four deals. The first two concern long-term loans to be provided by the China Development Bank to Rosneft, which will receive US$15bn, and oil pipeline monopoly Transneft, which will receive US$10bn. The third is a 20-year oil supply contract between China National Petroleum Corporation (CNPC) and Rosneft, and the fourth is an agreement between CNPC and Transneft regarding the construction and exploitation of the China-bound branch of the East Siberia-Pacific Ocean (ESPO) pipeline.

Although the financial terms of the deals were withheld, two unnamed Russian government sources unofficially provided details. According to an official in the Russian energy ministry, quoted by Vedomosti, the price of the oil supplied will be calibrated monthly, based on the Platts and Argus trade quotes for the Kozmino terminal. A high-level official quoted by Reuters reported that the interest rates of the loans will be pegged to LIBOR and will fluctuate between 5% and 5.5%. According to Russian energy minister Sergei Shmatko, Rosneft and Transneft will spend the Chinese loans in two main areas: ESPO and 'corporate development', which is likely to imply debt management.

Russia has long planned to start gas exports to China in the hope of ensuring security of demand in the face of EU efforts to diversify gas supplies. Discussions between the two countries, which were formalised through the signing of a preliminary agreement in October 2009, have so far been stymied by a failure to agree a gas price. This failure has prevented Russia and China from committing to fund the construction of the costly pipeline infrastructure necessary for exports. The pricing dispute reportedly arises from Russia's insistence on linking gas prices to oil prices, as is the case for exports to the EU.

Cooperation on natural gas was one of the issues discussed during a meeting between Russian Deputy Prime Minister Igor Sechin and his Chinese counterpart Wang Qishan in November 2010, according to the state-run China Daily website. Chinese energy official Gu Jun said on November 18 that the difference in the gas price demands between the two sides is currently only US$100/mcm, Bloomberg reported. Although linking gas prices to oil prices would help to compensate Russia for the higher cost of transporting gas to China, the resulting European-style price levels would be unacceptable to China. Benchmark prices in China are significantly lower than in Europe and are rarely raised.

Russia Oil & Gas Report Q2 2011

Norway Russia and Norway have agreed to settle a dispute over their maritime border in the Barents Sea, signing a treaty in September 2010. The dispute, which centred on 176,000sq km of sea, had prevented the area from being fully opened up to oil and gas exploration. The resolution of the dispute will boost efforts to develop the oil and gas resources of the Barents Sea.

The disagreement between the two countries, which dates back to around 1970, was based on conflicting claims to an area of around 176,000sq km in the centre of the sea. Norway based its claim on the 'median line' principle outlined in the UN Convention on the Territorial Sea and Contiguous Zones (1964) and the UN Convention on the Law of the Sea (UNCLOS, 1982), which stated that the maritime border should be drawn equidistantly between the two countries. The Soviet Union, and later Russia, countered that Russia's size relative to Norway dictated that it should receive a proportionally larger share of the sea and that it had claimed the area under dispute since 1926 using the meridian line rather than the median.

The treaty includes provisions for cooperation in the development of hydrocarbons in the case of any new discoveries being made that straddle the demarcation line. The two sides will also cooperate on determining the outer limit of the continental shelf in accordance with UNCLOS.

Qatar In a March 2010 press statement Gazprom said that Qatar had expressed interest in becoming involved in projects in the Yamal Peninsula at a working meeting between Gazprom's management committee and the Qatari Prime Minister Sheikh Hamad Bin Jassem Bin Jabor al-Thani. According to Gazprom, the two sides discussed potential cooperation in LNG transactions and swap deals between LNG and pipeline gas in the European and Asia-Pacific markets. In addition Gazprom claimed that the Qatari delegation had expressed interest in projects in the Yamal Peninsula, particularly in the possibility of commercialising the Tambeyskoe gas fields through the Yamal LNG project.

Qatar's discussion of gas cooperation with Russia will sound worrying to European gas consumers, which have taken advantage of the changing differential between LNG and pipeline gas prices to drive down the cost of energy imports. By cooperating over pricing the two countries could benefit as European gas demand recovers in the aftermath of the global economic downturn.

Belarus Russia and Belarus have had several disputes over energy supplies and pricing since 1991 when the latter became independent. As a former Soviet Union country, in the early-2000s Belarus received gas at a price of around US$46/mcm from Russia, a figure far below the market rate. In late-2006, however, as part of a more general policy of reducing energy subsidies to former Soviet satellites, Russia announced that it would increase gas prices, prompting Belarus to introduce an oil transit fee that led to Russia temporarily cutting off its supplies.

Russia Oil & Gas Report Q2 2011

Under a deal to solve the crisis, Belarus agreed that Russia would increase gas export prices to US$100/mcm rather than the initially planned US$200/mcm. The price reportedly increased to US$119/mcm in 2008. In return for these subsidised rates, Belarus allowed Gazprom to purchase 12.5% of its state gas transit company Beltransgaz annually from 2008 to 2010 for a total payment of US$2.5bn. Gas prices continued to rise in 2009, averaging US$150/mcm. During the winter period of peak demand, prices rose further from US$121.98/mcm in Q409 to US$169.22/mcm in Q110. In response, Beltransgaz started paying for gas at the lower rate of US$150/mcm, the average 2009 price. Gazprom claims that Beltransgaz owes US$137.49mn for gas imports in the peak period of Q110. This amount is set to increase, and Gazprom estimates that at this rate Belarus's gas debt could reach US$500mn by the end of 2010.

In BMI’s view the current situation is unsustainable and is likely to lead to a renewed flare-up of the two countries’ long-running dispute unless Belarus agrees to pay the higher price demanded by Russia. One possible outcome is that Belarus will offer Russian companies an increased stake in its main energy infrastructure companies, most likely in Beltransgaz and Belarus’s Mozyr refinery.

Kazakhstan Russia and Kazakhstan in September 2010 agreed to start jointly developing the Imashev gas and condensate field, which straddles the border of the two countries. The move follows a five-year period of near inactivity at the field, following a deal in January 2005 demarcating the Russia-Kazakhstan border. This progress on the field's development is a sign of Russia and Kazakhstan's willingness to cooperate on the development of shared resources.

The Imashev field is located on the border between Russia's Astrakhan Oblast and Kazakhstan's Atyrau Province near the Caspian Sea. The field is Kazakhstan's second largest gas field after Karachaganak, according to Kazakh news agency IRBIS, but it has not been developed owing to a dispute over the border with Russia. In January 2005, however, the two countries signed a border demarcation agreement under which Kazakhstan ceded a border village covering part of the field to Russia, in return for territory elsewhere and an agreement to develop the field jointly with Russia.

Following the Seventh Forum of Russia-Kazakhstan Inter-Regional Cooperation held in Ust- Kamenogorsk on September 6-7 2010, the two countries announced that they have now agreed to survey the field's reserves and prepare it for development. Russia's ITAR-TASS news agency reported that the field has estimated reserves of 128.7bcm of gas and 20.7mn tonnes of gas condensate, equivalent to 186.6mn bbl. Kazakh oil minister Sauat Mynbayev said that the field will be the first to be developed on the territory of the two states.

Others In May 2009, Japan and Russia signed a raft of energy cooperation deals. The deals include a joint oil

Russia Oil & Gas Report Q2 2011

exploration agreement, an accord that will see Russia supply enriched uranium to Japan, and a MoU to look at ways of transporting gas from Vladivostok to Japan, with additional deals likely to be signed in future.

Executives from US oil majors have accompanied US President Barack Obama on his state visit to Moscow in July 2009, holding negotiations over expanding their presence in Russia. Neil Duffin, head of ExxonMobil’s project development unit, told Reuters during the trip that the company wanted Russia to make sweetening amendments to its subsoil law.

Gas Transit And Marketing

Ukraine As a result of pricing, payment and transit disagreements, Russia cut off gas supplies to Ukraine on January 1 2009, causing a knock-on effect on European flows by January 7. Bitter wrangling between Moscow and Kiev ensued while supply disruptions in Eastern and south-eastern Europe reached crisis point. After a number of false starts, the flow of gas was eventually restored on January 20. Tense negotiations between the two countries over gas-related debts and prices continued throughout 2009 before an uneasy truce between Prime Minister Vladimir Putin and his Ukrainian counterpart Yulia Tymoshenko was established in November of that year. While the likelihood of a new gas supply cut in the winter of 2009/10 is significantly lower, the reputations of both countries as a reliable energy supplier and a transit state respectively have taken a battering, and the dispute has encouraged the EU to accelerate its gas supply diversification programme.

Gazprom and Ukraine's state-owned Naftogaz in November 2009 agreed to reduce Ukraine's gas imports in 2010 to 33.75bcm, down from the previously contracted 52bcm for that year. It was also agreed that Ukraine would not be fined for buying less gas in 2009. Between January and October 2009, Ukraine is said to have imported just 18.85bcm compared with the contracted 31.7bcm, according to Gazprom. Over 2009, Ukraine had agreed to buy a total of 42bcm. Furthermore, Russia had agreed to increase the transit fees it pays Ukraine by 60% in 2010. In 2009, transit fees stood at US$1.70 per mcm per 100km.

While the actual gas prices have not been released, Tymoshenko said that the gas price Ukraine pays 'will be almost the same in 2010 as it [was] in 2009'. Further details on the gas price and the transit fees Ukraine and Russia will pay respectively in 2010 have not been released. In January 2009, Putin and Tymoshenko agreed that in 2009 Ukraine would receive a 20% discount on European market prices in return for maintaining transit fees at the same rate as in 2008, with Ukraine to start paying European-level prices and for transit fees also to reach market levels as of January 1 2010. It is unclear whether Tymoshenko’s comment means that the absolute price Ukraine will pay for gas imports in 2010 will remain more or less the same or whether the same 20%-discount principle will continue to apply. The

Russia Oil & Gas Report Q2 2011

price that Gazprom charged Ukraine in Q109 was US$360/mcm, almost exactly double the US$179.50/mcm Ukraine paid in 2008.

In January 2009 Putin and Tymoshenko also agreed to eliminate RosUkrEnergo. This had been agreed before, in October 2008, so whether Naftogaz and Gazprom will from now on trade directly remains to be seen. RosUkrEnergo, which was created in 2004 to replace EuralTransGas as the intermediary to manage the gas trade between Turkmenistan and Ukraine, was established as a middleman between Gazprom and Naftogaz in January 2006 following the gas pricing dispute. A Swiss-registered monopoly JV, RosUkrEnergo, is 50% owned by Gazprom, with the remaining 50% owned by Raiffeisen Investment through its Swiss-registered Centragas Holding, acting on behalf of a consortium of Ukrainian businessmen. RosUkrEnergo has certainly profited from the Russia-Ukraine gas trade, and Naftogaz will be hoping that that company's elimination will help its own balance sheets.

Turkmenistan Relations between Ashgabat and Moscow have soured following a disagreement in April 2009 over an explosion on the pipeline that transports gas from Turkmenistan's Dauletabad field to Russia via Uzbekistan. The Turkmen government blamed Russia for unilaterally cutting the volume of deliveries through the pipeline without giving Turkmenistan due warning to relieve the extra pressure on the route, thereby causing a rupture. Moscow pinned the blame on technical problems on the Turkmen side, but Turkmen President Kurbanguly Berdymukhamedov has demanded an international investigation and has said he will seek compensation from Gazprom.

Gazprom clarified its stance on the incident in June 2009, stating that it reduced the pipeline’s throughput by 80% after notifying Ashgabat that it could no longer take the normal volumes owing to the economic slump. In response to Russia’s cut in gas purchases, Turkmenistan has boosted its efforts to diversify its customer base, announcing plans to raise exports to Iran, launch a new gas pipeline to China and supply gas for the EU-backed Nabucco pipeline. Gas exports finally resumed in January 2010, under the terms of a new agreement signed in late December 2009, which provides for 30bcm of Turkmen gas to be exported to Russia in 2010 and annually to 2028. Volumes have been cut drastically from the 70-80bcm of exports envisioned under the countries' previous gas supply agreement, which was signed in 2003, and from the 50bcm that Turkmenistan exported to Russia in 2008.

Uzbekistan Gazprom signed a one-year supply contract with Uzbekistan in December 2009. Under the new contract Gazprom will purchase 15.50bcm from Uzbekistan in 2010, up from 11.25bcm contracted in 2009. The deal was signed between Gazprom and Uztransgaz, the transportation and export unit of state-run gas company Uzbekneftegaz. Although neither side has announced the price formula, Gazprom said that it will be in line with conditions in the European gas market. Following the deal, Gazprom's deputy

Russia Oil & Gas Report Q2 2011

chairman, Alexander Medvedev, said that the two sides had agreed to start preparation for a long-term contract. The current gas supply framework, signed in 2002, is due to expire in 2012.

Belarus The special energy relationship Belarus has enjoyed with Russia since the collapse of the Soviet Union is steadily waning. Under an implicit arrangement that lasted until 2009, Minsk secured cheap energy in return for advancing Russia's political interests at home and abroad. The strain of this arrangement on the finances of Russia's gas exporter Gazprom and moves by Belarusian President Alexander Lukashenko to establish an independent foreign policy have put an end to the salad days of bilateral energy ties. In mid- 2010 the tensions spilled over. Following Gazprom's price increase for 2010, Belarus decided to pay for gas deliveries at the 2009 price, gradually building up a disparity that by the start of the dispute reached US$192mn. On June 21 Russia reduced gas supplies to Belarus by 15%, increasing the cuts daily to 60% by June 24. This was despite Belarus' requesting two weeks to find the money.

Belarus retaliated by cutting off transit volumes to Europe. In addition, Semashko announced that Gazprom owed Belarus US$217mn in gas transit fees, a sum later increased by President Lukashenko to US$260mn. According to a contract signed in 2006, Gazprom has to pay US$1.45/mcm per 100km, but Belarus subsequently increased its fee to US$1.74/mcm in 2009 and US$1.88/mcm in 2010. According to Lukashenko, Gazprom had paid for transit at the rate stipulated under the 2006 contract since late-2009 rather than increasing the payments in line with Belarusian demands.

A fragile truce was reached in late June 2010. Gazprom allegedly agreed to accept US$187mn from Belarus in payment for its gas debt rather than the US$192mn it had sought earlier. Gazprom also offered to pay US$233mn in fees for gas transit to Europe through Belarus, below the US$260mn claimed by Lukashenko but above the US$217mn announced by Semashko.

Belarus said in October 2010 that it expects to pay more for Russian gas in 2011, in a sign of an enduring energy truce between the two countries. On October 1, Belarusian First Deputy Prime Minister Vladimir Semashko said the cost of Russian gas next year will rise from US$184 per thousand cubic metres (mcm) at present to US$210/mcm. As recently as the mid-2000s Belarus paid US$40/mcm for the gas it imports from Russia. The deputy PM's announcement is an indication that the truce is holding for now, with Belarus apparently prepared to accept the fact that its gas bills will gradually head towards the European average. Although Belarus is paying an ever-higher price for Russian gas, its supplies are still cheaper that elsewhere in Europe. Gazprom's average sales price in mid-2010 stood at US$280/mcm.

Poland Russian-Polish relations have often been fractious, although they have improved slightly since 2009 under the more pragmatic new government of Donald Tusk. A new gas supply deal between Polskie Górnictwo Naftowe i Gazownictwo (PGNiG) and Gazprom was ratified by the Polish government on

Russia Oil & Gas Report Q2 2011

February 10. Under the agreement, Gazprom has agreed to increase gas supplies to 11bcm a year. The existing supply deal between the countries, known as the Yamal contract, has been extended from 2022 to 2037 and the two sides also agreed to extend an earlier deal for gas transit via the Yamal-Europe pipeline, which runs to Germany, until 2045.

The deal's slow progress towards approval reflects disagreements between Poland and Russia over transit fees payable to EuRoPolgaz, the operator of the Polish section of the Yamal pipeline. Between 2006 and 2009 Gazprom unilaterally decided to pay lower transit fees than those set by the Polish energy market regulator URE. According to a report in Polish daily newspaper Rzeczpospolita, the two sides have come to an agreement under which PGNiG will receive a discount on the price paid for gas deliveries in return for dropping its claim against Gazprom. Putin claimed in September 2009 that under international agreements the company should be owned 50:50 by Gazprom and PGNiG. He called for an investigation into the way that the Polish company Gas Trading had acquired a 4% stake in the project, with Gazprom and PGNiG holding 48% each.

Even after the deal was signed by the two sides, it was delayed by the EU, which was concerned over third party access (TPA) to the Yamal-Europe gas pipeline. Although the deal benefits Poland in that it allows it to increase imports and limit prices without having to increase the supply contract length, there are several aspects to the deal that benefit Russia. Gazprom will retain control over the destination for its gas through a clause banning PGNiG from selling gas to third countries without Russian permission. In addition, as Gazprom and PGNiG control both the Yamal-Europe pipeline and the gas flowing through it, they also have the ability to block TPA by keeping gas volumes at or near to 100% of capacity.

According to separate press releases, PGNiG and Gazprom finally signed an annex to their existing gas supply contract on October 29 2010, under which gas supplies to Poland will be increased while keeping the length of the contract the same. Under the deal, Poland will be able to import up to 9.03bcm in 2010 (9.7bcm according to Russian norms), rising to 9.77bcm in 2011 (10.5bcm), and then to 10.24bcm (11.0bcm) over 2012-2022. Any gas above the contractual minimum will be sold at a discount. PGNiG valued the deal at around PLN8.5bn (US$2.94bn) per year and said that it could save US$250mn per year using the full discount.

The Baltic Region Gazprom in September 2009 began transporting gas along the second branch of the Minsk-Vilnius- Kaunas-Kaliningrad pipeline, increasing its capacity from 1.4bcm to 2.5bcm. While the expansion of the pipeline is aimed at increasing gas supplies to the Russian enclave of Kaliningrad, Lithuania's gas company Lietuvos Dujos views it as essential for its security of supply. Gazprom also built an underground gas storage facility at Kaliningrad, which was completed in late-2009. Gazprom supplies Lithuania with gas under a long-term agreement effective through 2015. In 2008 Lithuania received 3.1bcm of Russian gas in 2008.

Russia Oil & Gas Report Q2 2011

Tensions between Gazprom and Estonia and Lithuania have been rising since the two countries announced plans in mid-2010 to break up their Gazprom-controlled gas monopolies in an attempt to loosen Russia's grip on their energy markets and comply with the EU's energy competition directive.

Prospects for an amicable solution have since been falling. On August 25 2010, the state-controlled Russian gas giant sent a letter to Lithuanian Prime Minister Andrius Kubillius threatening international court action if his government splits up Lietuvos Dujos into trading and distribution arms. Gazprom argues the reform will wipe out its 34% stake in Dujos, adding that Lithuanian government acted unilaterally without consulting the firm's shareholders. Kubillius told local media that the letter amounted to 'big company pressuring a small country', setting the scene for a standoff with Moscow.

Lithuania is the largest gas consumer among the three Baltic states, and like the rest of the region is wholly reliant on Gazprom for its gas supplies. Together with Estonia, Lithuania has long complained that it is forced to pay some of the highest gas prices in Europe. According to local media, Gazprom will charge Lithuania US$320/mcm over 2010. An average realised gas price paid by Gazprom's non-FSS European customers in H110 was just below US$300mcm, with most FSS states paying significantly less. Gazprom argues that owing to the small absolute volumes consumed by the Baltic states, it needs a price premium to make supplying the region worthwhile.

Gazprom has managed to keep a presence in all the Baltic markets following the break-up of the Soviet Union and owns about a third of the national gas companies of Estonia (37%), Latvia (34%) and Lithuania (34%). The more Russia-friendly Latvia appears to be content with the status quo for the time being. Its two neighbours, however, have become decisively uncomfortable in Gazprom's grip. The Nord Stream subsea pipeline from Russia to Germany, bypassing the Baltics, has only raised Vilnius and Tallinn's energy security fears.

As an alternative to Gazprom's supplies Lithuania is pushing the Amber pipeline project. In its revised form the 5bcm pipeline will link the country with Poland's planned LNG terminal. The Świnoujście terminal is due onstream in around 2015. For the foreseeable future, however, Lithuania's dependence on Russian gas looks solid. The same applies to even greater extent to Estonia. Until the two countries develop tangible supply alternatives, brinksmanship with Gazprom could lead to some long cold Baltic nights.

Azerbaijan In March 2009 Gazprom and Azerbaijan's state-owned Socar signed an MoU for the delivery of a minimum of 500Mcm of Azeri gas to Russia a year starting in January 2010. A final binding agreement followed in October 2009. Socar's CEO Rovnag Abdullayev said following the deal that Azerbaijan would export 1bcm of gas to Russia from January 2010. The exported gas will be sourced from the first phase of Azerbaijan's Shah Deniz field. At a later stage, Russia may also import gas from Shah Deniz's

Russia Oil & Gas Report Q2 2011

second phase. Gas from this project has also been earmarked for the EU-backed Nabucco pipeline project, which is intended to supply Europe bypassing Russia.

In January 2010 Gazprom announced plans to double gas imports from Azerbaijan to 2bcm from 2011. Gazprom added earlier in the month that it would be willing to buy 'all gas exported by Azerbaijan'.

The Middle East There has been much talk of extending Russia’s Blue Stream pipeline to Turkey further south into the Middle East. In February 2006, Turkish energy ministry officials claimed that talks were under way between Gazprom and Turkish state-run gas distributor Botaş about extending the pipeline through Turkey to Syria, Lebanon, Israel and Cyprus in a project known as Blue Stream II. Speaking during an official visit to Turkey in June 2010, however, Prime Minister Putin said Israel is now likely to be excluded from the Blue Stream II project. Putin said that gas discoveries in recent years in Israel have reduced the country's future gas import projections, making an extension of the pipeline to Israel unnecessary. Putin stressed that the decision was not connected to an attack by the Israeli navy on a convoy heading towards Gaza, which drew international criticism. The attack does appear to have had an impact on Turkey's view of the project, however, with the country's Aksam newspaper citing unnamed energy ministry sources as saying that Turkey's international agreements with Israel, including Blue Stream II, would now be reviewed.

India In January 2011 Russia signed an agreement with Afghanistan to help build the proposed Turkmenistan- Afghanistan-Pakistan-India (TAPI) gas pipeline. The move followed a report in India's Hindustan Times newspaper, citing senior Indian officials, which claimed that India was blocking the involvement of Chinese companies in the project. Although Russian involvement could boost the project's chances of going ahead, it undermines TAPI's aim of diversifying Central Asia's gas export routes away from Russia. In any case, BMI thinks the pipeline is highly unlikely to be built in the near to medium term.

In December 2010 India's state-run Oil and Natural Gas Corporation (ONGC) established a framework with Sistema that could see the potential merger of their Russian oil and gas assets. During a visit to India by Russian President Dmitri Medvedev, the international subsidiary of ONGC, ONGC Videsh (OVL), signed a framework agreement with Sistema. Under the deal, they agreed to 'consider opportunities for a potential transaction' involving either Sistema's or OVL's current Russian oil and gas assets or any assets that either company may acquire prior to the signing of any definitive agreement. The parties also envisage joint investments in other exploratory assets, while OVL said it would lead a consortium of Indian state-run firms to possibly acquire a stake in Sistema.

Russia Oil & Gas Report Q2 2011

Oil Transit

The Baltic Region Russian Prime Minister Vladimir Putin signed an order on December 1 2008 for the construction of a second trunk line of the Baltic Pipeline System (BPS). The new line will boost Russia's oil export capacity from the Baltic Sea and will provide an alternative export route to the Druzhba North pipeline that runs from Russia through Belarus and Poland into Germany. Transneft proposed building the new BPS trunkline (BPS-2) in January 2007, and the government approved the project in May 2007. The existing BPS transports oil from European Russia to Primorsk on the Gulf of Finland. Construction was completed in 2001 and current capacity is 1.5mn b/d. BPS-2 will extend 1,300km from the Bryansk region to the port of Ust-Luga, near Primorsk, with a branch going to the Kirishi refinery. Oil should start flowing in Q312 at an initial rate of 600,000b/d, with capacity to be raised subsequently to 1mn b/d. The estimated cost is RUB120-130bn (US$4.3-4.7bn). Construction appears to have been delayed indefinitely from the June 2009 start-up date.

Belarus Historically Russian companies were exempt from Russian export duties on oil exports to Belarus. This encouraged the companies to operate with so-called 'give-and-take' contracts, under which they would export duty-free crude oil to Belarus, where they would process it for a fee at the country's refineries before re-exporting it to Europe. In April 2007, however, as part of a general process of phasing out energy subsidies to former satellite states, Russia imposed a limited export duty on crude oil exports to Belarus and insisted that Belarus increase excise tax on oil products. This led to Russian companies ceasing the 'give-and-take' contracts and companies that had participated, such as Lukoil, began selling oil directly to the owner of the country's two refineries, Belneftekhim.

Following a by-now almost annual dispute between Russia and Belarus over oil prices, Russia cut off crude supplies to Belarus in January 2011, forcing Belarus to halt fuel exports to Europe. Belarus also struck a deal to import crude via the Odessa-Brody pipeline through Ukraine.

Russia briefly stopped supplying Belarusian refineries in January 2010 after the existing supply deal expired without the two sides agreeing on a new framework. Under the expired agreement, Belarus had benefited from preferential oil trading terms with its eastern neighbour, with its refineries paying only around 36% of the standard Russian crude export tariff and then making a healthy profit exporting their refined products to European customers at market prices. During earlier negotiations over the new oil deal, Russia had said that it would provide tax-free oil to Belarus for domestic consumption, but that the country should pay export duties for oil exported to Europe.

Belarus argued that this would go against an agreement on a customs union that the two countries signed late in 2009 and responded by demanding higher transit fees for oil crossing its territory. This divergence

Russia Oil & Gas Report Q2 2011

of positions was behind the two sides' failure to agree new terms. Oil flows resumed after a precarious temporary agreement was reached in late January 2010, which committed Belarus to paying full export duties on re-exported Russian oil. All duties, however, are due to disappear after the new customs union between the two counties comes into force in mid-2010.

Turkey The governments of Turkey, Russia and Italy in October 2009 signed a preliminary agreement for the construction of the Samsun-Ceyhan oil pipeline, which would cross Turkey from the Black to the Mediterranean coast and thereby provide Russia with another export route for its Black Sea oil terminals. Russia agreed to supply the pipeline, also known as the Trans Anadolu Pipeline (TAP), earlier in 2009. The 550km oil pipeline will have an initial capacity of 1mn b/d, which will eventually rise to 1.5mn b/d. No start-up dates have been released. Transneft was offered a 50% stake in the pipeline in December 2009, by Anadolu Pipeline Company (TAPCO), a 50:50 JV between Eni and local company Çalik Energy, which is developing the project.

In an effort to fill the TAP pipeline, Transneft said in June 2010 that it could support proposals to impose quotas on shipments of oil through the Bosphorus. According to remarks made by Transneft's president, Nikolai Tokarev, at least two proposals are being considered to achieve this. Under one proposal, companies intending to export oil from the Black Sea would be given a quota restricting the volumes that can be transported through the Bosphorus. Volumes beyond the quota would have to be exported by pipeline. Under the other proposal, crude oil exports through the Bosphorus would be halted completely, forcing companies to transport all oil volumes by pipeline. Oil products and petrochemicals would be unaffected by both proposals and would still be transported through the Bosphorus. Tokarev did not specify how the quotas would be imposed.

Russia Oil & Gas Report Q2 2011

Table: Key Upstream Players

Oil/liquids production Gas production Company (000b/d) Market share (%) (bcm) Market share (%)

Lukoil 1,830 19.5 7.4 1.2

Surgutneftegaz 1,197 12.1 14.1 2.3

Gazprom Neft*** 957 9.4 na 0.3

Tatneft 519 5.1 0.8 0.1

Gazprom 335 3.3 462 78.3

TNK-BP 1,680 14.7 12 1.9

Rosneft 2,180 21.5 12.4* 2.1

Russneft 254 2.3 na na

Total 11 0.1 0.02 nm

Imperial 13.5 0.1 na na

Novatek 60 0.5 32 5.1

Shell 106 1 2 1

Alliance 42e 0.4 na na

Includes JV entitlements, e = estimate, na = not available/applicable. Source: BMI, 2008 company data; , ***includes all Gazprom Group companies.

Key Downstream Players

Refining capacity Company (000b/d) Market share (%) Retail outlets Market share (%)

Rosneft 1,127 20.5 1,762 15

Lukoil 908 16.3 2,170 19e

TNK-BP 774 14.3 1,400* na

Bashneft Affiliates 704 13.0 317 na

Gazprom Neft 538 9.9 1,562 na

Surgutneftegaz 348 6.4 305 3

Slavneft 315 5.8 na na

Tatneft 149 2.7 484 na

*Including Ukraine; e = estimate, na = not available/applicable. Source: BMI. Company data 2010 apart from fuels retail data 2009.

Russia Oil & Gas Report Q2 2011

Company Monitor

Gazprom

Company Analysis Address Gazprom The threat of a break-up appears to have passed, with Russia keen to Nametkina ul., d. 16 consolidate the gas major’s position, strengthen its grip on aspects of the 117997 Moscow Russia energy market and liberalise domestic and CIS pricing. It also intends to Tel: +7 (495) 719 3001 increase its direct ownership. With higher domestic selling prices, earnings Fax: +7 (495) 719 8333 will benefit and more cash will be available for supply and export expansion. www.gazprom.ru The addition of Sibneft has accelerated the growth of Gazprom and established it as the leading Russian generator of hydrocarbons volumes, Financial Statistics revenues and earnings. Revenues RUB3.0trn (2009) RUB3.52trn (2008) SWOT Analysis RUB2.42trn (2007) Strengths: Dominant share of upstream gas supply RUB2.15trn (2006) RUB1.38trn (2005) Control of gas transportation system Net income Rising export demand for gas RUB793.8bn (2009) Huge exploration upside potential RUB742.9bn (2008) Scope for domestic merger RUB658.0bn (2007) RUB613.3bn (2006) Weaknesses: Cost and efficiency disadvantages RUB311.1bn (2005) Rising investment requirement

Artificially low domestic gas prices Operating Statistics (inc. Gazprom Neft) Opportunities: Growth in domestic/CEE/EU gas demand Gas production: Large areas of unexplored territory 462.0bcm (2009) Incorporation of Sibneft assets and management 550.0bcm (2008) Efficiency gains/price liberalisation 548.6bcm (2007) Crude production: Threats: Russian corporate governance 645,600b/d (2008) Changes in national energy policy 680,000b/d (2007) Condensate production: 220,000b/d (2008) 226,000b/d (2007)

Russia Oil & Gas Report Q2 2011

Market Position

Gazprom accounts for 80% of Russia’s gas production (2009) and holds at least two-thirds of the nation’s gas reserves (or 15% of world reserves). The company also has a virtual monopoly control over the domestic gas pipeline network, which supplies fuel to almost every Russian region, the CIS states and over 25 European nations. The firm remains heavily reliant on overseas gas sales, as it is forced to supply gas to the domestic market at subsidised rates. Domestic prices, however, are gradually being liberalised and are set to reach around US$70/mcm in 2010 and US$90/mcm in 2011, up from around US$20/mcm in the early-2000s. Notable foreign assets include minority stakes in China’s West-East gas pipeline, and in phases 2 and 3 of Iran’s giant South Pars project.

In 2009, Gazprom’s production fell to 460bcm, according to preliminary government figures. This was the worst performance in the company's history, with the current low of 512bcm registered in 2001. In Q110, however, domestic demand began to recover, pushing up Gazprom's production figures. This led CEO Alexei Miller to announce a more ambitious target of 529bcm for 2010. In April 2010 he told Russian media that by 2013 the company expected to produce 565.5bcm, which would be a 13-year production high. Speaking at a news conference on June 9, however, Gazprom's gas and condensate departmental head, Vsevolod Cherepanov, said that from mid-May 2010 the company had begun to see a much sharper seasonal drop in demand than it had expected. Cherepanov said that the company has now revised its gas production forecasts. The company now expects to produce 519.3bcm in 2010, down roughly 10bcm on Miller's forecasts. He said that the company expects this to increase to 528.6bcm in 2011 and to 542.4bcm in 2012.

Strategy

By 2030, Gazprom wants to become a global energy player, reaching new markets with LNG and underwater pipelines. It wants to add 90mn tonnes of LNG capacity by 2030. At present Sakhalin-II is the only operational liquefaction terminal. With output at its mature Western Siberia fields in decline, Gazprom expects new generation projects in the Arctic (Yamal, Shtokman), East Siberia (Kovykta, Chayandinskoye) and the Far East (Sakhalin) to fuel future growth, accounting for half of its production by 2020. Gazprom also planned to supply about 25% of the world’s LNG needs by 2030, but that target was scrapped following the decline of the US import demand. By early-2010 Gazprom’s executives had acknowledged the need for a strategic overhaul owing to the negative impact of rising domestic US gas production. In December 2005, then deputy chairman Medvedev announced Gazprom's aim 'to gain more than 10% of the US market by 2010, increasing to 20% [at a later date]'. With US demand for gas imports on the wane, these targets are now looking decidedly unrealistic.

Having scuppered Gazprom's North American ambitions, the spreading 'shale revolution' is beginning to pose a threat to its core business closer to home. The first negative consequences are already being felt by the company, as LNG cargoes head for European ports having been turned away from the US. There is,

Russia Oil & Gas Report Q2 2011

however, a more fundamental threat in the making to Gazprom's position in the European gas market. Bolstered by the successful application of technological advances in hydraulic fracturing (fraccing) in the US and Canada, the oil majors are now eyeing European shale plays, moving into such unlikely gas producing destinations as Poland and Sweden. Should the European shale basins prove to be commercial, the competitiveness of Russian gas imports in the region will be seriously, and perhaps terminally, undermined.

The Yamal peninsula is believed to contain around 2.14bn bbl of oil plus 10.4tcm of gas. Although no firm project timetable has been set, Gazprom is aiming to start producing the first 15bcm of gas in Yamal by Q312 (a year later than originally expected) and then gradually boost volumes to 250bcm per year. The economic downturn, however, has forced the company to postpone investment in expensive new projects. In a setback for its resource nationalism agenda, Gazprom’s debt burden has led the company to express its readiness to reduce its stake in major projects, including Nord Stream and Shtokman, in return for increased funding from foreign partners.

In February 2009, Russian business daily Kommersant reported that in an attempt to cut costs, Gazprom may invest exclusively in projects that would be profitable at a Brent price below US$25/bbl, with an exchange rate of US$1/RUB36. Kommersant reported that planned investments had previously been based on US$50/bbl. The plan was swiftly denied by the company, which stressed that no concrete strategic decisions have been made. Despite denying the report, Gazprom’s high debt levels, which stood at some RUB1.7trn (US$56bn) in mid-2009, must be a concern for the company. The Russia-Ukraine gas dispute is also likely to have hit its bottom line by around US$1-1.5bn, as well as damaging EU confidence in Russian gas supplies.

The firm’s reported interest in UK gas supplier Centrica indicates a determination to gain greater control over its Western European customers, despite the assured political opposition to such a deal. Regardless of the rhetoric, Gazprom is committed to future European energy supplies through pre-existing contracts and infrastructure. In fact, most of Gazprom’s current export capability is geared towards Western Europe, and the cost of this network should ensure full usage through the long term. True, the Eurasian giant is busy courting the Asian market, but this relationship is in the very early stages.

Gazprom is intensifying its relations with Western Europe. The company confirmed in November 2007 that it is discussing long-term gas supply deals with several Italian utilities, including Enel and Edison. The news follows the 2006 agreement between Eni and Gazprom to extend supply contracts to 2035, which will allow the Russian company to sell gas directly to the Italian market. Gazprom has previously said that it plans to sell up to 3bcm of gas to Italy per annum from 2010. In March 2008, Gazprom announced that it may swap Russian upstream properties for some of Enel’s power assets. Meanwhile, January 2008 saw Gazprom announce plans to control 10% of the French gas market by 2012/13. In 2007 the company directly supplied France with only 500Mcm. The bilateral ties are certainly getting closer,

Russia Oil & Gas Report Q2 2011

with major French utilities EDF and GDF Suez close to getting a minority stake in the South Stream and North Stream pipelines respectively.

In November 2007, Gazprom announced plans to operate a natural gas entity in the US by 2014. While realising that the company will have to overcome regulatory barriers to enter the US market, it has said that it will use its economic strength to acquire assets.

Latest Developments

Corporate Gazprom has published its financial results for Q310 ending September 30 2010. The company reported revenue of RUB786.45bn (US$26.85bn) and net profit of RUB159.04bn (US$5.43bn). Revenue increased from US$684.21bn (US$23.36bn) in Q309, while profits were down 8.93% on the previous year. The somewhat disappointing results can be attributed to an increase in oil and gas purchase costs of 29%.

Gazprom’s 2010 capex rose despite the downward revision to the revenue target. In September 2010, the company's board approved an amended version of the 2010 budget, raising planned investment by 13% to RUB905bn (US$29bn). To some extent the injection of an extra RUB103bn of investment in 2010 reverses Gazprom's belt-tightening in 2009. In November 2009 Gazprom cut its 2009 capex by RUB216.5bn. Projects that were put on ice in the economic downturn are now gradually being defrosted. Extra investment in long-term projects such as South Stream and Algerian exploration also indicates Gazprom's broad strategic ambitions of defending its position in European gas markets.

In 2010 Gazprom has been facing pressures to reduce its European prices. One of Gazprom's largest customers, E.ON Ruhrgas of Germany, has reportedly asked for a fresh price cut in August 2010, only six months after receiving its first discount. Should E.ON succeed in gaining a concession, other European utilities are set to follow suit.

In February 2010 E.ON was among five major European utilities that obtained a price concession on a take-or-pay long-term supply contract with Gazprom. In E.ON's case, the German utility gained a right to buy 16% of its Russian gas imports through to 2012 at spot prices. In H110, Gazprom says it sold gas to Europe on long-term contracts for around US$300/mcm. Prices at UK's National Balancing Point (NBP), Europe's largest spot hub, averaged US$207/mcm in the same period, falling to as low as US$150/mcm in early 2010.

Fresh demands for discounts are a highly unwelcome development for Gazprom, which has been hoping for a steady European economic recovery to revive its flagging fortunes in its main market. In Germany in particular, Gazprom has been losing market share to Norway, and to a lesser extent the Netherlands.

Russia Oil & Gas Report Q2 2011

Over 2009 European companies have been talking with Gazprom to reduce the volumes of gas that they are committed to buying under long-term 'take-or-pay' contracts. With imported gas volumes remaining below levels agreed with Russia, European buyers are seeking to avoid penalties set out in the contracts by agreeing a reduction in gas purchases, as has recently been arranged between Russia and Ukraine. Citing an unnamed Gazprom source, Russian daily Kommersant stated that the first company due to pay according to the 'take-or-pay' contracts is Eni on January 18 2010, followed by Turkey's state-owned Botaş and German company E.ON. According to Kommersant, other companies affected are Germany's BASF and RWE, and France's GDF Suez and Total.

Gazprom announced the country's largest ever debt issuance on April 7 2010, in an attempt to raise US$10.2bn on Russia's bond market. The decision highlights Gazprom's attempts to take advantage of a highly active domestic bond market to restructure its long-term debt obligations. Gazprom instructed its banking arm, Gazprombank and Moscow-based Renaissance Bank to run the bond issue programme, which will comprise 13 issuances over a five-year period.

By July 2009 Gazprom was set to acquire a controlling stake in Kyrgyzstan's national gas company Kyrgyzgaz, following Bishkek’s approval of an agreement allowing Gazprom to participate in the company’s privatisation. Gazprom has apparently proposed buying a 75% plus one share in Kyrgyzgaz. The negotiations, however, are still in progress for unspecified reasons.

In November 2009, Gazprom sold to Germany’s E.ON Ruhrgas a 25% stake in Severneftegazprom, a Gazprom subsidiary and licence holder of the Yuzhno-Russkoye gas field in West Siberia. In return, Gazprom received from E.ON a 49% stake in Russia's Gerosgaz, which itself holds an almost 3% stake in Gazprom. Gazprom now owns 100% of Gerosgaz. E.ON’s direct 3.5% share in Gazprom has not been affected by the deal.

In June 2009, Gazprom and Statoil signed a three-year MoU on E&P in northern Russia and Norway, replacing a 2005 cooperation agreement signed with Statoil and Norsk Hydro prior to their merger. According to a joint statement, the new MoU will not only see the two companies work together in E&P but also design and development of technologies for the harsh Arctic environment. In December 2009, the companies deepened ties by signing another MoU on joint gas trade in the US.

Gazprom and Kogas signed a gas and chemical deal worth US$102bn in September 2008. As part of the agreement, Russia will supply South Korea with 10bcm of gas per year over a 30-year period from 2015.

In April 2009 Gazprom exercised its right to purchase a 20% stake in oil producer Gazprom Neft from Eni. Under the deal Gazprom will pay US$4.2bn for the stake. SeverEnergia, (at the time of the deal 60:40 owned by Eni and Enel) acquired equity in Gazprom Neft and a 100% stake in Western Siberia- focused gas companies ArcticGaz and Urengoil in April 2007 for RUB151.54bn (US$5.83bn) during a

Russia Oil & Gas Report Q2 2011

controversial liquidation auction of Yukos assets. As part of the deal, Gazprom secured an option to buy a majority stake in the gas assets and the shares in Gazprom Neft before April 9 2009 for around US$4bn. At the time, the deal seemed in Gazprom's favour as it was believed to undervalue Gazprom Neft. The agreed US$4.2bn purchasing price is equal to the price paid by Eni, plus interest, although it is significantly above 20% of Gazprom Neft’s valuation at the time that the deal went through (US$2.2bn). The economics of the deal are perplexing, highlighting the deal’s marked political undertones.

Gazprom moved to finalise the acquisition of majority stakes in ArcticGaz and Urengoil in September 2009. Gazprom farmed in a 51% into SeverEnergia for US$1.6bn, leaving Eni and Enel with 29.4% and 19.6% respectively. Eni claims the consortium’s licences hold an estimated 5bn boe of reserves. It aims to launch the Samburskoye field by June 2011, with output expected to reach 150,000boe/d by 2013.

Gazprom said in November 2008 that it was considering US majors Exxon and Conoco as potential partners in its Yamal LNG development. One option being looked at is a swap agreement, through which Conoco could be granted access to the Yuzhno-Tambeisky gas deposits in Yamal in return for Gazprom's joining projects in Alaska. Should a deal of this kind go ahead, it would mark a significant step forward in Gazprom's North American expansion plans.

Projects Gazprom's Board Chairman Viktor Zubkov announced in March 2011 that work on the Shtokman gas field offshore Russia in the Barents Sea is on schedule. The US shale gas developments will not result in any change in its investment plans, Zubkov told reporters in Oslo, following his meeting with the trade minister of Norway, Trond Giske. The components of the investment decision are scheduled to be revealed in 2011, said Zubkov. The Chairman's comments came after media reports that the Shtokman project was facing further delays to 2018.

In March 2011 Gazprom won the auction for TNK-BP subsidiary Rusia Petroleum, the licence holder of the Kovykta gas field. According to reports, the starting price was put at RUR15.1bn (US$525.5mn) and Gazprom bid RUR22.3bn (US$776mn) to secure the assets. This seems a low price when considering that the Kovykta field holds estimated reserves of 2tcm, under Russia's C1+C2 classification, making it one of the world's largest untapped conventional gas fields. However, according to Jonathan Muir, TNK-BP's CFO, quoted by Dow Jones, the company is pleased with the price, having invested US$675mn in Kovykta's development, it had aimed 'to get back what we've spent'.

Shell is considering offering equity stakes in its Asian assets to Gazprom as part of a deal to expand the Sakhalin-II LNG project, Bloomberg reported in February 2011. Shell is reportedly in the process of selecting overseas assets that could be offered to Gazprom for investment, including in 'areas of strategic interest' such as the Asia-Pacific region, one source said. The Anglo-Dutch major is attempting to convince Gazprom to add a third liquefaction train to the producing Sakhalin-II LNG project.

Russia Oil & Gas Report Q2 2011

Bloomberg’s sources evealed that Shell may also gain access to new blocks offshore Sakhalin Island in order to locate more feedstock gas to supply this train.

Gazprom launched test production from Russia's first coal bed methane (CBM) project in February 2010. The CBM production facility at the Taldinskoye coal field in the Kuzbass region of south-western Siberia is expected to produce up to 5bcm of gas per annum once fully online in 2011-2012. The gas will supply the industrial belt of western Siberia, lowering the share of coal in the regional energy mix.

Gazprom is re-evaluating its global expansion strategy in the light of falling US gas import demand. The unexpected growth of unconventional gas production in North America has torpedoed Gazprom's ambitious plans for exports to the world's largest gas consumer, raising questions over the future of the giant Shtokman development in northern European Russia. Following the announcement by Gazprom in February 2010 that first gas from the Shtokman project has been pushed back by three years to 2016, Russian news agency Prime-Tass has reported that the project’s consortium may be considering sending all of the field's gas by pipeline to European markets rather than exporting half as LNG, as previously envisioned. The news agency, citing documents from the consortium, reported that if the company fails to reach an investment decision on developing LNG at the project by the December 2011 deadline, gas would be transported via pipeline to Europe. The Shtokman Development Company (SDC) comprises Gazprom (51%), Statoil (24%) and Total (25%). An FID is due in March 2010.

Gazprom in October 2009 announced plans to bring forward the start of production at the Kirinskiy field in the Sakhalin-III project, potentially to fill the Sakhalin-Vladivostok pipeline. The field, which was initially expected to come onstream in 2014, is now scheduled to start in late-2011 or early 2012. The Kirinskiy field, discovered in 1992, is estimated to hold 75.4bcm of gas and 64mn bbl of condensate. In June 2009, the field was awarded to Gazprom, and exploration drilling started in July.

Gazprom petitioned the government in August 2009 to award it four new Yakutian permits – Srednetuginskoye, Tas-Uriahskoe, Coboloh-Nedzhelinskoe and Verhneviluchanskoe – because projected output at its Chayandinskoe Block alone would allegedly be insufficient to justify constructing a connector to the Sakhalin-Khabarovsk-Vladivostok pipeline, thereby connecting Yakutia to the expanding gas pipeline network on the Pacific coast. At the end of 2007, proven and probable reserves at the four new blocks stood at 462.6bcm of gas (based on Russia’s A, B and C1 classification). Although Gazprom did not disclose its output projections for Chayandinskoe, CEO Miller stated that the high helium content of the block's gas would require the construction of an expensive processing plant. Gazprom planned to bring the block onstream in 2016, the same year it plans to finish the construction of the Yakutia- Khabarovsk interconnector. The 6,000km pipeline has a design capacity of 32-35bcm per annum and aimed at eventually enabling exports of Yakutia’s gas from coastal LNG terminals.

Russia Oil & Gas Report Q2 2011

By mid-2009 Gazprom had already been awarded 14 blocks in eastern Russia without a competitive tender. According to Vedomosti, Gazprom paid around RUB11bn for the blocks, which have combined reserves of 6.29trn of gas and 8bn bbl of condensate. Apart from its petition for four new Yakutia blocks, Gazprom asked the government for tax holidays and/or export duty exemptions for its eastern projects. The newspaper’s government sources claim Putin overall supported Gazprom's suggestions.

Whether Gazprom has the need or the capacity to develop the new Yakutia permits is in question. In 2004 Gazprom estimated Chayandinskoe’s reserves at 1.24tcm, over half of Yakutia’s total, and more than sufficient for the planned pipeline to the Pacific. Moreover, the impact of the recession on Gazprom's finances has already forced the company to freeze several high-profile projects in the east and north of the country. In the current circumstances, Gazprom would find it difficult to fund the development of Chayandinskoe, let alone the four new Yakutia blocks it has asked for. The concessions are therefore likely to be idled for years to come.

According to Vedomosti’s report in July 2009, wholly state-owned Rosneftegaz may replace Gazprom in the ownership talks for the giant Kovykta field in the eastern Irkutsk region. Nominally, the majority stakeholder in the project remains TNK-BP, but as a result of pressure from the energy ministry, for the past two years the Anglo-Russian company has been negotiating the sale of its stake to Gazprom. The MoU on TNK-BP’s sale of its interest in the Kovykta operating vehicle, Rusia Petroleum, to Gazprom was signed in June 2007. In pushing for the sale, the Kremlin focused on TNK-BP's failure to raise gas output at the project to the 9bcm required by the terms of the contract. This was based on the assumption that the Irkutsk authorities would comply with their part of the contract, building the required downstream infrastructure to channel Kovykta’s gas to local end-users. Irkutsk has failed to do this: the utilised gas output at the field is by early 2009 was an annualised 30Mcm.

TNK-BP's inability to raise production led the Russian subsoil agency, using somewhat perverse logic, to threaten to withdraw the Kovykta licence. It was thought that once Gazprom took the reins, the company would be likely to alter contract terms to allow exports outside Irkutsk, with the eventual aim of constructing a gas pipeline to China. It now appears, however, that Kovykta has become the latest major gas development to be shelved by Gazprom as a result of the recession. Officials at the company told Kommersant that given the current demand conditions, Gazprom would prefer to concentrate on cheaper and lower-risk projects, adding that they were 'indifferent' towards Kovykta.

Previously, Gazprom intended to begin large-scale development at Kovykta by 2017. The planned transfer of its interests to a holding company implies that even this date could be optimistic. Rosneftegaz, chaired by the Vice-Prime Minister Igor Sechin, has never participated in any active operations, suggesting the project will remain frozen for years to come. Although Gazprom confirmed talks with Rosneftegaz on the Kovykta transfer, Kommersant's sources stated that no final decision had been made.

Russia Oil & Gas Report Q2 2011

In BMI's view, even if Gazprom divests Kovykta at this stage, its monopoly on Russia's gas export means it will re-enter the project when the economics of the projects are deemed to be sufficiently favourable.

Gazprom announced in June 2009 that it was indefinitely delaying the construction of a gas pipeline to China after the two countries failed to come to a gas price agreement. Russia and China have been in negotiations over gas exports since 2006, but their inability to resolve the differences resulted in the ambitious pipeline project, which was to transport some 30bcm of gas from 2011 and up to 85bcm at a later stage, being frozen. While Russia may previously have held the upper hand in negotiations, thanks to its vast gas reserves and China's rapidly rising demand, Beijing is now benefiting from major new gas import deals with Kazakhstan, Turkmenistan and Myanmar.

In May 2009, Gazprom boosted the annual budget for the Sakhalin-Vladivostok pipeline to RUB50bn (US$1.6bn). The 1,830km pipeline is due onstream in Q311. Gazprom is also considering building an LNG export terminal and a petrochemical facility near Vladivostok. The pipeline will link two major projects offshore Sakhalin Island that are currently onstream, Sakhalin-I and -II, to the mainland. The section to Khabarovsk is already operational. Initially, Sakhalin-I's gas supplies will be used to feed local demand. In the same month Gazprom announced that it was set to buy 20% of gas produced from the Exxon-operated Sakhalin-I, according to media reports. Tensions between Exxon and the Kremlin have been high owing to a disagreement over marketing rights for gas from the project, with Exxon wanting to export the gas directly at (higher) international prices and the Kremlin wanting Gazprom to buy all of Sakhalin's I gas at (lower) domestic prices.

Gazprom and its German partner Wintershall have brought onstream the Achimgaz project in July 2008. The US$1bn, 50:50 Achimgaz JV in Yamal is to produce nearly 1bcm of gas per annum and 6,000b/d of condensate. The project’s lifespan is 40 years.

Gazprom announced in September 2008 plans to invest RUB23.5bn in constructing a new gas pipeline in the Far East. The pipeline will connect the Sobolevskoe deposit with the capital of the Kamchatka region, Petropavlovsk-Kamchatsky, and is due onstream in 2010. While it will be designed to supply the domestic market, in the longer term it may also be used to connect remote gas reserves to the country’s export infrastructure.

Russia Oil & Gas Report Q2 2011

Gazprom Neft

Company Analysis Address Gazprom Neft Sadovnicheskaya Street 4 Already the dominant force in the Russian energy sector, Gazprom’s attempts 113035 Moscow to become a major oil player paid off in 2005 with the acquisition of Sibneft. Russia Now re-christened Gazprom Neft, Sibneft was due to have merged with Tel: +7 (495) 777 3152 Yukos to form one of the world’s leading oil producers. The collapse of the Fax: +7 (495) 777 3151 www.gazprom-neft.com deal during the Yukos crisis, however, made an eventual link with another player inevitable. Gazprom’s move denied Western companies the chance to Financial Statistics acquire a well managed, profitable business – but has given the gas giant a Revenues: major opportunity to develop oil expertise. US$24.17bn (2009) US$33.08bn (2008) SWOT Analysis US$21.77bn (2007) US$20.18bn (2006) Strengths: Significant role in Russian oil supply Net income: US$2.77bn (2009) Cost-effective producing assets US$4.66bn (2008) Substantial domestic refining business US$4.14bn (2007) US$3.66bn (2006) Strong retail portfolio

State support Operating Statistics Net oil production (inc. equity entitlement) Weaknesses: Lack of foreign partners 957,000b/d (2009) Rising investment requirement 932,000b/d (2008) 868,700b/d (2007) Some cost and efficiency disadvantages 657,000b/d (2006) Opportunities: International expansion Refining throughput Focus on under-explored Russian regions 670,700b/d (2009) Cost cutting/asset upgrading potential

Threats: Sustainability of Russian oil growth

Oversupply in CEE refining capacity

Competition with Rosneft

Russia Oil & Gas Report Q2 2011

Market Position

Gazprom Neft was founded as Sibneft in 1995 and took on a broad portfolio of former state assets. Following two failed merger attempts with Yukos in September 2005, Gazprom acquired 72% in Sibneft, buying out businessman Roman Abramovich’s stake in a US$13bn deal, raising its stake to 95.7% after exercising its buy-out right in April 2009. The company was then renamed Gazprom Neft. It is now the fifth largest crude producer in Russia and has one of the best growth rates, owing to its strong position in high-potential regions. Gazprom Neft’s upstream assets are chiefly located in the Northwest and Western Siberia (Yamal-Nenets, Khanty-Mansiysk, Omsk, Tomsk, Tiumen), as well as Irkutsk and Chukotka further east. The main production arm is Noyabrskneftegaz, which operates about 30 fields in the Yamal-Nenets and Khanty-Mansiysk autonomous regions and holds around 60% of the company’s reserves.

Other major producing assets include stakes in Slavneft and Tomskneft, jointly owned with TNK-BP and Rosneft respectively. As of Q309 Gazprom Neft also has managerial control of Sibir Energy, which it won after significant effort. Sibir's upstream operations are focused on Khanty-Mansiysk where it holds the Salym fields, operated on a 50:50 basis with Shell, and the Yuzhnoe and Orekhovskoe fields, operated by subsidiary Magma Oil (95%). In 2009, Sibir’s net output averaged around 80,000b/d.

Gazprom Neft’s refining and market assets include the 385,000b/d Omsk Refinery and a 60% vote in the 240,000b/d Moscow Oil Refinery, as well as a growing network of service stations primarily located in Western Siberia, although Sibir’s acquisition has given it a strong position in Moscow. Through its wholly owned unit Moscow Oil and Gas Company (MOGC), Sibir owns 100% of 69 MKT-branded service stations, 51% of Mosnefteproduct's 64 stations and storage terminals and 25% of BP's Moscow retail network.

The company is involved in the planned 1mn b/d Burgas-Alexandroupolis pipeline, which will transport Russian crude to Europe and is preliminarily scheduled for completion in 2010. Gazprom Neft also works on the Northern Zadegan project in Iran.

Strategy

Gazprom Neft plans to produce 1.8mn b/d by 2020 through developing Arctic fields and investing US$70bn. Gazprom Neft expects to receive the licence to develop the Arctic Prirazlomnoye deposit by 2010 and plans to start work at the giant offshore field five years later. Downstream, the company plans to raise refining capacity until it accounts for two-thirds of crude production. It will achieve this goal by purchasing refineries at home and abroad, and is particularly interested in buying more European assets after in February 2009 acquiring 51% of Serbia’s Naftna Industrija Srbije (NIS).

Russia Oil & Gas Report Q2 2011

Latest Developments

Gazprom Neft was awarded rights to develop the Novoportovskoye and Orenburgskoye East oil fields from parent Gazprom in December 2009. Novoportovskoye and Orenburgskoye East fields hold around 1.7bn and 700mn bbl of oil reserves respectively.

In December 2009, Gazprom Neft signed a deal to acquire Sweden-based Malka Oil’s subsidiary STS- Service for US$118mn. STS has three licences in the Tomsk region with combined oil and condensate reserves of 189mn bbl (C1+C2). The deal has yet to be approved by Malka’s shareholders.

Gazprom Neft gained majority ownership of mid-sized domestic producer Sibir Energy in June 2009 after acquiring 50% of investment company Bennfield. Having bought the assets of Bennfield's joint owner Igor Kesaev, Gazprom Neft acquired indirect ownership of 23.35% of Sibir's shares, bringing its total stake in the AIM-listed firm to at least 54.7% (following a series of opaque deals with various previous shareholders, 2.3% of Sibir’s shares are unaccounted for). Gazprom Neft consolidated Sibir into its financial accounts and manages the company in partnership with the Moscow city council (19.3%). In late-September 2009, Gazprom Neft petitioned the Russian competition authorities to acquire 100% of Sibir, adding that it expects an answer soon. Whether it was able to come to an agreement with the remaining shareholders, particularly the Moscow council, which in mid-2009 indicated its intention to raise its Sibir stake, remains unclear.

Since having trumped a rival bid from TNK-BP in late April 2009, Gazprom Neft has bought out Sibir’s floating shares and some of its major investors, spending a combined US$1.67bn on the deals. The ownership of the other 50% of Bennfield (and therefore 23.3% of Sibir) remains disputed by its owners. The outstanding Bennfield shares are currently held as collateral by state-owned Sberbank, pending payment of its outstanding debts.

Gazprom Neft’s deputy director, Boris Zilbermints, said in December 2008 that the company may be looking for foreign partners to develop the Prirazlomnoye oil field in the Barents Sea. Gazprom’s subsidiary Sevmorneftegaz previously reneged on its intentions to bring in foreign participants and stated plans to develop the field on its own. Gazprom is currently constructing an offshore production platform at Prirazlomnoye, which is expected to be completed by late-2010 or early-2011. Gazprom plans to hand over the field, along with a number of other licences, to Gazprom Neft in 2009/10. Prirazlomnoye, which holds estimated oil reserves of 600mn bbl, is expected to produce 120,500b/d.

In December 2008, CEO Alexander Dyukov has also made an offer to Chevron to develop more fields in western Siberia. Gazprom Neft and Chevron formed a JV in 2007, Northern Taiga Neftegaz, to explore for and develop assets in the Yamal-Nenets region.

Russia Oil & Gas Report Q2 2011

Rosneft

Company Analysis Address Rosneft 26/1 Sofiskaya Rosneft’s Yukos acquisitions turned the company into Russia’s largest oil 115998 Moscow producer, surpassing private rival Lukoil, and extending state control to some Tel: +7 (495) 777-44-22 Fax: +7 (495) 777-44-44 40% of Russian production. In addition, the company has also become www.rosneft.com Russia’s largest refiner. Rosneft is largely state-owned, although a 2006 IPO has introduced an element of privatisation that the recession-hit Russian Financial Statistics government in late-2009 pledged to deepen. Gazprom and Rosneft in Revenues: November 2006 agreed a strategic cooperation deal that should see them US$63.05 (2010) share major development opportunities, rather than fighting over them. US$46.83 (2009) US$68.99bn (2008) SWOT Analysis US$49.22bn (2007) Net income: Strengths: Largest domestic oil producer US$10.67(2010) Strong relationship with government US$6.52(2009) US$11.1bn (2008) Large fuels retail network US$6.5bn (2007) Portfolio of CEE downstream interests Operating Statistics Weaknesses: Complex corporate structure Oil production: Inherited high cost base and inefficiency 2.32mn b/d (2010) 2.18mn b/d (2009) Opportunities: Growth in Russian oil production 2.13mn b/d (2008) Rise in CEE regional oil consumption 2.0mn b/d (2007) Gas production: Expansion into Chinese downstream market 12.7bcm (2009) Long-term gas export opportunities 12.4bcm (2008) 15.7bcm (2007) Threats: Sustainability of Russian oil growth 13.6bcm (2006) Proven reserves (PRMS): Oversupply in CEE refining capacity 22.9bn boe (2009) Changes in national energy policy 22.3bn boe (2008) 21.7bn boe (2007) 11.8bn boe (2006)

Russia Oil & Gas Report Q2 2011

Market Position

Rosneft’s 19 E&P subsidies cover most of the Russian regions, but around 80% of its production comes from Western Siberia (Yuganskneftegaz and Purneftegaz) and the Volga region (Samaraneftegaz). Rosneft owns and operates seven major refineries in Russia: the Tuapse refinery on the Black Sea coast; the Komsomolsk refinery in the Russian Far; the Kuibyshev, Novokuibyshevsk, and Syzran refineries in the Volga-Urals region; and the Achinsk and Angarsk refineries in East Siberia. The company is also planning to construct a new 240,000b/d facility in Primorsk in Leningrad Region with Surgutneftegaz. Rosneft also runs export terminals in Arkhangelsk, Tuapse, Nakhodka and De-Kastri, and operates a retail network of around 600 service stations.

On January 14 BP announced its first mega-deal since the Macondo oil spill in 2010, joining forces with Rosneft in a ground-breaking US$16bn share exchange and joint exploration initiative. The two sides signed an agreement for the joint exploration of three blocks the South Kara Sea in the Russian Arctic, which is considered highly prospective. Under the share swap, the Russian company agreed to take a 5% stake in BP, while BP in return will receive a 10% stake in Rosneft. The deal would add to BP's existing 1.2% stake in Rosneft, which it acquired for US$1bn at a partial IPO in 2006. With TNK-BP resolutely opposing the deal, however, it is not yet clear whether it will be able to go ahead.

Strategy

Over the next two decades, Rosneft aims to become Russia’s leading energy company both in output and financial terms. To achieve this it is pursuing several policies. The company plans to increase crude production by exploiting existing oil reserves, with the goal of reaching 2.8mn b/d by 2015 and 3.4mn b/d by 2020. Rosneft also aims to exploit upside potential in gas. Rosneft believes itself to be capable of producing 40bcm by 2012, but the volumes will depend on gas sales and access to UGSS capacity, regarding which Rosneft is currently negotiating with Gazprom. The company is also developing value chains linking upstream assets directly to export markets and refining facilities. Ownership or a significant equity share in marketing subsidiaries will allow Rosneft to maximise netbacks.

Under the 2010 business plan, Rosneft is planning capex of RUB217bn, equivalent to US$7.23bn using the exchange rate applied by Rosneft. The figure is the same as the investment originally envisioned for 2009. In February 2009, however, capex for that year was subsequently boosted to RUB227.85bn. Of the 2010 capex target, US$2bn will go on the refining segment, a 150% rise y-o-y. In June 2007, Rosneft then CEO Sergei Bogdanchikov announced plans to expand the company's refining capacity ninefold by 2015. Rosneft is planning to boost output in 2010 by 4.5% to 2.36mn b/d on the back of new start-ups in East Siberia.

Rosneft confirmed to investors in February 2011 that it wants to play a bigger role in the country's gas export business. In particular, the company is eyeing gas exports from the West Siberian Kharampur and

Russia Oil & Gas Report Q2 2011

the East Siberian Vankor fields to China, according to Pavel Fyodorov, a senior company official. The comments come after the company's CEO, Eduard Khudainatov, told reporters in September 2010 that the company would enter talks with Gazprom over joining long-delayed plans to export Russian gas to the Chinese market.

In June 2007, Bogdanchikov said the company plans to issue bonds to reduce debt and expand refining capacity ninefold. He further said that the company may build new oil refineries abroad, potentially in China and in other East Asian countries, to meet its refining capacity target by 2015.

Latest Developments

According to a February 2011 press release, Rosneft's revenues rose by 35% in 2010 to US$63.05bn, while net income rose by 63.7% to US$10.67bn. Oil production increased by 6.4% from 2.18mn b/d in 2009 to 2.32mn b/d in 2010, although total hydrocarbons production rose only 5.7% in boe terms to 2.52mn boe/d. Capex also increased from US$7.25bn in 2009 to US$8.93bn in 2010, while net debt fell by more than a quarter from US$18.5bn to US$13.7bn.

Rosneft joined forces in January 2011 with US major ExxonMobil to explore for oil and gas in the Russian section of the Black Sea. An agreement at the World Economic Forum in Davos on January 27 paves the way for the creation of a joint operating company that will focus initially on exploration and development activities in the Tuapse Trough, an 11,200sq km deepwater area off Russia's Black Sea coast. Rosneft officials told Reuters that Exxon would invest the initial US$1bn and the venture would be owned 50:50 at the exploration stage, with Rosneft taking two-thirds ownership of the venture at the production stage.

Rosneft has announced a 64% rise in profits in 2010, largely on the back on increased production from fields such as Vankor and Verkhnechonsk. Rosneft's revenues rose by 35% in 2010 to US$63.05bn, while net income rose by 63.7% to US$10.67bn. Oil production increased by 6.4% from 2.18mn b/d in 2009 to 2.32mn b/d in 2010, although total hydrocarbons production rose only 5.7% in barrels of oil equivalent (boe) terms to 2.52mn boe/d.

Rosneft approved projects to build two new refineries at opposite ends of the country at a board meeting on November 29. The first, 20,000b/d plant will be built in Chechnya and will be the region's first refinery since the Chechen war in 1994. The second plant, a 200,000b/d integrated refinery and petrochemicals plant will be built at Nakhodka in the Primorsky region. This second plant will expand Rosneft's presence in Russia's Far East and will process ESPO crude.

A company press statement on September 6 2010 said First Vice-President Khudainatov has been appointed president of Rosneft with immediate effect. Khudainatov's previous roles have included a spell

Russia Oil & Gas Report Q2 2011

at the Executive Office of the Russian president, as well as the position of general director of Severneftegaz. He replaced Bogdanchikov, who had been in charge since 1998. According to an FT report on September 4, Bogdanchikov is believed to have been at odds with company chairman and Deputy Prime Minister Igor Sechin. An unnamed FT source said that Khudainatov was less likely to adopt positions that conflicted with those of Sechin. Khudainatov's managerial background at Severneftegaz, a Gazprom subsidiary, has prompted speculation that Rosneft is looking to increase its exposure to Russia's gas industry.

Rosneft has made a significant discovery in the Irkutsk region in Eastern Siberia, according to a statement by the Russian energy ministry in January 2009. The discovery holds 1.2bn bbl of oil (C1+C2). The discovery was made at the Sevastyanovo field in the Mogdynskiy Block, which Rosneft acquired in 2006 for RUB1.32bn (US$44mn). No further details have been released, and Rosneft has not yet commented on the discovery.

Sinopec and Rosneft are considering building a 400,000b/d refinery in the Far Eastern Primorsky Krai region, the Chinese company’s chairman, Su Shulin, said in October 2009.

Russia Oil & Gas Report Q2 2011

Lukoil Company Analysis Address Lukoil is the leading private Russian oil company and should remain Lukoil Oil Company 11 Sretenski Boulevard so – particularly now that ConocoPhillips is on board as a strategic 101000 Moscow investor and upstream partner. Domestic volume growth is beginning Tel: +7 (495) 927 4444 to slow, but new projects, such as the Yuzhnoye Khylchuyu field in Fax: +7 (495) 916 0020 the Timan-Pechora region and fields in Uzbekistan and Iraq, provide www.lukoil.com growth potential. The downstream portfolio is also benefiting from Financial Statistics international investment, putting Lukoil into a position of secure Revenues medium- and long-term revenue and earnings expansion. US$81.5bn (2009) US$107.7bn (2008) SWOT Analysis US$82.2bn (2007) Strengths: Leading role in Russian oil supply US$68.1bn (2006) US$56.2nn (2005) Rising share of Caspian production Net income Substantial domestic downstream business US$7.0bn (2009) US$9.1bn (2008) Strong portfolio of CEE downstream interests US$9.5bn (2007) Conoco strategic partnership US$7.5bn (2006) US$6.4bn (2005) Weaknesses: Slower domestic growth than other producers Operating Statistics Rising investment requirement Net domestic oil production (inc. Cost and efficiency disadvantages equity shares): 1.84mn b/d (2009) pportunities: Growth in Russia/Caspian oil production O 1.93mn b/d (2008) Rise in CEE regional oil consumption 1.95mn b/d (2007) Net domestic sale gas production: Cost cutting/asset upgrading potential 6.3bcm (2009) Massive Iraq development 8.7bcm (2008) 8.2bcm (2007) Threats: Sustainability of Russian oil growth Refining throughput (group total):

Oversupply in CEE refining capacity 893,000,000b/d (2009) 894,000b/d (2008) Changes in national energy policy 976,000b/d (2007) Proven oil and gas reserves: 17.5boe (2009) 19.3bn boe (2008)

Russia Oil & Gas Report Q2 2011

Market Position

Russia’s largest private crude producer, Lukoil, had been in competition for the top spot with Yukos prior to the latter’s liquidation. Lukoil now accounts for 18% of Russian oil production and 18.3% of refining throughput, while boasting 1.3% of world oil reserves and 2.1% of global production. The bulk of the company’s E&P assets are located in West Siberia, with smaller reserves in European Russia, Nenets (Timan-Pechora) and the North Caspian regions. Lukoil holds stakes in E&P projects in Azerbaijan, Kazakhstan, Uzbekistan, Egypt, Saudi Arabia and Colombia as well a contract for the second phase of the giant West Qurna oil field in Iraq.

ConocoPhillips bid for a minority Lukoil stake in 2004, subsequently raising its interest in the company to 20% at a combined cost of US$7.5bn. Lukoil and Conoco also created the 70:30 Naryanmarneftegaz JV to develop the Yuzhno-Khylchuyu field in the northern Nenets region. Production began in mid-2008, with output expected to peak at 150,000boe/d. Lukoil’s relationship with Conoco appeared to be weakening in March 2010 when the US company informed Lukoil of its plans to sell half its 20% stake in the Russian producer as part of a US$10bn divestment programme.

Internationally, the company has refining assets in the Netherlands, Italy, Ukraine, Romania and Bulgaria, and retail networks in the US and most Eastern European and CIS states. International operations account for over 30% of Lukoil’s total refining capacity, 60% of its retail network and 4% of the resource base.

Strategy

Lukoil has curtailed its growth ambitions for the 2010s under its new 2010-2019 strategic development plan that was outlined in December 2009. The company will reduce annual capex to US$0.9bn from US$1.2bn envisioned under the previous 10-year plan (2007-2016), until it better understands the impending 'revolutionary changes' in the oil and gas industry, said Vice-President Leonid Fedun.

The biggest change in the 2010-2019 plan is a major reduction in upstream spending and output targets. Capex on E&P will total US$60bn, 20% less than the target in the previous 10-year plan (2007-2016). Consequently, Lukoil now expects oil production to reach only 2.7mn b/d by the end of the coming decade, significantly below the 4mn b/d previously envisioned for end-2016. Furthermore, the company is increasingly pessimistic over output prospects from its maturing fields. The new plan raises the upstream capex earmarked for new generation projects from 39% to 57%, while investment in West Siberia and Volga/Urals will fall by 30% in comparison with the old scenario.

The gas segment has also lost its shine for Lukoil. Fedun believes the impending 'acute glut' of global gas supply will exert strong downward pressure on prices and will hurt the profitability of its non-associated projects. Consequently, Lukoil will postpone gas developments in the Caspian and Yamal, previously

Russia Oil & Gas Report Q2 2011

seen as some of its main growth regions. The new plan sees the share of gas in total production rising from 10% in 2009 to 26% by 2019, against 33% previously envisioned for 2016.

In the downstream segment, Lukoil has also significantly reduced its planned expansion. The company hopes to achieve 1.45mn b/d of refining throughput by 2019, much less than the 2mn b/d envisioned under the previous plan. Capex on refining, power generation and petrochemical divisions will amount to US$25bn, with 78% of that figure earmarked for domestic projects. The investment will be channelled into upgrades and efficiency measures rather than capacity expansion.

The new plan suggests Lukoil may curb its foreign downstream asset buying spree, which saw the company acquire more than US$4bn of refining and fuel retailing assets in 2007-2009, culminating in the payment of US$725mn for a 45% stake in a Dutch refinery from Total in September 2009. Rumours have been circulating that Lukoil may be interested in more European refining assets that the French major is considering selling, but the new downstream budget certainly leaves little scope for large purchases. The company's growth strategy for retail networks in Turkey and Eastern Europe may also be affected. Having reduced its capex, Lukoil will use the freed-up funds to concentrate on improving profitability and cash flow and raising dividends. The new emphasis on caution and shareholder returns mirrors that of its partner Conoco and goes against the generally resurgent mood of the oil industry.

Under legislation passed in 2008, offshore fields in Russia, excluding the Caspian Sea, can only be developed by companies in which the government owns a stake of 50% of greater and which have a five- year record of working on such projects, effectively limiting participation to Gazprom and Rosneft. Although recent Black Sea deals with US majors Chevron and ExxonMobil suggest that minority stakes can now be farmed out to private partners, the law excludes privately owned Lukoil from operating in the Russian Black Sea, forcing it to look elsewhere, including offshore Romania and Ukraine.

Latest Developments

In March 2011 Lukoil signed an agreement with Gazprom to supply natural gas from the Caspian Sea and West Siberia. Under the agreement, Lukoil will supply 8.35bcm of gas from its Bolshekhetskaya field to Gazprom's 160,000km gas pipeline network starting in 2012.

In February 2011 Lukoil strengthened its overseas refining portfolio through the acquisition of an additional 11% stake in ERG’s ISAB refinery. By increasing its stake to give it a controlling interest in the company, Lukoil has demonstrated that it is committed to building up a network of high-complexity refineries in Europe and Russia.

Lukoil has secured a long sought-after tax break for its North Caspian projects in a move that should boost investment in the high-potential region. According to Russian news agency Interfax, on September

Russia Oil & Gas Report Q2 2011

23 2010 the Kremlin approved a reduction of export duties on Caspian oil, without specifying the exact amount. Earlier in September 2010 Russian energy minister Sergei Shmatko said the discount will be the same as those seen in the East Siberian fields. According to a July 2010 report in Russian business newspaper RBK, the alignment of Caspian export duties with those in East Siberia would save Lukoil US$460mn in 2011.

In November 2010 Lukoil sold US$1bn worth of dual-tranche notes due in 2020 to fund general corporate expenses. The company sold notes worth US$800mn at a price of 99.081% of their face value. The second tranche of notes, valued at US$200mn, was issued at a price of 102.44% of their face value. The funds will also be spent to repay the company's debt.

US major Conoco decided to sell its entire 20% stake in Lukoil in mid-2010. The company sold 7.6% back to the company for US$3.4bn in Q310, and the remaining 60% will be sold on the open market by end-2011.

Lukoil reported revenues of US$23.9bn and net income of US$2.05bn in Q110. Revenues increased from US$14.75bn in Q109, while profits were up 126.9% on the previous year.

In April 2010 Lukoil brought the first oil field in the Russian sector of the Caspian Sea onstream with the launch of production from the Yuriy Korchagin deposit. Korchagin is one of Lukoil's six large discoveries in the Caspian, touted as one of Russia's new oil and gas frontiers.

In December 2009, Lukoil gained full control of the LukArco vehicle after buying out its partner BP for US$1.6bn. The deal gives Lukoil a 12.5% stake in the Caspian Pipeline Consortium (CPC), a trunkline running from western Kazakhstan to Russian ports, and a 5% stake in the giant Tengiz field in Kazakhstan.

Lukoil was planning to launch the Yuri Korchagin field in Russia’s sector of the Caspian Sea in early- 2010. The field holds 570mn boe of possible (P3) reserves and is expected to produce 50,000b/d of oil and 1bcm of gas at its peak. Yuri Korchagin is one of the six large fields discovered by Lukoil in the Russian sector of the Caspian Sea since entering the area in 1995. To date, Lukoil boasts 100% exploratory drilling success in the Caspian, making it one of the high-growth potential regions for the company. In September 2009 Lukoil provided an update for its North Caspian project, announcing plans to produce 200,000b/d of oil and 6bcm of gas per annum by 2016. This is significantly below Lukoil’s previous announcement made in April 2009, which put the North Caspian target at 260,000b/d and 14bcm by 2016. The April 2009 announcement called for RUB390bn (US$16.6bn) of Caspian investment.

Russia Oil & Gas Report Q2 2011

After Korchagin, the second field, the larger Filanov (Filanovskoe), is due onstream in 2014. Gas output from Korchagin and Filanov will be pumped to the Russian region of Kalmykiya and then onwards to Gazprom’s trunklines. Development of the mostly gas-bearing Khvalynskoe deposit on the Kazakh maritime border is carried out under a PSA held by the Caspian Oil and Gas Company consortium comprising Lukoil (50%), state-run KazMunaiGaz (KMG, 25%), and French companies Total (17%) and GDF Suez (8%). Khvalynskoe is expected to peak at 8bcm and is preliminarily due onstream in 2016. The North Caspian fields are located relatively close to Lukoil’s refineries including plants at Odessa (Ukraine), Bourgas (Bulgaria) and Ploieşti (Romania).

In June 2009, a state-run Russian financial institution acquired a stake in Lukoil. The companies did not comment on the size of the stake and the terms of the deal, but unnamed sources have told Reuters that the stake is less than 5%.

Lukoil and Transneft have allegedly approached Polish refiner PKN Orlen over buying a stake in Lithuania's Mažeikių refinery, Polish media reported in April 2009. PKN’s trumping of Russian bids for a controlling stake in Mažeikių in 2006 coincided with Transneft’s decision to shut down the refinery's feedstock pipeline owing to apparent technical problems.

One of the company's most high-profile foreign deals, the purchase of a 10% stake in Spanish-Argentine company Repsol YPF, fell through in late 2008 after the Spanish government appeared to implicitly blocked the deal as a result of popular opposition.

Russia Oil & Gas Report Q2 2011

TNK-BP

Company Analysis Address TNK-BP 18/2, Schipok St. Following an acrimonious battle for control over TNK-BP during 115093 Moscow H108, BP and its Russian partners in September 2008 restructured the Russia Tel: +7 (495) 745 7846 board and top management, signalling a new chapter in the company’s Fax: +7 (495) 787 9642 history. More recently, efforts to form a close relationship with www.tnk-bp.com Rosneft have upset some board members, who believe BP’s Russian strategy should be developed using the TNK relationship, not through Financial Statistics a share-based alliance with Rosneft. A sound deal with the Russian Revenues: state-controlled group could provide the breakthrough BP needs to US$34.75bn (2009) establish a strong and politically efficient Russian business, so the US$51.9nn (2008) support of TNK is essential. US$38.6bn (2007) US$35.5bn (2006) US$30.0bn (2005) SWOT Analysis Net income: US$4.97bn (2009) Strengths: Major oil producer US$5.3bn (2008) Significant share of refining capacity US$5.3bn (2007) US$6.6bn (2006) Large fuels retail network US$4.7bn (2005) Portfolio of CEE downstream interests Operating Statistics Benefits of BP management/technology Oil production (inc. JVs): 1.68mn b/d (2009) Weaknesses: Complex corporate structure 1.45mn b/d (2008) Inherited high cost base and inefficiency 1.42mn b/d (2007) Gas production: Opportunities: Growth in Russian oil production 12bcm (2009) Rise in CEE regional oil consumption 11.6bcm (2008) 9.4bcm (2007) Cost cutting/asset upgrading potential Refining throughput (Russia): Long-term gas export opportunities 574,000b/d (2009) 675,000b/d (2008) Threats: Sustainability of Russian oil growth 778,000b/d (2007) Proven oil and gas reserves (PRMS) Oversupply in CEE refining capacity 11.67bn boe (2009) Changes in national energy policy 8.1bn boe (2008) 8.3bn boe (2007)

Russia Oil & Gas Report Q2 2011

Market Position

In February 2003, UK-based oil major BP and Russian financial companies Alfa Group and Access- Renova (AAR), the owners of TNK, agreed to a US$6.35bn merger of their Russian businesses. At the time the deal represented the single largest Western investment in post-Soviet Russia. BP later agreed to pay a further US$1.4bn to include AAR’s 50% interest in Slavneft in the new JV. TNK-BP is governed by a 10-member board, with representatives nominated equally by BP and AAR and decisions taken unanimously. AAR nominates the chairman and BP the CEO.

TNK-BP’s upstream assets are chiefly located in the West Siberia and Volga-Urals. The main gas producer is its Rospan wholly owned subsidiary, which produced 6.5bcm in the Nizhnevartovsk region in 2008. TNK-BP has four refineries in Russia and one in Ukraine, with a total nameplate capacity of 560,000b/d. The Saratov refinery in southern Russia can produce Euro-3 and Euro-4 gasoline, while the Ryazan refinery, in Central Russia, has had the technology to produce Euro-5 diesel since 2008. It also owns a retail network of 1,600 sites in Russia and Ukraine.

TNK-BP and BP have long had an acrimonious relationship. In September 2008, BP and AAR signed an MoU setting out a resolution to their six-month dispute over control of TNK-BP, signalling a breakthrough in a complex and acrimonious power struggle. Tensions between the two sides flared up again in January 2011 following a US$16bn BP/Rosneft share swap and exploration deal. AAR said that BP had committed to pursue its Russian interests solely through TNK-BP, and blocked a planned US$1bn additional dividend payment proposed at end-January, thus denying BP its US$500mn share. The TNK- BP board was due to rule on the deal, but BP boycotted the meeting, making it inquorate.

Strategy

TNK-BP approved a US$1.8bn investment plan for 2010-2012 in February 2010. The planned upstream spending is in line with its strategy of aggressively replacing its reserves each year. Of the total, around US$1.7bn (96%) is to be spent on the two upstream projects. The first involves the full field development and the establishment of regional infrastructure at the eastern part of the Uvat group of oil fields, while the second project is the further development of the Verkhnechonskoe oil field in East Siberia.

TNK-BP will be hoping that the investment in its upstream Siberian assets will help contribute towards its goal of replacing 100% of its production with new reserves each year. The company aims to spend around 80% of its total budget each year on upstream projects, with the focus on its core East Siberian and West Siberian regions. US$137mn has been earmarked to upgrade a diesel hydrotreater unit at the company's 130,000b/d Saratov refinery, as part of a US$1.3bn package outlined in October 2009 to enhance fuel quality from the company's refineries.

Russia Oil & Gas Report Q2 2011

In November 2010 TNK-BP announced plans to invest US$3.8bn to more than double gas production to 30bcm a year by 2020. The main thrust of TNK-BP's plan is to increase the utilisation of associated gas, the head of the company's gas division, Alastair Ferguson, told a press conference on November 22. In order to meet government requirements on associated gas introduced in 2009, the company has already achieved the government-set target utilisation rate of 85% ahead of the end-2010 deadline, and now needs to increase this to 95% by 2012. Ferguson said that to meet this target the company would invest US$1.8bn in associated gas, a move that would allow it to account for over half of the company's total gas production by 2020.

TNK-BP’s growing gas output is obliging the group to negotiate with pipeline monopoly Gazprom over the offtake of the extra volumes. TNK-BP has started signing long-term (three-year) contracts for the supply of gas to customers, according to the company in November 2007. The conclusion of long-term contracts with customers of TNK-BP requires guarantees of gas transportation by Gazprom. There have also been talks with Gazprom over the joint construction of a now-scrapped LNG project near St. Petersburg.

Latest Developments

In March 2011 TNK-BP announced that crude production at its Uvat project in western Siberia is expected to reach its peak of 10mn tpa, equivalent to about 216,000b/d, by 2015-2016. This is a year earlier than originally planned.

The three independent board members of TNK-BP have been asked to vote on whether BP can proceed with its landmark share-swap and Arctic exploration deal with Rosneft. The ongoing saga began on January 14 2011, when BP and Rosneft announced a partnership involving joint exploration of three Russian Arctic blocks in the South Kara Sea that were awarded to Rosneft in 2010. AAR objected to the deal, claiming that BP was obliged by the TNK-BP shareholders' agreement to pursue its Russian activities solely through its Russian joint venture. AAR filed for an injunction in London's High Court on January 27, which it received on February 1.

TNK-BP has published its financial results for Q310, which ended on September 30 2010. The company reported revenues of US$11.4bn and a net profit of US$1.45bn. Revenues increased from US$10.26bn in Q309, while profits were down 13.69% on the previous year. The decline in net profit has been attributed to the higher cost of shipping oil through the state-run Transneft pipeline system.

TNK-BP in July 2010 was in talks with unnamed banks over taking a US$700mn unsecured three-year loan, according to Reuters.

Russia Oil & Gas Report Q2 2011

On June 3 2010, TNK-BP announced that it had begun voluntary bankruptcy proceedings for its subsidiary Rusia Petroleum, the operator of the Kovykta field. TNK-BP initiated bankruptcy proceedings against Rusia after recalling its loans to the subsidiary in mid-May 2010. By end-Q110, Rusia's total debt stood at RUB11.4bn (US$367mn), according to company's financial report. Although the company did not state the preferred buyer for Russia’s assets, it is most likely that the Kovykta licence will find its way to government-connected firms.

In May 2010 the company said that it is planning to expand its premium-class bitumen production by 60% y-o-y. The move is in response to Russian legislation increasing the minimum lifespan of roads, which will boost demand for longer-life bitumen products. To contribute to the 60% growth target, TNK- BP aims for a 50% increase in production of its polymer-modified TNK Alfabit brand of premium bitumen from 24,000 tonnes in 2009 to 36,000 tonnes in 2010. TNK-BP claimed that using TNK Alfabit, which will be produced at its pilot plant in Ryazan, 250km south-east of Moscow, could extend the life of a road to seven-10 years from the current two to three years.

The Russkoye field, located in Russia's Yamal-Nenets region, holds an estimated 2.25bn bbl of oil reserves (international P3 classification). Discovered in 1968, the field remained undeveloped owing to the challenging climate and the lack of heavy oil processing technology. TNK-BP estimates the total cost of developing the field at US$4.5bn. Peak production is expected to be between 200,000b/d and 400,000b/d, depending on whether TNK-BP constructs facilities for blending the oil to allow it to be transported by pipeline.

TNK-BP is ramping up volumes at the Uvat project in the Tyumen region of West Siberia. In early- February 2009, its subsidiaries Tyumenneftegaz and TNK-Uvat brought onstream the Ust-Tegusskoe and Urnenskoe fields. According to TNK-BP's figures cited by Oil & Capital, output from the two new fields was expected to average 60,000b/d in 2009 and above 100,000b/d in 2010. The company expects to reach peak output of approximately 220,000b/d in 2015/16. The Ust-Tegusskoe and Urnenskoe fields will account for half of that figure, while the other half will come from smaller satellite fields that are yet to be developed. By end-2009, total investment in Uvat was set to reach RUB13bn.

TNK-BP entered the Uvat district in the early 1990s and has since discovered an estimated 1.47-1.61mn bbl of recoverable reserves (C1+C2) in its 13 licences in the area. There are currently 21 known fields in the Uvat project, the first of which, Kalchinsoe, entered production in 1993. Discoveries in 2007/08 included the Kosukhinskoe, Protozanovskoe, Secero-Kachkarskoe, Nemchinovskoe, Sredne-Keumskoe, A.Malyk, Yuzhno-Venikhyartskoe and Zapadno-Epasskoe fields. Uvat is set to become a cornerstone of TNK-BP's Western Siberian strategy, with the company planning to incorporate its assets in the neighbouring Omsk and Khanty-Mansiysk regions into the project.

Russia Oil & Gas Report Q2 2011

Russia's environmental watchdog Rosprirodnadzor has advised Rosnedra, Russia's subsoil agency, to withdraw the licence for the Kovykta gas condensate field from TNK-BP. A dispute over the field's development has been ongoing for years, with TNK-BP being pressured to sell its 62.8% stake to a state- owned company. In June 2007, an MoU was signed under which TNK-BP agreed to sell its interest in Rusia, the operator of Kovykta, to Gazprom. Talks over the sale broke down, however, and since July 2009 Gazprom seems to have put its interest in the field on the backburner as a result of the recession.

In the past Rosnedra has argued for the removal of the licence from TNK-BP thanks to the company's inability to raise production to 9bcm as required under the terms of the licence. However, this output target was based on the assumption that the Irkutsk authorities would comply with their part of the contract through building the required downstream infrastructure to channel Kovykta's gas to end-users. With Irkutsk having failed to fulfil its side of the contract, TNK-BP has not been unable to meet the contracted output targets.

Currently, TNK-BP holds 62.8% in Kovykta through its stake in Rusia Petroleum, whose other shareholders are Interros Resources (26%) and the Irkutsk government (11%). Kovykta's reserves are estimated at 2tcm (C1+C2). Viktor Vekselberg, one of the company’s Russian co-owners, announced in June 2009 that the sale of Kovykta could be imminent and the government was close to including Kovykta in Gazprom’s investment programme.

TNK-BP in August 2009 announced plans to construct a new 450Mcm gas processing plant at the Pokrovskoe oil field in the Orenburg region by 2012. Pokrovskoe is operated by TNK-BP’s subsidiary Orenburgneft. Capturing 95% of associated gas production is nominally a legal requirement in Russia. By end-2008, TNK-BP had already invested over US$600mn in gas utilisation projects and the company plans to invest a further US$700mn in such projects by 2012 with the view of raising the utilisation from the current rate of roughly 80% to 95%. Although cost estimates for the Pokrovskoe facility have not been announced, Kommersant’s industry sources put the price tag at US$150-400mn. TNK-BP already reached a deal with Gazprom to link the plant to its pipeline system. It is estimated that around 80% of TNK-BP’s gas production in 2009 will be a by-product of oil production.

In June 2009, TNK-BP announced the start of new phase of production at the Kamennoye oil field in West Siberia, boosting its output to 36,000b/d. In 2004-2008, TNP-BP invested over US$600mn in Kamennoye and hopes to boost its output to 80,000b/d by 2015.

In mid-October 2008, VerkhnechonskNefteGas, a JV between TNK-BP (68%) and Rosneft (32%), began commercial oil production at the Verkhnechonsk field in East Siberia, which is expected to average 26,100b/d over 2009. TNK-BP believes Verkhnechonsk to hold recoverable reserves of over 1bn bbl of oil and sees peak production at 140,600-200,900b/d. Crude is exported to Asia via the ESPO pipeline.

Russia Oil & Gas Report Q2 2011

TNK-BP said it had invested around US$1bn in the field to date and is likely to spend another US$4bn over the course of its producing life, with capex of US$500mn planned for 2009.

Russian police raided TNK-BP headquarters on March 2008 as part of a long-running criminal investigation against Sidanko Oil (one of the companies merged to form TNK-BP in 2003).

TNK and Sibneft jointly acquired Slavneft in 2004’s privatisation auction, with the company producing over 360,000b/d of crude from fields in Western Siberia.

Russia Oil & Gas Report Q2 2011

Tatneft

Company Analysis Address Tatneft JSC Lenina ul., d. 75 Tatneft is struggling to deliver upstream volumes, and has a small and Almetyevsk inefficient downstream operation. Attempts to diversify 423450 Tatarstan, Tel: +7 (495) 937 5533 internationally have met with mixed success, with modest exposure in Fax: +7 (495) 937 5532 Ukraine and a stalled deal in Turkey. State priorities do not www.tatneftjsc.ru necessarily coincide with those of the company, and Tatneft looks unlikely to be able to compete effectively with its larger Russian Financial Statistics peers. Investment is required at high levels in order to maintain Revenues: output, expand petrochemicals capacity and enlarge/improve its RUB220bn (2009) downstream arm. RUB444.3bn (2008) RUB356.3bn (2007) RUB318.3bn (2006) SWOT Analysis Net income/(loss): (RUB100bn) (2009, prelim.) Strengths: Dominant oil producer in Tatarstan RUB8.41bn (2008) Growing CEE portfolio RUB43.3bn (2007) RUB29.8bn (2006) Domestic refining and marketing interests

Involvement in petrochemicals supply Operating Statistics Crude production: Weaknesses: Rising investment requirement 519,100b/d (2009) Modest refining/retail capacity 501,500b/d (2008) 517,000b/d (2007) Limited upside potential in oil supply Gas production Opportunities: Growth in local oil/regional demand 756Mcm (2009) 760Mcm (2008) Expansion of petrochemicals segment Downstream oil upgrading/expansion Proven oil reserves: 6.311 bbl (2009) Threats: Sustainability of upstream oil volumes 6.25bn bbl (2008) 5.91bn bbl (2007) Oversupply in CEE refining capacity Proven gas reserves Changes in national energy policy 36.8bcm (2007)

Russia Oil & Gas Report Q2 2011

Market Position

Tatneft is the main oil company active in the Volga region of Tatarstan and the country’s sixth-largest oil producer. The group’s key shareholders are the regional government of Tatarstan (with 31%), the TAIF group of companies (6%) and employees (8%). Downstream assets include two Tatarstan refineries, the 20,000b/d Kichuyi plant (100%) and the Nizhnekamsk plant (63%), and a network of over 600 service stations in Russia and Ukraine. Tatneft holds an 8.6% stake in Ukraine’s largest refinery, the 370,000b/d UkrTatNaft. The company also has exploration acreage in Libya and Syria.

Strategy

Tatneft said in January 2004 that planned expansion projects through to 2010 would cost over US$2.7bn. This will include a US$1.3bn processing complex at the Nizhnekamsk refinery, incorporating a polypropylene and polyethylene production plant. Tatneft will also expand its service station network and the capacity of the Nizhnekamsk synthetic motor oil plant. The company’s crude output is expected to remain flat over the next five years, as it is already investing billions to maintain production levels at its ageing fields.

Latest Developments

In November 2009, Tatneft increased its syndicated loan to US$1.5bn from US$900mn. The three-year loan, which is secured on oil exports, was oversubscribed. The loan will be used for general corporate purposes particularly for Tatneft's refinery and petrochemical complex, which is currently being built at Nizhnekamsk in Tatarstan.

In May 2009, Kalmneftegaz, in which Tatneft holds a 50% stake, has booked 35bcm of gas reserves from a discovery in northern Kalmykia.

Russia Oil & Gas Report Q2 2011

Total Company Analysis Address Sadovaya-Samotetchnaya The French major’s focus in Russia is the European Arctic. Total’s most Road 24/27 significant upstream asset is its 40% stake in the Kharyaga field. The 127051 Moscow company has also been named partner of the Shtokman development field, Russia but it may not gain ownership of Shtokman’s reserves or production. In the Tel: +7 (495) 937 3784 downstream segment, Total has some petrol outlets across the country. The Fax: +7 (495) 937 3785 E-mail: [email protected] French company is keen, as are most IOCs, to increase its stake in Russia’s upstream despite the challenging business environment. Financial Statistics (group) Total revenue: SWOT Analysis EUR131.3bn (2009) Strengths: Offshore and deepwater expertise EUR180.0bn (2008) EUR158.7mn (2007) Good relationship with Gazprom EUR132.7bn (2006) Weaknesses: Rising investment requirement EUR117.1bn (2005) Net income: Unpopularity of PSAs EUR8.6bn (2009) Opportunities: Rise in CEE regional oil and gas consumption EUR13.9bn (2008) EUR12.2bn (2007) Potential for award of further Russian acreage EUR11.4bn (2006) Threats: Sustainability of Russian oil growth EUR11.6bn (2005)

Changes in national energy policy Operating Statistics Uncertainties over financing and future operations of Net oil production: Shtokman 11,000b/d (2009) 8,000b/d (2008) 7,000b/d (2007) 7,000b/d (2006)

Net gas production: 204Mcm (2009)

Russia Oil & Gas Report Q2 2011

Market Position

Total’s interest in Russia is concentrated in the Arctic region of Yamal-Nenets. The company has a 50% interest in the Kharyaga oil field, which holds estimated reserves of 1.2bn bbl of oil. The 29-year PSA was signed in 1995 and came into operation in 1999. Current output is around 20,000b/d, but following the development of Phase 3, production at Kharyaga is expected to rise to around 60,000b/d by 2013. The combined investment in the project is put at US$900mn. The other partners in the project are Statoil (30%), Zarubezhneft (20%) and the Nenets Oil Company (10%), which is controlled by the regional government. Downstream, Total operates petrol stations across the country’s main cities.

In July 2007, the company gained a 25% stake in the Shtokman field in the Barents Sea, which holds gas reserves of around 3.2tcm. According to Total’s CEO, Christophe de Margerie, the company will invest US$4-5bn in the project over the next five years. The company has relevant expertise in deepwater and long-distance gas production, as well as in LNG transportation. The operating consortium will take on all the risks and will own the infrastructure for 25 years once production has started. The licence for the field, however, will be held by Gazprom’s 100%-owned Sevmorneftegaz unit, with Gazprom retaining all output marketing rights. There has been some confusion over whether Total will be allowed to book a 25% share of the field’s reserves, with the company’s CEO claiming that it will do so, while Gazprom’s statement suggests that this is not the case.

Strategy

The French company has been one of the few foreign majors to maintain investment in the country, in spite of the new paradigm for foreign investment in the country, which provides for state control over resources and production with minority stakes for foreign partners. The company seems to be benefiting from France’s admission of Gazprom into the national downstream market. It is speculated that in return for greater access to the French market, Total was given Shtokman stake. Putin's good relations with de Margerie are likely to give Total the reassurance it needs to increase investment in Russia. In June 2009, Les Echos newspaper cited Total’s head of E&P, Yves-Louis Darricarrere, as saying that Total and Gazprom are looking at more joint projects in Russia.

Latest Developments

In March 2011 Total signed a US$4bn cooperation deal with Novatek involving two related deals. Under the first agreement, Total will buy a 12.08% stake in Novatek from the firm's two main shareholders, Leonid Mikhelson and Gennady Timchenko, for around US$4bn. Following this purchase, both sides have agreed for Total to increase its holding to 15% within one year, and to 19.4% within three years. The French major will appoint a director to the Novatek board, gain around 120,000boe/d in equity production, and 1bn boe of proven and probable (2P) reserves.

Russia Oil & Gas Report Q2 2011

Under the second agreement, Total will buy a 20% stake in the Yamal LNG project, apparently from Timchenko's 49% holding in the project. Novatek will remain the operator and largest shareholder in Yamal LNG, with a 51% stake. Yamal LNG aims to develop the 1.25tcm South Tambey gas field through the construction of a 15mn tpa LNG terminal, equivalent to 20.7bcm. Production is due to start in 2016 at 5mn tpa (6.9bcm), increasing to full capacity in 2018.

In June 2009 Putin approved a JV between Total and independent gas producer Novatek. Putin’s blessing followed Total’s sale of its stake in its Dutch refinery to Lukoil. Following a meeting with Total's CEO, Putin approved Novatek and Total's US$900mn plan to develop the 47.3bcm Termokarstovoye field in Yamal-Nenets, and even intimated that the French group could be chosen for the second phase of the Shtokman field project. Under the deal, Total will take a 49% stake in Terneftegaz, a Novatek subsidiary, which holds the Termokarstovoye licence. The partners will carry out further appraisal and development studies with the aim of launching the project in 2011.

The Russian government in April 2009 approved Total’s plans to invest US$403.7mn in development of the Kharyaga field during 2009, ending previous disputes over the project’s spending. In March 2007, the energy ministry accused Total of failing to comply with the terms of Kharyaga’s licensing agreement. This has prompted concern that Total’s share in the field could go the way of Shell’s Sakhalin-II stake and TNK-BP’s interest in Kovykta, and be sold to Gazprom. However, in July 2007, Russian authorities approved an increase in the 2007 cost estimate for Kharyaga oil field. Cost overruns on PSAs have been a major sticking point between IOCs and Russian regulators, as PSAs only oblige operators to share their profits with the state once their expenses are recouped.

In July 2007, following months of indecision by Gazprom, Total was chosen as a partner in Shtokman. Originally, Gazprom had pre-selected IOCs to act as minority equity partners in the field’s development, and shortlisted Total, along with Norway’s Statoil and Norsk Hydro, and US majors Chevron and ConocoPhillips. In October 2006, however, Gazprom performed a sudden volte-face and declared that it would develop the field on its own. This move raised doubts among analysts as to whether the company had the financial resources and technical ability for such a challenging project, especially considering its lack of LNG experience at the time. Since then, Gazprom has gradually softened its approach, first stating that it would allow IOCs in contractors, and then giving Total a major role in the field’s development.

In 2006, Rosneft cancelled a deal with Total to develop the Vankor oil field, and the French major lost its appeal against the decision.

Russia Oil & Gas Report Q2 2011

Imperial Energy

Company Analysis Address Indian-owned Imperial Energy focuses its operations in the Tomsk region. Imperial Energy Corporation 49 Berkeley Square Imperial has an unrivalled position among junior independent oil London, W1J 5AZ companies in the Russian upstream sector, having high-potential properties. Tel: +44 (0)207 758 9658 However, the company’s activities in 2007 were overshadowed by a dispute Fax: +44 (0)207 758 9659 [email protected] with Rosprirodnadzor, the Russian environmental watchdog, over the company’s reserves statements, which Rosprirodnadzor called Financial Statistics ‘substantially overstated and misleading’. Although the dispute has been Revenues: resolved, the company is likely to face further scrutiny from Russian US$67.5mn (H108) authorities. US$19.9mn (2007) US$3.1mn (2006) SWOT Analysis Net profit/(loss) (US$18.9mn) (H108) Strengths: Successful independent, junior oil company (US$42.4mn) (2007) Vast reserves potential (US$14.6mn) (2006)

Rapidly rising production levels Operating Statistics Net oil production: Weaknesses: Rising investment requirement 13,500b/d (2008e) Opportunities: Growth in Siberian oil production 2,285b/d (2007)

Potential IPO of oil services subsidiary

Threats: Changes in national energy policy

Sustainability of Russian reserves/production

Further disputes with Russian authorities/regulators

Strong portfolio attracting national companies

Russia Oil & Gas Report Q2 2011

Market Position

Founded in 2004, in Russia Imperial operates through three subsidiaries: Imperial Nord, Sibinterneft and Allianceneftegaz. Most of its assets are located in the Tomsk region, the second largest producing region of Western Siberia after Tuymen.

Most of Imperial’s assets are underdeveloped discoveries from the Soviet era. The company is now using the latest technology to maximise the potential of its assets. Imperial Nord holds three E&P licences for blocks 69, 77 and 80, which are the sites of the company’s two producing fields: Snezhnoye and Maiskoye. Sibinterneft holds two exploration licences in Block 74. A Russian state company has previously drilled 13 exploratory wells in the licence. Allianceneftegaz owns six individual exploration licences in blocks 70, 85 and 86.

Strategy

The company targeted production of about 16,000b/d by end-2009 and 25,000b/d by 2010. It has further set new targets of reaching 60,000b/d by the end of 2010 and 80,000b/d by the end of 2011. In January 2008, Imperial said that it may also be looking to sell shares in its oil services unit Rus Imperial Group.

Imperial’s owner, ONGC Videsh Ltd (OVL), in September 2009 announced plans to invest an additional US$209mn to boost production. Imperial's output plummeted to 6,000b/d at the time of OVL’s acquisition in January 2009, but is now being gradually ramped up again.

Latest Developments

Indian state-controlled Oil & Natural Gas Corporation’s (ONGC) international unit OVL completed the acquisition of Imperial Energy in January 2009 for US$2.1bn. Originally, an official from ONGC said that the company would spend US$600mn over the next two or three years on developing Imperial's assets, a figure based on the H108 record-high oil prices. In March 2009, however, ONGC’s managing director, Radhey Sharma, said the investments in Imperial will be cut without specifying the figures. Strategically, ONGC's main priority is securing energy supply to meet India's growing domestic demand. However, it appears to have paid a high price for Imperial Energy, and now looks to be reconsidering its commitment to the company. According to unnamed industry sources cited by Reuters in early March 2009, ONGC was considering selling control of Imperial Energy to Rosneft.

At the end of January 2008, Imperial updated its Russian registered reserves. As a result of five new registration applications to Russian authorities in November 2007, the company’s registered reserves rose by 179% to 379mn boe.

Russia Oil & Gas Report Q2 2011

In November 2007, Gazprombank offered to buy a 25% stake in Imperial at a discount to its share price at the time. This triggered a sharp fall in the value of the company. One positive from any equity-based relationship with Gazprom is that any national obstacles to field development and growth for Imperial are likely to be cleared more easily with a strategic partnership. However, the proposed deal is a typical Russian move to claw back oil and gas assets on the cheap.

In October 2007, Imperial won permission from Transneft to transport its crude oil from its Maiskoe field at Block 70 to the market. Imperial’s oil will be exported as well as sold to the domestic market. Oil from Maiskoe now flows along Imperial’s own 159km pipeline and into the Transneft national transport system at the Luginetskoe station.

In October 2007, Imperial announced an oil discovery with its Tamratskoye-3 well. It estimated the well’s reserves at around 3.4mn bbl. Imperial further said that the company had made a potentially substantial oil discovery at the North Chertalinskoe field a month earlier.

Russia Oil & Gas Report Q2 2011

Novatek

Company Analysis Address

Russia’s largest private gas producer is going from strength to strength. On OAO NOVATEK the back of good Kremlin connections and solid management, production and 12a, Nametkina street Moscow, 117420 reserves continue to rise steadily and profitability remained strong even in the Russia 2008-2009 downturn. The big test to the company’s ambitions, however, will Tel: +7 (495) 730-60-00 come once its Arctic LNG projects get under way, as the company will be Fax: +7 (495) 730-60-07 challenging Gazprom’s export monopoly. www.ina.hr

SWOT Analysis Financial Statistics Strengths: Very large untapped Arctic gas field Sales RUB52.3bn (H110) Good reserve base RUB86.9bn (2009) Good Kremlin connections RUB76.1bn (2008) Net income/(loss) Condensate cash flow RUB18.1bn (H110) Weaknesses: Remote deposits RUB25.7bn (2009) RUB22.9bn (2008) High costs of LNG projects Operating Statistics Kremlin’s anxiety over foreign partners in the Arctic Net condensate production Opportunities: North-eastern Passage 60,000b/d (2009) Net gas production Exports to Asia 32bcm (2009) Threats: Lack of export markets Proven hydrocarbon reserves 8.85bn boe (end-2009) Resurgence of Gazprom’s monopolistic instincts

Cost inflation in the Arctic

Russia Oil & Gas Report Q2 2011

Market Position

Founded in 2004, Novatek is Russia’s largest private gas-focused player, focusing its activities on Yamal- Nenets. Its proven reserves stood at 8.85bn boe by end-2009. The strong reserve growth was attributed to new wells at the Yurkharovskoe and Sterkhovoye fields and the discovery of new deposits in the Khancheyskoe field. The company is majority-owned by its management, although Gazprom has a 19% interest in it. Although still a minnow in comparison with the state gas giant, Novatek has been growing steadily in recent years, reaching 32bcm of output in 2009, plus 60,000b/d of oil and condensate.

As the company seeks to expand its share of the domestic gas market, it is beginning to directly clash with Gazprom, which is keen to protect its quasi-monopoly on distribution. Novatek, however, is a formidable competitor, boasting the support of Genadiy Timchenko, a former secret service official with close connections to Putin. In June 2009, Timchenko raised his direct stake in the company to 20.8%.

Novatek scored a major victory in November 2009, when Gazprom conceded the independent a right of access to the national pipeline, in return for an 18% net-back transit fee. This enabled Novatek to press ahead with the deal to supply subsidiaries of Russia’s largest power provider, Inter RAO UES, with 65bcm from 2010 to 2015 at a cost of around RUB177.3bn (US$6bn). Although Inter RAO is already contracted to buy that gas from Gazprom, Novatek was able to woo the utility with lower prices, to the ire of the state gas giant.

Strategy

The company is pursuing a two-pronged strategy – boosting supplies to the domestic market while developing LNG export projects in Yamal. To advance Yamal LNG forward Novatek will need a well- heeled foreign partner but the company has given conflicting indications about when this will happen and who will be joining it. A number of IOCs as well as the government of Qatar have made overtures to Novatek about joining the Yamal LNG scheme.

Latest Developments

In March 2011 Total signed a US$4bn cooperation deal with private Russian gas company Novatek. Under the deal, Total will become the main international partner at Novatek's 15mn tpa Yamal LNG project and will initially buy a 12.1% stake in the company, which it plans to increase to 19.4% within three years. The deal fulfils a longstanding ambition for Total, which tried to acquire a 25% stake in Novatek in 2005, and will significantly increase the company's Russian reserves and production. For Novatek, the agreement provides it with a strategic partner with technological capability and access to funding.

Under the second agreement, Total will buy a 20% stake in the Yamal LNG project, apparently from Timchenko's 49% holding in the project. Novatek will remain the operator and largest shareholder in

Russia Oil & Gas Report Q2 2011

Yamal LNG, with a 51% stake. Yamal LNG aims to develop the 1.25tcm South Tambey gas field through the construction of a 15mn tpa LNG terminal, equivalent to 20.7bcm. Production is due to start in 2016 at 5mn tpa (6.9bcm), increasing to full capacity in 2018.

On November 8 2010, Novatek announced that its board had approved the purchase of a 51% stake in Siberian gas minnow Sibneftegaz from Gazprom's banking affiliate Gazprom Bank. Sibneftegaz, which owns several licences in the Yamal-Nenets Region, has ABC1+C2 reserves under the Russian classification system of 396bcm and produced 7.3bcm in 9M10. Analysts cited by Platts put the value of the stake at around US$1bn.

Earlier in November 2010, Gazprom agreed to sell a controlling stake in SeverEnergia to its oil subsidiary Gazprom Neft and Novatek for US$1.5bn. Although the deal will increase the exposure of Gazprom Neft and Novatek to the Yamal region, the motivation for the deal has yet to become clear. Their Yamal Development JV will also acquire US$250mn of SeverEnergia's debts under the deal. Eni and Enel will retain the remaining 49% stake.

Russia is considering exempting Novatek's Yamal LNG project from the mineral extraction tax (MET), the country's deputy finance minister, Sergei Shatalov, said in October 2010. An exemption would signal upside potential for Yamal LNG, while its developer's profile continues to grow Shalatov said on October 11 that Yamal LNG is the only project being considered for an exemption from the MET. Speaking at Novatek's Yurkharovskoye field in the Russian Arctic on the same day, Prime Minister Vladimir Putin confirmed that the company may be exempted from the levy on gas produced for Yamal LNG.

In May 2009, Novatek paid US$650mn in cash to acquire a 51% stake in Yamal LNG, denying rumours of a planned share offer. Gazprom holds another 25.1% in Yamal LNG through a subsidiary as well as directly controlling 19% in Novatek itself. Gazprom previously announced its intention to begin feasibility studies on an LNG plant on the peninsula in early-2010, although the financial crisis is likely to push the date back. The CEOs of the two companies agreed to begin third-party negotiations on the project following a meeting in August 2009. Yamal LNG is the operator of the South-Tambeyskoe gas field in the Yamal-Nenets region. In June 2009, Gazprom shortlisted Total and Shell for participation in Yamal LNG adding that that Mitsui and Mitsubishi were also expected to obtain minority rights in the project. Interest has also been previously expressed by Conoco.

Amid much fanfare, in August 2010 Novatek has shipped its first cargo of condensate via the Northern Sea Route (aka the Northeast Passage) to demonstrate the feasibility of selling its resources in the Barents Sea region directly to Aisa. A cargo of condensate was dispatched to China in Sovcomflot's high-tonnage tanker Baltica with support from a nuclear icebreaker.

Russia Oil & Gas Report Q2 2011

By using the Northeast Passage, Novatek can reduce its normal journey to China and Japan of around 20,400km around the Suez Canal to around 12,500km, which would allow for a significant reduction in transit time, fuel costs and the risk of pirate attacks.

Russia Oil & Gas Report Q2 2011

Russneft Company Analysis Address 69 Pyatnitskaya St. Although a relatively small producer by Russian standards, Russneft is Moscow well integrated with upstream oil assets, two refineries, service Russia,115054 stations, and a fuels terminal. While this means that the company is Tel: (495) 411-6309 relatively safe from crude price fluctuations, the company’s main Fax: (495) 411-6325 challenge over the late-2000s has been dealing with state influence http://eng.russneft.ru/ and legal disputes. Following its acquisition by Sistema in 2010 these problems appear to be behind Russneft, giving it the chance to Financial Statistics Revenue: stabilise its declining crude production. With the threat of a merger RUB116.14bn (2009) with Bashneft on the horizon, the company’s independent existence RUB137.10bn (2008) itself looks at risk. RUB113.70bn (2007) RUB102.45bn (2006) SWOT Analysis Net Profit : RUB15.57bn (2009) trengths: Integrated upstream and downstream S RUB10.58bn (2008) Diverse upstream oil portfolio (RUB12.25bn (2007) RUB9.94bn (2006) Weaknesses: Declining oil production Operating Statistics Oversupply in CEE refining capacity Year established: 2002 Opportunities: Growth in Russian oil production Refining capacity: 132,594b/d (2009) Rise in CEE regional oil consumption Oil production: Threats: Vulnerable to state influence 254,942b/d (2009) 286,082b/d (2008) Large state-run competitors 281,260b/d (2007) 296,328b/d (2006)

Russia Oil & Gas Report Q2 2011

Market Position

Russneft, one of Russia’s largest privately owned energy companies, was formed in 2003 when its owner Mikhail Gutseriyev left Slavneft and purchased some of its assets. Russneft produced 255,000b/d in 2009. It has 30 separate upstream operations split into four groups – West Siberia, Ural, Povolzhsk and central Siberia – and has recoverable reserves of 4.6bn bbl.

In the downstream, Russneft also owns two refineries: the 132,594b/d Orsknefteorgsintez plant in Orsk (Orenburg) which produces fuels and the Neftemaslozavod plant which it acquired from TNK-BP in 2005 and is dedicated to production of lubricants and protective rustproof compounds. In 2009 the Orsk refinery processed about 105,000b/d, giving it a utilisation rate of just under 80%. The company also owns a network of 96 petrol stations (end-2009) and a 140,000b/d crude oil terminal in the Bryansk region.

Russneft was breaking the mould of an increasingly state-dominated industry, until its shares were frozen by a district court in August 2007 after owner Gutseriyev was charged with tax evasion. Gutseriyev subsequently sold the company to Basic Element (Basel) investment vehicle controlled by Oleg Deripaska, a major businessman generally seen as a Kremlin ally. The Kremlin's removal of an international search warrant for Gutseriyev in November 2009 enabled the Russneft’s founder to resume ownership of the company. In January 2010, Gutseriyev agreed to take over Russneft from Deripaska in return for assuming the company's US$6bn-worth of debts and a US$600mn in cash.

Strategy

With Gutseriyev's relations with the government apparently mended for the time being, we expect the businessman's extensive experience in the oil sector to spur Russneft's development in the coming years. Following his return, Gutseriyev agreed to farm out 49% of Russneft to conglomerate Sistema for an undisclosed amount. The Russneft stake will allow Sistema to balance out its downstream-heavy portfolio, helping it to fill its refineries.

In May 2010 Gutseriyev said that Russneft was considering merging with fellow Sistema subsidiary Bashneft within two to three years. According to Gutseriyev, the merged company would then conduct an IPO. He added that Russneft intends to increase its annual oil production to 400,000b/d of oil in the next few years and to make an annual profit of US$1.5bn (RUB45.9bn).

Russia Oil & Gas Report Q2 2011

Recent Developments

In September 2010 Sistema announced that the process of restructuring Russneft’s debt was nearing completion. The announcement followed remarks by Sistema President Leonid Melamed in May 2010 that once Bashneft covers debts of US$7bn Sistema could allow the two companies to merge.

Russneft and its partner MOL in August 2009 settled an internal dispute over the jointly operated Zapadno-Malobalykskoye (ZMB) field in West Siberia. According to the Interfax news agency, Russneft agreed to pay a RUB6.3bn (US$201mn) debt for the oil it bought from ZMB. Although the settlement has diffused internal tensions, Russneft's stake in the project remains threatened by a competing ownership claim from Rosneft.

Gazprom Neft suspended talks on buying Russneft in April 2009. Gazprom Neft appears to have baulked at Deripaska's reported valuation of the company, according to Vedomosti’s sources. Gazprom Neft had wanted to buy Russneft by assuming its debt, which is estimated at US$5.6bn, while Deripaska has valued the company at US$7.5-8bn excluding debt. The negotiations broke down after the indebted Deripaska was thrown a lifeline by state-owned Sberbank, which agreed to restructure one of Russneft’s loans.

Russia Oil & Gas Report Q2 2011

Surgutneftegaz – Summary

Surgutneftegaz is the fourth largest crude producer in Russia. Its traditional base is southern West Siberia but it has been expanding into Timan-Pechora and Khanty-Mansyisk in the north and views Eastern Siberia as another growth region. Crude production averaged 1.2mn b/d in 2009; gas output totalled around 14.1bcm. The company’s downstream assets include the 398,000b/d Kirishi Oil Refinery (KINEF) in the Leningrad region. Retail assets include a network of around 300 service stations in north- western Russia. Sales in 2008 amounted to RUB547bn. Its reporting of profits, however, is somewhat erratic, as it does not follow international accounting standards. In March 2009, Surgutneftegaz made its first foray into international markets, paying US$1.4bn for a 21.2% stake in Hungarian oil and gas company MOL, to the chagrin of the Hungarian government.

Surgutneftegaz is an opaque company. It moved 42% of its shares to a separate company in 2003 and since then has not revealed the ownership of that stake, instead classing the stock as treasury shares. According to a statement by Russian strategist Stanislav Belkovsky to German newspaper Die Welt in 2007, Prime Minister Vladimir Putin himself owns 37% of Surgutneftegaz.

Sistema – Summary

Telecom-focused Russian conglomerate Sistema made a big entrance into the oil industry in April 2009, acquiring six major upstream and downstream businesses in the Republic of Bashkortostan (Bashkiria) in the Urals region. The deal gave Sistema a 76.5% stake in Bashneft, the regional quasi-monopoly, plus five affiliated refining and marketing concerns.

In December 2010 India's state-run ONGC established a framework with Sistema that could see the potential merger of their Russian oil and gas assets. During a visit to India by Russian President Dmitri Medvedev, the international subsidiary of ONGC, OVL, signed a framework agreement with Sistema. Under the deal, they agreed to 'consider opportunities for a potential transaction' involving either Sistema's or OVL's current Russian oil and gas assets or any assets that either company may acquire prior to the signing of any definitive agreement. The parties also envisage joint investments in other exploratory assets, while OVL said it would lead a consortium of Indian state-run firms to possibly acquire a stake in Sistema.

In early-2010, Sistema reached a preliminary agreement to acquire 49 % of Russneft. The Russneft stake will allow Sistema to balance out its downstream-heavy portfolio, helping it to fill its refineries. Further upstream growth is expected to come from the once-sleepy Bashneft, with Sistema targeting 7.8% crude output growth in Bashkiria in 2010. Given Sistema's growth ambitions, further acquisition of oil assets in Russia and the former Soviet Union is to be expected in the near future.

Russia Oil & Gas Report Q2 2011

In December 2009 Sistema signed a strategic cooperation agreement with India’s ONGC for joint energy projects in the FSU.

Bashneft – Summary

Sistema subsidiary Bashneft holds 2.2bn of proven reserves and is the second largest producer in the Volga-Urals region after Tatneft. The company produced around 234,000b/d from around 140 fields in Bashkiria and neighbouring Tatarstan and Udmurtia in 2008. The company’s biggest revenue earner, however, is its large affiliated refining business, which comprises the Ufaneftechim, Novoil, Ufaorgsintez and Ufimskiy plants, and accounts for around 10% of Russia’s refining capacity. Production of refined products in 2008 stood at 420,000b/d. Marketing arm Bashkirnefteproduct has around 317 service stations in the region. Sistema is now pushing to acquire full ownership of the Bashir assets.

In September 2010, Sistema articulated a strategy for Bashneft focused on raising its 2011 capital expenditure to raise oil production, while spinning off the company's oil field services division. We believe that the medium-term outlook for Bashneft is bright, given that the company has not only been successful at boosting crude output, but also at winning the Kremlin's good graces.

Russia's Natural Resources Ministry announced on December 2 2010 that Bashneft had won the development rights to the onshore Trebs and Titov fields, after fellow producer Surgutneftegaz failed to participate in the auction. Bashneft offered to pay RUR18.5bn (US$597mn) for the deposits, higher than the initial price of RUR18.17bn (US$587mn) set by the ministry. Surgutneftegaz did not make the advance payment required and failed to present a feasibility study, and consequently was disqualified.

Located in Russia's northern Timan-Pechora Basin, the Trebs and Titov deposits have C1+C2 reserves of 604mn boe and 426mn boe, under the Russian reserve classification system. The auction for the development rights to the fields attracted significant industry interest, despite the fact that the government wanted participants in the tender to refine at least 42% of the fields' crude output at local refineries and sell a further minimum of 15% on the Russian Commodities and Raw Materials Exchange.

Sistema said that Bashneft intends to spin off its oilfield services division and raise capex, Reuters quoted a Sistema vice-president as saying on September 23 2010. Sistema's senior vice-president, Alexander Korsik, said that the decision to divest Bashneft's oil services and drilling operations was based on a desire to optimise efficiency. Korsik said that Sistema was discussing the sale of these operations with several leading service companies, including Baker Hughes, Schlumberger and Halliburton. He suggested that the process would not be complete for a few years. A Baker Hughes executive told Reuters earlier that it was interested in Bashneft's assets, as it was looking to grow its Russian business.

Russia Oil & Gas Report Q2 2011

Korsik also said Bashneft intends to raise its 2011 capex significantly. While he did not reveal specific figures, he stated that capex growth would be 'in double digits,' and would be concentrated in improving oil sales margins. Based on previous announcements, Bashneft's capital investments are expected to rise from RUB16bn (US$516mn) to RUB21bn (US$677mn) in 2009-10. This followed an announcement was made by Rustem Khamitov, the governor of Bashkiria, in September 2010, that Sistema will invest RUB100bn (US$3.24bn) in upgrading Bashneft’s refineries in 2011-2014. The move will help it remain competitive in the fuels export market as local rivals such as TNK-BP invest heavily in their own plants.

Itera – Summary

Itera is another significant domestic Russian gas player. An opaque company, it has traditionally been a gas trader but in the 2000s got involved in production. Itera works close with Gazprom and has access to its pipeline system. While Itera is keen to establish itself as a leading ‘independent’ Russian gas producer, it has backed a continuation of Gazprom’s near-monopoly.

Itera was founded in 1992 and started marketing gas in 1994. An opaque company, it has activities in Russia, Central Asia, Europe and the US through a network of almost 150 offices and affiliated companies. In 1998 the company moved into gas production for the first time through taking a stake in fields in Russia's Yamal-Nenets region. According to Vedomosti the company rapidly became the CIS's second largest gas producer after Gazprom, with which it worked closely.

In the early-2000s Gazprom repeatedly expressed interest in acquiring a controlling stake in the company. Following Itera's rejection of the bids, its strong market position began to weaken and most of its producing assets, as well as its concession to deliver Central Asian gas to Ukraine, were transferred to Gazprom. From around 30bcm in 2003, the company's production has fallen significantly, with 2010 production targeted at 13.5bcm according to Vedomosti.

According to an October 5 report in Russian business daily Vedomosti citing Itera vice-president Aleksandr Berezikov, the company wants to sell up to 50% of its shares to a strategic investor. Berezikov said that a new investor would bring additional technology and investment to help the company grow, and that he was holding discussions with unnamed companies. Vedomosti cited two unnamed sources close to the matter who said that TNK-BP has been in talks with Itera for several months. One source claimed a deal was close to completion and that TNK-BP would pay for the stake through allocating some of its gas assets to Itera along with a cash payment to pay down its debts.

Royal Dutch Shell – Summary

Anglo-Dutch Shell is no longer the leading member of the US$10bn Sakhalin-II integrated project in the Far East, having relinquished control to Gazprom in December 2006 after a drawn-out battle. Previously,

Russia Oil & Gas Report Q2 2011

Shell held a 55% stake but now retains 27.5% minus one share. Shell is also involved in the Salym group of oil fields in Western Siberia through a 50:50 Salym Petroleum JV with Sibir Energy, a Gazprom Neft subsidiary. The partners are developing the West Salym, Upper Salym and Vadelyp fields, which hold an estimated 600mn bbl of crude reserves. The Salym fields started commercial production in December 2005, peaking at around 160,000b/d in 2009, mostly from West Salym.

In spite of the chequered history of its Russian operations, Shell has proposed developing Yamal reserves with Gazprom. In February 2009, Shell’s former CEO Jeroen van der Veer also said the company was looking to discuss joint projects with Gazprom in the Far East. This was followed in June 2009 by Putin’s informal invitation to Shell to join the Rosneft/Gazprom-led Sakhalin-III and -IV project, which were abandoned by BP.

In March 2009 Salym Petroleum extended a drilling contract with US-based oil field services company Halliburton in a deal worth US$100mn. Halliburton has been working at Salym since 2005 and will now remain there until at least 2013.

ExxonMobil – Summary

US major’s subsidiary Exxon Neftegas (ENL) operates the US$12bn Sakhalin-I project with a 30% stake, working alongside two units of Rosneft (20%), India's OVL (20%) and a consortium of Japanese companies JNOC, Japex, Itochu and Marubeni (30%). The partners are developing the Chayvo, Odoptu and Arkutun-Dagi offshore fields, which are estimated to contain up to 2.3bn bbl of crude and 485bcm of potential recoverable gas resources. Oil production from Chayvo, the only producing field so far, began in 2006. Production peaked the very next year at around 225,000b/d (somewhat below initial expectations) and has been declining since, averaging 193,000b/d in 2008 and 165,000b/d in 2009. Chayvo also produces gas, with output expect to eventually reach 10bcm per year. Currently, consumption of Sakhalin-I's gas remains confined to the Khabarovsk region. Rising output volumes, however, present significant export potential.

Progress at Sakhalin has been slower than expected owing to disagreements between Gazprom and Exxon over gas marketing rights. Exxon supports the construction of a pipeline to China, an option it has under

Russia Oil & Gas Report Q2 2011

the project’s PSA. Gazprom, on the other hand, has previously favoured shipping the gas as LNG from the Sakhalin-II export terminal, although more recently it has insisted the gas is needed to supply the domestic market to support industrial expansion in eastern Russia.

In late-April 2009, Exxon resumed work at Sakhalin-I after the energy ministry finally approved its US$2bn cost plan for that year. Delay in the budget approval forced Exxon to briefly halted work on the project in February 2009. In December 2010 Exxon and the Russian government have struck a compromise over the disputed budget for the 2010 Sakhalin-1 project. The government approved a budget of US$2.7bn for the project, less than the US$3.5bn requested by Exxon but more than twice the US$1bn budget previously approved by the government.

The Odoptu field came onstream in October 2010. Oil production from Odoptu will offset some of the declining output from Chayvo. The Odoptu Phase 1 development will utilise the existing midstream infrastructure connected to the Chayvo field. Crude from Odoptu will be sent by pipeline to the Russian mainland for export via the De-Kastri terminal in the Khabarovsk region. No production estimates for the Odoptu fields have been released. In May 2010 Exxon said that the Odoptu field will increase output at Sakhalin-I by 30,000b/d when it comes onstream.

Transneft – Summary

State-owned Transneft is Russia’s oil pipeline monopoly. It transports about 93% of Russia’s oil production, operating some 50,000km of long-distance pipelines, including the Druzhba (Friendship) line, which runs from Russia through Belarus and Poland into Germany. Transneft is also the largest shareholder (31%) in the 750,000b/d CPC system, which stretches 1,505km from Tengiz in Kazakhstan to the Russian Black Sea port of Novorossiysk.

In December 2008, the government approved Transneft’s request to increase oil transportation tariffs by 15.7% from 2009. While this increase is lower than the 21% rise requested by Transneft, the news will present another blow to Russian oil producers that are already exporting crude at a loss after paying export duties, transportation tariffs and taxes amid subdued oil prices. In 2008, Transneft raised its oil shipping fees in January and August by 19.4% and 10.7% respectively. The company has argued the increases are necessary to maintain its infrastructure and finance new projects, particularly the ESPO.

Sakhalin Energy – Summary

Sakhalin Energy operates the Sakhalin-II project, which formally began operations on February 18 2009 and which incorporates an oil field with associated gas, a natural gas field with associated condensate, a pipeline, and an LNG processing plant and export terminal. Once fully onstream, the project will produce 9.6mn tpa of LNG and around 900,000b/d of crude oil. As of December 2006 Sakhalin Energy is majority

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owned by Gazprom (50% plus one share) alongside former majority owner Shell (27.5% minus one share), Mitsubishi (12.5%) and Mitsui (10%). Gazprom paid US$7.45bn for its majority stake. Roughly two-thirds of Sakhalin-II’s LNG exports will be exported to nine utilities in Japan, while the remaining third goes to South Korea and North America.

In March 2009, Osaka Gas signed an SPA to buy 200,000tpa of LNG from Sakhalin-II from 2011 without disclosing the financial terms.

Wintershall – Summary

Wintershall is an upstream subsidiary of German chemical group BASF. The company has two major projects in Russia. The first, the US$3bn Yuzhno (South) Russkoe gas project, holds recoverable natural gas reserves of more than 600bcm, and reach plateau production rate of 25bcm per annum in mid-2009. The companies have a preliminary agreement in place to supply over 800bcm of gas to Europe to 2043 through BASF’s distribution arm Wingas. The second project is the US$1bn Achimgaz JV in the Yamal- Nenets region, in which Gazprom and Wintershall are equal partners. It came onstream in July 2008 and produced around 1bcm and 6,000b/d of condensate in 2009 and is expected to peak at 7.5bcm and 55,000b/d of condensate. The project’s lifespan is put at over 40 years.

BP – Summary

Until the Rosneft deal is completed, BP’s presence in Russia will remain concentrated on the TNK-BP JV, with the British major having pulled out of the CPC pipeline consortium and significantly reduced its Sakhalin exposure. Following the Macondo oil spill in mid-2010, BP had put much more emphasis on TNK-BP’s projects in order to offset tough going at its offshore operations, although deteriorating relations with the JV could well discourage BP from continuing this strategy. The spill could usher in a new era of BP involvement in Russia, with former CEO Tony Hayward actively courting Russian politicians and state-run energy firms.

BP has been active in Sakhalin since 2006, when it launched a 49:51 JV with Rosneft to develop Sakhalin-IV and -V areas in the Sea of Okhotsk. The most promising acreage in Sakhalin-IV was thought

Russia Oil & Gas Report Q2 2011

to be the West Schmidt Block, with reserves estimated at up to 3bn bbl of oil and 255bcm of gas. Two exploration wells were drilled at the Medved and Toiskaya structures in 2007 but both disappointed. Following extensive interpretation of seismic data, BP appears to have decided that the block holds little commercial prospects and in March 2009 abandoned the Sakhalin-IV project.

In February 2010, BP and Rosneft also relinquished the East Schmidt Block at Sakhalin-V. BP and Rosneft said that after evaluating extensive seismic data they decided not to proceed to the drilling phase, again owing to poor commerciality. The JV, however, has chosen to keep the other permit in the Sakhalin-V project, the Kaigansky-Vasuykanskiy (KG) Block. The partners drilled two deepwater wells at KG in 2006 and have been sufficiently encouraged by the results to shoot more seismic data in 2010 in preparation for further drilling. Estimated reserves at the only certified discovery at the block, dubbed the Kaigansko-Vasyukanskoye Sea field, are put at 118mn bbl of oil and condensate (ABC1).

With all synergy between Sakhalin-IV and Sakhalin-V now lost, any commercial discoveries at the KG block are most likely to be developed in conjunction with the Sakhalin-III project further south.

Lundin Petroleum – Summary

Swedish independent Lundin Petroleum has interests in four production licences and one exploration licence in Russia. Its most prospective asset is the Laganskiy (Lagansky) Block in the Northern Caspian, where the October 2008 Morskaya discovery is estimated to hold 230mn boe of recoverable reserves. Although Lundin currently holds a 70% interest in Laganskiy, Gazprom has a call option to acquire a 50% plus one share stake. Lundin has also agreed a call option to acquire an additional 30% stake from remaining shareholder Gunvor, an oil trader. Should both options be exercised, Lundin would retain 50% minus one share in the block, leaving Gazprom 50% plus one share.

In February 2009, Rosnedra extended Lundin’s exploration permit for the Laganskiy Block until August 2014. The contract extension will allow Lundin to delay the drilling of the Morskaya-2 appraisal well until 2010, which will test the western section of the discovery. The Petrovskaya structure, which was estimated to hold reserves of up to 300mn bbl, however, has disappointed after the Petrovskaya-1 exploration well came up dry in November 2009.

Irkutsk Oil Company – Summary

Irkutsk Oil Company, known by its Russian acronym INK, was established in November 2000 by bringing together several small oil and gas producers in the Irkutsk region of East Siberia. It was the first to bring onstream oil production in Irkutsk and remains the largest producer in the region. The company currently holds 11 oil and gas fields, all operated by separate subsidiaries. The company appears to be owned by its management, with 8.1% held by the European Bank for Reconstruction and

Russia Oil & Gas Report Q2 2011

Development (EBRD). INK has a strong focus on gas capture and is pursuing various policies to eliminate flaring at its fields. Production in 2008 stood at 6,000boe/d. There are several developments in the pipeline, which should benefit from connection to the ESPO export pipeline.

In November 2009, state-run Japan Oil, Gas and Metals National Corporation (JOGMEC) signed an agreement with INK to study the potential application of gas-to-liquids (GTL) technology at their joint projects. The agreement formalises GTL plans announced by the INK chairman in September 2009. The technology would be applied at the Mogdinskiy Severniy, Bolshetirskiy and Yaraktinskiy Zapadnyy blocks, which are being developed by INK-Sever, a 51:49 JV between INK and JOGMEC.

Aladdin Oil & Gas – Summary

Oslo-listed Aladdin Oil & Gas was founded in 2006 and is solely focused on Russian exploration and production. It holds four licences through its 100%-owned Geotechnologia subsidiary: Middle Sediolskoye, West Uthinskoye and two licences in the Timan-Pechora Basin, all in north-western Russia. In addition, the company's 100%-owned Orneftegaz and Veselovskoe subsidiaries are exploring in the south of the country: at Bogdanovskoe in the pre-Caspian depression and in the Volga-Ural Basin, giving Aladdin a total of eight Russian licences. According to Nedrelid, Aladdin has invested a total of NOK375mn (US$66.9mn) in Russia since 2006.

In October 2009 Aladdin signed an agreement with Gazprom’s subsidiary KomiRegionGaz to sell 46Mcm per annum for five years from its Middle Sediolskoe field in the Komi Republic. Trial production started in March 2010. The gas price for deliveries will be adjustable, with the price for Q409 set at RUB1,770/mcm (US$60/mcm). On October 14, the company announced that it was increasing its P2 reserve estimates for the Middle Sediolskoe field to 383Mcm. Aladdin is hoping to produce 2,650boe/d in Russia in 2010. The Sediolskoye supply deal will provide Aladdin the funds towards the development of its remaining licences, after three years of net losses. Aladdin's future growth prospects will depend on the commercialisation of some of its other licences, particularly the oil-bearing West Uthinskoye licence.

PetroNeft – Summary

London-listed PetroNeft was established in 2005 to develop assets in West Siberia. The company owns Licence 61, which covers an area of 4,991sq km, with 100%. The licence is also located in the Tomsk region and contains two proven oil fields – Lineynoye and Tungolskoye – as well as around 25 additional prospective areas and further potential prospects that have been identified through seismic surveys. According to consultants Ryder Scott, the Lineynoye and Tungolskoye fields hold total proven, probable and possible (3P) reserves of 70.6mn bbl, while the additional and potential prospects are estimated to hold 3P reserves of 253mn bbl and exploration resource reserves (4P) of 100mn bbl. In early December

Russia Oil & Gas Report Q2 2011

2009, PetroNeft announced plans to drill nine wells on the licence, with the first one scheduled to be spudded in April 2010.

In December 2009, PetroNeft was awarded the Ledovy licence in the Tomsk region. The licence does not include two producing oil fields – Grushevoye and Lomovoye – that are located in the area. However, PetroNeft believes that two undeveloped discoveries – Ledovoye and Sklonavaya – have significant potential, and under the agreement the company can use the existing infrastructure at the two producing fields, including the Vasyugan-Raskino oil pipeline, to develop other discoveries. Under the agreement, PetroNeft's three-year exploration programme will include the reprocessing of seismic and well data, the acquisition of 750km of new seismic data and the drilling of one well. It is targeting three drilling prospects, which are estimated to hold 55mn bbl of oil in place. The licence, which covers 2,447sq km, is the company's second in the area.

Alliance Oil – Summary

Independent oil company West Siberian Resources (WSR) merged with Russia-focused mid-sized Alliance Oil in April 2008. The US$2.5bn deal created a vertically integrated player with assets in Russia and Kazakhstan. Alliance's shareholders control 60% of the new entity and WSR's the remaining 40%. As of end-2009, the company had proven and probable (P2) reserves of 526mn bbl, output of 42,700b/d, refining capacity of 70,000b/d and a retail network of 255 stations in eastern Russia. During FY09, the company reported revenues of US$1.73bn and net profit of US$345mn. Revenues were down from US$2.72bn in 2008, while profits were up from US$45.97mn in the previous year.

Others – Summary

Spanish major Repsol YPF is reportedly in talks with Rosneft about acquiring a 25% stake in the Sakhalin-III project.

AIM-listed Urals Energy is a sizeable independent focused on East Siberia. By early-2008 the company held P2 reserves of 822mn boe. However, following the collapse of a loan restructuring deal with Sberbank in the wake of the global financial crisis, Urals was forced to agree to divest to Sberbank its stakes in key Taas Yuriakh Neftegazodobycha and Dulisma operating units in mid-2009 as part of the loan repayment deal. The company’s future now looks uncertain with a hostile takeover or liquidation being a large threat. Its shares were suspended from AIM in July 2009. Ural’s aim to raise output to 75,000b/d by 2013 is no longer feasible. In November 2007 Urals acquired a 35.5% in Taas, in what was at the time one of the largest deals by a Russian-based independent.

PetroVietnam is seeking government approval to invest US$614mn in an oil E&P JV with Zarubezhneft. The partners were awarded four oil blocks in western Siberia in May 2008, beating the only other bidder,

Russia Oil & Gas Report Q2 2011

Rosneft. Russia and Vietnam signed an agreement to deepen E&P cooperation in 2006. The agreement was implemented through the award of the licences in Yamal-Nenets and also extends the life of the companies' first JV, Vietnam-based Vietsovpetro. PetroVietnam would have a 49% stake in the US$1.25bn JV, which will explore blocks N1, N2, N3 and N4 in Nenets. The blocks currently consist of 13 fields and hold estimated oil reserves of around 572mn bbl. According to Zarubezhneft, the partners were planning to start drilling at the fields by end-2008 and expect to produce 80,365-100,457b/d within five to seven years. Zarubezhneft, which controls a 51% stake in the JV, will provide the remainder of the capital.

In December 2009, PetroVietnam also established a gas partnership with Gazprom, the 49:51 Gazpromviet, again mirroring a sister JV in Vietnam. The new JV will jointly develop the Nagumanov field in the Urals region.

Japan's Mitsubishi and Mitsui are interested in acquiring stakes in the Sakhalin-III project in Russia's Far East, according to a report in Japanese newspaper Yomiuri Shimbun citing unnamed industry sources. The Japanese companies already hold 10% and 12.5% stakes respectively in the adjacent Sakhalin-II project, which supplies LNG to Japan. Their intention to farm in to the Gazprom-led Sakhalin-III development is therefore believed to be motivated by the expected cost synergies with Sakhalin-II and a desire to secure additional gas supplies.

In October 2009, AIM-listed Matra Petroleum spudded its first appraisal well at the Sokolovskoe field in the Arkhangelovskoe licence in the Orenburg region of the Urals. The A-13 well is estimated to cost around US$4.5mn and is expected to be completed by the end of February 2010.

Western Siberia-focused independent Exillon Energy launched a successful US$100mn IPO on AIM in December 2009, making it the first share offering by a Russian oil producer since the start of the financial crisis in mid-2008. Exillon, which is registered in the Isle of Man and headquartered in Dubai, acquired its first assets in early 2009, receiving permits for 10 oil fields in north-western Siberia. Its operations are split between two subsidiaries: Exillon TP, which operates five fields in the Timan-Pechora Basin in the Komi Republic and Exillon WS, which operates another five fields in Khanty-Mansiysk. The Exillon WS and TP fields were discovered in 1971 and 1988 respectively and are both producing an unspecified small amount of light oil. Despite the fields' long production history, Exillon believes the assets hold significant upside potential and is seeking to raise funds for their development through an IPO.

Former IOC Partners – Summary

Austria's OMV divested its Russian exploration assets in September 2010, a few months after announcing its intention to leave the country. It operated in Russia via Ring Oil Holding and Trading, which held eight exploration blocks in the region of Saratov and two blocks in the region of Komi. Ring’s majority

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owner was Romania’s Petrom, which also sold out in late 2010. Petrom’s assets went to little-known Malta-registered player Mineral & Bio Fuels for an undisclosed sum.

In August 2009, Petrom reported its first Russian exploration success at the Lugovaya-1 well, located in Saratov's Kamenskiy licence. Well tests showed a flow rate of more than 2,500b/d of light sweet oil in one zone, while two gas-bearing formations produced a combined 4,000boe/d of sweet gas and condensate. Russia's natural resources ministry said in October 2009 that reserves at the block could be as much as 80mn tonnes, or 586mn bbl, although it did not specify the level of certainty attached to this estimate.

Ironically, this exploration success may have been the reason for OMV's decision to exit Russia. According to Russian's law on strategic deposits, passed in May 2008, the state is empowered to take over oil exploration licences where recoverable reserves exceed 70mn tonnes (513mn bbl). Should the natural resources ministry's reserves estimate be accurate, the Kamenskiy licence would be subject to this law. Although the law provides for compensation of costs plus a 30%-50% 'premium,' the fact that licences are subject to state appropriation is a major risk and has contributed to negative investor perception of Russia.

Russia Oil & Gas Report Q2 2011

Oil And Gas Outlook: Long-Term Forecasts

Regional Oil Demand

A slight strengthening of the 2010-2015 oil demand trend is predicted for the 2015-2020 period, reflecting the economic weakness prevailing in the earlier period, as well as the under-developed nature of several key economies, ongoing wealth generation thanks to rising export volumes, plus the maturing of new EU member states. The region’s oil consumption is expected to increase by 13.9% in 2015-2020, after 13.8% growth in the period 2010-2015. Over the extended 2010 to 2020 forecast period, Azerbaijan leads the way, with oil demand increasing by an estimated 96.7%, followed by Uzbekistan and Turkmenistan (+62.9%) and Kazakhstan’s 39.3% growth. Hungary lags the field, as a result of greater market maturity and the lack of hydrocarbons income that stimulates economies elsewhere in the region.

Table: CEE Oil Consumption (000b/d)

Country 2013f 2014f 2015f 2016f 2017f 2018f 2019f 2020f

Azerbaijan 92 98 105 112 120 129 138 147

Bulgaria 105 107 109 111 114 116 118 121

Croatia 112 114 115 117 119 121 122 124

Czech Republic 223 228 231 235 238 242 246 249

Hungary 172 174 177 179 182 185 188 190

Kazakhstan 263 276 289 304 319 335 352 369

Poland 589 598 607 616 625 635 644 654

Romania 233 240 247 254 262 270 278 286

Russia 3,162 3,241 3,322 3,406 3,491 3,578 3,667 3,759

Slovakia 90 93 96 99 102 105 108 111

Slovenia 60 61 63 65 67 69 71 73

Turkey 689 740 755 770 785 801 825 850

Turkmenistan 143 150 158 166 174 183 192 201

Ukraine 343 353 363 374 386 397 409 421

Uzbekistan 123 129 135 142 149 157 165 173

BMI universe 6,396 6,602 6,774 6,951 7,133 7,321 7,522 7,730 other CEE 154 155 155 156 157 158 158 159

Regional total 6,550 6,757 6,929 7,107 7,290 7,478 7,681 7,889

f = forecast. All forecasts: BMI.

Russia Oil & Gas Report Q2 2011

Regional Oil Supply

CEE oil production is forecast to rise 10% from 2010 to 2020, with a likely plateau approaching in Russian, Kazakh and Azeri output, and no other major country expected to have substantial longer-term upside potential. Kazakhstan is by far the biggest contributor to growth, with output forecast to rise by 33.3% between 2010 and 2020. Turkmenistan exceeds it in percentage terms (+54.1%), but is a much smaller absolute contributor. Russia has the weakest production trend among the major producers, with a likely 4.6% gain between 2010 and 2020.

Table: CEE Oil Production (000b/d)

Country 2013f 2014f 2015f 2016f 2017f 2018f 2019f 2020f

Azerbaijan 1,385 1,395 1,425 1,450 1,450 1,395 1,350 1,295

Bulgaria 3 3 3 3 2 2 2 2

Croatia 21 20 20 19 19 18 17 16

Czech Republic 8 8 7 7 7 7 6 6

Hungary 28 26 24 22 20 20 18 18

Kazakhstan 1,900 2,050 2,300 2,350 2,400 2,400 2,350 2,300

Poland 30 29 27 26 24 23 22 21

Romania 80 77 71 65 60 60 53 48

Russia 10,395 10,499 10,604 11,000 11,000 10,945 10,890 10,836

Slovakia 3 3 2 2 2 2 1 1

Slovenia 50 47 44 40 36 32 30 26

Turkmenistan 310 350 375 368 360 353 346 339

Turkey 90 86 81 77 73 70 66 63

Ukraine 97 95 95 93 91 89 88 86

Uzbekistan 14,400 14,686 15,078 15,521 15,545 15,416 15,239 15,056

Regional total 1,385 1,395 1,425 1,450 1,450 1,395 1,350 1,295

f = forecast. All forecasts: BMI.

Russia Oil & Gas Report Q2 2011

Regional Refining Capacity

CEE is set for a 22.1% increase in crude distillation capacity between 2010 and 2020, contributing to the expansion of the world’s over-stretched refining industry. Cheap and plentiful local crude supplies help make it a region of choice for refinery investment, although government control of the downstream industry will need to be eased. Kazakhstan, Russia, Poland, Turkey and Bulgaria have particularly ambitious expansion plans, reflecting either crude output growth or local demand expansion. The region should increase in importance as a net exporter of refined products.

Table: CEE Oil Refining Capacity (000b/d)

Country 2013f 2014f 2015f 2016f 2017f 2018f 2019f 2020f

Azerbaijan 442 442 442 442 442 742 742 742

Bulgaria 177 177 207 247 247 247 247 247

Croatia 250 250 250 250 250 250 250 250

Czech Republic 183 183 183 223 223 223 223 223

Hungary 161 161 161 161 161 161 161 161

Kazakhstan 348 348 348 348 348 348 348 348

Poland 578 578 578 678 678 678 678 678

Romania 537 537 537 537 537 537 537 537

Russia 5,763 5,763 5,813 5,813 5,813 5,913 5,913 5,913

Slovakia 121 121 121 121 121 121 121 121

Slovenia na na na na na na na na

Turkey 613 813 813 1,013 1,013 1,013 1,623 1,623

Turkmenistan 275 275 275 275 375 375 375 375

Ukraine 880 880 880 880 880 880 880 880

Uzbekistan 224 224 224 224 224 224 224 224

Regional Total 10,552 10,752 10,832 11,212 11,312 11,712 12,322 12,322

f = forecast. na = not applicable. All forecasts: BMI.

Russia Oil & Gas Report Q2 2011

Regional Gas Demand

Gas demand growth could slow somewhat between 2015 and 2020, when compared with the 17.5% rate expected for the 2010-2015 period. There is likely to be some 15.1% gas market expansion in the region in the final five years of the period. Expansion of gas consumption is expected to be at its greatest in Turkmenistan, Bulgaria, Kazakhstan and Poland. Russia is likely to lag the field.

Table: CEE Gas Consumption (bcm)

Country 2013f 2014f 2015f 2016f 2017f 2018f 2019f 2020f

Azerbaijan 10.5 11.0 11.6 12.2 12.8 13.4 14.1 14.8

Bulgaria 4.5 4.7 5.0 5.2 5.5 5.7 6.0 6.3

Croatia 4.2 4.3 4.5 4.7 4.9 5.1 5.3 5.5

Czech Republic 10.4 11.0 11.4 12.0 12.4 12.5 13.0 13.5

Hungary 12.3 13.0 14.0 15.0 15.5 15.9 16.5 17.0

Kazakhstan 27.3 28.7 30.1 31.6 33.2 34.8 36.6 38.4

Poland 16.5 17.5 18.0 18.6 19.1 19.7 20.3 20.9

Romania 15.1 15.6 16.2 16.8 17.4 18.0 18.6 19.2

Russia 417.0 418.0 426.4 434.9 443.6 452.5 461.5 470.7

Slovakia 6.6 6.7 7.0 7.4 7.4 7.8 8.2 8.6

Slovenia 1.3 1.3 1.4 1.5 1.5 1.6 1.7 1.8

Turkey 42.0 44.5 50.0 52.0 55.0 57.0 60.0 62.0

Turkmenistan 26.4 28.4 30.6 32.8 35.3 38.0 40.8 43.9

Ukraine 51.6 52.9 54.2 55.6 56.9 58.4 59.8 61.3

Uzbekistan 53.3 54.6 56.0 57.4 58.8 60.3 61.8 63.4

Regional Total 698.9 712.3 736.3 757.5 779.2 800.6 824.1 847.3

f = forecast. All forecasts: BMI.

Russia Oil & Gas Report Q2 2011

Regional Gas Supply

A production increase of 12.5% is forecast for CEE in 2015-2020, representing a deceleration compared with the 21.1% predicted during the 2010-2015 period. Kazakhstan’s explosive growth in the first half of the forecast period is not sustainable, with volumes set to rise 21.2% in 2015-2020, compared with a growth rate of 65.0% in 2010-2015. Russia is still the key player in the region, with gas output rising 23.2% between 2010 and 2020. Turkmenistan’s supply is expected to increase by 115.4% over the same period.

Table: CEE Gas Production (bcm)

Country 2013f 2014f 2015f 2016f 2017f 2018f 2019f 2020f

Azerbaijan 21.0 21.0 21.0 22.0 32.0 32.0 32.0 32.0

Bulgaria 1.1 1.5 1.4 1.3 1.3 1.2 1.1 1.0

Croatia 3.0 3.0 3.0 2.8 2.7 2.6 2.5 2.3

Czech Republic 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

Hungary 2.0 2.0 2.0 1.8 1.8 1.6 1.5 1.0

Kazakhstan 60.0 64.0 66.0 70.0 73.0 75.0 77.0 80.0

Poland 4.5 4.5 4.3 4.2 4.0 3.7 3.5 4.0

Romania 8.8 8.6 8.3 8.0 7.7 7.2 6.7 6.0

Russia 620.0 635.0 650.0 652.0 655.0 670.0 681.0 690.0

Slovakia na na na na na na na na

Slovenia 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

Turkey 1.2 2.0 2.0 1.8 1.5 1.0 1.0 1.0

Turkmenistan 74.0 90.0 90.0 95.0 95.0 100.0 125.0 140.0

Ukraine 21.0 21.0 20.0 20.0 20.0 18.0 17.0 16.0

Uzbekistan 81.0 83.5 86.0 89.0 92.0 95.0 100.0 100.0

Regional total 897.9 936.4 954.2 968.1 986.2 1,007.5 1,048.5 1,073.5

f = forecast. na = not applicable. All forecasts: BMI.

Russia Oil & Gas Report Q2 2011

Russia Country Overview

Between 2010 and 2020, we are forecasting an increase in Russian oil production of .5%, with output rising slowly from an estimated 10.28mn b/d in 2010 to a peak of 11.00mn b/d in 2016/17, before easing to 10.84mn b/d by 2020. Oil consumption during the period is forecast to rise by 28.3%, permitting exports peaking at 7.59mn b/d in 2016. Gas consumption is expected to be up from an estimated 396bcm to 471bcm by 2020, providing export potential peaking at 224bcm in 2015.

Methodology And Risks To Forecasts

In terms of oil and gas supply, as well as refining capacity, the projections are wherever possible based on known development projects, committed investment plans or stated government/company intentions. A significant element of risk is clearly associated with these forecasts, as project timing is critical to volume delivery. Our assumptions also take into account some third-party estimates, such as those provided by the US-based Energy Information Administration (EIA), the International Energy Agency (IEA), the Organisation of the Petroleum Exporting Countries (OPEC) and certain consultants’ reports that are in the public domain. Reserves projections reflect production and depletion trends, expected exploration activity and historical reserves replacement levels. We have assumed flat oil and gas prices throughout the extended forecast period, but continue to provide sensitivity analysis based on higher and lower price scenarios. Investment levels and production/reserves trends will of course be influenced by energy prices. Oil demand has provide itself to be less sensitive to pricing than expected, but will still have some bearing on consumption trends. Otherwise, we have assumed a slowing of GDP growth for all countries beyond our core forecast period (to 2015) and a further easing of demand trends to reflect energy-saving efforts and fuels substitution away from hydrocarbons. Where available, government and third-party projections of oil and gas demand have been used to cross check our own assumptions.

Russia Oil & Gas Report Q2 2011

Glossary Of Terms

AOR additional oil recovery JPDA joint petroleum development area APA awards for predefined areas KCTS Kazakh Caspian Transport System API American Petroleum Institute km kilometres bbl barrel LAB linear alkyl benzene bcm billion cubic metres LDPE low density polypropylene b/d barrels per day LNG liquefied natural gas bn billion LPG liquefied petroleum gas boe barrels of oil equivalent m metres BTC Baku-Tbilisi-Ceyhan Pipeline mcm thousand cubic metres BTU British thermal unit Mcm mn cubic metres capex capital expenditure MEA Middle East and Africa CBM coal bed methane mn million CEE Central and Eastern Europe MoU memorandum of understanding CPC Caspian Pipeline Consortium mt metric tonne CSG coal seam gas MW megawatts DoE US Department of Energy na not available/ applicable EBRD European Bank for Reconstruction and Development NGL natural gas liquids EEZ exclusive economic zone NOC national oil company e/f estimate/forecast OECD Organisation for Economic Cooperation and Development EIA US Energy Information Administration OPEC Organization of the Petroleum Exporting Countries EM emerging markets PE polyethylene EOR enhanced oil recovery PP polypropylene E&P exploration and production PSA production sharing agreement EPC engineering, procurement and construction PSC production sharing contract EPSA exploration and production sharing agreement q-o-q quarter-on-quarter FID final investment decision R&D research and development FDI foreign direct investment R/P reserves/production FEED front-end engineering and design RPR reserves to production ratio FPSO floating production, storage and offloading SGI strategic gas initiative FTA free trade agreement SoI statement of intent FTZ free trade zone SPA sale and purchase agreement GDP gross domestic product SPR strategic petroleum reserve G&G geological and geophysical t/d tonnes per day GoM Gulf of Mexico tcm trillion cubic metres GS geological survey toe tonnes of oil equivalent GTL gas-to-liquids conversion tpa tonnes per annum GW gigawatts TRIPS Trade-Related Aspects of Intellectual Property Rights GWh gigawatt hours trn trillion HDPE high density polyethylene TTPC Trans-Tunisian Pipeline Company HoA heads of agreement TWh terawatt hours IEA International Energy Agency UAE United Arab Emirates IGCC integrated gasification combined cycle USGS US Geological Survey IOC international oil company WAGP West African Gas Pipeline IPI Iran-Pakistan-India Pipeline WIPO World Intellectual Property Organization IPO initial public offering WTI West Texas Intermediate JOC joint operating company WTO World Trade Organization AOR additional oil recovery JPDA joint petroleum development area

Russia Oil & Gas Report Q2 2011

Oil And Gas Ratings: Revised Methodology

Introduction

BMI has revised the methodology of its Oil & Gas Business Environment Ratings. Our approach has been threefold. First, we have disaggregated the upstream (oil/gas E&P) and downstream (oil refining and marketing, gas processing and distribution), enabling us to take a more nuanced approach to analysing the potential within each segment, and the different risks along the value chain. Second, we have identified objective indicators that may serve as proxies for issues/trends that were previously evaluated on a subjective basis. Finally, we have used BMI’s proprietary Country Risk Ratings (CRR) in a more refined manner in order to ensure that only those risks most relevant to the industry have been included. Overall, the new ratings system – which is now integrated with those of all 16 industries covered by BMI – offers an industry-leading insight into the prospects/risks for companies across the globe.

Ratings Overview

Conceptually, the new ratings system is organised in a manner that enables us clearly to present the comparative strengths and weaknesses of each state. As before, the headline Oil & Gas BER is the principal rating. However, the differentiation of Upstream/Downstream and the articulation of the elements that comprise each segment enable more sophisticated conclusions to be drawn, and also facilitate the use of the ratings by clients, who will have varying levels of exposure and risk appetite for their operations.

Oil & Gas Business Environment Rating: This is the overall rating, which comprises 50% Upstream BER and 50% Downstream BER:

Upstream Oil & Gas Business Environment Rating: This is the overall Upstream rating which is composed of limits/risks (see below);

Downstream Oil & Gas Business Environment Rating: This is the overall Downstream rating which comprises limits/risks (see below).

Both the Upstream BER and Downstream BER are composed of Limits/Risks sub-ratings, which themselves comprise industry-specific and broader Country Risk components:

Limits of Potential Returns: Evaluates the sector’s size and growth potential in each state, and also broader industry/state characteristics that may inhibit its development;

Russia Oil & Gas Report Q2 2011

Risks to Realisation of those Returns: Evaluates both Industry-specific dangers and those emanating from the state’s political/economic profile that call into question the likelihood of expected returns being realised over the assessed time period.

Table: BMI Oil And Gas Business Environment Ratings: Structure

Component Details

Oil & Gas Business Environment Rating Overall rating

- Upstream BER 50% of O&G BER

- Limits of Potential Returns - 70% of Upstream BER

- Upstream Market - 75% of Limits

- Country Structure - 25% of Limits

- Risks to Realisation of Potential Returns - 30% of Upstream BER

- Industry Risks - 65% of Risks

- Country Risks - 35% of Risks

- Downstream BER 50% of O&G BER

- Limits of Potential Returns - 70% of Downstream BER

- Upstream Market - 75% of Limits

- Country Structure - 25% of Limits

- Risks to Realisation of Potential Returns - 30% of Downstream BER

- Industry Risks - 60% of Risks

- Country Risks - 40% of Risks

Source: BMI

Russia Oil & Gas Report Q2 2011

Indicators

The following indicators have been used. Overall, the rating uses three subjectively measured indicators, and 41 separate indicators/datasets.

Table: BMI Oil And Gas Business Environment Upstream Ratings: Methodology

Indicator Rationale

Upstream BER: Limits to potential returns

Upstream Market

Resource base

Indicators used to denote total market potential. High values are given better - Proven oil reserves (mn bbl) scores.

- Proven gas reserves (bcm)

Growth outlook

Indicators used as proxies for BMI’s market assumptions, with strong growth - Oil production growth (2009-2014) accorded higher scores.

- Gas production growth (2009-2014)

Market maturity

Indicator used to denote whether industries are frontier/emerging/developed or mature markets. Low existing exploitation in relation to potential is - Oil reserves/ production accorded higher scores.

- Gas reserves/ production

- Current oil production vs. peak

- Current gas production vs. peak

Country structure

Indicator used to denote opportunity for foreign NOCs/IOCs/Independents. State ownership of assets, % Low state ownership scores higher.

Indicator used to denote market competitiveness. Presence (and large Number of non-state companies number) of non-state companies scores higher.

Upstream BER: Risks to potential returns

Industry Risks

Subjective evaluation of government policy towards sector against BMI- Licensing terms defined criteria. Protectionist states are marked down.

Subjective evaluation of government industry orientation. Protectionist states Privatisation trend are marked down.

Country Risk

Rating from BMI’s CRR. It evaluates the constraints imposed by power, Physical Infrastructure transport & communications infrastructure.

Rating from BMI’s CRR It evaluates the risk of a sharp change in the broad Long Term Policy Continuity Risk direction of government policy.

Russia Oil & Gas Report Q2 2011

Table: BMI Oil And Gas Business Environment Upstream Ratings: Methodology

Indicator Rationale

Rating from BMI’s CRR. It evaluates the government’s ability to enforce its Rule of Law will within the state.

Rating from BMI’s CRR, to denote risk of additional illegal costs/possibility of opacity in tendering/business operations affecting companies’ ability to Corruption compete.

Source: BMI

Table: BMI Oil And Gas Business Environment Downstream Ratings: Methodology

Indicator Rationale

Downstream BER: Limits to potential returns

Downstream Market

Market

Indicator denotes existing domestic oil processing capacity. High capacity is Refining capacity (000b/d) considered beneficial.

Indicator denotes size of domestic oil/gas market. High values are accorded Oil demand (000b/d) better scores.

Gas demand (bcm)

Indicator denotes fuels retail market penetration; low penetration scores Retail outlets/1,000 people highly.

Growth outlook

Indicators used as proxies for BMI’s market assumptions, with strong growth Oil demand growth (2009-2014) accorded higher scores.

Gas demand growth (2009-2014)

Refining capacity growth (2009-2014)

Import dependence

Refining capacity vs. oil demand, % Indicators denote reliance on imported oil products and natural gas. Greater (2009-2014) self-sufficiency is accorded higher scores.

Gas demand vs. gas supply, % (2009-2014)

Country structure

Indicator used to denote opportunity for foreign NOCs/IOCs/Independents. State ownership of assets, % Low state ownership scores higher.

Indicator used to denote market competitiveness. Presence (and large No. of non-state companies number) of non-state companies scores higher.

Data from BMI’s CR team. Indicators used as proxies for overall market size Population, mn and future potential.

Nominal GDP, US$bn

GDP per capita, US$

Russia Oil & Gas Report Q2 2011

Table: BMI Oil And Gas Business Environment Downstream Ratings: Methodology

Indicator Rationale

Downstream BER: Risks to potential returns

Industry Risks

Subjective evaluation of government policy towards sector against BMI- Regulation defined criteria. Bureaucratic/intrusive states are marked down.

Subjective evaluation of government industry orientation. Protectionist states Privatisation trend are marked down.

Country Risk

Rating from BMI’s CRR. It evaluates the risk of a sharp change in the broad Short Term Policy Continuity Risk direction of government policy.

Rating from BMI’s CRR. It evaluates the vulnerability to external economic Short Term Economic External Risk shock, the typical trigger of recession in Emerging Markets.

Rating from BMI’s CRR. It evaluates the current trajectory of growth and the Short Term Economic Growth Risk state’s position in the economic cycle.

Rating from BMI’s CRR. It evaluates the government’s ability to enforce its Rule of Law will within the state.

Rating from BMI’s CRR, to denote risk of additional illegal costs/possibility of opacity in tendering/business operations affecting companies’ ability to Legal Framework compete.

Rating from BMI’s CRR. It evaluates the constraints imposed by power, Physical Infrastructure transport & communications infrastructure.

Russia Oil & Gas Report Q2 2011

BMI Methodology

How We Generate Our Industry Forecasts

BMI's industry forecasts are generated using the best-practice techniques of time-series modelling. The precise form of time-series model we use varies from industry to industry, in each case being determined, as per standard practice, by the prevailing features of the industry data being examined. For example, data for some industries may be particularly prone to seasonality, meaning seasonal trends. In other industries, there may be pronounced non-linearity, whereby large recessions, for example, may occur more frequently than cyclical booms.

Our approach varies from industry to industry. Common to our analysis of every industry, however, is the use of vector autoregressions. Vector autoregressions allow us to forecast a variable using more than the variable's own history as explanatory information. For example, when forecasting oil prices, we can include information about oil consumption, supply and capacity.

When forecasting for some of our industry sub-component variables, however, using a variable's own history is often the most desirable method of analysis. Such single-variable analysis is called univariate modelling. We use the most common and versatile form of univariate models: the autoregressive moving average model (ARMA).

In some cases, ARMA techniques are inappropriate because there are insufficient historical data or data quality is poor. In such cases, we use either traditional decomposition methods or smoothing methods as a basis for analysis and forecasting.

It must be remembered that human intervention plays a necessary and desirable part of all our industry forecasting techniques. Intimate knowledge of the data and industry ensures we spot structural breaks, anomalous data, turning points and seasonal features where a purely mechanical forecasting process would not.

Energy Industry

There are a number of principal criteria that drive our forecasts for each Energy indicator.

Energy Supply Supply of crude oil, natural gas, refined oil products and electrical power is determined largely by investment levels, available capacity, plant utilisation rates and national policy. We therefore examine:

Russia Oil & Gas Report Q2 2011

National energy policy, stated output goals and investment levels;

Company-specific capacity data, output targets and capital expenditures, using national, regional and multinational company sources;

International quotas, guidelines and projections, such as OPEC, IEA, EIA.

Energy Consumption A mixture of methods is used to generate demand forecasts, applied as appropriate to each individual country:

Underlying economic (GDP) growth for individual countries/regions, sourced from BMI published estimates. Historic relationships between GDP growth and energy demand growth at an individual country are analysed and used as the basis for predicting levels of consumption;

Government projections for oil, gas and electricity demand;

Third-party agency projections for regional demand, such as IEA, EIA, OPEC;

Extrapolation of capacity expansion forecasts, based on company- or state-specific investment levels.

Cross Checks

Whenever possible, we compare government and/or third party agency projections with the declared spending and capacity expansion plans of the companies operating in each individual country. Where there are discrepancies, we use company-specific data as physical spending patterns to ultimately determine capacity and supply capability. Similarly, we compare capacity expansion plans and demand projections to check the energy balance of each country. Where the data suggest imports or exports, we check that necessary capacity exists or that the required investment in infrastructure is taking place.

Sources

Sources include those international bodies mentioned above, such as OPEC, IEA, and EIA, as well as local energy ministries, official company information, and international and national news agencies.