Nomura Alternative Energy Global

2 July 2010 Nomura

N O M U R A I N T E R N A T I O N A L ( H K ) L I M I T E D

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Nomura Anchor Reports examine the key themes and value drivers that underpin our sector views and stock recommendations for the next 6 to 12 months.

Any authors named on this report are research analysts unless otherwise indicated. See the important disclosures and analyst certifications on pages 349 to 352.

Alternative Energy | G L O B A L

POWER & UTILITIES

Clarisse Pan +852 2252 2192 [email protected]

And the Global Utilities and Renewables Research Team

Green light for value Given steep YTD declines globally in the shares of many alternative energy companies, we see attractive investment opportunities as cost reduction is encouraging demand and government stimulus has only just begun. Of the US$177bn pledged towards investment in renewable energy and energy efficiency measures by governments worldwide, only 14% was utilised in 2009. That said, growth trends are asymmetric across subsectors and not every inexpensive stock is undervalued. In this first-ever global collaborative report, Nomura analysts look at the entire spectrum of alternative energy to identify shifts in the operational outlook in each subsector and highlight the best investment ideas in our coverage. Our conclusions: wind and nuclear remain the technology of choice for renewable energy in emerging countries. Chinese mid to down stream solar should benefit as European players look to outsourcing to maintain profitability. We also like European polysilicon players and European solar equipment manufacturers. Chinese wind component manufacturers with export and offshore potential should find themselves in a sweet spot. China, India, Japan and Korea are set to lead the nuclear renaissance, followed by Russia and the US. We also find potential in geothermal and CBM in Asia, and CSP and small nuclear reactors in developed countries.

Investment opportunities

Shifts we see

Crystal ball gazing

Key beneficiaries: solar, wind, utilities and capital goods

RUNNING

THEME

Analysts Clarisse Pan +852 2252 2192 [email protected] Ivan Lee, CFA Head of Asia Power, Utilities, and Renewable Energy +852 2252 6213 [email protected] Manu Singh +91 22 4053 3696 [email protected] Martin Young Head of European Utilities & Renewables +44 20 7102 1536 [email protected] Catharina Saponar, CFA +44 20 7102 1231 [email protected]

Shigeki Matsumoto, CFA (Japan) +81 3 5255 1605 [email protected]

2 July 2010 Nomura 1

Alternative Energy | G L O B A L

POWER & UTILITIES


And the Global Utilities and Renewables Research Team

Action While we expect a rebound in clean energy investments in 2010F and 2011F, we

recommend a selective approach for stock picks given shifts in policies, demand growth among geographies and technology/manufacturing bases. We like Chinese manufacturers with cost leadership and export capability, and European and Japanese manufacturers for high-quality materials/equipment and nuclear utilities.

Catalysts Government policy support, cost-down efforts for better economics, easier access

to project financing, grid and power storage technology development.

Anchor themes

Global new energy demand growth is shifting from Europe to Asia and the US, with wind power remaining the technology of choice, followed by nuclear and solar. Lower-cost Chinese producers should continue to gain global share, while Europe and Japan remain major suppliers of technologies and high-end products.

Green light for value Investment opportunities

Performance of clean energy stocks, especially solar, has been lacklustre YTD, owing to uncertainties over government subsidy plans, looming feed-in tariff (FIT) cuts, volatile currency exchange rates and difficulty in project funding. Nonetheless, given the expected funding from government stimulus plans, combined with expected demand driven by falling ASPs of clean energy technologies and steep declines in stock prices of most clean energy companies, we believe that the time is ripe to look at clean energy names for emerging opportunities again.

Shifts we see

We expect Chinese solar companies to benefit from outsourcing, as European players look to outsource to maintain profitability. The global wind turbine manufacturers will be the prime beneficiaries of a global wind recovery. We also like European polysilicon players and solar equipment manufacturers. Chinese wind component manufacturers with export and offshore potential should find themselves in a sweet spot, in our view. China, India, Japan and Korea look set to lead the nuclear renaissance, followed by Russia and the US.

Crystal ball gazing

We believe Germany will lead strong solar PV volume growth in 2010F, while emerging markets will lend support in 2011F. We expect the global wind energy market to register modest growth in 2010F but see a rebound in 2011F. We expect global nuclear capacity to grow by 139-427GW over 2010-30F, from 372GW in 2009. Other clean energy technologies have huge potential, but their time has yet to come, in our view.

Key beneficiaries: solar, wind, utilities and capital goods

Key beneficiaries: 1) solar: JA Solar, Yingli, Wacker Chemie, SMA Solar, Centrotherm and Ulvac; 2) wind: China High Speed (CHST), Vestas and Gamesa; 3) nuclear: KEPCO, Dongfang Electric, Electricité de France (EDF), GDF Suez, E.ON, Toshiba Plant Systems & Services, Hitachi, Toshiba Corp, Tokyo Electric and Kansai Electric; and 4) geothermal: Energy Development Corp.


Stocks for action

Stock RatingPrice

(local)

Price target(local)

JA Solar BUY 4.8 8.0

China High Speed Trans BUY 17.6 23.5

Yingli Green Energy BUY 10.5 23.0

Electricité de France BUY 35.1 53.0

Vestas BUY 286.9 390.0

Wacker Chemie BUY 121.6 145.0

Toshiba Plant Syst & Serv BUY 1,152 1,560

Tokyo Electric Power BUY 2,432 3,500

Energy Development Corp BUY 6.2 6.4

KEPCO BUY 34,000 43,000

GDF Suez BUY 25.6 35.0

China Longyuan* REDUCE 7.8 8.5

Solarworld REDUCE 10.4 9.0

Q-Cells REDUCE 6.2 6.0

Note: 23 June closing prices

* Price target under review

RUNNING THEME

Analysts Clarisse Pan Asia Renewables +852 2252 2192 [email protected] Ivan Lee, CFA Head of Asia Power, Utilities, and Renewable Energy +852 2252 6213 [email protected] Manu Singh (India) +91 22 4053 3696 [email protected] Elaine Wu (HK & China) +852 2252 2194 [email protected] Daniel Raats (SE Asia, Australia) +852 2252 2197 [email protected] Martin Young Head of European Utilities & Renewables +44 20 7102 1536 [email protected] Catharina Saponar, CFA (Europe) +44 20 7102 1231 [email protected] Shigeki Matsumoto, CFA (Japan) +81 3 5255 1605 [email protected] Masaya Yamasaki (Japan) +81 3 5255 0571 [email protected] Tetsuya Wadaki (Japan) +81 3 5255 1797 [email protected] Shigeki Okazaki (Japan) +81 3 5255 1719 [email protected] Ryo Tazaki (Japan) +81 3 5255 1743 [email protected] Keith Nam (Korea) +82 2 3783 2304 [email protected] Sabine Park (Korea) +82 2 3783 2342 [email protected]

Alternative Energy | Global Global Utilities and Renewables Research Team


Contents

Executive summary 6 We see a rebound in clean energy investment in 2010F… 6 … but performance of clean energy stocks has been divergent 6 Shifts and key investment themes 8

Quick overview of different alternative energy technologies 11 Solar: strong volume growth driven by Germany in 2010F while emerging markets lend support in 2011F 11 Wind: growth at 7% y-y and 14% y-y in 2010F and 2011F respectively; China and US maintain dominance 13 Nuclear: capacity could reach 818GW in 2030F, from 372GW in 2009 15 Other technologies: significant potential but their time has yet to come 18

Clean energy investments to bounce back 22 Maximum benefit of green stimulus to accrue in 2010F 22 1Q10 reflects recovery underway 24 China emerges as the new market leader 25 US has recovered since 1Q10… 26 … while Europe turned weaker in 1Q10 26 Wind and solar energy have gained the most traction 27 Economic conditions in Europe remain a concern 27

Global solar PV outlook 29 Global solar demand to grow 55% in 2010F and 29% in 2011F 29 Germany to remain key demand driver but other regions catching up fast 29 Supply surplus to continue into 2H10F and 2011F 31 ASP to fall in 2H10F due to German FIT cut and rising supply 35 Outsourcing to China set to increase 36 Solar policy outlook 36

Global wind power outlook 40 Global wind demand to grow 7% in 2010F and 14% in 2011F 40 Offshore wind markets to take-off 42

Global nuclear power and uranium outlook 49 Current state of nuclear power 49 Russia, US and UK set to lead the non-Asian charge 55 Need for energy diversity and security 57 Uranium: the fuel and its outlook 60

Global outlook for other renewables 66 Other technologies hold significant potential, but their time is yet to come 66 Coal seam gas in Australia 71



China alternative energy 73 China wind power sector 73 China solar photovoltaic sector 84 China hydropower sector 100 China waste management & waste-to-energy sector 106 China bio-energy sector 112

India 117 Wind — the leader in renewable energy in India 117 Solar — India has huge potential 121 Nuclear — significant growth expected in medium term 124

Korea 128 Nuclear power: a government priority 128 Nuclear power capacity to account for 33% by 2022F 128 Nuclear plants under construction 129 Exporting Korea’s nuclear technology overseas 130 US$40bn UAE nuclear power deal 130

Australia 132 Wind — among the best resources worldwide 132 Bio-energy — adding 1GW capacity by 2020F 133 Solar — growth to slow owing to less favourable subsidies 134 Australia’s uranium reserves are the world’s largest 135 Government policy 136

Thailand 139 Background to Thailand’s alternative energy drive 141 Renewable energy to account for 10% of installed capacity by 2022 142 Tariff-driven renewable energy incentives 142 Other measures to encourage renewable energy 145 Laos crucial to Thailand fuel diversification efforts 145 Nuclear planned for 2020, but we are sceptical of execution 147 Industry regulation and planning 147

The Philippines 149 Geothermal and hydro — 34% of generating mix 149 Pro-renewable government policies 149 Feed-in tariffs under discussion 151 Philippines geothermal 151 Philippines hydro electric 155 Philippines nuclear power 157

Indonesia 159 A major geothermal growth node 159



Europe renewable energy 163 Investment thesis and stock picks 163 Drivers of renewables build out 165 Our views on technologies 168 Developments and policies, by country 169

Global nuclear renaissance — Europe Nuclear 177 Nuclear renaissance driven by political, cost and environmental concerns 177 Russia, US and UK set to lead the non-Asian charge 178 Power prices not high enough to set incentives for new builds 178 How to participate — utilities 178 What is driving the nuclear renaissance? 180 Cost overruns are an issue 182 Nuclear issues and policies, by country 184 France — nuclear issues and policies 186 Germany — nuclear issues and policies 188 Russia — nuclear issues and policies 191 UK — nuclear issues and policies 193 US — nuclear issues and policies 196

North America renewables 198 Investment themes and picks 198 Drivers of renewables build 199 Views on technologies 199 Developments and policies 200

Japan alternative energy 204 Promoting nuclear power and renewable energy 204 Promoting nuclear power 208 Maintenance, heavy machinery companies poised to benefit 219 Measures to expand renewable energy 222

Current snapshot of renewable energy 232 Wind: Asia emerges as the new regional leader 235 Solar: Demand from a more diversified country base 236 Nuclear power 237 Other renewable technologies 238



Latest company views 245 Asian companies

Energy Development Corp 246

KEPCO 250

JA Solar 254

Yingli Green Energy 257

LDK Solar 260

China Longyuan Power 263

Suzlon Energy 266

GCL Poly Energy 269

China High Speed Transmission 272

European companies

Electricite De France 277

Fortum Oyj 281

Gamesa Corp Tecnologica Sa 284

Vestas Wind Systems A/S 288

Wacker Chemie Ag 292

Solarworld Ag 295

Centrotherm Photovoltaics Ag 299

EDF Energies Nouvelles Sa 302

Japanese companies

Toshiba Plant Systems & Services 307

Japan Steel Works 311

NPC Incorporated 316

Hitachi 320

Toshiba Corp 324

Ulvac 328

Mitsubishi Heavy Industries 333

Tokyo Electric Power Co 341

Kansai Electric Power Co 345

Also see our report: Solar — Picking the sunny spots (4 Feb, 2010)

Also see our Anchor Report: Asia Pacific Nuclear Power — Asia starts global nuclear chain reaction (25 Jan, 2010)

Also see our report: The nuclear renaissance (15 Jan, 2010)

Also see our Anchor Report: Asia Alternative Energy — Blue sky coming through (29 Jan, 2010)

http://www.nomura.com/research/getpub.aspx?pid=355559






Executive summary

Executive summary Clarisse Pan +852 2252 2192 / [email protected]

Manu Singh +91 22 4053 3696 / [email protected] Ivan Lee, CFA +852 2252 6213 / [email protected]

We see a rebound in clean energy investment in 2010F… Of the total US$177bn pledged towards investment in renewable energy and energy-efficiency measures by governments worldwide, only 14% was utilised in 2009. According to New Energy Finance (NEF), nearly 68% of the clean energy stimulus spending will be spent in 2010F (35%) and 2011F (33%). Consequently, we expect to see government support for clean energy to continue in 2010F and 2011F. According to 1Q10 data released by NEF, investment in clean energy is steadily returning after a decline in 2009. Total new financial investment in clean energy grew 31% y-y in 1Q10 to US$27.3bn from US$20.8bn in 1Q09.

We note that wind energy remained the technology of choice for investors and attracted US$14.1bn in 1Q10, the highest amongst all renewable energy technologies. We believe that along with wind, solar is also attracting significant investor attention. In 1Q10, out of 111 deals by VC/PE, solar accounted for 29 of them, more than two times that of wind, which registered 12 deals.

Exhibit 1. Total new financial investment in clean energy

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New financial investment in clean energy

Four quarter rolling average

(US$bn)

Source: New Energy Finance, Nomura research

Exhibit 2. Total new financial investment in clean energy — 1Q10 vs 1Q09

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Publicmarkets

VC and PE Assetfinancing

Totalinvestment

1Q09 1Q10(US$bn)


… but performance of clean energy stocks has been divergent Contrary to popular wisdom that upticks in clean energy investment should attract investor interest, the story has been just the opposite. We note that performance of clean energy stocks, especially solar, has been lacklustre YTD owing to several factors. Uncertainties over government subsidy plans, looming cuts in feed-in tariffs (FIT) and difficulties in raising funds for renewable energy projects are some of the reasons that have led to negative sentiment, in our view.

According to New Energy Finance, nearly 68% of the clean energy stimulus spending will be spent in 2010F (35%) and 2011F (33%)

Sentiment weighed by uncertainties regarding government subsidy plans, looming FIT cuts and difficulties in raising funds



Exhibit 3. S&P global clean energy index

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(Index=100)

Note: Value on 1 January, 2010 = 100

Source: Bloomberg, S&P, Nomura research

While the investment community has concerns about the negative implications for government subsidies owing to the macro woes in Europe and elsewhere, we note that since in only a few countries are subsidies linked to government budgets (Spain, US), there should not be too much impact from fiscal austerity. In reality, the only area where we see a direct impact is Spain. The government’s decision to review the entire energy/utilities sector will lead to a long period of overhang over tariffs, likely to the end of 2010. A number of European countries have followed suit to Germany’s FIT reduction, but this is on market grounds and a reflection of cost and technology advance rather than fiscal concern.

Similarly, wind energy demand in the US has been affected as falling fossil fuel prices have made wind energy less competitive, especially against natural gas-based power plants. Moreover, US utilities are delaying signing the power purchase agreement (PPA) with wind project developers amid expectations of a further decline in wind turbine generator (WTG) ASP.

Nevertheless, countries across the world remain committed towards clean energy technologies. We note that G-20 countries account for more than 90% of total clean energy investment and over the past five years their investments in clean energy have grown more than five times. Expected clean energy funds from previously announced government stimulus plans, combined with expected demand driven by falling ASPs of clean energy technologies and steep declines in stock prices of most clean energy companies, should make the sector attractive for investment, in our view.

Exhibit 4. Top 10 countries by renewable energy capacity 2009 (GW)

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Source: New Energy Finance, PEW, Nomura research

Exhibit 5. Top 10 countries by renewable installed capacity growth (2005-09)

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-27

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Investor concern on subsidy reduction from Europe

Nevertheless, countries across the world remain committed towards clean energy technologies



Shifts and key investment themes We note that many governments prioritised clean energy in Economic Recovery Funding last year. As the focus is largely on innovators, businesses and installers in 2010F and 2011F, we believe this should help lower the cost of clean energy technologies and pave the way for their wider adoption.

Investors need to be selective in their stock selection and be aware of shifts in policy, demand growth and technology/manufacturing base, among others. In this report, we highlight the key shifts underway in different technologies and regions.

Market:

Global new energy end market demand growth is shifting from Europe to Asia and the US, with wind power continuing to be the technology of choice, followed by nuclear, biomass and solar.

We believe the changing nature of Europe and Japan as a manufacturing and technology location in the broader global sector context, while outsourcing to lower-cost Chinese manufacturers, should increase, owing to pressure on ASPs and margins along the value chain.

Renewable energy as a challenge and opportunity for other sectors.

Policies:

We believe that in the near term, FIT or other financial incentives are critical to trigger demand growth, while national portfolio standards play a significant role in promoting renewable energy, sustaining its growth and attracting investments in the long term. In our view, countries with strong national policies, such as China, Germany and the US, have a higher probability of emerging as market leaders in clean energy technology.

Solar:

Subsidy cuts in European countries should lead to increased outsourcing to China. This should benefit Chinese solar players such as JA Solar, LDK and Renesola, which have exposure to non-brand OEM businesses.

Strong growth in solar end demand, along with solar companies’ focus on cost leadership and efficiency to maintain profitability amidst falling ASPs, should lead to strong order inflows for European solar equipment manufacturers, such as SMA Solar and Centrotherm.

Strong market growth benefits volume plays, namely European polysilicon manufactuers, eg, Wacker Chemie.

Wind:

The timing and speed of the global wind recovery is the most important topic for global turbine manufacturers, in particular Vestas. The swing factor is the recovery in the US, but Asian growth also benefits the global names.

We find Chinese wind gearbox manufacturer CHST in a sweet spot, as it should benefit from its strong position in China — we expect China to remain one of the top wind countries — as well as the company’s export potential due to its cost competitiveness and product quality comparable to international peers.

Europe will be the main growth driver of the offshore wind market and we expect the global offshore market to grow 113% y-y in 2010F and 111% in 2011F. The offshore wind segment will be the next growth driver for the Chinese WTG market as attractive locations for onshore wind farm development have already been exploited. Potential beneficiaries are Vestas and Repower in Europe and Sinovel, China High Speed and Goldwind in China, in our view.

China, Germany and the US have higher probability of emerging as market leaders in clean energy technology

With focus largely on innovators, businesses and installers, we expect lower costs of clean energy technologies



Nuclear: New build in Asia is set to be dominated by China, India, Japan and Korea, while that in the rest of the world is likely to be more widely spread. However, ex Asia, three countries stand out as having significant new build aspirations over the next 15 years. They are Russia, where we see 16GW of capacity additions, the US (12GW) and the UK (10GW).

Key beneficiaries: 1) solar: JA Solar, Yingli, Wacker Chemie, SMA Solar, Centrotherm and Ulvac; 2) wind: China High Speed, Vestas and Gamesa; 3) nuclear: KEPCO, Dongfang Electric, EDF, GDF Suez, E.ON, Toshiba Plant Systems & Services, Hitachi, Toshiba Corp, Tokyo Electric and Kansai Electric; 4) geothermal: Energy Development Corp.

Exhibit 6. Company snapshot

Companies with exposure to solar Ticker Rating

Yingli Green YGE US BUY

JA Solar JASO US BUY

Wacker Chemie WCH GR BUY

REC REC NO BUY

PV Crystaloxx PVCS LN BUY

Renesola SOLA LN BUY

Solar Millennium S2M GR BUY

Centrotherm CTN GR BUY

SMA Solar Technology S92 GR BUY

Ulvac 6728 JP BUY

LDK Solar LDK US NEUTRAL

GCL Poly 3800 HK NEUTRAL

Abengoa ABG SM NEUTRAL

Roth & Rau R8R GR NEUTRAL

Meyer Burger MBTN SW NEUTRAL

Solargiga 757 HK REDUCE

Q-Cells QCE GR REDUCE

Solarworld SWV GR REDUCE

Conergy CGY GR REDUCE

Solon SOO1 GR REDUCE

Manz Automation M5Z GR REDUCE

Companies with exposure to geothermal

Energy Development Corp EDC PM BUY

Source: Nomura research

Exhibit 7. Company snapshot

Companies with exposure to wind Ticker Rating

China High Speed 658 HK BUY

Vestas VWS DC BUY

Gamesa GAM SM BUY

Suzlon SUEL IN NEUTRAL

EDF Energies Nouvelles EEN FP NEUTRAL

China Longyuan 916 HK REDUCE

Companies with exposure to hydro

EGCO EGCO TB BUY

GLOW GLOW TB BUY

RATCH RATCH TB NEUTRAL

China Yangtze Power 600900 CH BUY

Fortum FUM1V FH REDUCE

Electricité de France EDF FP BUY

Companies with exposure to nuclear

KEPCO 015760 KS BUY

E.ON EOAN GR BUY

Electricité de France EDF FP BUY

GDF Suez GSZ FP BUY

Toshiba Plant Systems & Services 1983 JP BUY

Hitachi 6501 JP BUY

Toshiba Corp 6502 JP BUY

Tokyo Electric Power 9501 JP BUY

Kansai Electric Power Co Inc 9503 JP BUY

RWE RWE GR NEUTRAL

Japan Steel Works 5631 JP NEUTRAL

Mitsubishi Heavy Industries 7011 JP NEUTRAL

Fortum FUM1V FH REDUCE




Exhibit 8. Global alternative energy company universe Environmental protection

Waste-to-energy Waste management and recycling Wastewater treatment Forestry

China Everbright International 257 HK Asaka Riken 5724 JP Beijing Capital Co 600008 CH China Grand Forestry Green Res. 910 HK

China Power New Energy Dev 735 HK Centillion Env CENR SP Bio-treat Technology BIOT SP China Timber Resources 269 HK

Covanta CVA US China Boqi Environmental 1412 JP China Everbright International 257 HK Forest Enterprises Australia FEA AU

HKC (Holdings) 190 HK China Ecotek Corporation 1535 TT China Water Affairs Group Ltd 855 HK Fujian Yongan Forestry Group 000663 CH

Tianjin Teda 000652 CH China Metal Recycling (listing pending) 773 HK China Water Industry Group Limited 1129 HK Great Southern GTP AU

Weifu High Tech 000581 CH Ecowise Holdings ECW SP Eguard Resources Development 000826 CH Guangzhao Industrial Forest GIFB SP

Zhongde Waste Tech ZEF GR Enviro-Hub Holding ENVH SP Guangdong Investment 270 HK Gunns Limited GNS AU

PRAJ Industries PRJ IN Epure International EPUR SP Hong Kong and China Gas 3 HK Jilin Forest Industry 600189 CH

Shriram EPC SEPC IN Fujian Longking 600388 CH Hyflux Limited HYF SP Lingui Dev Bhd LING MK

Fujikoh Co 2405 JP NWS Holdings 659 HK Mentiga Corp MENT MK

Air pollution control Hua Xia Healthcare Holdings 8143 HK Sinomem Technology Limited SINO SP Minho Malaysia MIN MK

CO2 Group Ltd COZ AU Insun ENT Co. 060150 KS Tianjin Capital Environmental Protection 1065 HK Samko Timber Ltd SAMKO SP

Eco-Tek Holdings 8169 HK Jiangxi Black Cat Carbon 002068 CH Veolia VIE FP Samling Global 3938 HK

Envair Holding B ENHB MK Keppel Corp Limited KEP SP Wuhan Sanzhen Industry 600168 CH Sumalindo Lestar SULI IJ

Fujian Longking Co Ltd 600388 CH Koentec Co . 029960 KS Xinjiang Tianye Water Saving 840 HK Tekala Corp Bhd TEK MK

Kael Co Ltd 082270 KS Shenzhen Dongjiang Environment 8230 HK Sino-Environment SINE SP TFS Corporation TFC AU

KC Cottrell Co Ltd 009440 KS Takeei Corp 2151 JP Phoslock Water S PHK AU Timberwell Bhd TWB MK

Zhejiang Feida Environment 600526 CH Transpacific Industries Group TPI AU Ion Exchange ION IN Wijaya Baru WIJ MK

Union Steel Hldg USH SP Shriram EPC SEPC IN Willmott Forests WFL AU

Wuhan Kaidi Electric 000939 CH Thermax TMX IN Yunnan Green 002200 CH

Zhejiang Feida Environmental 600526 CH Suez Environnement SEV FP

Zhonghui Holdings ZHL SP

Ion Exchange ION IN

Ecoboard India WBS IN

Clean and renewable

Solar Wind Hydro Nuclear

Cell Gearbox GD Power 600795 CH Nuclear equipment providers

China Sunergy CSUN US China High Speed Transmission 658 HK Guangdong Elec 000539 CH Areva SA CEI FP

E-Ton Solar 3452 TT Hansen Transmission HSN LN Guiguan Power 600236 CH General Electric Co GE US

Gintech 3514 TT Wind Turbine Guizhou Qianyuan Power 002039 CH Harbin Air Conditioning Co 600202 CH

JA Solar JASO US Baoding Tianwei Baobian Electric 600550 CH Hydroogkh HYDR RU Harbin Power Equipment 1133 HK

Motech 6244 TT Clipper CWP LN Inner Mongolia Mengdian 600863 CH Hitachi Limited 6501 JP

Q-Cells QCE GR Dongfang Electric 1072 HK Sichuan Minjiang Power 600131 CH Kajima Corp 1812 JP

Wafer, Cell and Module Gamesa GAM SM Unified Energy EESR RU Kimura Chemical Plants 6378 JP

Trina Solar TSL US Goldwind 002202 CH Yangtze Power 600900 CH Shanghai Electric Group 2727 HK

Yingli Green Energy YGE US Guizhou Changzheng Electric 600112 CH Lanco Infratech LANCI IN BHEL BHEL IN

Cell and Module Huayi Electric 600290 CH Tata Power TPWR IN HCC HCC IN

Canadian Solar CSIQ US Lanzhou Great Wall Electrical 600192 CH L&T LT IN L&T LT IN

Evergreen Solar ESLR US Ningxia Yinxing Energy 000862 CH GMR GMRI IN Toshiba 6502 JP

Solarfun SOLF US Nordex NDX1 GR GVK GVKP IN Toshiba Plant Systems & Services 1983 JP

Sunpower SPWR US Repower RPW GR Fortum FUM1V FH Japan Steel Works 5631 JP

Suntech Power STP US Shanghai Electric 2727 HK Electricité de France. EDF FP Mitsubishi Heavy Industries 7011 JP

Tata Power TPWR IN Suzlon SUEL IN Hydro Equipment Dongfang Electric 1072 HK

BHEL BHEL IN Vestas VWS DC BHEL BHEL IN Shanghai Electric 2727 HK

Moser Baer MBI IN Xiangtan Electric Manufacturing 600416 CH Kirloskar Brother KKB IN Nuclear power producers

XL Telecom XLE IN Shriram EPC SEPC IN Alstom India ABBAP IN CLP Holdings 2 HK

Bharat Electronics BHE IN Blade ABB India ABB IN Datang International 991 HK

Webel SL Energy WSES IN Jiangsu Miracle Logistics System 002009 CH NTPC NATP IN

Wafer Sinoma Science & Technology 002080 CH Tokyo Electric Power 9501 JP

Green Energy 3519 TT Tianjin Xinmao Science & Technology 000836 CH Kansai Electric Power 9503 JP

LDK LDK US Wind Project Operator

MEMC WFR US Acciona ANA SM

Renesola SOL US China Longyuan Power Group 916 HK

Solargiga 757 HK China Power New Energy 735 HK

Wafer Works 6182 TT China Windpower Group 182 HK

Module and System CLP Holdings 2 HK

Aleo Solar AS1 GR Guangdong Baolihua New Energy 000690 CH

Conergy CGY GR HK Electric Holdings 6 HK

Solon SOO1 GR HKC Holdings 190 HK

Fully Integrated Shanghai Huitong Energy Resource 600605 CH

Ersol ES6 GR Shenyang Jinshan Energy 600396 CH

REC REC NO Iberdrola Renovables IBR SM

SolarWorld SWV GR EDF Energies Nouvelles EEN FP

Polysilicon EDP Renovaveis EDPR PL

OCI Company (DC Chem) 010060 KS

Wacker Chemie WCH GR Solar thermal

Equipment Abengoa ABG SM

SMA solar technology SMA GR Solar Millennium S2M GR

Roth & Rau R8R GR

Centrotherm CTN GR

Meyer Burger MBTN SW

Manz automation M5Z GR

Biomass Coal-to-chemical Coalbed methane Natural gas

Bio-fuel producers Baike 000627 CH Caterpillar Inc. CAT US AGL Resources ATG US

Australian Biodiesel Group ABJ AU China Energy Limited CEGY SP Eastern Star Gas Limited ESG AU Atmos Energy ATO US

Australian Renewable Fuels ARW AU Datang International 991 HK Energy Developments Limited ENE AU Cheniere Energy LNG US

China Biodiesel Int'l Holdings CBI LN Lanhua 600123 CH Enric Energy Equipment 3899 HK China Gas 384 HK

Mission Biofuels MBT AU Lutianhua 000912 CH Enviro Energy International 8182 HK CR Gas 1193 HK

Verasun Energy Corp VSE US PetroChina 857 HK Far East Energy Corp FEEC US El Paso EP US

PRAJ Industries PRJ IN Shenhua Ningxia 1088 HK Green Dragon Gas GDG LN Enbridge Energy Partners EEP US

Shriram EPC SEPC IN Sinopec 338 HK Greenpower Energy GPP AU GAIL GAIL IN

Abengoa ABG SM Tiancheng 600392 CH Hong Kong and China Gas 3 HK HKCG 3 HK

Feedstock producers Tianke 600378 CH Karoon Gas Australia Limited KAR AU Korea Gas 036460 KS

Chaoda Modern Agriculture 682 HK Tianranjian 000683 CH Metgasco Limited MEL AU ONGC ONGC IN

China Agri 606 HK Zhongyu Gas Holdings Limited 8070 HK Pacific Asia China Energy Inc. PCE CN Osaka Gas 9532 JP

IOI Corporation IOI MK Xinao Gas Holdings Limited 2688 HK PetroChina 857 HK Perusahaan Gas PGAS IJ

Kuala Lumpur Kepong KLK MK Yanzhou 1171 HK Planet Gas Limited PGS AU Petronas Gas PTG MK

Noble Group NOBL SP JSPL JSP IN Sunshine Gas Limited SHG AU Reliance Industries RIL IN

Sinofert Holdings 297 HK Reliance Industries RIL IN Toho Gas 9533 JP

Wilmar Int'l Limited WIL SP Essar Oil ESOIL IN Tokyo Gas 9531 JP

Xiwang Sugar Holdings 2088 HK ONGC ONGC IN Towngas China 1083 HK

Xinao Gas 2688 HK

Water utilities Energy conservation

Beijing Capital Company 600008 CH Hyflux HYF SP Shanghan Chengtou 600649 CH Environmental Clean Tech ESI AU

Beijing Enterprises Water 371 HK Ion Exchange (India) ION IN Suez Environment SEV FP Environmental Solutions ESWW US

Bio-treat Technology BIOT SP Manila Water Co. Inc MWC PM Sinomem Technology SINO SP Hitachi Zosen 7004 JP

China Boqi Environ. Solutions 1412 JP Pan Asia Environmental 556 HK Tianjin Capital 1065 HK Takuma Co. 6013 JP

China Everbright International 257 HK PBA Holdings Berhad PBAH MK Veolia VIE FP Surya Roshini SYR IN

China Water Affairs 855 HK Puncak Niaga Holdings Bhd PNH MK Woongjin Coway Co Ltd 021240 KS Havells India HAVL IN

China Water Industry 1129 HK Qianjiang Water Resources 600283 CH Xinjiang Tianye Water Saving 840 HK Wipro WPRO IN

Eastern Water EASTW TB Ranhill Berhad RANU MK YTL Power International YTLP MK Battery

Guangdong Investment 270 HK Shanghai Youngsun 900935 CH BYD 1211 HK

Northumbrian Water NWG LNU United Utilities UNN/ LN Exide CHLR IN

Pennon PNN LN Severn Trent SVT LN Source: Nomura research



Sector overview

Quick overview of different alternative energy technologies

Clarisse Pan +852 2252 2192 / [email protected]

Manu Singh +91 22 4053 3696 / [email protected]

Ivan Lee, CFA +852 2252 6213 / [email protected]

Solar: strong volume growth driven by Germany in 2010F while emerging markets lend support in 2011F

Germany to remain key demand driver but other regions catching up fast

We expect global PV demand to grow 55% y-y in 2010F and 29% y-y in 2011F. The rapid growth rate for 2010F owes mainly to Germany, which on our estimates, will contribute 44% of total global capacity addition in 2010F. In addition to Germany, we expect Italy, France and Spain to be the other key demand drivers of the global solar PV market in 2010F. Europe as a region will continue to dominate the global solar PV market and contribute approximately 76% of the global demand in 2010F. However, we are positive that global solar PV demand is becoming more broad-based with the emergence of new countries such as China and the US.

For 2H10F, we are particularly confident about the volume outlook of Chinese solar companies given their cost competitiveness, as well as their improved brand image and product quality. We believe most of the listed companies have already sold out their FY10F available capacity.

For 2011F, we expect annual solar installation in France and Italy to record growth of 65% y-y and 30% y-y, respectively, and partly make up for the decline in solar demand from Germany, for which we expect it to decline by 2% y-y. Along with France and Italy, we see significant growth from emerging markets such as the US and China, which we expect to witness growth of 75% and 90%, respectively, in 2011F. We believe that even after incorporating the proposed and upcoming tariff reductions, returns will still be attractive enough to support a strong solar end market in Europe.

Exhibit 9. Solar demand — annual new installation

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

2003 2004 2005 2006 2007 2008 2009 2010F 2011F

0

20

40

60

80

100

120

140Demand (LHS) Growth y-y (RHS)(MW) (%)

Source: EPIA, Solarbuzz, Nomura estimates

Europe as a region will continue to dominate the global solar PV market

Global solar PV demand is becoming more broad-based with the emergence of new countries such as China and the US



Exhibit 10. Average IRRs for European renewables under current support schemes

Technology Country Average IRRWind Germany 6-8% France 6.5-9% Spain 7-8% Italy 12% UK onshore 9% US – PTC c7% US – cash grant 7-8% Solar Germany 8-10% France 12-16% Spain 12-15% Italy 18-20%


Supply surplus to continue into 2H10F and 2011F

While we see tight supply for wafer and cell in 1H10F, we find that polysilicon supply remains ample due to aggressive capacity expansion by both international incumbents and new entrants in Asia. That being said, we see very high execution risk to these capacities, and have had indications of delays, which could result in the poly market ending up tighter than it might appear at first glance. We believe ASPs of wafers and cells are likely to increase ~5% q-q in 2Q10F, while we only see polysilicon prices stabilising at US$50-55/kg during the same period. We expect polysilicon capacity to grow 40% y-y in 2010F and 30% y-y in 2011F. Consequently, we expect the surplus in polysilicon to continue in 2H10F and 2011F, which should lead to a further price decline, the brunt of which for the tier-2/3 manufacturers — not just in polysilicon but also flowing across the value chain.

Exhibit 11. Polysilicon surplus

(50,000)

0

50,000

100,000

150,000

200,000

250,000

2008 2009 2010F 2011F 2012F

Polysilicon supply

Global demand (solar+semi)

Supply-demand gap

(MT)

Source: Company data, Nomura estimates

Fall in ASPs to continue

With polysilicon ASPs in 2Q10F hovering in the same range (US$50-55/kg) as in 1Q10, we are seeing some stability. Over the remainder of 2010, prices are likely to hold up around the low US$50/kg level for incumbent polysilicon manufacturers while we expect new entrants, such as GCL Poly, to continue lowering prices as production ramp up. Thereafter, we would expect a trajectory towards the US$40-50/kg level in 2011F. European companies are likely to fetch ASPs above average and Chinese ones below average. On account of the polysilicon price decline, the capacity expansion across the value chain and the increased competition due to the entry of new players, we expect to see further ASP declines in wafers, cells and modules in 2010F.

Aggressive polysilicon capacity expansion by both international incumbents and new entrants in Asia

Capacity expansion and growing competition to exert pressure on ASPs of wafer, cell and module in 2010F

Capacity expansion and growing competition to exert pressure on ASPs of wafer, cell and module in FY10F



Outsourcing to China set to increase

We expect high-cost European and Japanese companies to increase outsourcing to China to maintain profit margins. Given the 15-16% FIT reduction in Germany, we expect solar project developers to look for a similar ASP reduction. Tier-one Chinese module companies have significant cost advantages compared with their European peers and hence, can price their modules 15-20% cheaper than their European peers without compromising on quality.

Nomura’s solar stock picks

Within Asia, JA Solar (JASO US, BUY, PT: US$8.00) remains our top pick in the China solar sector in the near term, given its strong earnings momentum over the next few quarters, low exposure to euro depreciation and positive changes in its business model and customer portfolio, which we expect to help a re-rating of the stock. We maintain our BUY on Yingli (YGE US, BUY, PT: US$23.00), given its long-term prospects, brand equity and cost leadership.

We note that Tier-1 European poly manufacturers should benefit from global solar end market volumes, translating into poly volumes growth and from their sustainable competitive advantages in businesses with high barriers to entry. Our preferred picks are Wacker Chemie (WCH GR, BUY, PT: €145) and REC (REC NO, BUY, PT: NOK25). Within the wafer segment, we like Renesola (SOLA LN, BUY, PT: GBp250) for its cost advantages of its Chinese manufacturing. We also think that PV Crystalox (PVCS LN, BUY, PT: GBp78) is well positioned, with the added benefit of selling into the premium Japanese market. Demand growth, which is driving expansion, and the need for innovation, which is driving upgrades and replacements, should translate into strong order flow for Centrotherm (CTN GR, BUY, PT: €40), which is well positioned with a strong high end product portfolio. We also like SMA (S92 GR, BUY, PT: €125) as a direct beneficiary from end market growth due to its manufacturer agnostic inverter business, which is leveraged into end market demand.

Wind: growth at 7% y-y and 14% y-y in 2010F and 2011F respectively; China and US maintain dominance We expect the global annual wind turbine generator (WTG) market to grow 7% y-y in 2010F and 14% y-y in 2011F, with China and the US to remain the top end markets. We expect China and European WTG markets to be the key growth driver for the global market in 2010F and contribute approximately 39% and 29% of the global installation, respectively. A difficult credit environment combined with falling fossil fuel prices would lead to subdued growth in 2010F, in our view. Consequently, we expect the US market to decline 18% y-y in 2010F, but we expect the market to rebound in 2011F and grow 25% y-y.

Exhibit 12. Global WTG market new installation

0

10,000

20,000

30,000

40,000

50,000

60,000

2007 2008 2009 2010F 2011F 2012F

0

5

10

15

20

25

30

35

40

45

Global annual demand (LHS) Growth y-y (RHS)(MW) (%)

Source: BTM Consult ApS, Nomura estimates

Tier-one Chinese module companies have significant cost advantages compared with their European peers

Solar stock picks: JA Solar, Yingli, Wacker Chemie, REC, Renesola, PV Crystalox, Centrotherm and SMA

A difficult credit environment, combined with falling fossil fuel prices should lead to subdued growth in 2010F



Offshore wind markets to take off

We remain positive about the prospects of the offshore wind turbine market and expect growth in this segment to take off. We note that most offshore projects are expected to come up in Europe, especially in Germany and the UK. We expect the offshore wind market to grow 113% y-y in 2010F and 111% in 2011F.

We see the offshore market as a major growth area within the wind segment. This is the case globally, but Europe is a centre of development and will, in our view, witness the most important growth at the early stage. We see offshore wind as an area of significant growth over the next 10-20 years, particularly for those companies with operations in northern Europe, where wind resources offer attractive opportunities.

Within Asia, the offshore wind segment in China should also be the next growth driver for the Chinese WTG market, in our view. According to comments made by wind operators including China Longyuan and China Windpower, a majority of attractive locations for onshore wind farm development have already been occupied by industry players. As a result, we expect offshore wind development to become the next growth driver for the Chinese wind industry over the next three years.

Chinese WTG makers grow global share along with China market, while European WTG makers maintain quality leadership

The entry of three Chinese players – Sinovel, Goldwind and Dongfang – into the top-10 global wind turbine generator suppliers clearly reflects the growing prominence of China in the global wind energy sector. With 13.8GW of new capacity installed, China has become the largest wind market worldwide since 2009. Its cumulative wind capacity grew at an impressive rate of 115% y-y in 2009, thanks to favourable government policies and easier availability of project financing. We note that Chinese wind turbine suppliers control more than 85% of the domestic market and hence the significant growth in the Chinese market has helped Chinese wind turbine suppliers to break into the global league.

We note that international players have entered the Chinese wind turbine market but have been losing market share in the China market. Chinese players are able to price their wind turbines 20-30% cheaper than their international peers, and this gives them a decisive edge when bidding for projects in China. Consequently, Sinovel, Goldwind and Dongfang together gained 10.2% incremental market share of the global wind turbine market at the expense of incumbents in 2009. However, we are observing that the Western quality proposition appears to be gaining ground again and think that Vestas and Gamesa could improve order flows from China. We have recently seen improving order flow for Western manufacturers. We take this as a sign of market opening, as well as a change in customer mentality from pure cost per MW to cost per MWh, and thus expect them to continue making inroads, while Chinese wind companies should maintain dominance in the Chinese market.

We expect the Chinese WTG suppliers, with their superior cost competitiveness and strong funding availability from the mother country, to start to attempt moving towards overseas markets. However, we believe that this would be a long-term process, as the majority of the Chinese WTG suppliers do not have long enough track records and local customer relationships overseas. In our view, the European market leaders will defend their market share through their customer relationships and technological edge. Furthermore, as wind turbine manufacturing needs to take place close to the end markets, Chinese manufacturers would lose their key cost advantages in other regions and competition would move onto a level playing field.

Offshore market the major growth area within the wind segment



Entry of bigger players a welcome change

There has been a shift in the customer base for wind energy towards bigger players, such as power utilities and independent power producers (IPPs) over the past few years. The fact that the market share of the top-15 wind operators has increased to 35% in 2009 from 23% in 2003 is a clear indication of the trend, of which the larger players are beginning to dominate, in our view. We are positive about this shift in customer base as the entry of these bigger players, who have much-deeper pockets, should provide stability in demand.

A shift towards larger-size turbines

The average size of installed wind turbine continues to increase, especially in more developed wind markets such as in European countries. However, the speed of the transition towards larger-sized wind turbines is slow, as most of the new wind turbine suppliers, especially in China, currently provide only smaller-size turbines of around 1.5MW, in our view. Another trend that we are witnessing is that wind turbine suppliers are focusing their research and development efforts on products that can work efficiently in areas which have weaker wind conditions. We note that the key reason for the shift is that areas with stronger wind conditions in most developed wind markets have already been exploited, leaving weaker wind areas for wind farm development.

Nomura’s wind stock picks

Within Asia, CHST (658 HK, BUY, PT: HK$23.50) remains our top pick in the sector for its strong margin outlook, cost-control capability, continuously improving product mix and undemanding-looking valuations.

For Europe, turbine manufacturers are our preferred picks as we see them benefitting from a market leadership position, high-end technology that will be an enabler for levelised cost of energy (LOCE) and broad geographic exposure to global growth with an increased presence in Asia. Vestas (VWS DC, BUY, PT: DKK390) is our top pick.

Nuclear: capacity could reach 818GW in 2030F, from 372GW in 2009 We now expect the next wave of nuclear power plant construction to begin under the backdrop of rising electricity demand and a greater need for low-carbon energy. Based on World Nuclear Association’s (WNA) forecasts, global nuclear capacity will reach 818GW in 2030 (a 4% CAGR from 372GW in 2009) and will represent 16% of total electricity generation (from 14%). This requires an investment of US$1.3tn during the period. Our Nomura global nuclear model suggests a 180GW increase in capacity by 2024F, which is possibly conservative, but still indicates a 48% increase from existing global nuclear capacity. Of this, Asia (China, India and Japan) will likely account for more than half. We note that growing demand for electricity (especially from emerging economies such as China and India), combined with the need for clean energy amid threats of global warming and the need for energy security and diversification, is the key driver for the upcoming growth in nuclear power.

Majority of the new additions to come from Asia

According to the WNA, there is 200GW of nuclear capacity planned or under construction in the world, the majority of which (62%) is in Asia — led by China (28%; 20GW under construction and 37GW planned), India (12%; 3GW and 22GW), Japan (10%; 2.3GW and 18GW) and Korea (7%; 6.7GW and 8.2GW). There were 53 nuclear reactors under construction in the world, with 33 located in Asia.

Wind stock picks: CHST and Vestas

Asia is likely to account for more than half of the 180GW expected rise in capacity by 2024F, in our view



Exhibit 13. Global nuclear power capacity

371 372445

511

380

543

807

0

100

200

300

400

500

600

700

800

900

2008 2010F 2020F 2030F

(GW) Low Case High Case

Source: IAEA

Exhibit 14. Global nuclear power generation

2,598 2,785

3,962

5,930

3,7713,261

2,732

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2008 2010F 2020F 2030F

(TWh) Low Case High Case

Source: IAEA

Uneven uranium distribution prompts increase in cross-border M&A activity

As nuclear power development is picking up speed, uranium demand is set to grow at approximately the same pace as the rise in nuclear power capacity. The increase in demand has seen an expansion in uranium exploration and production. Uranium exploration expenditures in 2006 were US$774mn, a 250% increase from 2004, according to the International Atomic Energy Agency (IAEA).

World-known reserves of uranium (5.5mn tonnes) to 2006 consumption are 100 years, but they are mostly held by Australia (23%), Kazakhstan (15%) and Russia (10%). Because the US, France and Japan have the largest number of nuclear reactors in the world, they make up over 58% of global uranium demand. As China, India, Russia and South Korea have the largest amount of nuclear power capacity in the pipeline; uranium demand growth will be driven mainly by these countries, which also raises concerns about these countries’ fuel security. We believe the mismatch on uranium resources and demand should drive more cross-border M&A and co-operation on uranium to happen.

Uranium spot prices set to rise

Spot uranium per pound U3O8 traded at around US$41 in June 2010.

Nuclear has lowest generation cost

According to a study conducted by International Energy Agency (IEA) and the Nuclear Energy Agency (NEA), which compiled data from 10 countries, the cost of nuclear generation is the cheapest, followed by coal, gas, wind, micro-hydro and solar. Costs of generating electricity depend on some country-specific factors. On average, nuclear power has lower costs than others (coal, gas, on-shore wind), mainly due to its high utilisation, long depreciation period and low O&M costs.

Smaller nuclear reactors attracting attention

Today, due to the high capital cost of large power reactors generating electricity via steam cycles and the need to service small electricity grids under about 4GWe, we see smaller nuclear reactor units being developed. These may be built independently or as modules in a larger complex, with capacity added incrementally as required. Westinghouse's IRIS (International Reactor Innovative & Secure) is an advanced third-generation reactor. A 335MWe capacity is proposed, although it could be scaled down to around 100MWe. For developed countries, small modular units offer the opportunity of building as necessary; for developing countries it may be the only option, because their electric grids cannot take 1,000-plus MWe single units.

We believe the mismatch in uranium resources and demand should drive more cross-border M&A and co-operation



Nomura’s nuclear-related stock picks

We identify AECL (Canada, although up for sale), Areva (France), Atomstroyexport (Russia), GE Hitachi (US, Japan), Mitsubishi Heavy Industries (Japan), and Toshiba (US, Japan) as the companies competing for reactor design and build. We acknowledge that KEPCO (Korea) may participate and be successful in non-Asian tenders, but assume that Chinese providers will stay largely domestically focused for now. A number of European utilities are active in nuclear.

We like EDF, given its future nuclear expansion plan within and outside of France and also due to lifetime extension benefits related to its nuclear portfolio. In addition to EDF, we also like GDF Suez for its lifetime extension benefits of its existing nuclear plants, which can be done at a fraction of the cost of new build.

Within Asia, we like KEPCO, Korea’s consortium leader for overseas nuclear project bids. The KEPCO-led consortium successfully bid for the largest overseas turnkey nuclear power project to date, out of Abu Dhabi, in December 2009. Domestically, 85% of KEPCO’s generating capacity expansion through 2016 will come from nuclear power. An impending fuel cost escalation scheme, which will bring about a tighter, more guaranteed tariff scheme, also reaffirms our BUY rating on KEPCO. Also, Hyundai E&C and Samsung C&T have a stake of 55% and 45%, respectively, in the W7tn UAE nuclear plant-building contract and should see an 8-10% uplift to sales from this project.

We also like Dongfang Electric, which we believe has immediate and the biggest benefit from the robust growth of new energy investment (nuclear and wind) in China. The company currently has a market share of 60% and 15% in nuclear and wind power equipment market in China, respectively. Shanghai Electric (with a market share of 33% in nuclear and 2% in wind), which has partnership with Westinghouse (AP1000), should benefit from growth in 3G nuclear facilities in the longer term. With China’s aggressive capacity growth plans, a focus on nuclear power operators has been the search for uranium.

Two Hong Kong-listed companies, CNNC International and Silver Grant have respectively received investments from China National Nuclear Corp (CNNC) and China Guangdong Nuclear Power Holding Co (CGNPC) (unlisted) with plans to acquire uranium assets overseas. We are also on the lookout for potential listings of China nuclear power operators. CGNPC stated it is targeting an IPO in 2011.

In India, of particular interest to us are Larsen and Toubro, which has formed a JV with Nuclear Power Corporation of India for the manufacturing of nuclear forgings, and Hindustan Construction Company, which has already played a big part in building several of India’s nuclear power plants.

In Japan, we believe Electric power utilities’ increased capital spending will benefit the sales and operating profits of shipbuilding/heavy machinery companies that build thermal and nuclear power plants, other capital goods companies, and electric power plant maintenance companies. We expect a particular boost to earnings at valve manufacturers and plant maintenance companies with a high weighting of sales to electric power companies.

In particular, we focus on two valve manufacturers that also provide maintenance services, Okano Valve Mfg. and Toa Valve Engineering, and three plant maintenance companies, Toshiba Plant Systems & Services, Tokyo Energy & Systems, and Taihei Dengyo Kaisha. These companies generate more than half of their total sales from electric power companies (10/3 estimates), and their earnings should be strong in 11/3 as well.

Nuclear stock picks: EDF, KEPCO



Exhibit 15. Weighting of sales to electric utilities at capital goods companies (10/3 estimates): valve suppliers, maintenance companies lead the pack

0 20 40 60 80 100 120

[6501] Hitachi

[5631] Japan Steel Works

[6502] Toshiba

[7011] Mitsubishi Heavy Industries

[1983] Toshiba Plant Systems & Services

[1968] Taihei Dengyo

[1945] Tokyo Energy & Systems

[6466] Toa Valve Engineering

[6492] Okano Valve Mfg

(%)

Nuclear power

Thermal power, other types

Source: Weighting of sales to electric utilities at capital goods companies (10/3 estimates): valve suppliers, maintenance companies lead the pack

Other technologies: significant potential but their time has yet to come

Bioenergy

We expect China, India and the US to lead the biomass-to-power expansion in the next few decades. In the medium term, the focus for biomass-to-power would be on the decentralised biomass systems, especially at places where feedstock is easily available. We expect biofuel production to grow 6-8% per year and will contribute around 5% of total road transport fuel in 2030F.

Exhibit 16. Biomass-to-power installed capacity

0

40

80

120

160

200

2007 2015F 2020F 2025F 2030F

(GW)

Source: IEA, Nomura estimates

Geothermal

With nearly 8GW of projects under development, we see a lot of interest in geothermal technology due to a combination of base load power, cost competitiveness and zero emissions. According to the International Geothermal Association, installed capacity of geothermal energy is expected to grow more than 70% to 18.5GW by 2015, from 10.7GW in 2009. The US has the largest geothermal capacity, now just over 3GW (28.8% of the world total), followed by the Philippines (1.9GW), Indonesia (1.2GW) and Mexico (1GW). As a global leader in geothermal energy production with expertise throughout the geothermal value chain, we see appreciable scope for EDC to further expand its geothermal energy capacity base over the medium term.

We expect biofuel production to grow 6-8% per year

As a global leader in geothermal energy production, we see appreciable scope for EDC to further expand its geothermal energy capacity base



Exhibit 17. Geothermal installed capacity

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

2003 2004 2005 2006 2007 2008 2009 2010F 2015F

(MW)

Source: IGA, Nomura estimates

Hydropower

According to the IEA, approximately 160GW of hydropower capacity is currently under construction, of which half is in China, while India is constructing 13GW, Russia and Brazil each has about 5GW under construction. There is limited scope for development and expansion of hydropower in Organisation for Economic Co-operation and Development (OECD) countries as the best sites have already been exploited, in our view. In the Philippines, we believe EDC and Aboitiz are well placed to benefit from increased hydroelectric utilisation over the medium term, which should underpin earnings and valuations. In addition, we like China Yangtze Power, the world’s largest hydropower producer with 21GW of capacity on hand, to benefit from the rapid growth of hydropower in China.

Exhibit 18. Hydropower penetration by region

0

10

20

30

40

50

60

70

80

Africa Asia SouthAmerica

Australasia NorthAmerica

Europe

(%)

Source: World Atlas of Hydropower & Dams, Nomura research

Concentrating solar power (CSP)

According to industry estimates (Greenpeace International, SolarPACES, and Estela), cumulative capacity of CSP technology is expected to reach 830GW by 2050F, from around 1GW in 2009, implying a CAGR of 18% over the next 40 years, under the moderate scenario. In our view, among different CSP technologies, “parabolic trough” technology provides peak demand generation and would be the technology of choice. We note that several emerging technologies that promise higher conversion efficiencies and cost-competitive generation have been demonstrated on a smaller scale. These technologies, such as point-focusing power towers and line-focusing Fresnel reflectors, may extend the ability of CSP to provide shoulder or base-load power in addition to peak.



Exhibit 19. CSP technology cumulative growth

0

100

200

300

400

500

600

700

800

900

2009 2010F 2015F 2020F 2025F 2030F 2035F 2040F 2045F 2050F

(GW)

Source: SolarPACES, Estela, Greenpeace, Nomura research

China eyes coal bed methane (CBM) to alleviate energy shortages

China has set an ambitious target to increase coal bed methane (CBM) use to 10bn m3 (or 10% of total gas use) by 2010, from 0.5bn m3 (or 1% of total gas) in 2007. Meanwhile, it targets increasing nationwide proven reserves to 300bn m3 and setting up an integrated industry system by 2010F.

We expect a bright future for the CBM industry in China, mainly because: 1) natural gas shortages will spur CBM demand; 2) there is government support in terms of subsidies and VAT rebates; and 3) the high profitability the business enjoys. At the same time, however, this business is intensive in terms of capital and technology, so players have to come in with strong balance sheets. They also need to have sufficient reserves, execution ability on the operating side and self-owned downstream gas projects.

Exhibit 20. Global CBM resources Exhibit 21. China’s CBM output

40 26

11

120

30

0

20

40

60

80

100

120

140

Russia Australia China US

Explored

10.9 tn m3 is minable reserves

Untapped

Reserve

(trn m3)

110

30

116

0

20

40

60

80

100

120

140

2007 2010F 2015F 2020F

07-10F CAGR: 170%

10-20F CAGR: 28%

CBM output (bn cm)

Source: China's Ministry of Land and Resources, SinoPetro Industrial Express Source: Asia Pulse, NDRC, Nomura research

Coal seam gas in Australia

Current estimates point to Australia benefiting from over 3.2bn boe of coal seam gas (CSG) reserves (2P) in the Surat-Bowen basin, and potentially an equal amount in the deeper and more technically challenging Gunnedah basin. New ventures by AWE could develop shale gas in Australia’s Perth basin, while Santos’ recent announcement points to the potential for 2.5bn boe of unconventional gas possibilities in the Cooper Basin. East coast unconventional gas production is also relatively new with BG Group’s A$5.0bn takeover of Queensland Gas in October 2008, marking the beginning of an era of increased production and global interest in Australia’s CSG basins.

We expect a bright future for the CBM industry in China



Exhibit 22. Australia’s CSG recent market transactions

Date Buyer Seller A$/GJ 2P A$/GJ 3P

2-Jul-09 Santos PEL 238 / 434 2.55 0.66

2-Jul-09 Santos Eastern Star Gas 3.75 0.97

22-Apr-09 Origin Pangaea na 0.57

3-Apr-09 Arrow Tipton West 0.71 0.3

9-Feb-09 BG Group Pure 1.96 0.41

24-Dec-08 AGL Sydney Gas 4.17 3.17

19-Dec-08 AGL PEL 285 2.11 0.97

28-Oct-08 BG Group QGC 1.93 0.75

8-Sep-08 ConocoPhillips Origin Energy 3.01 1.41

20-Aug-08 QGC Sunshine Gas 1.73 0.74

2-Jun-08 Shell Arrow 1.83 0.52

29-May-08 Petronas Santos 3.91 1.31

1-Feb-08 BG Group QGC 1.58 0.67

Average 2.44 0.96

Source: Eastern Star Gas, Deloitte, Nomura research

For more information on nuclear power development, please refer to our Anchor Reports, Asia starts global nuclear chain reaction, 25 January, 2010, by our Asia utilities team, and The nuclear renaissance… coming to a country near you, 18 January, 2010, by our European utilities team.

For more information on alternative energy, please refer to our Anchor Reports, Asia Climate Change — the investors' roadmap to change, 2 July, 2009, and Blue sky coming through, 29 January, 2010.

For more information on water and environmental protection, please refer to our Anchor Report, Flowing strongly, 1 February, 2010.



Investment in alternative energy

Clean energy investments to bounce back


Manu Singh +88 05 33696 / [email protected]

Maximum benefit of green stimulus to accrue in 2010F Of the total US$177bn pledged towards investments in renewable energy and energy-efficiency measures by governments across the world, only 14% was utilised in 2009, as per New Energy Finance (NEF). According to NEF, nearly 68% of the world’s clean energy stimulus funding will be spent in 2010F (35%) and 2011F (33%). This, in our view, speaks directly to government support of clean energy in the next couple years.

We note that the total annual investment in clean energy declined by 6% y-y to US$162bn in 2009, from a peak of US$173bn in 2008. However, we note this is far less than expected when stacked up against NEF’s earlier projection of a 26-32% y-y decline in 2009; we think increased energy investments in Asia are what largely narrowed the gap. We note that China recorded particularly high investments, such as the US$2.6bn IPO of China Longyuan Power, and heavy spending on large-scale solar and wind projects.

Despite a difficult credit environment almost everywhere, we remain optimistic about a rebound in financial investments in clean energy in 2010F. NEF estimates financial investments in clean energy will grow more than 20% y-y to some US$200bn this year. We believe there will be a wide push toward diversifying into cleaner energy sources. A considerable portion of the world now appears willing to adopt strong national policies to reduce global warming and set clean energy incentives for a better and a more sustainable tomorrow.

Exhibit 23. Global annual investments in clean energy

0

50

100

150

200

250

2004 2005 2006 2007 2008 2009 2010F

(10)

0

10

20

30

40

50

60

70

Global annual investment (LHS)

Growth y-y (RHS)

(US$bn) (%)

Source: New Energy Finance (NEF), PEW, Nomura research

Clean energy intersecting with global stimulus packages



Exhibit 24. Distribution of investments in clean energy by sector (2005-09)

0 20 40 60 80 100 120

Argentina

Australia

Brazil

Canada

China

France

Germany

India

Indonesia

Italy

Japan

Mexico

South Africa

South Korea

Spain

Turkey

UK

US

Rest of Europe-27

Others

Biofuels

Solar

Wind

(%)

Source: NEF, PEW, Nomura research

Exhibit 25. Expected clean energy stimulus spending

0

10

20

30

40

50

60

70

2009 2010F 2011F 2012F 2013F

0

5

10

15

20

25

30

35

40

Expected clean energy stimulus spending (LHS)

% of total (RHS)

(US$bn) (%)

Source: NEF, Nomura research



Exhibit 26. Clean energy stimulus by country (2009)

0 10 20 30 40 50 60 70

Canada

Brazil

France

UK

Australia

Germany

Spain

Japan

EU27

S Korea

China

US

(US$bn)


1Q10 reflects recovery underway Based on 1Q10 data released by NEF, we note that investments in clean energy are rebounding steadily after a decline in 2009. Total new financial investments in clean energy grew by 31% y-y to US$27.3bn in 1Q10, from US$20.8bn in 1Q09.

Asset financing continued to be the main form of investment in clean energy, accounting for nearly 82% of total investments. Venture-capital and private-equity funding (VC/PE) investment and public market fund-raising accounted for the rest of the investments in clean energy, contributing 11% and 7%, respectively.

Exhibit 27. New financial investment in clean energy

0

5

10

15

20

25

30

35

40

45

50

1Q04

2Q04

3Q04

4Q04

1Q05

2Q05

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4Q05

1Q06

2Q06

3Q06

4Q06

1Q07

2Q07

3Q07

4Q07

1Q08

2Q08

3Q08

4Q08

1Q09

2Q09

3Q09

4Q09

1Q10

New financial investment in clean energy

Four quarter rolling average

(US$bn)


Exhibit 28. New financial investment in clean energy by investment type

0

5

10

15

20

25

30

35

40

45

50

1Q04

2Q04

3Q04

4Q04

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1Q06

2Q06

3Q06

4Q06

1Q07

2Q07

3Q07

4Q07

1Q08

2Q08

3Q08

4Q08

1Q09

2Q09

3Q09

4Q09

1Q10

Public markets

VC and PE

Asset financing

(US$bn)


1Q10 data reflects a rebound in clean energy investments



Exhibit 29. New financial investment in clean energy (1Q10 vs 1Q09)

0

5

10

15

20

25

30

Publicmarkets

VC and PE Assetfinancing

Totalinvestment

(US$bn)


Exhibit 30. Global asset financing for newly built clean energy assets

0

5

10

15

20

25

30

35

1Q04

2Q04

3Q04

4Q04

1Q05

2Q05

3Q05

4Q05

1Q06

2Q06

3Q06

4Q06

1Q07

2Q07

3Q07

4Q07

1Q08

2Q08

3Q08

4Q08

1Q09

2Q09

3Q09

4Q09

1Q10

(US$bn)


Exhibit 31. Global public markets’ new investments in clean energy

0

3

5

8

10

13

1Q04

2Q04

3Q04

4Q04

1Q05

2Q05

3Q05

4Q05

1Q06

2Q06

3Q06

4Q06

1Q07

2Q07

3Q07

4Q07

1Q08

2Q08

3Q08

4Q08

1Q09

2Q09

3Q09

4Q09

1Q10

(US$bn)


Exhibit 32. Global VC and PE new investments in clean energy

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.51Q

042Q

043Q

044Q

041Q

052Q

053Q

054Q

051Q

062Q

063Q

064Q

061Q

072Q

073Q

074Q

071Q

082Q

083Q

084Q

081Q

092Q

093Q

094Q

091Q

10

(US$bn)


China emerges as the new market leader With total clean energy investments in China growing more than 50% y-y to US$34.6bn in 2009, China has emerged as the market leader in financial investments in clean energy. The Chinese government’s strong policy support to renewable energy and the easy availability of funds are the key factors, in our view, that have propelled China to the leadership position.

We note that China was the largest investor in clean energy globally in 1Q10, with investments of US$6.5bn.

China has become the largest investor in clean energy globally



Exhibit 33. Top-10 countries in clean energy investment (2009)

0

5

10

15

20

25

30

35

40C

hina

Uni

ted

Sta

tes

Uni

ted

Kin

gdom

Res

t of

EU

-27

Spa

in

Bra

zil

Ger

man

y

Can

ada

Ital

y

Indi

a

(US$bn)


US has recovered since 1Q10… Difficult economic and financial market conditions in 2009 took their toll on the US, which sank to second place after having been the global leader here over the past five years. In 2009, clean energy investment declined 42% y-y to US$18.6bn in the US, despite the long-term extension of federal production and investment tax credits, as well as the availability of funds through the American Recovery and Reinvestment Act, which, we believe, helped to stem the decline.

We foresee a recovery in new financial investment in the US, with asset financing in the US rising to US$3.5bn in 1Q10, from US$2.4bn in 4Q09. 1Q10 was the strongest quarter for the US since 2Q09, largely owing to the US$394mn construction debt package for the Alta Wind Energy Centre in Tehachapi, California.

… while Europe turned weaker in 1Q10 Despite the positive clean energy investment momentum in Asia and the US in 1Q10, project investments in Europe declined to US$4bn in 1Q10, from US$6bn in 4Q09 and US$7.6bn in 1Q09, based on NEF data. Credit financing conditions remain difficult in Europe. With the ongoing sovereign debt issues, austerity may take the place of investment in clean energy in the near future.

Exhibit 34. Top-10 countries by renewable energy capacity (2009)

0

10

20

30

40

50

60

Uni

ted

Sta

tes

Chi

na

Ger

man

Spa

in

Indi

a

Japa

n

Res

t of

EU

-27

Ital

y

Fra

nce

Bra

zil

(GW)


Exhibit 35. Top-10 countries by five-year growth in installed capacity (2005-09)

0

50

100

150

200

250

300

Sou

th K

orea

Chi

na

Aus

tral

ia

Fra

nce

Indi

a

Uni

ted

Kin

gdom

Tur

key

Uni

ted

Sta

tes

Can

ada

Res

t of

EU

-27

(%)


Recovery in financial investment underway in the US



Wind and solar energy have gained the most traction We note that wind energy remains the technology of choice for investors, attracting US$14.1bn of investments in 1Q10, the highest figure among all the renewable energy technologies. We believe that wind remains the most bankable clean energy technology, owing to its cost competitiveness and scalability compared with other renewables, and we expect wind energy to lead the investment table in the near future.

Along with wind energy, solar is also attracting investor attention. In 1Q10, of the total 111 deals by VC/PE, solar accounted for 29 deals, against wind at 12. We note that investments in solar energy are quickly catching up with wind energy, and looking at falling module ASPs, improving technology and increasing political support, investments in solar energy could easily surpass wind energy once solar energy achieves grid parity, in our view.

Exhibit 36. Global asset financing for new build clean energy assets by technology (1Q10)

Wind64%

Solar13%

Small hydro8%

Biofuels3%

Biomass and waste

11%

Marine1%


Exhibit 37. Global VC/PE financing in clean energy assets by technology (1Q10)

Wind 25%

Biomass and waste

3%

Small hydro 7%

Biofuels 3%

Energy smart

technologies35%

Others 7%

Solar 17%

Geothermal 3%

Wind 25%

Biomass and waste

3%

Small hydro 7%

Biofuels 3%

Energy smart

technologies35%

Others 7%

Solar 17%

Geothermal 3%


Economic conditions in Europe remain a concern Despite the early progress made in 1Q10, we remain concerned about the fallout from the sovereign debt trouble in Europe for clean energy investments. A decline in tax revenues during the recession and the emergency increase in government spending to prevent depression during 2008-09 have left many government budgets and national debts in a perilous state.

European countries aim to lower their fiscal deficits. Only in a few countries are subsidies linked to government budgets (Spain, the US), thus there should not be too much impact from fiscal austerity, the discussion is open in a number of countries — prompting concern among investors. Over time, we project a period of less generous financial subsidies from European governments. While it is too early to say whether a weaker macro environment will have an immediate impact on clean energy investment, we reckon this could be an overhang for investor sentiment towards the sector in the near term.

Wind is the technology of choice for clean energy investors, but solar gaining traction



Exhibit 38. Cumulative solar PV capacity by region

0

5,000

10,000

15,000

20,000

25,00020

00

2001

2002

2003

2004

2005

2006

2007

2008

2009

ROWEuropeNorth America

(MW)

Source: BP Statistical Review of World Energy 2010, Nomura research

Exhibit 39. Cumulative wind capacity by region

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

North America S.&Cent. America

Europe & Eurasia Middle East

Africa Asia Pacific

(MW)

Source: BP Statistical Review of World Energy 2010, Nomura research

We note that the renewable energy sector is largely policy-driven, rather than market-driven, and the ongoing economic difficulties may jeopardise not only future investments but also announced stimulus packages. We believe recent problems in the Euro zone have increased investors’ risk perception towards renewable energy and any sudden change in existing policies may scare away investors. Moreover, bank lending for clean energy projects, which is already in short supply, could become even more scarce if governments start cutting subsidies and existing feed-in tariffs for renewable energy.

Exhibit 40. Current account balance as % of GDP

(8)

(6)

(4)

(2)

0

2

4

6

8

Ger

man

y

Sw

eden UK

Cze

chR

epub

lic

Fra

nce

Ital

y

Spa

in

2009 2010F

(%)

Source: IMF, Nomura research

Exhibit 41. General government net debt as % of GDP

0

20

40

60

80

100

120

France Germany Italy UK

2009 2010F(%)

Source: IMF, Nomura research



Global outlook

Global solar PV outlook Clarisse Pan +852 2252 2192 / [email protected]

Catharina Saponar, CFA +44 20 710 21231 / [email protected]


Global solar demand to grow 55% in 2010F and 29% in 2011F We expect global PV demand to grow 55% and 29% y-y in 2010F and 2011F, respectively, helped by Germany, Italy and France. Moreover, we foresee strong long-term demand from new markets such as the US (from 2011F) and China. Demand elasticity triggered by a fall in ASP, combined with exceptionally strong demand in Germany, are the key growth drivers in 2010F, in our view. Consequently, global solar PV installed capacity is expected to reach 33.5GW in 2010F and 48GW in 2011F, from 22.3GW in 2009.

Exhibit 42. Solar demand — annual new installation

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

2003 2004 2005 2006 2007 2008 2009 2010F 2011F

0

20

40

60

80

100

120

140

Demand (LHS) Growth y-y (RHS)(MW) (%)

Source: Nomura estimates

Germany to remain key demand driver but other regions catching up fast We expect Germany to be the key demand driver of this growth and contribute 44% of the total global capacity addition in 2010F. Project developers in Germany are looking to complete installation before a 15-16% tariff reduction, hence, demand in Germany is exceptionally strong for 2010F. Consequently, Germany’s annual solar installation is expected to grow 30% to 4.9GW at the least, and potentially more than that. However, after the feed-in tariff cut kicks in during 2H10, we expect demand from Germany to flatten out post-2010F, and annual installation in Germany will likely decline by 2% in 2011F.

We expect Italy, France and Spain to be the other key demand drivers of the global solar PV market in 2010F. Europe as a region will continue to dominate the global solar PV market and contribute approximately 76% of global demand in 2010F. However, we are positive about the fact that global solar PV demand is becoming more broad-based with the emergence of new countries such as China and the US. Supportive government policies, renewable standards at the national and state level, and a steep decline in module ASP are helping the adoption of solar PV technologies in these countries. We expect regional diversification in global solar demand to continue; hence, Europe’s share should decline, in our view.

Germany likely to lead global solar demand in 2010F but other regions catching up fast



Exhibit 43. Global PV demand by country

PV demand in MW 2008 2009 2010F 2011FGlobal capacity 13,347 16,882 20,320 24,417Global production capacity 8,675 10,973 13,208 15,871% growth 26.5 20.4 20.2 Global demand 5,606 7,216 11,206 14,424 % growth 28.7 55.3 28.7-Thin film 901 1,543 2,341 Global demand by region Germany 1,500 3,800 4,940 4,841 % growth 153.3 30.0 (2.0) Italy 258 730 1,095 1,424 % growth 182.9 50.0 30.0 France 46 185 463 763 % growth 302.2 150.0 65.0 Spain 2,511 69 500 500 % growth (97.3) 624.6 0.0 Europe 4,549 5,618 8,524 10,195 % growth 23.5 51.7 19.6 US 342 477 620 1,085 % growth 39.5 30.0 75.0 China 45 160 592 1,125 % growth 255.6 270.0 90.0 Asia 589 842 1,644 2,579 % growth 43.0 95.2 56.9 RoW 126 279 419 565 % growth 121.4 50.0 35.0


Exhibit 44. Europe’s share likely to fall

0

4,000

8,000

12,000

16,000

20,000

2008 2009 2010F 2011F 2012F

60

65

70

75

80

85

Europe annual installation (LHS)

Global annual installation (LHS)

Europe share (RHS)

(MW) (%)


We note that solar companies across the value chain have come out with strong results for 1Q10, thanks to higher-than-expected volume growth and margins. They have also guided positively for 2Q10F. In our view, solid 2H10F operating results especially for the Chinese solar companies would be the result of strong solar demand in Germany at the beginning of 2H10F, followed by rising demand from other European countries that could not secure sufficient supply in 1H10 due to rush demand from Germany.



For 2H10F, we are particularly confident about the volume outlook of Chinese solar companies given their cost competitiveness, as well as their improving brand image and product quality. Euro weakness is, however benefitting European manufacturers over the short term. We believe most of the listed companies have already sold out their 2010F available capacity.

For 2011F, we expect annual solar installation in France and Italy to record y-y growth of 65% and 30%, respectively, and partly make up for the decline in solar demand from Germany which we expect to slip by 2% y-y. Along with France and Italy, we expect significant growth from emerging solar markets such as the US and China, which are expected to grow 75% and 90% in 2011F, respectively.

Exhibit 45. Solar PV demand by country (2011F)

0

1,000

2,000

3,000

4,000

5,000

6,000

Spain RoW France USA China Italy Germany

(MW)


Supply surplus to continue into 2H10F and 2011F While we see tight supply for wafer and cell in 1H10F, we find that polysilicon supply remains ample due to aggressive capacity expansion by both international incumbents and new entrants in Asia. That being said, we see very high execution risk to these capacities, and have had indications of delays, which could result in the poly market ending up tighter than it might appear at first glance. We believe ASPs of wafers and cells are likely to increase ~5% q-q in 2Q10F, while we only see polysilicon prices stabilising at US$50-55/kg during the same period. We expect polysilicon capacity to grow 40% y-y in 2010F and 30% y-y in 2011F. Consequently, we expect the surplus in polysilicon to continue in 2H10F and 2011F, which should lead to a further price decline, the brunt of which for the tier-2/3 manufacturers — not just in polysilicon but also flowing across the value chain.

Exhibit 46. Polysilicon surplus

(50,000)

0

50,000

100,000

150,000

200,000

250,000

2008 2009 2010F 2011F 2012F

Polysilicon supply Global demand (solar+semi)

Supply-demand gap

(MT)

Source: Company data, Nomura estimate

Aggressive polysilicon capacity expansion by both international incumbents and new entrants in Asia



Exhibit 47. Global polysilicon supply

Polysilicon capacity (MT) 2008 2009 2010F 2011F

Wacker Chemie 15,000 18,191 23,165 30,902

% growth 50 21.3 27.3 33.4

REC 6,000 7,640 13,821 20,027

% growth 3 27 81 45

Hemlock 14,500 20,000 25,000 36,000

% growth 32 38 25 44

Tokuyama 5,200 8,200 11,000 14,000

% growth 4 58 34 27

Mitsubishi Materials 2,100 2,250 2,500 2,800

% growth 11 7 11 12

Mitsubishi Polysilicon 1,550 1,600 1,840 2,024

% growth 11 3 15 10

MEMC 8,200 8,500 10,000 15,000

% growth 37 4 18 50

Sumitomo Titanium 1,050 1,200 1,380 1,587

% growth 5 14 15 15

TIER-1 CAPACITY 53,600 67,581 88,706 122,340

% growth 27 26 31 38

TIER-2 CAPACITY 10,200 34,750 37,950 47,550

% growth 0 241 9 25

TIER-3 CAPACITY 17,010 28,160 39,860 43,010

% growth 217 66 42 8

METALLURGICAL SILICON 19,500 25,000 45,000 62,000

% growth 301 28 80 38

TOTAL POLY SI CAPACITY 100,310 155,491 211,516 274,900

% growth 86 55 36 30

Realistic Tier-1 48,240 60,823 79,835 110,106

Realistic Tier-1+2 56,910 90,360 112,093 150,524

Realistic Tier-1+2+3 67,967 108,664 138,002 178,480

Realistic Tier-1+2+3+umg-si 71,867 113,664 147,002 190,880

REALISTIC AVERAGE POLY CAPACITY 71,867 92,765 130,333 168,941

% growth 29 40 30

Total polysilicon demand 75,276 75,621 106,500 130,216


However, we note that there is execution risk attached to some of the Chinese solar polysilicon manufacturers and not all their capacity may come on-stream in time. Our channel checks suggest that some of the Tier-2 Chinese polysilicon manufacturers are finding it difficult to lower their cost below the current ASP and, hence, are incurring losses. This is positive for the European incumbents as the resulting polysilicon surplus should be less than expected and thus lessen pricing pressure. It also underpins their competitive advantage from execution and quality.



Exhibit 48. Cell production by country (2009)

Germany14%

Japan12%

China36%

ROE4%

India2%

Africa & Middle East0%

America4%

Malaysia6%

Taiwan11%

ROA11%

Source: Photon International, Nomura research

After briefly holding back capacity expansion plans in 1H09, solar companies, particularly in Asia resumed expansion and many players across the solar value chain announced plans to increase capacity. Most players operated at full capacity utilisation in 1H10, and our channel check suggests their capacities are fully booked for 2H10F.

In addition to polysilicon, companies across the solar value chain continue to invest in capacity expansion. The expansion is broad-based, comprising companies across different regions. Despite strong demand expected throughout 2010F, we look for the supply surplus to continue until 2011F based on current capacity expansion plans announced by major players across the value chain. We estimate that listed Chinese companies are going to expand wafer capacity by 42% h-h and cell capacity by 73% h-h in 2H10F.

In our view, cost reduction will be the key in deciding tomorrow’s winners in the solar sector. Increase in competition, decline in subsidies and race to reach grid parity are the main drivers for this trend. Given the falling ASPs across the solar value chain, companies are focused on bringing down the cost of production quickly to maintain profitability. At Intersolar, we found that companies are focused on scaling up, increasing efficiency of cells and modules, with a particular focus on cell-to-module efficiency, throughput increase and lowering of capex.

As the solar end market is mostly concentrated in Europe, modules are priced in euro. A weaker euro means lower revenue realisation, which is negative for Chinese solar companies whose revenue is in renminbi. Since material and labour expenses are RMB-denominated, a weaker euro erodes profit margins, given that module ASPs are in euro. Consequently, in the short term, euro depreciation should benefit the European module players. However, we maintain that it is cost leadership and product quality that will determine the winners, in the long term.

Cost leadership to decide tomorrow’s winners in the solar sector



Exhibit 49. Expansion plans announced across the solar value chain

Company Country Announcements

Wacker Germany Plans to expand silicon production from 18,000 tonnes in 2009 to 25,000 tonnes in 2Q10 (+39% y-y)

LDK China Plans to expand wafer production to 2.2GW by 2010 from 1.9GW in 2009 (16% y-y). We expect LDK to reach annual polysilicon installed capacity of 16,000 tonnes by 2011 from 11,000 tonnes currently.

ReneSola China Wafer manufacturing capacity increased to 950MW in 1Q10 from 825MW in 4Q09. Plans to add 260MW by 2Q10, taking total capacity to 1210MW. Polysilicon production expected to reach 1,500-1,700 tonnes in FY10F. Total solar product shipment expected in the range of 1-1.1GW in 2010, recently revised up from 900-950MW.

Gintech Taiwan Plans to expand cell capacity to 1GW by 2011 from 600MW currently.

Sanyo Japan Plans to expand cell/module capacity from 690MW in 2009 to 1.2GW by early 2011 (+74%).

Canadian Solar China Plans to expand module capacity from 820MW at end-2009 to 1GW (+22%), including China and Canada, by mid-2010. It also announced plans to expand cell capacity from 420MW at end-2009 to 700MW by mid-2010F. (+67%).

Trina China Plans to expand cell/module capacity from 600MW in 2009 to 850-950MW by end-2010F.

SMA Germany Plans to expand inverter manufacturing capacity to 11GW by end-FY10.

Juwi Germany Expects its installed base of PV system capacity to increase to 2,000MW by 2012 F from 400MW.

EDF Energies Nouvelles

France Total installed PV capacity at 80MW by end-2009 vs 20MW in 2008. Target to achieve 500MW by end-2012F.

Source: Photon International, Company data, Nomura research

Exhibit 50. Capacity expansion by major wafer manufacturers in Greater China

0

500

1,000

1,500

2,000

2,500

4Q09 1Q10 2Q10F 3Q10F 4Q10F

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Comtec Solar Trina Solargiga

Yingli Renesola GCL Poly

LDK Solar Total

(MW) (MW)


Exhibit 51. Capacity expansion by major cell manufacturers in Greater China

0

200

400

600

800

1,000

1,200

1,400

1,600

4Q09 1Q10 2Q10F 3Q10F 4Q10F

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

Renesola Solarfun E-tonCSIQ Gintech Neo Solar Power

Trina Motech Yingli

Suntech JA Solar Total

(MW) (MW)




ASP to fall in 2H10F due to German FIT cut and rising supply Given the potential delay in Germany’s tariff cut and strong demand from other European countries, we currently see solar ASP holding up well into the early part of 3Q10F. Yet, we see downside risk to 2H10F ASP guidance by companies, especially Chinese solar companies which are guiding for 5-10% h-h ASP decline (in US dollar terms) in 2H10F. We believe this is aggressive given the planned 15-16% German tariff cut and weak euro outlook.

From the high of US$500/kg in 3Q08 to nearly falling 90% to the current spot price of US$50-55/kg in 2Q10F, polysilicon has seen the steepest ASP correction in the solar value chain, resulting in ASP declines across the other segments of the value chain. With polysilicon ASP in 2Q10F hovering at the same range (US$50-55) as in 1Q10, we are seeing some stability. However, looking at upcoming polysilicon capacity, we expect the price to continue its downtrend in 2010F and 2011F. Over the remainder of 2010, prices are likely to hold up around the low US$50/kg level for incumbent polysilicon manufacturers while we expect new entrants, such as GCL Poly, to continue lowering their prices along with their production ramp up. Thereafter, we would expect a trajectory towards the US$40-50/kg level in 2011F. European companies are likely to fetch ASPs above average and Chinese ones below average.

Helped by the polysilicon price decline, capacity expansion across the value chain, and growing competition due to the entry of new players, we expect to see further ASP decline in wafer, cell and module in 2010F. In the short term, we are witnessing tight supply in wafer and cell but looking at the upcoming capacity in the pipeline, we believe the prices will come down. Consequently, we expect to see module ASP decline to US$1.65/w in 2010F. There will continue to be regional differentiation of ASPs.

We believe that Tier-1 Chinese module manufacturers are successfully moving into the high-end module segment, which until recently has been dominated by European module manufacturers. Focus on branding and marketing by Chinese Tier 1 players, combined with successful R&D initiatives to improve module efficiency, are the key reasons for their success, in our view. Consequently, increased competition in the high-end market due to entry of the Chinese Tier 1 player will likely lead to a decline in the premium earned by the European peers.

Exhibit 52. Solar cost decline scenario — Asian case

Best Case Scenario Assumptions 2008 2009 2010F 2011F

Spot Polysilicon Cost (US$/kg) 150 70 45 40

Silicon consumption (g/watt) 6.40 6.21 6.02 5.84

Polysilicon Cost (US$/watt) 0.96 0.43 0.27 0.23

Non-silicon Module Cost (US$/watt) 1.00 0.87 0.78 0.70

Total Module Cost (US$/watt) 2.07 1.43 1.22 1.16

Installation and BOS Cost (US$/watt) 2.00 1.70 1.45 1.23

System Cost (US$/watt) 4.58 3.51 2.99 2.68

Note: We assume no disruptive conversion efficiency improvement


Exhibit 53. GM comparison across the value chain — 2010F

US$/watt Polysilicon Wafer Cell Module

ASP 0.31 0.81 1.18 1.65

COGS 0.21 0.67 0.96 1.20

Gross margin (%) 32.3 17.2 18.6 27.3




Outsourcing to China set to increase China has been the leading manufacturing country for solar photovoltaic (PV) products since 2007. According to Photon International, China accounted for 36% of global solar PV cell production in 2009, up from 33% in 2008, and was more than twice the size of the second-place Germany (15% global share). In 2009, Chinese solar companies Suntech, Yingli, JA Solar, and Trina made it into the global top 10 cell producers, accounting for 5.7%, 4.3%, 4.2%, and 3.2% of global supply, respectively.

Given the 15-16% FIT reduction in Germany, we expected solar project developers to look for ASP reductions, but our channel checks so far suggest less than the headline tariff reduction. Tier-1 Chinese module companies have significant cost advantage over their European peers and, hence, can price their modules 15-20% cheaper than their European peers without compromising on quality. We expect high-cost European and Japanese companies to increase outsourcing to China to maintain profit margins.

We are already witnessing a trend where European module customers are requesting Tier-1 Chinese solar companies such as JA Solar, Renesola, and LDK Solar to manufacture modules for them. The trend of outsourcing to Chinese solar companies enhances their volume outlook as it increases their addressable market size.

We note that solar manufacturers based in Europe and the US are looking to shift their manufacturing base to Asian countries such Malaysia and Singapore. The idea behind this move is to negate the cost advantage enjoyed by Chinese players and to compete more efficiently. However, we do not expect any significant boost to their cost competitiveness by this move given the higher cost incurred during ramp up. Moreover, we believe China enjoys a significant advantage over other Asian countries in terms of a much larger and established manufacturing base, which has given it a head start, relatively inexpensive labour and supportive government policy.

Exhibit 54. Sales growth q-q for Asian and European players

(100)

(50)

0

50

100

150

200

3Q08 4Q08 1Q09 2Q09 3Q09 4Q09 1Q10

Q-Cell SolarWorld Solon

Trina Solar Yingli Green Energy Suntech Power

Motech JA Solar E-Ton Solar

(%)

Source: Company data, Nomura research

Solar policy outlook In our view, recent share price weakness within the solar section reflects market concerns on the fallout of weakening European economies, which could have negative implications for financial subsidies going forward. Nonetheless, given that only in few countries’ subsidies are linked to government budgets (Spain; US), there should not be too much impact from fiscal austerity, although the discussion is open in a number of countries. Over time, we are looking forward to a period of less generous financial subsidies from European governments. While it is too early to see whether a weaker macro environment will have an immediate impact on solar companies’ earnings outlook, we reckon that this could be an overhang to the investment sentiment towards the solar sector in the near term.

Tier-1 Chinese solar companies such as JA Solar, Renesola and LDK Solar to gain from an increase in module outsourcing from Europe

Weaker macro environment in European countries to weigh down solar stocks in the near term



Germany

Germany’s upper house has voted down the subsidy cut, a 15-16% FIT reduction, in Germany leading to a delay in implementation. Earlier Germany’s lower house had passed the subsidy cuts and they were expected to be implemented on 1 July, 2010. We note that the issue will now be settled by a parliamentary mediation committee raising hopes for a slight decrease in the rate of cut. We believe the chance of scaling down the subsidy cut appears slim but any reduction would be positive for the sector. Earlier, Germany’s lower house had passed the law implementing a 16% decrease for rooftops, 11% for reconversion areas, 15% for the other installations and no more feed-in tariff for PV installations on agricultural land.

Spain

According to government sources, Spain will be following Germany’s footsteps and is expected to sharply cut to its solar subsidy programme. According to a Reuters news item of 16 June, 2010, for big floor-mounted units Spain is looking to implement a 30% subsidy cut for the existing solar panel plants and 45% for future solar plants, while a subsidy cut for smaller roof mounted is expected to be 25%. Meanwhile, the government has announced a full review of the utilities sector, which, in our view, means that it will take into late 2010 at best for an update on the renewables regime.

Italy

The current feed-in tariff scheme will end on 31 December, 2010, and a new regime will be in place from 2011. The latest draft for a follow-up regime, which was released in early February, contains a total of 42 different tariffs, depending on system type and power classification. It also includes three tariff reduction stages staggered throughout 2011, after which point cuts of 6% would take effect in 2012 and 2013. Moreover, the draft law contains regulations that anticipate solar electricity production tariffs combined with other local subsidy programs to provide a lump sum that would make investments in PV systems more attractive.

Further, there are plans for a special tariff for CSP systems of 32 euro cents (US¢44.3) per kWh for installations with up to 200 kW and 28 euro cents (US¢38.8) for all other systems, which is about the same as the subsidies paid for equivalently sized ground-mounted systems. CSP systems would also benefit from a lower annual degression rate of 2% in 2012F and 2013F.

China

Various outlets in the Chinese press (including CBN, China Energy News) have quoted industry experts and researchers at Energy Research Institute of NDRC, such as Dinghuan Shi, the President of China Society for Renewable Energy, Zhongying Wang, Director of Renewable Energy Development Centre of NDRC and Huanli Shi, Researcher at Energy Research Institute of NDRC, on the event that NDRC is likely to unveil higher targets for Solar PV. Based on their talks, NDRC is likely to raise its 2020F targets of solar power to 20GW (from original 1.8GW, up 1,011%). This implies an 11-year CAGR of 46% through 2020F.

While the announcement of this new target has been later than market expectations (originally expected in 4Q09 or 1Q10), our recent checks suggest that an announcement is likely in 3Q10, when the Chinese government is expected to unveil stimulus packages for alternative energy and several other industries.



Japan

In November 2008, a system was started for purchasing surplus electricity (the portion not consumed by the owner) generated by solar power. Until FY10, the purchase price for surplus electricity is ¥48/kWh generated by households (¥39/kWh for overlap with other power generators on the owner’s premises) and ¥24/kWh for non-households (¥20/kWh). The price of ¥48/kWh is about twice the price that electric power companies pay voluntarily.

The Japanese government plans to lower the purchase price in stages, starting with a cut to about ¥42/kWh in FY11 (officially it has not yet been decided), with the aim of halving the system cost for solar power generation in three to five years. Investment in solar power should thus be recovered in 10-15 years. The surplus electricity purchase system will continue for 10 years at a fixed price; it excludes facilities for the power generation business (above 500kW) and includes equipment already installed when the system started. All consumers of electricity will bear the burden of the purchase costs.

Nomura’s solar stock picks

For Asia-ex Japan: JA Solar remains our top pick in the China solar sector in the near term, given its strong earnings momentum over the next few quarters, low exposure to euro depreciation and positive changes in its business model and customer portfolio, which we expect to help a re-rating of the stock. We maintain our BUY on Yingli given its long-term prospects, brand equity and cost leadership. We remain NEUTRAL on LDK, given its stretched balance sheet, potential dilution risk from fund-raising and unclear outlook beyond 2Q10F. We also remain NEUTRAL on GCL Poly, given its expansion into wafers, which are not earnings-accretive and carry execution risks.

For Europe: our preferred pick for European poly manufacturers is Wacker Chemie (WCH GR, BUY, PT €145), as we believe it stands to benefit from global solar end market volumes translating into poly volumes growth and sustainable competitive advantages in a business with high barriers to entry. We think that the share price of REC (REC NO, BUY, PT NOK 25) could get re-rated on the back of its ongoing turnaround across its poly, wafer and module operations. Within the wafer segment, we see Asian manufacturers as benefitting from material cost advantages. Renesola (SOLA LN, BUY, PT GBp 250) should thus benefit from the cost advantages of its Chinese manufacturing. We also think that PV Crystalox (PVCS LN, BUY, PT GBp78) is well positioned, with the added benefit of selling into the premium Japanese market. At the cell and module level, we see Solarworld (SWV GR, REDUCE, PT €9) as a likely high-end survivor, but expect pressure on profitability. Q-Cells (QCE GR, REDUCE, PT €6) is making steps towards improving profitability but still faces major strategic challenges from its business model that is very exposed to the commoditised cell end. We like European equipment manufacturers as they stand to benefit from solar PV demand growth which is driving expansion and the need for innovation driving upgrades and replacements should translate into strong order flow. Centrotherm (CTN GR, BUY, PT €40) is well positioned with a strong high-end product portfolio. We also see SMA (S92 GR, BUY, PT €125) as a direct beneficiary from end market growth due to its manufacturer-agnostic inverter business which is leveraged into end market demand.



Exhibit 55. Solar peer valuation comparison

Price Mkt cap P/E (x) P/BV (x) ROE (%)

Company Ticker Rating (local) (US$mn) FY09 FY10F FY11F FY09 FY10F FY11F FY09 FY10F FY11F

Cell

Motech 6244 TT REDUCE 99.00 1,165 900.0 31.3 18.9 2.3 1.9 1.7 4.7 88.1 146.2

E-Ton Solar 3452 TT REDUCE 46.50 362 n.a. 387.5 91.2 1.1 0.9 0.9 (29.8) (1.2) 1.0

JA Solar JASO US BUY 4.77 801 n.a. 5.5 4.6 0.8 0.9 0.8 (1.9) 18.6 18.5

Q-Cells QCE GR REDUCE 6.24 904.1 n.a. n.a. 34.6 1.00 1.04 1.00 (184.1) (3.0) 2.9

Wafer, cell and module

Trina Solar TSL US BUY 18.58 1,445 9.7 13.2 9.0 1.7 1.4 1.2 17.6 12.6 15.8

Yingli Green Energy YGE US BUY 10.51 1,560 n.a. 10.3 9.3 1.3 1.5 1.3 (4.9) 15.4 14.7

Cell and module

Suntech Power STP US BUY 9.49 1,710 16.9 12.8 10.0 1.1 1.0 0.9 6.8 8.1 9.5

Canadian Solar CSIQ US BUY 11.10 474 10.8 7.1 6.2 0.9 0.8 0.7 13.0 12.5 12.5

Sunpower SPWR US NR 14.19 1,325 11.1 8.2 6.8 0.9 0.9 0.7 11.2 10.0 9.4

Evergreen Solar ESLR US NR 0.80 166 n.a. n.a. 15.1 0.5 0.6 0.5 (24.9) (7.0) 1.7

Wafer

LDK LDK US NEUTRAL 5.66 744 n.a. 9.0 8.2 0.8 0.8 0.7 (26.6) 8.9 9.0

Solargiga 757 HK REDUCE 1.43 332 10.9 8.1 n.a. 1.4 1.2 n.a. 13.8 15.9 n.a.

Renesola SOL US BUY 2.01 520.3 n.a. 7.3 5.3 1.11 0.92 0.74 (16.0) 15.1 17.3

MEMC WFR US NR 11.14 2,533 16.2 9.4 7.5 1.1 1.0 0.9 7.7 10.8 11.8

Wafer Works 6182 TT NEUTRAL 41.30 353 n.a. 17.6 9.3 2.2 2.0 1.6 (5.9) 11.8 19.2

Green Energy 3519 TT NR 67.90 342 n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a.

Polysilicon

Wacker Chemie WCH GR BUY 121.58 7,446 35.7 14.2 11.9 3.13 2.61 2.22 (3.7) 20.6 21.4

GCL Poly 3800 HK NEUTRAL 1.62 3,223 (90.3) 10.7 12.0 1.6 1.8 1.6 (3.8) 18.2 13.9

OCI 010060 KS NR 237,500 4,577 11.6 10.0 9.8 2.9 2.3 1.9 28.0 25.5 21.1

Tokuyama 4043 JT NEUTRAL 433.00 1,686 19.2 15.9 13.7 0.6 0.6 0.6 3.3 4.0 4.4

PV Crystalox Solar PVCS LN BUY 0.56 348 7.9 9.8 8.3 0.88 0.84 0.78 11.4 8.6 9.4

Module and System

Solon SOO1 GR REDUCE 5.07 78.2 n.a. n.a. 15.3 0.24 0.26 0.25 (41.5) (6.8) 1.6

Conergy CGY GR REDUCE 0.75 368.6 n.a. n.a. 43.0 2.86 3.57 3.25 (89) (25.5) (9.3)

Aleo Solar AS1 GR NR 10.63 170 5.7 11.4 n.a. 1.5 1.3 n.a. n.a. n.a. n.a.

Equipment Manufacturers

SMA Solar Technology S92 GR BUY 85.52 2,967.5 18.4 13.8 12.7 7.28 5.18 3.95 39.5 37.6 31.0

Centrotherm CTN GR BUY 28.86 610.6 21.4 15.7 12.4 1.77 1.59 1.40 8.3 10.1 11.3

Meyer Burger MBTN SW NEUTRAL 27.50 877 38.7 27.7 19.7 5.19 4.39 3.61 13.4 15.9 18.4

Roth and Rau R8R GR NEUTRAL 21.85 301.5 23.3 18.6 13.9 1.38 1.29 1.18 5.9 7.0 8.5

Manz Automation M5Z GR REDUCE 47.13 211.1 n.a. 54.1 15.4 1.18 1.15 1.07 (5.4) (2.1) 7.0

Solar Development

Solar Millennium S2M GR BUY 20.70 319 8.4 6.1 4.5 1.49 1.12 0.88 23.3 24.4 24.8

Diversified

Abengoa ABG SM NEUTRAL 17.74 1978 9.4 8.2 7.2 1.37 1.14 0.96 21.2 19.6 18.2

Fully Integrated

SolarWorld SWV GR REDUCE 10.37 1,428.2 19.6 21.6 17.6 1.34 1.26 1.18 6.8 5.8 6.6

REC REC NO BUY 18.8 2,899.1 n.a. 690.3 13.6 0.74 0.75 0.84 (13.9) 0.1 6.2

Note: Pricing as of 23 June, 2010

Source: Bloomberg consensus estimates for not rated companies



Global outlook

Global wind power outlook Clarisse Pan +852 2252 2192 / [email protected]

Catharina Saponar, CFA +44 20 710 21231 / [email protected]


Global wind demand to grow 7% in 2010F and 14% in 2011F Over the years, wind energy’s contribution to global electricity supply has been steadily increasing and according to BTM Consult ApS, wind energy contributed 1.6% of the total global electricity generation in 2009. We note that electricity generation from wind energy has grown at a much faster pace than total global electricity in the past decade and we expect this trend to continue in the future.

Exhibit 56. Wind energy contribution to global electricity generation

0.0

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1.8

1997

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(%)

Source: BTM Consult ApS, Nomura research

Exhibit 57. Growth rate of wind vs global electricity generation

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Multiple (wind/total) (RHS)

(%) (x)


China, the US and Europe to remain key demand drivers We expect the global annual wind turbine generator (WTG) market to grow by 7% y-y in 2010F and 14% y-y in 2011F, with China and the US remaining the top-end markets.

We expect the WTG markets in Europe and China to be the key growth drivers for the global market in 2010F. We reckon that China and Europe will account for around 39% and 29% of annual global installation in 2010F, respectively. While we believe that policy support and growth visibility of China wind power will remain strong, we see 2010F as a transition year for players along China’s wind value chain. We estimate that the annual growth of wind capacity installation will start to slow from 100% y-y each year between 2007 and 2009 to around 15% y-y in 2010F. As the majority of Chinese wind companies have generated 70-90% of their wind revenues within China, those unable to start generating meaningful overseas revenue are likely to suffer from a significant slowdown in earnings growth, in our view.

We acknowledge that the difficult credit environment combined with the fall in fossil fuel prices would make it difficult for utilities to sign power purchase agreements (PPA) in the US, which could subdue growth in 2010F. Consequently, we expect the US market to decline by 18% y-y in 2010F. However, we expect the market to bounce back in 2011F, with growth of 25% y-y.

The US market is likely to decline in 2010F owing to the weak PPA market which we see as fallout from the recession. We believe that the delay in the US recovery will hit order inflows of international WTG players in the near term. For example, Vestas and Suzlon have been hit hard by a slower-than-expected pace of recovery in the US market, as the US is one of its key markets.

Electricity generation from wind energy growing at faster pace than total global electricity in the past decade; trend expected to continue in the future, in our view

China, US and Europe to remain as the key markets



As for the impact on CHST, although GE Wind, the dominant WTG supplier in the US, is its large customer, we believe CHST’s overseas shipment growth in 2010F is secure given its competitive pricing, which helps its foreign customers to lower costs, as well as the launch of its 2.5MW gearbox to GE Wind in 2H10F, which implies a share gain at GE.

Wind has been the technology that got the most important scale deployment Europe wide, with 76.5GW installed at the end of 2009. Going forward, we estimate an annual installation rate of c.16GW pa in the European market. In the wind sector, we see stable rates of installations in Europe, but we expect Asia and the US to overtake Europe over time. Currently, Europe is providing the stable growth basis for both developers and turbine manufacturers as they wait for a pick-up from the US and lack market accessibility in China.

Turbine manufacturers are our preferred picks in Europe as we see them benefitting from a market leadership position, high-end technology that will be an enabler for low LOCE (levelised cost of energy) and broad geographic exposure to global growth with an increasing presence in Asia. We estimate that developers’ valuations are attractive as current share prices on average reflect only assets on the ground and under construction. But we believe that the high levels of exposure to the weak PPA situation in the US may pose a risk to execution on capacity growth target. This could be an overhang on share prices until later in 2010.

Exhibit 58. Global WTG market new installation

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2007A 2008A 2009A 2010F 2011F 2012F

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Exhibit 59. Global WTG market cumulative installation

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2007A 2008A 2009A 2010F 2011F 2012F

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Exhibit 60. Nomura global wind model

WORLDWIDE WIND POWER ANNUAL INSTALLATION (MW) 2008 2009 2010F 2011F 2012FGlobal Demand 28,191 38,104 40,874 46,614 53,666% Growth 42 35 7 14 15 Europe 9,180 10,738 11,987 13,008 15,059% Growth 11 17 12 9 16 Americas 9,527 11,433 9,983 12,386 14,863% Growth 64 20 (13) 24 20 South and East Asia 8,201 14,991 17,441 19,469 21,711% Growth 64 83 16 12 12 OECD-Pacific 1,056 623 830 976 1,099% Growth 77 (41) 33 18 13 Africa 227 317 631 771 929% Growth 173 40 99 22 20 Other Continents 0 2 3 4 5% Growth (100) 50 50 25 OFFSHORE WIND POWER ANNUAL INSTALLATION (MW) 2008 2009 2010F 2011F 2012FEurope 344 624 1,364 2,508 2,228% Growth 72 81 119 84 (11) North America 0 0 0 420 210% Growth (50) Asia 0 63 100 160 221% Growth 60 38 Global Demand 344 687 1,464 3,088 2,659% Growth 72 100 113 111 (14) Wind Supply (MW) 2008 2009 2010F 2011F 2012FBig six 21,472 19,960 23,400 25,399 27,691% Growth 26 (7) 17 9 9Others 9,855 15,852 18,558 22,060 25,305% Growth 272 638 150 158 135 Global Supply 31,327 35,812 41,957 47,458 52,996% Growth 41 14 17 13 12 CUMULATIVE INSTALLED CAPACITY 2008 2009 2010F 2011F 2012FCumulative Demand (GW) 122 160 201 248 301% Growth 30 31 26 23 22 Cumulative Demand -Offshore (MW) 1,421 2,108 3,572 6,660 9,319% Growth 32 48 69 86 40 Source: BTM Consult ApS, Nomura estimate

Offshore wind markets to take-off With 687MW of annual installation, the offshore wind turbine market represents less than 2% of the total wind energy annual installation in 2009. Despite the slow progress made so far, we remain positive on the future prospect of the offshore wind turbine market and expect growth in this segment to take off. We note that most of the offshore projects are expected to come up in Europe, especially Germany and the UK. We expect offshore wind market to grow 113% y-y in 2010F and 111% in 2011F.

Higher project cost and longer gestation period in comparison to onshore projects, logistical difficulties, combined with lack of wind turbine suppliers for the offshore technology, are the key reasons for the smaller market size in this segment, in our view. Until recently, Repower, Siemens and Vestas were the only players who were active in the offshore wind turbine market. However, with new players such as Areva, Winwind, and Sinovel entering the offshore wind turbine market, we expect the supply side constraints to start easing off.



Exhibit 61. Cumulative offshore wind capacity

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2007 2008 2009 2010F 2011F 2012F 2013F 2014F 2015F

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Exhibit 62. Offshore wind – under construction (Nov 2009, MW)

Siemens50%

BARD13%

Repower6%

Multibird (Areva)1%

Vestas21%

Others9%

Siemens50%

BARD13%

Repower6%

Multibird (Areva)1%

Vestas21%

Others9%

Source: EWEA, Nomura estimate

We expect the offshore wind segment to be the next growth driver for the Chinese WTG market. According to comments made by wind operators, including China Longyuan and China Windpower, we believe that the majority of the attractive locations for onshore wind farm development have already been occupied by industry players. As a result, we expect offshore wind development to spur China wind industry growth over the next three years.

In our view, development of offshore wind projects could potentially benefit Chinese wind component and equipment manufacturers. While the majority of these companies do not have a track record in offshore applications, feedbacks we received from wind farm operators reveal that cost considerations indicate that operators prefer Chinese wind turbines and components.

We also expect Suzlon to benefit from the growth in the offshore market as Repower is the technology leader in this segment. This can be highlight from the fact that in 2009 Repower signed a framework agreement with RWE Innogy for supply of 250 Repower 5M/6M offshore wind turbines, one of the biggest offshore wind turbine contracts, worth approximately US$2bn.

We see the offshore market as a major growth area within wind. This is the case globally, but Europe is a centre of development and will see the most important growth early on, in our view. The UK and Germany will be the centres of development as c.32GW from the Crown Estate concessions that have been awarded in Round 3 get developed. Even though we only expect around 50% of the awarded concessions to



eventually fully develop, this is still substantial growth from the current base of just below 1GW of offshore capacity. We also expect strong momentum in Germany as developers aim to commission projects in order to capture the speedy bonus of Eur20/MWh for projects commissioned before 2015 and total capacity of c.3GW by 2014. Beyond this, Belgium, the Netherlands, France and Scandinavia will also be key areas of growth.

We see offshore wind as an area of significant growth over the next 10-20 years, particularly for those companies with operations in northern Europe, where wind resources offer the best opportunities. Significant investment will be required, and we expect the likes of Centrica, DONG, EDPR, E.ON, Iberdrola, RWE, SSE and Vattenfall to lead the development, with Siemens and Vestas dominating turbine supply, though new entrants such as GE and REpower will seek to make headway.

From a seller’s market to a buyer’s market Until recently, wind turbine suppliers enjoyed a stronger bargaining power in comparison to their customers, thanks to the strong demand and limited supply of wind turbines, in our view. However, wind turbine manufacturers’ capacity expansion in the past few years, combined with weakness in demand stemming from the impact of the economic crisis, has created a surplus in the wind turbine market. This has shifted the bargaining power from hands of wind turbine suppliers to customers.

Moreover, the shift in customers mix towards bigger players, such as utilities and independent power producers (IPPs), has altered the equation in favour of wind turbines customers. Unlike smaller players, utilities customers have much deeper pockets and the capability to plan and execute on large projects, in our view. We believe utilities have taken the advantage of the intense competition prevailing in the wind turbine market, and have been able to get lower ASPs, shorter delivery times and better after-sale services, in our view.

Exhibit 63. Cost structure of a typical wind turbine installed in Europe (2MW)

Land4%

Foundations7%

Grid connection9%

Others5%

Turbine (Ex-works)

75%

Source: EWEA, Nomura estimate

Fall in ASP to continue in FY10F Fall in price of key raw materials and removal of bottlenecks in critical components, combined with the increase in competition, have led to decline in ASP of wind turbines. We note that the price of steel, which contributes nearly 90% of the total cost of a wind turbine, has fallen significantly from its peak in 2008 and suppliers have been quick to pass on the benefit to their customers. Moreover, capacity expansion by gearbox manufacturers has led to a more balanced supply of gearboxes for the wind turbines and has helped shorten the lead times of wind turbines to customers.

Growing competition amongst wind turbine suppliers is also leading to pricing pressure in the industry. Our channel checks suggest that prices for wind turbines had fallen



about 18% in China in 2009, given the aggressive capacity expansion and consequently the fierce competition among wind turbine manufacturers. ASP’s for Western manufacturers have held firmer. We believe that this trend will continue in 2010F and expect another 10-15% y-y ASP decline this year for Chinese manufacturers and less than that for Europeans. In our view, Chinese WTG players are facing acute overcapacity and are willing to lower their selling prices to secure new orders. According to our checks, European manufacturers are not willing to engage into this behaviour Moreover, the wind turbine suppliers are looking to pass on the cost savings to customers in the form of lower wind turbine prices owing to the reduced raw material costs, especially falling steel prices since 2009.

Exhibit 64. World hot rolled coil price index

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(US$/tonne)

Source: Bloomberg, Nomura research

Chinese WTG makers grow global share along with China market, while European WTG makers maintain quality leadership

The entry of three Chinese players – Sinovel, Goldwind and Dongfang – into the top-10 global wind turbine generator suppliers clearly reflects the growing prominence of China in the global wind energy sector. With 13.8GW of new capacity installed, China has become the largest wind market worldwide since 2009. Its cumulative wind capacity grew at an impressive rate of 115% y-y in 2009, thanks to favourable government policies and easier availability of project financing. We note that Chinese wind turbine suppliers control more than 85% of the domestic market and hence the significant growth in the Chinese market has helped the Chinese wind turbine suppliers to break into the global league.

Exhibit 65. Chinese WTG manufacture gaining global market share

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Dongfang Goldwind Sinovel

(%)




We note that international players have entered the Chinese wind turbine market but have been losing market share in the China market. Chinese players are able to price their wind turbines 20-30% cheaper than their international peers, and this gives them a decisive edge when bidding for projects in China. Consequently, Sinovel, Goldwind and Dongfang together gained 10.2% incremental market share of the global wind turbine market at the expense of incumbents in 2009. However, we are observing that the Western quality proposition appears to be gaining ground again and think that Vestas and Gamesa could improve order flows from China. We have recently seen improving order flow for Western manufacturers. We take this as a sign of market opening, as well as a change in customer mentality from pure cost per MW to cost per MWh, and thus expect them to continue making inroads, while Chinese wind companies should maintain dominance in the Chinese market.

We expect the Chinese WTG suppliers, with their superior cost competitiveness and strong funding availability from the mother country, to start to attempt moving towards overseas markets. However, we believe that this would be a long-term process, as the majority of the Chinese WTG suppliers do not have long enough track records and local customer relationships overseas. In our view, the European market leaders will defend their market share through their customer relationships and technological edge. Furthermore, as wind turbine manufacturing needs to take place close to the end markets, Chinese manufacturers would lose their key cost advantages in other regions and competition would move onto a level playing field.

Entry of bigger players a welcome change

We note that there has been a shift in customer base for wind energy towards bigger players such as power utilities and independent power producers (IPPs) over the last few years. The fact that the market share of the Top 15 wind operators has increased to 35% in 2009 from 23% in 2003 is a clear indication of the trend where the larger players are beginning to dominate, in our view. We are positive about this shift in customer base as the entry of these bigger players, who have much-deeper pockets, provide stability in demand.

The increasing political support towards renewable energy has led to setting up of longer term renewable energy targets (RETs) in many countries across the world. This has put pressure on the power utilities companies in these countries to diversify their installed capacity towards cleaner energy sources to meet the RETs, in our view. Considering that most of these players have strong balance sheets, we believe that this should also help in solving the project financing issue for the ongoing and future projects, as banks find it easier to lend to bigger players. As the wind energy projects are becoming bigger in size, they need much more capital than in the past; as a result, the smaller players find it difficult to make the cut.

Exhibit 66. Top 15 utilities/IPP wind farm operators

Cumulative capacity (MW)

Name of the wind farm operator 2007 2008 2009Iberdrola Renovables 7,362 8,960 10,350 NextEra Energy 5,077 6,374 7,544 Acciona Energy 3,824 4,566 6,230EDP Renovaveis 3,639 5,052 6,227 China Longyuan 1,620 2,924 4,842 Datang 1,008 2,154 3,023 E.ON 855 1,890 2,873 EDF Energies Nouvelles 1,218 2,031 2,650 Invenergy 887 1,723 2,018 Eurus Energy 1,385 1,722 1,903 Infigen Energy 1,859 1,530 1,739 RWE Innogy 489 639 1,568 Huaneng New Energy 129 402 1,550 Enel 857 1,237 1,510 GDF Suez 690 1,054 1,492 Total 30,899 42,258 55,519




Shift towards larger-size turbines We note that the average size of installed wind turbine continues to increase, especially in more developed wind markets, such as European countries. However, the speed of the transition towards larger-sized wind turbines is slow as most of the new wind turbine suppliers, especially in China, currently provide only smaller-sized turbines of around 1.5MW, in our view. The average size of wind turbine supplied in 2009 grew just 33KW y-y to 1,599KW.

However, going forward, we expect Chinese suppliers to move into higher-megawatt turbines, around 2MW, to cater to international markets. This should help the global market to shift towards larger-sized turbines. Moreover, looking at the growth potential of the offshore market segment, which employs much larger wind turbines, combined with increased installation of larger sized onshore wind turbines, we expect the pace of the transition towards larger-sized turbines to quicken, in the mid-to-long term.

Another trend that we are witnessing is that wind turbine suppliers are focusing their research and development efforts towards products that can work efficiently in areas having weaker wind conditions. We note that the key reason for the shift is that areas with stronger wind conditions in most developed wind markets have already been exploited, leaving relatively weaker wind areas for wind farm development.

Exhibit 67. Product segmentation by size of global WTG supplied

0

20

40

60

80

100

Below 1500kW Above 1500 kW

2007 2008 2009

(%)


Exhibit 68. Average wind turbine capacity factor by country (2009)

0 5 10 15 20 25 30 35

USAGermany

SpainChinaIndiaItaly

FranceUK

DenmarkPortugalCanada

NetherlandJapan

AustraliaGreece

SwedenAustria

ROWGlobal avg.

(%)


Nomura’s wind stock picks

Within Asia, CHST remains our top pick in the sector due to its strong margin outlook, cost-control capability, continuously improving product mix and undemanding-looking



valuations. We re-iterate our conservative view on China Longyuan Power given its demanding valuation, despite Longyuan’s scarcity value as the largest wind power operator in Asia. We await further progress on Suzlon’s order inflows and balance sheet clean-up to be positive for the stock despite its low-looking valuation.

For Europe, the turbine manufacturers are our preferred picks as we see them benefitting from a market leadership position, high-end technology that will be an enabler for low LOCE (levelised cost of energy) and broad geographic exposure to global growth with an increasing presence in Asia. Vestas (VWS DC, BUY, PT: DKK 390) is our top pick, while we also like Gamesa (GAM SM, BUY, PT: €13.00). We estimate that developers’ valuations are attractive as current share price on average reflect only assets on the ground and under construction. But we believe that the high levels of exposure to the weak PPA situation in the US may lead to risk to execution on capacity-growth target. This could be an overhang on share prices until later in 2010. IBR (IBR SM, REDUCE, PT: €3.60) and EDF EN (EEN FP, NEUTRAL, PT: €39) are our key names in the space.

Exhibit 69. Wind peer valuation comparison

Price Mkt cap P/E (x) EPS

growthPEG

(x) P/BV (x) ROE (%)

Company Ticker Rating (local) (US$mn) 09 10F 11F (%) 10F 09 10F 11F 08 09 10F

Gearbox

CHST 658 HK BUY 17.60 2,818 19.9 13.7 10.5 37.6 0.4 4.3 3.5 2.3 23.7 28.3 26.6

Hansen Transmission HSN LN N-R 81.50 817 29.1 13.6 9.1 15.1 0.9 1.1 1.0 0.9 (1.4) 2.9 7.8

Wind turbine

Clipper CWP LN N-R 63.00 202 n.a. 6.2 4.8 n.a. n.a. n.a. n.a. n.a. n.a. 4.1 0.9

Gamesa GAM SM BUY 8.13 2,438.5 17.2 22.3 12.4 11.0 2.02 1.26 1.20 1.12 10.5 7.3 5.4

Nordex NDX1 GR N-R 8.17 672 18.7 12.0 8.5 48.6 0.2 1.5 1.3 1.2 7.2 8.0 12.0

Repower RPW GR N-R 118.00 1,336 17.6 14.6 n.a. n.a. n.a. 2.1 1.8 n.a. 13.4 13.4 13.8

Suzlon SUEL IN NEUTRAL 57.60 2,200 n.a. 9.8 5.0 n.a. n.a. 1.0 0.9 0.8 2.8 (1.6) 10.1

Vestas VWS DC BUY 286.90 9,681 13.3 18.0 11.6 6.0 3 2.28 2.07 1.75 26.1 17.2 11.5

Wind project operator

China Long Yuan Power Group 916 HK REDUCE 7.83 7,515 46.4 35.0 21.8 46.0 0.8 1.9 2.2 2.0 10.0 6.9 6.5

Acciona ANA SM BUY 69.42 5,431 19.5 14.8 11.9 27.8 0.5 0.7 0.7 0.7 22.3 4.1 4.9

Theolia TEO FP N-R 2.35 117 n.a. 50.0 11.7 n.a. n.a. 0.6 0.7 0.6 (12.9) (2.9) (0.5)

Iberdrola Renovables IBR SM REDUCE 2.81 14,587 26.0 22.8 18.7 17.9 1.3 1.0 1.0 0.9 3.3 3.9 4.3

EDF Energies Nouvelles EEN FP NEUTRAL 28.73 2,749 21.4 22.9 17.7 22.0 1.04 1.44 1.38 1.31 4.6 5.2 6.0

EDP Renovaveis EDPR PL NEUTRAL 5.01 5,380 32.3 24.4 20.1 26.7 0.9 0.8 0.8 0.8 2.1 2.5 3.2

Greentech Energy Systems GES DC N-R 13.30 106 14.0 2.1 2.3 147.6 0.0 0.0 0.0 0.0 (16.0) 2.3 4.7

China Power New Energy 735 HK N-R 0.74 678 19.0 12.5 12.1 25.1 0.5 1.0 0.9 0.9 3.3 5.3 8.0

China Windpower Group 182 HK N-R 0.69 646 16.4 11.5 8.1 42.3 0.3 1.4 1.2 1.0 6.4 9.2 11.7

Note: Pricing as of 23 June 2010

Source: Bloomberg consensus estimates for not rated companies



Global outlook

Global nuclear power and uranium outlook


Martin Young +44 20 710 21536 / [email protected]

Elaine Wu +852 2252 2194 / [email protected]

Current state of nuclear power Nuclear power contributed 14% of the world’s total electricity generation in 2007, according to the International Energy Agency (IEA). It is the third-largest source of generation after coal (41%) and hydro (16%). There are 435 nuclear power reactors in operation worldwide (as of December 2009) with total net installed capacity of 372GW. The US is the largest nuclear power user in the world, generating 31% of the world’s nuclear energy in 2008, followed by France (16%) and Japan (9%).

Nuclear power was first put into commercial use in the 1950s and saw rapid growth in capacity build-out during the 1960s and 1970s. However, development has slowed significantly since the late 1980s (with capacity CAGR slowing to 0.8% during the 1990s, from 9.1% in the 1980s) following the Three Mile Island accident in 1979 and the Chernobyl accident in 1986, which severely dented sentiment towards nuclear power in the West and undermined the reputation of the nuclear power industry.

Exhibit 70. Number and capacity of nuclear power reactors (1956-2006)

0

50

100

150

200

250

300

350

400

450

500

1956 1961 1966 1971 1976 1981 1986 1991 1996 2001 2006

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000Number of reactors (LHS) Capacity in MW (RHS)

Source: International Atomic Energy Agency (IAEA)

Nuclear power is the third-largest source of generation after coal and hydro

Development slowed significantly in the past couple of decades — the fallout of two big accidents



Exhibit 71. Global nuclear capacity by country (1980-2008)

(MW) Growth (%) CAGR (%)

Countries 1980 1985 1990 1995 2000 2005 2007 2008 08 v 00 2000-08

China - - - 2,188 2,188 6,587 8,438 8,438 285.6 18.4

India 832 1,143 1,324 1,746 2,508 2,993 3,782 3,782 50.8 5.3

Japan 14,918 23,612 30,867 39,625 43,262 47,593 47,587 47,278 9.3 1.1

South Korea 564 3,580 7,220 9,115 12,990 16,810 17,451 17,647 35.9 3.9

Pakistan 125 137 125 125 425 425 425 425 0.0 0.0

Argentina 335 935 935 935 978 935 935 935 (4.4) (0.6)

Armenia 816 816 - 376 376 376 376 376 0 0

Belgium 1,670 5,464 5,501 5,631 5,712 5,801 5,824 5,824 2.0 0.2

Brazil - 626 626 626 1,976 1,901 1,795 1,766 (10.6) (1.4)

Bulgaria 1,224 1,632 2,585 3,538 3,760 2,722 1,906 1,906 (49.3) (8.1)

Canada 5,172 9,741 13,993 14,902 9,998 12,584 12,610 12,577 25.8 2.9

Czech Republic - 391 1,632 1,782 2,611 3,373 3,619 3,634 39.2 4.2

Finland 2,208 2,300 2,310 2,310 2,656 2,676 2,696 2,696 1.5 0.2

France 14,388 37,478 55,808 58,573 63,080 63,260 63,260 63,260 0.3 0.0

Germany 10,323 18,110 21,250 20,972 21,283 20,339 20,430 20,470 (3.8) (0.5)

Hungary - 825 1,710 1,729 1,729 1,755 1,829 1,859 7.5 0.9

Italy 1,112 1,273 - - - - - - NA NA

Kazakhstan 135 135 135 50 - - - - NA NA

Lithuania - 1,380 2,760 2,370 2,370 1,185 1,185 1,185 (50.0) (8.3)

Mexico - - 640 1,256 1,290 1,360 1,360 1,300 0.8 0.1

Netherlands 498 508 539 510 449 450 482 482 7.3 0.9

Romania - - - - 655 655 1,305 1,300 98.5 8.9

Russia 8,596 15,841 18,898 19,848 19,848 21,743 21,743 21,743 9.5 1.1

Slovakia 780 1,632 1,632 1,632 2,440 2,442 2,034 1,711 (29.9) (4.3)

Slovenia - 632 620 620 676 656 666 666 (1.5) (0.2)

South Africa - 1,840 1,840 1,840 1,840 1,800 1,800 1,800 (2.2) (0.3)

Spain 1,073 5,608 7,099 7,097 7,468 7,591 7,450 7,450 (0.2) 0.0

Sweden 5,515 9,450 9,919 10,058 9,417 8,916 9,034 8,996 (4.5) (0.6)

Switzerland 1,940 2,881 2,942 3,056 3,170 3,220 3,220 3,220 1.6 0.2

UK 8,686 12,485 13,496 13,718 13,059 11,852 10,222 10,097 (22.7) (3.2)

Ukraine 2,286 8,324 13,020 13,045 11,195 13,107 13,107 13,107 17.1 2.0

US 50,881 74,401 96,228 98,068 96,297 98,145 100,266 100,683 4.6 0.6

World 135,285 248,070 320,482 342,225 350,590 368,136 371,758 371,562 6.0 0.7

% covered by above Asian countries 12 11 12 15 18 20 21 21

Source: IAEA

The next nuclear boom

We look for the next wave of nuclear power plant construction to begin under the backdrop of rising electricity demand and a greater need for low-carbon energy. According to the International Atomic Energy Agency (IAEA), nuclear capacity will grow by 139-427GW (or 37-112%) during 2010-2030F, from 372GW in 2009, based on its low and high projections.

But growing electricity demand, especially low-carbon energy, is likely to drive a new wave of nuclear capacity build out



Exhibit 72. Global nuclear power capacity projections

371 372445

511

380

543

807

0

100

200

300

400

500

600

700

800

900

2008 2010F 2020F 2030F

(GW) Low Case High Case

Source: IAEA

Exhibit 73. Global nuclear power generation projections

2,598 2,785

3,962

5,930

3,7713,261

2,732

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2008 2010F 2020F 2030F

(TWh) Low Case High Case

Source: IAEA

Summary of IAEA projections:

Nuclear power generation is expected to grow steadily in the next three decades, at a CAGR ranging from 1.6% to 3.8%. Despite the rise in capacity, the Low-Case projection estimates a decline in nuclear’s share in electricity generation because the world’s aggregate power generation grows at an even faster rate. Nuclear’s share of electricity generation is currently at about 14% and the ratio is expected to range from 12.6% to 15.9% in 2030F, based on Low and High Case scenarios.

Nuclear power capacity is estimated to grow in a similar fashion as with nuclear power generation, at a CAGR of 1.6-3.9% over 2010-2030F.

Emerging economies, especially those in Asia, will experience significant growth in nuclear power capacity. Some developed countries, such as the US and France, already have large amounts of nuclear power capacity and some European countries are phasing out nuclear power due to environmentalist opposition. Hence, this growth in developed countries is estimated to be comparatively slow in the next few decades. Since electricity demand in emerging economies is expected to grow at a faster pace than that of the developed countries, emerging countries require more installed capacity to generate enough electricity to meet demand. Nuclear power will be an important source to generate electricity as greenhouse gas emissions become a worldwide issue.

WNA guides for similar growth in nuclear power capacity

The IAEA projections are in line with the projection from the World Nuclear Association (WNA) – which estimates nuclear power capacity will grow to 600GW and 818GW in 2030, based on its Reference-and Upper-Case projections, respectively.

The IAEA forecasts steady growth in nuclear power generation over the next three decades…

… mainly driven by capacity growth in emerging economies



Exhibit 74. Projected nuclear power capacity by country based on WNA’s Reference Scenario

(MW) CAGR (%)

Asian countries 2008 2010F 2015F 2020F 2025F 2030F 2010-30FTaiwan 4,884 4,884 7,484 7,484 8,784 8,876 3.0Japan 47,577 47,122 52,408 56,666 64,757 65,904 1.7Korea 16,920 16,920 24,710 28,700 32,690 38,050 4.1Vietnam - - - - 950 950 NAChina 8,467 8,467 28,967 50,467 71,467 93,967 12.8India 3,797 5,356 8,259 15,885 24,274 31,432 9.3Indonesia - - - 950 950 950 NAMalaysia - - - - 950 950 NAPakistan 425 425 600 900 900 900 3.8Philippines - - - - - - NAThailand - - - - - - NA

Total 82,070 83,174 122,428 161,052 205,722 241,979 5.5 (GW) CAGR (%)Region 2008 2010F 2015F 2020F 2025F 2030F 2010-30FLatin America 4 4 5 7 10 10 4.6US 100 101 102 106 117 122 1.0Europe 135 136 131 135 135 130 -0.2Asia 69 69 85 95 111 118 2.7Canada 13 13 14 15 16 15 0.9Other 6 9 12 23 36 45 8.6Russia 21 22 24 28 36 46 3.7Eastern Europe 14 14 14 16 19 20 2.0China 9 9 29 51 72 94 12.8

World 371 375 415 476 551 600 2.4 Source: WNA

Exhibit 75. Projected nuclear power capacity by country based on WNA’s Upper Scenario

(MW) CAGR (%)

Asian countries 2008 2010F 2015F 2020F 2025F 2030F 2010-2030FTaiwan 4,884 4,884 7,484 8,784 10,084 11,384 4.3Japan 47,577 47,122 55,046 65,589 68,189 75,989 2.4Korea 16,920 17,870 24,710 30,030 36,720 42,040 4.4Vietnam 1,900 2,850 3,800 NAChina 8,467 8,467 29,967 72,967 95,467 134,467 14.8India 3,797 5,356 12,092 21,458 32,920 41,939 10.8Indonesia - - - 950 1,900 3,800 NAMalaysia - - - 950 1,900 2,850 NAPakistan 425 425 725 1,200 2,500 3,500 11.1Philippines - - - - - 1,900 NAThailand - - - - 950 1,900 NA

Total 82,070 84,124 130,024 203,828 253,480 323,569 7.0 (GW) CAGR (%)Region 2008 2010 2015 2020 2025 2030 2010-2030FLatin America 4 4 6 8 15 24 8.7USA 100 101 102 112 135 144 1.8Europe 135 136 138 149 170 186 1.6Asia 69 70 87 110 125 146 3.7Canada 13 14 15 17 19 19 1.6Other 6 9 16 37 62 86 12.2Russia 21 23 28 35 46 52 4.1Eastern Europe 14 14 15 17 23 25 3.1China 9 9 30 73 96 135 14.8

World 371 378 437 558 688 818 3.9 Source: WNA

All of these new capacity additions will translate into US$1.3tn in nuclear power investment during 2010-2030F, according to the IEA.



Exhibit 76. Projected investment in renewables, CCS and nuclear by country/region based on IEA’s 450 Scenario

2010-20F 2021-30F

(US$2008bn) Renewables CCS Nuclear Renewables CCS Nuclear

OECD+ 866 51 189 1,190 411 449

US 228 35 87 371 273 130

EU 474 9 32 522 82 176

Japan 40 1 29 62 7 65

Other major economies 549 6 194 886 106 246

Russia 24 3 26 106 22 41

China 451 1 153 622 66 168

Other countries 292 1 39 948 20 151

India 102 1 15 365 9 73

World 1,707 58 422 3,024 537 846 Note: Figures do not include investment in photovoltaics in buildings

Source: IEA

Our Nomura global nuclear model suggests 180GW new build

Our European Utilities team has built a growth model for new nuclear around the world. This is a country-by-country analysis and assumes a pragmatic and conservative approach to the plans of each country. In particular, recession-driven demand destruction is likely to prompt a reassessment of plans as well as a trend towards lifetime extensions in Europe. Finance is also a concern in places like Europe and the US, and may derail or delay many new build plans, in our view. As a consequence, our global nuclear model suggests a capacity increase of 180GW by 2024F, which may be conservative, but still indicates a 48% increase from existing global nuclear capacity. Of this, Asia (China, India and Japan) is likely to account for more than half. Note: growth models that include communicated plans/ambitions from countries will naturally result in a higher growth profile. China is one such region, where significant plant capacity (95GW+) has been proposed, but we do not include this in our model. Our Asian utilities team includes planned nuclear reactors in China in their forecasts and expects 70GW to be in operation by 2020F (this is included in our global model.)

Exhibit 77. Global nuclear additions (MW)

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

2009

2011

2013

2015

2017

2019

2021

2023

Source: WNA, Nomura estimates

Exhibit 78. Global nuclear additions by region

Middle East2%

Africa2%

Americas11%

Asia57%

Europe28%


Capacity growth to come from Asia

Much of the growth in nuclear power capacity will come from Asia, chiefly China, India, Japan and South Korea. WNA expects these countries to contribute to more than 60% of the world’s new capacity planned-and-under-construction.

Asia to drive much of the growth in nuclear capacity

We forecast a global nuclear capacity increase of 180GW by 2024F or a 48% increase from the current levels



Exhibit 79. Nuclear power reactors planned or under construction (as of December 2009)

Reactors under construction Reactors planned

Number MW

% of world total Number MW

% of world total

China 18 19,240 38.8 35 37,000 24.7

Russia 9 7,130 14.4 7 8,000 5.3

India 6 2,976 6.0 23 21,500 14.4

South Korea 6 6,700 13.5 6 8,190 5.5

Canada 2 1,500 3.0 4 4,400 2.9

Japan 2 2,285 4.6 13 17,915 12.0

Slovakia 2 840 1.7 0 0 0.0

Argentina 1 692 1.4 1 740 0.5

Finland 1 1,600 3.2 0 0 0.0

France 1 1,630 3.3 1 1,630 1.1

Iran 1 915 1.8 2 1,900 1.3

Pakistan 1 300 0.6 2 600 0.4

US 1 1,180 2.4 11 13,800 9.2

North Korea 0 0 6.0 1 950 14.4

Thailand 0 0 0.0 2 2,000 0.6

Vietnam 0 0 0.0 2 2,000 0.0

Indonesia 0 0 0.0 2 2,000 0.0

Asia 33 31,501 63.5 86 92,155 61.6

World 53 49,588 100.0 136 149,645 100.0 Source: WNA, Nomura research

Exhibit 80. Nuclear capacity under construction (as of December 2009)

0 5,000 10,000 15,000 20,000 25,000

Pakistan

Argentina

Slovakia

Iran

USA

Canada

Finland

France

Japan

India

South Korea

Russia

China

(MW)

Source: WNA

As of December 2009, nuclear power reactors under construction or planned in Asia made up 62% of the world total 200GW, led by China (28%), India (12%) and Japan (10%), according to WNA. There were 53 nuclear reactors under construction in the world, with 33 located in Asia. As China and India have witnessed fast economic growth in recent decades, their energy requirements are likely to be strong. China (as of January 2010) has 20 reactors under construction, while India has six. Both have aggressive plans to develop nuclear power, with an additional 59GW planned (China



37GW; India 22GW), accounting for 39% of capacity planned in the world. Japan and South Korea have developed sophisticated nuclear power industries and are pursuing steady growth with 13 and six reactors planned, respectively.

In our opinion, the key drivers for the upcoming growth in nuclear power include: 1) growing demand for electricity (especially from emerging economies such as China and India); 2) the need for clean energy amid threats of global warming and; 3) the need for energy security and diversification.

Russia, US and UK set to lead the non-Asian charge New build in Asia is likely to be dominated by China, India, Japan and Korea, while that in the rest of the world is likely to be more widely spread out. However, ex Asia, three countries stand out as having significant new build aspirations over the next 15 years — Russia, where we see 16GW of capacity additions, the US (12GW) and the UK (10GW).

Russia is firmly embracing the nuclear renaissance, although given the recession and demand decline, it revised its budget downwards in July 2009. Of the 37GW capacity that has been proposed as part of delivering a 25%-30% nuclear share in electricity supply by 2030, we believe that a plant without a start date in construction may be delayed or not come to fruition. That being said, Russia already has 7.5GW of new capacity under construction and a further 8.2GW with planned construction start dates. We include this capacity within our global nuclear model.

The UK is set to lead the way in terms of new nuclear build in Western Europe. The government is firmly behind new nuclear build and in January 2008 published a white paper setting out such a preference. The driver of this support is a need to replace the coal capacity that will be shut down at the end of 2015, and the British Energy capacity that reaches the end of its operational life. While the government has no specific targets for new nuclear, most of the big European utilities are interested in building new nuclear plants in the UK, although we take a more conservative approach in our global nuclear model and suggest that only 10GW will be built by 2022F.

There is strong support in the US for new nuclear build and a number of policy instruments have been developed, including federal loan guarantees and tax credits. Proposals have been tabled for over 46GW of new capacity, of which 1,180MW is under construction, and 11,000MW is planned with engineering, procurement and construction contracts (EPCs) in place. With the exception of one project, all are on the shortlist for a federal loan guarantee. Our global nuclear model assumes that only the latter capacity will enter service in the next 15 years.

Nuclear power: the low carbon solution

Compared with conventional thermal fuels, nuclear power is almost free of greenhouse gas (GHG) emissions. Electricity from a nuclear power generator is produced by splitting uranium atoms to release heat, which in turn creates steam to generate power. There is no production of greenhouse gases since there is no combustion of carbon during this process, unlike fossil fuels which combine with oxygen to produce heat. From the perspective of the overall lifecycle of different types of fuel, nuclear power emits GHG only in plant construction, uranium mining, milling, enrichment and fabrication. Therefore, nuclear power is expected to gain a bigger advantage over conventional thermal sources.

Nuclear power is almost free of greenhouse gas emissions

Elsewhere, Russia, the US and the UK stand out with significant new build aspirations



The chart below illustrates the amount of GHG emitted from various electricity generation methods, based on the data from the IAEA. This shows that coal-generated electricity emits the largest amount of emissions. Renewable sources emit a fraction of the amount of those from fossil fuels. Nuclear power does not generate direct GHG emissions from the production of electricity. Its indirect emissions from electricity production are only 1-2% of those from coal. Data from the IEA in the table overleaf, which breaks down emissions of CO2, SO2 and NOx, show similar results.

Exhibit 81. Greenhouse gas emissions from electricity production

1,017790

575362

289

176

113

77

236 4 280 100 48 10 21 90

200

400

600

800

1,000

1,200

1,400

Co

al

Co

al

Ga

s

Ga

s

Hyd

ro

Hyd

ro

Sol

ar P

V

Sol

ar P

V

Win

d

Win

d

Nuc

lear

Nuc

lear

Indirect emissions, from life cycle

Direct emissions from burning

grams CO2-e/kWh

Source: IAEA. Note: two bars indicate range

Exhibit 82. Lifecycle air emissions from various electricity generation methods

Emission (g/kWh)

CO2 SO2 NOx

Coal

Best practice 955.0 11.8 4.3

Flue gas desulphurisation & low NOx 987.0 1.5 2.9

Oil

Best practice 818.0 14.2 4.0

Gas

Combined cycle gas turbines 430.0 -- 0.5

Diesel

Embedded 772.0 1.6 12.3

Energy crops

Current practice 17-27 0.07-0.16 1.1-2.5

Future practice 15-18 0.06-0.08 0.35-0.51

Hydro

Small scale 9 0.03 0.07

Large scale 3.6-11.6 0.009-0.024 0.003-0.006

Solar

PV 98-167 0.20-0.34 0.18-0.30

Thermal electric 26-38 0.13-0.27 0.06-0.13

Wind 7-9 0.02-0.09 0.02-0.06

Geothermal 79 0.02 0.28

Source: IEA, Nomura research

CO2 emissions avoided

Nuclear energy accounts for 45% of global carbon-free electricity. It prevents 2.6bn metric tonnes of CO2 emissions each year and has avoided 60bn tonnes of CO2 emissions to date compared with the equivalent coal-fired power, according to the Nuclear Energy Institute (NEI) and the OECD Nuclear Energy Agency. This is in contrast to the 26bn tonnes of carbon dioxide emitted globally by the transportation, power generation and industrial sectors each year.

Nuclear power’s indirect emissions from electricity production is only 1-2% of those from coal

Nuclear energy accounts for 45% of global carbon-free electricity



According to the NEA, “the cumulative emissions of CO2 from fossil fuels used for electricity production” during 1971-2004 were 218Gt and the cumulative saving from the use of nuclear power were 58Gt of CO2 equivalent.

The WNA has said that nuclear electricity avoids nearly 700mn tonnes of carbon dioxide, 1.1mn tonnes of nitrogen oxide and 3.3mn tonnes of sulphur dioxide in the US.

Need for energy diversity and security In order to ensure supplies of resources needed for energy and to become less reliant on limited resources such as oil, various countries have taken a move to diversify from their key sources of energy such as coal. China has been leading the way in this effort. President Hu Jintao placed an emphasis on growing nuclear energy as a way to fight climate change. Even though coal will continue to be its dominant source for electricity generation, China has been making big efforts in expanding its renewable and nuclear capacity. It has plans to revise its nuclear capacity target to 70-86GW by 2020 from the current 40GW, according to government data.

The advantage of nuclear power is that nuclear fuel supplies are relatively inexpensive and highly energy-intensive. Its small volume allows for easy stockpiling and it can act as a buffer against energy insecurity.

Other than concerns over GHG emissions from coal generation, the reliability of power grids is also an issue in the wintertime during snowstorms. Transportation of coal has previously been held up by storms, leading to power shortages.

Similarly, countries that do not have rich resources, such as Japan and South Korea, are continuing their efforts in expanding their nuclear power programmes.

Nuclear plays an important role in energy diversification because other renewable energy sources are not enough to help control GHG emissions. The IEA projects that these new renewable sources can only provide around 6% of world electricity by 2030 even with continued government subsidy and research support. IEA’s executive director, Nobuo Tanaka, said in October 2009 that the world would need to build 18 reactors a year to make nuclear power reach 18% of the global energy mix by 2030.

Smaller nuclear reactors attracting attention

Today, due partly to the high capital cost of large power reactors generating electricity via the steam cycle and partly to the need to service the small electricity grids under about 4GWe, there is a move to develop the smaller units. These may be built independently or as modules in a larger complex, with capacity added incrementally as required (see the section below on Modular construction using small reactor units). The numbers produced provide economies of scale. There are also plans to develop small units for remote sites.

Generally, modern small reactors for power generation are expected to have greater simplicity of design, economy of mass production and reduced sitting costs. Many are also designed for a high level of passive or inherent safety in the event of malfunction.

Modular construction using small reactor units

Westinghouse's IRIS (International Reactor Innovative & Secure) is an advanced third-generation reactor. A 335MWe capacity is proposed, although it could be scaled down to around 100MWe. IRIS is a modular pressurized water reactor with integral primary coolant system and circulation by convection. Fuel is similar to present light water reactors (LWRs) and (at least for the 335MWe versions) fuel assemblies are identical to those in AP1000, according to Westinghouse. Enrichment is 5% with burnable poison and fuelling interval of four years (or longer with higher enrichment). US design certification is at the pre-application state.

Developers of IRIS have outlined the economic case for modular construction of their design (about 330MWe), and the argument applies similarly to other smaller units. They point out that IRIS, with its size and simple design, is suited for modular construction in the sense of progressively building a large power plant with multiple

Countries are moving to diversify from emissions-heavy energy sources like coal

The world needs to build 18 reactors pa to make nuclear power become 18% of the global energy mix by 2030



small operating units. The economy of scale is replaced here with the economy of serial production of many small and simple components and prefabricated sections. They expect construction of the first IRIS unit to be completed in three years, with subsequent reduction to only two years.

Site layouts have been developed with multiple single units or multiple twin units. In each case, units will be constructed so that there is physical separation sufficient to allow construction of the next unit while the previous one is operating and generating revenue. In spite of this separation, the plant footprint can be very compact so that a site with three IRIS single modules providing a 1,000MWe capacity is similar or smaller in size than one with a comparable total power single unit.

Eventually, IRIS is expected to have capital cost and production cost comparable with larger plants. However, any small unit such as this will potentially have a funding profile and flexibility otherwise impossible with larger plants. It will generate positive cashflow for the next module to be built as one module is finished and starts producing electricity. Westinghouse estimates that 1,000MWe delivered by three IRIS units built at three year intervals financed at 10% for ten years require a maximum negative cashflow of less than US$700mn (compared with about three times that for a single 1,000MWe unit). For developed countries, small modular units offer the opportunity of building as necessary. For developing countries, it may be the only option as their electric grids cannot take 1,000+MWe single units.

Nuclear’s cost competitiveness

According to a study by the IEA and NEA, which compiled data from 10 countries, the cost of nuclear generation is among the cheapest, followed by coal, gas, wind, micro-hydro and solar. The cost of generating electricity depends on some country-specific factors. On average, nuclear power has lower costs than other types of fuel.

Based on NEA and IEA’s study, nuclear power generation cost is US$40-140/MWh, demonstrating that nuclear power costs are lower than those for other types of plants. NEA and the IEA found that the share of investment in total levelised generation cost is around 70% while the other cost elements, O&M and fuel cycle, represent averages of 20% and 10% respectively. Compared with other fossil fuels, nuclear power’s proportion of capital costs is higher and fuel costs are lower.

Exhibit 83. Generation cost of various energy sources

Source: NEA, IEA

Our European research team also did a cost analysis of new entrant power cost (see exhibit below), which also shows that nuclear is the most economic form of new build for large-scale generation capacity, although its relative merits depend on the price of CO2.

Nuclear generation cost is among the cheapest



Exhibit 84. New entrant power costs (€/MWh)

0

20

40

60

80

100

120

CCGT - EUR Coal Clean Coal Nuclear Wind - On Wind - Off Market CCGT Market Coal

Return Decommissioning O&M costs Carbon costs Fuel costs(EUR/MWh)

Nomura long term price assumption of €65/MWh

€66/MWh €67/MWh

€86/MWh

€58/MWh €63/MWh

€107/MWh

€50/MWh

€56/MWh


Exhibit 85. Cost structure of generation plants by type at 10% discount rate

50

20

70

15

7

2035

73

10

0

10

20

30

40

50

60

70

80

90

100

Coal Gas Nuclear

Investment costs O&M Fuel(%)

Source: NEA, IEA

With high fixed costs, nuclear power generation plants are subject to scale economies. The unit cost of generation falls substantially with increased output. While base load demand is growing, capacity factors of nuclear plants around the world have increased by 10 percentage points since 1990 from 70% to 80%, according to the WNA. We expect this trend to continue in the short term, hence further reducing operating and management costs.

Prices of nuclear fuel also experienced a substantial decrease in recent decades. Nuclear fuel costs in the US were 1.28 cents per kWh in 1985 and 0.44 cents per kWh in 2004. Because uranium costs are only a small fraction of total kWh cost (around 5%), the impact on electricity costs will be relatively insignificant. Therefore, nuclear fuel costs fell substantially although uranium prices have risen sharply in the past two years. Considering possible technology progress in enrichment and spent fuel management, we expect a further decline in fuel costs of nuclear power.

A combination of lower fuel costs and O&M costs provides nuclear power with competitiveness from the perspective of operation. In the US, the cost of electricity production for nuclear power fell to 1.76 US cents per KWh in 2007 from 2.60 US cents per KWh in 1995, according to the NEI.

Fuel costs account for 10-20% of nuclear power generation costs

Nuclear fuel price experienced a substantial decrease in recent decades



Exhibit 86. Production costs of power generation by type in the US

0

2

4

6

8

10

12

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

(Cents/KWh) Coal Gas Nuclear Petroleum

Source: NEI

Uranium: the fuel and its outlook

As nuclear power development is picking up speed, we believe that uranium demand is set to grow approximately at the same pace with the increase of nuclear power capacity. The increase in demand has seen an expansion in uranium exploration and production. Uranium exploration expenditures in 2006 were US$774mn, a 250% increase from 2004, according to the IAEA.

Because the US, France and Japan have the largest number of nuclear reactors in the world, they account for over 58% of the world’s uranium demand. As China, India, Russia and South Korea have the largest amount of nuclear power capacity in the pipeline; uranium demand growth will be mainly driven by these countries.

Exhibit 87. World’s uranium requirement, 2009

USA , 29%

Others, 11%Sweden , 2%

France , 16%

Japan , 13%Russia , 5%

South Korea, 5%

UK, 3%

Canada , 3%

Germany , 5%

India , 1%

Ukraine , 3%

China , 3%

Source: WNA, Nomura research

Primary supply of uranium is dominated by a few countries. Canada, Australia and Kazakhstan are the largest providers of primary supply, collectively accounting for 60% of the world’s total. In recent years, Kazakhstan has been aggressively increasing its production, at an annual average rate of 21% over the past five years compared with Canada’s -3% and Australia’s 3%.

Uranium demand is set to grow

China, India, Russia and South Korea driving demand growth



Exhibit 88. World’s uranium production and capacity by country (2008)

0 2,000 4,000 6,000 8,000 10,000 12,000 14,000

France

Pakistan^

Romania^

Czech Rep

India^

Brazil

South Africa

China ^

Ukraine^

USA

Uzbekistan

Niger

Russia^

Namibia

Australia

Kazakhstan

Canada

(tU)Production Capacity

Source: WNA. Note: ^ WNA/UI estimates

Major uranium mines are located in Australia, Canada, Niger, Namibia, Russia and Kazakhstan. The top eight mines account for about 82% of the world’s total output. According to the WNA, capacity utilisation at operating mines in 2008 was 90%.

Exhibit 89. World's major uranium mines (2008)

Mine Region Owner, stake% Mine type 2008 production (tU) % of world production

McArthur River Canada Cameco Conventional 6,383 15

Ranger Australia ERA (Rio Tinto, 68%) Conventional 4,527 10

Rossing Namibia Rio Tinto, 69% Conventional 3,449 8

Olympic Dam Australia BHP Billiton By-product (copper) 3,344 8

Priargunsky Russia ARMZ Conventional 3,050 7

Arlit Niger Areva Conventional 1,743 4

Rabbit Lake Canada Cameco Conventional 1,368 3

Akouta Niger Areva Conventional 1,289 3

McClean Lake Canada Areva Conventional 1,249 3

Akdala Kazakhstan Uranium One ISL 1,034 2

World total from top ten mines 27,436 63 Source: WNA

Cameco’s McArthur River mine in Canada is the largest mine in the world with a capacity of 7,200tU. Cameco has another mine under development in Canada at Cigar Lake, which will have a capacity of 6,925tU and will begin operation in 2013, according to the WNA.

Cameco’s McArthur River mine — largest in the world



In Australia, BHP Billiton has plans to expand its uranium production level at Olympic Dam by more than four times to 16,110tU from 3,385tU. The mine expansion is expected to occur over 10 to 11 years.

From the perspective of companies, primary supply is dominated by eight producers. Supply provided by these companies’ accounts for more than 80% of the world’s total primary supply.

Exhibit 90. Major uranium miners based on production volume (2008)

Kazatomprom12%

Areva14%

Rio Tinto19%

Cameco15%

Other13%General Atomics

1%

Uranium One3%

Paladin2%

Navoi5%

BHP Billiton8%

ARMZ8%

Source: WNA

Under the WNA’s Reference-Case projection, the production of uranium will increase rapidly in the next decade, at a 5% CAGR over 2008-2020F or nearly doubling from 43,853tU in 2008 to 80,238tU in 2020F. This is mainly a result of new mines coming online. However, uranium production is projected to start to decline slightly in 2026F as reserves and resources are exhausted.

In Africa, for example, seven new mines will help push production levels to double in the next 10 years. In Russia, Atomredmetzoloto (ARMZ) has a goal of increasing its annual production from 3,500tU to 20,000tU.

Under the WNA’s Upper-, Lower- and Reference-Case projections on uranium production, assumptions were made that production would rise in the next 10 years under all three scenarios.

Exhibit 91. Projected uranium production (2008-30F)

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

2008

2009

F

2010

F

2011

F

2012

F

2013

F

2014

F

2015

F

2016

F

2017

F

2018

F

2019

F

2020

F

2021

F

2022

F

2023

F

2024

F

2025

F

2026

F

2027

F

2028

F

2029

F

2030

F

(tU) Upper Reference Lower


Primary supply is dominated by eight companies

Production of uranium will increase rapidly



Uranium resources are sufficient to support nuclear power development, in our view. In 2007, 439 nuclear reactors in the world consumed about 65,000tU. According to the WNA, world known reserves of uranium are more than adequate to satisfy reactor requirements to well beyond 2030. World uranium production has been rising steadily in the past decade from 33,719tU in 1998 to 43,853tU in 2008. The run-up of uranium prices since 2003 has also given more incentives for further production and exploration of the metal. The ratio of known uranium resources to 2006 consumption is 100 years, according to the NEA, which implies there is still a lot of room for growth.

Spot prices of uranium peaked at US$138 per pound in June 2007 following tight supply and intense bidding. In 2008, utilities in Europe and North America rebuilt their inventory to protect themselves against further price rises and potential supply shortages. Spot prices have since fallen to around US$41 per pound (June 2010).

As for the near-term future of the spot uranium market, TradeTech (a US firm that provides market information and consulting services to the nuclear fuel industry), expects a return to the market by the more traditional buyers in 2010. Although active supply remains considerable, buying activity results in upward price pressure, with a resulting price rise to a peak value of about US$55 per pound U3O8, followed by a drop back to the high US$40s for the rest of 2010F. Well into 2011F, TradeTech sees buying activity picking up for yet another major round, with another price rise to a peak of slightly over US$60 per pound U3O8. Although these results are for only one scenario, a fairly robust finding is that the spot price is projected to remain in the range of US$45-60 per pound U3O8 over the next 24 months.

Exhibit 92. Uranium spot price history (1968-2009)

0

20

40

60

80

100

120

140

160

1968

1970

1972

1974

1976

1978

1980

1982

1984

1986

1988

1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

0

50

100

150

200

250

300

350

400

(per Pound U3O8) (per kgU as U3O8)

Source: TradeTech

Outlook on uranium demand and supply

Based on WNA’s Reference-Case projections, uranium supply from primary and secondary sources would be adequate to supply the reactor requirements up to 2020F. Beyond that, more mines would have to be put into operation to satisfy demand. World reactor requirements are projected to rise from 64,500tU in 2008 to 76,900tU in 2015F, 91,500tU in 2020F and 106,100tU in 2030F. The annual growth rate during 2008-2030F would be 2.2%, same as the growth rate in nuclear generating capacity. Under the Upper-Case projections, uranium requirements are expected to rise to 84,800tU in 2015F, 106,600 in 2020F and 140,100tU in 2030F.

Spot prices of uranium peaked at US$138 per pound in June 2007

Supply looks adequate up to 2020F



Exhibit 93. Projected uranium demand and supply for 2008-30F, under WNA’s Reference Case

(000 tU)

0

20

40

60

80

100

120

140

2008

2010

F

2012

F

2014

F

2016

F

2018

F

2020

F

2022

F

2024

F

2026

F

2028

F

2030

F

Current capacity Secondary supply

Under development Planned

Prospective World requirements


Recent M&A activities of uranium assets

Cross border M&A on uranium assets is set to increase due to the mismatch of uranium resources and demand, in our view. Especially, the huge nuclear capacity build out in Asia has led to concerns over the nuclear fuel security and Asia countries have been actively searching for uranium assets in Kazakhstan, Australia, Canada and countries in Africa. In particular, China currently relies on imports for about half of its uranium needs, with supplies coming from Russia, Namibia, Australia and Kazakhstan. As we expect China’s nuclear capacity to reach 70GW by 2020F (from the current 8.6GW), China is likely to import 80% of its uranium by then.

Uranium resources in Australia have been targets of acquisition, which require approval from the Foreign Investment Review Board. One recent deal is China Guangdong Nuclear Power Holding Corp’s (CGNPC) 70% stake purchase of uranium explorer Energy Metals Ltd. The Australian government approved CGNPC subsidiary China Uranium Development Co’s A$83.6mn (US$76mn) offer for Energy Metals in October 2009. Other acquisitions by foreign investors are listed below.

Exhibit 94. Foreign acquisition of Australian uranium assets

Company Main deposits Overseas investor, share Value of share (A$) Date

Pepinini Curnamona project, Crocker's Well Sinosteel, 60% of project 31mn Sep-06

Uranium One Honeymoon Mitsui, 49% of deposits 104mn Dec-08

Uranium One Honeymoon Japanese consortium, 20% of company Jan-09

Rio Tinto Kintyre Cameco & Mitsubishi, 100% of deposit 518mn Jul-08

Mega Uranium Lake Maitland Itochu consortium, 35% of project 77mn Feb-09

Energy Metals Bigrlyi 54% China Guangdong NPC, 70% of company 86mn Aug-09 Source: WNA

Kazakhstan, which has ambitious goals to double its uranium production to 30,000tU by 2018, has attracted investments from China, Canada, Russia, and France in its uranium assets. Similarly, Kazatomprom, the government-owned national atomic company, has also made investments in foreign companies in the industry. In 2007, it purchased a 10% stake in Westinghouse.

Kazakhstan has also been cooperating with China in a few projects. Following Chinese President Hu Jintao’s visit to Kazakhstan in December 2009, the two countries are expected to sign an agreement for China to receive nuclear power assistance from Kazakhstan, according to a China Daily report.

Australia uranium assets: acquisition targets

China is a close partner



China Guangdong Nuclear Power Co (CGNPC) has already begun cooperating with Kazakhstan’s state nuclear power firm for uranium. The legal framework will allow for further cooperation in the nuclear energy field.

CGNPC is a 49% joint venture partner in two mines while China National Nuclear Corp (CNNC) is a 49% joint venture partner in another. Sino-Kazakhstan Uranium Resources Investment Co, a CGNPC subsidiary, will invest in the Semizbai-U JV for the Irkol and Semizbai mines, with 640tU and 425tU per year, respectively. CNNC will invest in the Zhalpak project, with 640tU per year. The uranium will be supplied to China as fabricated fuel.

Exhibit 95. Foreign acquisition of Kazakhstan uranium assets

Company, project or mine Foreign investor and share Value of share or project if known

Inkai JV (Inkai mines) Cameco, 60% n.a.

Betpak Dala JV (South Inkai, Akdala mines) Uranium One, 70% US$350mn for 70% in 2005

Appak JV (W.Mynkuduk) Sumitomo, 25%, Kansai, 10% US$100mn total in 2006

JSC Akbastau & Karatau (Budenovskoye deposit) ARMZ, 50% (agreement to sell Karatau share to Uranium One)

n.a.

Zhalpak CNNC, 49% n.a.

Katco JV (Moinkium, Tortkuduk mines) Areva, 51% US$110mn in 2004

Kyzlkum JV (Kharasan 1 mine) Uranium One, 30%, Japanese, 40% (Marubeni, Tepco, Toshiba, Chubu, Tohoku, Kyushu)

US$75mn in 2005 for 30%, US$430mn total in 2007 (both mines)

Baiken U JV (Kharasan 2 mine) Japanese, 40% (Marubeni, Tepco, Toshiba, Chubu, Tohoku, Kyushu)

US$430mn total in 2007 (both mines)

Semizbai-U JV (Irkol, Semizbai mines) CGNPC, 49% n.a.

Zarechnoye JV (Zarechnoye & S.Zarechnoye mines) ARMZ, 49% US$60mn total Source: WNA

CGNPC and CNNC already have investments here



Global outlook

Global outlook for other renewables Clarisse Pan +852 2252 2192 / [email protected]


Other technologies hold significant potential, but their time is yet to come

Biomass: a longer-term story

According to the International Energy Association’s (IEA) long-term estimate, biomass-based energy can sustainably contribute 25-33% of global energy needs by 2050F. The IEA study suggests that the theoretical potential for biomass is around 1500EJ/year by 2050F. However, we note that given several sustainability constraints the prudent estimate comes down to 200-500EJ/year (excluding aquatic biomass). Of this, forestry and agricultural residues and other organic wastes (including municipal solid waste) would account for 50-150EJ/year, while the rest would come from energy crops, surplus forest growth and increased agricultural productivity.

We believe that similar to other renewable energy technologies, a key factor that would enable bioenergy reach its true potential is favourable government policies and technological advancement that would bring down the cost. In the mid-term, ie up to 2030F, strong renewable targets will be the main driver behind the increase in biomass demand, and feedstock such as use of residues and wastes, sugar, starch and oil crops, and increasingly, non-food crops (organic wastes, forestry residues, high yielding woody or grass energy crops and algae) will be utilised to meet this demand.

According to the IEA, China, India and the US are likely to lead the biomass-to-power expansion in the next few decades. In the medium term, the focus for biomass-to-power will likely be on decentralised biomass systems, especially where feedstock is readily available. The IEA estimates biofuel production will grow by 6-8% pa and contribute around 5% of total road transport fuel in 2030F.

Exhibit 96. IEA projections for biomass-to-power generation

0

200

400

600

800

1,000

1990 2007 2015F 2020F 2025F 2030F

(TWh)


Biomass can sustainably contribute 25-33% of global energy needs by 2050F



Exhibit 97. IEA projections for biomass-to-power installed capacity

0

40

80

120

160

200

2007 2015F 2020F 2025F 2030F

(GW)


Exhibit 98. Overview of global technical potential of land-based biomass supply (primary energy)

Biomass category Technical biomass potential year 2050F (EJ/yr)

Energy crop production on surplus agricultural land 0 – 700

Energy crop production on marginal lands <60 – 110

Residues from agriculture 15 – 70

Forest residues 30 – 150

Dung 5 – 55

Organic wastes 5 – >50

Total <60 – >1100


Geothermal to grow more than 70% to 18.5GW by 2015F

With an addition of just 397GW of installed capacity, implying 3.8% y-y growth, geothermal energy has lagged behind the high growth seen in other renewable energy technologies such as wind and solar. We note that the growth in installed capacity in 2009 was concentrated in the US and Indonesia, which together contributed 79% of the global capacity additions. The US has the largest geothermal capacity, now just over 3GW (28.8% of the world total), followed by the Philippines (1.9GW), Indonesia (1.2GW) and Mexico (1GW).

However, with nearly 8GW of projects under development, we are witnessing a lot of interest in geothermal technology due to a combination of base load power, cost-competitiveness and zero-emissions. According to the International Geothermal Association, the installed capacity of geothermal energy is expected to grow more than 70% to 18.5GW by 2015F, from 10.7GW in 2009.

Geothermal energy is expected to grow to 18.5GW by 2015F, from 10.7GW in 2009



Exhibit 99. Geothermal expansion plan by countries

Country Development

Kenya Looking to produce 490MW of geothermal power by 2012F and as much as 4,000MW within 20 years.

Germany Has over 150 geothermal power plant projects at some stage of development and expects to have over 280MW on line by 2020F, according to the European Commission.

Turkey Has a goal to reach 550MW of geothermal power on line by 2013F.

Philippines Energy from geothermal power makes up approximately 18% of the country's electricity generation.

El Salvador Geothermal power plants provide 26% of the electricity.

Indonesia National Energy Blueprint sets a goal of 9,500MW of geothermal power production, an 800% increase.

Iceland Derives 25% of its electricity and 90% of its heating from geothermal resources.

US The world leader in geothermal electricity production with more than 3GW of installed capacity from 77 power plants.

Source: IGA, Nomura research

Exhibit 100. Geothermal installed capacity

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

2003 2004 2005 2006 2007 2008 2009 2010F 2015F

(MW)

Source: IGA, Nomura research

Hydropower is a mature energy source

According to the IEA, hydropower electricity generation is expected to reach 4,680TWh by 2030F, implying a CAGR of 1.7% over 2009-30F. We note that maximum capacity additions will take place in Asia, owing to low hydropower penetration, growing demand for electricity and huge hydropower resources. The hydropower sector in Asia has seen tremendous growth, mainly backed by hydropower rich countries such as China, Japan, India and Australia. With substantial unexploited hydropower resources, these countries are likely to see significant hydropower capacity additions, especially China and India.

We note that there is limited scope for development and expansion of hydropower in the OECD countries as the best sites have already been exploited, in our view. Moreover, environmental regulations constrain new development of hydropower resources. We note that according to the IEA some 160GW of hydropower capacity is currently under construction, of which half is in China; India is constructing 13GW, while Russia and Brazil each have about 5GW under construction.

Hydropower capacity in China grew at 10-18% pa between 2004 and 2009. However, based on recent comments by government officials on the nation’s hydropower development plans, cumulative hydropower capacity is scheduled to expand from 197GW at end-2009 to 405GW (including 75GW of small-hydro projects) by end-2020F, implying an 11-year CAGR of 7%.

Asia is seeing the most capacity additions in hydropower



We expect China Yangtze Power, the world’s largest hydropower producer with 21GW capacity on hand, to benefit from the growth of hydropower in China. We think the company is well positioned, given: 1) future asset injection from its parent (around 43GW in hydro assets are under construction at the parent level); and 2) a likely tariff hike to match the hydro tariff with the coal-fired tariff. Its shareholdings also offer an earnings cushion.

Exhibit 101. IEA outlook for hydropower electricity generation

0

1,000

2,000

3,000

4,000

5,000

1990 2007 2015F 2020F 2025F 2030F

(TWh)


Exhibit 102. Hydropower penetration by region

7

22

33

49

6975

0

10

20

30

40

50

60

70

80

Africa Asia SouthAmerica

Australasia NorthAmerica

Europe

(%)

Source: World Atlas of Hydropower & Dams, Nomura research

Concentrated solar power: strong takeoff expected in long term

We note that according to industry estimates (Greenpeace International, SolarPACES, and Estela), the cumulative capacity of CSP technology is expected to reach 830GW by 2050F, from around 1GW in 2009, implying a CAGR of 18% over the next 40 years, under a moderate scenario.

In our view, among the different CSP technologies, “parabolic trough” technology provides peak demand generation and will be the technology of choice. We note that several emerging technologies that promise higher conversion efficiencies and cost-competitive generation have been demonstrated on a smaller scale. These technologies, such as point-focusing power towers and line-focusing Fresnel reflectors, may extend the ability of CSP to provide shoulder or base-load power in addition to peak.

CSP technology is expected to reach 830GW by 2050F, from around 1GW in 2009



Highlights of moderate scenario (source: Greenpeace International, SolarPACES, and Estela)

Under the moderate CSP scenario, growth rates are expected to be substantially higher than under the reference version. The assumed cumulative annual growth rate starts at 17% for 2011F, and increases to 27% by 2015F. The growth rate stays at 27% pa until 2020F, then falls gradually to 7% by 2030F, 2% in 2040F and 1% after 2050F. As a result, the scenario foresees the following.

By the end of this decade, global solar power capacity is expected to reach 4GW, with annual additions of 2.9GW.

By 2020F, global solar power capacity is expected to reach 68.6GW, with annual additions of 12.6GW. By 2050F, the world is expected to have a combined solar power capacity of more than 830GW, with the annual market running close to 41GW.

In terms of generated electricity, the moderate scenario assumes that more than 246TWh is produced by concentrated solar power in 2020F. Depending on demand side development, this will account for 1.1-1.2% of global demand in 2020F and 8.5-11.8% in 2050F.

Exhibit 103. Operational experience, installed capacity and produced electricity by technology type

Technology type Installed capacity

2009 (MW) Electricity produced

up to 2009 (GWH)

Approximate capacity, under construction and

proposed (MW)

Parabolic trough 500 >16,000 >10,000

Solar tower 40 80 3,000

Fresnel 5 8 500

Dish 0.5 3 1,000 Source: SolarPACES, Estela, Greenpeace, Nomura research

Exhibit 104. CSP technology cumulative growth

0

100

200

300

400

500

600

700

800

900

2009

2010

F

2015

F

2020

F

2025

F

2030

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2035

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2040

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2045

F

2050

F

(GW)


Exhibit 105. CSP technology annual growth

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F

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F

(MW)


Going forward, we see an abundance of solar resources and qualified land for deployment of CSP. For example, as per government estimates, in south-western US alone, using the suitable land in proximity to the transmission network can provide 200GW of potential CSP production. This would represent about one-fifth of the projected US installed generating capacity by 2020F.

We see an abundance of solar resources and qualified land for deployment of CSP



China eyes CBM to alleviate energy shortage

With GDP growth long in the double digits, China has significant energy demand. The nation has long relied on coal to generate roughly three-quarters of its electricity. According to the Ministry of Land and Resources, China’s CBM resources total 36.8tn m3, the third-largest in the world, of which about 30% or 11tn m3 was exploitable reserves as at end-2007. Regions with the most abundant CBM resources include Shanxi, Shaanxi, Inner Mongolia and the northern parts of Xinjiang.

CBM, also known as coal seam gas or coal seam methane, is a form of natural gas, and notorious as the main cause of coal mine explosions. Unlike most gases that are stored in typical sandstone or other conventional gas reservoirs, methane is stored within the coal by a process called adsorption. The methane is in a near-liquid state, lining the inside of pores within the coal (called the matrix). It can be used as natural gas in homes and in industry (chart below right). CBM has some green attributes. Its use should help to reduce emissions of greenhouse gases and increase energy supplies. And as a collateral benefit, tapping it will make coal mines safer.

China has set an ambitious target to increase CBM use to 10bn m3 (or 10% of total gas use) by 2010F, from 0.5bn m3 (or 1% of total gas) in 2007. Meanwhile, by 2010F, nationwide proven reserves should increase to 300bn m3 and an integrated industry system should be set up.

We expect a bright future for the CBM industry in China, mainly because: 1) the natural gas shortage should spur CBM demand; 2) there is government support in terms of subsidies and a VAT rebate; and 3) it is a highly profitable business. At the same time, however, this business is intensive in terms of capital and technology, thus players need strong balance sheets. They also need sufficient reserves, execution ability on the operating side and self-owned downstream gas projects.

Exhibit 106. Global CBM resources Exhibit 107. China’s CBM output

40 26

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Russia Australia China US

Explored

10.9 tn m3 is minable reserves

Untapped

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2007 2010F 2015F 2020F

07-10F CAGR: 170%

10-20F CAGR: 28%

CBM output (bn cm)

Source: Ministry of Land and Resources, SinoPetro Industrial Express Source: Asia Pulse, NDRC, Nomura research

Coal seam gas in Australia Current LNG production in Australia is 100% conventional gas, derived from two offshore basins, both located on Australia’s west coast. Woodside operates the North-West Shelf (NWS) joint venture, which began exporting in 1989 and has a design capacity of 16.3mtpa, sourcing natural gas from the Carnarvon Basin. Younger and smaller Darwin LNG, operated by ConocoPhillips, began production in 2006, has a production capacity of 3.6mtpa and sources gas from the Bayu-Undan field in the Timor Sea.

East coast unconventional gas production is also relatively new, with BG Group’s A$5.0bn takeover of Queensland Gas in October of 2008 marking the beginning of an era of increased production and global interest in Australia’s CSG basins.

We see a bright outlook for the CBM industry in China



Exhibit 108. Australia’s CSG recent market transactions

Date Buyer Seller A$/GJ 2P A$/GJ 3P

2-Jul-09 Santos PEL 238 / 434 2.55 0.66

2-Jul-09 Santos Eastern Star Gas 3.75 0.97

22-Apr-09 Origin Pangaea na 0.57

3-Apr-09 Arrow Tipton West 0.71 0.3

9-Feb-09 BG Group Pure 1.96 0.41

24-Dec-08 AGL Sydney Gas 4.17 3.17

19-Dec-08 AGL PEL 285 2.11 0.97

28-Oct-08 BG Group QGC 1.93 0.75

8-Sep-08 ConocoPhillips Origin Energy 3.01 1.41

20-Aug-08 QGC Sunshine Gas 1.73 0.74

2-Jun-08 Shell Arrow 1.83 0.52

29-May-08 Petronas Santos 3.91 1.31

1-Feb-08 BG Group QGC 1.58 0.67

Average 2.44 0.96

Source: Eastern Star Gas, Deloitte, Nomura estimates

Current estimates point to Australia benefiting from more than 3.2bn boe of CSG reserves (2P) in the Surat-Bowen basin, and potentially an equal amount in the deeper and more technically challenging Gunnedah basin. New ventures by AWE could develop shale gas in Australia’s Perth basin, while Santos’s recent announcement points to the potential for 2.5bn boe of unconventional gas in the Cooper basin.



Asia-ex Japan

China alternative energy Clarisse Pan +852 2252 2192 / [email protected]



China wind power sector We believe that wind power will continue to receive the strongest support from the Chinese government as the preferred renewable energy, owing to its superior economics and scalability. In addition to a standardised and improved wind tariff scheme announced in July 2009, we note that the central government started refining regulations on grid connections and wind power dispatches in late-2009 to resolve grid bottleneck issues and ensure a healthy long-term outlook for wind power. In the recently amended Renewable Energy Law, the government has also tried to streamline funding sources for wind subsidies.

While we believe that policy support and growth here will remain strong, we see this year as a transitional one for players along the China wind value chain. We estimate that growth of annual wind capacity installation will start to slow from 100% y-y each year between 2007 and 2009 to around 15% y-y in 2010F. As a majority of Chinese wind companies have been generating 70-90% of their wind revenues within China, those unable to start to bring in meaningful overseas revenue will, we believe, begin to see earnings growth slow significantly.

Besides slowing the growth rate of capacity installation (end demand) within China, we identify several other challenges: 1) grid connection bottlenecks; 2) overcapacity within certain segments such as blades and wind turbine generators (WTG); 3) the outlook for Clean Development Mechanism (CDM); and 4) quality concerns at Chinese equipment/component manufacturers, which generally have a short track record.

According to several National Development and Reform Commission (NDRC) officials and industry players, the Chinese government is likely to announce in 3Q10F a cumulative wind power capacity target of 150GW by 2020F, implying an 18% 11-year CAGR. We believe that the Chinese wind industry could surpass this target and we remain confident about the clear visibility into wind demand growth in China. Nonetheless, we adopt a more selective approach on stock picks and prefer equipment/component manufacturers that can start meaningful overseas sales and sustain a high earnings growth profile. We retain our conservative stance on wind turbine manufacturers and wind farm operators. Our top pick is China High Speed Transmission (CHST).

China is the world’s fastest-growing wind power market

The Chinese government unveiled its “Renewable Energy Mid-to-Long-Term Development Plan” in September 2007, where the government has set a target for cumulative wind power capacity to grow from 1.26GW at end-2005 to 5GW by end-2010F and 30GW by end-2020F. However, the pace of wind power capacity installation has, so far, significantly surpassed the goal set by the government.

According to the Global Wind Energy Council (GWEC), China installed 13.8GW of wind power capacity in 2009, taking cumulative wind power capacity to 25.9GW at end-2009.

As elsewhere, wind is the cornerstone of the new green energy drive

Significant growth has built such a high base that overseas markets must be built to maintain momentum

We favour those with an overseas strategy: our top pick is China High Speed Transmission



Exhibit 109. Global top 10: cumulative capacity (2009)

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Source: Global Wind Energy Council (GWEC), Nomura research

Exhibit 110. Global top 10: annual installation (2009)

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Source: GWEC, Nomura research

According to several NDRC officials and industry players, China’s NDRC is drafting a stimulus plan for the alternative energy industry, which will raise the country’s cumulative capacity target for wind power from the current 30GW to 150GW by end-2020F, which implies a very steady CAGR of 18% through 2020F.

Exhibit 111. Potential new NDRC targets for renewable energy sources

Existing 2020F targets Potential new 2020F targets

(GW) 2009 2020F 09-20F CAGR (%) 2020F 09-20F CAGR (%)

Nuclear 9 40 15 70 20

Wind 25 30 2 150 18

Solar 0.3 1.8 18 20 46

Note: potential 2020F targets for wind, solar and nuclear power are based on recent news flow

Source: CBN, China Energy News, Nomura estimates

Moreover, based on our estimates, China could install another 15.8GW of wind capacity in 2010F, which would lift China’s cumulative wind power capacity beyond 40GW by end-2010F. This implies China will far surpass the NDRC’s current plan of 30GW by end-2010F.

Exhibit 112. China: cumulative and new installation wind capacity

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New installation (LHS)

Cumulative capacity(GW) (GW)

Source: BTM Consult, GWEC, Nomura estimates



China’s wind power market is expected to grow consistently faster than the global market through to 2030F, based on our estimates, as we expect China to steadily gain share in the global wind power market. We forecast that China’s global wind market share will gradually expand from 16% in 2009 to around 18% in 2020F.

Exhibit 113. China: cumulative wind power capacity and global market share

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High visibility but growth to slow to a normal 15% in 2010F

With 13.8GW of new capacity installation, China has become the largest wind power market in the world since 2009. Cumulative wind power capacity in China grew at an impressive rate of 115% y-y in 2009, owing to favourable government policies and easier availability of project financing. The entry of three Chinese players — Sinovel, Goldwind and Dongfang — into the top-10 global wind turbine generator (WTG) suppliers also clearly reflects the growing prominence of China in the global wind energy sector.

Exhibit 114. Global WTG market share (2009)

GE Wind13%

Sinovel9%

Enercon9%Goldw ind

7%

Gamesa7%

Dongfang7%

Suzlon7%

Siemens6%

Others19%

Vestas13%

REpow er3%

Source: BTM, Nomura research

Although we believe that visibility into wind demand in China remains strong this year, we expect the growth rate to slow in 2010F to a more normal 15% y-y rate, owing to a high base effect and grid connection bottlenecks. We estimate China’s annual installation will reach around 15.8GW in 2010F.

China likely to deliver about a fifth of the world’s wind power in 2020F, on our estimates

Three Chinese players rank in the global top-10



Exhibit 115. China: annual installation

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Exhibit 116. China: cumulative installation

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Growth y-y (%)

(GW) (%)


Grid connection bottlenecks remain a serious challenge

Based on cumulative wind capacity data from the China Electricity Council (CEC) and China Wind Energy Association (CWEA), we estimate around 37% of installed wind turbine generators were not connected to the grid as at end-2009. This was a significant jump from 26% in 2008. Although we expect this gap to trend slightly downwards to 35% in 2010F, we believe grid connection bottlenecks remain a serious challenge for wind power companies in China.

While the central government started to grapple with such issues in 2009 and is expected to adopt measures to improve grid connection and wind power generation conditions, we only expect the grid issue to be resolved gradually over the next three to five years.

Exhibit 117. China: % of WTG lacking grid connection

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2007 2008 2009 2010F

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40 CEC cumulative capacity

CWEA cumulataive capacity

Gap estimate (RHS)

(GW) (%)

Source: China Electricity Council (CEC), China Wind Energy Association (CWEA), Nomura estimates

In our view, the grid connection problem in China is a result of:

Mismatch between locations of wind resource and power consumption. China’s onshore wind resources are concentrated in the north, north-western and north-eastern regions, while power consumption is higher in the south-eastern coastal areas. According to the CWEA, by end-2009, the top-five provinces with the highest cumulative wind capacity were Inner Mongolia, Hebei, Liaoning, Jilin and Heilongjiang. These five provinces comprised some 70% of China’s cumulative wind capacity at end-2009.

Better grid connection needed

But it is not windy where the economy is thriving



On the other hand, power consumption was the highest in Guangdong, Jiangsu, Shandong, Zhejiang and Hebei provinces in 2009, according to the CEC. These five provinces accounted for some 40% of China’s overall power consumption in 2009.

To resolve this issue, the Chinese government has been exploring the possibility of establishing or relocating high energy consumption industry bases to provinces with rich wind resources. Moreover, the government has plans for the construction of ultra-high-voltage grid lines to transmit power from north, north-western and north-eastern China to Beijing, Tianjing and Tanggu and environs to the middle of China.

Exhibit 118. China wind resource distribution

Source: Center for Wind and Solar Energy Resources Assessment

Lack of centralised planning for construction of grid network and wind farms. Due to poor economics, grid operators normally have less incentive to construct networks in remote provinces, where wind resources tend to be richer. The difference between construction lead time of grid operators and wind farm operators (more than two years and one year, respectively) intensifies the mismatch between construction of grid network and wind farms, in our view.

To resolve this issue, the Chinese government has stated in the updated Renewable Energy Law (revised in 2H09 and coming into effect in April 2010) that the nation ought to have centralised planning for construction of grid network and wind farms. While at the provincial level, each province will have near-term and medium-term planning, the central government would provide long-term, bigger-picture guidance and ensure consistency between plans of different provinces.

Immature grid quality and operating technology to handle wind power effectively. The intermittence of wind power generation has increased the difficulty for grid operators to manage and utilise wind power effectively. As major grid operators lack adequate experience handling wind power, and the quality of grid networks in remote areas (with their richer wind resources) tends to weaker; at times wind farm operators will be told by grid operators to halt feeding power into the grid for the sake of “grid network safety”.

To resolve this issue, the Chinese government has stated in the updated Renewable Energy Law that grid operators are responsible for enhancing grid

Move the industry to where the wind is?

Wind comes and goes and this challenges the grid



quality and establishing a smart grid network to better utilise power generated by renewable energy projects.

More importantly, in the updated Renewable Energy Law, the Chinese government specified that relevant government agencies would soon announce minimum requirements on renewable energy purchase (in terms of percentage of overall power purchase) for grid operators to ensure there is no waste in renewable power generation.

Favourable government policy to continue

We expect the Chinese government to unveil a stimulus package for the new energy industry in 3Q10F, which should be widely expected by the market, since the capacity targets have been circulated by the industry since mid-2009. We expect the Chinese government to raise the cumulative wind capacity target from the original 30GW to 150GW by 2020F.

We also believe that the Chinese government will provide a clearer guideline to enhance grid connection and grid quality. Based on our estimates, by end-2009, about 37% of the installed wind capacity in China was not connected to the grid, implying waste in wind farm investments. While the central government has thought through such issues and is expected to adopt measures to improve current conditions, we only expect the grid issue to be resolved over the next three to five years.

While the NDRC issued a notice at the beginning of 2Q10 indicating that power tariffs and prices of certain natural resources will trend upwards, we do not expect the government to raise wind power tariffs in 2010F or 2011F, given declining WTG prices and robust project pipelines announced by major wind farm operators.

Although we do not expect the standardised wind power tariffs (next exhibit) to be raised in the near term, checks with wind farm operators suggest the Chinese government will raise wind power tariffs for certain national-level concession projects, with tariffs even lower than benchmark coal-fired tariffs.

Exhibit 119. China: wind tariff scheme

Location Feed-in-tariffWind resource Province (RMB/kWh)

Type I (Strongest) Inner Mongolia, Xinjiang 0.51

Type II Hebei, Inner Mongolia, Gansu 0.54

Type III Jilin, Heilongjiang, Gansu, Ningxia, Xinjiang 0.58

Type IV (Weakest)

Beijing, Tianjin, Hebei, Shanxi, Liaoning, Jilin, Heilongjiang, Shanghai, Jiangsu, Zhejiang, Anhui, Fujian, Jiangxi, Shandong, Henan, Hubei, Hunan, Guangdong, Guangxi, Hainan, Chongqing, Sichuan, Guizhou, Yunnan, Shanvxi, Qinghai

0.61

Source: NDRC

Other policy supports include:

Initiation of national-level concession projects. Before the announcement of the Renewable Energy Law, which provides fundamental guidelines for the development of renewable energies in China, the government conducted concession projects annually at the national level to promote the development of wind power since 2003. Through public tendering, the government granted exclusive rights to successful bidders to develop large-scale (above 50MW) wind projects. The government will ensure grid connections, as well as guarantee that power companies purchase electricity generated from wind projects at pre-determined rates. Other government support initiatives include wind resource evaluations and feasibility studies.

While we do not expect the government to be aggressive in launching onshore concession projects, we note that there are currently four offshore concession

Quite a bit of wind off grid



projects open for public bidding. We believe that the Chinese government will again adopt national-level concession projects as a tool to boost development of offshore wind farms in China.

Grid operators must provide grid connection to renewable energy. According to the Renewable Energy Law, power grid operators must provide grid connection services and take up all the electricity resources available.

Incremental renewable energy cost must be shared among electricity users. According to the Provisional Administrative Measures on Pricing and Cost Sharing for Renewable Energy Power Generation and the Provisional Regulation on Renewable Energy Surcharge, the difference resulting from higher on-grid tariffs of renewable energy over average on-grid tariffs of conventional thermal electricity, should be shared equally by all electricity users across the nation.

The Chinese government has a Renewable Energy Development Fund through collecting Renewable Energy Surcharges of RMB0.2/kwh, RMB0.2/kwh, and RMB0.1/kwh from secondary, tertiary, and residential electricity users (primary users are exempted), respectively, along with their electricity bills. So far, this fund has subsidised various types of renewable energy projects including wind, biomass, concentrated solar and solar PV, while wind power received the majority of the subsidies given that it has the most robust development in China.

Renewable energies R&D subsidies. The Ministry of Finance has set up the Renewable Energy Development Fund to support R&D and demonstrative projects of renewable energy, as well as encourage the localisation of equipment production. In addition, renewable energy companies can apply for R&D subsidies from: 1) the National Natural Science Foundation of China; and 2) the Ministry of Science and Technology’s ‘High-Tech Research and Development Program of China’ (‘863 Program’) and the ‘National Basic Research Program of China’ (‘973 Program’).

Preferential tax treatment. Wind project operators enjoy a preferential value-added tax of 8.5% (compared with 17% originally). Import tariffs on wind turbines have been halved to 6%; the import tariff on wind components is 3%. In addition, the government recently raised export VAT rebates on wind gearboxes and related components to 15%.

Compulsory renewable energy capacity share. According to the Renewable Energy Mid-and-Long-Term Plan, any power producer with capacity of more than 5GW must increase actual ownership of power capacity from non-hydro renewable energies to 3% and 8% of its total capacity by end-2010 and 2020, respectively. Given that wind power is currently the cheapest and most scalable among non-hydro renewable energies, we believe that it will be the likely choice for power producers to meet their renewable energy requirements.

Chinese government to pursue “regulated”growth

China wind capacity installation has been growing at more than 100% pa since 2006. This super-charged growth rate, in our view, is the root cause of several major issues in China’s wind industry, including grid connection bottlenecks, oversupply of low quality components/equipment and low returns for wind projects.

We note that the Chinese government has changed its stance, pursuing more “regulated” growth since mid-2009. Senior government officials have publicly categorised wind turbine manufacturing as being a “significantly oversupplied industry” in China, and have requested that local banks tighten lending to wind turbine manufacturers to keep the boom from turning to bust.

Recently, according to Reuters (9 June, 2010 ), Chinese regulators have been ordered to freeze some IPOs of renewable energy companies on concerns over overcapacity issues in the wind turbine and polysilicon manufacturing industries, which is another measure to prevent over-expansion.

Preferential tax rates one way to help build the industry

Growth has been a bit too rushed

Government putting the brakes on a bit



According to CWEA, China’s wind turbine manufacturing segment was highly fragmented in 2009, with the top-three producers (Sinovel, Goldwind and Dongfang) comprising 60% of the market and the rest of the market made up of more than 70 small producers.

Exhibit 120. China: WTG market share (2009)

Sinovel26%

Goldwind20%Guodian

6%Dongfang

15%

Mingyang5%

Vestas4%

Xiangtan3%

GE2%

Suzlon2%

Gamesa2%

Shanghai Electric2%

Windey2%

Repower1%

Others10%

Source: CWEA, Nomura research

In the medium term, the Chinese government is likely to encourage greater consolidation within the wind turbine manufacturing segment. The top four state-owned suppliers are Sinovel, Goldwind, Dongfang and Guodian.

Another aspect reflecting the Chinese government’s tightening control over the wind sector is the government’s centralised approach to monitoring the expansion of wind capacity and grid construction. The Chinese government has stated in the updated Renewable Energy Law that the nation ought to have centralised planning for the construction of grid network and wind farms. While each province will have near-term and medium-term planning, the central government will provide long-term, bigger-picture guidance and ensure consistency between plans of different provinces.

In our view, a more regulated market with a more normal growth rate would help to enhance the quality of wind components/equipments in China and consequently lift wind farm operators’ return profile. However, during the transition period, we believe that smaller domestic players and foreign players could suffer.

Consolidation part of the plan

Oversight part of the plan



Chinese wind companies should continue to dominate the market

We observe that Chinese wind turbine producers have increased their share in the China wind market from 20% in 2004 to 87% in 2009. We expect Chinese wind turbine and component manufacturers to sustain their dominant market share in China over the next few years, given their close ties with local wind farm operators (mainly state-owned power producers) and cost leadership.

We note that the wind farm operators in China are generally very cost sensitive, owing to the low wind power tariffs in China. Based on our checks, foreign turbine manufacturers have recently seen improving order flow. We take this as a sign of market opening, as well as change in customer mentality from pure cost per MW to cost per MWh.

In our view, even though the Chinese government lifted the 70% local content requirement in December 2009, the impact on Chinese manufacturers will be minimal as a majority of the leading foreign wind turbine manufacturers such as Vestas, GE, Gamesa and Suzlon, have had production facilities set up in China for more than three years — and have constantly lost market share to their Chinese peers.

Exhibit 121. Chinese wind turbine makers gaining share in China

20%

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77%87%

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Source: CWEA, Nomura research

Recently, the Chinese government started to encourage development of offshore wind farms. While the majority of the Chinese wind turbine manufacturers do not have a track record in offshore applications, the feedback we received from wind farm operators shows that they might still prefer Chinese wind turbines, since they are so cost competitive.

WTG oversupply leading to ASP decline

Our channel checks suggest that prices for WTG have declined by around 18% in China in 2009, given aggressive capacity expansion, softer raw material prices and fierce competition between WTG manufacturers. We believe this trend will continue in 2010F and expect another 15% y-y ASP decline this year.

In our view, WTG players in China are facing high overcapacity and are willing to lower their selling prices to secure new orders. Moreover, WTG players are looking to pass on savings to customers in the form of lower WTG prices, owing to reduced raw material costs, especially falling steel prices since 2009.

Based on our checks with wind farm operators, foreign turbine manufacturers currently command an ASP premium of 10-15% to that of their Chinese peers. It will be interesting to observe to what degree foreign turbine makers will try to compete on price; the fall in the euro has surely freed up some room here.

Formidable cost advantage in turbines

A cheaper euro likely means more competition



Offshore wind development to be the next growth driver

According to comments made by wind operators including China Longyuan and China Windpower, the majority of the attractive locations for onshore wind farm development have already been occupied by industry players. As a result, we expect offshore wind development to become the next growth driver of China’s wind industry over the next three years.

Based on industry checks, the Chinese government launched a public bidding for four offshore wind projects (Jiangsu Binhai, Sheyang, Dafeng and Dongtai) in May 2010, the results of which are expected to be announced this September. According to China Securities Journal, China Longyuan Power, Huaneng New Energy, China Guangdong Nuclear, and Guohua Energy Investment are participating in the bidding.

So far, China does not have a standardised tariff scheme for offshore wind projects and the tariff rates are expected to be granted on a project-by-project basis. The wind tariff granted for the Donghai Bridge project near Shanghai was RMB0.978/kwh, significantly lower than the tariffs of offshore wind farms in Europe at around €0.15/kwh. Nonetheless, according to Longyuan, operators expect to generate profits from offshore wind projects if the tariff is above RMB0.80/kwh.

Given the unclear outlook on offshore wind tariffs and thus the uncertainty over offshore wind farm returns, we believe that the development of offshore wind farms could be neutral to Chinese wind farm operators at the current stage.

However, in our view, the development of offshore wind projects could benefit Chinese wind component and equipment manufacturers. While the majority of these companies do not have track records in offshore applications, the feedback we took in from wind farm operators suggests that they might still prefer Chinese wind turbines and components based on cost considerations.

According to CWEA, so far, only Sinovel has launched 3MW wind turbines for offshore applications, while Shanghai Electric and Dongfang have used 2MW and 1.5MW turbines, respectively, for offshore installations. We expect Goldwind to launch its 3MW hybrid-drive turbines in 2H10F for offshore installation. Based on checks with China High Speed Transmission, we believe that other leading turbine manufacturers are also in the process of launching 3MW turbines.

Exhibit 122. Chinese turbine makers with offshore installations (2009)

Company Unit Capacity (MW)

Sinovel 2 6

Dongfang 41 61.5

Shanghai Electric 3 6

Haizhuang 4 8

Source: CWEA

To summarise, we expect companies such as CHST to benefit from the offshore wind development trend in the near term. Other players in this sector include Sinovel and Goldwind. However, we do not view this as a positive catalyst for wind farm operators, given the unclear tariff and return outlook.

Again, low cost goes a long way in winning bids, even absent a track record



We prefer component/equipment makers ready to start export

Based on our expectation of flattish wind power tariffs and slowing growth in China this year, we continue to prefer wind component/equipment makers that are capable to start exporting out of China, such as CHST, as this should help to sustain growth in the near future.

In addition to CHST, in 2009, domestic wind turbine manufacturers including Sinovel, Goldwind and Shanghai Electric, had very minimal overseas shipments, accounting for 0.2-2.0% of overall shipments.

Exhibit 123. Chinese turbine makers with overseas shipments (2009)

Company Destination Capacity (MW)

Sinovel India 15

Goldwind US 4.5

Shanghai Electric UK, Thailand 6.25

Source: CWEA

We remain conservative on downstream wind farm operators given unattractive project returns, uncertainty from CDM income and grid connection bottlenecks.

CHST remains our top pick

CHST remains our top sector pick, owing to its strong margin outlook, cost control capability, steadily improved product mix and undemanding-looking valuation. We reaffirm our conservative view on China Longyuan Power, given what we see as demanding valuation (despite its position as the largest wind operator in Asia). We await further progress on Suzlon’s order inflows and balance sheet clean-up to turn positive on the stock despite its undemanding valuation.

Exhibit 124. Listed Chinese wind-concept companies

Gearbox

China High Speed Transmission 658 HK

Blade

Jiangsu Miracle Logistics System 002009 CH

Sinoma Science & Technology 002080 CH

Tianjin Xinmao Science & Technology 000836 CH

Wind turbine

Dongfang Electric 1072 HK

Shanghai Electric 2727 HK

A-Power Energy Generation Systems APWR US

Baoding Tianwei Baobian Electric 600550 CH

Guizhou Changzheng Electric 600112 CH

Huayi Electric 600290 CH

Lanzhou Great Wall Electrical 600192 CH

Ningxia Yinxing Energy 000862 CH

Xiangtan Electric Manufacturing 600416 CH

Wind project operator

Guangdong Baolihua New Energy 000690 CH

Shanghai Huitong Energy Resource 600605 CH

Shenyang Jinshan Energy 600396 CH

Ningxia Yinxing Energy 000862 CH

China Windpower Group 182 HK

China Power New Energy 735 HK


CHST seems best positioned for expansion



China solar photovoltaic sector China’s solar PV sector used to be “unloved” by the government given its much higher generation costs relative to the cost of conventional or even other renewable energy sources, such as hydro and wind power. The NDRC’s current Renewable Energy Development Plan only targets 1.8GW of cumulative solar PV capacity by 2020, far lower than the 40GW target for nuclear and 30GW target for wind.

Nonetheless, with China becoming the world’s largest producer in 2008, the Chinese government has turned more supportive to develop domestic consumption for solar. That being said, we believe that it is unlikely the government will unveil feed-in tariffs for solar PV in 2010F. Moreover, we expect domestic demand to enhance only the volume outlook for Chinese companies, not their earnings outlook, given current low solar project returns at home.

Our top pick is JA Solar, given its strong earnings momentum over the next few quarters, low exposure to euro depreciation and positive changes in its business model and customer portfolio, which we expect to help drive a valuation re-rating of the stock. We maintain our BUY rating on Yingli, given its long-term prospects, brand equity and cost leadership. We see long-term investment value emerging after recent weak share performance.

China has been the chief solar producer since 2007

China has been the leading manufacturing country for solar photovoltaic (PV) products since 2007. According to Photon International, China accounted for 38% of global solar PV cell production in 2009, up from 33% in 2008, and more than double the share of the number-two player, Germany (15% global share). In 2009, Chinese solar companies Suntech, Yingli, JA Solar and Trina made it into the global top-10 cell producers, accounting for 5.7%, 4.3%, 4.2% and 3.2% of global supply, respectively.

Exhibit 125. China’s share of global solar cell production

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2007 2008 2009 2010F

0

10

20

30

40

50

60Volume (LHS) Global Share (RHS)(MW) (%)

Source: Photon International, Nomura estimates

China is the world’s largest solar producer

JA Solar stands out here

China has four solar producers among the global top-10



Exhibit 126. Global solar cell production by country (2009)

China36%

Germany14%

Taiwan11%

Malaysia6%

Japan12%

Africa and Middle East0%

India2%US

4%

Rest of Europe4%

Rest of Asia11%


Going into 2010F, we expect China’s solar production to rise by 50% y-y, enabling it to maintain its lead in the global market. Based on company guidance, major listed Chinese solar companies, on average, will ramp up capacity by 57% y-y this year. We estimate that listed Chinese solar companies accounted for roughly 50% of China’s solar production in 2009.

Exhibit 127. Cell capacity of major Chinese solar companies

(MW) 2009 2010F (% y-y)

Renesola 120 240 100

Solarfun 360 480 33

CSIQ 420 700 67

Trina 600 900 50

Yingli 600 1,050 75

Suntech 1,100 1,400 27

JA Solar 800 1,500 88


But China remains a small end market for solar as of 2009

Demand for solar PV has historically been very weak in China, owing to high generation costs, poorer scalability and the lack of government support. Despite being the largest solar PV producer in 2009, China had only cumulative solar PV capacity of 0.25GW by end-2009, much smaller than major solar PV markets such as Germany (9.1GW), Spain (3.3GW) and Japan (2.4GW).

Although annual solar installation jumped 4x from 45MW in 2008 to 160MW in 2009 (see chart below), owing to a wave of favourable government policy, the 2009 annual installation figure fell short of market expectations of 400-500MW. We believe that part of this was due to the time lag between project completion and grid connection, as well as the lack of a standardised feed-in tariff scheme in China.

But not as keen to use solar as to make it



Exhibit 128. China: solar PV new installation

0

20

40

60

80

100

120

140

160

180

200

2003 2004 2005 2006 2007 2008 2009

0

10

20

30

40

50

60

70

80

90

100

China new installation (LHS)

% of global (RHS)

(MW) (%)

Source: EPIA, Nomura research

Exhibit 129. Cumulative solar PV capacity (2009)

0

2,000

4,000

6,000

8,000

10,000

12,000

Ger

man

y

Japa

n

US

Spa

in

Ital

y

Chi

na

(MW)


China turning more supportive on domestic solar consumption

Since mid-2009, the Chinese government has turned more supportive on domestic solar consumption, which we view as a result of listed Chinese solar companies’ lobbying during the global solar downturn in 4Q08 and 1H09. We note that since the listed Chinese solar companies are typically among the top economic contributors in their localities, they are well supported by local governments.

With the end demand of these Chinese solar companies highly concentrated overseas, most of them were hard hit by the global downturn in 2H08 and 1H09, as money dried up worldwide.

We believe that the Chinese government has incentives to change its stance not so much from the angle of adopting solar PV as a major source of energy, but rather to maintain the nation’s leading position as a solar product supplier. This, in our view, is evidenced by the government’s limited financial subsidies to solar projects so far.

Exhibit 130. Global top-10 solar producers’ share (2009)

First Solar9%

Q-Cells5%

Others55%

Trina3%

Sunpower3%

Gintech3%

Kyocera3%

JA Solar4%

Yingli4%

Sharp5%

Suntech6%


The Chinese government is backing the lead here



Major solar subsidies in China

MOF and MOHURD have rolled out subsidies for BIPV projects. At the end of March 2009, China’s Ministry of Finance (MOF) and Ministry of Housing and Urban-Rural Development (MOHURD) jointly issued a policy that subsidises the installation cost of building-integrated PV (BIPV) projects in China at a rate of RMB1.5-2.0/watt, representing two-thirds of the solar system cost in China.

MOF announced its “Golden Sun Programme”. In July 2009, China’s Ministry of Finance (MOF) announced Temporary Management Method of Financial Subsidies for Golden Sun Demonstrative Projects, the second set of solar PV subsidy schemes by the ministry. Under the programme, the MOF will provide financial support to Golden Sun Demonstrative Projects, including on-grid and off-grid solar PV projects with scale larger than 300kw. The MOF will subsidise 50% and 70% of the investment costs of on-grid and off-grid solar PV projects, respectively, including solar system costs and grid connection costs. As at end-2009, the MOF had granted subsidies to some 500MW solar projects under the Golden Sun Programme.

NDRC likely to unveil much higher targets for solar PV. Various Chinese media have quoted industry experts and researchers at the Energy Research Institute of the NDRC, such as Dinghuan Shi, the President of the China Society for Renewable Energy, Zhongying Wang, Director of the Renewable Energy Development Centre of the NDRC and Huanli Shi, Researcher at the Energy Research Institute of the NDRC, on the event that the NDRC is likely to unveil higher targets for solar PV. Based on their talks, the NDRC is likely to raise its 2020 solar power target to 20GW (raised by about 1,000% from 1.8GW previously). This implies an 11-year CAGR of 46% through 2020F.

While the announcement of this new target has been later than the market’s expectation (originally expected in 4Q09 or 1Q10), our recent checks suggest that an announcement is likely in 3Q10F, when the Chinese government is expected to unveil stimulus packages for alternative energy and several other industries.

Exhibit 131. NDRC’s potential new targets for renewable energy sources

Existing 2020 targets Potential New 2020 targets

(GW) 2009 2020F 09-20F CAGR (%) 2020F 09-20F CAGR (%)

Nuclear 9 40 15 70 20

Wind 25 30 2 150 18

Solar 0.3 1.8 18 20 46

Note: 2020F potential targets for wind, solar and nuclear power are based on recent news flows

Source: CBN, China Energy News, Nomura research

China can be a major solar market based on potential NDRC targets

Based on the NDRC’s potential new 2020 target of 20GW, we estimate that cumulative solar PV capacity would rise at a 46% CAGR over the next 11 years. We also estimate that China’s annual new installation of solar PV products on average will account for 8-15% of the global annual market, making China one of the top-five solar PV markets in the world over the next decade.

Higher targets likely for solar PV



Exhibit 132. China cumulative solar capacity and global share

0

5

10

15

20

25

2009 2020 - Existing 2020 - Potential new target

0

2

4

6

8

10

12

14

16

China cumulative solar capacity (LHS)

China as % of global market (RHS)

(GW) (%)


Current lack of preferential feed-in tariff for solar PV a major hurdle

There is currently no standardised preferential tariff for solar in China, and we estimate that system owners would have an IRR of negative 8% without financial subsidies. Although there has been some speculation since the middle of 2009 that the Chinese government will unveil a feed-in tariff scheme for solar PV, we believe it is unlikely the government will finalise such a scheme this year, which should cap the installation potential, particularly for 2010F.

In 2009, the Chinese government hosted a public bidding for a 10MW project in Dunhuan and granted a RMB1.09/kwh preferential tariff to the project winner. Since then, the industry has expected a similar level of feed-in tariff to be announced for solar PV projects in China. We estimate that systems owners would have IRR of around 1% at this RMB1.09/kwh tariff level.

Chinese solar manufacturers believe that a tariff in the range of RMB1.2-1.5/kwh would ensure more reasonable returns, triggering demand growth.

In our view, the Chinese government is likely to opt for the establishment of a standardised national tariff scheme for solar (similar to the one implemented for the wind sector), ie, the central government will host public biddings for several solar projects in different regions to gradually learn what is the “cost” level for solar project investors and what is the tariff level that would give them the incentive to build solar projects.

We expect the tariff coming out of such a public bidding approach would be low, based on the experience of the Dunhuan bidding in 2009, as well as China’s wind power industry. Consequently, we believe that any feed-in tariff to be announced for solar PV would more likely provide a lift for volume, but not profitability for listed Chinese solar companies.

Introduction of a feed-in tariff would help to lift volume, but not profitability



Chinese polysilicon producers have scaled back expansion but oversupply should hold sway

We note that Chinese polysilicon makers have delayed or scaled down expansion since 2009. For example, we see slower-than-expected capacity expansion at LDK Solar, Shunda and Asia Silicon, while GCL Poly is the only exception. In general, we expect 2010F polysilicon capacity increase in China to be 10-15% slower than our original expectation.

In our view, the lack of sufficient funding as well as technology know-how to ramp up production in a timely manner are two major reasons for the delays. Although the credit environment in China has more or less been the envy of the world since 2008, the government, recall, has categorised polysilicon manufacturing as an industry in over-capacity and has made it clear to banks to reel in lending here. Recently, according to Reuters, Chinese regulators have been ordered to freeze some initial public offerings of renewable energy companies on concerns over overcapacity issues in the wind turbine and polysilicon manufacturing industries (9 June, 2010 ).

Exhibit 133. Chinese polysilicon manufacturers’ capacity expansion

0

20,000

40,000

60,000

80,000

100,000

120,000

2006 2007 2008 2009 2010F 2011F 2012F

(MT)


This being said, we believe oversupply of polysilicon will hold up in China as foreign incumbents have no difficulty exporting their production to China. Moreover, in this case, these incumbents generally offer a better price and higher product quality.

Exhibit 134. Polysilicon supply-demand gap

(50,000)

0

50,000

100,000

150,000

200,000

250,000

2008 2009 2010F 2011F 2012F

Polysilicon supply Global demand (solar+semi)

Supply-demand gap

(MT)


Polysilicon oversupply likely to persist in China



Outsourcing to China set to increase

Given the 15-16% FIT reduction in Germany, we expected solar project developers to look for a similar ASP reduction. Tier-one Chinese module companies have significant cost advantages compared with their European peers and, hence, can price their modules 15-20% cheaper than these peers without compromising quality. We expect high-cost European and Japanese companies to increase outsourcing to China to maintain profit margin. We are already witnessing a trend where European module customers are requesting tier-one Chinese solar companies such as JA Solar, Renesola and LDK Solar to manufacture modules for them. In our view, the trend of outsourcing to Chinese solar companies has enhanced their volume outlook, not just because of orders, but because it is also growing addressable market size.

Impact from weak EU outlook — mid-to-upstream more immune

As the outlook for European economies seems to be turning weaker, we currently see risks to solar demand in 2H10F and 2011F, given potential for a tighter credit/financing environment, and less generous financial subsidies from European governments. While it remains early to see whether a weaker macro environment will have an immediate impact on solar companies’ earnings outlook, we reckon that this could be an overhang to the solar sector in the near term. Given the depreciating euro, we believe profitability of downstream players, such as Yingli, could be hit in 1H10F, since 50-60% of its revenues are euro-denominated but only 0-20% of COGS is euro-denominated. We estimate 50-60% of its revenue is euro-denominated, 30% is in US dollars and the rest is in renminbi. In terms of costs, we estimate that 15-20% of its COGS are in euro, 70-75% in renminbi and the rest in US dollars.

However, with the majority of revenue and costs denominated in renminbi, mid-to-upstream players, such as JA Solar and LDK, appear more protected from euro depreciation in the medium term, in our view.

JA Solar is our top pick

JA Solar (BUY) remains our top pick from the China solar sector in the near term, given its strong earnings prospects over the next few quarters, low exposure to euro depreciation and positive changes in its business model and customer portfolio that we expect to help drive a valuation re-rating of the stock. We maintain our BUY rating on Yingli given its long-term prospects, brand equity and cost leadership. We see long-term value emerging after recent weak share performance, and believe there will be earnings upside in the near term as the company has adopted measures to mitigate the impact from euro depreciation. These measures count discounting accounts receivable to domestic banks, renegotiating contracts into US-dollar denominated ones, and raising euro-based ASP.

We remain NEUTRAL on LDK, given its stretched balance sheet, potential dilution risk from fund-raising and unclear outlook beyond 2Q10F. We also remain NEUTRAL on GCL Poly given its expansion into wafers, which does not appear to be earnings accretive and carries execution risks, in our view.

Nuclear power in China

China is undergoing its largest-ever nuclear power development programme. Although nuclear power accounted for only 1.1% of total installed power capacity in China in 2008 and 2% of total power generation, the government has plans to grow the nuclear share of China’s total generating capacity to 5% by 2020. This is based on recent reports by state media, which indicate that central authorities plan to revise their 2020 nuclear power capacity target from 40GW to 70-86GW. (China currently has 11 reactors in operation, with 8.6GW of generating capacity.) These plans are also supported by the head of China National Energy Administration, Zhang Guobao, who has a preference for nuclear power among the various alternative energy sources given its scalability, reliability and low generation costs.

Largest nuclear power development programme in history

Weaker macro backdrop likely to cast a shadow on the solar sector

We like JA Solar for its strong near-term earnings prospects and limited euro exposure



Exhibit 135. China: nuclear power plants in operation

Name Type Location Net capacity (MW) Date connected

Guangdong-1 PWR Guangdong 944 8/31/1993

Guangdong-2 PWR Guangdong 944 2/7/1994

Lingao 1 PWR Guangdong 935 2/26/2002

Lingao 2 PWR Guangdong 935 12/15/2002

Qinshan 1 PWR Zhejiang 279 12/15/1991

Qinshan 2-1 PWR Zhejiang 610 2/6/2002

Qinshan 2-2 PWR Zhejiang 610 3/11/2004

Qinshan 3-1 PHWR Zhejiang 665 11/19/2002

Qinshan 3-2 PHWR Zhejiang 665 6/12/2003

Tianwan 1 PWR Jiangsu 1,000 5/12/2006

Tianwan 2 PWR Jiangsu 1,000 5/14/2007

Total: 6 plants, 11 reactors 8,587

Source: World Nuclear Association (WNA)

Both China’s nuclear power installed capacity and generation have been growing rapidly since 1991. Installed capacity grew from 279 MW in 1991 to 8.6GW in 2008, which is equivalent to a CAGR of more than 25%. Meanwhile, nuclear generation grew from 0.5bn KWh in 1992 to 62.6bn KWh in 2008, representing a CAGR of more than 35%. The share of nuclear power in the generation mix also grew from 0.1% to 1.9% in 2007.

Exhibit 136. China: nuclear generation

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

2003 2004 2005 2006 2007 2008

(m kWh)

9% 5-yr CAGR

Source: China Electricity Council, Nomura research

Exhibit 137. China: nuclear capacity

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

(MW)

Source: NDRC, Nomura research

One of the reasons for China to expand into nuclear power is its heavy reliance on coal, which accounted for 82% of electricity generation in 2008. The problem with coal-fired power generation, other than its high GHG emissions, is that most of China’s coal reserves are located in the north or northwest regions, away from most of China’s economic activity. Nearly half of China’s rail capacity is currently used in transporting coal. Transportation becomes a bigger problem in the winter months when tracks are blocked by heavy snow, leading to delays in the delivery of coal and thus power shortages.

Nuclear power fits well into the equation to solve this problem because it emits no greenhouse gases during power generation and because nuclear power plants can be located in coastal areas, closer to economic centres. This base load electricity source also helps to meet China’s growing electricity demand, which the IEA projects will register a 4% CAGR over 2007-30.



Exhibit 138. China: electricity generation projections

3,318

5,622

6,692

7,810

8,847

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2007 2015F 2020F 2025F 2030F

(TWh)


The government’s potential capacity target of 70GW by 2020 is achievable, in our view. According to the World Nuclear Association (WNA), there are 57 nuclear power plants planned or under construction in China, which would increase nuclear power capacity by 61GW to 70GW by end-2020, exceeding the NDRC’s target of 40GW. If we include the 20 nuclear power projects under planning or in the application stage, then the cumulative nuclear power capacity could surpass 100GW by 2020F, more than double the government’s target. If all the announced projects materialise, we expect that average annual new installation of nuclear capacity to be 7.5GW over the next 12 years, implying a 12-year capacity CAGR of 22% through 2020F.

Exhibit 139. China: nuclear reactors in operation, under construction, planned and proposed, as of January 2010

Source: IAEA, WNA, Nomura research

11

90

20

37 79.0

38.9

8.621.9

0

10

20

30

40

50

60

70

80

90

100

Operating Under construction Planned Proposed

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

90.0

Capacity (RHS) # of reactors (LHS)

(GW)(No.)



Exhibit 140. China: nuclear power plants planned and under construction, as of January 2010

Plant Province MWe gross Reactor model Project control Construction start Operation

Lingao Phase II, units 1&2 Guangdong 2x1080 CPR-1000 CGNPC 12/05, 5/06 12/10, 8/11

Qinshan Phase II, units 3&4 Zhejiang 2x650 CNP-600 CNNC 4/06, 1/07 2011, 2012

Hongyanhe, units 1-4 Liaoning 4x1080 CPR-1000 CGNPC 8/07, 4/08, 3/09, 7/10 10/12, 2014

Ningde units 1-4 Fujian 4x1080 CPR-1000 CGNPC 2/08, 11/08, 12/09, 15/7/10 12/12/2015

Fuqing units 1&2 Fujian 2x1080 CPR-1000 CNNC 11/08, 6/09 10/13, 8/14

Yangjiang units 1-4 Guangdong 4x1080 CPR-1000 CGNPC 12/08, 8/09, 15/7/10, 15/3/11 8/13/2016

Fangjiashan units 1&2 Zhejiang 2x1080 CPR-1000 CNNC 12/08, 7/09 12/13, 10/14

Sanmen units 1&2 Zhejiang 2x1250 AP1000 CNNC 3/09, 12/09 10/13, 6/14

Haiyang units 1&2 Shandong 2x1250 AP1000 CPI 9/09, 31/7/10 5/14, 3/15

Taishan units 1&2 Guangdong 2x1700 EPR CGNPC 10/09, 1/7/10 12/13, 11/14

Shandong Shidaowan Shandong 210 HTR-PM Huaneng 10-Jan 2013 or 2014

Fangchenggang units 1&2 Guangxi 2x1080 CPR-1000 CGNPC 15/12/09 2014

Fuqing units 3-6 Fujian 4x1080 CPR-1000 CNNC 2010

Changjiang units 1&2 Hainan 2x650 CNP-600 CNNC or Huaneng Dec-09 2014, 2015

Tianwan units 3&4 Jiangsu 2x1060 VVER-1000 CNNC Oct-10

Hongshiding (Rushan) units 1&2 Shandong 2x1080 CPR-1000 CNEC/CNNC 2009 2015

Ningde units 5&6 Fujian 2x1080 CPR-1000 CGNPC

Dafan, Xianning, units 1&2 Hubei 2x1250 AP1000 CGNPC late 2010

Xiaomoshan (Jiulongshan), units 1&2 Hunan 2x1250 AP1000 CPI Apr-10 4/2015 - 2018

Taohuajiang units 1&2 Hunan 4x1250 AP1000 CNNC Sep-10 2015

Pengze units 1&2 Jiangxi 2x1250 AP1000 CPI 2010 2013-14

Haiyang units 3&4 Shandong 2x1250 AP1000 CPI 2010

Wuhu units 1&2 Anhui 2x1080 CPR-1000 CGNPC late 2011 2015

Total: 57 reactors 60,730

Note: China Guangdong Nuclear Power Holding (CGNPC), China National Nuclear Corporation (CNNC), China Power Investment Corporation (CPI)




Exhibit 141. China: nuclear power reactors in operation and under construction, as of Jan 2010

Beijing

Heilongjiang

Jilin

Liaoning

HebeiShanxi

Shandong

Anhui

Zhejiang

Fujian

Jiangxi

Hubei

Hunan

GuangdongGuangxi

Hainan

Yunnan

Guizhou

Sichuan

Shaanxi

Ningxia

Gansu

Qinghai

Xinjiang Inner Mongolia

HenanJiangsu

Power reactors in mainland China

In operation

Under construction

Daya Bay 2

11

20

Ling Ao 22

Taishan 1

Yangjiang 2

Fuqing 2

Ningde 2

Sanmen 2

Qinshan 5 4

Tianwan 2

Haiyang 1

Hongyanhe 4

Tibet

Beijing

Heilongjiang

Jilin

Liaoning

HebeiShanxi

Shandong

Anhui

Zhejiang

Fujian

Jiangxi

Hubei

Hunan

GuangdongGuangxi

Hainan

Yunnan

Guizhou

Sichuan

Shaanxi

Ningxia

Gansu

Qinghai


HenanJiangsu


In operation

Under construction

Daya Bay 2

11

20

Ling Ao 22

Taishan 1

Yangjiang 2

Fuqing 2

Ningde 2

Sanmen 2

Qinshan 5 4

Tianwan 2

Haiyang 1

Hongyanhe 4

Tibet

Beijing

Heilongjiang

Jilin

Liaoning

HebeiShanxi

Shandong

Anhui

Zhejiang

Fujian

Jiangxi

Hubei

Hunan

GuangdongGuangxi

Hainan

Yunnan

Guizhou

Sichuan

Shaanxi

Ningxia

Gansu

Qinghai


HenanJiangsu


In operation

Under construction

Daya Bay 2Daya Bay 22

1111

20

Ling Ao 22Ling Ao 2222

Taishan 1Taishan 11

Yangjiang 2Yangjiang 22

Fuqing 2Fuqing 22

Ningde 2Ningde 22

Sanmen 2Sanmen 22

Qinshan 5 4Qinshan 55 44

Tianwan 2Tianwan 22

Haiyang 1Haiyang 11

Hongyanhe 4Hongyanhe 44

Tibet


Based on our China power equipment team’s estimates and a target of 70GW nuclear capacity by 2020F, we estimate that China’s nuclear power equipment market will reach about RMB350bn over the next decade. If we apply a localisation rate of 70% for nuclear island equipment, 80% for conventional island equipment, 90% for balance of plant (BOP) equipment, 100% for other equipment, plus an overall discount factor of 85%, cumulative revenue from now to 2020F attributable to local equipment suppliers will reach RMB250bn — twice the combined FY08 revenue of the Big-3 power equipment players, namely Dongfang Electric, Shanghai Electric and Harbin Power.

Assumptions

1. Installed capacity. We estimate installed capacity will reach 70GW by 2020F, versus the current target of 40GW, according to the mid- to long-term targets set by the government. We believe that the government will revise up its target, given strong momentum in the nuclear power sector.

2. Technology mix. Our analysis of existing nuclear projects in China indicates that CPR1000 (2.5G) is the most widely deployed technology, with a market share of more than 50%. On the 3G front, AP1000 is the most widely selected 3G+ technology, with a market share of 29%, with EPR taking a relatively minor 6%. We expect CPR1000 to continue to take half of the market, with AP1000 seen to be gaining share as China develops its own 3G-plus technology. We believe that EPR will remain a relatively minor technology, with a market share of around 5%.

We estimate China’s nuclear power equipment market will reach about RMB350bn over the next decade



Exhibit 142. China: technology mix for projects under construction/planning

AP100029%

EPR6%

CPR-100056%Others (e.g. CNP-

600/ HTR-PM/ AES-91)

9%


3. Unit cost for CPR1000. The most recently published cost of CPR1000 is around US$1,500/KW (source: CNNC). We believe the cost can be lowered as the technology enters mass production and components are further localised (currently 60-70%). Our view is that costs could ultimately fall to less than RMB10,000/KW (or US$1,400/KW), as targeted by the government.

4. Unit cost for AP1000. Our research reveals that the average cost of AP1000 is US$2,674/KW in China, or just 58% of the comparable cost for AP1000 projects overseas. We believe that the discount is justifiable, given the use of local content. Moreover, we believe that the cost can be reduced to US$2,000/KW as the localisation ratio increases.

5. Unit cost for EPR. Our research reveals that the unit cost for EPR reactors is some US$2,626/KW in China. This is about 64% of the current average of overseas contracts. We believe that the cost can be reduced to US$1,800/KW. The cost is lower than for AP1000, since we believe domestic power equipment players, such as Dongfang Electric, have already captured certain technologies needed to produce components for EPR reactors through extensive expertise in the 2.5G nuclear area.



Exhibit 143. Current AP1000 and EPR projects overseas

AP1000 projects

Project name Progress energy VC-Sumer Gorgia

Details 2 x 1,100KW reactors 2 x 1,117KW reactors 2 x 1,100KW reactors

Contract cost (US$) 11,000,000,000 9,800,000,000 9,600,000,000

Installed capacity (KW) 2,200,000 2,234,000 2,200,000

Unit cost (US$/KW) 5,000 4,387 4,364

Average unit cost (US$/KW) 4,583

Local unit cost (US$/KW) 2,674

Implied discount (%) 42

EPR projects

Project name Flamanville Olkiluoto

Details 1 x 1,650KW reactor 1 x 1,650KW reactor

Contract cost (€) 3,960,000,000 5,300,000,000

Installed capacity (KW) 1,650,000 1,650,000

Unit cost (€/KW) 2,400 3,212

Unit cost (US$/KW) 3,504 4,690

Average unit cost (US$/KW) 4,097

Local unit cost (US$/KW) 2,626

Implied discount (%) 36


6. Total cost breakdown. We have applied a share of total investment costs for nuclear island, conventional island, BOP and other equipment at 37%, 17%, 11% and 35%, respectively. This is consistent with the current share of a standard 2.5G project, as reported by the CNNC.

For a standard 2.5G reactor project, about 35-40% of the total investment goes towards the construction of the nuclear island. Although a typical nuclear reactor consists of hundreds of parts, the steam generator and reactor pressure vessel combined represent 18-20% of the total investment (or 50% of the total investment in a nuclear island). In particular, the combination of steam generator, steam turbine and generator accounts for some 20-30% of the total cost for a nuclear power plant. Other major parts include the nuclear reactor inner core, reactor coolant pump, valves, steam turbines and the generator, each contributing 4-6% of the total nuclear reactor cost.



Exhibit 144. Investment budget for a 2.5G nuclear plant

Modules RMB / KW RMB / KW % to total cost Big 3 suppliers

Pre-construction preparation 189 1.7

Steam Generator 906 8.0 DFE, SEG, HPE

Reactor Pressure Vessel 1,133 10.0 DFE, SEG, HPE

Pressuriser 227 2.0 DFE, SEG, HPE

Control Rod / Nuclear Reactor Internals

453 4.0 SEG

Reactor Coolant Pump 566 5.0 DFE, SEG, HPE

Valves 566 5.0 n.a.

Others 290 2.6 DFE, SEG, HPE

Nuclear Island 4,142 36.6

Steam Turbines 680 6.0 DFE, SEG, HPE

Generator 680 6.0 DFE, SEG, HPE

Others 521 4.6

Conventional Island 1,880 16.6

Balance of Plant 1,232 10.9 DFE, SEG, HPE

Nuclear fuel 552 4.9

Others 3,334 29.3

Total 11,329 100.0

Total (US$/KW) 1,666 Note: Dongfang Electric (DFE), Shanghai Electric (SEG) and Harbin Power (HPE).

Source: CNNC, Nomura estimates

7. Localisation and discount factor. China’s overall long-term target localisation rate for nuclear power equipment is around 70%, as some complex components will still have to be imported. Since nuclear island components are relatively complex, we believe that conventional island and BOP components should have a higher localisation rate. The estimated long-term localisation rate for nuclear island equipment, conventional island equipment, BOP equipment and other equipment should be 70%, 80%, 90% and 100%, respectively, according to government mandate. We believe that it will be difficult to reach such localisation ratios over the next two to three years, since construction of an AP1000 unit takes five to six years (including planning and consultation stages). We apply an overall discount factor of 15% to reflect the actual revenue flowing to local power equipment players over the next 10-11 years.



Exhibit 145. Revenue for nuclear equipment industry

Installed capacity (GW)

2008 8.6

2020F 70.0

Increase in capacity 61.4

Expected technology mix

CPR1000 (2.5G) (%) 50

AP1000 (3G+) (%) 45

EPR (3G+) (%) 5

Share of increase in capacity (GW)

CPR1000 (2.5G) 30.7

AP1000 (3G+) 27.6

EPR (3G+) 3.1

Unit cost (US$/KW)

CPR1000 (2.5G) 1,400

AP1000 (3G+) 2,000

EPR (3G+) 1,800

Total cost per technology (US$bn)

CPR1000 (2.5G) 43.0

AP1000 (3G+) 55.3

EPR (3G+) 5.5

Total 103.8

Total (RMBbn) 705.6

Equipment share (US$) 50

Expected revenue (RMBbn) 352.8

Bear case Base case Bull case

70% localisation

across all categories

Localisation rate: NI-70%; CI-80%; BOP-90%;

Others-100%

100% localisation across all

categories

Nuclear island share (%) 37.0 37.0 37.0

Conventional island share (%) 17.0 17.0 17.0

BOP share (%) 11.0 11.0 11.0

Other (%) 35.0 35.0 35.0

Localisation rate

Nuclear island share (%) 70 70 100

Conventional island share (%) 70 80 100

BOP share (%) 70 90 100

Other (%) 70 100 100

Revenue to local players before discount (RMBbn) 247 298 353

Discount factor (%) 15 15 15

Revenue to local players after discount (RMBbn) 210 253 300




China’s search for uranium

With the government’s track record in executing nuclear power constructions on schedule, we believe one of the largest obstacles that could impede growth in nuclear power development is the procurement of uranium. Hence, we believe a focus for China’s nuclear power sector in the coming years is the acquisition of overseas uranium assets.

This is evidenced by CNNC’s and CGNPC’s recent foray into the international markets. Through a backdoor listing in November 2008, CNNC established Hong Kong-listed CNNC International, with a main goal to procure uranium assets overseas. In June 2009, CNNC International bought 69.5% of a Canadian company called Western Prospector, which has a uranium mine in Mongolia with 8,000 tonnes of reserves. Estimated annual production is 1,000-2,000 tonnes.

Similarly, in November 2009, CGNPC invested HK$728mn for a 16.67% stake in HK-listed Silver Grant. Silver Grant will use the proceeds for “investment projects or acquisition opportunities relating to natural resources, energy and nuclear related matters”, according to the company statement. We believe this is a way for CGNPC to indirectly make investments in overseas uranium assets through a listed vehicle. As mentioned earlier, CGNPC has already started making these acquisitions through its subsidiary, China Uranium Development Co., with its investment in Energy Metals Ltd.

Such investments will continue in order for the two nuclear power operators to secure enough fuel supply in the long run, in our view. We believe they will continue to look for investments in Kazakhstan, Australia, Canada and countries in Africa.

China relies on imports for about half of its uranium needs, with supplies coming from Russia, Namibia, Australia and Kazakhstan. According to WNA’s estimates, China produced 769 tonnes of uranium in 2008. CNNC, which is the dominant domestic uranium producer by output, said it aims to raise its domestic uranium production to 2,000 tonnes a year by 2020.

This is still far below the projected amount of uranium required by China. According to the head of CGNPC’s uranium supply unit (Guangdong Nuclear Uranium Resources Co), Zhou Zhenxing, the company alone will need more than 100,000 metric tonnes of uranium between 2009 and 2020. This is a 5x increase from 2,000 tonnes in 2009 to 10,000 tonnes a year in 2020.

Based on the WNA’s Reference Scenario projections — which make a conservative assumption that nuclear power capacity will grow only to 50GW by 2020 — China’s uranium requirement will grow by more than 3x to 9,676 tonnes in 2020F from 2,875 tonnes in 2010F. If China increases its cumulative nuclear power capacity to 70GW by 2020F, as we are projecting, the requirement for uranium would be even larger.

Procurement of uranium is key

Both CNNC and CGNPC are investing in uranium overseas

According to WNA’s estimates, China produced 769 tonnes of uranium in 2008



Exhibit 146. China’s uranium requirement as projected by WNA’s Reference Scenario

2,875

6,720

9,676

15,675

20,368

0

5,000

10,000

15,000

20,000

25,000

2010F 2015F 2020F 2025F 2030F

(tonnes U)

Source: WNA

China hydropower sector In our view, China hydropower, particularly small-hydro, stands to benefit from government policy aimed at lowering GHG emission and promoting use of renewable energies. China is the largest hydropower country worldwide in terms of exploitable resources and actual development. Hydropower is also the second-largest source of power supply in China, accounting for 16% of China’s power generation in 2009.

Based on the government’s latest comments, we estimate that China hydropower capacity is scheduled to post a CAGR of 7% between 2009 and 2020F, far slower than other alternative energy such as wind, solar and biomass, which we estimate will see a CAGR of 18-35% during the same period.

Moreover, we project that the planned capacity for 2020F would represent 74% of the country’s technically exploitable hydro resources, and thus believe that the growth potential of hydropower will be more constrained in China over the long term.

Although we expect much slower growth from hydropower than the same from other alternative energy sources in China, we note that the government has turned more supportive to hydropower since early 2010, owing to China’s pressing need to achieve its renewable energy consumption target (15% from non-fossil fuel sources) by 2020F.

Further, we continue to expect even stronger government support to small-hydro in China. This, we believe, is because of small-hydro’s position as a low-cost renewable source, and a tool to expand power supply coverage to the remote and rural areas to boost economic growth in these regions. Current listed small-hydro companies include Minjiang Power, Mindong Power, Qianyuan Power, Guiguan Power, Wenshan Power and Guidong Power.

China hydro is the largest worldwide

According to China’s Ministry of Water Resources (MWR), China has technically exploitable hydro resources of 542GW, the largest in the world. By end-2009, China’s cumulative hydropower capacity totalled 197GW, topping that of other countries by a large margin. In 2009, China’s hydropower generation reached 513Twh, some 55% higher than Canada’s and Brazil’s, respectively, the second- and third-largest hydro countries worldwide, based on BP statistics.

Hydropower is the second-largest source of power in China



Exhibit 147. Global top-10 hydropower countries (2009)

0

20

40

60

80

100

120

140

160C

hina

Can

ada

Bra

zil

US

Rus

sian

Nor

way

Indi

a

Ven

ezue

la

Japa

n

Sw

itzer

land

(m tonnes of oil equivalent)

Source: BP Statistics, Nomura research

Within China, hydropower also plays a key role as the second-largest power supply after thermal power. By end-2009, hydropower capacity accounted for 23% of China’s overall power capacity, and the annual power generation of hydro contributed 14% of China’s overall generation.

Exhibit 148. China hydropower capacity by type

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

2003 2004 2005 2006 2007 2008 2009 2020F

0

5

10

15

20

25

30

Small hydro (<50MW) (LHS)

Large hydro (LHS)

Hydro as % of overall (RHS)

(MW) (%)

Source: NDRC, China Electricity Council, Nomura International (Hong Kong)

The hydropower resources are abundant but unevenly distributed in China. As shown below, China’s hydropower projects are concentrated in south-west, north-west, middle and southern China, along the Jinsha, Yangtze, Yanglong and Huang rivers. Further, the water runoff also fluctuates significantly throughout the year given seasonality effects.



Exhibit 149. China water resources

Source: Company data

China hydropower growth could slow to a 7% CAGR through 2020F

Hydropower capacity in China grew at 10-18% y-y between 2004 and 2009. However, based on China government officials’ latest comments on the nation’s planning for hydropower development, cumulative capacity of hydropower is scheduled to expand from 197GW by end-2009 to 405GW (including 75GW of small-hydro projects) by end-2020F, implying an 11-year CAGR of 7%.

This is not only slower than the historical growth of hydropower in China, but also a lot slower than the planned growth of other alternative energy sources such as wind, solar and biomass, which we estimate to see a CAGR of 18-35% during the same period.

We believe that such slower growth of hydropower results from a much higher base effect, as well as the hydro resources available in China. We estimate that our projected 2020F hydropower capacity will account for 74% of the country’s technically exploitable hydropower resources, which means that by 2020F, installed hydropower capacity could be more than 74% of the country’s economically exploitable resources. Consequently, we expect the growth rate of hydropower to gradually slow over the next couple of decades.

Exhibit 150. China hydro generation and growth

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

2003 2004 2005 2006 2007 2008 2009 2020F

(15)

(10)

(5)

0

5

10

15

20

25

Large hydro (LHS)


Growth (RHS)

(GWh) (%)

Source: NDRC, China Electricity Council, Nomura estimates

Hydropower growth likely to lag far behind other alternative energy sources



Exhibit 151. China hydro capacity and growth

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

2003 2004 2005 2006 2007 2008 2009 2020F

0

2

4

6

8

10

12

14

16

18

20

Large hydro (LHS)


Growth (RHS)

(MW) (%)

Source: NDRC, China Electricity Council, Nomura estimates

But we see government support turning more positive lately

Over the past few years, the development of hydropower, particularly large-scale hydro, in China has faced obstacles such as environmental damage as well as having to displace and re-habit people. According to the NDRC, China has only approved 14GW of hydro projects since 2007, less than 5GW per year. In 2Q09, China’s Ministry of Environmental Protection also halted the approvals of large-hydro projects at Jinsha River by China Huadian Corp and China Huaneng Group for environmental violations, citing that the halt aimed to “prevent low-level surplus construction and building of excess capacity.”

However, since the beginning of 2010, we have sensed a change in the government’s attitude towards the development of large-scale hydropower in China; we freely admit that this is a subjective call. The CEC recently issued a report advocating that if the government does not resume approval of large-hydro projects in the near term, there will be very minimal incremental capacity increase from large-hydro projects during the 13th Five-Year Plan period (2016-2020F). Mr Guobao Zhang, the head of the China Energy Bureau, also commented that China needs to approve 120GW of hydro projects (61% of cumulative hydro capacity by 2009) during 2010-15F, which he felt is difficult to achieve based on the current approval status. Thus he encouraged the relevant agencies to accelerate the process of getting the approval.

In our view, the positive change in government’s stance towards large-scale hydro is mainly about the pressing need to accelerate clean energy generation to meet its non-fossil fuel energy consumption targets (15% of overall energy consumption from non-fossil fuel sources) by 2020F. According to Mr Guobao Zhang, the Head of the China Energy Bureau, China’s non-fossil fuel energy consumption accounted for less than 8% of overall energy consumption in 2009, down from 8.9% in 2008.

The government seems to be turning more supportive of hydro projects …

… although perhaps only with meeting clean energy consumption target in mind



Exhibit 152. China non-fossil fuel energy consumption as % of total energy consumption

0

2

4

6

8

10

12

14

16

2005 2008 2009 2020F

Government target: 15%(%)


We believe that large-scale hydro would be one of the cheapest and most scalable ways to help China achieve its clean energy consumption target. Although the Chinese government does not define large-scale hydro as a type of renewable energy in certain cases (since large-hydro projects normally require change in landscape and/or re-habitation, and are not environment-friendly), we believe that in the near and medium term, growth of large-scale hydro would be more aggressively supported by the government.

Small-hydro receives stronger government supports than large-hydro

China’s Ministry of Water Resources (MWR) categorises hydro-power into two types: large-hydro and small-hydro, where small-hydro indicates those with capacity of less than 50MW. According to the MWR, the technically exploitable hydropower resources of small-hydro is 128GW, most of which is located in less developed rural areas in the mid-western, north-western and northern regions.

Compared to large-hydro projects, small-hydro projects have advantages including no requirement for strong water runoff, simpler design, shorter time for construction, less negative impact on environment, and easier O&M (operating and maintenance). Further, since small-hydro projects are normally located close to the end market, loss from transmission is minimal and construction of complicated grid networks is not required.

Given the natural distribution of resources and the features of small-hydro, we note that the Chinese government has viewed small-hydro projects as an effective tool to extend power supply networks to remote areas, which the government believes will subsequently enhance economic growth.

China started promoting small-hydro projects in the 1950s, in conjunction with the country’s agricultural and rural development. Based on comments made by officials from China’s MWR, small-hydro projects have provided power supply to a rural population of more than 300mn. The MWR also noted the development of small-hydro has increased electricity penetration rates in rural villages from less than 40% in 1980 to 99.6% in 2008. The government expects to increase small-hydro capacity through 2015 to resolve power supply issues for, say, another 677mn people.

By end-2009, the installed capacity and annual generation of small-hydro reached 55GW and 16Twh, both figures accounting for some 30% of China’s overall hydropower capacity and generation in 2009.



Exhibit 153. China small-hydro generation and growth

0

50

100

150

200

250

300

2003 2004 2005 2006 2007 2008 2009 2010F 2020F

(5)

0

5

10

15

20

25


Growth (RHS)

(bn kwh) (%)

Source: NDRC, China Electricity Council, Nomura research

We note that, in some cases, the Chinese government does not regard large-hydro as a renewable energy, since the development of large-hydro projects most of the time requires re-habitation or changes to landscape. Consequently, we believe that small-hydro would more directly benefit from the government’s move toward greater renewable energy usage.

Incentives and tariff scheme for small-hydro projects: 8% ROE

To encourage development, the Chinese government has introduced various incentives for small-hydro since the early 1990s. The MWR issued a circular in 1991 stating that electricity users living within the service areas of small-hydro projects are required to pay RMB0.02/kwh along with their electricity bills to establish a “small-hydro development fund” to support future construction of new small-hydro projects. Moreover, since 1994, small-hydro project owners have received VAT rebates, which lowered their VAT to 6%, much lower than the 17% rate for large-hydro projects. In terms of income tax credits, some provinces return half or even 100% of income tax payments to small-hydro project operators to help to finance their operation and future capital spending.

At present, the pricing of small-hydro projects is determined by local governments on a case-by-case basis. The local governments will calculate the appropriate tariffs based on a guaranteed project ROE of 8%. Owing to lower generation cost of small-hydro, we note that the tariffs granted to small-hydro are normally a good deal lower than the tariffs granted to coal-fired power, even when the electricity from both projects are sold to the same grid line. The Chinese government has recently resolved to launch a new policy that enables small-hydro projects to receive the same tariffs as the coal-fired power projects when both are selling to the same local grid company. We believe that this is positive to small-hydro project owners, since their tariffs could be raised under this circumstance.

Moderate small-hydro capacity growth to 75GW by 2020F

We believe that China’s stronger support for small-hydro than for large-hydro is mainly about the government’s intention to create additional income sources for agricultural and rural areas, and not because the government wants to use small-hydro to optimise its power supply structure. Such a stance is evident from NDRC’s moderate plan for small-hydro. Based on NDRC’s present plan, China’s cumulative capacity of small-hydro will expand from the current 55GW to 75GW, implying an 11-year CAGR of 3%.

Small-hydro favoured by government mainly to boost economic growth in rural areas



Exhibit 154. China: small-hydro capacity

0

10

20

30

40

50

60

70

80

2003 2004 2005 2006 2007 2008 2009 2020F

(GW)

Source: NDRC, China Electricity Council, Nomura research

Listed players in the China hydropower field

Exhibit 155. Listed Chinese hydropower companies

Type Company Code

Large-hydro China Yangtze Power 600900 CH

Mindong Power 000993 CH

Qianyuan Power 002039 CH

Minjiang Power 600131 CH

Whenshan Power 600995 CH

Guiguan Power 600236 CH

Small-hydro

Guidong Power 600310 CH


China waste management & waste-to-energy sector

China’s solid waste problem

Chinese municipalities generated about 154mn tonnes of residential (municipal) waste in 2008 and, by 2030, this could increase to 480mn tonnes — nearly double that projected for the US over the same period. Every year, Chinese cities generate one-third of the total waste produced in the world, and this is growing at a rate of 10% annually, compared with 8% worldwide.

Exhibit 156. Industrial solid waste in China

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

2000 2001 2002 2003 2004 2005 2006 2007 2008

Industrial solid waste generated

Industrial solid waste utilizaed

(mn tonnes)

Source: National Bureau of Statistics

Exhibit 157. Residential solid waste in China

0

20

40

60

80

100

120

140

160

180

2000 2001 2002 2003 2004 2005 2006 2007 2008

Residential solid waste disposed

Harmless residential solid waste treated

(mn tonnes)

Source: National Bureau of Statistics

Waste is growing faster in China than in the rest of the world



According to a study by the China Council for International Cooperation on Environment and Development (CCICED) in 2006, about 860mn people will be living in cities by 2020F, exerting further pressure on the already overburdened urban waste disposal system. Trends and estimates of China’s waste industry are as follows:

According to the World Waste Survey, China came in just after Europe and the US in terms of waste output in 2004. The average Chinese urban resident generates 440kg of waste a year (compared with 766kg in the US), but China will overtake the US within a decade if it maintains waste output at its historical 19% CAGR.

Among China’s 660 cities, 52 of the big and medium cities (with populations exceeding 500,000) account for 60% of the country’s total garbage. Less than a dozen of these cities have adopted comprehensive municipal waste reduction and recycling programmes, according to government statistics.

Garbage pile-up in 2020 could reach 400mn tonnes for China, the volume generated by the entire world in 1997, according to the CCICED.

Landfills of solid waste have already rendered 50,000 hectares of land around cities, and in another 12 years, the landfills in China’s urban areas will reach capacity, according to CCICED.

Exhibit 158. Municipal waste collection volume

0

50

100

150

200

250

UnitedStates

China Germany Japan Italy UnitedKingdom

France

(mn tonnes)

Source: United Nations MBS database

Exhibit 159. Treatment of municipal waste

0%10%20%30%40%50%60%70%80%90%

100%

UnitedStates


France

Landfilled Incinerated

Recycled/composted Others/untreated


In 2005, the World Bank reported that for China to adequately address its growing solid waste the country must:

Increase the national waste management budget eightfold over the next 15 years.

Develop approximately 1,400 more landfills over the next 25 years.

More of an emerging market than wastewater treatment

Solid waste treatment has been overlooked by local governments in the past, since this problem is not as pressing as water shortages, but has gradually accumulated to an alarming level as industrialisation and urbanisation accelerates. Only 40% (260 cities) of the Chinese cities have adopted some level of waste treatment fee-charging mechanism, and waste treatment accounts for some 2% of the total expenditure by municipal governments in public utilities.

It is a newer market than wastewater treatment, since a charging system for waste treatment was established in 2002 (wastewater tariff mechanism was introduced in 1998), followed by guidelines for forming concessionary rights in 2004 (those wastewater treatment was set in 2003), and regulatory requirements for proper waste disposal issued by the Ministry of Environmental Protection in 2006 (wastewater treatment was fully opened up by the Ministry of Construction in 2004).

Solid waste had been a second-tier problem, but disposal is becoming more urgent



Recently targeted by the Ministry of Construction, versus 70% set under the 11th Five-Year Plan

Assumed target for 12th Five-Year Plan

Waste treatment, which is considered a downstream operation, has already been opened up by the central government for commercialisation and foreign investments, while processing fees (payable to treatment operators) are generally subsidised in full owing to lack of tariff collection systems, as authorities have not yet settled on if such costs should be recovered through billings of water, electricity or other means —legislative powers of these utilities are segregated among different offices of the city. Services for waste collection and transportation, which involve more social and safety concerns, are still being rendered directly by local governments. We believe the current structure should last for some time until unified policies are rolled out to reform the waste industry in terms of pricing and environmental standards. Until unified policies are rolled out to reform the waste industry in terms of pricing and environmental standards, we believe the current structure should last for some time.

While the waste treatment industry is still in its infancy where growth and penetration are top priorities of the government — creating a compelling landscape for expansion in the next three-five years that is similar to the water industry since 2004 and gas distribution in 2000-06 — we believe local governments are more likely to allow stable margins for the downstream operators.

Accelerating growth in waste treatment capacity

For residential solid waste, China has a waste treatment ratio of 67% in 2008 in urban areas, a substantial improvement from 2005’s 52%, and implied a treatment capacity CAGR of 7%. Assuming the treatment ratio in urban China reaches 72% by end-2010F as targeted by the Ministry of Construction on 5 January, 2010 (higher than the 70% set during the 11th Five-Year Plan) and 90% by end-2015F, we estimate capacity growth will accelerate to 10% pa.

Such growth is seen from prevailing under-penetration in the sector, given that past investments made in waste treatment were only 2.2% of total expenditure for municipal public utilities, and only 40% (260 cities) of China’s cities had adopted some level of waste treatment fee-charging mechanism. Except for the few cities that have built-in waste treatment fee into water tariffs, most other cities have a fee collection ratio of only 30%. As a result, municipal governments are encouraged to privatise and commercialise the market to bring efficiency in waste collection and treatment.

Exhibit 160. China: residential solid waste treatment in urban areas

Residential solid waste in urban area 2003 2004 2005 2006 2007 2008 2009F 2010F 2011F 2012F 2013F 2014F 2015F

Capacity for waste treatment ('000 tonnes/day) 219.6 238.5 256.3 258.0 271.8 315.2 345.2 378.2 417.0 458.7 503.5 551.7 603.4

Capacity growth (%) 9 7 1 5 16 10 10 10 10 10 10 9

Residential waste collected (mn tonnes/year) 148.6 155.1 155.8 148.4 152.2 154.4 162.1 170.2 178.7 187.6 197.0 206.9 217.2

Waste output growth (%) 9 4 0 (5) 3 1 5 5 5 5 5 5 5

Residential waste treated (mn tonne/year) 75.4 80.8 80.5 77.5 94.3 103.1 108.2 113.6 119.3 125.3 131.5 138.1 145.0

Implied utilisation/efficiency (%) 95 94 87 83 96 91 90 90 90 90 90 90 90

Waste treatment ratio (%) 51 52 52 52 62 67 69 72 76 79 83 86 90 Source: China Statistical Yearbook; Nomura International (Hong Kong) Limited



Exhibit 161. Municipal waste collection volume

0

50

100

150

200

250

UnitedStates


France

(mn tonnes)


Exhibit 162. Treatment of municipal waste

% 0 10 20 30 40 50 60 70 80 90 100

UnitedStates


France

Landfilled IncineratedRecycled/composted Others/untreated

(%)


WTE set for a 17% capacity CAGR through 2015F

Alongside gradual growth in waste treatment demand, we have identified waste-to-energy (WTE) as outshining other waste treatment projects in terms of capacity growth, since it has higher environmental standards and energy efficiency but accounts for less than 20% of China’s residential waste currently being treated, versus 80% being processed by landfill sites.

Based on guidelines set out by the Environmental Protection Bureau, China is expected to have 300 WTE plants by end-2015F, from ~100 in 2008 and 75 in 2007; and also electricity generation from WTE plants of 3bn kWh in 2010 (0.1% of total power demand), up from 0.2bn kWh in 2007.

This would imply a capacity CAGR of 17% for WTE projects during this period, which looks higher than the 10% implied for wastewater treatment, and 6-8% for power and coal industries during 2010-12.

Although dominant, landfill sites are becoming less preferred

Since landfill is a less capital-intensive approach toward waste treatment, it has been widely used among less developed cities in China. Although landfills are easy to construct with immediate effect, solid waste can cause considerable threats to the environment and human health as it decomposes. Land filling may produce contaminated land that is unsuitable for some future uses. When poorly managed, leachate (ie, contaminated liquid arising from solid waste) will contaminate underground water. Landfill gases, such as methane and carbon dioxide, pose serious health concerns. According to the World Bank, as most of China’s older landfills do not have proper linings (ie, a dense synthetic material that acts as a barrier between the waste and ground), these landfills will leach toxins into nearby soil, ground and surface water resources. Residents of China are already suffering from the impact of landfills, reporting health concerns such as respiratory diseases, cancers and high blood pressure. The US Environmental Protection Agency indicated dioxins from landfills are considered a serious threat to public health, and it has been widely reported that landfills could have an adverse effect on health and increase the likelihood of cancer.

While industrial waste is commonly treated by landfills and recycling due to their hazardous nature, municipal waste would be ideally treated by incineration. Although waste incineration also emits chemicals detrimental to human health (for instance, dioxins, furans and mercury), this can be captured by air-filtration while landfills produce a larger volume of methane and other hazardous gases over time owing to waste decomposition, as compared with ashes arising from incineration. Also, the Ministry of Environmental Protection recently lifted the standards for landfill operations, among which wastewater emissions from underground have to meet a Grade 1A standard, bringing the initial capex for landfill closer to that of waste incineration.

Landfill is an easy solution, but one with long-term consequences

Incineration seems more toxic, but decay over time releases more toxins and greenhouse gases

WTE running ahead of both energy and power industries



Government support in waste treatment

In 1995, the Solid Waste Law and Regulations was passed as China’s first comprehensive law to prevent and control environmental pollution from solid waste, which authorised the Chinese government to impose solid waste discharge fees on enterprises responsible for discharging waste in a manner that failed to comply with relevant environmental laws governing the land filling of hazardous wastes. In 2004, the import of hazardous wastes was banned, while the imports of solid wastes could only be used as raw materials or for recycling. Under the 11th Five-Year Plan (2006–2010F), the central government re-emphasised the need to reduce industrial waste, which includes the goal of reusing 60% of industrial solid waste and to reduce waste output by 10%.

Examples of tax concessions for waste-related and environmental projects include:

Corporate income tax: three-year exemption plus three-year 50% reduction (under FY08 new tax law) for Sino-foreign enterprises.

Value-added tax in on-grid power tariff will be refunded immediately upon collection for waste-to-energy and methane-to-energy projects.

On-grid power tariffs at a premium of RMB0.25/kWh above the provincial benchmark tariffs for waste-to-energy and methane-to-energy projects.

Priority dispatch: electricity generated from WTE plants are dispatched by power grid with priority, under current renewable energy initiatives.

VAT refund on purchases of local equipment during construction.

No VAT and import tax chargeable on imported equipment, for environmental protection projects that have investments by foreign entities.

Exhibit 163. Tendering timeline for WTE project

The Tendering Process Timeframe

The Government Authority commissions the tendering company to announce the public tender 1 month

The tendering company screens received application according to the government’s specifications 1 month

Accepted applicants submit their tenders 1 month

Tenders are reviewed by a panel of specialists invited by the tender company 3 days

The government authority engages in negotiations with the tender winner 2-3 months

Tender results are released 2 weeks

The government authority and the tender winner sign a (BOT) agreement Source: NEE; Nomura research

Getting more serious about recycling



Exhibit 164. China’s regulatory reform for the waste industry

Date Rules & regulations Authorities Particulars

Jun 2002 Directive for Establishing Charging System for Municipal Residential Waste Treatment

NDRC, Ministry of Finance, Ministry of Construction, SEPA

Establishes the requirement for treating municipal residential waste. Defines requirements and scope for calculating, charging and regulating waste collection and treatment services. Promotes commercialisation of waste treatment, to foster a sustainable environment. Defines national standards to meet.

May 2004 Management Policy of Operating Concession Rights for Hazardous Waste

State Council Defines requirements and procedures for obtaining concession rights for hazardous waste treatment, transport, landfill and incineration.

May 2004 Management Policy of Operating Concession Rights for Municipal Utilities

Ministry of Construction

Defines the requirements, responsibilities, procedures for obtaining concession rights in operating municipal utilities, which includes water supply, gas supply, heat supply, public transport, sewage treatment, waste treatment, etc. This rule opens up China’s utilities market for foreign investment opportunities, in order to accelerate commercialisation of public utilities among major municipalities.

Mar 2005 Management Policy for Municipal Construction Waste


Defines requirements for disposing, treating and transporting municipal construction waste (e.g. facilities treating construction waste are prohibited to treat residential and industrial waste). Defines penalty charges for violations.

Apr 2005 Management Policy for Preventing Pollution from Solid Waste Disposal

National Congress Defines the prevention of solid waste generation, promotes recycling and proper treatment. Defines guidelines in collecting, treating and transporting solid waste, which includes municipal residential waste, industrial and hazardous waste.

Oct 2005 Management Policy for Preventing Pollution from Disposing Hazardous Chemical Waste

SEPA Defines treatment and disposing policies for disposing hazardous chemical waste. Encourages hazardous chemical waste be centrally and professionally treated.

Jan 2006 Subsidized Tariff for Power Generated from Renewable Energy Rule

NDRC Power generated from renewable/alternative energy (eg, wind, solar, biomass and waste) will be given a subsidised tariff of RMB0.25/kWh over respective provincial benchmark tariffs, for 15 years, but allowance of which would be reduced by 2% pa for operations entered after 2010.

Jul 2006 Disclosure Requirement for Solid Waste Pollutants for Big and Medium Size Municipalities

SEPA Requires all state environmental protection authorities in big and medium size municipalities to regularly disclose information such as solid waste generation, treatment situation, type, etc.

Jun 2007 List of Products encouraged to be developed (revised)

NDRC The NDRC has revised the list of products/equipments for environmental protection which the government encourages to develop. This includes sewage treatment facilities, waste incineration equipments, flue gas filtrations, solid waste disposal facilities, etc. This revised list covers 107 products, and development which would receive government subsidizes/concessions.

Jul 2007 Management Policy for Municipal Residential Waste


Defines requirements for disposing, treating and transporting municipal waste. Defines minimum capital requirement for entering into residential waste treatment operations (register capital of RMB5-50mn for landfill, > RMB100mn for incineration). Defines the extent of use in automatic equipments. Defines penalty charges for violations.

Aug 2007 New Dispatch Priorities for Renewable Energy

NDRC, SEPA, SERC, Energy Council

The NDRC has ordered grid companies to give dispatch priorities to renewable energy providers, and then to efficient power generators according to fuel consumption and pollutant emission levels. Trial process has already started in September in five southern provinces — Jiangsu, Guangdong, Guizhou, Sichuan and Henan.

Source: Various entities, Nomura research



China bio-energy sector We believe that China’s bio-energy sector, including bio-mass to electricity, bio-gas and bio-fuel, will benefit from the Chinese government’s stance on reducing GHG emissions and raising consumption of renewable energy. In our view, bio-mass to electricity was the first among the renewable energy sources to see a standardised preferential tariff in China, and the most generous one at that, because the Chinese government sees bio-energy as a way to boost farmers’ income, which some claim are not fully participating in China’s growth.

Despite strong support from the government, we note that the sector so far has not grown as rapidly and vigorously as the government initially planned. According to the CEC, China had biomass-to-electricity capacity of 3.15GW by end-2008, up 2GW y-y, which seemed on track to achieve the government’s target at 5.5GW by 2010. Nonetheless, we note that utilisation rates and profitability remain low, particularly from the agricultural and forestry biomass-to-electricity segments.

We identify some obstacles for the bio-energy sector: 1) lack of a centralised network for collection of biomass feedstock, 2) shortages of fuel sources including forestry, straw and other crop residue, 3) lack of centralised near- and long-term planning by the government, 4) lack of standardised technology, processes and product certification to enable large-scale production and 5) difficulty in obtaining grid connection.

Three government agencies have set aggressive targets

According to the 11th Five-Year Renewable Energy Development Plan and the Renewable Energy Mid-to-Long-Term Development Plan, the NDRC has set targets for various types of bio-energy, including biomass-to-electricity, biogas and biofuel for the end of 2010 and 2020.

Exhibit 165. China government’s plan for bio-energy

(MW) 2005 2010F 2020F 05-10 CAGR (%) 10-20 CAGR (%)

Biomass-to-electricity 2,000 5,500 30,000 22 18

Agricultural biomass 1,700 4,000 24,000 19 20

Biogas 100 1,000 3,000 58 12

Waste 200 500 3,000 20 20

Biogas (bn m3) 8 19 na. 19 na.

Household 7 15 30 16 7

Large-scale livestock farms 1 1 na. na. na.

Industrial waste water 0 3 n.a. n.a. n.a.

Fuel (k tonnes)

Solid biomass n.a. 1,000 50,000 n.a. 48

Bioethanol 1,020 3,000 10,000 24 13

Biodiesel 50 200 2,000 32 26

Source: NDRC, China Ministry of Agriculture, Nomura research

To complement the NDRC targets, the Ministry of Agriculture issued the Agricultural Bio-energy Industry Development Plan 2007-2015 in 2007, which laid out a more detailed implementation plan for bio-energy development, particularly in agricultural and rural areas. The State Forestry Administration published the National Plan for Energy Forest in 2010 to ensure sufficient fuel supply for biodiesel and biomass-to-electricity by 2020F. Moreover, it is drafting a National Forestry Biomass Energy Development Plan for 2011-2020.

First among the renewable energy sources to see support from the Chinese government in the form of a generous preferential tariff



Biomass-to-electricity

Biomass-to-electricity refers to the process of generating electricity by burning bio-mass feedstock including forestry residues (a by-product of timber and pulp production), agricultural residues (eg, straw from cereal production), agro-processing residues (from crop processing), urban waste and biogas generated from waste treatment.

The NDRC and the Ministry of Agriculture have scheduled expanding biomass-to-electricity capacity to 4GW and 24GW by 2010 and 2020, respectively, representing CAGRs of 22% and 18% over 2005-2010 and 2010-2020. We note that more focus will be on agricultural bio-mass to electricity and forestry bio-mass to electricity, which are slated to reach 3GW and 1GW capacity by 2010, based on the government plans.

At present, the Chinese government grants preferential tariffs for bio-mass to electricity power plants at RMB0.25/kwh on top of the local benchmark coal-fired power tariff. This is much more generous than the preferential tariff scheme for wind power, which is now RMB0.12-0.22/kwh above the national average coal-fired power tariff.

Exhibit 166. Growth of different types of biomass-to-electricity in China

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Currently, the majority of the bio-mass to electricity projects in China are fuelled by sugar cane residue. For agricultural and forestry biomass, the government’s plan is to establish demonstrative power plants, using straw and residue of crops or sugar cane as feedstock at major cotton and crop growing areas, including Hebei, Inner Mongolia, Liaoning, Jilin, Heilongjiang, Jiangsu, Henan, Shandong, Hubei, Hunan, Jiangxi, Anhui, Yunnan and Sichuan provinces.

Based on estimates of the Ministry of Agriculture, China could produce 780mn tonnes and 900mn tonnes of straw by 2010 and 2015, respectively, from which 400mn tonnes and 450mn tonnes could be used to fuel bio-mass to energy power plants and generate electricity of 200mn TOCE and 225mn TOCE. As of 2009, China’s annual production of straw was around 700mn tonnes.



Exhibit 167. China crop straw distribution (tonne/thousand square meters)

Source: China Ministry of Agriculture

For bio-gas to energy, since the bio-gas can be produced along with waste treatment at poultry/livestock farms or waste-water treatment at paper, brewery and leather manufacturers, the government encourages these industries to construct mid-to-large scale biogas-to-energy projects. The government targets achieving bio-gas to energy capacity of 1GW and 3GW by 2010 and 2020, respectively.

We discuss waste-to-energy in further detail in a subsequent section of this report.

Bio-gas

Bio-gas is generated when bacteria degrade biological material in the absence of oxygen in a process known as anaerobic digestion. Since bio-gas is a mixture of methane and carbon dioxide, it is a renewable fuel produced from waste treatment. Bio-gas can be obtained directly from a variety of sources, including landfill, waste water and sewage treatment sites, livestock and poultry slurries, and other waste facilities. It can also be produced in dedicated anaerobic digestion facilities that take in a wide variety of feedstocks, such as farm and food waste, to produce biogas. The gas can be used in gas engines to generate electricity or in boilers to provide process heat or space heating.

Exhibit 168. China rural household bio-gas production targets

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For rural and agricultural households, the Chinese government is aiming to promote bio-gas as a supplementary source of gas supply. Moreover, the government believes that the production process of bio-gas could at the same time enhance agricultural waste treatments and protect the environment. According to the Ministry of Agriculture, as of 2009, there were 35mn agricultural households with biogas facilities. The government targets expanding to another 5mn agricultural households in 2010, perfectly on track to achieve NDRC’s 11th Five-Year Plan.

For urban areas, the Chinese government targets accelerating construction of bio-gas projects at locations such as large-scale livestock and poultry farms, industrial organic waste-water treatment plants and urban sewage water treatment plants. The government targets building 6,300 large-scale bio-gas projects by 2010.

Bio-fuel

Bio-fuel is defined as a solid, liquid or gaseous fuel obtained from relatively recently lifeless or living biological materials. There are two common ways of producing biofuel: one is by growing crops with high sugar and starch, another is by growing crops high in vegetable oils. Currently, the common use of bio-fuel includes home heating, cooking and powering vehicles.

Bio-fuels are far less carbon neutral than other green energies, as the combustion of biofuels produces carbon dioxide and other greenhouse gases. The potential for biofuels to be carbon neutral relies on the notion that the carbon being emitted is reused in the next cycle of plant growth.

According to the Ministry of Agriculture, there are 200 types of crops and plants the government sees as suitable for the production of bio-fuels. However, as the government’s highest priority is to ensure food supply and security for the population, the Ministry of Agriculture has narrowed the scope of “energy crops” to four. These are: sugar cane, sweet sorghum, sweet potato and tapioca, which it sees as crops suitable for bio ethanol production. Corn (maize) and potato are excluded from the list for food supply security reasons.

Based on the Ministry of Agriculture’s plan, focused provinces for “energy” sugar cane include Guangxi, Guangdong, Yunnan, Hainan, and Fujian. Focused provinces for sweet sorghum include Heilongjiang, Shandong, Inner Mongolia, Xinjiang, and Hebei. Focused provinces for sweet potato include Guangxi, and Sichuan. Focused provinces for tapioca include Guangxi, Guangdong, Hainan, Fujian, and Yunan.

Exhibit 169. China crop production

(mn tonnes) 2003 2004 2005 2006 2007 2008 Tonnes required to produce a tonne of ethanol

Rice 161 179 181 182 186 192 3

Wheat 86 92 97 108 109 112 4

Corn 116 130 139 152 152 166 3

Potatoes and Tapioca 35 36 35 27 28 30 Sweet potato: 7-8; tapioca: 6-7

Sugar Cane 90 90 87 97 113 124 17

Beets 6 6 8 8 9 10 10

Source: National Bureau of Statistics of China, Nomura International (Hong Kong)

According to reports from the Ministry of Commerce, currently the nation mainly adopts tapioca and sweet sorghum as sources for biofuel production, while there is limited development in sugar cane-based bio-fuel, given the huge sugar consumption in China.

The government aims to promote biogas as a supplementary source of gas in rural areas



Exhibit 170. China bio-fuel resources

Note: Red: sugar cane residue; Green: rice husk; Yellow: corn

Source: China Ministry of Agriculture

Exhibit 171. China bio-fuel targets

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Solid biomass Bioethanol Biodiesel(k tonnes)




Asia-ex Japan

India Clarisse Pan +852 2252 2192 / [email protected]


Ivan Lee, CFA +852 2252 6213 [email protected]

We note that under India’s National Action Plan on Climate Change, the target for minimum renewable purchase standards has been set at 5% of total power purchases in 2010 and, thereafter, should increase by 1% each year for 10 years, leading to 15% by 2020. The target is for renewable energy to contribute 10% of total power generation capacity and have a 4-5% renewables share in the electricity mix by 2012. Consequently, we expect renewable energy to grow faster than traditional power generation, accounting for around 20% of total added capacity planned for 2008-12. This should provide a major fillip to renewable energy in India, especially wind, which is a well established technology.

Exhibit 172. India renewable energy installed capacity as of 31 March, 2010

Power from renewable energy

Grid-interactive renewable power (MW) Added in FY10 Cumulative installed capacity Estimated potential

Biomass Power (Agro residues) 153 866 16,881

Wind Power 1,565 11,807 45,795

Small Hydro Power (up to 25MW) 305 2,735 15,000

Cogeneration-bagasse 295 1,334 5,000

Waste to Energy 5 65 2,700

Solar Power 8 10 50MW/sq km

Sub-total 2,332 16,817

Off-Grid/Distributed Renewable Power (including Captive/CHP Plants)

Biomass Power / Cogen.(non-bagasse) 51 232

Biomass Gasifier 13 122

Waste to- Energy 16 47

Solar PV Power Plants 0 2

Aero-Generators/Hybrid Systems 0 1

Sub-total 80 405

Total 2,412 17,222

Remote Village Electrification 1,013 Villages & Hamlets 5,348 villages/1,408 hamlets

Decentralised Energy Systems

Family Type Biogas Plants 1.06 lakh 42.40 lakh

SPV Home Lighting System 72,886 nos. 5,83,429 nos.

Solar Lantern 82,999 nos. 7,92,285 nos.

SPV Street Lighting System 8680 nos. 88,297 nos.

SPV Pumps 106 nos. 7,334 nos.

Solar Water Heating - Collector Area 0.62mn. sq.m. 3.53 Mln. sq.m.

Note: 1 lakh = 0.1mn

Source: Ministry of New and Renewable Energy (MNRE), Nomura research

Wind — the leader in renewable energy in India

India wind market to grow 30% y-y in 2010F

In 2009, India’s Ministry of New and Renewable Energy (MNRE) announced a new generation-based incentive (GBI) of INR0.5/kWh for electricity fed into the grid using wind power. We note that this is an additional incentive on top of the tariff fixed by the State Electricity Regulatory Commissions (SERCs). We believe that the GBI should encourage actual wind energy generation, which we believe is a better utilisation of wind resources rather than capacity addition.

Renewable energy should account for 20% of total capacity added over 2008-12

GBI should help in better utilisation of wind resources



We note that the GBI will have an overall cap of INR6.2mn/MW, which is to be availed in a minimum period of four years and a maximum period of 10 years. The GBI will be limited to cover a maximum capacity addition of 4,000MW under the 11th Five-Year Plan (2007-12) only.

We believe that new government incentives, both at the central and state level, will help the Indian wind energy market grow significantly from current levels. At present, annual capacity additions in India are generally around 1,200-1,800MW, which we expect to jump to 2,000-2,500MW in the next few years. We expect annual wind energy installation in India to grow 30% in 2010F and 25% in 2011F.

Exhibit 173. Annual wind installation in India

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We also expect the GBI to help attract investment from independent power producers (IPPs) and make the market more broad based. Unlike other countries, where utilities are the major customer of wind turbines, we note that the Indian wind energy market is dominated by manufacturing companies, which use wind energy for captive purposes. Incentives in the form of accelerated depreciation and a poor supply of grid-based electricity are the key reasons behind this trend, in our view.

In 2009, tough economic conditions combined with an uncertain policy environment due to delays in government budget led to a 35% y-y decline in annual wind energy installation in India to just 1,172MW.

New entrants to increase competition but Suzlon should maintain dominance

With more than 60% wind turbine market share, Suzlon has dominated the Indian wind energy market over the past 11 years. However, we believe that the competition will intensify in the next few years as new wind turbine players are looking to enter India, which they find attractive given its growth potential.

We note that the competition is from both domestic and international players, especially Chinese companies looking to win customers through attractive pricing. We believe that Chinese companies are beginning to make inroads in the Indian wind turbine market, as evidenced from the fact that Sinovel supplied 15MW of wind turbines to India in 2009.

In India, the vagaries of the grid have seen corporates building wind capacity to power their plants

China making a bid for the India market



Exhibit 174. India: wind turbine market share (2009)

Suzlon61%

Vestas8%

Sinovel1%

Others21%

Vestas RRB9%


Despite the growing competition on its home turf, we remain confident that Suzlon can protect its market share given its deep understanding of the domestic market, long-standing customer relationships and the width of its product offerings, which provides Suzlon an edge over its rivals in India. Suzlon has a diverse customer mix, consisting of small, medium and large-scale businesses, private and public sector companies, power utilities, independent power producers and even high net worth individuals.

In India, Suzlon follows an end-to-end model, which covers everything from land and site identification to operations and maintenance over the entire life of the project and also securing the financing for the projects. This is valuable for Indian customers since many of them do not have any experience in the sector.

We believe international players will find it difficult to match up to Suzlon when it comes to project execution and service offering, as local understanding and long-term relationships play a big role in securing deals, as well as in successful and timely execution of projects. As testimony to its clout in India, Suzlon has installed more than 4,800MW of wind turbines in India to date, accounting for 44% of India’s cumulative wind capacity. Consequently, we expect Suzlon to continue to dominate the India wind turbine market and maintain its current market share.

Exhibit 175. Suzlon market share in India

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Suzlon's market share in India (RHS)

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Source: BTM Consult ApS, Company data, Nomura research

But we see Suzlon as more than a match for competitors, home-grown and otherwise …

… as a local, Suzlon can take you from finding a site to lights on



Exhibit 176. Guidelines/incentives for wind power generation in various states

State Wheeling Banking Buy-back Third-party sales Capital subsidy Other incentives

Andhara Pradesh

5% of energy wheeled

Not allowed Rs. 3.50/per KWh w.e.f. 09.09.2008 (frozen for 10 years)

Allowed under Electricity Act 2003 subject to regulation framed by respective SERs

Industrial status Reactive Power: 10 paise per KVARh up to 10% & 25 paise per KVARh above 10%.

Tamil Nadu 5% of energy

5% (12 months financial year April to March)

Rs. 3.39/ per KWh (No Escalation) Allowed under Electricity Act 2003 subject to regulation framed by respective SERs

Nil Reactive Power: 25 paise perKVARh up to 10% & 50 paise per KVARh above 10%.

Karnataka 5% of energy

Allowed @ 2% of energy Input

Rs. 3.40/ per KWh without any escalation for 10 years of commercial operation


No Electricity Duty or 5 years

Reactive Power: 40 paise per KVARh

Kerala To be decided by SERC

To be decided by SERC

Rs. 3.14/ KWh for 20 years Allowed under Electricity Act 2003 subject to regulation framed by respective SERs

West Bengal

7.5%. of energy fed off grid

Rs. 4/ KWh Allowed under Electricity Act 2003 subject to regulation framed by respective SERs


Gujarat 4% of energy

Settlement to be done month to month & surplus energy at end of month & surplus energy at end of month shall be deemed as sold to utility as per tariff rate.

Rs. 3.50/KWh for 20 years Allowed under Electricity Act 2003 subject to regulation framed by respective SERs

Electricity duty exempted

Reactive power < 10% energy exempted, then 10 paise/ KVARh. Reactive Power > 10% of energy exported, then 20 paise/ KVARh

Madhya Pradesh

2% of energy

Allowed, but proposal for this invited from DISCOM

Year wise rates (Rs./kWh) from 1st to 20th year 1styr- 4.03 2nd yr - 3.86 3rd yr- 3. 69 4th yr- 3.52 5th yr - To 20th yr - 3.36


No Electricity Duty for 5 years

Reactive Power: 27 paise for KVARh

Maharashtra 2% of energy + 5% as T&D loss

12 months Rs. 3.50/KWh (first year of commissioning) (escalation of 15 paise per year for 13 years)


Power evacuation arrangement, Approach Road, Electricity Duty, Loan to Cooperative Societies


Rajasthan 50% of normal charge as applicable for 33 KV, in addition to transmission charges of 3.6%

Six months (Apr to Sep. 8 Oct to Mar. Utilisation of banking energy not permitted in Dec to Feb)

Rs. 4.2S/ KWh for Jaisalmer, Barmer 8 Jodhpur. Rs. 4.50/KWh for all other districts


Exemption from Electricity Duty @50% for 7 years

Reactive Power 5.75 paise per KVArh with escalation of 0.25 paise per year

Source: MNRE, Nomura research



Exhibit 177. Policy support for wind energy sector

Fiscal and financial incentives Concession on import duty on specified wind turbine parts

80% accelerated depreciation over one or two years

10-year income tax holiday for wind power generation projects

Excise duty relief on certain components

Some states have also announced special tariffs, ranging from INR3-4 per kWh, with a national average of around INR3.50 per kWh

Wheeling, banking and third-party sales, buy-back facility by states

Guarantee market through a specified renewable portfolio standard in some states, as decided by the state electricity regulator by way of power purchase agreements

Reduced wheeling charges as compared to conventional energy

Land policies The Ministry of Environment and Forests has issued guidelines for diversion of forest lands for non-forest purposes, particularly to enable wind generation

Clearance of leasing and forest land for up to a period of 30 years for wind developers

Financial assistance Setting up of the Indian Renewable Energy Development Agency (IREDA), the premier finance agency of the Government of India to provide soft loans for renewable energy projects, particularly for demonstration and private sector projects

Wind resource assessment The government set up the Centre for Wind Energy Technology (C-WET) to map wind energy potentials

The C-WET has set up more than 1,000 wind monitoring and wind mapping centres across 25 states

Wind mapping at 50 metres (C-WET) and 60-80 metres height (private companies)

Source: GWEC, IWTMA, Nomura research

Solar — India has huge potential

India solar market to grow 75% in 2010F

Being a tropical country, India has huge potential for solar power generation. As per government estimates, India receives 5,000tn kWh per year, with most parts of the country receiving 4-7 kWh per square metre per day. Looking at the poor power transmission and distribution infrastructure of the country, we note that there is ample opportunity for both grid and off-grid solar power systems.

The launch of Jawaharlal Nehru National Solar Mission (JNNSM) has created a lot of interest in the India solar sector. According to Phase 1 of the solar mission, India is looking to have 1.1GW of solar PV installed capacity by 2013. Consequently, to achieve this target, cumulative solar PV installed capacity will need to grow by more than 7x by 2013F from the current level. To create demand and attract investment in the sector, the government is looking to provide various incentives. We expect India’s solar PV market to grow by 75% y-y in 2010F and 50% y-y in 2011F. We believe India has huge potential for solar PV and given the right policy support India can become a key solar market in the longer term.

Exhibit 178. Planned incentives and targets for domestic solar industry manufacturing

Domestic solar manufacturing Installed capacity 4-5GW

2020 target Create dedicated manufacturing capacities for poly-silicon to manufacture 2GW capacity of solar cells annually

Financing and other incentives Zero import duty on capital equipment, raw materials

Excise duty exemption

Low interest rate loans

Priority sector lending

Incentives under Special Incentive Package (SIPs) policy to set up integrated manufacturing plants

Single window clearance mechanism for all related permissions

Create 2-3 large solar manufacturing tech parks consisting of manufacturing units covering the entire solar value chain

Quality Solar components be covered under the Bureau of Energy Efficiency’s star rating programme to ensure high standards


As a sunny country with an iffy grid, solar power is a good opportunity …

… indeed, we see 75% growth in this market in 2010F



Exhibit 179. India: solar PV annual installation

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Exhibit 180. India: solar PV cumulative installation

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Source: EPIA, Nomura estimates

JNNSM road map

We note that the mission is back-end loaded and most of the demand will be realised in Phase 3. The mission has been divided into a three phase approach, Phase 1 spans the remaining period of the 11th Five-Year Plan (until FY12) and the first year of the 12the Five-Year Plan (up to FY12-13), Phase 2 will cover the remaining four years of the 12th Five-Year Plan (FY13-17) and Phase 3 will encompass the full 13th Five-Year Plan (FY17-22).

Given the emerging cost and technology trends, we note that the mission will be regularly evaluated and reviewed to protect the government from subsidy exposure in case expected cost reduction does not materialise or is more rapid than expected. The mission expects to achieve grid parity by 2022 and expects to compete with coal-based power plants by 2030.

Exhibit 181. India solar road map

Application segment Target for Phase I (2010-13)Cumulative target for Phase 2

(2013-17) Cumulative target for Phase 3

(2017-22)

Grid solar power incl. roof top 1,100MW 4,000MW 20,000MW

Off-grid solar applications (incl. rural solar lights)

200MW 1,000MW 2,000MW

Solar collectors 7mn sqm 15mn sqm 20mn sqm




Exhibit 182. India: PV road map efficiency targets towards 2022F

Conversion efficiency target (%)

Type of solar cell Present status production (R&D) 2011-12F 2017-18F 2021-22F

Crystalline silicon solar cell 13 – 16% (19.7%) 18 (22) 22(23.5) 24 (25)

Thin-film a-Si solar cell 5 – 6%* (10 – 12%) * Pilot plant 8 (13.5) 9 (14.5) 11 (14.5)

CdTe (12%) 10 (15 ) 15(20) 20(25)Polycrystalline solar cell

CIGS (13%) 10 (15) 15(20) 20(25)

GaAs Conc solar cell NA (27) 35(40) 40 (45)

Dye/ organic nano based solar cell (2-5%) (5 -10) 8- 10(15) 12-17 (25)


Exhibit 183. India: PV road map targets towards 2022F

Target

Present Status 2011-12F 2017-18F 2021-22F

Module life in years 20-25 > 25 > 30 > 35

Electronics life in years (efficiency) 10 (96%) > 10 (97%) > 15 (98%) >20 (98%)

Battery life 1,200-1,500 1,500-1,800 1,800-2,200 2,200-2,800


India lacks solar manufacturing infrastructure

We note that unlike China, India does not have a strong manufacturing base in solar based technology. According to government sources, there are currently around 15 players in cell manufacturing, more than 20 players in modules and more than 50 in solar assembly. Currently, Indian companies import most of their polysilicon requirements, as there is no domestic infrastructure for polysilicon manufacturing.

Similar to the global trend, crystalline silicon technology dominates the market and accounts for nearly 90% of the solar modules manufactured in India, while the rest is based on Thin Film technology.

Despite the low solar PV manufacturing capacity, India still exports most of the solar products as domestic demand is almost non-existent. However, we expect this to change and believe that most of the domestic capacity will be utilised to meet the near-term target of 1GW by 2013, as envisaged in Phase 1 of the solar mission. Looking at the mission’s long-term target of 20GW by 2022F, we expect private investments to flow in all verticals of the solar value chain.

Exhibit 184. India: solar PV by application

Exports 65%Lights 6%

Pumps 2%

Off grid plants 4%

Grid plants 1%

Railways 5%

Telecom 6%

Others 11%


India has plenty of sunshine, but it does not have polysilicon manufacturing



Nuclear — significant growth expected in medium term

Nuclear power capacity to reach 20GW by 2020F and 63GW by 2032F

With the addition of 440MW (220MWX 2) in 2010 (by March 2010), India’s nuclear power plant cumulative capacity increased to 4,560MW in 2010, from 4,120MW in 2009. Another 5,020MW of nuclear power capacity is under construction and is expected to be commissioned between 2010 and 2016. Beside the plants under construction, India will need to add about 10GW of incremental new capacity to meet its mid-term target of 20GW by 2020. The government realises that it would not be possible for the government-owned National Power Corporation of India Ltd (NPCIL) alone to achieve the target, and hence participation of the private sector, both domestic and international, is imperative.

India plans to import Light Water Reactors (LWR) of 1,000MW and above capacity from countries such as France, Russia and the US. Simultaneously, India will continue to work on its domestic Pressurised Heavy Water Reactor (PHWR) technology.

Given that India can now access the international uranium market, it plans to expand its nuclear portfolio by using higher-capacity PHWR of 700MW. The expansion of the PHWR portfolio is an important component in getting plutonium, the fuel for Fast Breeder Reactors (second stage) and, hence accelerating India’s progress towards the third stage of its nuclear power programme. For more information on India’s three-stage nuclear power plan, please refer to the India section of our Anchor Report, Asia starts global nuclear chain reaction.

Exhibit 185. India: nuclear power road-map

1,09

5

1,56

5

1,78

5

2,22

5

2,72

0

2,72

0

2,72

0

2,77

0

3,36

0

3,90

0

4,12

0

4,12

0

4,56

0

20,0

00

63,0

00

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

198

0-8

5

198

5-9

0

199

0-9

2

199

2-9

7

199

7-0

2

200

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3

200

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200

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5

200

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6

200

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7

200

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200

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0

202

0F

203

2F

(MW)

1,09

5

1,56

5

1,78

5

2,22

5

2,72

0

2,72

0

2,72

0

2,77

0

3,36

0

3,90

0

4,12

0

4,12

0

4,56

0

20,0

00

63,0

00

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

198

0-8

5

198

5-9

0

199

0-9

2

199

2-9

7

199

7-0

2

200

2-0

3

200

3-0

4

200

4-0

5

200

5-0

6

200

6-0

7

200

7-0

8

200

8-0

9

200

9-1

0

202

0F

203

2F

(MW)

Source: DAE, Nomura research

India needs the private sector to help develop its nuclear capacity

Sourcing nuclear capacity at home and abroad



Exhibit 186. Nuclear power plants under operation

Plant Unit Type Capacity (MW) Date of commercial operation

TAPS 1 BWR 160 Oct-69

TAPS 2 BWR 160 Oct-69

TAPS 3 PHWR 540 Aug-06

TAPS 4 PHWR 540 Sep-05

RAPS 1 PHWR 100 Dec-73

RAPS 2 PHWR 200 Apr-81

RAPS 3 PHWR 220 Jun-00

RAPS 4 PHWR 220 Dec-00

RAPS 5 PHWR 220 Feb-10

RAPS 6 PHWR 220 Mar-10

MAPS 1 PHWR 220 Jan-84

MAPS 2 PHWR 220 Mar-86

KAIGA 1 PHWR 220 Nov-00

KAIGA 2 PHWR 220 Mar-00

KAIGA 3 PHWR 220 May-07

NAPS 1 PHWR 220 Jan-91

NAPS 2 PHWR 220 Jul-92

KAPS 1 PHWR 220 May-93

KAPS 2 PHWR 220 Sep-95

Total 4,560

Note: Kaiga Generating Station (KGS), Kakrapar Atomic Power Station (KAPS), Madras Atomic Power Station (MAPS), Narora Atomic Power Station (NAPS), Rajasthan Atomic Power Station (RAPS), Tarapur Atomic Power Station (TAPS), Pressurised Heavy Water Reactor (PHWR), Boiling Water Reactor (BWR)

Source: NPCIL, Nomura research

Exhibit 187. Nuclear power plants under construction

Project Capacity (MW) Expected commercial operation

Kudankulam 2 x 1000 Unit 1 – Dec-2010

Unit 2 – Jun-2011

Rajasthan 2 x 700 Unit 7 – Jun-2016

Unit 8 – Dec-2016

Kaiga 1 x 220 Unit 4 – Jul-2010

Kakrapar 2 x 700 Unit 3 – Jun-2015

Unit 4 – Dec-2015

Total 5,020

Source: NPCIL, Nomura research

We note that the Indian government has given ‘in principle’ approval for five greenfield sites in October 2009 to set up Pressurised Heavy Water Reactors (PHWRs) in Haryana (4 x 700 MW), Madhya Pradesh (2 x 700 MW) and Light water Reactors (LWRs) based on international cooperation in Gujarat (6 x 1000 MW), Andhra Pradesh (6 x 1000 MW) and West Bengal (6 x 1000 MW). NPCIL has commenced pre-project activities at these sites. The pre-project activities will be undertaken in four phases. Work on the first phase, comprising site investigation and various related studies in respect of these five sites have been initiated in full swing.

Moreover, we note that the government has also sanctioned for capacity expansion at Kudankulam (6 x 1,000, LWRs) and accorded for Jaitapur (6x1,650, LWRs). Looking at ongoing and future capacity expansion plans, we believe that India can easily surpass its mid-term target of 20GW by 2020F (India’s FY20F).

Five greenfield power sites in the works



Exhibit 188. “In-principle” approved sites

Site Units Capacity (MW) Total Remarks

Kumharia, Haryana 4 700 2,800 Pre-project activities initiated

Bargi, Madhya Pradesh 2 700 1,400 Pre-project activities initiated

Kudankulam, Tamilnadu 6 1,000 6,000 KK 1&2 under construction

Jaitapur, Maharashtra 6 1,650 9,900 Land acquisition in progress

Haripur, West Bengal 6 1,000 6,000

Mithi Virdi, Gujarat 6 1,000 6,000

Kovvada, Andhra Pradesh 6 1,000 6,000

The exact capacity of the sites would depend on the number and type of reactors set up at

each site

Total 36 38,100

Source: Department of Atomic Energy (DAE)

Joint venture with NPCIL will be the preferred route for private sector

As per the Atomic Energy Act of 1962, only government-controlled entities can engage in production of nuclear power generation. Looking at the perceived risk associated with the operation of nuclear power plants, we do not expect any changes in this policy. In our view, the only way out for the private sector is to form joint ventures with NPCIL to tide over this problem. We are already seeing plenty of activity in terms of partnerships being signed between NPCIL and the private sector (domestic and international players alike). Even some public-sector companies operating in the energy and power sector are jumping on the nuclear bandwagon.

After the Nuclear Suppliers Group (NSG) waiver, NPCIL has signed Memorandum of Understandings (MoU) with players from different countries across the nuclear value chain, from mining to nuclear plant manufacturers. We believe this will lay a strong foundation to execute on India’s ambitious nuclear power plans.

Exhibit 189. Recent activities in the Indian nuclear sector

Date Events

September 30, 2008 India signs Civilian Nuke Pact with France

October 10, 2008 India signs of 123 Agreement with the US

December 6, 2008 India sign Civilian Nuke Pact with Russia

January 24, 2009 NPCIL and Kazakhstan's KAZATOMPROM sign MOU broadening cooperation in the nuclear industry

February 4, 2009 NPCIL and AREVA sign MOU to set up nuclear power plants at Jaitapur in Maharashtra State. This MOU provides for engagement of NPCIL and AVERA into the discussion for preparing the contract and related detail of setting up of two to six 1,650MW EPRTM reactor units including life-time fuel supply for these reactors. AREVA also signed agreement to supply 300 tonnes of uranium

February 11, 2009 DAE and TVEL, Russian Federation sign contract for long-term supply of 2,000 tonnes of natural uranium pellets for India's PHWR and another contract for about 60 tonnes of low-enriched uranium for the two BWRs

February 14, 2009 NPCIL and NTPC sign MOU to incorporate a joint venture for setting up nuclear power plants in India

March 23, 2009 NPCIL and GEH, US sign MOU to start discussions on techno-commercial aspects of Advanced Boiling Water Reactor

May 28, 2009 NPCIL and WEC (US) sign MOU to set up AP1000 reactors in India

August 27, 2009 NPCIL and KEPCO ink MOU covering bilateral cooperation in the field of nuclear power

November 4, 2009 NPCIL and IOCL sign MOU to set up nuclear power plants in India

November 30, 2009 NPCIL and L&T set up JV to build facility for special steels and ultra-heavy forgings

April 07, 2010 Rolls-Royce and Larsen & Toubro to collaborate on global nuclear opportunities

April 27, 2010 NPCIL and NTPC Limited sign a JV agreement

Source: NPCIL, L&T, Nomura research

Post the India-US nuclear deal and the NSG waiver, India has been courted by all the top nuclear power plant (NPP) manufacturers (including Westinghouse, Areva and GE). The NPP manufacturers are either trying to tie up with NPCIL or other domestic engineering companies (L&T), anticipating the opening up of India’s nuclear sector for private players in the near future. We believe that Russia has a head start and holds an edge over other international players given its long-standing relationship with NPCIL. As India’s trusted partner, Russia Atomstroyexport (ASE, Russia) has supplied reactors for Kundankulam-1 & 2 (under construction).

The private sector must join hands with the government on nuclear

Russia would seem to have the inside track in working with India on nuclear



International equipment suppliers awaiting policy amendment

Despite the successful passing of the India-US nuclear bill and getting a waiver from the NSG, we note that the nuclear power plans of the international players have been stuck. The reason for this is that India does not have any law to ascertain liabilities in case of a possible nuclear mishap. We believe in the present environment, international players will find it to difficult to supply nuclear equipment to India.

To solve this problem, the Indian government recently introduced The Civil Liability for Nuclear Damage Bill, 2010 in the Parliament. The bill deals with liabilities in case of a possible nuclear mishap. However, we note that the opposition political parties are vehemently opposing the bill. Their main opposition stems from the fact that the amount of liability is small compared to international standards.

We note that the passage of the bill is a key requirement for implementing the landmark 2008 India-US nuclear deal. The government tabled the bill in the Lok Sabha (House of the People) in May 2010, which has since been referred to as the Parliamentary Standing Committee on Science and Technology. Considering the contentious nature of the bill and opposition of the political parties, we expect to see further delay in passing of the bill. The bill will now be debated in a Parliamentary Standing Committee, which is expected to submit its report by July 2010.

Some legal infrastructure needed as well …

… current law in the works is seen as letting international players shirk their fair burden by some



Asia ex-Japan

Korea Keith Nam +82 2 3783 2304 / [email protected]

Sabine Park +82 2 3783 2342 / [email protected]


Nuclear power: a government priority The Korean government published its “green road map” in the National New Growth Engine in August 2008, promoting economic growth by developing low-carbon energy sources. The road map includes various innovation programmes to foster green growth through 2012F, thereby further developing the economy and creating more jobs. The National Green Growth Engine Program selected nuclear power as the most workable source of low-carbon energy. Non-nuclear alternative power sources, mostly solar power, contribute less than 0.5% of Korea’s power generation. The government is aware that building nuclear power plants can cost 2-3x more per MW than thermal and incremental power plants. Meanwhile, uranium is cheaper than other fuel types, such as coal and LNG, in terms of power generation.

KEPCO leads Korea’s nuclear drive both domestically and overseas

In Korea, we highlight KEPCO, Korea’s consortium leader for overseas nuclear project bids. The KEPCO-led consortium successfully bid for the largest overseas turnkey nuclear power project to date, out of Abu Dhabi, in December 2009. Domestically, 85% of KEPCO’s generating capacity expansion through 2016 will come from nuclear power. An impending fuel cost escalation scheme, which will bring about a tighter, more guaranteed tariff scheme, also reaffirms our BUY rating on KEPCO stock.

Nuclear power capacity to account for 33% by 2022F According to the Fourth Power Supply Plan announced by the Ministry of Knowledge and Economy (MKE), Korea will invest W37tn (about US$33bn) in increasing generation capacity over the period to 2022F to meet electricity demand. The plan includes the establishment of 12 nuclear power reactors, seven coal-fired units and 11 liquefied natural gas (LNG) units.

As such, we estimate that installed nuclear power capacity will account for 33% of total installed capacity in Korea by 2022F, versus 25% in 2008, overtaking coal and LNG-fired capacity, which currently account for the highest portions (33% and 25%, respectively). In terms of generating volume, we estimate the nuclear portion will grow from 34% in 2008 to 48% in 2022F, while the coal portion shrinks from 39% to 36% over the same period. The MKE expects electricity demand to grow at an average 2.1% pa to some 500.1bn kilowatt hours in 2022F.

Exhibit 190. Korea: nuclear generation

0

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Exhibit 191. Korea: nuclear capacity

0

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FY

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Nuclear power capacity to account for 33% in 2022F vs 25% in 2008

Korea promoting nuclear power as the most workable source of low-carbon energy

Non-nuclear alternative energy sources contributing 0.4% of power generation

KEPCO: also, a tighter tariff scheme pending



Exhibit 192. Korea: generating capacity by power plant type

0

20,000

40,000

60,000

80,000

100,000

120,000

FY08 FY10F FY15F FY20F FY22F

Nuclear Coal LNG Oil Hydro Other(MW)

Source: Ministry of Knowledge and Economy

Nuclear plants under construction Since Korea’s first nuclear power plant Kori No.1 started operation in April 1978, the country has continued to build nuclear power plants to secure a steady supply of power. The country currently has 20 operating nuclear reactors.

As energy demand continues to rise, the government plans to build a total of 12 new nuclear reactors by 2022F. With these new reactors, we estimate that electricity generated by nuclear power plants will account for more than half of all electricity produced in Korea. The 12 new nuclear reactors include eight under construction or on order, all due to start up between 2010F and 2016F, with another two plants proposed to be on line by 2030F. Work began on two of the new units — Shin Wolsong 2 and Shin Kori 1 — in 2008.

Korea ranks sixth in terms of energy produced by nuclear reactors, behind the US, France, Japan, Russia and Germany. Nuclear power plants provide more than 36% of the country’s electric power supply, compared with a global average of around 16%.

Exhibit 193. Korea: nuclear reactors under construction

Generating Start Commercial

Power plant Type capacity (MW) construction operation

Shin Kori 1 OPR-1000 1,000MW Jun-06 Dec-10

Shin Kori 2 OPR-1000 1,000MW Jun-07 Dec-11

Shin Wolsong 1 OPR-1000 1,000MW Nov-07 Mar-12

Shin Wolsong 2 OPR-1000 1,000MW Sep-08 Jan-13

Shin Kori 3 APR-1400 1,350MW Oct-08 Sep-13

Shin Kori 4 APR-1400 1,350MW Sep-09 Sep-14

Shin Ulchin 1 APR-1400 1,350MW Mar-11 Dec-15

Shin Ulchin 2 APR-1400 1,350MW Mar-12 Dec-16

Shin Kori 5 APR-1400 1,350MW Aug-14 Dec-18

Shin Kori 6 APR-1400 1,350MW Aug-15 Dec-19

Shin Wolsong 3 APR-1400 1,350MW Jun-20

Shin Wolsong 4 APR-1400 1,350MW Jun-21

Total: 12 14,800MW Source: World Nuclear Association, WNA

The government plans to build a total of 12 new nuclear reactors by 2022F



Exporting Korea’s nuclear technology overseas Korea’s nuclear technology has advanced to the level of exporting nuclear power plants on a turnkey basis — ie, the construction and transfer of ready-to-use power plants to clients. The nuclear industry, led by Korea Hydro Nuclear Power, endeavours to export the APR1400, an advanced power reactor developed in Korea.

The domestic industry is also pushing ahead with the APR+ Technology Development Project, with support from the MKE. The APR+ project is designed to overcome export constraints by localising essential design computer codes and technology for potential buyers. If this project is successfully completed, Korea will ultimately be able to export nuclear power plants on a turnkey basis.

The APR+ project focuses on exporting homegrown nuclear power plant designs on a turnkey basis. The project aims to further advance existing nuclear technologies, such as essential design tools, nuclear plant design and nuclear plant construction/ operating know-how to the level of major nuclear vendors.

The government's nuclear technology development strategy, Nu-Tech2015, has two main components. One concerns the localisation of key technologies such as nuclear reactor design computer codes, reactor coolant pumps and man-machine interface systems. The other component is the APR+ project, which is aimed at developing globally marketable nuclear power plant designs by making the original reactor type safer and more economically efficient. The success of the APR+ project is essential for the success of the Nu-Tech2015 strategy. We think Korea will emerge as one of the top nuclear-reactor exporting countries by 2015F, when these technology development projects are expected to bear fruit.

The APR+ project was launched on 1 August, 2007. The APR+ project will be developed as a kind of Generation III+ reactor type, with improved safety and economic efficiency. The project will be carried out in three phases and is scheduled to be completed by 2015F. The APR+ project is expected to boost the national economy and the export capability of the domestic nuclear industry.

Exhibit 194. Reactor models for nuclear power plants


US$40bn UAE nuclear power deal Korea won a contract at the end of 2009 to set up four nuclear reactors for the oil-rich United Arab Emirates (UAE). The deal, signed on 27 December, will authorise a consortium led by state-owned KEPCO to design, build and run reactors that will produce 5,600MW of electricity. We reiterated our positive view on the Korean power and construction sectors in our 28 December, US$40bn UAE nuclear power deal.

Korea endeavours to export the APR 1400, an advanced power reactor developed in Korea

Korea should emerge as a top nuclear-reactor exporting country by 2015F when the Nu-Tech2015 nuclear development projects are expected to bear fruit

Korean consortium wins first major Gulf nuclear project



Korea’s big first step in a US$1tn-plus market

While the contract to build the four reactors is worth about US$20bn, the consortium expects to earn another US$20bn by jointly operating the plants for 60 years, according to Al Jazeera News. The reactors — the first nuclear plants in the Gulf Arab region — are scheduled to start supplying electric power to the UAE grid in 2017. “This deal is the largest mega-project in Korean history,” according to a statement from the office of Lee Myung-bak, the South Korean president. Korea’s Ministry of Knowledge Economy (MKE) expects 430 new nuclear power plants to be built worldwide by 2030 at a cost of over US$1tn. The Korean bid won for pricing, efficiency and shorter construction period.

The Korean bid had turned out to be surprisingly competitive against bids from France and a joint US-Japanese consortium. We think Korea’s APR1400 (Advanced Power Reactor) is praised for: 1) a shorter construction period of 48 months, versus EPR’s (European Pressurized Reactor) and US-made reactors’ 57-60 months; 2) a 20-30% cost saving compared with French, US and Japanese project costs; 3) a track record of 93% nuclear plant capacity usage in Korea, the highest in the world; and 4) safety features and improved materials.

Exhibit 195. Evolution of the nuclear reactor industry

AP600

Business cooperation

B&W (USA)

Framatome (France)

Siemens (Germany)

M itsubishi (Japan)

Combustion

Asea-Atom (Sweden)

Brown Boveri (S it l d)

Westinghouse (USA)

Toshiba (Japan)

G.E. (USA)

Hitachi (Japan)

AEP (Russia)

AECL(Canada)

1980s 1990s 2000s 2007

Framatome (France)

Siemens (Germany)

Framatome ANP

ABB-CE

Westinghouse (USA)

AREVA-NP

M itsubishi

Korea nuclearindustry (DHIC, KOPEC)

Westinghouse (USA)

Toshiba (Japan)

G.E. (USA)

Hitachi (Japan)

AEP (Russia)

AECL (Canada)

B WR businessco o perat io n

F o undat io n o f an asso ciat io n

iABWR ESBWR

AP1000

ECR - CANDU

WWER-1000

ACR 1000

EPR

US APWR

APR-1400OPR-1000

System 80 + P WR business

Source: International Atomic Energy Agency (IAEA)

UAE contract gives Korean consortium a chance to win operation and maintenance contracts

UAE win puts Korean nuclear players in good position for future global projects

Korea’s APR1400 reactor design now among IAEA’s major global reactor technologies



Asia-ex Japan

Australia Daniel Raats +852 2252 2197 / [email protected]



With 305 renewable energy projects (of greater than 100kW in size) contributing more than 10.6GW, renewable energy amounts to 16% of the total installed power capacity in Australia. Of the total installed capacity of renewable energy, hydro contributes 77% and leads the list. Wind energy, which contributes 16% of total renewable energy, is second. As per the Clean Energy Council of Australia, seven new wind energy projects totalling 559MW of installed capacity, along with new hydro projects totalling 171MW and bio-energy projects totalling 23MW, are currently under construction.

Exhibit 196. Australia renewable energy installed capacity (November 2009)

Fuel source Installed capacity

(MW)Number of

projectsPercentage

(%)Hydro 8,186 113 77.0 Wind 1,668 48 15.7 Bio-energy: – Bagasse cogeneration 474 29 4.5 – Black liquor 77 3 0.7 – Crop waste 2 1 0.0 – Food and agricultural wet waste 4 2 0.0 – Landfill gas 163 69 1.5 – Sewage gas 37 18 0.3 – Wood waste 9 3 0.1 Bio-energy sub-total 766 125 7.2 Large scale solar PV & solar thermal 9 17 0.1 Wave 1 1 0.0 Geothermal 0.1 1 0.0 Renewable total 10,629 305 100.0 Note: Smaller generation units of solar PV (~145MW) have not been included

Source: Clean Energy Council (Australia), Nomura research

Wind — among the best resources worldwide With new capacity addition of 300MW, Australia’s total wind installed capacity grew 19% y-y to 1,886MW in 2009. At the close of 2009, there were 51 wind farms in Australia generating approximately 4,284GWh or 1.6% of Australia’s national electricity demand. Another seven projects totalling 588MW are under construction and are expected to be commissioned within the next three years.

South Australia has the largest installed wind capacity, accounting for 43% of the nation’s total installed wind capacity. We note that Australia’s wind resources are among the best in the world. As per Australia’s Clean Energy Council (CEC), there are currently 7,000MW large large-scale wind farm energy projects proposed in the pipeline, with many of them having already received planning permission.

For 2010F and 2011F, we expect Australia’s annual wind installation to grow by 50% y-y and 10% y-y, respectively, backed by effective government policies, such as the recently legislated expanded Renewable Energy Target (RET).

Exhibit 197. Newly added wind power capacity in 2009

Owner Location State Installed capacity (MW)

Acciona Waubra Victoria 192

Infigen Energy Capital Wind Farm New South Wales 141

Pacific Hydro Portland Stage 3 (Cape Nelson South) Victoria 44

Origin Energy Cullerin Range New South Wales 30 Source: GWEC, Nomura research

Australia is a dry continent, but hydro still supplies more than two-thirds of the renewable mix

Australia is wind rich

Overall, we see 50% y-y growth in installed capacity this year, and 10% y-y next year (off a much higher base)



Exhibit 198. Australia: wind farms under construction

Owner Location State

Expected commission year

Installed capacity (MW)

AGL Hallett Stage 2 South Australia 2010 71

Pacific Hydro Clements Gap South Australia 2010 57

Union Fenosa Crookwell 2 New South Wales 2010 92

Infigen Energy Lake Bonney Stage 3 South Australia 2010 39

AGL Oaklands Hill Victoria 2011 67

Roaring 40’s Musselroe Tasmania 2011 129

AGL Hallett Stage 4 (Nth Brown Hill) South Australia 2012 132 Source: GWEC, Nomura research

Exhibit 199. Australia: total installed wind capacity

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Exhibit 200. Australia: installed wind capacity by state

South Australia 43%

Western Australia 12%

Victoria 25%

Tasmania 8%

New South Wales 11%

Queensland 1%

Source: GWEC, Nomura research

Bio-energy — adding 1GW capacity by 2020F With installed capacity of 765MW, bio-energy represents 7.2% of the total renewable energy capacity in Australia. Of all types of bio-energy, bagasse (the leftovers of sugarcane production) cogeneration contributes the most with 62.4%, followed by landfill gas, which represents 21.2%. As per government estimates, some 11,000GWh each year could be delivered from bio-energy, equivalent to 1,845MW of installed capacity by 2020F. We note that new capacity is currently being commissioned and more plants are in the construction phase, notably in New South Wales.

Bio-energy a significant part of the mix; no surprise in an agricultural nation



Exhibit 201. Australia: installed bio-energy capacity by type

Bagasse cogeneraton 63%Black liquor 10%

Landfill gas 21%

Sewage gas 5%Wood waste and

others 1%


Exhibit 202. Australia: bio-energy plants currently under construction

Fuel source Location Owner StateCommission

year

Installed capacity

(MW)

Food and Agricultural Wet Waste

Mt Cotton Darwalla Group QLD 2009/10 7.6

Landfill Gas Woodlawn Stages II-IV

Veolia Environmental

Services

NSW 2010 19

Sewage Gas Warriewood Sydney Water NSW 2009/10 0.25

Sewage Gas Wollongong Sydney Water NSW 2009/10 0.51

Sewage Gas Glenfield Sydney Water NSW 2009/10 0.53

Wood Waste Dandenong Consolidated Energy Resources

VIC 2009/10 2.4

Sewage Gas Liverpool Sydney Water NSW 2009/10 0.33


Solar — growth to slow owing to less favourable subsidies Despite the global financial crisis, the Australian solar PV industry grew approximately 38% in 2009, owing mainly to government incentives in the form of rebates. In 2009, more than 56MW of grid-connected solar power was installed in Australia. At the end of 2009, Australia had installed capacity of about 145MW. We note that more than 41,000 homes across Australia have solar PVs installed.

Solar PV has a long history of supplying reliable ‘off grid’ power to remote and regional Australian communities. Around 70% of all PV installations are currently off-grid. However, with the introduction of recent government incentives, the number of grid-connected solar PV installations has grown rapidly, now accounting for about 30% of Australia’s total solar installed capacity.

We note that the growth in 2009 was mainly driven by a federal government rebate of A$8/watt (capped at A$8,000), which when combined with Renewable Energy Certificates (RECs) meant that zero-cost 1kW solar power systems were being offered by a number of companies. However, the government rebate was replaced by Solar Credits, a point-of-sale discount based upon the market value of a multiplied number of RECs, and hence the upfront government support has significantly diminished.

Like Germany and other nations, Australia is reeling back solar subsidies



Exhibit 203. Total solar PV installed capacity in Australia

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Exhibit 204. Percentage of households using solar energy

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Australia’s uranium reserves are the world’s largest We note that according to the World Nuclear Organisation, Australia has the world’s largest uranium reserves, representing 23% of global reserves. We note that over the past three years, Australian uranium exports have averaged almost 10,000tonnes/year, providing about 22% of world uranium supply from mines. Australia’s uranium, which is used only for electricity generation, is supplied under arrangements which ensure that none finds its way into nuclear weapons. In the year 2008-09, Australia exported more than 10,000 tonnes of uranium oxide concentrate with a value of more than A$1bn. Uranium comprises about 35% of the Australia’s energy exports.

Exhibit 205. Global uranium resources

Australia 23%

Kazakhstan 15%

South Africa 8%

Canada 8%

Brazil 5%

Namibia 5%

Others 20%

Russia 10%

US 6%

Source: World Nuclear Organisation, Nomura research

Australia holds just shy of a quarter of the world’s uranium; and this comprises some 35% of its energy exports



Government policy Given below is the summary of government policies both at the central and state level in Australia.

Exhibit 206. Clean energy state-by-state snapshot

State Installed capacity

% of nationwide

installed capacity (%)

Number of

projects Technologies Feed-in-tariff Support for clean energy established In 2009

Australian Capital Territory (ACT)

6 0.1 5 Bioenergy Hydro

50.05 cents / kWh for less than

10kW; 40.04 cents / kWh for

10-30kW (gross)

Committed A$30mn of funding for large-scale solar projects

New South Wales

4,860 45.7 77 WaveSolar Thermal

Solar PVBioenergy

WindHydro

60 cents / kWh (gross)

NSW Wind Renewable Energy Precincts. State government’s A$700mn Climate Change

Fund, established in July 2007, operational. Since 2007 funds have been allocated in the following areas: – A$100mn Residential Rebate Program – A$30mn NSW Green Business Program – A$30mn Public Facilities Program – A$40mn Renewable Energy Development Fund – A$20mn School Energy Efficiency Program – A$20mn Rainwater Tanks in Schools Program – A$150mn programme under the Energy Efficiency Strategy

Northern Territory

2 0.0 6 Solar PVBioenergy

N/A

Queensland 1,107 10.4 56 GeothermalBioenergy

WindHydro

44 cents / kWh (Net)

State government’s A$50mn Renewable Energy Plan to increase deployment of renewable energy initiatives and accelerate growth of this sector established in 2009.

A$15mn Queensland Geothermal Energy Centre of Excellence to drive geothermal research and technology

Solar Bonus Scheme — a feed-in tariff to pay domestic and small energy customers for the surplus electricity generated from roof-top solar systems

South Australia 774 7.3 24 Solar PVBioenergy

WindHydro

44 cents / kWh (Net)

The South Australian Government claims to offer national best practice land use planning for accommodating wind farms.

Solar feed-in scheme under review. Current rates; A$0.44 per unit of electricity (kilowatt-hour, kWh) for householders and small business customers who feed solar electricity into the grid.

Renewable Energy Target (RET) 33% of electricity to be produced by renewable energy by 2010

Tasmania 2,442 23.0 43 BioenergyWind

Hydro

Current retail offer – at

20 cents / kWh FiT – TBC

The Tasmanian Government released its Energy Policy Statement in December 2009 and has set up a Tasmanian Renewable Energy Industry Development Board

Western Australia

267 2.5 31 BioenergyWind

Hydro

20 cents / kWh FiT – TBC"

Sustainable Energy Development Office (SEDO) Grants Program – A$5,000 to A$50,000 for community-based sustainable energy projects targeting householders to increase use of renewable energy

Victoria 1,171 11.0 62 Solar PVBioenergy

WindHydro

Premium FiT for solar PV – 60

cents / kWh F&R Tariff – at least

1:1 (FiT/Net))

Victorian Renewable Energy Target Scheme (VRET) commenced 1 January, 2007 — 10% by 2016 – 3274GWh VRET will be absorbed into the national RET scheme when it commences in 2010

Sustainable Energy Large Scale Demonstration Program — A$72mn grants programme to support the development of larg-scale, pre-commercial demonstrations of sustainable energy technologies

Total 10,629 100.0 304




Exhibit 207. Federal renewable energy initiatives

Programme/ scheme name

Type/ cost of policy Purpose

Eligible renewable technologies

Participant eligibility/ requirements

Duration/ introduction Grant amount

Additional information

Solar

Solar Flagships Program (Part of A$4.5bn Clean Energy Initiative)

A$1.5bn over 6 years. Competitive funding for solar energy plants

To create an additional 1,000MW of solar generation capacity

Commercially proven solar technologies. Proposal may include solar thermal and solar PV with generation capacity of at least 150 MW. Proposals must meet Solar Flagships criteria and Education Investment Fund criteria

Technology used in the project must have been demonstrated in operation at a scale of at least 30 MW generation capacity for 12 months

Round 1 closed 15 February, 2010. Successful projects expected to be announced in 2H 2010.

Expected to leverage A$2 of industry and state government funding for A$1 of Commonwealth investment

Round 1 projects scheduled to complete commissioning of plant by 31, December, 2015

National Solar Schools (Temporarily suspended until July 2010)

Grants programme

To allow schools to generate electricity from renewable sources, improve energy efficiency, reduce energy consumption

Solar power systems, small wind, small hydro, solar & heat pump hot water systems

Government and non-government schools

July 2008 until 30 June, 2015. Currently suspended to new claims until July 2010.

Systems >2kW up to A$50,000 grant Systems <2kW up to A$30,000

Administered through DEWHA

Solar Cities A$75mn programme Solar cities are: Adelaide, Alice Springs, Blacktown, Central Victoria, Moreland, Perth, Townsville

To demonstrate effects of combining cost reflective pricing with widespread use of solar technology and examine barriers.

Solar Technologies

Solar cities Duration 2005 - 2013

N/A Data collected & analysed to find the most effective energy management for communities

Australian Solar Institute (Part of A$4.5bn Clean Energy Initiative)

A$100mn over 4 years. Competitive grants programme

To support solar researchers

Concentrating solar thermal energy and solar PV

Researchers from public and private sectors

To commence operations by July 2009

Variable. Round 1 successful projects announced December 2009

Round 2 projects proposals expected to be called for first half 2010

Bioenergy

Second Generation Biofuels Research & Development Program(Part of A$4.5bn Clean Energy Initiative)

A$15mn competitive grants programme

To support research, development & demonstration of new biofuel technologies & feedstocks

2nd generation biofuels

Applicant must be research institution, university or business with capability to undertake research, development or demonstration of 2nd generation biofuels

Delivered over 4 years from 2008-2009 to 2011-12

Matching grants of A$1- $5mn

Administered through ACRE

Geothermal

Geothermal Drilling Program (Part of A$4.5bn Clean Energy Initiative)


To support cost of drilling geothermal wells for proof of concept

Geothermal Applicant must be non-tax exempt incorporated. Australian company which holds Australian geothermal exploration licence

Launched 20, August 2008

Grants of up to A$7mn provided as dollar-for-dollar matched funding

Administered through ACRE

Policy common for all renewable energy technologies

Australian Centre here for Renewable Energy (ACRE) (Part of A$4.5bn Clean Energy Initiative)

A$567mn programme. One stop shop for renewable energy businesses

To promote development, commercial guidelines on & deployment of renewable energy technologies

Renewable technologies

Organisation’s governance and guidelines – TBC

To be established 2009-10

N/A - Advisory body

Under Minister for Resources & Energy

Renewable Energy Demonstration Program (Part of A$4.5bn Clean Energy Initiative)


Funding to assist in demonstration of renewable energy for power generation commercial scale in Australia

Solar, geothermal, wind, biomass, hydro, ocean energy, combination technologies

Applicant must be non-tax exempt incorporated Australian company

Launched 20 February, 2009. Funding provided in rounds

Size of grants expected to be A$50-100mn (up to one third of eligible expenditure on the project

Administered through the Australian Centre for Renewable energy (ACRE). Applications invited for funding 2009/2010 and beyond



Exhibit 207. Federal renewable energy initiatives (Cont’d)

Programme/ scheme name

Type/ cost of policy Purpose

Eligible renewable technologies

Participant eligibility/ requirements

Duration/ introduction Grant amount

Additional information

Other policy support measure

Renewable Energy Target (RET)

Mandates Australia’s use of electricity generated from renewable sources. Investment estimated at A$5bn

To encourage additional generation of electricity from renewable energy sources.

Renewable energy generated or deemed to have been generated

Accredited power stations or small generation units that have generated renewable energy or deemed to have generated renewable energy

Expanded renewable energy target (RET) commenced 1 January, 2010

N/A. Market price paid for Renewable Energy Certificates (RECs)

Target set at additional 45,000 GWh by 2020

Carbon Pollution Reduction Scheme (CPRS)

Proposed emissions trading scheme

To reduce Australia’s carbon emissions by placing a cap on amount of carbon pollution the economy can emit

N/A Scheme will include 75% of Australia’s emissions and involve mandatory obligations for approx 1,000 entities

Scheduled to commence 1 July 2011 but has not been legislated

N/A Targets between 5 - 25% of 2000 emissions levels by 2020 and 60% by 2050

Innovation Investment Fund

Venture capital support programme

To support commercialisation of Australian research by co-investing in innovation funds

Investing in early stage and commercialising Australian R&D

Fund managers Round 3 applications close 31 May 2010

Investment provided to venture capital fund on 1:1 ratio - maximum commonwealth capital A$20mn

Clean Energy Innovation Centre – EnterpriseConnect Network

Part of A$50mn Enterprise Connect Initiative

Centre offers services to clean energy industry including free business reviews and supporting grants

Clean energy technologies eg solar, wind, wave, tidal, biofuels and cogeneration, development and supply of methods, equipment and technology used to reduce energy demand or increase energy efficiency.

Small & medium sized businesses in the clean energy industry

Launched 2009

Business reviews, ongoing mentoring, grants up to A$20,000 (will contribute to half the cost of approved projects)

Centre located in Newcastle

Retooling for Climate Change Program (Part A$240mn Clean Business Australia initiative)

A$75mn over 4 years Competitive grants programme

Aims to help Australian manufacturers reduce their environmental footprint

Small-scale cogeneration plants

Applicant must be non-tax exempt incorporated Australian company and have annual turnover of less than A$100mn

Commenced 2008 until 2012

A$10,000 - A$500,000, up to a maximum of half the cost of project.

Applications may be submitted at any time and will be assessed on a regular basis

Climate Ready Program (Part of A$240mn Clean Business Australia initiative)

A$75mn over 4 years Competitive grants programme

To support research & development, proof-of- concept & early-stage commercialisation activities

Small scale renewable energy technologies

Applicant must be non-tax exempt incorporated Australian company and have an annual turnover of less than A$100mn

Commenced 28 July 2008

A$50,000 - A$5mn on a matching funding basis

Currently closed for application

Clean Energy Trade and Investment Strategy

A$14.9mn will be spent over 3 years

To attract investment into Australia's clean energy sector and assist Australian clean energy companies to access international markets

Solar, wind, geothermal, marine, bioenergy and biofuels

Australian business TBC N/A Austrade to appoint industry specialists in Australia and in major offshore markets




Asia-ex Japan

Thailand Daniel Raats +852 2252 2197 / [email protected]


Thailand is endowed with one of the largest agricultural sectors in Southeast Asia, near all-year sunshine and a geography which is, in certain areas, conducive to the exploitation of wind power. Moreover, while hydro potential is limited domestically, neighbouring Laos offers significant untapped potential. This, combined with the government’s desire to reduce Thailand’s dependence on natural gas and imported oil-based fuels and to promote indigenous energy sources, has seen Thailand emerge as a leading developer of renewable and alternative energy resources in Southeast Asia. We believe this strong momentum in renewable energy development will be sustained over the medium term, while large-scale hydro and nuclear alternatives form a cornerstone of regulators’ long-term planning.

Generating mix heavily gas-dependent Thailand’s electricity supply industry (and its economy in general) relies heavily on natural gas as a fuel source. According to data from the Energy Policy and Planning Office (EPPO), gas-fired plants accounted for circa 70% of electricity generated in Thailand and the electricity industry was responsible for 70.4% of overall natural gas consumption in Thailand in 2008. Moreover, the industry’s leverage to gas as a fuel source is even larger if one takes into consideration that about 10% of total Thai gas consumption is by industrial customers, which accounted for the largest proportion (45%) of electricity consumption in 2008

While gas-based electricity production has appeal, due to lower capital costs, shorter gestation period, high efficiency, environmental characteristics and modular technology, the heavy reliance on it as a fuel source has become an increased cause for concern with regards to Thailand’s energy security.

Natural gas transportation and supply in Thailand is undertaken by the Petroleum Authority of Thailand (PTT). According to the Department of Mineral Fuels, as at December 2008, Thailand had proven (2,012mm BOE) and probable (2,098mm BOE) reserves, which at current levels of usage, represents about 25 years of supply.

Exhibit 208. Generating mix by fuel type

0

50

100

150

200

250

300

350

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

Natural Gas HydroLignite Imported CoalHeavy Oil Power ImportRenewable Energy Nuclear

Source: EPPO, Electricity Generating Authority of Thailand (EGAT), Nomura research

Exhibit 209. Generating mix by fuel type

0

20

40

60

80

100

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

Natural Gas Hydro Lignite

Imported Coal Heavy Oil Power Import

Renewable Energy Diesel Nuclear(%)

Source: EPPO, EGAT, Nomura research

At current production levels Thailand has proven and probable reserves to sustain consumption for 25 years

Gas accounts for roughly 70% of Thailand’s generation mix

Thailand, one of the most proactive countries in Southeast Asia in promoting alternative energy



Exhibit 210. PTT gas sales by customer (2008)

Industry12%

GSP17%

SPP13%

IPP28%

EGAT30%

Note: GSP = gas separation plant

Source: PTT, Nomura research

Exhibit 211. PTT gas sales by customer (1998 vs 2008)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

1998 2008

IPP SPP

EGAT GSP

Industry

(mmscfd)


Gas prices affected by oil and currency volatility

The Petroleum Authority of Thailand (PTT) sells gas to the power sector at a price comprising a gas pool price, the PTT’s marketing margin charge and a pipeline tariff. The gas pool price is the weighted average cost of natural gas from all gas producers in the Gulf, Thailand and neighbouring counties, such as Myanmar. Since the quantity of gas purchased from each producer remains relatively stable given the long-term nature of supply contracts, the key variable in the weighted cost is the respective gas wellhead price, which is indexed to economic factors including fuel oil prices, currency exchange rates plus CPI and PPI.

This indexing mechanism, written into the respective gas purchase agreement between the PTT and the gas producer, introduces price volatility, especially during periods of high oil prices (since it is linked to fuel oil prices in Singapore), potentially amplified by exchange rate volatility. Together, these two variables — the fuel oil price and the exchange rate — are particularly important since they introduce the sensitivity of world energy markets and the world economy to Thailand’s gas price.

From the perspective of Thailand’s electricity supply industry, post our discussions with market participants, we understand gas input costs to the power industry generally lag movements in oil prices by roughly six months and trace oil price movement with a correlation coefficient of about 40-50%, all else being equal.

Exhibit 212. Natural gas price structure to power producers

Power Producers ~71%

EGAT ~30%

IPP ~28%

IPP ~13%

Customer Sales Price Structure

Gas Pool Price + +

Average Purchased Gas Price

1.75%

1.75%

9.33%

~21.7 Bt/MMBtu* (Td 20.6553 + Tc 1.1112)

Supply Margin Pipeline Tariff

Note: Thailand's Energy Regulatory Commission has approved the pipeline tariff increase from Bt19.7/MMbtu to Bt21.7/MMbtu, effective 1 April 2009


PTT sells gas to the power sector at a price comprising a gas pool price, PTT’s marketing margin charge and a pipeline tariff

This indexing mechanism introduces price volatility, especially during periods of high oil prices

The gas input costs to the power industry generally lag movements in oil prices by roughly six months



Background to Thailand’s alternative energy drive In 1992, Thailand undertook its earliest legislative foray into the renewable energy sector through its Small Power Producer (SPP) Programme, under which the implementation of cogeneration and renewable energy projects was governed. In 1994, a separate Independent Power Producer (IPP) Programme was introduced for larger power plants. The SPP Programme was initially restricted to plants of 60 MW or less, but later amended to include plants up to 90 MW and incorporated qualifying criteria on issues such as the plant’s use of steam and cogeneration levels of efficiency.

Under the programme, SPPs are allowed to sell a maximum of 90 MW to the grid under long-term power purchase agreements (PPAs) with the Electricity Generating Authority of Thailand (EGAT) ranging, generally, between five and 25 years. Unlike IPPs, which are obligated to sell their entire output to the EGAT, SPPs are also able to sell electricity and/or steam (for cogen plants) to industrial customers located adjacent to their plants using private distribution lines. The long-term PPAs allocate market risk to the EGAT (and its captive rate-payers), allowing SPPs to focus on managing operation and fuel-related risks.

Generators that can guarantee (firm) supply must generate a minimum of 7,008 hours a year (equating to an availability of circa 80%) if fired by traditional fossil fuels or 4,760 hours (utilisation of 54.3%) if they utilise renewable energy sources — and are remunerated with references to the EGAT’s long-run avoided capacity and energy costs. Non-firm generators are free to generate as many hours as they please, but are remunerated at a lower rate equating to the EGAT’s short-run avoided energy costs. The ability of SPPs to sell 90 MW to the grid is important, as it provides an element of surety to earnings that greatly enhances the operation’s financial viability, since direct sales to industrial customers are subject to demand-side risk.

To be competitive, sales of electricity to industrial customers are indexed to the national grid at rates slightly lower than those of the Provincial Electricity Authority (PEA), which means that SPPs are affected by the fuel transfer payment (Ft) component of electricity tariffs, designed to compensate the company for fuel price fluctuations. However, since officials have the ability to defer Ft adjustments, the margins for SPP electricity sales to industrial customers may be affected by a short-term divergence between tariffs and fuel prices. Yet over the longer term, any divergence is intended to reverse (ie, Ft should play catch-up with fuel costs on a cumulative basis). Industrial users that purchase directly from SPPs benefit from lower electricity tariffs and greater surety of supply since electricity is not subject to central grid-related interruptions.

The programme’s initial success was largely derailed by the Asian Financial Crisis of 1997, when a glut of power availability festered the suspension of long-term purchase agreements for new cogeneration facilities. Even in the subsequent recovery, producers burdened with reluctant utilities, unattractive tariffs, technological risks and expensive interconnection requirements, continued to struggle.

Partially in response to this, in May 2002, Thailand initiated its Very Small Power Producer (VSPP) programme, which facilitates the interconnection of renewable energy generators less than 1 MW in size. Under the regulation, generators are able to offset their own consumption at retail rates in what is referred to as net metering. If they are able to generate a net surplus of electricity, the regulation stipulates that the PEA and the Metropolitan Electricity Authority (MEA) are obligated to purchase this electricity at the same rate purchased from the EGAT. Unlike in the case of SPPs, the important feature of this tariff structure is that there is no firm versus non-firm distinction; instead, generators receive higher tariffs during peak hours. In December 2006, VSSP regulations were expanded to hand similar terms for renewable and fossil-fuel combined heat and power (CHP) projects with a capacity of up to 10 MW.

SPPs can sell a maximum of 90 MW into the grid, and can sell electricity/steam directly to industrial users

Firm supply is remunerated with references to EGAT’s long-run avoided capacity and energy costs

Ft is not always exactly correlated to fuel price movements

Thailand initiated its VSPP programme in May 2002

Thailand’s SPP Programme was initiated in 1992



Renewable energy to account for 10% of installed capacity by 2022 Thailand’s existing Power Development Plan (PDP) aims to have renewable energy contribute about 10% of installed capacity by 2022 and, according to comments made by Thailand’s Energy Minister Wannarat Charnnukul (23 May, 2009, The Nation), the country intends, in broader terms, to increase the share of renewable energy from the current 6% to 20% of total energy consumption over the next 15 years. Thailand’s Draft PDP 2010, currently subject to a public consultation process, estimates that renewable energy (excluding hydro) will account for about 6% of aggregate power consumption by 2030, up from around 3% currently. This implies renewable energy generation will register a CAGR of 7.8% over the next 20 years.

Exhibit 213. Thailand: 15-year alternative energy targets

0

1,000

2,000

3,000

4,000

5,000

6,000

Existing 2008-2011 2012-2016 2017-2022

Biomass Wind Solar Hydropower Biogas MSW(MW)

Source: EGAT, Nomura research

Exhibit 214. Thailand: alternative energy master plan targets (2008-22)

(MW) Existing 2008-2011 2012-2016 2017-2022Shortfall relative to

potential

Solar 32 55 95 500 49,500

Wind 1 150 400 700 900

Hydropower 5 165 281 324 376

Biomass 1,597 2,800 3,235 3,700 700

Biogas 29 60 90 120 70

MSW 5 100 130 160 160

Total 1,669 3,330 4,231 5,504 51,706

Source: Department of Alternative Energy Development and Efficiency

Tariff-driven renewable energy incentives

Overview of upstream tariffs

Upstream electricity tariff structures between basic generators (IPPs, SPPs and VSPPs) and the EGAT as a single buyer vary as a function of the amount and type of electricity generated and the firmness (both the duration and obligation to buy the generated power) of the contractual relationship.

Tariffs for IPPs consist of availability or capacity payments, designed to compensate IPPs for fixed investment costs (including debt service) and fixed operating and maintenance costs, and to provide IPPs with a rate of return and an energy charge designed to cover variable costs including fuel payments. In addition to insulating IPPs from fuel and demand risks, IPP payments incorporate dollar indexation as a hedge to earnings against foreign currency-denominated debt. Because capacity payments are designed to compensate IPPs for investment costs, while they vary on a case-by-case basis, they tend to be front-loaded to

IPP tariffs consist of an availability or capacity payment and an energy charge

Thailand’s Alternative Energy Master Plan targets 5,500 MW of alternative capacity by 2022



match the IPPs’ debt repayment profile, tapering off towards the end of the PPA, especially for older generation IPPs, which came into existence at a time when debt markets were not sufficiently deep. With depreciation unaltered, this decline in capacity charges has implications for the earnings profile of IPPs with maturing PPAs if they do not have a pipeline of replacement projects.

SPP payments. As mentioned earlier under the SPP discussion, payments to SPPs vary according to whether the capacity is regarded as firm or not, which is a function of the ability to guarantee power generation availability. Firm SPPs get an unbundled base tariff comprised of capacity payments based on the EGAT’s long-run avoided capacity and energy costs. Non-firm SPPs receive only an energy payment benchmarked off the EGAT’s short-run avoided energy costs. A distinguishing factor between SPP and IPP payments is that SPP contract terms are standardised, whereas IPP PPA terms are generally tailored to the IPPs’ specific circumstances and, unlike the case with IPPs whose payments tend to decline as the PPA matures and retires debt, SPP payments are level, implying reduced marked deterioration for earnings in the later stages of a PPA.

VSPP payments. As described above, VSPP payments are based on net metering, which in essence means that generators are able to use excess electricity produced to turn back their electricity metres and effectively bank the electricity until required. This ensures that generators receive the full retail value of all electricity produced. If the VSPP produces electricity greater than its consumption needs over a monthly billing period, the VSPP regulation stipulates that the MEA and the PEA must purchase the electricity at wholesale (ie, rates at which electricity is purchased from the EGAT), which is about 80% of the retail rates. A key distinguishing factor between VSPPs and SPPs is that there is no firm versus non-firm distinction and, instead, generators receive higher tariffs during peak times.

Adder tariffs. A key element of the existing renewable energy regime is the ‘green’ subsidy available to both SPPs and VSPPs using renewable energy in the form of an “adder tariff” for a period of seven to 10 years from COD, which is fixed for certain fuel sources such as municipal wastes (MSW), wind and solar, or determined through a competitive bidding process for fuels such as biomass, in which the lowest proposed “adder tariff” is given priority. On 10 March, 2009, Thailand’s National Energy Policy Council (NEPC) approved an increase in these “adders,” which we outline below. We also note that SPP/VSPPs in the three southernmost provinces of Thailand — namely Yala, Pattani and Narathivath — are eligible for special “adder tariffs” (THB1/Kwh for biomass/gas, min/micro hydro, MSW, and THB1.5/Kwh for wind and solar) to alleviate the incremental investment risk of generating power with renewable energy sources in these locales. We note that, based on our channel checks with companies in Thailand under our coverage, we understand that regulators are considering a reduction in the solar adder tariff from the current THB8.0/Kwh to THB6.5/Kwh, although nothing is official yet.

VSPP payments are based on net metering, and receive adder tariffs for using renewable fuels

Payment to SPPs for electricity sales to EGAT varies depending on the “firmness” of capacity and the fuel source



Exhibit 215. Thailand: renewable and alternative energy generation

Adder

Bht/KWh US cents/ kWhTargeted capacity

2009-21 (MW)

Biomass 3,700

< 1MW 0.5 1.43

> 1MW 0.3 0.86

Biogas 120

< 1MW 0.5 1.43

> 1MW 0.3 0.86

Waste 160

Fertilisation/landfill 2.5 7.14

Thermal process 3.5 10.00

Wind 800

<50kW 4.5 12.86

>50kW 3.5 10.00

Hydro 324

50kW<200kW 0.8 2.29

<50kW 1.5 4.29

Solar 8.0 22.86 500

Total 5,604

Source: Energy Regulatory Commission

Overview of downstream tariffs

Downstream tariffs are made up of wholesale (the rate that the EGAT sells to the MEA and the PEA) and retail (the rate at which the MEA and the PEA sell to final customers) rates. In addition, given direct competition with the grid, off-grid SPP electricity sales to industrial customers can be viewed as being linked to PEA tariffs.

The EGAT sells electricity to the MEA and the PEA at a uniform wholesale rate. To ensure that tariffs are uniform for both rural and urban consumers, the MEA is required to make a lump sum subsidy to the PEA to account for the higher transmission costs.

Retail electricity tariffs are comprised of: 1) a base tariff; 2) an automatic fuel adjustment mechanism (Ft); and 3) a value-added tax, currently at 7%. The base tariff includes costs associated with generation, transmission and distribution, and varies according to consumer categories. The Ft component is calculated by making certain assumptions for variables such as fuel costs, inflation rates and exchange rates in an attempt to have tariffs reflect the actual cost of production and compensate operators for cost changes that are beyond their control. While Ft is adjusted once every four months, as noted, the authorities have the ability to obscure this transmission mechanism over short intervals to dampen the impact of fuel price volatility or extreme fuel shock. Over time, however, Ft will be allowed to recoup any such deviations from the cost of production so that, on a cumulative basis, the intended relationship between production costs and tariffs holds.

SPPs’ electricity sales to industrial customers. In addition to electricity sales to the EGAT, SPPs sell electricity directly to industrial customers at what is generally a small (circa 5%) discount to PEA tariffs, with the size of the discount varying depending on intensity of competition. As such, regardless of the fuel source used by the SPP to generate electricity, revenues are linked to PEA tariffs, which are designed to reflect movements in the grid-wide fuel costs (predominantly natural gas) which may have an implication for SPPs’ margins. Moreover, for seven gas-fired SPPs, the margins may be exposed during times of sharp gas price rises when Ft does not adjust commensurately, although hypothetically this should eventually reverse.

On 10 March, the NEPC approved a higher “adder tariff” to further stimulate the development of renewable technologies

SPP electricity sales to industrial customers are indexed to PEA tariffs

Retail electricity tariffs consist of a base tariff, an automatic fuel adjustment mechanism and a 7% VAT



SPP steam sales. In addition to electricity sales to the EGAT and industrial customers, cogen SPPs sell steam to industrial users subject to inherent limitation on the ability to transport steam over long distances greater than 4/5km. Steam sales are generally priced on an avoided cost model, which, in turn, implies indexation to gas prices as a fuel source. Given that steam production is effectively a by-product of the cogen process, avoided cost pricing for steam sales offers attractive margins to SPPs, in our view.

Other measures to encourage renewable energy To encourage the use of renewable fuel sources, Thailand introduced a Renewable Portfolio Standard (RPS) requiring IPPs that wish to sell electricity to the EGAT have at least 5% of their installed capacity fuelled by renewable sources. Other promotional measures include Board of Investment (BOI) tax incentives and a Revolving Fund, which aims to ensure that projects have access to affordable funding.

Laos crucial to Thailand fuel diversification efforts While the targeted capacity to be imported from Laos was scaled down heavily in March 2009’s PDP revision (from 5,574 MW to 2,187 MW, on our numbers), we believe Laos, in particular, will continue to feature prominently in Thailand’s future capacity plans since it offers the country an opportunity to diversify its generating mix in ways it is unable to do domestically — whether it be due to geographical limitations (for hydro projects) or opposition from the public and environmental groups (for coal-fired and hydro projects).

Laos is a mountainous, landlocked country with a substantial endowment of natural resources and covers a significant part of the Mekong River basin — almost 35% of the total inflows in the Mekong River are contributed by main tributaries throughout Laotian territory. Laos’ Ministry of Energy and Mines estimates that the country has theoretical hydroelectric potential of about 26,500 MW, excluding the mainstream Mekong. Of this, about 18,000 MW is technically exploitable, with 12,500 MW found in the major Mekong sub-basins and the remainder in minor Mekong or non-Mekong basins. Less than 5% of the country’s hydropower potential has been developed over the past 30 years, but we believe this is set to change dramatically in the coming years as Laos’ government actively courts investment through promotional policies. Moreover, Laos offers a stable social-political setting and Thailand enjoys a relatively friendly government-to-government relationship (perhaps more so than with neighbouring Cambodia, for instance).

We note that according to Thailand’s Draft PDP 2010, purchases from neighbouring countries are expected to register a CAGR of 10% over the coming 20 years — driven primarily by cross-border hydro projects — which will see this power source’s share of the overall generation mix escalate from around 6% in 2010F to roughly 19% by end-2030F.

In response to greater cross-boarder business prospects, unexciting prospects for capacity additions at home and, in contrast to the domestic situation, the absence of a return-eroding competitive bidding process, Thai IPPs have looked to partner with Laotian state-linked enterprises and international partners in greenfield coal (Ratch and Banpu) and hydro (EGCO and Ratch) projects. In 2009, Glow received approval from Laotian authorities for the acquisition of a 67.25% stake in the already operational Houay Ho from its parent.

Currently, EGCO has the largest exposure to Laos through its 25% interest in Nam Theun 2. Assuming a COD in 2010F, we estimate additional attributable hydro capacity of 272 MW. The recent acquisition of Houay Ho means that Glow has 102 MW in Laos-based hydro capacity. Ratch’s exposure to Laos also looks set to increase significantly over the coming five years, with the completion of Nam Ngum 2 (+154 MW) in 2013F and Hongsa Lignite (+751W), which is slated to achieve a COD in 2015F.

Being essentially a by-product of the cogen process, avoided cost pricing for steam sales to industrial customers offers attractive margins, in our view

Laos represents a key growth node for Thai IPPs



The company also has interests in the Num Ngum 3, Xie Pian-Xe Namnoy and Nam Bak hydro plants, although these projects still do not have signed PPAs with the EGAT.

Exhibit 216. Glow Energy’s attributable capacity and pipeline

Details Total attributable capacity (MW) Power purchase agreement details Non-power capacity

Domestic International Processed Water

(Cm/hr)

%

owned Fuel type IPP SPP/

VSPP Laos Others

Total attr.

Power capacity

COD date

Capacity under PPA with EGAT

PPA Duration

PPA expiration

date Remaining PPA years

Steam (t/hr) Clarified

Demine-ralized

Existing projects

Glow IPP 95 Gas 677 0 0 0 677 2003 677 25 2028 19 0 0 0

Glow Energy Phase 1 100 Gas 0 0 0 0 0 1994 0 na na na 250 1110 230

Glow Energy Phase 2 100 Gas 0 281 0 0 281 1996 180 21 2017 8 300 900 280

Glow Energy Phase 4 100 Gas 0 77 0 0 77 2005 0 na na na 137 600 200

Glow SPP 1 100 Gas 0 124 0 0 124 1998 110 23 2021 12 90 0 190

Glow SPP 2/3 100 Coal/Gas 0 513 0 0 513 1999/00 300 25 2024/25 15/16 190 0 150

Houay Ho Hydro 67 Hydro 0 0 102 0 102 1999 85 30 2029 20 0 0 0

Projects under construction

CFB# Coal 100 Coal 0 70 0 0 70 2010 0 na na na 140 0 0

Phase 5 Gas 100 Gas 0 342 0 0 342 2012 74 25 2037 na 120 0 0

Gheco 65 Coal 429 0 0 0 429 2011 429 25 2036 na 0 0 0

Projects under development

HHPC expansion* 67 Hydro 0 0 67 0 67 ~2015 na na na na na na na

Summary

Total existing capacity 677 995 102 0 1775 967 2610 1050

Capacity under construction 429 412 0 0 841 260 0 0

Capacity under dev. with PPA 0 0 0 0 0 0 0 0

Total growth factored into forecasts 429 412 0 0 841 260 0 0

Capacity under dev. w/o PPA (not in forecasts) 0 0 0 0 0 0 0 0

Note: * These projects are not currently factored in to our earnings estimates given lack of pricing clarity and the probability of the projects proceeding


Exhibit 217. Ratch’s attributable capacity and pipeline



(Cm/hr)

%

owned Fuel type IPP

SPP/ VSPP Laos Others

Total attr.

Power capacity COD date


PPA Duration

PPA expiration



Demine-ralized

Existing projects

Ratch. Power Plant (TH) 100 Gas 1,470 0 0 0 1,470 2000 1470 25 2025 16 0 0 0

Ratch. Power Plant (CCGT) 100 Gas 2,175 0 0 0 2,175 2001 2175 25 2026 17 0 0 0

Tri Energy Power Plant 50 Gas 350 0 0 0 350 2000 350 20 2020 11 0 0 0

Ratchaburi Power (RPCL) 25 Gas 350 0 0 0 350 2008 350 25 2033 24 0 0 0

Pratu Tao-A 100 Fl. gas 0 2 0 0 2 2007 2 5 2012 3 0 0 0


Num Ngum 2 25 Hydro 0 0 154 0 154 2013 154 25 2038 na 0 0 0


Hongsa Lignite 40 Lignite 0 0 751 0 751 2015 751 25 2040 31 0 0 0

Num Ngum 3* 25 Hydro 0 0 110 0 110 2017 na na na na 0 0 0

Xie Pian - Xe Namnoy* 25 Hydro 0 0 98 0 98 2017 na na na na 0 0 0

Nam Bak* 25 Hydro 0 0 40 0 40 2017 na na na na 0 0 0

Khao Kor Wind Farm* 30 Wind 0 18 0 0 18 2011 na na na na 0 0 0

Summary

Total existing capacity 4,345 2 0 0 4,347 0 0 0





Note: * These projects are not currently factored in to our earnings estimates given lack of pricing clarity and the probability of the projects proceeding




Exhibit 218. EGCO’s attributable capacity and pipeline



(Cm/hr)

%

owned Fuel type IPP SPP/

VSPP Laos Others

Total attr. Power

capacityCOD date


PPA Duration

PPA expiration



Demine-ralized

Existing projects

Rayong Power Plant 100 Gas 1,232 0 0 0 1,232 1994 1232 20 2014 5 0 0 0

KEGCO 1 100 Gas 70 0 0 0 70 1996 70 15 2011 2 0 0 0

KEGCO 2 100 Gas 754 0 0 0 754 1996 754 20 2016 7 0 0 0

BLCP 50 Coal 717 0 0 0 717 2006/07 717 25 2031/32 22/23 0 0 0

GEC-GPG (KK2) 50 Gas 755 0 0 0 755 2007/08 755 25 2032/33 23/24 0 0 0

EGCO Cogen 80 Gas 0 94 0 0 94 2003 48 21 2024 15 24 0 0

ROI-ET Green 70 Rice husk 0 7 0 0 7 2003 6 21 2024 15 0 0 0

GEC-GCC 50 Gas 0 55 0 0 55 1998 45 21 2019 10 8 0 0

GEC-NKCC 50 Gas 0 63 0 0 63 2000 45 21 2021 12 12 0 0

GEC-SCC 50 Gas 0 63 0 0 63 1999 45 21 2020 11 12 0 0

GEC-GYG 50 Parawood 0 12 0 0 12 2006 10 25 2031 22 0 0 0

Conal-WMPC 18 Diesel 0 0 0 19 19 1998 na 18 2016 7 0 0 0

Conal-SPPC 18 Diesel 0 0 0 10 10 1998 na 18 2016 7 0 0 0

EGCO BVI-QPL 26 Coal 0 0 0 131 131 2000 na 25 2025 16 0 0 0


Nam Theun 2 25 Hydro 0 0 272 0 272 2010 249 25 na na 0 0 0


Nam Theun 1* 48 Hydro 0 0 248 0 248 na na na na na 0 0 0

Summary

Total existing capacity 3,528 293 0 160 3,981 56 0 0





Note: * These projects are not currently factored in to our earnings estimates given lack of clarity pricing and the probability of the projects proceeding


Nuclear planned for 2020, but we are sceptical of execution According to Thailand’s existing system planning guidelines, the country hopes to add its first 1,000 MW nuclear power plant to the power system by 2020, followed by a further 1,000 MW in 2021. The Draft PDP 2010 suggests that after making an initial contribution to the generation mix in 2020, nuclear generation will see a 10-year CAGR of 18% over 2020-30, eventually accounting for 11% of Thailand’s electricity consumption needs. While there is still ample time for public relations work, given the significant social resistance faced by developers of coal-fired power plants within Thailand’s borders, we see significant execution obstacles in this regard.

Exhibit 219. Draft PDP 2010 generation mix evolution

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

Nat

ural

gas

Impo

rted

coal

Nei

ghbo

urin

gco

untr

ies

Nuc

lear

Ren

ewab

leE

nerg

y

Hyd

ro

2010 2010-2030 additions(GWh)

Source: EPPO, Glow Energy, Nomura research

Industry regulation and planning The Energy Industry Act, which came into effect on 11 December 2007, separates the regulatory process from policy formulation and electricity as well as natural gas industry operation. The new law also set provisions for the establishment of the Energy Regulatory Commission (ERC) as an independent regulatory body tasked with,

The Energy Industry Act separates the regulatory process from policy formulation and electricity as well as natural gas industry operations



amongst others, setting electricity tariffs, issuing power plant licences, inspecting industry operations and issuing regulations for the effective functioning of the industry.

The idea behind the Act is to demarcate the policy setting, regulation and monitoring, and service provision for the energy industry (including power). The National Energy Policy Council (NEPC), chaired by the prime minister, oversees the policy aspect, while the Ministry of Energy, through the Energy Policy and Planning Office (EPPO) and the ERC, looks after the regulation and monitoring of the industry. The three government enterprises, the EGAT along with the MEA and the PEA, look after the effective implementation of services as per the plans. The Department of Alternative Energy Development and Efficiency (DEDE) is tasked with promoting energy efficiency and conservation through the use of renewable energy sources.

While the ERC is not strictly independent, given that seven of the board members are elected by the Energy Ministry, its establishment does (finally) provide a single regulatory body for the industry, as was initially proposed as a critical component to the successful implementation of the Thailand Enhanced Single Buyer model. We concur with the view that having a single regulator should facilitate better integration and coordination, while also expediting any industry reforms.

Exhibit 220. Breakdown of regulatory roles

Regulation and

Agency Policy Monitoring Implementation

National Energy Policy Council (NEPC) Х

Ministry of Energy (i.e. EPPO) Х

Energy Regulatory Board (ERC) Х

Electricity Generating Authority of Thailand (EGAT) Х

Metropolitan Electricity Authority (MEA) Х

Provincial Electricity Authority (PEA) Х

Private Sector Х

Source: World Bank Thailand Infrastructure Report (2008)

Power Development Plan

Thailand’s electricity supply planning process follows essentially a two-step process. First, the Thai Load Forecasting Committee generates load forecasts to predict energy demand, and these forecasts, in turn, form the basis for a long-term Power Development Plan (PDP) that determines what centralised power plants are built and the timing of their introduction. The PDP is reviewed by the Ministry of Energy and approved by the NEPC and Council of Ministers. Plants are added subject to two criteria.

First, Thailand aims to maintain a minimum reserve margin of 15% (note: the PDP defined reserve margin as capacity in excess of annual peak demand as a proportion of capacity, whereas popular convention is for this ratio to be expressed as a percentage of peak demand), with capacity restricted to what EGAT deems dependable. Non-dependable capacity includes a certain proportion of hydro capacity since the availability of these plants varies significantly in the dry season and from year to year.

Second is the loss of load probability (LOLP) — a measure of the probability that system demand will exceed capacity during a given period — should not exceed an hour per year (ie, every place in the country should have sufficient generation and transmission to have power 99.99% of the time).

The current PDP 2007 has been revised twice since its release in light of weaker-than-anticipated demand growth. An entirely new PDP is scheduled to be released by end-2010.

We concur with the view that having a single regulator should facilitate better integration and coordination, while also expediting any industry reforms

The Power Development Plan determines what power plants are built and the timing thereof. An entirely new PDP is scheduled to be released by end-2010



Asia ex Japan

The Philippines Daniel Raats +852 2252 2197 / [email protected]


Geothermal and hydro — 34% of generating mix In the Philippines, the harnessing and utilisation of renewable energy (RE) comprises a critical component of the government's strategy to provide energy supply for the country. This is evident in the power sector, where increased generation from geothermal and hydro resources has lessened the country's dependence on imported and polluting fuels. According to statistics provided by the DOE, in 2008, geothermal (18%) and hydroelectric (16%) energy combined accounted for 34% of the Philippines’ generating mix. Renewable energy sources such as solar, micro-hydro, wind and biomass are also seeing widescale use in the government's rural electrification efforts.

Exhibit 221. The Philippines: generation by fuel source (2008)

Hydro16%

Diesel 6%

Wind and solar0%

Oil 1%

Coal26%

Natural Gas32%

Geothermal

18%

Gas Turbines

0%

Combined cycle 1%

Oil based8%

Source: DOE, Nomura research

Exhibit 222. The Philippines: capacity by fuel source (2008)

Oil based21%

Solar0%

Wind0%

Coal 25%

Natural gas20%

Geothermal11%

Hydro23%


Pro-renewable government policies The government's policy aims to facilitate the energy sector's transition to a sustainable system with RE as an increasingly prominent, viable and competitive fuel option. The shift from fossil fuel sources to renewable forms of energy is a key strategy in ensuring the success of this transition. Current initiatives in the pursuit of this policy are directed towards creating a market-based environment that is conducive to private sector investment and participation, and one that encourages technology transfer and research and development. To this end, current fiscal incentives provide for a preferential bias to RE technologies and to projects that are environment friendly.

Based on current DOE projections, renewable energy is expected to provide up to 40% of the country's primary energy requirements by end-2013. As an aggressive move to promote RE development and use, the DOE has identified long-term goals, namely: 1) to increase RE-based capacity by 100% by 2013; and 2) to increase the non-power contribution of RE to the energy mix by 10mn barrels of fuel oil equivalent (MMBFOE) in the next 10 years. In support of these general goals, the government aims to be the number one geothermal energy producer in the world; be the number one wind energy producer in Southeast Asia; double hydro capacity by 2013 and expand the contribution of biomass, solar and ocean waves by about 131 MW.

The Renewable Energy Act of 2008 became effective on 30 January, 2009 and provides a strategic alternative to fossil fuels that is aimed at fostering sustainable growth, a cleaner environment, energy independence and security for the country

Harnessing renewable energy is a crucial component of the government’s policy to diversify the Philippines’ energy mix

Passing of the RE Act not only creates value for existing operating assets, but enhances the viability of projects in the pipeline as well

To promote private sector investment and participation, current fiscal incentives favour RE technologies and projects



through the development and utilisation of renewable and indigenous energy resources. The act institutionalised both fiscal (a seven-year tax holiday, after which a tax rate of 10% applies; net operating loss carry-over for the first three years from the start of commercial operation; accelerated depreciation; tax- and duty-free import of machinery and equipment; 0% VAT on the sale of fuel or power generated from renewable energy sources; tax-exempt sale of carbon emission credits) and non-fiscal (renewable portfolio standard and priority dispatch) incentives to sustain existing and attract new investment.

Exhibit 223. The Philippines: salient features of the Renewable Energy Act (I)

Pre-RE Act legislation RE Act

Income tax holiday BOI registration 6 years ITH under pioneer status 4 years ITH under non-pioneer status Plus one extra bonus year

7 years ITH from commercial operations

Government share Steam – 60% of gross value Hydro – Share of LGUs-National Wealth (1% of gross receipts)

Steam – 1.5% of gross income Others – 1% of gross income Existing projects covered by change in government share

Importation of materials/ equipment

0% duties for 3-5 years (on BOI’s discretion)

0% duties for 10 years (on registration)

Net operating loss carry-over 3 years 7 years

Realty tax rate 2% (cities) and 1% (provinces) of assessed values; 1% of assessed values for SEF

1.5% of net book value; integrated development and generation facility taxed only on the power plant component

Corporate income tax rate (after ITH period)

30% 10%

VAT on sale of power generated from RE

0% 0%

Tax on carbon credits 30% income tax and 0% VAT Tax exempt

Others Other BOI incentives: Additional 50% deductible wages for the

first 5 years of operation

Applications for accelerated depreciation Cash incentive for missionary electrification Tax credit on domestic capital equipment and services

Market incentives: Creation of renewable energy market to implement minimum

percentage of generations from RE sources (Renewable Portfolio Standards)

Direct contraction by RE facilities with end users for supply of power (Green Energy Option)

Source: EDC, DOE, Nomura research



Exhibit 224. The Philippines: salient features of the RE Act (II)

Source: DOE, Aboitiz Power, Nomura research

Feed-in tariffs under discussion The government has dangled another incentive for potential investors in the RE field that would allow them to charge slightly higher tariff rates for the production of energy from renewable or alternative raw materials. According to Marriz Agbon, president of the Philippine Agricultural Development and Commercial Corp (PADCC), the Renewable Energy Board has applied with the Energy Regulatory Commission (ERC) for a feed-in tariff for biofuels. The feed-in tariff, Agbon said, would be in addition to the regular generating cost of power generating firms. Thus, a firm generating power, for example from biomass or biofuel, could charge an additional feed-in tariff based on the renewable material the firm is using. The National Renewable Energy Board, created by the RE Act, is coming up with its proposal for the feed-in-tariff (FIT) rules to the ERC. The tariff incentive is likely to be implemented within the year.

Philippines geothermal

A major player in geothermal production

The Philippines has the second-largest geothermal installed capacity in the world, with 1,958MW as at end-2008, according to disclosure by the DOE. This is roughly 12% of the country’s aggregate 2008 installed capacity of 15,680MW (and about 22.6% of the Philippines’ 2008 dependable capacity of 13,049MW). Based on data from the World Geothermal Congress (2005), the Philippines accounted for approximately 21% of the world’s entire geothermal production capacity.

In 2005, the Philippines accounted for 21% of global geothermal installed capacity

Feed-in tariff expected to be finalised by end-2010F



Exhibit 225. Geothermal capacity by country (1995, 2000, 2005)

0

500

1,000

1,500

2,000

2,500

3,000

US

A

Phi

lippi

nes

Mex

ico

Indo

nesi

a

Ital

y

Japa

n

New

Zea

land

Icel

and

Cos

taR

ica

El

Sal

vado

r

1995 2000 2005(MW)

Source: Geothermal Energy Forum, Nomura research

Exhibit 226. Global installed geothermal capacity (2005)

USA27%

Philippines21%Mexico

11%

Indonesia9%

Italy9%

Japan6%

New Zealand

5%

Other12%

Source: Geothermal Energy Forum, Nomura research

In terms of the generating mix, in 2008, geothermal energy accounted for roughly 18% of the Philippines’ aggregate electricity production. In terms of different grids, while Luzon’s generating mix is dominated by fossil fuels (geothermal energy accounts for only 8% of Luzon’s generating mix), geothermal energy dominates the generating mix in Visayas in the central Philippines (72% of the mix).

Exhibit 227. The Philippines: generating mix by fuel type (2008)

Geothermal

18%

Natural Gas32%

Coal26%

Wind and solar0%

Oil -based 8%

Hydro16%


Ample scope for geothermal growth in the Philippines

The Philippines is located within the so-called Pacific Ring of Fire – an area encircling the Pacific Ocean and parts of the Indian Ocean where active earthquakes and volcanoes are concentrated along tectonic plate boundaries. Most of the world’s richest geothermal sources are located within the area. As a result, the Philippines is endowed with significant geothermal potential, which the DOE has estimated at 4,500MW, of which only 1,958MW was being utilised as at end-2008, according to the DOE’s disclosure.

The DOE aims to step up geothermal energy utilisation significantly over the next five years by some 1,000MW, which equates to a further 51% on the country’s existing installed geothermal generation capacity and would, by our calculations, elevate the Philippines to the world’s number one geothermal energy producer.

In this regard, according to a Reuters article dated 6 November, 2009, the Philippine government aims to approve 19 new contracts to explore and develop the country's geothermal energy resources over the coming five months, which could attract more

Geothermal energy accounts for 18% of the generating mix, and dominates the generating mix in Visayas

The DOE estimates that the Philippines has geothermal potential of around 4,500MW

Government aims to approve 19 new contracts to explore and develop the country’s geothermal energy resources in the coming five months



than US$2.5bn in private investment from both domestic and foreign entities. According to the report, the government has issued tenders for the development of 10 geothermal sites and negotiated nine more deals directly with various companies; combined, the exploration areas could harness more than 620MW of geothermal energy.

Exhibit 228. World pattern of plates, oceanic ridges, oceanic trenches, subduction zones, and geoth. fields

Note: Arrows show the direction of movement of the plates towards the subduction zones. (1) Geothermal fields producing electricity; (2) mid-oceanic ridges crossed by transform faults (long transversal fractures) and (3) subduction zones, where the subducting plate bends downwards and melts in the asthenosphere

Source: Geothermal-energy.org

Philippines



Exhibit 229. The Philippines: geothermal production areas (2005)

Source: DOE

For the 10 geothermal sites earmarked to be allocated through competitive bidding, the DOE set a deadline for the submission of proposals of 27 November, 2009, and is currently evaluating the proposals based on scores weighted according to technical (30%), financial (30%) and work programme (40%) merits. We note EDC has submitted bids for four geothermal exploration zones, and based on our discussions with management, we understand that EDC will also be negotiating directly with the government for exploration contracts in the ‘frontier zone.’

Given EDC’s status as a global leader in geothermal energy production, with expertise throughout the geothermal value chain, we see appreciable scope for EDC to further expand its geothermal energy capacity base over the medium term.

Exhibit 230. The Philippines: details of, and qualifying bids for, the 10 geothermal exploration areas

Daklan, Benguet Natib, Bataan

Labo, Camarines Norte

Acupan, Benguet

Montelago, Oriental Mindoro

Isarog, Camarines Sur

Sta. Lourdes Tagburos, Puerto Pincesa City, Palawan

Mainit, Surigao del Norte

Maibarara in Laguna and Batangas

Area (hectares)

23,639 11,929 9,324 18,408 4,033 16,279 1,600 37,691 1,600

Pre-qualified bidders

Clean Rock Renewable Energy Resources Corp

Clean Rock Renewable Energy Resources Corp

PNOC Renewables Corp

Primary Energy

Constellation Energy Corp

PNOC Renewables

Primary Energy

Energy Development Corp

Petro Energy Resources Corp

Pan Pacific Power Corp

Pan Pacific Power Corp

Aragorn Power and Energy Corp




Envent Holdings

Magma Energy Corp

Envent Holdings

Winning bid TBA TBA TBA TBA TBA TBA TBA TBA TBA

Source: Assorted press, Manila Standard Today, Nomura research

Geothermal production areas in the Philippines

EDC has submitted bids for four of 10 geothermal exploration zones



Philippines hydro electric

Positive on hydroelectric potential

Rising hydrocarbon fuel prices, intensifying global environmental awareness, and the Philippines’ RE Bill, in our view, further accentuate the marginal cash cost advantage that hydropower has relative to competing fuel sources. In our view, this will accelerate exploitation of the Philippines’ significant hydroelectric resources. We believe EDC and Aboitiz in particular are well placed to benefit from increased hydroelectric utilisation over the medium term, which should underpin earnings and valuations.

Significant untapped hydro capacity

According to the DOE, the Philippines has more than 13,000MW in untapped hydropower resource potential, of which 85% is considered large and small hydros (>10MW), 14% is classified as mini-hydro (101kw-10MW) and less than 1% is classified as micro-hydro (1kW-100kW).

Given the low level of current hydroelectric resource utilisation (<3.3GW at end-2008) and pro-renewable fiscal and non-fiscal government policies introduced pursuant to the RE Act, we see significant scope for further organic growth in this area over the medium term, which we believe could drive earnings and valuations for the listed Filipino IPPs under our coverage.

Factoring in the acquisition of the Magat and Ambuklao-Binga hydroelectric power plants, Aboitiz Power is the largest Filipino-owned private sector company in hydroelectric power generation in terms of installed capacity (c.341MW, which equates to roughly 18% of its attributable capacity, including Pagbilao and PB117/118), and with extensive experience in all things hydro, we believe the company is in an excellent position to capture future market share and benefit from what promises to be significant growth in the Philippines’ hydroelectric power utilisation.

Despite being a predominantly geothermal power producer, following its entry into hydroelectric power generation through the acquisition of a 60% interest in Pantabangan-Masiway hydroelectric complex (112MW, roughly 6% of its attributable capacity), EDC has also articulated ambitions to pursue hydroelectric growth opportunities as the group looks to build out its exclusive RE-based power generation portfolio.

Exhibit 231. Aboitiz Power: attributable capacity breakdown by fuel type (9M09)

Oil/Diesel18%

Geothermal24%

Coal40%

Hydro18%

462 MW

341 MW

779 MW

358 MW

Note: Factors in Pagbilao and PB117/118


According to the DOE, the Philippines has more than 13,000MW in untapped hydroelectric power potential

Hydro accounts for 18% of Aboitiz Power’s installed power generation capacity



Exhibit 232. The Philippines: Installed capacity by fuel type (2008)

Hydro21%

Geothermal

12% Natural Gas18%

Coal28%

Non convl0%

Diesel/Oil21%

Source: Source: DOE, Nomura research

Exhibit 233. The Philippines: breakdown of installed capacity

(MW) 2003 2004 2005 2006 2007 2008

Coal 3,958 3,967 3,967 4,177 4,213 4,213

Diesel/Oil 3,604 3,669 3,663 3,602 3,616 3,353

Natural Gas 2,763 2,763 2,763 2,763 2,834 2,831

Geothermal 1,932 1,932 1,978 1,978 1,958 1,958

Hydro 2,867 3,217 3,222 3,257 3,289 3,291

Non conventional - - 26 26 26 34

Total 15,124 15,548 15,619 15,803 15,936 15,680


Impounding hydro allows generators to target peak times

Impounding hydroelectric power plants, such as Aboitiz’s Magat and Ambuklao – Binga facilities, which have the ability to store water for use in generating electricity, allows generators the flexibility to target peak hours of the day and periods of favourable spot market prices and defer generation in times when spot rates are unfavourable. According to Aboitiz, Magat (attributable capacity: 180MW) can store sufficient water to support one month’s worth of generation, while the company’s other merchant facility, Ambuklao – Binga (attributable capacity: 88MW), has two weeks of storage capacity.

No marginal cash cost, downside protection

In addition, hydroelectric power plants have no fuel costs and thus have very limited marginal operating costs. Gencos’ hydroelectric power plants can therefore sell at prices below the marginal fuel costs of fossil fuel-fired plants and still generate cashflow. Where the ability to store water offers merchant hydroelectric power plants upside through targeting peak hours and periods of favourable spot rates, gencos with merchant hydroelectric capacity are also afforded downside protection in the form of price floors defined by the marginal cost of fossil fuel-fired plants.

Tropical climate, diversified portfolio mitigates hydrology risk

In years of less favourable hydrological conditions, such as when there are droughts, merchant hydro plants face volume constraints, while gencos with power purchase agreements (PPAs) could potentially incur penalties should they be unable to satisfy take-or-pay conditions. However, since the Philippines has a tropical climate, it has regular seasonal rainfall patterns, which combined with a geographically diversified hydroelectric power generation portfolio, in our view, goes a long way towards mitigating risks associated with adverse hydrological conditions.

Impounding hydroelectric power plants affords gencos the opportunity to target peak times and favourable spot rates

Merchant hydroelectric facilities have downside protection through low marginal costs and price floors defined by the marginal cost of fossil fuel-fired plants

Hydrological risks are mitigated by geographic diversification and the Philippines’ tropical climate



Seasonality and location have a direct bearing on precipitation levels. In Luzon, where the rainy and summer seasons are more pronounced, higher rainfall is normally experienced over the months of June to September, and as a result, hydropower plants located in Luzon operate at their maximum capacity over this period. In contrast, in Mindanao, hydropower plants experience well-distributed rainfall over the duration of the year, with a modestly higher level of precipitation over the months of December until April. This seasonality in rainfall has a significant impact on the utilisation of run-of-river hydroelectric power plants such as Aboitiz’s Hydro Electric Development Corporation, COR (38 MW, wholly owned) and Luzon Hydro Corporation, LHC (70 MW, 50%-owned) since these plants do not have the means to impound water.

Relationship between rainfall and tariffs insulates margins

There has historically been an inverse relationship between rainfall and spot prices. In times of high rainfall, prices of electricity drop as expensive fossil fuel supply is displaced by cheaper hydroelectric capacity, while the converse is true during times of drought. As a result, while gencos with merchant hydro capacity may see volumes decline during periods of low rainfall, this is partially offset by a more favourable pricing environment owing to supply served by more expensive fossil fuel-fired plants – a dynamic that introduces an attractive hedge to hydroelectric gencos’ EBITDA.

Philippines nuclear power

Nuclear power under consideration

Nuclear energy is somewhat of an exposed nerve in the Philippines after the country’s first attempt at building a nuclear power plant remains as the biggest white elephant in its history and is seen by many as symbol of corruption and cronyism in the Philippines.

During the first oil price shock in the early 1970s, the Philippine government under President Ferdinand Marcos decided to construct a nuclear power plant in Bataan, North of Manila on the Island of Luzon to support the country’s ambition to become an industrial hub in the region at a cost of more than US$2.3bn. From the very beginning, the nuclear plant undertaking was politicised. Marcos awarded the project to a losing bidder and his contacts were awarded many of the subcontracts for the project.

Contrary to the positive findings of a government-commissioned safety and technical study conducted in 1992, the design of the Yogoslav power plant was not applicable to the humidity and geographical conditions in the Philippines, while the location for the plant was chosen less than 10km from an active volcano, and was also within 25 miles of three geological faults.

An independent inspection conducted by several technical experts discovered that the reactor had 200 defects, and safety issues were also raised by the Philippine Atomic Energy Commission about the damaged containment structure, unshielded electric cables and faulty steam generator. In 1990, another independent study pointed out the structural weaknesses of the plant, mentioning deficiencies in the component cooling system, quality assurance programme and emergency power system.

When Marcos was ousted from power in 1986, the nuclear plant was not yet finished. The succeeding government of Corazon Aquino mothballed the plant because of strong local opposition, and to date, the plant has yet to produce a single Kwh of electricity.

In late 2008, faced with a looming power shortage and high fuel prices, the debate to revive the Bataan Nuclear Power Plant resurfaced, after Korea’s Kepco reportedly expressed interest in operating the plant – although there is currently little clarity over whether this is feasible or not.

On 10 May, 2010, The Philippines Star, quoting Energy Secretary Jose Ibazeta, reported that Mindanao could be the best site for a nuclear power facility, since it is close to Indonesia and Malaysia, which means the Philippines may be in a position to

An inverse relationship between rainfall and spot market tariffs insulates EBTIDA

Nuclear energy is a sensitive issue in the Philippines after Bataan turned out to be the biggest white elephant in the country’s history

However, faced with mounting power shortages, there has been talk of potentially reviving the project more than 30 years after its initial inception



export power. At the same time, the new facility would serve to boost the local economy, where power shortages have been a key constraint to growth.

The national government had earlier identified more than 10 potential sites for the country’s first nuclear power plant. In a related development, Napocor president Froilan Tampinco said a communication plan is already being drawn up in preparation for comprehensive nuclear power development for the country. Tampinco said an inter-agency group created to study the option of using nuclear as an alternative source of power for the Philippines, is now looking into all aspects of nuclear energy development. The Napocor chief earlier said it would be wise for the Philippines to consider medium-sized nuclear power facilities with capacity of 400-600MW.

The national government has also identified more than 10 alternative sights for the Philippines’ first nuclear power plant



Asia-ex Japan

Indonesia Daniel Raats +852 2252 2197 / [email protected]


A major geothermal growth node An active volcanic belt in Indonesia, measuring 7,000km in length and 50-200km in width, distributes geothermal energy resources along the volcanic lines of Sumatra, Java, Bali, West Nusa Tenggara, Northern Sulawesi and Maluku — most of which are located at the base or old caldera area of volcanoes. The Indonesian government has estimated that the country may have as much as 27,670MW (c.40% of estimated global geothermal resources) in geothermal energy resources, of which less than 4% is currently being utilised. Geothermal energy accounts for only c.1% of Indonesia’s primary energy mix (excluding biomass), which is dominated by oil (45%), coal (32%) and natural gas (19%). In 2008, hydropower accounted for 5% of the ex-biomass primary energy mix.

Exhibit 234. Indonesia: geothermal resources and reserves

Source: Indonesian Institute for Energy Economics, Statistics Geothermal Business Indonesia 2008, Nomura research

Exhibit 235. Indonesia: geothermal resources and reserves (2008)

Source: Statistics Geothermal Business Indonesia 2008, Nomura research

Currently less than 4% of Indonesia’s c.27,670MW of geothermal capacity is being utilised

13,334M

9,656MW

45MW

1,757MW

2,094MW

734MW

50MW

Reserves 13,103MW

Resources 14,567MW

Resources and reserves

Proven 2,288MW

Possible 1,050MW

Probable 11,229MW

Reserves

Indonesia has probable (11,229MW), possible (1,050MW) and proven (2,288MW) geothermal reserves of 13,103MW



Exhibit 236. Indonesia: geothermal resources and reserves

Resources Reserves

Location Speculative Hypothetical Probable Possible Proven Total

Sumatera 5,000 2,194 5,745 15 380 13,334

Jawa 1,960 1,771 3,225 885 1,815 9,656

Bali-Nusa Tenggara 410 359 973 - 15 1,757

Sulawesi 875 32 959 150 78 2,094

Maluku 370 37 327 - - 734

Kalimantan 45 - - - - 45

Papua 50 - - - - 50

Total 8,710 4,393 11,229 1,050 2,288 27,670 Source: Statistics Geothermal Business Indonesia 2008

Geothermal energy utilisation is poised to increase drastically, in our view. Higher and volatile oil prices, surging power demand and creaking infrastructure in the power sector have greatly enhanced the sense of urgency within Indonesia to exploit its alternative fuel sources — especially the country’s significant geothermal energy potential. The country’s long-term energy blueprint, as articulated by Presidential Decree No 5/2006, outlines the government’s plans to increase the share of geothermal energy in Indonesia’s overall primary energy mix to about 5% by 2025, along with nearly doubling the country’s installed geothermal power generation capacity to c.9500MW. This equates to roughly 30% of the additional 30,000MW of power capacity the government has targeted for development over this period.

In our view, such targeted high growth represents huge potential for both geothermal project developers and equipment manufacturers (such as Toshiba, Fuji, Mitsubishi, Ansaldo Energy, among others). Indonesian energy firms like Medco Energi Internasional and Star Energy are exploring possibilities for making new investments, while international energy giant Chevron has voiced its intention to double its existing geothermal operations in Indonesia (from roughly 630MW currently, according to company disclosure). Similarly, the Philippines-based EDC has stepped up its business development efforts in Indonesia and aims to leverage the technical expertise gained in its local market to secure both geothermal resource extraction and conversion contracts, most likely through JV agreements with local firms, we believe. The company has set up a Jakarta office and is in the exploratory stage, according to management.

Exhibit 237. Indonesia: existing and targeted primary fuel mix

Note: The 2008 primary fuel mix excludes biomass, which accounted for c.17.6% of the aggregate primary fuel mix

Source: Presidential Decree No.5/2006, Nomura research

Natural gas (LPG and LNG)

19%

Coal32%

Geothermal1%

Hydro5%

Crude oil and fuel45%

2008 primary fuel mix

Biofuels5%

Geothermal5%

Liquif ied coal2%

Other RE5%

Other17%Coal

33%

Crude oil and fuel20%

Natural gas (LPG and LNG)30%

2025 targeted primary fuel mix

By 2025, almost 30% of an additional 30,000MW planned capacity may rely on geothermal energy

The government’s energy plans harbour significant growth potential for geothermal project developers and equipment manufacturers, in our view



Exhibit 238. Indonesia: non-fossil fuel resources and utilisation (2007)

Types Resources Equivalent value Existing utilisation

Hydro 845.00 juta BOE 75.67GW 4.2GW

Geothermal 219.00 juta BOE 27.00GW 0.8GW

Mini/Micro Hydro 0.45GW 0.45GW 0.084GW

Biomass 49.81GW 49.81GW 0.3GW

Solar - 4.80 kWh/m2/day 0.008GW

Wind 9.29GW 9.29GW 0.0005GW

Uranium 24.112 ton* e.q. 3GW for 11 years - -

Note: * Resources only exist in Kalan region – West Kalimantan

Source: Indonesian Institute for Energy Economics, Nomura research

Exhibit 239. Indonesia: installed generating capacity by fuel type

Year Hydro Steam Gas Combined gas-steam Geothermal Diesel Combined oil-gas Wind Total

2000 4,199 11,117 3,805 6,863 525 11,223 - - 37,733

2001 3,113 7,946 1,973 6,998 785 3,016 - - 23,831

2002 3,155 6,900 1,225 6,863 785 2,589 - - 21,517

2003 3,170 9,574 1,225 7,148 785 2,879 - - 24,781

2004 3,199 10,865 2,340 6,846 800 3,277 12 - 27,339

2005 3,221 10,865 2,724 6,716 800 3,326 12 - 27,663

2006 3,532 12,990 2,727 7,895 800 3,001 12 - 30,958

2007 3,529 13,244 2,727 7,845 1,043 3,016 12 0 31,416

2008 3,510 12,014 3,453 7,306 933 3,070 12 0 30,298


Exhibit 240. Indonesia: installed generating capacity by fuel type (2008)

Steam40%

Gas11%

Combined gas-steam

24%

Geothermal3%

Diesel10%

Combined oil-gas

0%Wind0%

Hydro12%


Exhibit 241. Indonesia: electricity generated by fuel type (2007)

Steam gas23%

Geothermal2%

Gas turbines

3%

Water8%

Steam34%

Diesel7%

Purchased23%

Source: CEIC, Nomura research



Exhibit 242. Indonesia: total electrification percentage

52.0% 52.1% 52.5% 53.0%

53.4%

64.3%

62.1% 63.0%

45%

50%

55%

60%

65%

70%

2000 2001 2002 2003 2004 2005 2006 2007

Source: Key Indicators of Indonesia Energy and Mineral Resources (2008), Nomura research

Geothermal plants to account for 48% of the second 10,000MW plan

Indonesia’s power supply market is currently characterised by a chronic supply shortage, underpinning frequent and extended blackouts and, in the eyes of government, acting as a key constraint to what appears to be significant economic growth potential. In response, the government launched the first 10,000MW ‘crash power project’ in 2006 in a bid to anticipate increasing electricity demand, which has been growing in excess of 7% annually.

In the planning stage, the second 10,000MW crash programme, which unlike the entirely coal-fired first accelerated programme, is open to private sector participation and diversified across geothermal (48%), coal (26%) natural gas (14%) and hydro (12%). It is scheduled to be implemented between 2010 and 2014. In a presentation in August 2009 (according to Jakarta Post), PT Perusahaan Listrik Negara (PLN) said the projects under the programme were expected to generate a total electricity capacity of 10,580MW (of which 5,685MW would be located in Java with the remaining 4,895MW outside Java) at a total projected cost of roughly US$10bn.

According to a recent Jakarta Post article (27 January, 2010), however, Indonesia has revised the planned capacity for geothermal-fired power plants under the second 10,000MW crash programme down by about 700MW, as some of the initially proposed projects cannot be finished within the programme’s time frame. The government initially planned to produce as much as 4,733MW under the second 10,000MW power programme from geothermal power. In its latest report, state power utility PLN said the electricity supply to be generated from geothermal energy would be reduced to 3,975-4,077MW.

Exhibit 243. Indonesia: fuel mix of second 10,000MW crash programme

Geothermal48%

Gas14%

Coal26%

Hydro12%

Source: Jakarta Post, PLN, Nomura research

…and geothermal plants are to account for 48% of new capacity

The second 10,000MW accelerated plan is scheduled to be implemented between 2010 and 2014…

Indonesia’s government has set a target of achieving 95% electrification by 2020 – geothermal energy will play a crucial role, in our view



Europe

Europe renewable energy Catharina Saponar, CFA +44 20 710 21231 / [email protected]

Europe is where renewable energy started, and the region still accounts for the largest portion of global installed capacity.

Exhibit 244. Global renewable energy capacity

0

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ld

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(GW) Ocean (Tidal) power

CSP

Geothermal power

Solar PV, Grid-connected

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Geothermal power

Solar PV, Grid-connected

Biomass power

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Wind power

Source: REN 21

Exhibit 245. EU 27 share of renewables capacity

0102030405060708090

100

Win

d P

ow

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0102030405060708090

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(Tid

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ew

abl

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pac

ity

EU 27 RoW(%)

Source: REN 21

We see the key investment themes as:

End market demand growth within Europe for the global renewable energy sector;

The changing nature of Europe as a manufacturing and technology location in the broader global sector context; and

Renewable energy as a challenge and opportunity for other sectors beyond renewable energy.

Investment thesis and stock picks Wacker Chemie (WCH GR, BUY, PT: €145) and Vestas (VWS DC, BUY, PT:

DKK390) are our top picks.

We expect strong solar end markets, but prefer exposure to the upstream and downstream parts of the value chain, while avoiding the cell and module ends. We see equipment manufacturers as long-term beneficiaries.

Wind turbine manufacturers will likely see an order recovery in 2010F and thus return onto a trajectory of outperformance.

We believe the wind sector is characterised by a challenging macro environment, mainly due to US exposure. However, we look for the European names to outperform once demand recovers. In contrast, we prefer a more selective stance on the European names with regards to the greatly improved macro backdrop in solar.

Wind

In the wind sector, we see stable rates of installation in Europe. Over time, however, we expect Asia and the US to overtake Europe. While there is competition at the manufacturing end, we believe that European manufacturers have sustainable competitive advantages from technology and quality, as well as relationships with the largest global developers. It is also worth noting that wind turbine manufacturing tends to require factories close to the end markets due to high transport costs.

Largest renewables region

Top picks: Wacker and Vestas



The turbine manufacturers are our preferred picks as we see them benefiting from: 1) a market leadership position; 2) high-end technology that enables low loce (cost of energy); and 3) broad geographic exposure to global growth with an increasing presence in Asia. Vestas (VWS DC, BUY, PT: DKK390) is our top pick.

Developers’ valuations appear attractive as current share prices on average reflect only assets in the ground and under construction. But high exposure to the weak PPA situation on the US may lead to risks to execution on capacity growth targets. This could present share overhang until later in 2010F. IBR (IBR SM, REDUCE, PT: €3.60) and EDF EN (EEN FP, NEUTRAL, PT: €39.00) are our key wind names.

Solar

The solar sector is characterised by strong end market growth but with intense competition, ASP pressure, manufacturing dislocation and a fast innovation cycle.

In our view, Tier-1 European poly manufacturers stand to benefit from global solar end market volumes translating into poly volume growth. They also boast sustainable competitive advantages in a business with high barriers to entry. This, we believe, comes from their solid track records, higher quality grade, contracts with prepayments and lower manufacturing costs attributable to the advantage of having experience. Our preferred pick is Wacker Chemie (WCH GR BUY, PT: €145.00). We also look for a re-rating of REC (REC NO, BUY, PT: NOK30) on the back of the ongoing turnaround across its poly, wafer and module operations.

Within the wafer segment, we see Asian manufacturers benefiting from material cost advantages. Renesola (SOLA LN, BUY, PT: GBp250) should thus benefit from the cost advantages of its manufacturing in China. We also think that PV Crystalox (PVCS LN, BUY, PT: GBp78) is well positioned, with the added benefit of selling into the premium Japanese market.

At the cell and module level, the European names are challenged, in our view. Europe is likely to remain a premium market compared to other regions, namely Asia and the US. This should sustain higher-than-average price premiums for European high-end manufacturers. But the premium end appears to be getting more crowded as the industry moves towards a new quest for brand equity in recognition of the premium features preferred by European consumers. In particular, Chinese Tier-1 manufacturers are successfully increasing brand recognition and acceptance. As a result, we see the price premium for European manufacturers eroding. We expect ongoing margin pressure despite companies making strides in cost reduction in order to improve competitiveness vis a vis lower-cost Asian manufacturers. We see Solarworld (SWV GR, REDUCE, PT: €9.00) as a likely survivor at the high end, but expect pressure on profitability. Q-Cells (QCE GR, REDUCE, PT: €6.00) is taking steps to improve profitability but still faces major strategic challenges from a business model that is highly exposed to the commoditised cell segment.

We see European equipment manufacturers as potential winners from the reshaping of the sector. With a traditional engineering, technology and quality focus, we view the segment as an enabler for the manufacturing industry in achieving technology advances and cost reductions. Demand growth driving expansion and the need for innovation driving upgrades and replacements should translate into strong order flow. Centrotherm (CTN GR, BUY, PT: €40.00) appears well positioned, with a strong high-end product portfolio. We also see SMA (S92 GR, BUY, PT: €125.00) as a direct beneficiary of end market growth, given its manufacturer agnostic inverter business which is leveraged to end market demand.



Drivers of renewables build out We believe the EU 20-20-20 targets and subsidy schemes are the most important

drivers for renewables growth.

An increasingly carbon-constrained world favours renewables on a large scale, while small-scale development comes on the back of strong financial returns.

EU renewables policy and regulation

EU and national renewables targets and incentives will remain the most important drivers of renewables capacity build out, in our view. The EU has in place mandatory targets for renewables both on an EU-wide level and on a national level. At the EU level, the target is for 20% of energy production from renewables by 2020 (the “20-20-20 target”). This is translated into specific country targets.

Exhibit 246. EU renewables targets

(0.3) (0.2) (0.1) 0.0 0.1 0.2 0.3 0.4 0.5 0.6

Belgium

Bulgaria

Czech Republic

Denmark

Germany

Estonia

Ireland

Greece

Spain

France

Italy

Cyprus

Latvia

Lithuania

Luxembourg

Hungary

Malta

Netherlands

Austria

Poland

Portugal

Romania

Slovenia

Slovakia

Finland

Sweden

United Kingdom

Reduction targets in sectors not covered by the EU ETS compared to 2005

Share of renewables in final energy demand 2020

Share of energy from renewable sources in final consumption of energy. 2005

Source: EU Commission



Exhibit 247. Investment cases of key European names

Stock Ticker Rating Price target Investment points

Wacker Chemie WCHG DE / WCH GR Buy €145 Market leading Tier-1 poly manufacturer with sustained price, quality, cost and execution advantage

REC REC NO / REC OL Buy NOK 30 Tier-1 poly manufacturer. The current share price weakness reflects negative sentiment on wafer prices and execution of the company's capacity build. We see this as a buying opportunity as long-term growth prospects should return to focus later in the year

PV Crystalox PVCS LN / PVCS L Buy GBp 78 As a low-cost, high-quality wafer manufacturer with outsourced production, PV Crystalox should hold near-term profitability as we expect it to pass through pricing pressure. This positions the company to benefit from long-term growth with high profitability

Renesola SOLA LN / SOLA L Buy GBp 250 We think that Renesola has a superior business model, with low-cost China-based wafer manufacturing, coupled with in-house poly production and increasing vertical integration through module manufacturing. With this comes an intriguing strategy that pursues manufacturing white labelling for European manufacturers which could be anticipating where the sector might head over the long term. We recognize high execution risk as a new entrant, but the growth prospects imply strong upside.

Q-Cells QCE GR / QCEG DE Reduce €6 We are concerned that the company will be left out of the recovery as the impact of its restructuring will come too late and many questions relating to the business model remain open

Solarworld SWV GR / SWVG.DE Reduce €9 We think that the company is one of the few likely survivors, but we are concerned over long-term profitability. We are not tempted by the current share price level, but recognise that the stock may trade as a benchmark for the sector

Conergy CGY GR / CGYG DE Reduce €0.5 We see little barriers to entry in the company's installation and wholesale business, and the manufacturing business appears to be lacking in terms of competitiveness. With substantial balance sheet issues and being in breach of its banking covenants, the company's survival depends on its ability to negotiate further covenants and a refinancing. Its major shareholder who is also an underwriter of the main financing facility is looking to sell. Takeover speculation could continue.

Solon SOO1 GR / SOOG DE Reduce €4.50 Despite growth prospects, the company's business model of module manufacturing and solar park development is undifferentiated and constrained by a tight balance sheet. This might limit its ability to build up strength in some of the downstream areas where it is attractively positioned. We forecast it will take well into this year to return to profitability despite the attractive sector backdrop.

Solar Millennium S2M GR / S2MG DE Buy €45 On our bullish expectations for solar thermal, we like Solar Millennium as a pure play

Abengoa ABG SM / ABG MC Neutral €25 We see the growth prospects from new solar thermal capacity and biofuel plants as reflected in the current share price

Centrotherm CTN GR / CTNG.DE Buy €40 Centrotherm stands out in the equipment sector as one of the few companies with growth and with the highest quality orderbook. We expect the company’s market leading products to support further order momentum this year

Roth & Rau R8R GR / R8RG.DE Neutral €27 Roth and Rau could be a late recovery name with its focus on single equipment by large manufacturers which we think will pick up this year

Manz Automation M5Z GR / M5GG.DE Reduce €38 We think the share price is discounting too much optimism on a 2010F recovery and future growth potential from lithium ion batteries. Even with a sizeable recovery built into our numbers and some growth contribution from lithium ion batteries, our price target implies around 50% downside. Manz is the most expensive stock in our equipment universe

Meyer Burger MBTN SW / MBTN.S Neutral SWF26 The company’s attractions as the market leader in wafer sawing equipment are in our view reflected in the current share price. For a further leg up, increased firm order momentum is required, in our view. We see the company’s drive towards vertical integration as reflective of a sector trend.

SMA Solar Technology S92 GR / S92G.DE Buy €125 Recent weakness in the share price on the back of concerns over the component shortage in the industry provides a buying opportunity in a downstream name that is directly geared to end market volume growth

Vestas VWS DC / VWSC. CO Buy DKK390 A market-leading global turbine manufacturer that should outperform once order growth returns

Gamesa GAM SM /GAM.MC Buy €13 Increasing exposure to new markets should broaden the company's exposure to turbine order flow as global growth picks up. Underpinning from multi-year contracts with large developers

EDF Energies Nouvelles EEN FP / EEN.PA Neutral €39 While there is risk of wind development being affected by the weak PPA market in the US, the company's growing solar development business will likely underpin capacity growth

Iberdrola Renovables IBR SM/ IBR. MC Reduce €3.60 A quality name with broad spread in the wind development segment, but we see short-term risk from the weak US PPA market

Source: Regulators’ publications, BTM Consult, Photon and Nomura

In our view a quest for growth and higher-than-average returns is driving increasing utility adoption of renewables build, firstly and already well underway in wind, and increasingly in solar. We estimate that wind projects deliver IRRs of 7-14% in Europe.



Exhibit 248. Average IRRs for European renewables under current support schemes

Average IRR (%)

Wind Germany 6-8

France 6.5-9

Spain 7-8

Italy 12

UK onshore 9

US ptc c7

US cash grant 7-8

Solar Germany 8-10

France 12-16

Spain 12-15

Italy 18-20

Source: Nomura

The solar market is, in our view, almost entirely driven by regulated financial returns. We see grid parity as a much lower-ranking consideration. Germany is the prime example; we estimate solar rooftop IRRs of around 9% after assuming that the 16% tariff reduction will become effective in July (see below). We believe that even on incorporating proposed and upcoming tariff reductions, returns will be attractive enough to support a strong solar end market in Europe.

CO2 getting tighter

Increasing costs of CO2 and more stringent EU-wide emission targets will, in our view, alter the European energy mix towards an increasing contribution of renewables. A step up of the 20% 2020 GHG emission target towards 30% is proposed, but this will depend on progress of international negotiations over a post-Kyoto regime.

The CO2 constraint in the EU will take a step forward with the end of free allowances post 2012. We expect this to lead to a consistent drive by generators to build or acquire low carbon generation capacity. While nuclear energy is clearly a very important part of this for the long term, renewables are arguably the most important change in the generation mix over the short term. In our view, wind is most likely to dominate due to its mature technology, its loce (cost of energy) being very close to competitiveness with conventional sources and scalability.

Exhibit 249. EU CO2 emissions to 2020 vs target

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Source: European Environmental Agency

Exhibit 250. EU CO2 emissions vs national caps

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Benelux, Scandinaviaand Other

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Western Europe cap

CEE cap

Benelux, Scandinavia &Others cap

Source: Bloomberg



Our views on technologies Wind and solar will remain dominant technologies over the near and medium term.

We see potential for marine technology development over the long term and small-scale geothermal deployment.

Wind and solar are the most important technologies as far as short and medium term deployment are concerned; marine technology might become very important for Europe but on a much longer horizon, more towards the end of this decade. We see deployment of biomass, but on a smaller scale. Geothermal will be a growing technology, but given geographic characteristics more in the small scale, low temperature segment rather than large scale, high temperature.

Wind

Wind technology saw the most important scale deployment across Europe with 76.5GW installed at the end of 2009. While initially, single and smaller scale projects made up the market, it is now large developers and utilities that are driving capacity growth. Going forward, we estimate the European market at an annual installation rate of c16GW pa. Currently, Europe is providing stable growth for both developers and turbine manufacturers as they wait for a pick-up from the US and given the lack of market accessibility in China. Given the latest points of evidence, this might continue to be the case for most of 2010.

The bulk of capacity is onshore wind, but offshore is picking up pace very quickly as some onshore markets are getting saturated. The Spanish and German onshore markets are beginning to near saturation, while we see further growth in France, Italy and Greece. In the UK, there is potential for growth onshore, but a difficult planning and permitting process is capping actual development and installations. At the same time, a dynamic offshore sector is developing (see below), and we see large developers concentrating on offshore as a result. Turkey and Central Europe have very good wind characteristics and we expect them to be new growth drivers for European wind.

We see the offshore market as a major growth area within wind. This is the case globally, but Europe is a centre of development and will, in our view, see the most important growth early on. The UK and Germany will be the centres of development as c 32GW from the Crown Estate concessions that have been awarded in Round 3 are developed. Although we only expect c 50% of the awarded concessions to eventually be fully developed, this is still substantial growth from the current base of just below 1GW of offshore capacity. We also expect strong momentum in Germany as developers aim to commission projects to capture the speedy bonus of €20/MWh for projects commissioned before 2015 and we see total capacity of around 3GW by 2014. Beyond this, Belgium, the Netherlands, France and Scandinavia will also be areas of growth.

Solar

Europe is the single most important region as far as global solar end market demand is concerned. Germany accounts for over 50% of global demand. We expect German demand to moderate from 2011 to gradually return towards a run rate of 3-3.5GW of annual installations from the likely over 5GW in 2010. At the same time, we expect new markets, namely France and Italy, to pick up the slack. The impact of the introduction of the new UK feed-in tariff remains to be seen. At GBp41/kWh plus GBp3/kWh as an export tariff for electricity feed into the grid rather than own consumption by the producer, it is an attractive rate even given the low sun intensity. However, the market is very immature with very low levels of awareness, limited panel infrastructure and supply chain and importantly, hardly any specialised financing. We are hearing anecdotal evidence of growth in the Czech Republic as the feed-in tariff

Wind and solar remain dominant; strong growth in offshore wind and new solar markets



there is very attractive at €480/MWh, but believe that financing is more of a bottleneck here than in other regions within Europe.

Within solar, PV is the dominant technology. Solar thermal is growing fast, but given the space and sun characteristics required, we expect it to remain confined to the Mediterranean region.

Other technologies

Marine and tidal technology are in the pilot stages, principally in the UK, but also off the Iberian coast. Growth potential for marine technology in Europe, especially in the UK is vast. However, we do not expect major commercial deployment this decade, given that capital costs still exceed the €6,000/MWh level and operating costs are also highly uncertain.

We expect geothermal to be a growing technology, but on a small scale and low temperature level. Within this segment, we expect increasing uptake for heatpumps and application within new build housing and potentially commercial developments as well as district heating. Only Italy lends itself to large scale, high temperature geothermal development on a utility scale and we expect Enel, the dominant player, to continue to develop its resource.

We see deployment of biomass but on a smaller scale.

Developments and policies, by country

Germany

Germany is the world’s fourth-largest wind market and largest solar market.

Offshore drives wind development in Germany as onshore becomes saturated.

We expect strong 2H solar demand and c. 5GW of installations in 2010.

Solar tariffs will be reduced by 16% in July 2010 despite the Upper House rejection and by 11-12% in January 2011.

Exhibit 251. Germany wind development forecast

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Source: BTM Consult, GWEC, EER and Nomura research

Exhibit 252. Germany solar development forecast

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Source: EPIA, Photon and Nomura research

Wind

While Germany is one of the largest markets, it is becoming saturated onshore. We continue to see onshore development, however, as medium-sized developers and municipalities continue to build in order to capture returns and diversify their electricity mix. Germany could become one of the major offshore centres, but development has so far been slow because of feed-in tariffs not providing sufficient incentive and large turbines being of limited availability. We think turbine availability will improve, and the



speedy bonus for offshore commissioning before 2015 will bring the tariff more in line with other countries, at €50/MWh.

Solar

Following a record year with 3.8GW of new installations in 2009, 2010 should be another strong year of demand, in our view, as price elasticity has firmly kicked in. We now estimate IRRs around the 10% level. Given that financing is available at 90% or more from 2.5-5%, this keeps returns attractive even after the upcoming tariff reduction in order to support a strong market. Installations were above 2GW in 1H ahead of the July one-off tariff reduction, and we expect another run up ahead of the January 2011 reduction to lead to a strong 4Q. Our recent feedback from manufacturers and installers has suggested demand is holding up very strongly, inventories in the channel are very low and manufacturers have reported to be sold out for the year. We also see firm pricing, albeit with an erosion of premium pricing at the high end.

The recent news that the German Upper House has not approved the proposed tariff reduction but invoked the Conciliation Committee in order to agree on a lower level of reduction is unlikely to change industry behaviour materially, as most industry participants expect the final outcome to be 16% rather than a lower percentage reduction. However, a 12% or more tariff reduction for January 2011, in our view, is highly likely, given that this will be extrapolated from June-September demand. For each 1,000MW above the government’s targeted 350MMW demand that is extrapolated from those months for the whole of 2010, feed-in tariffs will be reduced by an additional 1%, we estimate. Given that the market will likely be around 5GW, an expectation of higher feed-in tariff reductions seems reasonable to us. We believe this will again drive demand in a circular manner. Beyond that, we expect discussions over measures towards driving the market back towards the unofficially targeted growth rate around 3-3.5GW.

Key names

Enercon is the most important turbine supplier, followed by Vestas. Siemens might gain market share. RePower has a strong presence in offshore. Development is dominated by the major utilities, in particular RWE (RWE GR, NEUTRAL, PT: €71) and E.ON (EOAN GR, BUY, PT: €35), which aim to increase their renewables exposure as part of decarbonising their generation mix. We also expect them to take on a major role in offshore.

Wacker (WCH GR, BUY, PT: €145) is the market leading poly manufacturer with not only German, but also global market leadership. Solarworld (SWV GR, REDUCE, PT: €9) is the dominant high-end integrated solar name with very strong channel penetration. While predominantly focused on cells, Q-Cells (QCE GR, REDUCE, PT: €6) also has exposure to solar park development in Germany through its project business. Yingli (YGE US, BUY, PT: US$23) has been growing its market share in modules. SMA (S92 GR, BUY, PT: €125) is the market leading inverter manufacturer. Conergy (CGY GR, REDUCE, PT: €0.5) is a name with a strong downstream presence through its system integration and project development business. Centrotherm (CTN GR, BUY, PT: €40) and Roth & Rau (R8R GR, NEUTRAL, PT: €27) are leaders in the equipment market.



France

Strong potential for wind capacity growth, albeit with some risk from local resistance.

Very strong initial evidence of growth in the solar market, with more to come in 2011.

Stable and transparent wind feed-in tariff framework in line with European averages.

Solar tariffs are amongst the highest in Europe, even after the upcoming reduction in 2012.

Exhibit 253. France wind development forecast

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Exhibit 254. France solar development forecast

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France has the clearest growth case, with a stable and transparent feed-in tariff of €86/MWh (onshore) and a low degree of wind penetration within the energy mix. We expect the French market to reach the size of Germany’s on an annual basis from this year, which would make it the strongest onshore growth market within the large European economies. Current capacity is heavily concentrated in the north, but the level of wind resource in the south is also favourable to further development. There is some risk from increasing local resistance to projects, which seems to be affecting planning and permitting, and could lead to higher execution risk for projects and growth potentially coming in below expectations. Thus, this could put at risk the government’s 25GW target by 2020, according to our forecast, by a small amount.

Solar

Of the new growth markets, anecdotal evidence points to strong momentum of installations in France, in particular in the BIPV segment, where France offers one of the highest feed-in tariffs globally, with up to €0.55/kWh. Feed-in tariffs for rooftop installations will be reduced from 2012 from €0.55/kWh to €0.42/kWh. Even with the announced reduction, we think that the market should be very strong. The new level is still above the current level in Germany of €0.39/kWh, and some of the southern regions in France have considerably higher irradiation levels, which makes for very attractive returns. France should be the strongest incremental growth market in percentage terms this year, we expect. Anecdotal evidence seems to support this; as one indication, EDF has received 3,000 applications daily in November 2009. This is from a low sub 100MW level though. But we think that France can reach proportions of the German market size given the similar market sizes but better sun irradiation in France, particularly in the south. We forecast France to reach the 1GW by 2012.



Key names

EDF EN (EEN FP, NEUTRAL, PT: €39.00) is the most important wind and solar developer. GDF Suez (GSZ FP, BUY, PT: €35.00) and Iberdrola Renovables (IBR SM, REDUCE, PT: €3.60) are also stepping up development. Enercon (not rated) has the largest turbine market share, due to its relationship with EDF EN.

Spain

Wind capacity growth target of 5-5.5GW by 2012 vs 4GW already far advanced in the pipeline.

Solar capacity growth capped at 500MW pa (PV).

Overhang from uncertainty over new tariff regime for renewables; potential move from premium system for wind to feed-in tariffs, sizeable PV tariff reductions and retroactive reductions for renewables under discussion.

Policy frozen following government decision for energy review.

The Spanish government has surprisingly decided to review the entire energy sector. With this, it has put all decisions on the renewables regime on hold. We expect that it will take until about January 2011 for decisions and adjustments to the framework.

Exhibit 255. Spain wind development forecast

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Exhibit 256. Spain solar development forecast

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Spain is still the largest market as far as current annual installations are concerned, but uncertainty over regulation remains an overhang. Market growth in Spain appears to have stalled recently because of uncertainty over the amount of capacity currently at project stage that is eligible for the current feed-in tariff regime in 2010. The pre-register for all projects in Spain that was created for capacity to be commissioned in 2010 in order to plan the last 15% of capacity build towards the country’s 20GW target was closed at the end of June 2009 with over 3,000MW of projects registered. The total number of projects registered exceeds the build requirement for the 20MW target; as a result, there is uncertainty over approvals for the projects on the register. Meanwhile, the government has yet to draw up a follow-on regime for wind post 2010. We think it is likely that the current system of a premium to the wholesale electricity price will be maintained, but that the band for the cap and floor will be narrowed. This could lead to some further reduction of project IRRs, which currently stand at about 7.5%. As is typical for periods of revision of regulatory schemes, we think activity will be very low until the details of the new regime are fully ironed out.



Solar

We forecast the PV market at the annual cap level of 500MW. A removal of the cap has been suggested in various discussions but we think this is still highly uncertain. In addition, the potential and in our view very high risk of retroactive feed-in tariff reductions is an overhang for the PV sector. Feed-in tariffs are currently under discussion and could be reduced by 30% according to our take. This is within an ongoing broader revision of renewables tariffs and targets.

Solar thermal is a very important other segment of growth in Spain; in fact, Spain is one of the markets with the strongest near-term growth globally. Regulation has provided clarity on the capacity cap through the pre-register and has established a €270/MWh feed-in tariff; we think that this will lead to growth in the Spanish market this year. However, solar thermal is not spared from regulatory overhang. We think that there is risk of the government scaling back the pre-register and, thus, not all projects post 2010 might end up getting under way. Furthermore, there is risk of retroactive tariff adjustment.

Key names

Iberdrola Renovables (IBR SM, REDUCE, PT: €3.60) is the largest developer. EDP Renovaveis (EDPR PL, NEUTRAL, PT: €7.85) and Acciona (ANA SM, BUY, PT: €145) are also sizeable developers. Abengoa (ABG SM, NEUTRAL, PT: €25) has over 500MW of solar thermal capacity in the relevant pre-register and is the largest solar thermal developer and operator. Gamesa (GAM SM, BUY, PT: €13) is the largest turbine supplier, followed by Vestas (VWS DC, BUY, PT: DKK390).

Italy

Wind offers the highest remuneration globally; likely revision in 2011.

Attractive solar characteristics; remuneration one of the highest in Europe

Exhibit 257. Italy wind development forecast

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Exhibit 258. Italy solar development forecast

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Wind

Italy is a very attractive market given that it offers the highest remuneration globally for wind projects with a current reference price for total compensation of €180/MWh, reasonable wind potential and the low penetration of wind capacity within the energy mix. However, we believe the wind remuneration scheme could be revised in 2011, by which time we expect capacity to be close to target levels.



Solar

Italy is another potential high growth market that we expect to reach the 1GW mark by 2012. But growth has been somewhat slower than expected. Ground mounted systems are the predominant segment at this stage, and tight financing conditions as well as slow permitting have been the main reasons for slower growth. A highly complex remuneration system is in place that, while providing one of the highest levels of remuneration, also has many different tariffs.

Systems totalling 165MW were registered under the first Conto Energia program, and so far, 1GW has been registered with the current program, Nuovo Conto Energia, taking the total to 1.17GW. It is likely that Nuovo Conto Energia’s flexible cap of 1.2GW will be surpassed once all of the currently installed systems are registered. Official government targets are set within the framework of legislation currently in force (Nuovo Conto Energia – Ministerial Decree dated 19/02/2007): 3,000MW by 2016. However, during the discussions for the “20-20-20” EU Directive, the government presented a position paper of its own in which the PV market was addressed with regard to a potential of 8,500MW: 7,500MW roof-mounted and 1,000MW ground-mounted. This could thus imply annual growth above 1GW from 2010, in line with our forecast for somewhat above 1GW in 2010.

The current feed-in tariff scheme will end on 31 December, 2010, and a new regime will be in place from 2011. The latest draft for a follow-up regime, which was released in early February, contains 42 different tariffs, depending on system type and power classification. It also includes three tariff-reduction stages staggered over the course of 2011, after which point cuts of 6% will take effect in 2012 and 2013. Moreover, the draft law contains regulations that foresee solar electricity production tariffs combined with other local subsidy programs to provide a lump sum that would make investments in PV systems more attractive.

Furthermore, there are plans for a special tariff for CSP systems of 32 euro cents per kWh for installations with up to 200kW and 28 euro cents for all other systems, which is about the same as the subsidies paid for equivalently sized ground-mounted systems. The annual degression rate for CSP is proposed at 2% in 2012 and 2013.

Key names

Enel Green Power (ENEL IM, REDUCE, PT: €4.60) and EDF EN (EEN FP, NEUTRAL, PT: €39) through its Greentech (GES DC, not rated) option are leading wind developers, along with Fri-El. Vestas is market leader in turbine supply, followed by Nordex. Q-Cells (QCE GR, REDUCE, PT: €6) has very limited exposure through its solar park project business.



UK

Offshore wind is the key growth area following 32GW of licences awarded in round 3 in 2010, dominated by large developers.

Potential for a nascent solar market following the introduction of a domestic feed-in tariff scheme.

Exhibit 259. UK wind development forecast

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Exhibit 260. UK offshore development

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Wind

The UK is one of the big potential offshore development hotspots owing to its strong wind conditions, and we see growth as dominated by offshore. While the government is targeting onshore growth, the bulk of the overall wind target will likely be achieved through offshore. We currently forecast 5.6GW of offshore capacity by 2013 and 15GW by 2020. It is worth noting that while our 2020 forecast is above that of DECC (12GW), it is materially below the 33GW envisaged by Ofgem. It appears to us that momentum of developers is stronger for offshore ambitions, while planning and permitting is still a major bottleneck for onshore projects, and government and regulatory backing seems to work in favour of speeding up the process of offshore build.

Solar

We have so far not considered the UK as a solar market, given its low levels of irradiation and absence of supportive regulation. However, recently introduced feed-in tariff, mainly aimed at residential roof top installations, could bring new demand into the market. Considering only the GBp41/kWh tariff, we estimate c10% return. But the benefit might be higher as there is a provision for households not feeding into the grid and rather consuming electricity produced and only feeding back excess production. For the latter proportion, there is an additional “export tariff” of GBp3/kWh. Further, as returns are tax-free, solar might become an attractive investment product for high-bracket taxpayers. All of this could boost the base return. We, thus, think that such a market will develop, although awareness is extremely low, the local industry is not very developed and financing is sparse. As there will not be any reduction of the new tariff in 2011, but a revision in 2012, we would expect the market to gather pace from 2011.

Key names

Utilities and large developers dominate offshore wind — E.ON (EOAN GR, BUY, PT: €36.00), RWE (RWEG GR, NEUTRAL, PT: €71.00) and Iberdrola Renovables (IBR SM, REDUCE, PT: €3.60). Siemens (SIE GR, NEUTRAL, PT: €72.00 ) has a strong position in offshore, but we think that Vestas (VWS DC, BUY, PT: DKK390) stands good chances to capture market share.



CEE, others

Attractive wind characteristics throughout and good solar irradiation in the southern part of the region and ambitious renewables targets.

Wind and solar incentives provide an attractive background, but financing is still tight; grid and planning/permitting bottlenecks.

Exhibit 261. CEE wind development forecast

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Wind

Beyond the large Western markets, we believe Eastern Europe could become a very attractive growth region for wind. The entire region offers significant growth potential based on the EU “20-20-20” targets, which would imply renewables capacity (ie, wind as the dominant source) to multiply close to fivefold by 2020 in some areas before any material recovery in energy demand growth. Our long-term view of a material increase in CO2 prices, along with the very heavy coal weight of the energy mix in almost all countries, also supports strong wind build potential. Namely, Bulgaria, Romania, Hungary and Poland have good wind resource potential. Feed-in tariffs, in the €80-100/MWh range and market-based regimes in excess of €105/MWh at current prices further provide an attractive backdrop. However, while we expect momentum to gather pace, system and administrative bottlenecks, along with emerging market risk and higher difficulty for financing there, will curtail demand over the short term. Turkey is also gathering pace as a new growth region.

Solar

We think that the southern regions of Eastern Europe could become long-term attractive solar markets with high solar irradiation. Bulgaria and the Czech Republic have very attractive feed-in tariffs, at €380-480/MWh. At the moment, financing is still the main bottleneck. Wind seems to be taking a role as the leading renewables source, but we expect solar to catch on eventually as well.

Key names

Iberdrola Renovables (IBR SM, REDUCE, PT: €3.60) has stepped up development in the region. EDF EN (EEN FP, NEUTRAL, PT: €39) also has exposure chiefly in wind. Vestas (VWS DC, BUY, PT: DKK390) could be a beneficiary.



Europe

Global nuclear renaissance — Europe Nuclear

Martin Young +44 20 710 21536 / [email protected]

The global nuclear renaissance is being driven by capacity needs, political, cost and environmental concerns.

Russia, the UK and the US are set to lead the non-Asian charge for new nuclear capacity …

… with seven suppliers set to dominate the global market ex-Asia, although there are question marks over the economic returns that new builds will generate.

Nuclear-exposed stocks in the utilities space include EDF (BUY), E.ON (BUY), GDF Suez (BUY), RWE (NEUTRAL) and Fortum (REDUCE)

Nuclear power is enjoying a true renaissance across the globe. As many as 56 reactors, with a combined capacity of 51GW, are under construction, with China/Taiwan leading the way with 19 reactors under construction. However, big build programmes are also underway in Russia, while a number of western European nations and the US have pushed nuclear up the agenda; we expect significant new builds to commence in the next decade. This is likely to have major implications for both operators and suppliers to the value chain.

Nuclear renaissance driven by political, cost and environmental concerns Public acceptance of nuclear power plummeted following the accidents at Three Mile Island and Chernobyl, with construction programmes halted, lifetimes curtailed and in some instances, plants closed. However, in a world where security of supply, cost and environmental concerns and price stability are high on everybody’s agenda, nuclear power is enjoying a significant renaissance. We have developed a global nuclear model that suggests 180GW of new builds by 2024F, of which slightly more than half will be in Asia. It may well be that our estimates turn out to be conservative.

Exhibit 262. Global nuclear additions (MW, 2009F-24F)

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Exhibit 263. Global nuclear additions — geographic split (2009F-24F)

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Americas11%

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56 reactors with a combined capacity of 51GW are under construction across the world …

… we envisage 180GW of new nuclear capacity by 2024, 50%-plus in Asia



Russia, US and UK set to lead the non-Asian charge New build in Asia is set to be dominated by China, India, Japan and Korea, while that in the rest of the world is likely to be more widely spread. However, ex-Asia, three countries stand out as having significant new build aspirations over the next 15 years. These are Russia, where we see 16GW of capacity additions, the US with 12GW and the with UK 10GW in the next 15 years.

Russia is firmly embracing the nuclear renaissance, although given the recession and demand declines it lowered its budget in July 2009. Of the 37GW capacity that has been proposed as part of achieving a 25-30% contribution for nuclear power in electricity supply by 2030, we believe that projects without a construction start date may well be delayed or not come to fruition. That said, Russia already has 7.5GW of new capacity under construction and a further 8.2GW with planned construction start dates. We include this capacity within our global nuclear model.

The UK is set to lead the way in terms of new nuclear builds in western Europe. The government is firmly behind new nuclear builds and in January 2008 published a white paper setting out such a preference. This support is driven by a need to replace the coal capacity that will be shut down at the end of 2015 and the British Energy capacity that will reach the end of its operational life. Although the government has no specific targets for new nuclear, most major European utilities are interested in building new nuclear plants in the UK. In our global nuclear model, we take a conservative approach and suggest that only 10GW will be built by 2022F.

There is strong support in the US for new nuclear builds and a number of policy instruments have been developed to facilitate the growth of nuclear energy, including federal loan guarantees and tax credits. Proposals have been tabled for over 46GW of new capacity, of which 1,180MW is under construction, and 11,000MW is planned with engineering, procurement and construction contracts (EPCs) in place. With the exception of one project, all are on the shortlist for a federal loan guarantee. Our global nuclear model assumes that only the latter capacity will enter service in the next 15 years.

Power prices not high enough to set incentives for new builds The required power price to remunerate new nuclear depends on a number of key variables including the investment cost, the operating life, the decommissioning cost, fuel cost and the required rate of return. For an investment cost of €2.8m/MW, a required real post tax return of 7% and cost to decommission the plant based on 15% of investment cost, we estimate that a new nuclear power station will require a power price of €58/MWh in real terms.

With the 2012 forward prices in France at €57.8/MWh, in the UK at £50.6/MWh and the US (PJM) at US$54.25/MWh, it is clear that the economics of new build nuclear at this juncture are far from compelling. In Europe, the level of power prices are not helped by low CO2 pricing and an emissions trading scheme that does not provide the right incentives, in our view.

How to participate — utilities We believe nuclear is set to be a major factor in energy policy over the first half of this century but, from an investment perspective, how can one participate? A number of European utilities are active in nuclear, and we have divided these into three subgroups.

Russia, the US and the UK appear to have the most realistic non-Asian aspirations

Economics of new build far from compelling at current power prices



The big investor, EDF. EDF is Europe’s largest nuclear operator and any investor looking for exposure to nuclear via a utility name should consider it. EDF’s nuclear exposure can be summarised as follows:

Power price sensitivity: power prices in France are still largely driven by political pressures. With its low cost nuclear and hydro fleet based in France, EDF is exposed to power price movements. Taking France alone, we estimate that each additional €1/MWh is worth an additional value of €1.2/share.

Lifetime extension: EDF believes that it can extend the operating life of its reactors for 20 years for c. €0.67mn/MW. We estimate that this is worth an additional value of €8.2/share (we have not assumed a benefit share given France’s lower price environment).

New nuclear: EDF has expressed an interest in investing in new nuclear in many countries, although in our financial model, we only include investments in France (Flamanville and Penly), the US (Calvert Cliffs and one other EPR) and the UK (two EPRs) in the period to 2020. In addition, EDF is a 30% equity investor in two EPRs being built at Taishan in China. The chart below shows our estimate for cashflow from this new nuclear build. As can be seen, we see new nuclear as cashflow negative through to 2021F. Furthermore, we do not consider power prices in France, the UK and the US high enough at present to remunerate the cost of investment in new nuclear. As a consequence, we view EDF’s planned investment in new nuclear as value destructive to the tune of €1-2/share.

Exhibit 264. EDF — new nuclear cashflow (€mn)

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That said, we firmly believe that EDF will extend the operating life of its French nuclear fleet, and that the upside optionality arising from this outweighs the negatives of the new investments, given that the latter is already included in our €53 valuation that offers 51% potential upside. We are buyers of EDF.

The lifetime extenders, E.ON, GDF Suez and RWE. The lifetime of existing nuclear plants can be extended at a fraction of the cost of new builds. Recent evidence from both EDF and GDF Suez suggests that lifetime extensions can be delivered for c. €0.45mn/MW, securing 20 years of additional life in the case of EDF, and 10 years in the case of GDF Suez. Earlier, we estimated that the Belgian government’s decision to award a 10-year life extension to the country’s three oldest reactors is worth €500mn (€0.2/share) to GDF Suez for its 1.3GW equity share of the 1.8GW capacity of the three units in question. A simple calculation would suggest that if Germany grants extensions on a similar basis, it would be worth €3.2bn (€1.7/share) to E.ON and €2.4bn (€4.6/share) to RWE.

Despite challenging new build economics, we are buyers of EDF…

… with E.ON and RWE, the best way to get exposure to nuclear life extensions



We have also undertaken a more detailed approach to estimating the value of lifetime extension to German plants. Assuming an investment cost of €0.45mn/MW to secure a lifetime extension, invested evenly across a two-year period prior to scheduled decommissioning and positive NPV benefits from the push-back in decommissioning, we have estimated the benefit to E.ON and RWE for a range of extension timeframes and benefit shares. Using a 10-year extension as a central case, with a 50% share of the benefit, we suggest value enhancement of €2.2/share to E.ON and €6/share to RWE. Our preferred stock is GDF Suez (BUY, PT €35).

Exhibit 265. E.ON — nuclear life extension (€/share)

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Exhibit 266. RWE — nuclear life extension (€/share)

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The green option, Fortum. Fortum operates 3.2GW of nuclear capacity and together with 4.7GW of hydro capacity, it represents the green option for investors. A consequence of this low variable cost base is that Fortum is significantly exposed to power price variations; we estimate an additional value of €0.5/share for each additional €1/MWh. However, we see better value elsewhere in the sector and maintain a REDUCE rating on Fortum, with a €19.5 price target.

What is driving the nuclear renaissance? High profile accidents turned many nations against nuclear power; construction was

halted and early shutdowns followed.

2009 is a markedly different world and concerns over the security of supply, cost and the environment are driving a nuclear renaissance.

Our global nuclear model suggests new build of 180GW, which is possibly a conservative assumption.

Post the accidents at Three Mile Island and Chernobyl, nuclear power fell out of favour in many countries around the world, with construction programmes halted, operating lifetimes curtailed and units shut down. The past few years have seen a seismic shift towards nuclear, and now lifetimes are being extended, suspended construction programmes restarted and new builds planned. This shift in opinion and appetite is being driven by:

Fuel exposure and security of supply. Very few countries have sufficient indigenous resources of oil and gas to meet their energy requirements, and importing countries are exposed to political instability in exporting nations. Uranium is plentiful and available from countries with a history of greater political stability.

Cost. Our estimates of the cost of new builds position nuclear as the most economic form of new build for large-scale generation capacity, although its relative merits are dependent on the price of CO2.

Fortum is the green option, but we see little value and have a REDUCE rating

High profile accidents saw nuclear fall out of favour …

… but supply security, cost and environmental concerns are driving a major renaissance



Exhibit 267. New entrant power costs (€/MWh)

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CCGT - EUR Coal Clean Coal Nuclear Wind - On Wind - Off Market CCGT Market Coal

Return Decommissioning O&M costs Carbon costs Fuel costs(EUR/MWh)

Nomura long term price assumption of €65/MWh

€66/MWh €67/MWh

€86/MWh

€58/MWh €63/MWh

€107/MWh

€50/MWh

€56/MWh


Price stability. Cost estimates for new nuclear vary greatly and have clearly increased from the initial estimates of the capital cost of a new EPR. However, nuclear is a low variable cost form of generation and hence offers the possibility of long-term stable price contracts, particularly to those that have base load requirements.

Environmental concerns. Tightening CO2 targets mean a push towards low and zero CO2 forms of generation. Nuclear energy provides a base load output and with old coal stations being retired and clean coal still someway off, nuclear has a role not only in replacing existing nuclear capacity, but also in lowering the carbon footprint of electricity generation worldwide.

Global nuclear model suggests 180GW new build

Such is the enthusiasm for new nuclear that if we add the new build targets (planned and proposed) of countries with aspirations to build new nuclear capacity, it would total 500GW of new nuclear plant capacity, including the 51GW now under construction. For many reasons, we believe that not all of this will be built, particularly within a reasonable timeframe of 15-20 years. Our approach to building a growth model for new nuclear around the world involves a country-by-country analysis and applying a pragmatic and conservative approach to the plans of each country. In particular, recession-driven demand destruction is likely to prompt reassessment of plans, as will a trend towards lifetime extensions. Finance is also a concern and may derail many new build plans. As a consequence, our global nuclear model suggests a 180GW increase in capacity by 2024F, which is possibly conservative, but still indicates a 48% increase from existing global nuclear capacity. Of this, Asia (China, India and Japan) is likely to account for more than half. (Growth models that include communicated plans/ambitions from countries will naturally result in a higher growth profile. China is one such region, where significant plant capacity (95GW-plus) has been proposed, but we do not include this in our model. Our Asian utilities team includes planned nuclear reactors in China in their forecasts and expects 70GW in operation by 2020F (this is included in our global model.)

We have built a model that suggests 180GW of new build by 2024…




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Exhibit 269. Global nuclear additions — geographic split (2009F-24F)

Middle East2%

Africa2%

Americas11%

Asia57%

Europe28%


Is this volume of new build achievable?

Of the 180GW of new nuclear capacity that our model suggests will be built by 2024F, 51GW is already under construction. The question we pose is whether the remaining volume of new build is achievable? Our belief is that it is.

Firstly, as we have indicated, we have adopted a conservative, but hopefully realistic, view on the plans of individual countries given the potential issues in the planning process, cost and access to finance, and the reduced immediate need given the recession-driven fall in demand.

Secondly, history suggests that this level of expansion should be achievable from a technical perspective because in the 1980s 218 reactors with an aggregate capacity of 201GW were commissioned. Hence, we believe with bigger reactors, our new build expectation should be achievable.

Cost overruns are an issue Capital cost estimates for new nuclear vary significantly from technology to technology, and from country to country. Latest estimates point to new build costs of €2,500-3,100/kW, somewhat higher than the €2,065/kW first suggested by EDF for the Flamanville 3 plant. Cost overruns have been an ongoing issue in the nuclear industry, and the trend continues with the two Generation III+ plants under construction in Europe.

1. Olkiluoto 3 (TVO/Areva). Construction on this project started with TVO’s excavation work in 2004 and the construction site was handed over to the plant supplier (Areva) in 2005. Commercial operation is likely in 2012 versus an original schedule of 2009, while the estimated construction costs are now €5.5bn (as of August 2009) versus the €2.5bn originally planned.

2. Flamanville 3 (EDF/Areva). Construction for this project started in 2006 and commercial operation is likely in 2013 versus an original schedule of 2012F, while the estimated construction costs are now €4.0bn (as of August 2009) versus the €3.3bn originally planned.

… we view this as achievable and believe our estimate is probably alittle conservative

Costs have been rising and overruns are an issue



The required power price for new nuclear is heavily dependent on capex cost

The power price required to remunerate new nuclear depends on a number of key variables, including the investment cost, the operating life, the decommissioning cost, fuel cost and the required rate of return. Our €58/MWh required price set out above in our new entrant analysis is based on an investment of €2.8m/MW and a required real post-tax return of 7%. Assuming that there is little variation in fuel costs across different technologies and the cost to decommission the plant is based on 15% of the investment cost of the plant, it is easy to estimate a required power price for a variety of returns and investment costs.

Our analysis is shown in the chart below; it suggests that to deliver a 7% post-tax real return, a generation price of €49.6/MWh in real terms would be required at a capex cost of €2.5m/MW, while €66.5/MWh in real terms would be required at a capex cost of €3.5m/MW.

Exhibit 270. Required nuclear price (€/MWh) for different required returns (%)

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2,000 2,200 2,400 2,600 2,800 3,000 3,200 3,400 3,600 3,800 4,000

7.0% 7.5% 8.0% 8.5%

9.0% 9.5% 10.0%

Note: The X axis denotes capex cost of €mn/MW and the Y axis denotes a generation price of €/MWh to be achieved given post-tax returns.


Refurbishing units and extending operating lives offers short-term fix

New capacity should absorb the majority of nuclear capex over the next 15-20 years, but the economically sensible solution of extending nuclear lifetimes should not be ignored. Most plants were designed and licensed for 30-40 year operations, but in a number of countries, notably Finland, Sweden and the US, lifetimes have now been extended to as much as 60 years and, in many cases, capacity uprated as plant components were replaced. In addition, Belgium, Canada, Germany (details still to be agreed), the Netherlands and the UK have all embraced lifetime extensions, and we believe others, notably France, will follow.

The costs of extending nuclear operating life vary given the length of the extension, the safety standards imposed and capacity increases, if any, but ignoring the outliers, and focusing on recent data points, analysis suggests a cost of €400-700/kW for 10-20 years of additional operation, an attractive proposition versus the €2,500-3,100/kW cost of new build.

Refurbishing existing capacity and extending operating life is a very attractive proposition versus new build



Exhibit 271. Cost to extend nuclear life

Company Country Notes

British Energy UK £90mn for a five-year extension of Hinkley Point B and Hunterston B, with combined capacity of 1.2GW. Equivalent to €84/kW, although arguably of less relevance given the short extension.

Bruce Power Canada A 20-year extension for each of the 750MW Bruce A1 and A2 units is set to cost C$3.1-3.4bn, equivalent to €1,300-1,400/kW.

EDF France EDF suggests €600mn to extend the lifetime of a 900MW unit by 10 years, equivalent to €666/kW.

EPZ Netherlands €250mn donation for sustainable energy projects.

E.ON Sweden E.ON invested €700/kW for capacity uprate and lifetime extension to 60 years at its Oskarshamn plant in Sweden.

GDF Suez Belgium GDF Suez has stated that the investment required to extend the life of the three oldest reactors in Belgium (1.8GW) is €800mn, equivalent to €447/kW.

New Brunswick Power

Canada Cost to extend the operating life of the Point Lepreau1 reactor to 60 years and up-rate by 25MW estimated whose estimates at C$1.4bn, equivalent to €1,333/kW, although the project is running over-budget.

Ontario Power Generation

Canada A 20-year extension of unit A1 at the Pickering plant cost US$1,600/kW (€1,066/kW), well above the initial estimate.

TVO Finland €130mn to extend the lifetime of the two unit 1.7GW Olkiluoto BWR by 10 years, equivalent to €75/kW.

Source: Company reports, Nomura estimates

Nuclear issues and policies, by country The western world dominates global nuclear capacity, but Asia is expanding fast.

In the west, Russia, the UK and the US have plausible large-scale plans, while Italy and the UAE have made high profile entries to the race.

Lifetime extensions are also on the agenda and Belgium, Canada, Finland, Germany, the Netherlands, Sweden, the UK and the US have gone down this route.

Seven suppliers — AECL, Areva, Atomstroyexport, GE Hitachi, Mitsubishi Heavy Industries, Toshiba and KEPCO — are competing for ex-China new build.

The western world (including Russia) has dominated the nuclear power industry for many years, although the most significant capacity additions in the past decade have been in Asia, notably China, Korea and Japan.

Exhibit 272. Global nuclear capacity (1980-2008, MW)

Growth (%) CAGR (%)

1980 1985 1990 1995 2000 2005 2007 2008 2008 v 2000 2000-08

Belgium 1,670 5,464 5,501 5,631 5,712 5,801 5,824 5,824 2.0 0.2

Brazil 626 626 626 1,976 1,901 1,795 1,766 (10.6) (1.4)

Canada 5,172 9,741 13,993 14,902 9,998 12,584 12,610 12,577 25.8 2.9

Czech Republic 391 1,632 1,782 2,611 3,373 3,619 3,634 39.2 4.2

Finland 2,208 2,300 2,310 2,310 2,656 2,676 2,696 2,696 1.5 0.2

France 14,388 37,478 55,808 58,573 63,080 63,260 63,260 63,260 0.3 0.0

Italy 1,112 1,273 n/a n/a

Germany 10,323 18,110 21,250 20,972 21,283 20,339 20,430 20,470 (3.8) (0.5)

Russia 8,596 15,841 18,898 19,848 19,848 21,743 21,743 21,743 9.5 1.1

South Africa 1,840 1,840 1,840 1,840 1,800 1,800 1,800 (2.2) (0.3)

Spain 1,073 5,608 7,099 7,097 7,468 7,591 7,450 7,450 (0.2) 0.0

Sweden 5,515 9,450 9,919 10,058 9,417 8,916 9,034 8,996 (4.5) (0.6)

UK 8,686 12,485 13,496 13,718 13,059 11,852 10,222 10,097 (22.7) (3.2)

Ukraine 2,286 8,324 13,020 13,045 11,195 13,107 13,107 13,107 17.1 2.0

US 50,881 74,401 96,228 98,068 96,297 98,145 100,266 100,683 4.6 0.6

Other Europe (incl former USSR) 5,393 10,441 12,923 13,881 15,625 13,461 13,003 12,705 (18.7) (2.6)

Asia 17,647 33,362 44,364 57,683 66,257 79,292 82,604 82,519 24.5 2.8

Other Americas 335 935 1,575 2,191 2,268 2,295 2,295 2,235 (1.5) (0.2)

World 135,285 248,070 320,482 342,225 350,590 368,136 371,758 371,562 6.0 0.7

% covered by identified countries 82.7 82.0 81.6 78.4 76.0 74.2 73.7 73.8 Source: IAEA PRIS

Western world dominates, but Asia is mounting a charge



This trend is set to continue over the next few years as China, India, Japan and Korea are responsible for 60% of the 51GW of nuclear capacity currently under construction. Europe and the Americas should not be ignored, however, and outside the four countries mentioned above, nuclear power is very much on the political and energy industry agendas, whether it be new build or lifetime extensions for existing facilities.

Exhibit 273. Nuclear capacity under construction (MW, December 2009)

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PakistanArgentina

Slovak RepublicIran

United States Of AmericaFinlandFrance

UkraineBulgaria

JapanTaiwan

IndiaKorea

Russian FederationChina

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Source: IAEA PRIS

Countries can be split into a number of categories — the true believers (France, Russia, the UK and the US), the maintainers (Finland and Sweden), the extenders (Belgium and Germany), the agnostics (Spain) and the newcomers (Italy and UAE).

Russia, the UK and the US to lead the non-Asian charge for new build — we forecast that Asia will account for more than half of the new nuclear capacity built over the next 15 years, but that there will be also be significant new build in other parts of the world. Russia, the UK and the US have the most plausible expansion plans, although countries such as Italy and the UAE have also embraced new build enthusiastically.

Lifetime extensions — extending operating lifetimes is more cost effective than new build, and Belgium, Finland, Germany, the Netherlands, Sweden, the UK and the US have all gone down this route, and we expect others, such as France, to follow.

Seven suppliers appear to be competing for new build — we identify AECL (Canada, although up for sale), Areva (France), Atomstroyexport (Russia), GE Hitachi (US Japan), Mitsubishi Heavy Industries (Japan), and Toshiba (US Japan) as the companies competing for reactor design and build. We acknowledge that KEPCO (Korea) may participate and be successful in non-Asian tenders, but assume that Chinese providers will stay largely domestically focused for now.

Russia, the UK and the US lead the charge for non-Asian new build …

… while other countries are embracing lifetime extension, most recently Belgium and Germany




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Exhibit 275. Global nuclear additions — geographic split (2009-24F)

Middle East2%

Africa2%

Americas11%

Asia57%

Europe28%


France — nuclear issues and policies France is the world’s leading nuclear nation, at the forefront in both operation and

build.

More than three-quarters of the electricity generated in France is from nuclear energy and the fleet is relatively young.

France is embracing new build — one EPR is under construction and the construction of a second is scheduled to commence in 2012.

Nuclear industry development

The first commercial generation of electricity from nuclear energy in France took place in 1963, but there was significant expansion of the fleet in the late 1960s and the 1970s, with the construction of 58 PWR units on 19 sites. The average age of France’s nuclear plants is 23 years. With 63GW of nuclear capacity, France is the world leader in nuclear power generation and nuclear power accounts for over 75% of the electricity generated in the country, which is the highest penetration in the world.

Exhibit 276. France — nuclear capacity (MW)

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Exhibit 277. France — nuclear output (TWh)

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France is arguably the most pro-nuclear nation on the planet …



Exhibit 278. France — nuclear’s share of electricity (%)

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Exhibit 279. France — nuclear load factor (%)

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Source: IAEA PRIS

Key participants

EDF is the sole operator of nuclear power plants in France, although GDF Suez owns minority stakes in Chooz and Tricastin, while E.ON has 800MW of nuclear drawing rights. Enel has a 12.5% stake in the Flamanville 3 unit currently under construction.

Exhibit 280. France — nuclear capacity

Power plant Commissioned Capacity (MW)

Bugey 2-5 1979-80 2*910, 2*880

Fessenheim 1-2 1978 2*880

Blayais 1-4 1981-83 4*910

Dampiere 1-4 1980-81 4*890

Gravelines 1-6 1980-85 6*910

Tricastin 1-4 1980-81 4*915

Chinon B 1-4 1984-88 4*905

Cruas 1-4 1984-85 4*915

St Laurent 1-2 1983 2*915

Flamanville 1-2 1986-87 2*1330

Paluel 1-4 1985-86 4*1330

St Alban 1-2 1986-87 2*1335

Belleville 1-2 1988-89 2*1310

Cattenom 1-4 1987-92 4*1300

Golfech 1-2 1991-94 2*1310

Nogent 1-2 1988-89 2*1310

Penly 1-2 1990-92 2*1330

Chooz B 1-2 2000 2*1500

Civaux 1-2 2002 2*1495

Total 63,130

Source: Company reports, Nomura estimates

Technology

France’s nuclear fleet are all PWRs of three standard types designed by Framatome (now Areva), these being the 900MW series, the 1,300MW series and the 1,450MW N4 series. The differences to the standard size shown in the above table are owing to cooling requirements and capacity uprates in the N4 reactors. EDF plans to uprate five of its 900MW reactors by 3% over 2008-10F and its 20 1,300MW reactors by 7% from 2015. Areva is an active developer of nuclear around the world and has exported its technology to a number of countries.

… and EDF is the world’s largest nuclear operator



Appetite for development

Unsurprisingly, for a country where nuclear power is a key pillar of industrial policy and the cornerstone of electricity generation, France favours nuclear new build. A 1,600MW Areva EPR is under construction at Flamanville and is due for completion in 2012F, although delays in construction may push this back to 2013F; Enel has a 12.5% stake in this EPR. A second Areva 1,600MW EPR is to be built by EDF at Penly (GDF Suez will have a 25% stake, Total 8.3% and Enel has a right to take 12.5%. E.ON has also expressed interest), with construction likely to start in 2012F, and commissioning in 2017F. A third EPR, this time led by GDF Suez, is also likely, as are lifetime extensions beyond 40 years to the existing fleet.

Germany — nuclear issues and policies Germany is one of the world’s pre-eminent nuclear nations, behind only France,

Japan, Russia and the US in global rankings.

Early phase-outs have been revisited and lifetime extensions have been agreed upon by the government.

However, new build is not on the agenda.


Germany is one of Europe’s pre-eminent nuclear nations, with 20GW of capacity providing around 28% of the electricity generated in the country. The oldest of the 17 operating reactors entered service in 1975, although Germany’s nuclear heritage pre-dates this time. The Soviet designed reactors in East Germany were closed down post German reunification. Ownership of the country’s 17 reactors is split between the four big utilities (E.ON, RWE, Vattenfall and EnBW) although GDF Suez has recently acquired drawing rights from E.ON.

Exhibit 281. Germany — nuclear capacity (MW)

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Exhibit 282. Germany — nuclear output (TWh)

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160

180

1980 1985 1990 1995 2000 2005 2007 2008

Source: IAEA PRIS

New build is on the agenda, with one plant under construction and another planned

A pre-eminent nuclear nation, with ownership split between the four main utilities



Exhibit 283. Germany nuclear’s share of electricity (%)

0

5

10

15

20

25

30

35

1985 1990 1995 2000 2005 2007 2008

Source: IAEA PRIS

Exhibit 284. Germany — nuclear load factor (%)

0

10

20

30

40

50

60

70

80

90

100

1980 1985 1990 1995 2000 2005 2007 2008

Source: IAEA PRIS

Key participants

Ownership and operation of the German nuclear fleet sits mainly in the hands of the four main utilities — E.ON, RWE, Vattenfall and EnBW. In some instances, ownership of the plants is shared and can involve some minority stakeholders. GDF Suez has recently acquired 700MW of drawing rights from E.ON and EnBW/EDF acquired 800MW of drawing rights.

Exhibit 285. Germany — nuclear capacity

Reactor Ownership Type Capacity (MW) Operation

Biblis-A RWE PWR 1,167 2/1975

Neckarwestheim-1 EnBW: 99.8% / Deutsche Bahn: 0.2% PWR 785 12/1976

Brunsbüttel Vattenfall: 66.7% / EON: 33.3% BWR 771 2/1977

Biblis-B RWE PWR 1,240 1/1977

Unterweser E.ON PWR 1,345 3/1979

Isar-1 E.ON BWR 878 9/1979

Phillipsburg-1 EnBW: 99.8% / Deutsche Bahn: 0.2% BWR 890 3/1980

Grafenrheinfeld E.ON PWR 1,275 6/1982

Krümmel Vattenfall: 50% / EON: 50% BWR 1,260 3/1984

Gundremmingen-B RWE: 75% / EON: 25% BWR 1,284 4/1984

Gundremmingen-C RWE: 75% / EON: 25% BWR 1,288 1/1985

Gröhnde EON: 83.3% / SW Bielefeld: 16.7% PWR 1,360 2/1985

Phillipsburg-2 EnBW: 99.8% / Deutsche Bahn: 0.2% PWR 1,392 4/1985

Brokdorf EON: 80% / Vattenfall: 20% PWR 1,370 12/1986

Isar-2 EON: 75% / SW München: 25% PWR 1,400 4/1988

Emsland RWE: 87.5% / EON: 12.5% PWR 1,329 6/1988

Neckarwestheim-2 EnBW: 99.8% / Deutsche Bahn: 0.2% PWR 1,305 4/1989

Total 20,339


Technology

Germany has two types of reactors. There are six BWRs and 11 PWRs. All were built by Siemens-KWU and, as mentioned previously, all the Soviet-designed reactors in East Germany were shut down post reunification.


Nuclear power is a topical issue in Germany. The Chernobyl accident saw a previous SPD/Green coalition government push for a gradual phasing-out of nuclear power, and in June 2000, a compromise was reached under which Germany’s 19 nuclear reactors would be able to operate for an aggregate lifetime total of 2,623 TWh, this being equivalent to 32 years of continuous operation. The agreement also included a

Anti-nuclear feeling resulted in an early phase-out being adopted …



commitment not to introduce any “one-sided” economic or taxation measures. The compromise agreement was signed in June 2001 and is known as the “nuclear consensus”. However, in June 2010, the government announced that it was imposing a €2.3bn pa tax on enriched nuclear fuel from 2011-14F.

Exhibit 286. German nuclear phase-out by plant (MW)

StadeObrigheim

Biblis ANeckarwestheim-1

Biblis BBrunsbüttel

Isar-1Unterweser

Phillippsburg-1Grafenrheinfeld

KrümmelGundremmingen BGundremmingen C

Phillippsburg-2GrohndeBrokdorf

Isar-2Emsland

Neckarwestheim-2

2010 20202015


Exhibit 287. German nuclear capacity development (MW)

0

5,000

10,000

15,000

20,000

25,000

Jan-

10Ju

l-10

Jan-

11Ju

l-11

Jan-

12Ju

l-12

Jan-

13Ju

l-13

Jan-

14Ju

l-14

Jan-

15Ju

l-15

Jan-

16Ju

l-16

Jan-

17Ju

l-17

Jan-

18Ju

l-18

Jan-

19Ju

l-19

Jan-

20Ju

l-20

Jan-

21Ju

l-21

Jan-

22Ju

l-22

Jan-

23Ju

l-23


Since then, however, public support for nuclear energy has increased given concerns around security of supply, higher and increasingly volatile commodity costs and the absence of CO2 emission in nuclear generation. Faced with a declining reserve margin, and hence a looming capacity shortage, Germany’s tough CO2 targets and the commercial viability of Carbon Capture and Storage (CCS) technology still unproven, the extension of nuclear lifetime was a key policy item for both the CDU/CSU and FPD parties in last September’s elections. With these parties forming a coalition government, it is likely that the life of Germany’s nuclear fleet will be extended, although exact terms and benefit-sharing arrangements are yet to be worked out. There are, however, no plans to build new nuclear capacity.

… but lifetime extensions are now being discussed



Russia — nuclear issues and policies Russia was an early pioneer in nuclear power generation; however,

Chernobyl/technical problems plunged the industry into crisis.

Load factors are now increasing and a very large expansion plan has been proposed.

Russia is also aiming to export its technology.


In 1954, Russia was the first country in the world to produce nuclear electricity, with commercial scale production starting in the 1960s. The 1970s saw further expansion and 25 nuclear reactors were in operation by the mid 1980s. However, construction problems and the Chernobyl accident plunged the industry into crisis, and only one reactor was commissioned in 10 years. The collapse of the Soviet Union starved the industry of funds, and it was not until 2000 that construction was revived. Ownership and operation of the Russian nuclear power sector rests with the state holding company AtomEnergoProm.

Exhibit 288. Russia — nuclear capacity (MW)

0

5,000

10,000

15,000

20,000

25,000

1980 1985 1990 1995 2000 2005 2007 2008

Source: IAEA PRIS

Exhibit 289. Russia — nuclear output (TWh)

0

20

40

60

80

100

120

140

160

1980 1985 1990 1995 2000 2005 2007 2008

Source: IAEA PRIS

Exhibit 290. Russia — nuclear’s share of electricity (%)

0

2

4

6

8

10

12

14

16

18

1995 2000 2005 2007 2008

Source: IAEA PRIS

Exhibit 291. Russia — nuclear load factor (%)

0

10

20

30

40

50

60

70

80

90

1980 1985 1990 1995 2000 2005 2007 2008

Source: IAEA PRIS

The first nation to produce nuclear electricity, Chernobyl and the collapse of the Soviet Union plunged the industry into crisis



Key participants

The ownership and operation of the Russian nuclear fleet is in the hands of Energoatom (formerly Rosenergoatom), which is an entity within AtomEnergoProm. Other entities are responsible for new build design, construction, maintenance and upgrading.

Exhibit 292. Russia — nuclear capacity

Reactor Type Capacity (MW/unit)Commercial

operationScheduled

close

Balakovo 1-2 V-320 950 5/86, 1/88 2015, 2017

Balakovo 3-4 V-320 950 4/89, 12/93 2018, 2023

Beloyarsk 3 BN600 FBR 560 11/81 2010

Bilibino 1-4 LWGR EGP-6 11 4/74-1/77 2009, 09, 11, 12

Kalinin 1-2 V-338 950 6/85, 3/87 2014, 2016

Kalinin 3 V-320 950 12/04 2034

Kola 1-2 V-230 411 12/73, 2/75 2018, 2019

Kola 3-4 V-213 411 12/82, 12/84 2011, 2014

Kursk 1-2 RBMK 925 10/77, 8/79 2021, 2024

Kursk 3-4 RBMK 925 3/84, 2/86 2013, 2015

Leningrad 1-2 RBMK 925 11/74, 2/76 2019, 2022

Leningrad 3-4 RBMK 925 6/80, 8/81 2009, 2011, +20 yr

Novovoronezh 3-4 V-179 385 6/72, 3/73 2016, 2017

Novovoronezh 5 V-187 950 2/81 2035 after upgrade

Smolensk 1-3 RBMK 925 9/83, 7/85,1/90 2013, 2020

Rostov 1 V-320 950 3/01 2030

Total 21,743

Note: V=PWR, Source: WNA, Nomura estimates

Technology

Russia has one of the most diverse nuclear fleets in the world, including some technology unique to Russia and Lithuania. There are 15 PWRs spanning three generations, 11 RBMK light water graphite reactors (unique to Russia/Lithuania), four small BWR reactors in eastern Siberia and one BN-600 fast-breeder reactor. A number of the RBMK reactors are of concern to the western world, and the EC set early closure of Lithuania’s Ignalia plant as a condition for Lithuania’s membership of the EU.

Load factors that were low by western standards have improved markedly over the past five years and extensions are being considered to the existing 30-year life, with the V-200 series and RBMK getting 15-year life extensions and the V-300 series getting 25 years.


Russia is firmly embracing the nuclear renaissance, although given the recession and demand declines, it lowered its budget in July 2009. Of the 37GW capacity that has been proposed as part of achieving a 25-30% contribution for nuclear power in electricity supply by 2030, we believe that projects without a construction start date may well be delayed or not come to fruition. That said, Russia already has 7.5GW of new capacity under construction and a further 8.2GW with planned construction start dates. We include this capacity within our global nuclear model. Capacity under construction or with planned construction start dates is of the existing 950MW second generation type, or the 1,170MW VVER-1200 (AES-2006) third generation type. Both models are Atomstroyexport PWRs, and it appears that foreign involvement in reactor supply is limited to providing parts of the assembly.

Ownership and operation of the nuclear fleet is in the hands of Energoatom

Technology is diverse, but the RBMK type reactors are of concern to the western world

Russia has significant ambitions for new nuclear, but we believe some reactors may not be delayed or not built



UK — nuclear issues and policies Although a nuclear pioneer, nuclear slipped off UK’s radar in the 1980s and 1990s.

The large combustion plants directive (LCPD) and the pending closure of existing nuclear plants has resulted in the government fully supporting new nuclear; the UK is likely to lead the way in western Europe.

EDF, E.ON, GDF Suez, Iberdrola, RWE and SSE are all set to participate.


Although Russia was the first to generate nuclear power, UK’s Calder Hall reactor was the first to deliver electricity in commercial volumes. A raft of small Magnox power stations were built, followed by 14 advanced gas-cooled reactors (AGRs) over 1976-89. Government support for nuclear oscillated; although four PWRs were planned, only one was built. The majority of the fleet is in the hands of British Energy, which was privatised in 1996, taken back into government ownership in 2003 following financial difficulties, re-listed in 2005 and then bought by EDF in 2009. About 20% of UK’s electricity comes from nuclear energy.

Exhibit 293. UK — nuclear capacity (MW)

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

1980 1985 1990 1995 2000 2005 2007 2008

Source: IAEA PRIS

Exhibit 294. UK — nuclear output (TWh)

0

10

20

30

40

50

60

70

80

1980 1985 1990 1995 2000 2005 2007 2008

Source: IAEA PRIS

Exhibit 295. UK — nuclear’s share of electricity (%)

0

5

10

15

20

25

30

1985 1990 1995 2000 2005 2007 2008

Source: IAEA PRIS

Exhibit 296. UK — nuclear load factor (%)

0

10

20

30

40

50

60

70

80

1980 1985 1990 1995 2000 2005 2007 2008

Source: IAEA PRIS

A nuclear pioneer, about 20% of UK’s electricity needs are met by nuclear



Key participants

Ownership of the existing fleet is in the hands of two entities. The government-owned Nuclear Decommissioning Authority (NDA) owns and operates the two remaining Magnox stations, but these are set to close next year, while EDF (through British Energy) owns the remainder. Centrica owns a 20% stake in British Energy, and a number of Europe’s large integrated utilities have expressed an interest in building new nuclear plants in the UK. The country is set to be at the forefront of the nuclear renaissance in western Europe.

Exhibit 297. UK — nuclear capacity

Reactor Type Ownership Capacity per

unit (MW) OperationExpected

shutdown

Oldbury 1 & 2 Magnox NDA 217 1968 Dec 2010

Wylfa 1 & 2 Magnox NDA 490 1971-72 Dec 2010

Dungeness B 1 & 2 AGR British Energy 545 1985-86 2018

Hartlepool 1 & 2 AGR British Energy 595 1984-85 2014 (2019?)

Heysham 1 & 2 AGR British Energy 615 1985-86 2014 (2019?)

Heysham 3 & 4 AGR British Energy 615 1988-89 2023

Hinkley Point B 1 & 2 AGR British Energy 620 & 600 1976-78 2016

Hunterston B 1 & 2 AGR British Energy 610 & 605 1976-77 2016

Torness 1 & 2 AGR British Energy 625 1988-89 2023

Sizewell B PWR British Energy 1,196 1995 2035

Total 11,035


Technology

Unlike other countries where standardisation of technology is generally the norm, the UK’s approach to nuclear was somewhat haphazard. AGR technology is exclusive to the UK, and each pair is a unique design. This means that, if a problem occurs, individual solutions need to be found, a situation that was most marked in British Energy’s last years as an independent company. Despite these problems, lifetime extensions have been granted (Dungeness, Hinkley Point B and Hunterston B) and others are likely. Our own model for EDF assumes operating lifetimes five years longer than those in the above table for all, bar Dungeness and Sizewell B, on the basis that we believe it is technically possible, and that Dungeness was granted a 10-year extension. The UK’s only PWR is a Westinghouse design.


Although we would argue that France is the most pro-nuclear nation in western Europe, it is the UK that is set to lead the way in terms of new nuclear build in western Europe. The government is firmly behind new nuclear builds and in January 2008 published a white paper setting out such a preference. This support is driven by a need to replace the coal capacity that will be shut down at the end of 2015 and the British Energy capacity that will reach the end of its operational life.

Although the government has no specific targets for new nuclear, most major European utilities are interested in building new nuclear plants in the UK. EDF owns British Energy (Centrica owns 20%), and has augmented the grid connection agreements held by British Energy with additional agreements at Wylfa and Hinkley Point, although EDF has to dispose of land at either Dungeness or Heysham, and one of the grid connections at Hinkley Point. E.ON and RWE have formed a JV and have secured land and grid connections at Wylfa and Oldbury, while the alliance between GDF Suez, Iberdrola and SSE has secured an option on land at Sellafield. Vattenfall has expressed an interest in UK new build, but has yet to declare its hand.

EDF-owned British Energy dominates the UK nuclear landscape …

… but the technology is far from standarised

UK set to lead the new build charge in western Europe

EDF, E.ON/RWE and GDF Suez/Iberdrola/SSE all have advancing plans



Exhibit 298. UK grid connection agreements

Promoter Site Capacity (MW) Time

British Energy (EDF) Sizewell C 3,300 2016, 21

British Energy (EDF) Hinkley Point C 3,300 2016

British Energy (EDF) Dugeness C 1,650 2016

British Energy (EDF) Bradwell C 1,650 2016

EDF Wylfa B 1,670 2017

EDF Hinkley Point 1,670 2019

E.ON/RWE Oldbury B 1,600 2020

E.ON/RWE Wylfa C 3,600 2020, 21,22

Total 18,440


Unsurprisingly, each of the utilities above have large ambitions in terms of new build, although in our global nuclear model, we take a more conservative approach and suggest that 10GW will be built by 2022. Underpinning this view is the fact that the economics are still far from certain, particularly with a low carbon price, structural changes in demand have eased the pressure for new build and reactor designs are still to be approved. The generic design assessment (GDA) is ongoing in the UK, and of the four suppliers who submitted designs, AECL and GE-Hitachi have withdrawn, leaving Areva and Westinghouse as the only technologies under consideration. Despite a number of concerns being raised by the UK’s Health & Safety Executive (HSE) about each design, the HSE remains confident the GDA will be completed by June 2011.



US — nuclear issues and policies The US is the global nuclear leader, but has seen very little development over the

past 30 years.

It has a very fragmented ownership structure — 20 utilities account for 85% of capacity.

There is strong support for new nuclear and policy instruments are in place.


The US is the world’s largest producer of nuclear power with 27% of global installed capacity and 31% of power produced in 2008. However, as a consequence of the Three Mile Island accident and a preference for gas, no new build has been started since 1977, although construction delays mean that the youngest plant is only 13 years old. Major performance gains have been made over the years, and the US nuclear fleet has some of the highest load factors in the world.

Exhibit 299. US — nuclear capacity (MW)

0

20,000

40,000

60,000

80,000

100,000

120,000

1980 1985 1990 1995 2000 2005 2007 2008

Source: IAEA PRIS

Exhibit 300. US — nuclear output (TWh)

0

100

200

300

400

500

600

700

800

900

1980 1985 1990 1995 2000 2005 2007 2008

Source: IAEA PRIS

Exhibit 301. US — nuclear’s share of electricity (%)

0

5

10

15

20

25

1985 1990 1995 2000 2005 2007 2008

Source: IAEA PRIS

Exhibit 302. US — nuclear load factor (%)

0

10

20

30

40

50

60

70

80

90

100

1980 1985 1990 1995 2000 2005 2007 2008

Source: IAEA PRIS

Key participants

Unlike other countries where nuclear ownership tends to be concentrated in the hands of a few, in the US, it is very fragmented, and despite industry consolidation, there are still 26 operators, and many more owners, although 65% of capacity is spread between 10 utilities and 85% between 20 utilities.

The US is the world’s largest producer of power from nuclear energy, but enthusiasm waned post the Three Mile Island accident

Unlike other countries, the US nuclear industry is fragmented



Exhibit 303. US nuclear capacity

Owner Capacity (MW) % share Cumulative %

Exelon Corp. 16,712 16.7 16.7

Entergy Corp. 10,086 10.1 26.7

Tennessee Valley Authority 6,671 6.7 33.4

Dominion Resources, Inc. 5,698 5.7 39.1

FPL Group 5,470 5.5 44.5

Duke Energy Corp. 5,173 5.2 49.7

FirstEnergy Corp. 3,862 3.9 53.5

Constellation Energy Group 3,789 3.8 57.3

Progress Energy, Inc. 3,765 3.8 61.1

Southern Co. 3,614 3.6 64.7

Public Service Enterprise Group, Inc. 3,496 3.5 68.2

Luminant Holdco 2,300 2.3 70.4

PG&E Corp. 2,240 2.2 72.7

Edison International 2,225 2.2 74.9

American Electric Power Co. Inc. 2,069 2.1 77.0

PPL Corp. 2,060 2.1 79.0

North Carolina Municipal Power Agency No. 1 2,030 2.0 81.0

Xcel Energy, Inc. 1,668 1.7 82.7

Oglethorpe Power Corp. 1,199 1.2 83.9

Ameren Corp. 1,190 1.2 85.1

Others 14,950 14.9 100.0

Total 100,265

Source: NEI

Technology

The oldest nuclear plant began commercial operation in 1969, and there are currently 104 reactors on 65 sites. Of these, 35 are BWRs and 69 are PWRs. GE and Westinghouse dominate the nuclear fleet, although some reactors are Combustion Engineering or Babcock & Wilcox. Despite limited new build over the past 30 years, there have been 5,700MW of capacity uprates since 1977 and more are planned. Operating lifetimes have also been extended to 60 years in many cases.


As in many countries, the US has geopolitical concerns, and the significant rise in gas-fired capacity has exposed it to oil and gas price variations not previously encountered. As a result, there is strong support for new nuclear build and a number of policy instruments have been developed to facilitate the growth of nuclear energy, including federal loan guarantees and tax credits. Proposals have been tabled for over 46GW of new capacity, of which 1,180MW are under construction, and 11,000MW are planned with EPCs in place. With the exception of one project, all are on the shortlist for a federal loan guarantee, with one project having already been granted a guarantee. Our global nuclear model assumes that only the latter capacity will enter service in the next 15 years. Five technologies are present in the planned new build: Areva’s EPR, GE-Hitachi’s ABWR and ESBWR, Toshiba’s AP-1000 and MHI’s APWR. Of these, the GE Hitachi ABWR and the Toshiba AP-1000 already have design certification, but design modifications to the AP-1000 mean that a final safety evaluation is needed, which is likely in December 2010.

Lifetime extensions have been embraced …

… and new build is firmly on the political agenda — federal loan guarantees are on offer



North America

North America renewables Catharina Saponar, CFA +44 20 710 21231 / [email protected]

North America could be one of the most important growth regions for renewables globally. It has been characterised by stop-and-go growth in the past, mostly due to policy, legislation and regulation.

Investment themes and picks Growth in the US is, by a distance, the most important theme, even though we see momentum picking up in Canada, as well. Over the medium term, we see the recovery theme as the most important investment topic. Some important support schemes such as the investment tax credit and production tax credit have been renewed, or in the case of the renewable fuel standard, amended in 2008/09, and those are supportive of growth in the sector. But the impact of the recession has been profound, and a recovery from the dents into growth is the key topic.

Beyond this, yet also intricately connected and almost more important over the short and long term, are policy, legislation and regulation as sector drivers. While the Obama administration has brought about very important change in energy policy and the outlook for renewable energy, legislation is not in place firmly enough, in our view.

From those overarching themes, we see several sector drivers.

Recovery and new growth, principally of the solar and wind market

Competition within the manufacturing sector to capture growth

We see European and Asian names exposed to these themes.

Aside from large US developers, European wind developers are exposed to short-term weakness in the US PPA market, while the US market is a long-term growth driver. For them, the US accounts for over 50% of growth potential over the next five years. FPL (FPL US – N/R) is the most important name. Iberdrola Renovables (IBR SM – Reduce, TP: Eur 3.60), EDP Renovaveis (EDPR PL – Neutral, TP: Eur 7.85) and EDF EN (EEN FP – Neutral, TP: Eur 39) are all exposed.

Within wind turbine manufacturers, the European names have the largest exposure to the US, given their relationships with developers as well as the existing and growing manufacturing base. A recovery in order flow from the US is, in our view, one of the most important share price drivers for European wind turbine names, but less so for Asian names. GE (GE – US – N/R) has high levels of exposure. Vestas (VWS DC – Buy, TP: DKK 390) should be a prime beneficiary of order recovery, we believe.

Within solar, we see the potential market growth from the US as a positive driver across the sector. Our thesis that the global Tier 1 poly manufacturers have a sustainable competitive advantage holds for this market as well. MEMC (WFR US – N/R), Tokuyama (4043 JP - Neutral, TP: JPY 500) and Wacker Chemie (WCH GR – Buy, TP: Eur 145) are likely beneficiaries, in our view.

We also expect the wafer, cell and module segment to benefit from new growth, but anticipate very intense competition among US, Asian and European manufacturers. First Solar (FSLR US – N/R) should continue to benefit from utility scale solar build. Other beneficiaries are inverter manufacturers, Satcon (SATC US – N/R) and SMA (S92 GR – Buy, TP Eur 125) as well as manufacturing equipment manufacturers, in our view.

Long-term growth market; a weak year in 2010 with path to recovery in 2011. Legislation is paramount



Drivers of renewables build We see the drivers that will prevail for growth in renewable energy as follows

Regulation and policy imposing renewables obligations (State level RPSs) as a driver of base demand, as well as special stimulus packages as additional return drivers, eg the cash grant scheme.

Speculative demand from generators with the aim of diversifying their fuel mix away from an uncertain future of potentially high fossil fuel input costs may, in our view, only return over a longer-term horizon. A sizeable recovery in gas prices would be required to revive this renewable capacity merchant build as a demand driver.

The prospect of a carbon-constrained generation market over the long term. While legislation – and timing — are uncertain, it is reasonably likely, in our view, that carbon will eventually become a cost factor that generators will consider.

Return and economic consideration in high-priced electricity markets as long-term drivers.

Views on technologies Wind and solar will remain dominant technologies over the near and medium term.

Marine technology seems on the backburner despite large-scale development in earlier decades. We see growth in biofuels on the basis of the renewable fuel standards, but estimate the market to be in a situation of short-term overcapacity.

Wind

Within wind, onshore will likely prevail over at least the medium term. Potential is vast and the degree of market saturation low, with wind accounting for just 1.8% of energy produced in 2009. But we have also seen some momentum in the offshore market with the first sizeable projects reaching permitting milestones. While the sector is slow in the US over the short term, Canada is picking up momentum onshore and offshore with an ambitious capacity target and attractive feed-in tariffs in Ontario.

Solar

Utility scale solar pv and solar thermal currently dominate the solar segment, and we expect this to be the case over the short term. Considering the regulatory context for solar thermal in Spain as one of the first markets, we think that solar thermal could gain short-term momentum as developers shift their effort to the US market. Over the long term, the US solar thermal market might become one of the most important in the world, we believe, given the Southwestern deserts with some of the highest levels of irradiation globally and a vast space for large parks. We also expect growing adoption of commercial and residential rooftop solar pv over the medium term. Economic recovery will be an important driver.

Other technologies

Marine technology was taken to pre-commercial stages for some projects a few decades ago, but we perceive it to now be on the backburner when compared to other technologies. We see some growth for biofuels, driven by increasing renewable fuel standards, but estimate that the market is still in a situation of overcapacity.



Exhibit 304. North American energy mix 2006-30

0

200

400

600

800

1,000

1,200

1,400

1,600

2006 2015 2020 2025 2030

(GW) Coal OilGas NuclearHydro Biomass and WasteWind GeothermalSolar Tide and Wave

Source: IEA

Exhibit 305. US energy mix 2006-30

0

200

400

600

800

1,000

1,200

1,400

2006 2015 2020 2025 2030

(GW) Coal OilGas NuclearHydro Biomass and WasteWind GeothermalSolar Tide and Wave

Source: IEA

Developments and policies State level RPSs are the most important growth driver for renewables, in our view.

Weakness of electricity demand dilutes over the short term in some States.

Passage of energy and climate change legislation looks challenging.

2010 is a weak year for renewables with growth picking up from 2011; order momentum expected later in 2010

Ontario feed-in tariffs should drive wind and solar capacity growth in Canada

Exhibit 306. US wind development forecast

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

1998

A

2000

A

2002

A

2004

A

2006

A

2008

A

2010

E

2012

E

2014

E

2016

E

2018

E

2020

E

(MW)

(200)

0

200

400

600

800

1,000

(%)US Annual Wind Installations

%growth

Source: BTM Consult, GWEC, EER, EPIA, Photon and Nomura research

Exhibit 307. US solar development forecast

0

500

1,000

1,500

2,000

2,500

3,000

3,500

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

E

2011

E

2012

E

2013

E

2014

E

2015

E

(MW)

0

10

20

30

40

50

60

70

80

(%)USA Annual Solar Installations

% growth

Source: BTM Consult, EER, GWEC, EER, EPIA, Photon and Nomura research

We expect 2010 to be a weak and very back-end loaded year for renewables, but the strong long-term prospects should prop up interest and expectations of a 2011 pick-up. We see the following factors driving the market:

Most important, the timing and magnitude of electricity demand from the recession-induced demand destruction in the US to levels that imply new build requirement for utilities under their state RPS obligation. We think this could begin to come into play from late 2010. We look for consistent announcements of new PPAs by utilities and developers as the first indications. We think that this could also lead to a revival of wind turbine orders around the third or fourth quarters.

Energy legislation will be a share price and sentiment driver. If passed, it could lead to demand and order activity in our view from 2011, with wind being the most important beneficiary.



Economic recovery leading to housing activity will likely drive solar rooftop demand growth from 2011.

A recovery of commodity prices, ie gas, that would incite a revival of the merchant market for renewables build seems a much longer-term topic that we have not factored into our current expectations to a major extent.

Despite its having no direct production subsidies, the US market as the most important within North America, could be one of the most important renewables growth markets in the world, in our view. But growth over the near term depends strongly on policies and regulation.

In the broad absence of national regulation, state-level regulation and policy will in our view be the most important drivers of renewable energy. The most critical measures are renewables obligations (RPS) or goals for them, which are in place in 35 states. Most of them encompass renewables globally, but increasingly, they have carve-outs by technologies. As a result, they have so far been met mostly by wind, but as solar-carve-outs are increasing, we think that solar will increasingly take a share of RPS induced renewables build. We expect them be a growth driver not only as electricity demand grows, but also as the levels of RPS obligations are likely to increase over time according to our expectation. Short term, however, demand destruction resulting from the recession has been such that many utilities currently do not require new renewables capacity in order to comply with their RPS obligation for 2010. In some areas, this is also the case for 2011. We estimate that this is particularly evident in the Mid West, which has been hit hard by recession. Other strong RPS states around the East and West Coasts still seem to see capacity demand on the basis of RPS obligations. We estimate a demand recovery will eventually lead to new capacity build even in the states that are impacted more strongly, but this could take some time, into 2011.

Exhibit 308. US RPSs

Source: DSIRE

Beyond this, the cash grant scheme where developers can receive a 30% tax credit on their investment and convert this into a cash grant 60 days after commissioning of capacity, has sustained capacity build to a degree. We think that this will come into play more in the third and fourth quarters, as under the current programme, 5% will have to be invested by end-2010 for any project to be eligible before the scheme expires at the end of this year. An extension of the cash grant scheme could push things back, but if any, we would expect it to come very late in the year.



One of the most important topics in the North American market is energy and climate change legislation in the US. The long-expected energy bill was due to be passed in 2009 before Copenhagen and is one of the measures that should in particular drive wind demand growth on the basis of a national RPS and a carbon trading scheme. On our estimates, that would deliver incremental renewables demand in the States that do not have a state-level RPS. There could be a potential build requirement of 30-60GW over the long term, depending on the actual level of the RPS and to which extent it would have to be satisfied through new build or efficiencies and others. Beyond that, the prospect of a carbon-constrained world becoming reality, in our view, would lead to utilities building out renewable energy. We think that wind would be the prime beneficiary, due to its being scalable and competitive vs other renewable sources. But we would also expect large-scale solar to pick up as well.

The bill having slipped is one of the reasons behind the depressed wind turbine orders in the US, in our view, despite high levels of indicated interest as reported by the manufacturers. With other big legislative topics, healthcare and finances, now being largely out of the way, energy could be next on the agenda. But the contents of energy legislation are controversial, and mid-term elections are coming up in 4Q10. Thus, we perceive ambitions for passage of some legislation before the summer break or at least before the elections. Given the controversy around the various proposals, however, any bill may be heavily watered down. If a watered down bill does not come through either, an energy/climate change bill might slip into 2011 or later.

At the moment, two bills are active: The Waxman bill, which contains a national RPS of 20%, has passed the House, but seems to have little support in the Senate. The Kerry/Lieberman bill, which is currently in the Senate, does not contain an RPS and also encounters opposition on the proposed cap-and-trading scheme. We think that lack of support for the bills in their current form makes passage unlikely, also considering that reconciliation between the House and Senate bill would be required. This seems very difficult, in our view, given that we believe c 15 votes of the required 60 are not secured.

Exhibit 309. US energy legislation

Bill Chamber RPS Passed Notes

The Waxman Markey Bill - The American Clean Energy and Security Act

House of Representatives

√ √ Approved by the House on June 26, 2009 and is still in consideration in the Senate

The Kerry Lieberman Bill - The American Power Act

Senate × × Introduced in Senate. Includes a 17% reduction in CO2 emissions by 2020 from 2005 levels.

Source: US Senate sources and Nomura

Beyond this, we expect momentum in Canada to pick up on the basis of its good wind characteristics and attractive onshore and offshore as well as solar feed-in tariffs. Ontario is the most important province of development with a target of 4000MW of wind capacity by 2020, but Quebec (4600MW by 2016) and Alberta (2700MW over the next years) are also new growth spots.



Exhibit 310. Canada renewables targets and incentives

Solar Target Solar Incentives Wind Target Wind Incentives

Canada n/a Feed-in tariffs pay up to C$0.71/kWh over 20 years for roof-mounted solar PV systems, with lower payments for ground-mounted solar and other renewable energy technologies. Domestic content requirements of 50% for solar projects to be produced in Ontario

Provincial targets at to 12,000MW by 2014, CanWEA targets 55,000MW by 2025

Feed-in tariff (FiT) of C$1c/kWh for the first 10 years of production. Enacted in January 2007 and scheduled to run until March 2011.

Ontario n/a Feed-in tariffs range from C$0.802/kWh for residential rooftop projects <=10kW to a lowest of C$44.3/kWh for ground mounted systems >10kW. Duration: 20 years

4,000MW by 2020 Announced the ecoEnergy Renewable Power program in January 2007 to support the deployment of 4GW of renewable energy between 2007 and 2011. Government also has target for 90% of electricity to be generated from clean sources by 2020.

Onshore FiT: C$0.135/kWh for any size; Offshore FiT: C$0.19/kWh for any size.

The program has been extremely successful and all funding was fully allocated by early 2010, one year ahead of schedule. The government has been encouraged to extend the program as part of its 2010 Budget.

Source: GWEC



Japan

Japan alternative energy

Shigeki Matsumoto +81 3 5255 1605 / [email protected]

Promoting nuclear power and renewable energy

1) Periodic review of the basic energy plan

In June 2002, the Basic Law on Energy Policy came into force, based on the tenets of ensuring stable supply, meeting environmental requirements, and using market principles. Under the Basic Law on Energy Policy, the government draws up a basic energy plan that lays out long-term, comprehensive, and systematic policies for energy supply. The first basic energy plan was drawn up in October 2003. The law requires the basic energy plan to be revised as necessary at least every three years, and the first such revision took place in March 2007. Under the second and latest revision, the government has highlighted three main areas based on the legislation: 1) ensuring energy security; 2) tackling the global warming problem; and 3) looking to the energy and environment field as a key driver of economic growth.

The basic energy plan has to take into account both measures to prevent global warming (draft basic legislation on counteracting global warming was approved by the Cabinet in March 2010) and growth strategies. In December 2009, the Cabinet decided on a new basic growth policy, which is currently under discussion by the growth strategy planning committee of the National Policy Unit.

The plenary session and basic policy drafting session of the natural resources and energy committee were held on 19 April, with discussion on draft proposals to revise natural resource and energy policies as part of moves to revise the basic energy plan. On 27 May, a draft basic energy plan based on the content of this debate was put forward for public comment. Under the proposals, the energy supply targets for 2030 are twofold: 1) double energy self-sufficiency from the current 18% (4% from domestic sources of energy plus 14% from nuclear power) and the proportion of fossil fuels derived from Japanese-owned development interests from the current 26% (thereby raising the overall level of Japanese energy self-sufficiency from 38% to 70%, in line with the OECD average) and 2) increase the percentage of power generated from zero-emission power sources (nuclear power and renewables including hydroelectric power) to 70% (from 34% currently).

2) Raising energy self-sufficiency

Looking at the breakdown of Japan's primary energy supply, we can see that despite a decline in the percentage of oil in the wake of the 1973 oil shock, oil is still the energy source with the largest share, at 42% in FY08 (Exhibit below). As a result, energy prices in Japan tend to be at the mercy of fluctuations in the price of crude oil. Amid increasingly volatile crude oil prices, raising the proportion of energy supplied from sources besides oil, particularly from nuclear power, is likely to result in more stable domestic energy prices.

Revised policy puts emphasis on stable supply, tackling global warming and economic growth

Supply targets seek to raise energy self-sufficiency and power generated from zero-emission sources

Oil dependency still high



Exhibit 311. Breakdown of Japan's primary energy supply

0

10

20

30

40

50

60

70

80

90

100

73 79 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 (FY)

(%)

Oil Coal Natural gas Nuclear Hydroelectric Other

Note: (1) Calculation method changed from FY90 onward. (2) In FY73 and FY79 hydroelectric is included under the “other” category. (3) The “other” category includes renewable energy, etc.

Source: Annual Energy Report, Agency for Natural Resources and Energy

Japan imports almost all its fossil fuel (oil, natural gas, coal) requirements. In order to improve the stability of its energy supply, Japan needs to increase its independently developed energy interests while lowering its dependence on fossil fuels. By 2030, the government plans to increase its independently developed interests to more than 40% (from around 20% currently) for oil, over 60% (versus around 40% now) for coal, and over 50% (as against 26% currently) for fossil fuels. Trade from Japan's independently developed oil interests as a percentage of its total oil import volume is on an upward trend versus its 1973 level of 8%, but was still languishing at 16% in FY08 (Exhibit below).

Exhibit 312. Japan's independently developed oil interests

0

10,000

20,000

30,000

40,000

50,000

70 72 74 76 78 80 82 84 86 88 90 92 94 96 98 00 02 04 06 08 (FY)

('000kl)

0

2

4

6

8

10

12

14

16

18

20(%)Volume of trade from independently developed crude oil interests (lhs)

Percentage of independently developed oil interests (rhs)

Note: Figures from FY00 onward refer not to Japan's independently developed oil import volume as a percentage of total crude oil import volume but volume of trade from Japan’s independently developed oil interests as a percentage of total crude oil import volume.

Source: Agency for Natural Resources and Energy

Japan's energy self-sufficiency (excluding nuclear power but including hydroelectric power and the like) has dropped to 4% (FY07), which is well below the figures for other countries (Exhibits below). Almost all the uranium used as fuel in nuclear power is imported. However, once uranium has been imported it can be used for a long time, and as such, nuclear power can be regarded as quasi-domestic. Even including nuclear power, though, Japan's energy self-sufficiency is low by global standards. Note that energy self-sufficiency refers to the proportion of primary energy demand that can be secured domestically.

Toward expansion of independently developed fuel interests

Japan's energy self sufficiency low by global standards



Exhibit 313. Japan's energy self-sufficiency ratio

(6) (12) (15) (14) (15) (14)

57

146 5 4 4 4 40

10

20

30

40

50

60

1960 70 80 90 2000 05 06 07(CY)

(%)

12

1819181917

Note: Self-sufficiency figures shown are for the likes of hydroelectric power, geothermal power, and domestically produced coal and natural gas. Figures for nuclear power are shown in parentheses

Source: Energy Balances of OECD Countries 2004–2005, IEA

Exhibit 314. International comparison of energy self-sufficiency ratios

15 308

62 75 7691

144177

4 2

15 18 1941

5171 76 83

92

153

183

020

4060

80

100120

140160

180200

Ital

y

Jap

an

Ko

rea

Ge

rman

y

Fra

nce

US

Ind

ia

UK

Ch

ina

Ca

nad

a

Ru

ssia

(%)

Energy self-sufficiency (counting nuclear power as imported energy)Energy self-sufficiency (counting nuclear power as domestic energy source)+

Note: (1) Electric power imports/exports are counted as primary energy. (2) Amounts over 100% indicate exports.

Source: Energy Balances of OECD/Non-OECD Countries, 2006/07 (2009 Edition), IEA

3) Raising power generation from zero-emission sources

Zero-emission power sources accounted for 34% of Japan's total power generation in FY08, of which nuclear power accounted for 25.5% and hydroelectric and other 8.7% (hydroelectric 7.6%, new energy 1.1%) (Exhibit below). New energy includes wind power, solar power, biomass, waste material, and geothermal.

Zero-emission power generation reached 34% in FY08



Exhibit 315. Breakdown of power generation by power source in Japan

9 9 10

26 2941

0

10

20

30

40

50

60

70

80

90

100

1973 79 90 95 2000 01 02 03 04 05 06 07 08 09 10E 14E 19E(FY)

(%)

Hydroelectric, etc Nuclear LNG Coal Oil, etc

Note: Hydroelectric, etc = hydro + pumped storage + new energy.

Source: Energy in Japan 2010, The Electric Power Supply Plan, Agency for Natural Resources and Energy

In order to raise zero-emission power generation to 70%, the Japanese government plans to build new nuclear power facilities, increase deployment of existing facilities, and expand renewable energy (solar photovoltaic, wind power, geothermal power, hydroelectric power, biomass, heat pumps and other forms of aerothermal energy, solar thermal). As the term suggests, zero-emission power sources produce zero CO2 emissions from fuel combustion (Exhibit below). At the same time as helping to bring about a low-carbon economy, these power sources contribute to energy security.

Exhibit 316. CO2 emissions per unit of energy by power source

Life cycle CO2 emissions (g-CO2/kWh (transmission end))

111

130

38

88

408

478

704

887

11

15

22–25

29

53

0 200 400 600 800 1,000

Hydroelectric

Geothermal

Nuclear

Wind

Solar

LNG combined

Thermal (LNG)

Thermal (oil)

Thermal (coal)

Indirect emissions (during other life cycle phases)

Direct emissions (from combustion)

975

742

608

519

Note: 1) Indirect emissions occur during extraction of raw materials, construction of facilities, fuel transportation, etc. 2) nuclear power includes domestic reprocessing of spent fuel currently being planned, "pluthermal" use (assuming plutonium is recycled once), and highly radioactive waste disposal.

Source: Evaluation of Nuclear Power Generation Technology based on Life Cycle CO2 Emissions (August 2001) and Evaluation of Power Generation Technologies based on Life Cycle CO2 Emissions (March 2000), Central Research Institute of Electric Power Industry

Looking to raise power generation from zero-emission sources to 70%



Promoting nuclear power

1) Fourteen nuclear power plants are currently slated for construction in Japan

Nuclear power has been positioned as a core energy source that fulfils the energy policy targets of supply stability, meeting environmental requirements, and economic efficiency, and we think the government will strive hard to promote it.

The current target is to build nine new nuclear power plants (there were 54 in operation as of March 2010) and achieve a nuclear capacity factor of 85% (65.5% in FY09) by 2020F, and to build at least 14 new nuclear power plants (including the nine previously mentioned) and achieve a nuclear capacity factor of 90% by 2030F.

According to supply plans released by electric power companies in March 2010, 14 nuclear power plants are slated for construction in Japan. Chugoku Electric Power's Shimane No. 3 reactor (1.37mn kW advanced boiling water reactor [ABWR]), which has a scheduled commissioning date of December 2011, was 84.4% complete at end-April 2010, while Electric Power Development's Oma plant (1.38mn kW, ABWR), due to be commissioned in November 2014, was 13.4% complete. Construction of Japan Atomic Power's Tsuruga No. 3 reactor had yet to get under way as of end-May 2010.

Exhibit 317. Nuclear power plant construction plans

Plant Location Capacity Start of

Power company name (prefecture) Type ’000kW construction Startup

Chugoku Shimane Unit 3 Shimane ABWR 1,373 Dec 2005 Dec 2011

Electric Power Development Oma Aomori ABWR 1,383 May 2008 Nov 2014

Japan Atomic Power Tsuruga Unit 3 Fukui APWR 1,538 Oct 2010 Mar 2016

Tokyo Fukushima Daiichi Unit 7 Fukushima ABWR 1,380 Apr 2011 Oct 2016

Tokyo Higashidori Unit 1 Aomori ABWR 1,385 Dec 2010 Mar 2017

Japan Atomic Power Tsuruga Unit 4 Fukui APWR 1,538 Oct 2010 Mar 2017

Tokyo Fukushima Daiichi Unit 8 Fukushima ABWR 1,380 Apr 2012 Oct 2017

Chugoku Kaminoseki Unit 1 Yamaguchi ABWR 1,373 Jun 2012 Mar 2018

Chubu Hamaoka Unit 6 Shizuoka ABWR 1,400 class FY15 FY18–22

Kyushu Sendai Unit 3 Kagoshima APWR 1,590 FY13 FY19

Tokyo Higashidori Unit 2 Aomori ABWR 1,385 FY14 or later FY20 or later

Tohoku Namie Kodaka Fukushima BWR 825 FY16 FY21

Tohoku Higashidori Unit 2 Aomori ABWR 1,385 FY16 or later FY21 or later

Chugoku Kaminoseki Unit 2 Yamaguchi ABWR 1,373 FY17 FY22 Source: Nomura, based on company data

As shown in the Exhibit above, of the 14 planned nuclear power plants, 11 are boiling water reactors (BWRs) produced by Hitachi and Toshiba, which will have a total capacity of 14.64mn kW. The other three (4.67mn kW) are pressurised water reactors (PWRs), which are made by Mitsubishi Heavy Industries. In Japan, both BWRs and PWRs are in widespread use. Of the nine major power companies, Tokyo Electric Power, Chubu Electric Power, Tohoku Electric Power, Hokuriku Electric Power, and Chugoku Electric Power use BWRs, while Kansai Electric Power, Shikoku Electric Power, Kyushu Electric Power, and Hokkaido Electric Power use PWRs. Japan Atomic Power has both types of reactor.

The Toshiba group has a strong history of winning orders from Tokyo Electric Power, Chubu Electric Power, and Tohoku Electric Power for the construction of nuclear power plants (Exhibit below). These three electric power companies are due to build seven of the planned 14 reactors. Considering that the Toshiba group has already received the order for Electric Power Development's Oma plant, there is a possibility that Toshiba could win orders for up to eight reactors in the long term.

Importance of nuclear power

Target is to build 14 new plants and achieve nuclear capacity factor of 90% by 2030

Construction of two new plants has already begun

76% of new capacity due to be BWRs

Toshiba group could win lion's share of orders



Exhibit 318. Nuclear power plant construction history

Capacity Capacity

Company Plant name MW Commissioned Primary contractor Company Plant name MW Commissioned Primary contractor

Tokai (closed) 166 Jul 1966 GEC/SC Hamaoka 1

(closed) 540 Mar 1976 Toshiba

Tokai 2 1,100 Nov 1978 GE/Hitachi/Shimizu Hamaoka 2

(closed) 840 Nov 1978 Toshiba/Hitachi

Tsuruga 1 357 Mar 1970 GE Hamaoka 3 1,100 Aug 1987 Toshiba/Hitachi

Japan Atomic

Power

Tsuruga 2 1,160 Feb 1987Mitsubishi Heavy

Industries Hamaoka 4 1,137 Sep 1993 Toshiba/Hitachi

Tomari 1 579 Jun 1989Mitsubishi Heavy

Industries

Chubu

Hamaoka 5 1,380 Jan 2005 Toshiba/Hitachi

Hokkaido

Tomari 2 579 Apr 1991Mitsubishi Heavy

Industries Shika 1 540 Jul 1993 Hitachi

Onagawa 1 524 Jun 1984 Toshiba

Hokuriku

Shika 2 1,358 Mar 2006 Hitachi

Onagawa 2 825 Jul 1995 Toshiba Mihama 1 340 Nov 1970WH/MHI (nuclear power

division)

Onagawa 3 825 Jan 2002 Toshiba/Hitachi Mihama 2 500 Jul 1972MHI (nuclear power

division)

Tohoku

Higashidori 1 1,100 Dec 2005 Toshiba Mihama 3 826 Dec 1976 Mitsubishi Corp

Fukushima Daiichi 1 460 Mar 1971 GE Takahama 1 826 Nov 1974 WH/Mitsubishi Corp

Fukushima Daiichi 2 784 Jul 1974 GE/Toshiba Takahama 2 826 Nov 1975 Mitsubishi Corp

Fukushima Daiichi 3 784 Mar 1976 Toshiba Takahama 3 870 Jan 1985 Mitsubishi Corp

Fukushima Daiichi 4 784 Oct 1978 Hitachi Takahama 4 870 Jun 1985 Mitsubishi Corp

Fukushima Daiichi 5 784 Apr 1978 Toshiba Oi 1 1,175 Mar 1979 WH/Mitsubishi Corp

Fukushima Daiichi 6 1,100 Oct 1979 GE/Toshiba Oi 2 1,175 Dec 1979 WH/Mitsubishi Corp

Fukushima Daini 1 1,100 Apr 1982 Toshiba Oi 3 1,180 Dec 1991 Mitsubishi Heavy Industries

Fukushima Daini 2 1,100 Feb 1984 Hitachi

Kansai

Oi 4 1,180 Feb 1993 Mitsubishi Heavy Industries

Fukushima Daini 3 1,100 Jun 1985 Toshiba Shimane 1 460 Mar 1984 Hitachi

Fukushima Daini 4 1,100 Aug 1987 Hitachi Chugoku

Shimane 2 820 Feb 1989 Hitachi

Kashiwazaki-Kariwa 1 1,100 Sep 1985 Toshiba Ikata 1 566 Sep 1977 Mitsubishi Heavy Industries

Kashiwazaki-Kariwa 2 1,100 Sep 1990 Toshiba Ikata 2 566 Mar 1982 Mitsubishi Heavy Industries

Kashiwazaki-Kariwa 3 1,100 Aug 1993 Toshiba

Shikoku

Ikata 3 890 Dec 1994 Mitsubishi Heavy Industries

Kashiwazaki-Kariwa 4 1,100 Aug 1994 Hitachi Genkai 1 559 Oct 1975 Mitsubishi Heavy Industries

Kashiwazaki-Kariwa 5 1,100 Apr 1990 Hitachi Genkai 2 559 Mar 1981 Mitsubishi Heavy Industries

Kashiwazaki-Kariwa 6 1,356 Nov 1996 Toshiba/GE/Hitachi Genkai 3 1,180 Mar 1994 Mitsubishi Heavy Industries

Kashiwazaki-Kariwa 7 1,356 Jul 1997 Toshiba/GE/Hitachi Genkai 4 1,180 Jul 1997 Mitsubishi Heavy Industries

Kawachi 1 890 Jul 1984 Mitsubishi Heavy Industries

Tokyo

Kyushu

Kawachi 2 890 Nov 1985 Mitsubishi Heavy Industries Source: Nomura, based on Nuclear Power Pocket Book, 2009 edition

2) Demand for construction of new plants likely to increase

Hokkaido Electric Power completed its Tomari No. 3 reactor (0.912mn kW capacity) in 10/3. No new nuclear power plants are scheduled for completion in 11/3, but the total output of nuclear power plants due to come on stream is 1.37mn kW in 12/3, zero in 13/3 and 14/3, 1.38mn kW in 15/3, 1.54mn kW in 16/3, 4.3mn kW in 17/3, 2.75mn kW in 18/3, 1.4mn kW in 19/3, 1.59mn kW in 20/3, 1.385mn kW in 21/3, 2.21mn kW in 22/3, and 1.37mn kW in 23/3 (Exhibit below). While construction plans vary considerably from year to year, construction plans for some years exceed the recent peak years of 06/3, 98/3, and 94/3, when 2.46mn kW, 2.54mn kW and 3.96mn kW of nuclear capacity, respectively, were completed.

Plant completions in some years likely to exceed recent highs



Exhibit 319. Nuclear power plant capacity completed each fiscal year

Est

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

70/3 75/3 80/3 85/3 90/3 95/3 00/3 05/3 10/3 15/3E 20/3E(yy/m)

(MW)

Source: March 2010 supply plans

By FY22F, when the abovementioned 14 nuclear power plants should all have started commercial operation, nuclear power generating capacity should have risen by 19.6GW (40%) from 48.8GW at end-10/3 to 68.4GW (Exhibit below).

Exhibit 320. Nuclear power capacity in Japan should increase to 68.4GW by FY22F

Est

0

10

20

30

40

50

60

70

70/3 75/3 80/3 85/3 90/3 95/3 00/3 05/3 10/3 15/3E 20/3E(yy/m)

(GW)

7

Source: March 2010 supply plans

Due to percentage-of-completion-basis accounting, we think companies such as Toshiba Plant Systems & Services, which handle on-site construction (installation, in many cases involving subcontracting), book nuclear power plant construction orders as sales over around three years. The Exhibit below shows sales where sales (nuclear power plant output) are booked equally from three years previously, including the year of completion. We expect sales in the plant sector to switch to growth from 14/3 and peak in 16/3. We think majors (prime contractors) such as Mitsubishi Heavy Industries book sales over around five years.

Nuclear capacity in 2022F should be 40% higher than at end-March 2010

Plant manufacturers’ sales volume should also increase



Exhibit 321. Sales volume at plant companies (1)

Est

0

200

400

600

800

1,000

1,200

68/3 73/3 78/3 83/3 88/3 93/3 98/3 03/3 08/3 13/3E 18/3E 23/3E(yy/m)

(MW)

Note: 68/3 figures are output of nuclear power plants completed in FY67–69 ÷ 3.

Source: Nomura

Exhibit 322. Sales volume at plant companies (2)

Est

0

50

100

150

200

250

300

350

400

450

500

66/3 71/3 76/3 81/3 86/3 91/3 96/3 01/3 06/3 11/3E 16/3E 21/3E(yy/m)

(MW)

Note: 66/3 figures are output of nuclear power plants completed in FY65–69 ÷ 5.

Source: Nomura

3) Capacity factor improvement measures: lengthening operating cycles and shortening scheduled inspections

Japan's nuclear capacity factor has been lower than that of the US since 1999 (Exhibit below). This partly reflects extended shutdowns due to earthquake-proofing and equipment trouble. But under Japan's current system, the ceiling for the capacity factor is 80-85%, even with plants operating smoothly — short of the more-than-90% recorded in the US.

Nuclear capacity factor lower in Japan than US



Exhibit 323. Nuclear capacity factor lower in Japan than in the US

Nuclear capacity factor

0

10

20

30

40

50

60

70

80

90

100

70 75 80 85 90 95 00 05

(US: CY, Japan: FY)

(%)

US

Japan

Source: Nomura, based on NEI data, etc

With the aim of bringing the nuclear capacity factor into line with the US level, the Japanese government is seeking to extend the average operating cycle of nuclear plants to at least 18 months by 2030F (versus a maximum of 13 months at present) and to keep plant shutdowns caused by scheduled inspections to within an average of around two months. In theory, uninterrupted operation of 18 months followed by a two-month shutdown would bring the capacity factor to 90% (= 18 months ÷ (18 months + 2 months).

Japan introduced a new inspection regime in January 2009 with the aim of conducting more detailed inspections of individual plants in accordance with their age and the type of facilities and equipment, instead of performing uniform inspections for all nuclear plants. Under the current system, nuclear reactors are shut down every 13 months for inspection, but electricity companies will be able to extend this to 18 or 24 months if they deem such intervals between inspections to be appropriate. A prerequisite for gaining approval from local citizens and governments is stable operation of the nuclear plant for at least the current 13-month average.

To support activities aimed at improving understanding of the new inspection regime, the central government will pay a subsidy of ¥20mn per year over five years to local government jurisdictions in which nuclear plants are located, provided electricity companies seek approval to amend their security regulations relating to the extension of nuclear reactor shutdowns before end-FY13F.

In connection with these subsidies paid to local governments, the central government is considering measures that would promote new capacity expansion and equipment replacement at nuclear plants. The subsidy scheme was established to facilitate at the local level the installation of new facilities. At the same time, its aim is to ensure smooth plant operation, as stipulated in the Law on the Development of Areas Adjacent to Electric Power Generating Facilities. Accordingly, the basic concept is that more subsidy payments are made to the governments of regions where the most power is produced, with the result that plants that generate high volumes of power gain more understanding from the regions in which they are located. While subsidy payments are calculated based on production capacity and the volume of power generated, the government is looking to place a greater weight on the latter (equivalent to the nuclear capacity factor).

The nuclear capacity factor in the US was less than 60% in the 1980s. It rose to 66% in 1990, 77% in 1995 and 90% in 2002. We believe this increase reflected efforts to lengthen the operating cycle of plants and shorten scheduled inspections. The average operating cycle used to be around 12 months for reasons of fuel design. Fuel (some or all) was replaced each time a plant was shut down for a scheduled inspection, while fuel was also repositioned inside reactors to raise combustion efficiency. As a result of

Key goals are to lengthen operating cycles and shorten scheduled inspections

Possibility of a maximum operating cycle of 24 months in long term

Subsidy scheme supports new inspection regime

Strengthening correlation between subsidy payments to local governments and volume of electricity generated

Process by which capacity factor improved in the US



improved fuel performance since then, nuclear plants are able to operate uninterrupted for 18 months, and in some cases as long as 30 months (Exhibit below).

Exhibit 324. Country regulations government nuclear plant operation

US France Finland Korea Japan

Regulations on intervals between nuclear reactor shutdowns

Maximum of 30 months

Generic Letter 91-04 rules that maximum interval can be extended to 30 months

Nothing stipulated by law

Determined by approval of fuel management plan after fuel replacement

12-month and 18-month management methods allowed at present

Nothing stipulated by law

Maintenance required once every 2 years

12-month operation chosen for economic reasons

Maximum of 20 months

Governed by Article 19 of Enforcement Regulations

Maximum 13 months Governed by Article 54 of

Electricity Business Law and Article 91 of Enforcement Regulations

Max 26 months 23 months 13 months 17 months 16 months Shutdown intervals

Avg 18.8 months 12.8 months 12 months 15.1 months 13.6 months

Measures to extend intervals between shutdowns

No particular plans Interval for 1,300MWe reactors changed from 18 months to 15–21 months

Proposed change for N4 reactors from 12 to 17 months currently under discussion

24 months planned for EPRs to be newly introduced

No particular plans

Plans being discussed based on September 2006 document on improving the inspection regime for nuclear reactor facilities

Average operating cycle / inspection period

18.1 months / 44 days 14.1 months / 43 days 11.9 months / 12 days 11.5 months / 79 days 11.5 months / 98 days

Note: Interval between shutdowns is for period from 2002 to 2004 (from IAEA's PRIS database).

Source: Nuclear and Industrial Safety Subcommittee (24 August 2007), Federation of Electric Power Companies of Japan (28 September 2007)

The duration of scheduled inspections averaged 79 days in the 1990s (range of 40-106 days) but this was reduced to 39 days (range of 33-44 days) in the 2000s (Exhibit below). The main reason is that some tests conducted during shutdowns were replaced by online maintenance during plant operation.

Exhibit 325. Comparison of durations for nuclear plant shutdowns in Japan and US

0

50

100

150

200

250

90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 (FY)

(No. of days)

US Japan

Note: 1) Data for Japan are for the period from start to end of regular inspections (general load performance inspections). 2) Mihama No. 2 reactor excluded from FY94 data, Fukushima No. 1 reactor from FY05 data, and Mihama No. 3 reactor from FY06 data. 3) Japanese data for FY09 are currently being collated. 4) US data represent the average length of refueling outages for nuclear plants.

Source: US Nuclear Generating Statistics, Japan Nuclear Energy Safety Organization

The Agency for Natural Resources and Energy estimates that Japan's nuclear capacity factor would improve from 70% to 77% if the average operating cycle were to be increased from 13 months to 19 months as in the US, and from 70% to 87% if the duration of scheduled inspections were to be shortened from 143 days to 38 as in the US (Exhibit below). Reducing the average number of days a reactor is closed due to

Shortening scheduled inspections

Capacity factor in Japan could exceed 90% if same standards as US were adopted



an operational incident from 34 in Japan to 4.7 as in the US would, according to the agency, improve the capacity factor further from 87% to 93%. Extending the operating cycle to 24 months could increase the capacity factor to as high as 95%. The above Japanese data mainly relates to the operating cycle in which most plants underwent scheduled inspections in 2007-08 (with the exception of Chubu Electric Power's Hamaoka No. 1 and No. 2 reactors, which were scrapped after long-term shutdowns, and plants that faced long-term shutdowns as a result of the Niigata-Chuetsu earthquake).

Exhibit 326. Capacity factor calculation assuming similar standards to US were adopted in Japan

No. of Average

operating cycle

Average inspection

duration No. of shutdown

days Capacity factor

reactors months/reactor days/reactor days/reactor (%)

US 103 About 19 About 38 About 4.7 About 93

Japan 53 About 13 About 143 About 34 About 70

Assuming operating cycle extended to match US (a) 53 19 143 34 About 77

Assuming inspection days reduced to match US (b) 53 13 38 34 About 87

Assuming (a), (b) and same no. of shutdown days caused by operational problems as in US

53 19 38 4.7 About 93

Assuming extension of operating cycle to 24 months 53 24 38 4.7 About 95 Note: 1) Capacity factor = (average operating cycle for one reactor – average days of shutdown) ÷ (average operating cycle for one reactor + average days of shutdown). 2) Operating cycle is the period from the startup of a nuclear reactor for trial operation during inspection until shutdown for the next inspection. 3) Data exclude inspections of the Hamaoka No. 1 and No. 2 reactors that were scrapped after long-term shutdowns. Plants closed for long periods due to the Niigata-Chuetsu earthquake also excluded. 4) Data for each plant relate to the operating cycle in which most plants underwent scheduled inspections in 2007–2008.

Source: 22nd Nuclear Energy Subcommittee (5 March 2010)

Like the US, the operating cycle is longer in Korea than in Japan while the duration of scheduled inspections is shorter. Operating cycles average about 12 months in Finland and France, similar to Japan, but scheduled inspections are shorter. France implements load follow operations (cutting power output when demand is declining), so its capacity factor appears lower.

4) Boost to profits from improvement in nuclear capacity factor

The greater their reliance on nuclear power, the bigger the impact on electric power companies when the nuclear capacity factor rises. In the long term (ie, according to our 20/3 forecast), we think Kansai Electric Power and Tokyo Electric Power will depend heavily on nuclear power, with respective exposures of 50% and 48% (Exhibit below). Although it depends on fuel prices and the mix of alternative fuels, we estimate that a 1pp improvement in the nuclear capacity factor would reduce fuel costs by ¥7.1bn at Kansai Electric Power and by ¥12.0bn at Tokyo Electric Power).

Exhibit 327. Long-term reliance on nuclear power

50 4844

40 40 40 38

30 28

0

10

20

30

40

50

60

Kansai Shikoku Hokkaido Kyushu Chubu

(%)

Note: 20/3 estimates.

Source: Nomura

Comparison with other countries

The greater the reliance on nuclear power, the bigger the impact of improvements in the capacity factor



Exhibit 328. Impact of change in nuclear capacity factor on profits

0

2

4

6

8

10

12

14

Tokyo Kansai Hokuriku Shikoku Hokkaido

(¥bn)

Note: 1) Adjusted for power interchanges with other utility companies. 2) Figure for Hokkaido Electric Power includes Tomari No. 3 unit. 3) Assumes crude oil price of US$85/bbl and yen/dollar rate of US$1/¥90. 4) Coal included as an alternative fuel.

Source: Nomura

Assuming a nuclear capacity factor of 81% (five-year average of industry as a whole through 02/3), we estimate adjusted recurring profits (excluding factors likely to drop out over the medium term, such as gains/losses under the fuel cost adjustment system) for 11/3 of ¥456.3bn at Tokyo Electric Power and ¥215.0bn at Kansai Electric Power (Exhibit below). If we were to raise our capacity factor assumption to 90% and assume sensitivity as shown in the Exhibit at the top of the following page, then we would need to revise up our adjusted recurring profit estimates by 24% for Tokyo Electric Power and by 30% for Kansai Electric Power.

The profit sensitivity in the first Exhibit on the next page is that for when the nuclear capacity factor is raised above the normal 81%, while that in the second Exhibit is for when the capacity factor returns to normal. The mix of substitute fuels used differs in each case.

Exhibit 329. Adjusted EPS estimates

[9501] [9502] [9503] [9506] [9508]

TokyoElectric Power

ChubuElectric Power

Kansai Electric Power

TohokuElectric Power

KyushuElectric Power

Recurring profits (11/3E) A 208.1 118.1 156.0 41.1 55.7

Nuclear power capacity factor (11/3E, %) B 63 73 76 71 80

Normal (%) C 81 81 81 81 81

Sensitivity D 11.6 2.8 7.6 0.9 4.1

Fuel cost reductions ((C-B)*D) E 213.5 22.7 39.4 9.0 5.7

Fuel cost adjustment, actuarial differences, depreciation, other

F 141.6 71.5 22.5 35.9 35.7

Other G (106.9) (26.4) (2.9) 18.7 (0.5)

Adjusted recurring profits (A+E+F+G) 456.3 185.9 215.0 104.8 96.6

Adjusted EPS (¥) 205 139 148 117 120 Note: 1) Normal nuclear power plant capacity factor is average for FY97–01. 2) Decrease in fuel costs is based on crude oil price of $85/bbl and exchange rate of $1/¥90. 3) Sensitivity refers to Nomura estimate of impact on annual fuel costs of every 1ppt fluctuation in nuclear capacity factor. (4) We reversed amortization of residual book value stemming from 08/3 revisions to tax law. 5) For Tokyo Electric Power, other (i) includes the partial reversal of the sudden reduction in costs arising from the closure of the Kashiwazaki-Kariwa nuclear power plant; and (ii) excludes the proportion of the reduction in fuel costs corresponding to electricity sold to Tohoku Electric Power. 6) For Chubu Electric Power, other refers to emission credit costs arising from the closure of the Hamaoka No. 1 and No. 2 reactors. 7) For Kansai Electric Power, other refers to fuel cost reductions due to new power supplies and net CO2 emission credit costs. 8) For Tohoku Electric Power, other assumes that one-time increases in costs will decline over the medium term. 9) For Kyushu Electric Power, other assumes a normal capacity factor of 83% (because company’s nuclear power capacity factor is the most stable in the sector) and the net value for fixed cost reactionary growth risk.

Source: Nomura

We define fuel cost savings as decline in fuel consumption volume × average fuel price. As such, the higher fuel prices rise and the weaker the yen becomes, the greater the fuel cost savings. Assuming a $10/bbl rise in the price of crude oil, we estimate that Tokyo Electric Power's sensitivity (change in recurring profits with each 1pp shift in

Profits assuming achievement of 90% nuclear capacity factor

Capacity factor determines the mix of substitute fuels used

The higher fuel prices are, the greater the impact of improvements in nuclear capacity factor



nuclear capacity factor) would increase from ¥12.0bn to ¥13.4bn, while a ¥5 weakening in the value of the yen against the dollar would increase it from ¥12.0bn to ¥12.8bn (Exhibit below).

Exhibit 330. Rise in crude oil prices, yen depreciation enhances impact of improvement in nuclear power capacity factor

Change in sensitivity with each $10/bbl rise in crude oil price

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

Tok

yo

Chu

bu

Kan

sai

Chu

goku

Hok

urik

u

Toh

oku

Shi

koku

Kyu

shu

Hok

kaid

o

(¥bn)

Change in sensitivity with each ¥5depreciation against the dollar

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

Tok

yo

Chu

bu

Kan

sai

Chu

goku

Hok

urik

u

Toh

oku

Shi

koku

Kyu

shu

Hok

kaid

o

(¥bn)

Note: 1) Adjusted for power interchanges with other utility companies. 2) Figure for Hokkaido Electric Power includes Tomari No. 3 unit. 3) Change relative to base assumptions of US$85/bbl for crude oil price and US$1/¥90 for yen/dollar rate. 4) Coal included as an alternative fuel.

Source: Nomura

5) Increasing rated output at nuclear power plants

Increasing power generation at nuclear power plants is possible via uprates (increases in rated output) as well as by improving nuclear capacity factors. Uprates totaling 5,726MW were approved in the US in 1977-2014, of which 5,696MW has been implemented (Exhibit below). This equates to the same amount of electricity generation as building five new 1MW power plants. Uprates of 2,629MW are planned for 2010-14F.

In Japan, there are plans to carry out uprate work during the scheduled inspection of Japan Atomic Power's Tokai No.2 unit in FY12.

Exhibit 331. Uprates in US

Cumulative RHS)

0

200

400

600

800

1,000

1,200

77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 09

(CY)

(MWe)

0

1,000

2,000

3,000

4,000

5,000

6,000(MWe)

Source: Nuclear Regulatory Commission

6) Improvement in capacity factor can also impact on overseas orders

Low nuclear capacity factors in Japan are cited as one reason for Japanese companies missing out on the order for constructing a nuclear power plant in the United Arab Emirates (UAE). We think countries introducing new nuclear power facilities use capacity factors as one indicator to assess the reliability of equipment.

US has strong track record in uprates

Uprates in Japan

Low nuclear capacity factor a reason for Japanese companies missing UAE order?



According to the Agency for Natural Resources and Energy, the lesson to be learned from the UAE nuclear project is that Korean companies were successful because a state-run electricity company was leading the team (Exhibit below). The Korean consortium moreover agreed to a long-term (60-year) contract to run and maintain the facilities (we estimate this is worth around US$20bn in addition to the plant construction order) and to provide comprehensive support, including training staff. In addition, the Koreans were able to take quick decisions in response to various and abrupt changes in requirements and orders by the UAE side.

Exhibit 332. Order setup for UAE project

US-Japan team SPC(CEO Hitachi)

Hitachi, JGC,Kajima, M arubeni

Exelon(TEPCO)

General Electric

P lant construction Operational support Fuel provision

Korean team Korea Electric Power

Doosan Heavy Industries, Hyundai Engineering and

Construction, etcKorea Electric Power

Korea Electric Power

Plant construction Operational support Fuel provision

French team SPC(leader changed from Areva to EDF during bid)

Areva(public nuclear

power company)

EDF(public electricity company),

GDF Suez

Areva

Plant construction Operational support Fuel provision

Source: 23rd meeting of Nuclear Power Subcommittee (29 March 2010)

By contrast, the US-Japan team centred on a manufacturer (Hitachi). This was a one-off consortium of private companies, so adjustment costs among those involved were also substantial. Support for running the facility was to be provided by a US electric power company.

The French team apparently changed the lead company from a manufacturer (Areva) to EDF, the French publicly-owned electricity company, on the directions on President Sarkozy, but still failed to win the order.

We estimate the contracted amount to construct the facilities (four reactors for around US$20bn) was more than 20% lower than the bids submitted by the French and US-Japan teams. We think that the state-run company at the lead of the Korean bid has taken on the risk of private companies being unable to cope with unexpected cost increases or damages from works being delayed.

The following Exhibit shows the issues the Agency for Natural Resources and Energy sees for Japan in pursuing orders from countries introducing new nuclear power facilities.

Having state-run company in the lead one factor behind successful Korean bid

Manufacturer at core of US-Japan team

French bid also initially centred on manufacturer

Having state-run company as leader means greater risk tolerance

Lessons learned



Exhibit 333. Issues for Japan when bidding on overseas nuclear power projects

Source: 23rd meeting of Nuclear Power Subcommittee (29 March 2010)

At the end of April, Tokyo Electric Power, Kansai Electric Power, Chubu Electric Power, Toshiba, Hitachi, and Mitsubishi Heavy Industries agreed to establish a joint venture to work to win orders for nuclear power facilities overseas. We think the government will provide support so that private companies will not have to shoulder damages from delays on their own. The aim is to secure orders based on a public-private partnership, learning from the experience of losing out to the Korean bid for the UAE project. The near-term target appears to be the second phase of Vietnam’s nuclear energy project in Ninh Thuan Province.

Establishing consortium with view to winning orders for second phase of Vietnam’s nuclear energy project

Korea built unified structure whereby team was led by state-run Korea Electric Power and work subcontracted to manufacturers.

Manufacturers in Russian and French teams are themselves state-run.

Unified structure in all these cases means major risk-taking is possible

Under previous system centring on manufacturer, ability to makedecisions was insufficient, making it impossible to respond quicklyto various needs of customers.

Need for a unified structure centering around electric power company.

Scope for risk-taking was limited under previous system.

Need for risk dispersal among companies involved and review of scope for risk-taking by public institutions.

Also need to improve price competitiveness of companies involved.

Overall measures need to be strengthened, including forsupporting industries.

Need to train staff in countries introducing new facilities as in Japan.Also pressing need to train staff in Japan able to develop business overseas.

Need to conclude nuclear power agreements with countries introducingnew nuclear facilities, such as Vietnam.

Prompt consideration for creation of international framework forcompensation for nuclear damage via the CSC (Convention onSupplementary Compensation for Nuclear Damage).

Need for ability and system to provide packages meeting needs of partnercountries, including provision of infrastructure and new technology.

Countries such as US, France, Russia and Korea have already concluded nuclear power agreements with many of the major countries looking to introduce new nuclear power facilities.

In UAE project, Korea cooperating on staff training, renewable energy, etc.

Russia selling submarines to Vietnam.

1. Order setup

2. Price/risk-taking ability

3. Staff training, structural development

4. Ability to provide packages meeting needs of partner countries



Maintenance, heavy machinery companies poised to benefit

1) Fourteen nuclear power plants are currently slated for construction in Japan

Increased capital spending by electric power utilities benefits the sales and operating profits of shipbuilding/heavy machinery companies that build thermal and nuclear power plants, other capital goods companies, and electric power plant maintenance companies. We expect a boost to earnings at valve manufacturers and plant maintenance companies with a high weighting of sales to electric power companies.

We are focusing on two valve manufacturers that also provide maintenance services, Okano Valve Mfg. and Toa Valve Engineering, and two plant maintenance companies, Toshiba Plant Systems & Services and Tokyo Energy & Systems. These companies generate more than half of their total sales from electric power companies (10/3 estimates) (Exhibit below).

The two valve manufacturers — Okano Valve Mfg. and Toa Valve Engineering — derive more than 60% of their sales from electric power companies with nuclear plants. The two do not provide a break up of margins by product application, thermal versus nuclear power, but we think the margins on nuclear plant valves, which have stringent safety and reliability requirements, are higher than those on thermal and wind power plant valves. The two main types of nuclear power reactors are boiling water reactors (BWR) and pressurized water reactors (PWR). Equipment suppliers generally specialise in one type or the other (Exhibit on next page).

Exhibit 334. Weighting of sales to electric utilities at capital goods companies (10/3 estimates): valve suppliers, maintenance companies lead the pack

0 20 40 60 80 100 120

[6501] Hitachi

[5631] Japan Steel Works

[6502] Toshiba

[7011] Mitsubishi Heavy Industries

[1983] Toshiba Plant Systems & Services

[1968] Taihei Dengyo

[1945] Tokyo Energy & Systems

[6466] Toa Valve Engineering

[6492] Okano Valve Mfg

(%)

Nuclear power

Thermal power, other types

Source: Nomura, based on company data (ranked according to sales exposure to nuclear power)

Beneficiaries of investment growth

Toshiba Plant Systems & Services

Valve manufacturers with high proportions of sales to nuclear power industry



Exhibit 335. Division of work related to Japan's PWR and BWR nuclear power plants

Electric power Main Parts and Secondary Temperature Damage Pressure

Plant type company contractor processing work Cooling Valves control devices inspection vessels

PWR Kansai, Hokkaido, Shikoku, Kyushu, Japan Atomic Power

Mitsubishi Heavy Industries [7011]

Mitsubishi Heavy

Industries [7011]

Taihei Dengyo [1968]

Shinryo (unlisted)

Toa Valve Engineering

[6466]

Okazaki Mfg (unlisted)

Hihakaikensa (unlisted)

Tokyo, Chubu, Chugoku, Hokuriku, Tohoku, Japan Atomic Power

Hitachi [6501] Hitachi [6501] Hitachi Plant Technologies

(unlisted)

Hitachi Plant Technologies

(unlisted)

Kourin (unlisted)

BWR

Tokyo, Tohoku, Chubu, Japan Atomic Power

Toshiba [6502] IHI [7013] Toshiba Plant Systems &

Services [1983]

Shin Nippon Air Technologies

[1952]

Okano Valve Mfg

[6492]

Sukegawa Electric [7711]

Japan Steel Works [5631]

Note: Corporate relationships shown are not necessarily applicable to all nuclear power equipment in Japan.

Source: Nomura

Okano Valve, Toa Valve, and Teikoku Electric Mfg. (an equipment supplier) benefit in terms of new sales when nuclear power plants are built and from maintenance demand afterward. They are also likely to generate sales to overseas nuclear power plants over the medium term.

Okano Valve is a leading Japanese manufacturer of BWR valves, while Toa Valve is a leading Japanese manufacturer of PWR valves.

Teikoku Electric, one of the world’s leading canned motor pump manufacturers, has a track record of supplying pumps for nuclear power plants and has a higher share of the US market. The construction of new nuclear plants in China and other countries should be a longer term boon.

As new nuclear plants are built in Japan over the medium term, power plant maintenance companies are likely to increase their plant project revenues as well as maintenance revenues. A number of companies are considering working on new nuclear plants overseas, and Toshiba Plant is considering hiring more engineers and forming a US subsidiary.

Mitsubishi Heavy Industries and IHI generate only 5–19% of their sales from Japanese electric power companies, less than the valve manufacturers do, but these two companies still stand to benefit from increased capital spending by the electric power industry.

Mitsubishi Heavy supplies Japanese electric power companies with nuclear plant and equipment, gas turbines, steam turbines and boilers. Sales to Japanese electric power companies in 10/3 totaled an estimated ¥500bn (17% of total sales), of which we estimate ¥200bn was for nuclear power generation, mainly service.

Mitsubishi Heavy has very strong technologies for large gas turbines. It is one of the world’s leading manufacturers of the turbines, along with GE, Siemens, and Alstom. A pickup in spending on large gas turbines for power generation by Japanese electric power companies would benefit Mitsubishi Heavy’s sales.

IHI supplies Japanese electric power utilities with boilers and nuclear power equipment (eg, pressure containers). Japan’s electric power industry accounted for about 8% of the company’s 10/3 sales.

IHI supplies Toshiba with pressure containers for nuclear power plants. Since Toshiba manufactures BWRs, Tokyo Electric Power’s Nos. 7 and 8 Fukushima and Nos. 1 and 2 Higashidori nuclear plants, which all use BWRs, might use IHI’s pressure containers.

Other suppliers of nuclear plant equipment are shown in the Exhibit below. Japan Steel Works is very competitive globally in the market for pressure container materials. Worldwide oil and natural gas plant-related orders have been slow to rebound because of the yen’s strength against the euro, but the company is likely to benefit from increased capital investment in nuclear power by power companies in Japan as well as China and other countries.

Okano Valve benefits from new construction, maintenance

Nuclear plant valve manufacturers

Manufacturer of canned motor pumps for nuclear plants

Maintenance companies also likely to get new business

Mitsubishi Heavy stands to benefit from increased capital spending by the electric power industry

17% of Mitsubishi Heavy’s sales from Japanese electric power industry

Gas turbines constitute an area of strength

IHI supplies boilers and nuclear power equipment

Sales of nuclear plant equipment to Toshiba

Nuclear plant equipment suppliers also likely to benefit



Exhibit 336. Leading companies’ electric and nuclear power-related sales (10/3 estimates)

% of sales

Market cap

(6 Apr)Electric

power cosNuclear

plants

Code Company Rating (¥bn) (%) (%)

6492 Okano Valve Mfg Buy 16.6 97 63

6466 Toa Valve Holding Buy 6.4 98 60

1945 Tokyo Energy & Systems No rating 24.7 85 37

7711 Sukegawa Electric No rating 4.1 36 36

1983 Toshiba Plant Systems & Services Buy 103.5 57 25

1968 Taihei Dengyo No rating 36.4 75 24

6378 Kimura Chemical Plants No rating 18.1 17 17

6356 Nippon Gear No rating 5.7 18 15

6365 DMW No rating 7.9 15 12

1952 Shin Nippon Air Technologies No rating 16.1 9 9

6502 Toshiba Buy 2,093.4 20 9

7011 Mitsubishi Heavy Industries Neutral 1,319.1 36 9

5631 Japan Steel Works Neutral 399.3 16 7

6368 Organo No rating 37.0 11 5

7013 IHI Neutral 245.0 12 4

1976 Meisei Industrial No rating 16.1 5 4

1963 JGC Buy 439.9 6 3

6361 Ebara Neutral 210.1 2 2

6486 Eagle Industry No rating 34.1 3 2

6333 Teikoku Electric Mfg Neutral 18.7 9 2

6501 Hitachi Buy 1,660.8 8 2

6247 Hisaka Works Buy 30.6 3 1

6370 Kurita Water Industries Buy 353.9 1 1

5480 Nippon Yakin Kogyo No rating 45.1 6 1

5333 NGK Insulators Neutral 633.9 32 0 Source: Nomura (includes estimates by Nomura)



Measures to expand renewable energy Renewable energy has cost and supply stability issues, but its usage has been encouraged because: 1) its environmental impact is low; 2) for the most part it can be procured domestically; and 3) it can create jobs and new markets.

1) Limited scope for expansion of wind power

Japan’s installed wind power generating capacity was 1,900MW as of end-2008, ranking it 13th in the world. Japan has less land than Europe or the US and its geography is more challenging for wind power installations, on top of systemic limits at electric power companies (Exhibits below).

Exhibit 337. Japan’s installed wind power generating capacity

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

–89 91 93 95 97 99 01 03 05 07 (FY)

(MW)

0

200

400

600

800

1,000

1,200

1,400

1,600(Stations)

Installed capacity (lhs)

Installed stations (rhs)

End-FY081,854MW

1,517 stations

Source: Nomura, based on New Energy and Industrial Technology Development Organization (NEDO) data

Exhibit 338. International comparison of installed wind power generating capacity as of end-2008

Global 1,208GW(end-Dec 08)

25.2 23.9

16.8

12.29.6

3.7 3.4 3.2 3.2 2.9 2.4 2.2 1.9

0

5

10

15

20

25

30

US

Ger

man

y

Spa

in

Chi

na

Indi

a

Ital

y

Fra

nce

UK

Den

mar

k

Por

tuga

l

Can

ada

Net

herla

nds

Japa

n

(GW)

Japan is 13th with 1.9GW installed

(1.6% share)

Source: Nomura, based on World Wind Energy Association data

The current administration has not disclosed clear targets for wind power expansion, but in August 2009 the total energy survey committee’s supply and demand task force at METI projected that over the long term, wind power generating capacity could expand to around 5GW, or 5x the level in 2005. It stated that 6.4GW was the maximum potential for land-based wind power generation in Japan.

Wind power and other kinds of renewable energy are technologically feasible and the scope for cost reductions via greater installation is narrower than for solar power (Exhibit below).

Position of renewable energy

Limited areas are suitable for wind power

Is 5-6GW the ceiling?

Limited room for cost reductions with wind



Exhibit 339. Scope for cost reductions: less room with wind power than with solar power

2010 2020 2030 2050

¥50/kWh

¥30/kWh

¥10/kWh

Cost reductions via larger scale (smart meter technology)

Technological improvements in f loating and w ind mill

integration engineering

Emergence of ultraefficient (40%) solar power based on new

technological principles and systems

Solar power PV2030+ (NEDO)

Establishment of mass production systems for polysilicon, thin-film silicon CIS, etc

and performance improvements

Innovative w ind pow er technologies (double-layer vanes, high-speed rotation,

superconducting generators, etc)

Land and marine w ind power (NEDO)

Technological development in new materials, etc to increase performance

¥14

¥7 or less¥7 or less

¥7 or less

¥23¥10–14/kWh or less

¥7

¥7–10

¥7

Land-based wind power

Marine w ind power (AIST)

Note: NEDO = New Energy and Industrial Technology Development Organization; AIST = National Institute of Advanced Industrial Science and Technology

Source: Nomura, based on data from third meeting of METI project team on feed-in tariffs for renewable energy, held on 3 March 2010

2) Solar power: renewable energy with the largest potential

The Exhibit on the following page shows projections for the solar power market on an installed capacity basis. Data through 2009 in the Exhibit are based on statistics from the European Photovoltaic Industry Association. In 2009, despite initial projections for a major decline, the European market for solar power grew considerably, especially in Germany, as a result of the economic rebound, financial markets quickly recovering from tumultuous times, and a gradual resumption of financing for solar power projects from the summer.

In Japan, a resumption of subsidies for solar power installations and the start of a purchasing system for surplus electricity generated helped lift demand for solar power from the household sector, spurring strong market growth.

India and the US are markets that did not grow much despite great expectations. The US market was the biggest disappointment in 2009. Under current economic conditions, economic policies linked to job creation policies are needed. In India, the Moser Bear thin-film solar panel production line launch was not that successful, contrary to the expectations of government officials. In the US, the solar power industry was undermined by Republican policies that favoured the auto and oil industries and claims that the economic impact would not be significant even if an effort were made to introduce solar power. We think that attention needs to be paid to such protectionist moves and their impact on the solar panel industry.

Solar power market grew again in 2009

Expansion of Japan’s market

US was great disappointment in 2009



Exhibit 340. Our projections for the solar power market

(MW) 08 09 10F 11F 12F

World (main scenario) 6,283 7,216 10,760 11,370 13,485

US (main scenario) 342 477 900 1,500 1,800

Europe total 5,252 5,618 7,290 6,170 6,595

Germany 2,002 3,800 4,000 3,500 3,500

Spain 2,605 69 600 500 550

Italy 338 730 900 950 1,000

Greece 10 36 100 125 145

Czech Republic 51 411 900 100 130

Belgium 50 292 140 160 200

France 46 185 500 500 540

Portugal 50 32 70 75 80

Other 100 63 80 260 450

Asia 645 985 2,120 3,050 4,240

Japan 230 484 700 900 1,000

China 45 160 1,000 1,510 2,280

Korea 278 168 70 80 100

India 40 30 60 120 200

Other 52 143 290 440 660

Rest of world 43 136 450 650 850 Source: Nomura, based on European Photovoltaic Industry Association data for 2008–09 figures

In 2010, we look for the solar power market to expand considerably owing to: 1) a rush in demand before Germany lowers electricity purchase rates midyear; 2) growth in the Italian and French markets; 3) slow expansion of the US market; 4) continued growth of the Japanese market; and 5) the introduction of a solar power subsidy system in China, which has become the world’s largest producer of solar panels, to provide a stimulus to its domestic solar cell makers.

For 2011F and beyond, we expect the solar power market in Germany to contract, but the German government does not intend to shrink the market like Spain did, which severely damaged the solar power industry.

Eyeing a market size of 2.5-4.0GW annually, the German government aims to regulate its solar panel market by increasing subsidies when growth looks to be weaker than this target and decreasing subsidies when growth looks to exceed this target. We think that the US and China will become growth drivers in place of Germany and look for the overall market to expand steadily over the medium term while repeating inventory and equipment cycles.

In Japan, we think that solar power has the greatest growth potential among renewable energy sources. Under the aforementioned long-term energy outlook, METI projects that solar power capacity will increase to 20x the 2005 level (1.4GW with 80% at households) by 2020F, reaching 28GW (with 70% at households) (next Exhibit).

Expecting strong market growth in 2010F

Outlook for 2011F and beyond

US and China should drive expansion

Market could grow to 28GW by 2020F



Exhibit 341. Japan’s installed solar power capacity and system cost per kW

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 (CY)

(¥ '000/kW)

0.0

0.5

1.0

1.5

2.0

2.5(GW)

System cost per kW (LHS)

Cumulative installed base (total) (RHS)

Cumulative installed base (households) (RHS)

2.1

1.7

710

Source: Nomura, based on Japan Photovoltaic Energy Association data

In FY05, subsidies were discontinued for household solar power installation in Japan and domestic shipments of solar cell modules by Japanese makers declined y-y in FY06 and FY07. Subsidies were resumed in January 2009, however, leading to y-y growth again from FY08 (Exhibits below).

Exhibit 342. Subsidies for solar power in Japan

0

100

200

300

400

500

600

700

800

900

1,000

94 95 96 97 98 99

00–0

1

00–0

2

00–0

3 01 02 03 04 05 06 07 08 09 10

(FY)

(¥ '000/kW)

Note: 2000 is split into three periods

Source: Nomura, based on data from and interviews with METI, Agency for Natural Resources and Energy, Energy Conservation Dept, New Energy Dept, and New Energy Policy Dept

Exhibit 343. Japanese shipments of solar cell modules

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

81 86 91 96 01 06 (FY)

(MW)

Overseas

Domestic

Source: Nomura, based on Japan Photovoltaic Energy Association data

Solar power subsidies resumed in Japan in January 2009



In FY08 Q4, the overall subsidy budget was ¥9bn (envisioning about 35,000 projects), providing subsidies of ¥70,000/kW (around 10% of the purchase price) for installations with less than 10kW peak capacity and a total system cost of less than ¥700,000/kW (excluding tax). The budget for FY09 amounted to ¥20.05bn (envisioning 84,000 projects) with the same conditions for subsidies as in FY08. The budget for FY10 is ¥41.15bn (150,000 projects), but with a change in conditions for system cost to be less than ¥650,000/kW (excluding tax). The subsidy of ¥70,000/kW will not change.

In November 2008, a system was started for purchasing surplus electricity (the portion not consumed by the owner) generated by solar power. Until FY10, the purchase price for surplus electricity is ¥48/kWh generated by households (¥39/kWh for overlap with other power generators on the owner’s premise) and ¥24/kWh for nonhouseholds (¥20/kWh). The price of ¥48/kWh is about twice the price that electric power companies pay voluntarily. The Japanese government plans to lower the purchase price in stages, starting with a cut to about ¥42/kWh in FY11 (officially it has not yet been decided), with the aim of halving the system cost for solar power generation in three to five years. Investment in solar power should thus be recovered in 10-15 years. The surplus electricity purchase system will continue for 10 years at a fixed price; it excludes facilities for the power generation business (above 500kW) and includes equipment already installed when the system started. All consumers of electricity will bear the burden of the purchase costs.

The surplus electricity purchase price of ¥48/kWh is generally in line with the current cost of solar power generation. The solar power generating cost is much higher than the cost with other forms of power generation, but such costs are expected to decline with advances in technology and mass production in the future (Exhibit below).

Exhibit 344. Cost comparison by power generation type

0

10

20

30

40

50

60

Solar power(household)

Solar power Wind Biomass Hydro Micro hydro Geothermal

(¥/kWh)

46

37

55

49

26

11

41

12

13

8

(48)

24

12

(nonhousehold)

Note: (1) Wind and water exclude small-scale installations. (2) Micro hydro is defined as installations with capacity of less than 1,000MW.

Source: Nomura, based on data from fourth meeting of METI project team on feed-in tariffs for renewable energy, held on 24 March 2010

3) Cost to citizens could be a drag on growth

The Japanese government has been considering a feed-in tariff system for electricity generated by renewable resources, primarily solar power. The following Exhibit shows the four options that have been proposed, each a different combination of which generators are paid, how much they are paid, and for how long they are paid. The government is considering adding the purchase cost either to electricity rates or to taxes. The annual per-capita cost of the scheme in its 10th year (the launch is as yet unscheduled) has been calculated at ¥3,852-13,403, though this does not necessarily represent the direct impact on households because the cost will also be borne by nonresidential users.

Subsidies of ¥70,000/kW

Start of surplus electricity purchasing system in November 2008

Purchase price of ¥48/kWh is about in line with generating cost

Renewable energy feed-in tariffs are being considered, but burden on citizens is heavy



On top of this, there will also be costs to improve the stability of the electric power grid. These costs will depend on the capacity of the storage batteries used and are estimated at ¥218.5-1,976.4bn annually (¥1,821-16,470 per capita) in 2020. In addition to this public cost burden, there are also other limits as to how far the use of renewable energy can expand given the existence of households where it is difficult to install solar panels (raising the problem of fairness among households) and the likelihood that such a scheme would dent the international competitiveness of Japanese companies by driving up electricity rates.

The following Exhibits show estimates for the cost of grid stabilisation if 28GW and 35GW of solar power generation capacity is installed, though a breakdown of these costs is not provided. Storage batteries account for the bulk of the costs. Storage batteries store surplus energy not used by households. Grid stabilisation costs could be held down by controlling output and thus keeping surplus energy in check.

Exhibit 345. Options for renewable energy feed-in tariffs (calculations for 10th year under scheme)

Burden Grid stabilisation cost

Tariff coverage Purchase price Purchase

period

Generating capacity

addedPower

generatedCO2

reduction

CO2

reduction cost

Purchase cost

Standard household Per capita Cost

Per standard

household

¥/kWh years MW TWh '000t ¥/t ¥bn/year ¥/month ¥/year ¥bn/year ¥/month

Case 1 Purchasing all power from all forms of renewable energy, new + existing facilities

Solar: household 42 (35) Nonsolar: 20

20 37,730 + (34,740 +

)

51.3 + (48.1 + )

30,750 + (28,870 +

)

52,297 - (52,000 -

)

1,608.3 + (1,501.1 +

)

522 + (486 + )

13,403 + (12,509 +

)


20 37,730(34,740)

51.3(48.1)

30,750(28,870)

28,854(27,025)

887.3(780.1)

288 (252)

7,394 (6,501)

Case 2 Purchasing all power from commercial renewable energy forms, new facilities only


15 34,540(31,550)

42.8(39.7)

25,700(23,820)

28,025(25,743)

720.3(613.1)

234 (198)

6,003 (5,109)

259.9–1,976.4(218.5–

1,777.2)

74–561(62–504)

Solar: household 42 Nonsolar: 20

20 34,740 48.1 28,870 21,798 629.2 204 5,243 Case 3 Purchasing surplus household solar power, etc from commercial renewable energy forms, new facilities only

Solar: household 42 Nonsolar: 20

15 31,550 39.7 23,820 19,407 462.2 150 3,852

Solar: household 42 Wind: 12

Small hydro: 22 15 31,020 39.7 23,820 20,596 490.6 159 4,088

Case 4 Purchasing surplus household solar power, etc from commercial renewable energy forms, new facilities only Geothermal: 17

Biomass: 15

218.5–1,777.2 62–504

Reference: current system

Surplus solar power, new Solar: household 48 10 25,230 26.5 15,910 19,594 311.8 102 2,598 205.1–1,645.3 58–467

Note: 1) Tariffs for purchasing electric power generated by household solar power generation and other sources to last for 10 years under all options. 2) Purchase cost is only for generating capacity added and power generated. 3) Figures assume average of 600g of CO2/kWh for thermal electric power, but we calculate that emissions are roughly half (330g) when all power sources are considered. 4) CO2 reduction cost does not include grid stabilisation cost. 5) Purchase cost calculated as total purchases minus discretionary costs (fuel costs, etc). 6) Standard household burden assumes 300kWh used per month. 7) Per capita cost calculated by dividing purchase cost by 120mn. 8) Grid stabilisation cost is assumed as effect of reducing output for at least 14–30 days during period of low electric power demand (which results in lower storage battery costs), extrapolated to 2020. 9) Purchasing all refers to large-scale hydroelectric power, existing biomass power, and power sources still at R&D stage as well as commercially viable renewable energy. 10) Figures assume household solar power generation results in 60% surplus power. 11) Purchase price for household solar power generation is to be lowered in stages from initial amount and figures in parentheses show impact of purchase price of ¥35. 12) Household solar power generation includes existing facilities in all cases.

Source: Nomura, based on data from fourth meeting of METI project team on feed-in tariffs for renewable energy, held on 24 March 2010

Overlap with grid stabilisation costs

High storage battery costs



Exhibit 346. Grid stabilisation cost through 2020 assuming 28GW of solar power generating capacity (calculated at future value, ¥trn)

Scenario

Power distribution

measures (note 1)

Installation of storage batteries

(note 2)

Creation of control system

Output controllable

PCS (note 3)

Demand creation/

utilization

Storage battery/water

pumping loss, etc (note 4)

Thermal power

adjustment operation Total Remarks

1) No output control (storage batteries on grid side)

0.32 15.1 0.30 - - 0.35 0.15 16.2

1) No output control (storage batteries on customer side)

- 45.4–56.7 (note 5) 0.30 - - 0.05 0.15 45.9–57.2

2) Control output on special days (note 8)

0.32 2.80 (note 6) 0.30 0.02 - 0.08 0.15 3.67 Solar power output reduced by 730GWh/year

3) Control output by half on special days

0.32 7.56 0.30 0.02 - 0.19 0.15 8.54 Solar power output reduced by 360GWh/year

4) Control output on special days and downtimes (note 9)

0.32 0.55 (note 6) 0.30 0.02 - 0.02 0.15 1.36 Solar power output reduced by 1,560GWh/year

5) Control output on special days and downtimes and create demand

0.32 0.55 (note 6) 0.30 0.02 0.09 (note 7) 0.02 0.15 1.45 Solar power output reduced by 960GWh/year

Note: 1) We assume one voltage regulator (such as static VAR compensator; average price of ¥15mn) for every battery bank and one pole-top transformer (average price of ¥200,000) for every 5–8 homes. 2) Cost is only for storage battery system and does not include cost of renting land to install storage battery. Cost for NaS battery system is estimated at ¥40,000/kWh and that for LiB battery system is estimated at ¥100,000/kWh. 3) For solar power generating capacity of more than 10GW (= 18GW), we assume installation of output controllable PCS (boosting PCS costs by ¥5,000). 4) Includes electricity consumption needed to keep NaS battery warm. 5) If storage batteries are not being properly operated on customer side, they may be needed on grid side. 6) If installed base of solar power exceeds certain level, surplus power generated on weekend and unused during week will be carried over to next week, boosting amount of surplus power that needs to be dealt with and increasing marginal cost of storage battery installation measures. Cost of storage batteries needed to secure load frequency control capacity is included. Calculation assumes smart interfaces that control solar power generation and HP/EV are installed in about 3mn homes (about 60% of homes with solar panels; ¥30,000 per interface). 8) Golden Week holiday and period around New Year (about two weeks a year). 9) Weekends (Saturday or Sunday) during seasons (spring/autumn) when electricity demand is low: about 16 days/year. While it is not additional cost, increased consumption by households resulting from installation of solar power systems boosts fixed-cost burden per kWh for existing facilities.

Source: Nomura, based on data from third meeting of METI project team on feed-in tariffs for renewable energy, held on 3 March, 2010

Exhibit 347. Grid stabilisation cost through 2020 assuming 35GW of solar power generating capacity (calculated at future value, ¥trn)

Scenario

Power distribution

measures

Installation of storage

batteries

Creation of control system

Output controllabl

e PCS

Demand creation/

utilization

Storage battery/water

pumping loss, etc

Thermal power adjustment

operation Total Remarks

1) No output control (storage batteries on grid side)

0.40 22.70 0.38 - 0.03 0.55 0.18 24.20

1) No output control (storage batteries on customer side)

- 68.0–85.1 0.38 - - 0.06 0.18 68.7–85.7

2) Control output on special days

0.40 7.28 0.38 0.03 - 0.14 0.18 8.41 Solar power output reduced by 1,010GWh/year

3) Control output by half on special days

0.40 13.02 0.38 0.03 - 0.29 0.18 14.30 Solar power output reduced by 500GWh/year

4) Control output on special days and downtimes

0.40 1.34 0.38 0.03 - 0.03 0.18 2.36 Solar power output reduced by 2,160GWh/year

5) Control output on special days and downtimes and create demand

0.40 0.90 0.38 0.03 0.11 0.02 0.18 2.03 Solar power output reduced by 1,410GWh/year

Note: 1) If installed base of solar power exceeds certain level, surplus power generated on weekend and unused during week will be carried over to next week, boosting amount of surplus power that needs to be dealt with and increasing marginal cost of storage battery installation measures. 2) Aside from storage battery installation costs, our estimates are expanded based on figures for 28GW in 2020

Source: Nomura, based on data from third meeting of METI project team on feed-in tariffs for renewable energy, held on 3 March, 2010

The government has not disclosed the assumptions behind the four options, but if the feed-in tariff were applied to solar power generating facilities for commercial purposes, which are not part of the current version of the surplus electricity scheme, the government estimates that solar power capacity of 15.23GW would be installed in the first five years of the scheme, 29.98GW in the first 10 years, and 44.73GW in the first 15 years. Assuming that the purchase price at the start of the feed-in tariff scheme is the same as for the surplus electricity scheme (and assuming that electricity is bought from facilities for commercial purposes), the government estimates that 18.21GW of capacity would be installed in the first five years, 32.97GW in the first 10 years, and 47.72GW in the first 15 years.

Growth potential of solar power generation



Subsidies and facility prices will determine whether solar power generating capacity grows to projected levels, but for now we do not expect capacity to exceed 10GW, which is how much electric power companies say they can handle without causing problems with grid stability. Electric power companies say 5GW is the limit for wind power generation.

In 2009, the solar cell production equipment market grew about 18% to ¥728bn. Orders were weak, but deliveries of high-priced system projects ordered in 2008, such as for thin-film turnkey equipment, went well.

We look for the solar cell production equipment market to grow only 4% in 2010, reflecting when the economy and the solar cell market started recovering. One or two of the European and US thin-film equipment makers are likely to see sales drop substantially.

The Exhibit below shows the market shares of production equipment makers in 2008. European makers have the largest market share. Their share is particularly large in Asian markets. US makers appear to have a large share of the market, but most of Applied Materials' [AMAT US] solar cell production equipment is made in Europe and Japan, so the share held by US-made equipment is not that high. We think that Japanese makers will have an opportunity to increase their market share because Chinese and Taiwanese companies are looking to buy production equipment not made in Europe and the Japanese producers are known for their generous service and support.

Exhibit 348. Solar cell production equipment market outlook

20GW production capacity based on ¥3trn cumulative investment

100

870760728616

240

0

1,000

2,000

3,000

4,000

06 07 08 09 10E 11E ・・・・・・・・・

(CY)

(¥bn)Scenario 1: equipment technology becomes more important

Scenario 2: as with SPE, high growth continues

Scenario 4: prolonged slump owingto lack of equipment innovation

Early 20s–

Scenario 3: market limited to latecomers

Source: Nomura

10GW is likely to be limit for now

Outlook for solar cell production equipment market

Market growth is likely to slow in 2010

European makers are strong, but we expect Japanese makers to increase market share



Exhibit 349. Market shares of solar cell production equipment manufacturers in 2008

Schmid8.3%

Meyer Burger6.3%

Centrotherm8.1%

GT Solar8.7%

Roth & Rau6.1%

Oerlikon9.0%

Show a Shinku0.3%

Tokyo Rope Mfg1.0%

Nisshinbo Holdings1.3%

Shimadzu1.0%

Kuroda Electric0.2%Tokki

0.1%

Ferrotec1.8%

Ishii Hyoki1.9%

NPC2.3%

Asian makers, other1.3%

Ulvac6.5%

Yamaichi Electronics

0.1%

Shibaura Mechatronics

0.1%Applied

Materials12.9%

Von Ardene3.4%

Manz Automation4.6%

Europe55%

US26%

Japan18%

Source: Nomura

4) Impact on CO2 emissions of nuclear power and solar power

Renewable energy is more expensive than nuclear power, so the government must promote improvements in the utilisation ratio of existing nuclear plants to achieve targets for reducing CO2 emissions, in our view. Upping the utilization ratio by 1ppt at all existing nuclear power plants (combined output: about 48.8GW) would reduce CO2 emissions by between 1.9mn tpy (average CO2 emissions per unit of electricity generated from all power sources) and 2.62mn tpy (average CO2 emissions per unit of electricity generated from thermal power sources). Improving the nuclear power utilisation ratio would only entail loosening up regulations for practically no additional cost. Obtaining an identical impact on CO2 emissions would require investing ¥2.5-2.9trn (US$28-32bn at $1/¥90) in building 4.1GW worth of solar plants (see below).

Exhibit 350. Cost-benefit analysis for reducing CO2 emissions: nuclear power versus solar power

Note: 1) Utilisation ratios: nuclear power 80%, solar power 12%. 2) Solar power construction cost is ¥600,000–700,000/kW. 3) CO2 emission reduction impact is calculated as 0.444kg of CO2/kWh for units of electricity generated from all power sources and 0.612kg of CO2/kWh for units of electricity generated from thermal power (09/3). 4) Grid stabilisation cost assumes 53.21mn kW of solar power generating capacity (about 40x FY05 level) is installed by 2030. 5) Total output of nuclear power in Japan was 48.8mn kW in March 2010.

Source: Nomura, based on METI data

Solar power is more expensive than nuclear power

Reduces CO2 emissions

by 4.29–5.91mn tonnes

Reduces CO2 emissions

by 1.9–2.62mn tonnes

Nuclear

power Solar power

1.38mn kW / plant 9.2mn kW

48.8mn kW

x

1ppt

New facilities

¥400–500bn

Improvement in

utilisation ratio

¥5.5–6.4trn

¥2.5–2.9trn

¥5–10trn

No change in regulations

Grid stabilisation cost

4.1mn kW

+



Building a new nuclear power plant with output of 1.38mn kW would reduce CO2 emissions by 4.29–5.91mn tonnes annually, assuming a utilization ratio of 80%, at an estimated construction cost of ¥400-500bn ($4.4-5.6bn at $1/¥90). In order to realize the same reduction in CO2 emissions, 9.2GW of solar power facilities would be necessary at an estimated construction cost of ¥5.5-6.4trn ($61-71bn at $1/¥90).

If the installed capacity for solar power exceeds 10GW, electric power companies will have to invest in stabilizing their distribution systems. Based on estimates from the Agency for Natural Resources and Energy, grid stabilisation costs (mainly for storage batteries) would amount to ¥4.6-6.7trn ($54-74bn at $1/¥90) if 53GW (40x the FY05 level) of solar power generating capacity were installed by FY30. If demand for electricity were to decline more than assumed in the above estimate, the cost would exceed ¥10trn ($111bn at $1/¥90). We think that it would be politically untenable to pass the full cost of expanding renewable energy generation along to electricity and other energy prices.

Of the four options outlined above, the scenario with the greatest reduction in CO2 emissions achieves a cut of 30.75mn tonnes. This figure is only 2.4% of the 1,286mn tonnes of greenhouse gases emitted in Japan in FY08, when such emissions were lower due to the weak economy. The cost of lowering emissions in this scenario is about ¥52,300/t of CO2 (purchase cost only; excludes grid stabilisation cost), which is far higher than the recent price of emission credits, at ¥1,500/t. This cost assumes an average of 0.6kg of CO2/kWh for thermal power generation and would be roughly twice as high if based on the average of 0.33kg of CO2/kWh for all power sources, which would be a conservative assumption.

Initial construction cost is more than 10x as large for solar

Grid stabilisation costs are also incurred

CO2 reduction cost is 30x price of emission credits



Appendix: Current status of renewable energy

Current snapshot of renewable energy Clarisse Pan +852 2252 2192 / [email protected]


Despite current difficult financial conditions around the world, we believe government support towards clean energy technologies is much stronger now. Countries in Europe remain committed towards their targets to reach a 20% share of energy from renewable sources by 2020 and a 10% share of renewable energy specifically in the transport sector. Besides Europe, we note that many governments prioritise clean energy in the Economic Recovery Funding, of which the majority is focused on innovators, businesses and installers in 2010 and 2011, which should help to bring down the cost of clean energy technologies.

We note that G-20 countries account for more than 90% of clean energy investment, which has grown more than five times over the past five years. We believe that the national portfolio standard plays a significant role in promoting renewable energy, sustaining its growth and attracting investment. We also believe countries that have strong national policies, such as China and Germany, have a higher possibility of emerging as technology leaders in terms of clean energy technology. Despite the huge potential of clean energy resources, we note that the US has lagged behind in the clean energy technology sector. In our opinion, a strong national renewable standard programme can help the US recover lost ground.

According to the Renewable Energy Policy Network for the 21st Century (REN21), the clean energy policy target exists in more than 73 countries and at least 64 countries have policies to promote renewable power generation. Several countries have adopted policy targets over the past few years (from 2006 to 2009). For example, Australia, China, Japan, Luxembourg and the Netherlands have adopted new solar PV programmes. Developing countries such as Brazil, Chile, Egypt, Mexico, the Philippines, South Africa, Syria and Uganda have also become active in promoting renewable energy through the passing of laws supporting renewable energy; new blending mandates for bio-fuels appeared in 11 countries. We expect support for renewables to continue to grow worldwide with more countries focusing on renewable energy to meet their energy needs.

Exhibit 351. Top 10 countries by renewable energy capacity 2009 (GW)

0

10

20

30

40

50

60

Un

ited

Sta

tes

Ch

ina

Ge

rma

ny

Sp

ain

Indi

a

Jap

an

Res

t o

f E

U-2

7

Ita

ly

Fra

nce

Bra

zil

(GW)

0

10

20

30

40

50

60

Un

ited

Sta

tes

Ch

ina

Ge

rma

ny

Sp

ain

Indi

a

Jap

an

Res

t o

f E

U-2

7

Ita

ly

Fra

nce

Bra

zil

(GW)


Exhibit 352. Top 10 countries by renewable installed capacity growth (2005-09)

0

50

100

150

200

250

300

Sou

th K

orea

Chi

na

Aus

tral

ia

Fra

nce

Indi

a

Uni

ted

Kin

gdom

Tur

key

Uni

ted

Sta

tes

Can

ada

Res

t of

EU

-27

(%)




Exhibit 353. Renewable energy installed capacity as of 2008 (GW)

Technology World

total Developing

countries EU-27 China United Germany Spain India Japan

Wind power 121 24 65 12 25 24 17 10 2

Small hydropower 85 65 12 60 3 2 2 2 4

Biomass power 52 25 15 4 8 3 0 2 >0.1

Solar photovoltaic-grid 13 >0.1 10 >0.1 1 5 3 ~0 2

Geothermal power 10 5 1 ~0 3 0 0 0 1

Solar thermal power–CSP 1 0 0 0 0 0 0 0 0

Ocean (tidal) power 0 0 0 0 0 0 0 0 0

Total renewable power capacity (excluding large hydro)

282 119 103 76 40 34 22 13 8

Source: REN21, Nomura research

Exhibit 354. Top five countries by capacity added in 2008

Ranking New capacity investment

Wind power added

Solar PV added (grid-connected)

Solar hot water/heat added

Ethanol production

Biodiesel production

First United States United States Spain China United States Germany

Second Spain China Germany Turkey Brazil United States

Third China India United States Germany China France

Fourth Germany Germany South Korea Brazil France Argentina

Fifth Brazil Spain Italy France Canada Brazil


Exhibit 355. Top five countries by installed capacity

Ranking Small hydro Wind power Biomass power Geothermal power

Solar PV (grid-connected)

Solar hot water/heat4

First China China United States United States Germany China

Second United States Japan Brazil Philippines Spain Turkey

Third Germany United States Philippines Indonesia Japan Germany

Fourth Spain Italy Germany/Sweden/FinlandMexico United States Japan

Fifth India Brazil Italy South Korea Israel


Exhibit 356. Global electricity capacity breakdown 2008

Wind power1.72%

Conventional sources

77%

Solar0.13%

Hydropower20%

Biomass1.05% Other renewables

0.23%

Source: Global Wind Energy Council (GWEC), Nomura research



Exhibit 357. EU targets share of energy from renewable sources by 2020

0 10 20 30 40 50 60

Belgium

Bulgaria

Czech Republic

Denmark

Germany

Estonia

Ireland

Greece

Spain

France

Italy

Cyprus

Latvia

Lithuania

Luxembourg

Hungary

Malta

Netherlands

Austria

Poland

Portugal

Romania

Slovenia

Slovak Republic

Finland

Sweden

United Kingdom

(%)

Source: EC.EUROPA.EU, Nomura research



Exhibit 358. Country ranking according to E&Y all renewable index as on May 2010

Rank Country All

renewables Wind index

Onshore wind

Offshore wind

Solar index

SolarPV

Solar CSP

Biomass/ other Geothermal Infrastructure

1 US 69 70 75 57 73 72 75 63 67 65

1 China 69 74 77 66 59 66 40 57 51 74

3 Germany 64 65 64 70 59 72 23 64 55 63

4 India 63 64 72 42 66 67 63 57 44 63

5 Italy 61 61 64 53 64 66 59 56 65 66

5 UK 61 67 64 75 38 51 0 58 38 69

7 France 58 60 61 55 53 63 24 58 29 61

8 Spain 57 58 63 43 64 64 67 50 33 55

9 Canada 53 60 65 46 32 44 0 49 34 62

10 Portugal 51 54 58 42 48 57 22 45 32 56

10 Ireland 51 58 58 57 26 36 0 47 28 61

12 Greece 49 51 55 40 54 59 41 40 32 50

12 Australia 49 49 53 40 53 56 45 45 58 50

12 Sweden 49 53 53 53 32 43 0 55 34 51

15 Netherlands 48 53 52 58 35 47 0 41 22 44

16 Poland 45 50 53 42 31 43 0 41 22 46

16 Belgium 45 52 50 57 28 38 0 37 28 52

16 Brazil 45 46 50 34 40 44 29 47 21 43

19 Denmark 44 47 44 56 29 40 0 45 32 51

19 Norway 44 45 48 39 22 52 25 35 40 49

21 Japan 43 48 49 45 45 30 0 44 30 49

22 New Zealand 41 46 50 35 23 31 0 33 49 41

22 Turkey 41 43 45 35 39 43 28 36 43 44

24 South Africa 40 43 46 34 37 34 44 34 31 41

25 Austria 37 34 46 0 40 54 0 49 34 52

26 Czech 34 33 44 0 40 54 0 38 31 43

26 Finland 34 35 34 37 19 26 0 49 23 37

Note: The Ernst & Young country attractiveness indices provide scores for national renewable energy markets, renewable energy infrastructures and their suitability for individual technologies. The indices provide scores out of 100 and are updated on a regular basis. Combines with each set of technology factors to produce the individual technology indices

Source: Ernst & Young, Nomura research

Wind: Asia emerges as the new regional leader We believe that wind, among all renewable energy technologies, remains the most preferred technology by investors. Scalability, cost competiveness and quick installation are key advantages that give wind an edge over others. Wind power can be installed in a few months and wind farms can start to generate electricity even before completion. A single turbine connected to the grid can start to generate income for the wind farm developer. Even large offshore wind farms, which require a greater level of infrastructure and grid network connection, can be installed from start to finish in less than two years.

Despite the economic and financial crisis in late-2008/2009, which was expected to hit the sector hard, we note that cumulative wind capacity in 2009 increased to 160GW, implying growth of 31% y-y. Asia was the market leader amongst all regions, as it added 14.9GW of capacity in 2009. This was mainly due to China, the largest market in 2009, which added more than 13GW of capacity to almost 26GW in the year. The rapid growth rate of the Chinese wind market has helped domestic wind turbine suppliers to break into the global league, in our view. Sinovel, Goldwind and Dongfang are among the top-10 wind turbine suppliers and have gained global market share at the expense of their global peers.



Exhibit 359. Wind cumulative installed capacity

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

0

5

10

15

20

25

30

35

40

Wind installed capacity (LHS)

Growth y-y (RHS)

(MW) (%)

Source: BTM Consult, Nomura research

Exhibit 360. Top 10 countries by newly installed capacity (2009)

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

Chi

na US

Spa

in

Ger

man

y

Indi

a

Ital

y

Fra

nce

UK

Can

ada

Por

tuga

l

RO

W

(MW)


Solar: Demand from a more diversified country base

Europe remains the market leader in solar PV

Despite the economic crisis, total global solar PV installed capacity increased 48% y-y to 22.3GW in 2009. Europe remained the market leader with 16GW of installed capacity in 2009, representing about 70% of the world’s cumulative PV power installed at the end of 2009. Germany maintained its market leadership and with new capacity additions of 3.8GW, its cumulative installed capacity for solar PV increased to almost 9GW in 2009, representing a global market share of 40%.

Besides Germany, other countries are also making progresses. Italy installed 711 MW of capacity in 2009, enabling it to have the second-largest global market share. Czech Republic and Belgium made impressive progresses in 2009, with 411 MW and 292 MW of capacity installed, respectively. Major developments were seen in France with 285 MW installed, 185 MW of which were already connected. In Southern Europe, we believe that Portugal and Greece are the two promising markets with huge potential.

The solar PV market also developed significantly outside of Europe with 484 MW of installed capacity in Japan and 477 MW (including 40 MW of off-grid applications) of installed capacity in the US. China made its entry into the top-10 list and we expect it to become a major player in the coming years. Canada and Australia are emerging, whereas South Korea failed to repeat its strong performance of 2008.



Exhibit 361. Solar PV cumulative installed capacity

0

5,000

10,000

15,000

20,000

25,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

0

10

20

30

40

50

60

70

Solar PV cumulative installed capacity (LHS)

Growth y-y (RHS)

(MW) (%)

Source: European PhotoVoltaic Industry Association (EPIA), Nomura research

Exhibit 362. Solar PV cumulative installed capacity by country

0

5,000

10,000

15,000

20,000

25,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

USA ROW Japan EU China(MW)


Exhibit 363. Solar PV annual capacity addition by country (2009)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

IND

IA

GR

EE

CE

SP

AIN

CH

INA

SO

UT

HK

OR

EA

FR

AN

CE

Oth

ers

US

JAP

AN

ITA

LY

RO

E

GE

RM

AN

Y

(MW)


Nuclear power Nuclear power accounted for 14% of the world’s total electricity generation in 2007, according to the IEA. It is the third-largest source of generation after coal (41%) and hydro (16%). There are 435 nuclear power reactors in operation worldwide (as of December 2009) with total net installed capacity of 372GW. The US is the largest



nuclear power user globally, generating 32% of the world’s nuclear energy in 2008, followed by France (16%) and Japan (9%).

Nuclear power was first put into commercial use in the 1950s and saw rapid growth in capacity build-out during the 1960s and 1970s. However, development has slowed significantly since the late 1980s (with capacity slowing to a CAGR of 0.8% during the 1990s from 9.1% in the 1980s) after the Three Mile Island accident in 1979 and the Chernobyl accident in 1986, which severely soured sentiment towards nuclear power in the West and undermined the reputation of the nuclear power industry.

Exhibit 364. World nuclear energy consumption (Terawatt-hours)

0

500

1,000

1,500

2,000

2,500

3,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

North America S.&Cent. America Europe & Eurasia

Africa Asia Pacific

(TWh)

Source: BP Statistical review of Word Energy 2010, Nomura research

Exhibit 365. Nuclear generation by country as a percentage of world total, 2008

U.S.32%

France16%Russia

6%

South Korea6%

Germany5%

Canada3%

Others15%

Japan9%

Ukraine3%

China3%

Sweden2%

Source: Nuclear Energy Institute (NEI)

Other renewable technologies

Concentrated solar power

A concentrating solar power (CSP) system produces heat or electricity using hundreds of mirrors to concentrate the sun’s rays to a temperature typically between 400 ºC and 1,000ºC. We note that there are a variety of mirror shapes, sun-tracking methods and ways to provide useful energy, but they all work under the same principle. Individual CSP plants are typically sized between 50 MW and 280 MW, but could be larger. A CSP system can be specifically integrated with storage or in hybrid operation with fossil fuels, offering firm capacity and dispatchable power on demand. It is suitable for peak loads and base-loads, and power is typically fed into the electricity grid.



A range of technologies can be used to concentrate and collect sunlight, turning it into medium to high temperature heat. This heat is then used to create electricity in a conventional way, for example, using a steam or gas turbine or a Stirling engine. Solar heat collected during the day can also be stored in liquid or solid media, such as molten salts, ceramics; concrete or phase-changing salt mixtures. At night, it can be extracted from the storage medium to keep the turbine running. Solar thermal power plants with solar-only generation work well to supply the summer noon peak loads in wealthy regions with significant cooling demands, such as Spain and California. With thermal energy storage systems, they operate longer and even provide base-load power.

Exhibit 366. Comparison of main technology type for CSP

Parabolic trough Central receiver Parabolic dish Fresnel linear reflector

Grid-connected plants, mid to high-process heat

Grid-connected plants, high temperature process heat

Stand-alone, small off-grid power systems clustered to larger grid connected dish parks

Grid connected plants, or steam generation to be used in conventional thermal power plants.

Applications (Highest single unit solar capacity to date: 80 MW. Total capacity built: over 500 MW and more than 10GW under construction or proposed)

(Highest single unit solar capacity to date: 20 MW under construction, Total capacity ~50 MW with at least 100MW under development)

(Highest single unit solar capacity to date: 100 kW, Proposals for 100 MW and 500 MW in Australia and US)

(Highest single unit solar capacity to date is 5 MW in US, with 177 MW installation under development)

• Commercially available – over 16 billion kWh of operational experience; operating temperature potential up to 500°C (400°C commercially proven)

• Good mid-term prospects for high conversion efficiencies, operating temperature potential beyond 1,000°C (565°C proven at 10 MW scale)

• Very high conversion efficiencies – peak solar to net electric conversion over 30%

• Readily available

• Commercially proven annual net plant efficiency of 14% (solar radiation to net electric output)

• Storage at high temperatures

• Modularity • Flat mirrors can be purchased and bent on site, lower manufacturing costs

• Commercially proven investment and operating costs

• Hybrid operation possible • Most effectively integrate thermal storage

• Hybrid operation possible

• Modularity • Better suited for dry cooling concepts than troughs and Fresnel

• Operational experience of first demonstration projects

• Very high space efficiency around solar noon.

• Good land-use factor • Better options to use non-flat sites

• Easily manufactured and mass-produced from available parts

• Lowest materials demand • No water requirements for cooling the cycle

• Hybrid concept proven

Advantages

• Storage capability

• The use of oil-based heat transfer media restricts operating temperatures today to 400°C, resulting in only moderate steam quality

• Projected annual performance values, investment and operating costs need wider scale proof in commercial operations

• No large-scale commercial examples

• Recent market entrant, only small projects operating

• Projected cost goals of mass production still to be proven

• Lower dispatchability potential for grid integration

Disadvantages

• Hybrid receivers still an R&D goal

Source: Solarpaces, Estela, Greenpeace, Nomura research



Geothermal

With an installed capacity of 10.7GW, geothermal energy generated 67,246GWh of electricity in 2009. We note that with more than 3GW of installed capacity, the US is the global leader in geothermal energy. The Philippines, which generates 18% of its electricity from geothermal energy, is the world’s second-biggest producer. Indonesia, Mexico, Italy, El Salvador, Kenya, Nicaragua, Papua New Guinea and Turkey are some of the other key markets.

We estimate that geothermal will witness a CAGR of 20% over 2005-10F, but countries with projects under development are growing at a much faster pace. We believe that there is increased interest in geothermal energy across the world, given that 70 countries have projects under development or are actively considering geothermal energy in 2010, a 52% increase since 2007, when there were only 46 countries considering geothermal power development, according to the Geothermal Energy Association (GEA).

In addition to large power generation, geothermal energy is also used directly for a variety of purposes, such as for space and greenhouse heating, agricultural drying, industrial, space heating, snow melting, aquaculture and greenhouse production. Geothermal heat pumps accounted for an estimated 30GW of installed capacity by the end of 2008, with other direct uses of geothermal heat reaching an estimated 15GW. At least 76 countries use direct geothermal energy in some form.

Exhibit 367. Breakdown of global geothermal technology by country (2009)

Iceland 5%

New Zealand 6%

Italy 8%

Mexico 9%

Indonesia 11%

Philippines 18%

US 29%

Others 9%

Japan 5%

Source: BP Statistical review of Word Energy 2010, Nomura research, Nomura research

Exhibit 368. Growth of global geothermal industry

0

2,000

4,000

6,000

8,000

10,000

12,000

1990 1995 2000 2003 2004 2005 2006 2007 2008 2009

ROW Italy Mexico Indonesia Philippines US(MW)




Biomass

Key reasons for the rapid growth of global biomass production are increased prices of fossil fuels, growing environmental concerns, and considerations regarding security and diversification of energy supply. Currently, biomass meets nearly 10% of global energy consumption needs, which is mainly used for cooking and heating. We note that forestry, agricultural and municipal residues, and wastes are the main feedstock used for electricity generation and heat from biomass. Contributions for feedstock supply from sugar, grain and vegetable oil crops are much smaller.

Biomass is largely used as fuel wood in developing countries for heating and cooking. It contributes a significant amount of energy, which according to estimates by the IEA, accounts for 22% of total primary energy mix in developing countries. The use of biomass is expected to increase, in view of these countries’ rising population. However, in developed countries, biomass contribution to the total primary energy mix is declining significantly, to around 3%, as it is restricted to use in heat and power applications.

Different technologies exist or are being developed to produce electricity from biomass. Co-combustion (also called co-firing) in coal-based power plants is the most cost-effective use of biomass for power generation. Dedicated biomass combustion plants, including municipal solid waste (MSW) combustion plants, are also used in successful commercial operations, and many are industrial or district heating combined heat and power (CHP) facilities. For liquids and wet organic materials, anaerobic digestion is currently the best-suited option for producing electricity and/or heat from biomass, although its economic case relies heavily on the availability of low cost feedstock. All these technologies are well established and commercially available.

There are few examples of commercial gasification plants, and the deployment of this technology is affected by its complexity and cost. In the longer term, if reliable and cost-effective operation can be more widely demonstrated, gasification promises greater efficiency, better economics at both small and large scale, and lower emissions compared with other biomass-based power generation options. Other technologies (such as Organic Rankine Cycle and Stirling engines) are currently in the demonstration stage and could prove to be economically viable in a range of small-scale applications, especially for CHP.

Exhibit 369. Development status of the main technologies to upgrade biomass and/or to convert it into heat and/or power




Bio-fuel

In 2008, global bio-fuel production reached about 83bn litres, a more than four-fold increase compared with that in 2000. This amount currently contributes about 1.5% of global transport fuel consumption, with demand projected to rise steadily over the coming decades. We note that over the last decade, global bio-fuel production increased rapidly; in 2008, about 68bn litres of bio-ethanol and 15bn litres of bio-diesel were produced globally. First-generation bio-fuel, which was mainly in the form of ethanol from sugar cane and corn, contributed almost all of it.

The US is currently the largest bio-fuel producer, followed by Brazil and the European Union. While corn-based ethanol is dominating domestic production in the US, Brazil produces ethanol mainly from sugar cane. In the European Union, bio-diesel accounts for the major share of total bio-fuel production and is mainly derived from oil crops (canola and sunflower) as feedstock. While the US and the European Union are amongst the largest producers of bio-fuel, emerging and developing countries increased their share to about 40% of total global production. Brazil, China and Thailand are currently the largest producers outside the OECD region.

Exhibit 370. Ethanol production by region

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009


Africa Asia Pacific

(TTOE)

Note: TTOE = Thousand tonnes of oil equivalent


Exhibit 371. Type of bio-fuels

Type Definition

1st generation bio-fuels

1st generation bio-fuels include mature technologies for the production of bio-ethanol from sugar and starch crops, biodiesel and renewable diesel from oil crops and animal fats, and bio-methane from the anaerobic digestion of wet biomass.

2nd generation bio-fuels

2nd generation bio-fuels are novel bio-fuels or bio-fuels based on novel feedstocks. They generally use biochemical and thermochemical routes that are at the demonstration stage, and convert lignocellulosic biomass (non-food fibrous biomass such as straw, wood, and grass) to bio-fuels (e.g. ethanol, butanol, syndiesel).

3rd generation bio-fuels

3rd generation bio-fuels generally include advanced bio-fuels production routes, which are at the early stage of research and development or are significantly further from commercialisation (e.g. bio-fuels from algae, hydrogen from biomass).

Source: IEA

Hydropower

Hydroelectric power is the most widely used renewable energy technology worldwide and in 2009 it supplied more than 3,200 TWh of electricity. Renewable energy (including large Hydropower) contributes nearly 20%of total global electricity generation, of which hydropower’s share is 90%. The theoretical potential of worldwide hydropower is around 2,800GW, of which around 30% has been exploited up until now. Even though not all hydropower potential can be exploited, due to environmental and economic limitations, there is still a huge potential that is to be exploited. Developing countries mainly based in Asia, African and South America have a lot of potential to exploit hydropower.



Hydropower energy is normally applied to peak load demand, because it is readily stopped and started. It also provides a high-capacity, low-cost means of energy storage, known as pumped storage. We note that hydropower enjoys an edge over other renewable technologies as it offers the best conversion rate of 90%, due to direct conversion hydraulic forces electricity and consequently has the highest payback ratio. In addition, hydroelectric plants have longer life span, offer higher operating hours per year and take the least time to start. Once a hydroelectric complex is constructed, the project produces no direct waste, and has a considerably lower output level of the greenhouse gas carbon dioxide (CO2) than fossil fuel-powered energy plants. Of the total installed capacity, Asia accounts for nearly one-third of the total hydropower installed capacity. Europe and North America are also significant contributors.

Exhibit 372. Global hydroelectric generation by region by region

0

500

1,000

1,500

2,000

2,500

3,000

3,500

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009


Middle East Africa Asia Pacific

(TWh)


Exhibit 373. Energy payback ratio of energy options

0

50

100

150

200

250

300

Fue

l cel

l

Nat

ural

gas

Coa

l

Bio

mas

s

Sol

ar P

V

Coa

l

Nuc

lear

Bio

mas

s

Win

d

Hyd

ro(r

eser

voir)

Hyd

ro(r

un-o

f-riv

er)

(%)

Source: Hydropower, Nomura research



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Asian companies


Energy Development Corp EDC PM

POWER & UTILITIES | PHILIPPINES

Daniel Raats +852 2252 2197 [email protected]


Our top pick in SEA M&A-driven earnings growth

While utilisation will likely remain low and EDC’s FY10-12F capex burden will likely increase by some US$200mn given extensive rehabilitation requirements, we believe EDC’s successful 5 May bid for the 150MW Bacman geothermal power plant will be meaningfully earnings accretive post FY11F, given: 1) we expect EDC to sell electricity at near NPC grid rates (more than double the current steam sales tariffs) and; 2) we estimate the group stands to realise EBITDA margin expansion on its vertically integrated production process of around 20% relative to steam-only production.

Strong organic growth potential

As a ‘market leader’ in geothermal energy, with expertise across the entire geothermal value chain, a competitive cost structure, and presence in resource-rich markets with attractive pro-renewable government incentives, we believe EDC is well placed for sustained medium-term organic capacity expansion, likely beyond our current management-guided assumption of 280-300MW by 2020F. The Philippines’ RE Act (2008), which sharply cuts government royalty payments and corporate income taxes (from 30% to 10%) for EDC, not only creates value for EDC’s existing operations but also enhances the feasibility of its future project pipeline, in our view.

Reaffirming EDC as our top pick in SEA

EDC trades at an undemanding-looking 10.1x FY11F P/E, which we believe fails to reflect the Group’s steady organic growth profile and potential upside through M&A. Reiterating BUY on the stock and price target of PHP6.40/share.

Key financials & valuations31 Dec (PHPmn) FY09 FY10F FY11F FY12F

Revenue 22,067 26,723 28,026 32,288

Reported net profit 3,315 10,378 8,680 10,724

Normalised net profit 7,381 8,347 8,732 10,724

Normalised EPS (PHP) 0.39 0.45 0.47 0.57

Norm. EPS growth (%) 26.2 13.1 4.6 22.8

Norm. P/E (x) 11.9 10.6 10.1 8.2

EV/EBITDA (x) 11.8 7.7 7.5 6.5

Price/book (x) 3.1 2.3 2.0 1.7

Dividend yield (%) 2.1 2.4 3.0 3.7

ROE (%) 11.9 31.3 21.4 22.6

Net debt/equity (%) 125.8 81.7 69.8 54.8

Earnings revisions

Previous norm. net profit 8,347 8,732 10,724

Change from previous (%) - - -

Previous norm. EPS (PHP) 0.45 0.47 0.57

Source: Company, Nomura estimates

Share price relative to MSCI Philippines

1m 3m 6m

(2.1) (3.1) 2.2

(1.2) (4.1) 3.1

(7.6) (7.7) (4.0)

Hard


1,912

50.0

5.60/3.04

4.37

Absolute (PHP)

Absolute (US$)

Relative to Index

Estimated free float (%)

Market cap (US$mn)

7.2

Major shareholders (%)

Red Vulcan 50.0

52-week range (PHP)

3-mth avg daily turnover (US$mn)

Capital International

Stock borrowability

2.73.23.74.24.75.25.7

6.2

Jun

09

Jul0

9

Au

g09

Sep

09

Oc

t09

No

v09

De

c09

Jan

10

Feb

10

Ma

r10

Ap

r10

May

10

90

100

110

120

130

140

150

Price

Rel MSCI Philippines(PHP)

Closing price on 23 Jun PHP4.70

Price target PHP6.40(set on 17 May 10)

Upside/downside 36.2%Difference from consensus 0.6%

FY11F net profit (PHPmn) 8,680Difference from consensus 2.2%Source: Nomura

Closing price on 23 Jun PHP4.70

Price target PHP6.40(set on 17 May 10)


FY11F net profit (PHPmn) 8,680Difference from consensus 2.2%Source: Nomura

Nomura vs. consensus We believe our relatively weak FY11F EPS estimate stems from the fact that we have accounted for a pullback in near-term utilisation related to the Bacman rehabilitation.

Maintained

BUY


Action Being a market leader in geothermal energy production with expertise across the

entire geothermal value chain and a competitive cost structure, EDC looks well placed to benefit from what we believe will be significant growth in geothermal energy utilisation. Sweetened by potential near-term upside through M&A, reiterating BUY call on EDC and PT of PHP6.40/share.

Catalysts Strong demand growth, coupled with a constrained supply outlook, underpins

favourable sector fundamentals. The continued privatisation drive creates opportunities for inorganic growth.

Anchor themes

Leading indicators are showing signs of improvement, while rises in commodity prices, alongside relaxed monetary policy, are improving risk appetite, prompting a more positive stance toward utilities geared to the recovery.

Energy Development Corp Daniel Raats


Valuation methodology and risks

Valuation. We value EDC using a FCFF methodology, assuming a WACC of 9.9% and terminal growth of 2.0%.

Downside risks to our view. Over the near term, we see significant discontinuities in the regulatory environment as the key downside risk for the sector and EDC, although our checks with industry participants – gencos, DUs and the DOE – suggest that this is highly unlikely. On a firm-specific level, while our price target is by no means predicated on success in bidding for a portion of the 559MW Unified Leyte contracted capacity, EDC’s share price may be adversely affected by a sentiment-related sell-down should its bids fail or should competitive forces prompt the company to over-pay. Risks associated with EDC’s Miyazawa II bullet repayment due in FY10F have been mitigated through hedging.



Anticipated forex gain on Miyazawa II loan due in FY10F

Robust and sustainable earnings growth prospects

Financial statements

Income statement (PHPmn)

Year-end 31 Dec FY08 FY09 FY10F FY11F FY12F

Revenue 20,527 22,067 26,723 28,026 32,288Cost of goods sold (5,404) (6,287) (5,938) (5,646) (6,007)Gross profit 15,123 15,780 20,785 22,380 26,281SG&A (3,940) (6,395) (8,713) (10,092) (11,861)Employee share expenseOperating profit 11,183 9,385 12,072 12,289 14,420

EBITDA 11,859 10,584 15,348 15,742 17,988Depreciation (298) (868) (3,180) (3,357) (3,471)Amortisation (378) (331) (96) (96) (96)EBIT 11,183 9,385 12,072 12,289 14,420

Net interest expense (1,820) (2,484) (2,510) (2,528) (2,438)Associates & JCEsOther income (297) 1,478 - - - Earnings before tax 9,067 8,379 9,562 9,761 11,983Income tax (3,188) (945) (1,159) (971) (1,198)Net profit after tax 5,878 7,434 8,403 8,790 10,784Minority interests (37) (46) (48) (50) (53)Other itemsPreferred dividends (6) (8) (8) (8) (8)Normalised NPAT 5,835 7,381 8,347 8,732 10,724Extraordinary items (4,496) (4,066) 2,031 (52) - Reported NPAT 1,339 3,315 10,378 8,680 10,724

Dividends (5,303) (1,869) (2,087) (2,620) (3,217)Transfer to reserves (3,964) 1,446 8,292 6,060 7,507

Valuation and ratio analysisFD normalised P/E (x) 15.1 11.9 10.6 10.1 8.2 FD normalised P/E at price target (x) 20.5 16.3 14.4 13.7 11.2 Reported P/E (x) 65.7 26.6 8.5 10.2 8.2 Dividend yield (%) 6.0 2.1 2.4 3.0 3.7 Price/cashflow (x) 9.8 9.1 7.7 7.8 7.5 Price/book (x) 3.2 3.1 2.3 2.0 1.7 EV/EBITDA (x) 10.2 11.8 7.7 7.5 6.5

EV/EBIT (x) 10.9 13.3 9.8 9.7 8.1 Gross margin (%) 73.7 71.5 77.8 79.9 81.4 EBITDA margin (%) 57.8 48.0 57.4 56.2 55.7 EBIT margin (%) 54.5 42.5 45.2 43.8 44.7 Net margin (%) 6.5 15.0 38.8 31.0 33.2 Effective tax rate (%) 35.2 11.3 12.1 9.9 10.0 Dividend payout (%) 396.0 56.4 20.1 30.2 30.0 Capex to sales (%) 10.9 56.4 23.3 29.8 18.8 Capex to depreciation (x) 7.5 14.3 2.0 2.5 1.7

ROE (%) 4.6 11.9 31.3 21.4 22.6 ROA (pretax %) 16.2 13.2 16.1 15.4 16.9

Growth (%)Revenue 8.0 7.5 21.1 4.9 15.2 EBITDA 14.9 (10.8) 45.0 2.6 14.3

EBIT 11.4 (16.1) 28.6 1.8 17.3

Normalised EPS (6.7) 26.2 13.1 4.6 22.8 Normalised FDEPS (6.7) 26.2 13.1 4.6 22.8

Per shareReported EPS (PHP) 0.07 0.18 0.55 0.46 0.57Norm EPS (PHP) 0.31 0.39 0.45 0.47 0.57Fully diluted norm EPS (PHP) 0.31 0.39 0.45 0.47 0.57

Book value per share (PHP) 1.45 1.54 2.01 2.33 2.73DPS (PHP) 0.28 0.10 0.11 0.14 0.17Source: Nomura estimates

Healthy return metrics



Gearing is not a concern

Miyazawa II bullet repayment

Change in accounting treatment for geothermal steam and power facilities

Cashflow (PHPmn)


EBITDA 11,859 10,584 15,348 15,742 17,988Change in working capital (4,529) 4,713 78 (976) (2,631)Other operating cashflow 1,619 (5,563) (3,965) (3,516) (3,678)Cashflow from operations 8,949 9,734 11,461 11,250 11,679Capital expenditure (2,243) (12,436) (6,223) (8,358) (6,072)Free cashflow 6,706 (2,702) 5,238 2,892 5,607Reduction in investments 503 (60) - - - Net acquisitions (4,115) - - - -

Reduction in other LT assetsAddition in other LT liabilitiesAdjustments 1,539 (416) 296 17 42Cashflow after investing acts 4,634 (3,178) 5,534 2,909 5,649Cash dividends (5,303) (1,869) (2,087) (2,620) (3,217)Equity issue (404) - - - - Debt issue (528) 14,296 (14,052) (841) (882)Convertible debt issueOthers 162 1,015 (0) (0) - Cashflow from financial acts (6,073) 13,442 (16,139) (3,461) (4,100)Net cashflow (1,439) 10,264 (10,605) (551) 1,549Beginning cash 2,397 957 11,221 616 64Ending cash 957 11,221 616 64 1,613Ending net debt 33,272 36,244 30,766 30,528 28,096Source: Nomura estimates

Balance sheet (PHPmn)

As at 31 Dec FY08 FY09 FY10F FY11F FY12F

Cash & equivalents 957 11,221 616 64 1,613Marketable securities 674 735 735 735 735Accounts receivable 5,412 5,487 5,345 6,166 8,395Inventories 1,563 1,554 1,795 1,928 2,189Other current assets 5,117 141 171 179 452Total current assets 13,724 19,138 8,661 9,072 13,384LT investmentsFixed assets 5,280 59,877 62,921 67,921 70,522Goodwill 293 293 293 293 293Other intangible assets 45,237 3,142 3,046 2,950 2,854

Other LT assets 4,811 2,324 2,324 2,324 2,324Total assets 69,346 84,775 77,246 82,561 89,378Short-term debt 10,672 16,931 836 882 882Accounts payable 2,980 3,985 4,542 4,879 5,360Other current liabilities 2,050 848 498 148 (202)Total current liabilities 15,703 21,764 5,876 5,909 6,040Long-term debt 23,557 30,534 30,545 29,710 28,827Convertible debtOther LT liabilities 1,351 2,146 1,579 1,579 1,579Total liabilities 40,610 54,443 38,000 37,198 36,447Minority interest 1,484 1,530 1,578 1,628 1,681Preferred stock 75 94 94 94 94

Common stock 15,000 18,750 18,750 18,750 18,750Retained earnings 9,978 7,681 15,980 22,048 29,563Proposed dividends

Other equity and reserves 2,198 2,277 2,844 2,844 2,844Total shareholders' equity 27,251 28,802 37,668 43,736 51,250

Total equity & liabilities 69,346 84,775 77,246 82,561 89,378

Liquidity (x)

Current ratio 0.87 0.88 1.47 1.54 2.22 Interest cover 6.1 3.8 4.8 4.9 5.9

LeverageNet debt/EBITDA (x) 2.81 3.42 2.00 1.94 1.56

Net debt/equity (%) 122.1 125.8 81.7 69.8 54.8

Activity (days)Days receivable 94.0 90.1 74.0 75.0 82.5 Days inventory 91.6 90.5 102.9 120.3 125.4

Days payable 229.8 202.2 262.1 304.5 311.9 Cash cycle (44.3) (21.6) (85.2) (109.2) (104.0) Source: Nomura estimates


KEPCO 015760 KS

POWER & UTILITIES | SOUTH KOREA

Keith Nam +82 2 3783 2304 [email protected]


20-year wait nearing an end? 20-year wait for a more guaranteed tariff scheme

Politics have had some major negative ramifications for KEPCO’s tariff adjustments throughout its post-IPO history (IPO: 1989). As a result, CPI inflation since 1990 has totalled 120%, compared to only a 60% gain in KEPCO’s tariffs. With the June regional elections over, a tariff hike could be brought forward to bring up KEPCO’s rate-of-return (ROR) to the minimum target (6%), before implementing a proposed fuel cost escalation scheme by July 2011. KEPCO’s ROR formula, heretofore a loose guideline for determining tariffs, has seen only a 4% average ROR on net power plant in service since the Asian crisis years (1997-98), with RORs meeting the minimum 6% target only in two of the 12 years since the Asian crisis.

Hurt by a volatile Korean currency, post-North Korea

The W:US$ rate has risen almost 10% since the naval incident with North Korea. Every 1% won depreciation versus the US dollar results in an estimated 3% earnings decrease, as won-translated fuel costs rise. Essentially all of KEPCO’s earnings are denominated in won, while almost all of its fuel costs are in US dollars, exposing earnings to the volatility of forex markets. Implementation of a fuel cost escalation scheme could smooth out such forex-linked earnings volatility after two consecutive years of earnings losses (FY08-09).

Looking to get out of the 0.4-0.5x P/BV bottom range

KEPCO is by far the cheapest valued major Asian power utility. We believe the low valuation stems from: 1) a loose tariff scheme influenced by the government’s political and economic agenda, and; 2) KEPCO’s defencelessness against volatile W:US$ currency movements. A tighter tariff scheme would re-rate KEPCO’s valuations, in our view.

Key financials & valuations31 Dec (Wbn) FY08 FY09 FY10F FY11FRevenue 31,302 33,661 39,479 46,257

Reported net prof it (2,981) (107) 1,706 2,365

Normalised net profit (2,981) (107) 1,706 2,365

Normalised EPS (W) (4,647) (167) 2,658 3,687

Norm. EPS growth (%) (296.6) na na 38.7

Norm. P/E (x) na na 13.1 9.4

EV/EBITDA (x) 20.7 8.0 6.1 5.7

Price/book (x ) 0.5 0.5 0.4 0.4

Div idend yield (%) 0.0 0.0 2.4 3.3

ROE (%) (7.0) (0.3) 3.7 4.5

Net debt/equity (%) 66.8 78.9 71.8 71.3

Earnings revisions

Prev ious norm. net profit (107) 1,706 2,365


Prev ious norm. EPS (W) (167) 2,658 3,687

Source: Company, Nom ura estimates

Share price relative to MSCI Korea

1m 3m 6m

3.7 (9.3) 4.8

6.2 (13.8) 3.7

(4.2) (11.5) 1.5

Hard

Source: Company, Nom ura estimates

18,235

46.0

41,600/28,000

65.2

Absolute (W )

Absolute (US$)

Relative to Index

Est imated free f loat (%)

Market cap (US$mn)

24.1


Korea Development Bank 30.0

52-week range (W )


Korean Governm ent

Stock borrowability

26,000

31,000

36,000

41,000

46,000

609

70

9

80

9

909

10

09

110

9

12

09

11

0

210

31

0

41

0

510

80859095100105110115120

Price

Rel MSCI Kore a(W)

Closing price on 23 Jun W34,000

Price target W43,000(set on 14 Jun 10)

Upside/downside 26.5%Difference from consensus -3.5%

FY10F net profit (Wbn) 1,706Difference from consensus -10.6%Source: Nomura

Nomura vs consensus Nomura’s price target is below consensus. Our EV/capacity (MW) valuation method considers debt and MW expansion trends.

Maintained

BUY

Action While long in the making, the government is proposing a fuel cost escalation

scheme for tariffs to be implemented in July 2011, which would link electricity rates to fuel input prices on a regular basis. A tighter tariff scheme should move valuation up from the current low ranges of 0.4-0.5x P/BV. We reaffirm our BUY call and PT of W43,000.

Catalysts Catalysts that would move KEPCO stock towards our PT: 1) a tighter tariff scheme

linked to fuel prices and currency, and; 2) longer term, won currency strength.

Anchor themes

Earnings are affected by movements in the won-to-US dollar rates, international fuel commodity prices, CPI and interest rates. Also, KEPCO leads Korea’s consortia that bid for various nuclear power projects overseas.

N O M U R A F I N A N C I A L I N V E S T M E N T ( K O R E A ) C O L T D

KEPCO Keith Nam


Valuation methodology and investment risks Our price target of W43,000 is based on an EV/MW target of US$820,000, the median of KEPCO’s post-IPO 20-year EV/MW capacity range. Risks: 1) essentially all of KEPCO’s earnings are denominated in won, while almost all of its fuel costs are in US dollars, exposing earnings to the volatility of the forex and energy markets and 2) changes in the government’s electricity tariff policy and the macro backdrop can also have a large impact on KEPCO’s earnings. Further, earnings are highly leveraged to revenue growth, which poses a direct risk if the street cuts sales forecasts.

KEPCO Keith Nam



Sharp improvement in EBITDA from FY08 bottom, but free cashflow deficit persists

Income statement (Wbn)

Year-end 31 Dec FY07 FY08 FY09 FY10F FY11F

Revenue 29,010 31,302 33,661 39,479 46,257Cost of goods sold (24,705) (32,618) (30,734) (34,040) (39,420)Gross profit 4,305 (1,316) 2,927 5,439 6,837SG&A (1,848) (2,040) (1,903) (1,729) (1,936)Employee share expenseOperating profit 2,457 (3,356) 1,024 3,709 4,900

EBITDA 7,590 2,088 6,571 9,244 10,555Depreciation (5,133) (5,444) (5,547) (5,535) (5,655)Amortisation - - - - - EBIT 2,457 (3,356) 1,024 3,709 4,900Net interest expense (616) (942) (1,534) (1,825) (2,138)Associates & JCEs 120 287 257 260 319Other income 491 28 462 637 752Earnings before tax 2,452 (3,983) 208 2,782 3,834Income tax (895) 1,030 (286) (1,043) (1,438)Net profit after tax 1,557 (2,953) (78) 1,739 2,396Minority interests (41) (29) (30) (33) (30)Other items - - - - - Preferred dividends - - - - - Normalised NPAT 1,516 (2,981) (107) 1,706 2,365Extraordinary items - - - - - Reported NPAT 1,516 (2,981) (107) 1,706 2,365

Dividends (467) - - (521) (719)Transfer to reserves 1,049 (2,981) (107) 1,184 1,647

Valuation and ratio analysisFD normalised P/E (x) 14.7 na na 13.1 9.4 FD normalised P/E at price target (x) 18.6 na na 16.6 11.9 Reported P/E (x) 14.4 na na 12.8 9.2 Dividend yield (%) 2.2 - - 2.4 3.3 Price/cashflow (x) 3.1 12.5 3.5 2.5 2.2

Price/book (x) 0.5 0.5 0.5 0.4 0.4 EV/EBITDA (x) 5.2 20.7 8.0 6.1 5.7 EV/EBIT (x) 15.6 na 42.4 14.6 11.8 Gross margin (%) 14.8 (4.2) 8.7 13.8 14.8 EBITDA margin (%) 26.2 6.7 19.5 23.4 22.8 EBIT margin (%) 8.5 (10.7) 3.0 9.4 10.6 Net margin (%) 5.2 (9.5) (0.3) 4.3 5.1 Effective tax rate (%) 36.5 na 137.3 37.5 37.5 Dividend payout (%) 30.8 na na 30.6 30.4 Capex to sales (%) 29.5 32.0 37.2 32.0 29.8 Capex to depreciation (x) 1.7 1.8 2.3 2.3 2.4

ROE (%) 3.5 (7.0) (0.3) 3.7 4.5 ROA (pretax %) 3.3 (3.7) 1.4 4.1 4.8

Growth (%)Revenue 7.1 7.9 7.5 17.3 17.2 EBITDA (4.0) (72.5) 214.7 40.7 14.2

EBIT (15.3) (236.6) na 262.4 32.1

Normalised EPS (26.4) (296.6) na na 38.7 Normalised FDEPS (26.0) (296.6) na na 38.7

Per shareReported EPS (W) 2,363 (4,647) (167) 2,658 3,687Norm EPS (W) 2,363 (4,647) (167) 2,658 3,687Fully diluted norm EPS (W) 2,307 (4,536) (163) 2,595 3,599

Book value per share (W) 68,633 63,847 64,170 78,099 87,185DPS (W) 750 - - 813 1,120Source: Nomura estim ates

KEPCO Keith Nam


Cashflow (Wbn)


EBITDA 7,590 2,088 6,571 9,244 10,555Change in working capital 872 (4,786) (1,072) (2,129) (958)Other operating cashflow (1,478) 4,444 805 1,529 358Cashflow from operations 6,984 1,746 6,303 8,644 9,955Capital expenditure (8,545) (10,021) (12,519) (12,622) (13,800)Free cashflow (1,561) (8,275) (6,216) (3,977) (3,845)Reduction in investments (689) (3,905) (342) (402) (483)Net acquisitions (396) (465) (575) (547) (474)Reduction in other LT assets (179) 1,984 - (1,745) (70)Addition in other LT liabilities 1,279 (134) 131 2,343 1Adjustments (22) 30 - - - Cashflow after investing acts (1,568) (10,765) (7,002) (4,328) (4,870)Cash dividends (467) - - (521) (719)Equity issue 63 11 36 0 36Debt issue 1,494 7,502 5,198 3,520 3,944Convertible debt issue 271 467 - (521) (197)Others 353 1,393 1,838 1,883 1,839Cashflow from financial acts 1,714 9,373 7,072 4,361 4,903Net cashflow 146 (1,393) 71 33 33Beginning cash 3,021 3,168 1,775 1,845 1,878Ending cash 3,168 1,775 1,845 1,878 1,911Ending net debt 18,452 27,346 32,474 35,961 39,872Source: Nomura estim ates

Balance sheet (Wbn)

As at 31 Dec FY07 FY08 FY09 FY10F FY11F

Cash & equivalents 3,168 1,775 1,845 1,878 1,911Marketable securities 21 15 10 - - Accounts receivable 3,039 3,554 4,581 4,727 4,901Inventories 2,633 4,272 3,895 4,313 4,800Other current assets 474 723 697 611 650Total current assets 9,335 10,339 11,029 11,530 12,262LT investments 3,206 7,117 7,463 7,875 8,358Fixed assets 67,563 69,795 74,033 84,438 92,583Goodwill - - - - - Other intangible assets 841 947 682 770 856Other LT assets 1,984 - - 1,745 1,815Total assets 82,929 88,199 93,208 106,357 115,874Short-term debt 5,499 5,802 6,463 7,581 5,926Accounts payable 2,751 3,570 2,864 2,880 2,993Other current liabil ities 1,088 1,163 1,420 (246) (618)Total current liabilities 9,338 10,536 10,748 10,215 8,301Long-term debt 16,121 23,319 27,856 30,259 35,857Convertible debt - - - - - Other LT liabil ities 13,203 13,069 13,201 15,544 15,545Total liabilities 38,662 46,924 51,804 56,017 59,704Minority interest 234 313 234 234 235Preferred stock - - - - -

Common stock 3,208 3,208 3,208 3,208 3,208Retained earnings 26,924 23,502 23,405 24,612 26,289Proposed dividends (467) - - (521) (719)



Liquidity (x)

Current ratio 1.00 0.98 1.03 1.13 1.48 Interest cover 4.0 (3.6) 0.7 2.0 2.3


Net debt/equity (%) 41.9 66.8 78.9 71.8 71.3


Days payable 42.0 35.5 38.2 30.8 27.2 Cash cycle 29.6 41.8 54.4 56.2 53.0 Source: Nomura estim ates

Capex increases as KEPCO builds more nuclear capacity


JA Solar JASO US

SOLAR | CHINA



Weather the looming storm Strength continues into 2Q10F; upside to guidance

We expect JA Solar’s business to remain solid in 2Q10F, thanks to rush demand ahead of subsidy cuts in Germany and tight cell capacity supply. We see upside to management’s margin guidance, given the company’s ability to pass on rising wafer costs to customers.

Immune to euro depreciation over near term

We believe that JA Solar will remain fairly immune to euro depreciation, given that we estimate only 15% of its 2Q10F revenue will be euro-denominated. Despite JA Solar’s overseas expansion, management noted it will cautiously hedge the company’s euro exposure should the euro remain weak in 2H10F.

Well positioned for 2H10F

In our view, JA Solar is well positioned for a potential industry slowdown in 2H10F, given its progress in module OEM, growing customer base and cost leadership. Based on its capacity plan, we deem FY10F shipment guidance of 1GW-plus conservative.

Brighter earnings outlook for FY10F

In our 20 May, 2010, report, we raised our FY10F earnings estimate by 83%, mainly to reflect a faster-than-expected capacity increase, a stronger ASP in 1H10F and a brighter margin outlook.

Attractive valuation

JA Solar trades at an attractive 33% discount to peers. We apply the peer average P/E of 9x to FY10F earnings to derive our US$8.00 PT, which implies 68% upside. Reiterating BUY. Risks include uncertainty regarding government policies on solar energy, execution of R&D initiatives and progress in signing up overseas business partners.

Key financials & valuations31 Dec (US$mn) FY08 FY09 FY10F FY11FRevenue 796 554 1,246 1,598

Reported net profit (56.7) (13.2) 141.4 170.1

Normalised net profit 69.3 (13.2) 141.4 170.1

Normalised EPS (US$) 0.41 (0.12) 0.86 1.04

Norm. EPS growth (%) 5.4 (129.3) na 21.4

Norm. P/E (x) 11.6 na 5.5 4.6

EV/EBITDA (x) 6.9 19.5 4.0 2.5

Price/book (x) 1.1 0.8 0.9 0.8

Dividend yield (%) 0.0 0.0 0.0 0.0

ROE (%) (9.0) (1.9) 18.6 18.5

Net debt/equity (%) 2.0 net cash 16.0 net cash

Earnings revisions

Prev ious norm. net profit (13.2) 141.4 170.1


Prev ious norm. EPS (US$) (0.12) 0.86 1.04


Share price relative to MSCI China

1m 3m 6m

(5.4) 1.7 (21.7)

(5.4) 1.7 (21.7)

(14.3) 1.8 (21.0)

H ard


773

63.2

6.92/3.37

54.8

Absolute (US$)

Absolute (US$)

Relative to Index


Market cap (US$mn)

15.0


J inglong Group 24.7

52-week range (U S$)


Fidelity

Stock borrowability

3.0

4.0

5.0

6.0

7.0

8.0

Jun

09

Aug

09

Oct

09

De

c09

Fe

b10

Apr

10

50

70

90

110

130

150

Price

Rel MSCI China(US$)

Closing price on 23 Jun US$4.77

Price target US$8.00(set on 20 May 10)


FY10F net profit (US$mn) 141.4Difference from consensus 16.1%Source: Nomura


Price target US$8.00(set on 20 May 10)


FY10F net profit (US$mn) 141.4Difference from consensus 16.1%Source: Nomura

Nomura vs consensus We are more positive than consensus on JA Solar’s ability to pass on higher material costs in 2Q10F and improve its customer mix to maintain volume growth in 2H10F.

Maintained

BUY


Action We believe that JA Solar’s business remains solid in 2Q10F and look for upside to

margin guidance. In our view, JA Solar is immune to euro depreciation over the near term. For 2H10F, we are confident that it can enhance its customer portfolio by acquiring more module OEM business from established European players. Reaffirm BUY with PT of US$8.00.

Catalysts Execution of share repurchase programme, announcement of new overseas

customers/partners, progress on R&D and strong financial results.

Anchor themes

As the solar photovoltaic cell industry turns into a buyer’s market, we expect firms with scale, cost leadership, brand equity, strong distribution channels and quality/ technology differentiation to stand out. We also prefer more vertically integrated players to standalone players.

JA Solar Clarisse Pan


We forecast top-line growth of 128% y-y in FY10F, backed by strong demand visibility and the launch of module OEM business

Gross margin to improve significantly in FY10F owing to much higher utilisation and resilient ASP in 1H10F

Financial statements Income statement (US$mn)


Revenue 362 796 554 1,246 1,598Cost of goods sold (281) (652) (483) (996) (1,311)Gross profit 81 145 70 250 287SG&A (21) (44) (57) (61) (80)Employee share expense - - - - - Operating profit 60 101 13 189 207

EBITDA 64 114 40 224 259Depreciation (5) (13) (26) (35) (52)Amortisation - - - - - EBIT 60 101 13 189 207Net interest expense 7 (16) (26) (23) (18)Associates & JCEs - - - - - Other income (14) (13) 0 (8) - Earnings before tax 53 73 (12) 159 189Income tax 1 (3) (1) (18) (19)Net profit after tax 54 69 (13) 141 170Minority interests - - - - - Other items - - - - - Preferred dividends (0) - - - - Normalised NPAT 53 69 (13) 141 170Extraordinary items - (126) - - - Reported NPAT 53 (57) (13) 141 170

Dividends - - - - - Transfer to reserves 53 (57) (13) 141 170

Valuation and ratio analysisFD normalised P/E (x) 12.3 11.6 na 5.5 4.6 FD normalised P/E at price target (x) 20.6 19.5 na 9.3 7.7 Reported P/E (x) 12.3 na na 5.5 4.6 Dividend yield (%) - - - - - Price/cashflow (x) na na 3.2 8.5 1.7 Price/book (x) 1.1 1.1 0.8 0.9 0.8 EV/EBITDA (x) 10.0 6.9 19.5 4.0 2.5 EV/EBIT (x) 10.8 7.8 57.4 4.8 3.1 Gross margin (%) 22.3 18.2 12.7 20.1 18.0 EBITDA margin (%) 17.8 14.3 7.2 18.0 16.2 EBIT margin (%) 16.5 12.7 2.4 15.2 13.0 Net margin (%) 14.7 (7.1) (2.4) 11.3 10.6 Effective tax rate (%) (1.4) 4.8 na 11.1 10.0 Dividend payout (%) - na na - - Capex to sales (%) 16.0 14.8 16.2 18.3 12.5 Capex to depreciation (x) 12.3 9.1 3.4 6.5 3.9

ROE (%) 18.0 (9.0) (1.9) 18.6 18.5 ROA (pretax %) 23.0 16.1 1.7 19.5 19.0

Growth (%)Revenue 305.3 120.1 (30.5) 125.1 28.2 EBITDA 252.9 76.7 (65.2) 466.1 15.6

EBIT 255.2 68.9 (86.7) 1,308.8 9.6

Normalised EPS 181.9 5.4 (129.3) na 21.4 Normalised FDEPS 181.9 5.4 (129.3) na 21.4

Per shareReported EPS (US$) 0.39 (0.34) (0.12) 0.86 1.04Norm EPS (US$) 0.39 0.41 (0.12) 0.86 1.04Fully diluted norm EPS (US$) 0.39 0.41 (0.12) 0.86 1.04Book value per share (US$) 4.22 4.46 6.00 5.07 6.17DPS (US$) - - - - - Source: Nomura est imates

Big FX losses unlikely given low euro exposure

JA Solar Clarisse Pan


Management recently raised capex guidance to US$220-250mn for FY10F given faster-than-expected capacity expansion

Cashflow (US$mn)


EBITDA 64 114 40 224 259Change in working capital (152) (33) 41 (168) 200Other operating cashflow (69) (270) 85 36 (7)Cashflow from operations (157) (189) 165 92 452Capital expenditure (58) (118) (89) (228) (200)Free cashflow (215) (307) 76 (136) 252Reduction in investments (110) 100 10 - - Net acquisitions - - - - - Reduction in other LT assets (74) (229) 16 84 35Addition in other LT liabilities 0 18 6 (1) - Adjustments 73 168 (24) (82) (35)Cashflow after investing acts (326) (250) 84 (134) 252Cash dividends - - - - - Equity issue 458 - - - - Debt issue 7 43 29 116 - Convertible debt issue - 370 (67) 3 - Others 6 (37) (55) - 5Cashflow from financial acts 471 376 (93) 119 5Net cashflow 145 126 (9) (15) 257Beginning cash 12 157 283 274 259Ending cash 157 283 274 259 516Ending net debt (130) 14 (1) 133 (124)Source: Nomura est imates

Balance sheet (US$mn)


Cash & equivalents 157 283 274 259 516Marketable securities 110 10 - - - Accounts receivable 7 52 50 169 111Inventories 22 87 94 179 36Other current assets 183 130 119 138 138Total current assets 479 561 536 745 802LT investments - - - - - Fixed assets 73 201 253 445 593Goodwill - - - - - Other intangible assets 1 2 2 - - Other LT assets 74 303 287 203 167Total assets 627 1,067 1,078 1,393 1,563Short-term debt 27 72 1 - - Accounts payable 1 17 54 55 88Other current liabilities 31 39 37 91 58Total current liabilities 59 128 92 146 146Long-term debt - - 100 217 217Convertible debt - 225 172 175 175Other LT liabilities 0 18 23 23 23Total liabilities 60 370 387 561 560Minority interest - - - - - Preferred stock - - - - - Common stock 0 0 0 0 0Retained earnings 57 117 92 233 403Proposed dividends - - - - -

Other equity and reserves 510 580 599 599 599Total shareholders' equity 567 697 691 832 1,002

Total equity & liabilities 627 1,067 1,078 1,393 1,563

Liquidity (x)

Current ratio 8.06 4.40 5.82 5.10 5.50 Interest cover na 6.5 0.5 8.4 11.2

LeverageNet debt/EBITDA (x) net cash 0.12 net cash 0.59 net cash

Net debt/equity (%) net cash 2.0 net cash 16.0 net cash


Days payable 1.1 5.2 26.9 20.0 20.0 Cash cycle 32.6 38.8 74.9 62.0 42.0 Source: Nomura est imates

One of the best balance sheets among listed solar companies


Yingli Green Energy YGE US

SOLAR | CHINA



Long-term fundamentals intact Strong 1H10F operating results expected

Yingli’s 1H10F operating results could beat consensus estimates on better gross margins as a result of higher ASPs and lower-than-expected polysilicon costs. We believe that Yingli, like other Chinese solar companies, is running at full capacity in 1H10F, which should further strengthen its non-silicon cost competitiveness.

Near-term headwind from weak euro

We expect Yingli’s earnings to be hit hard in 1H10F by a depreciating euro, given that 50-70% of its revenue is euro-denominated, vs only 0-20% of its COGS. We are reviewing our estimates on consideration of euro forex forecast revisions, but we still see a long-term buying opportunity post 1Q10F results despite recent weak sentiment, given the company's strong long-term competitiveness.

In-house poly and PANDA could provide +ve surprises

While the market appears concerned about Yingli’s in-house polysilicon project, which embeds execution risks and pushes blended silicon costs higher than peers in 2H10F, we remain confident about Yingli’s abilities to ramp production and to lower non-silicon costs to maintain overall cost leadership. The market also has not factored in much contribution from the PANDA modules, the launch of which we believe is on track and could provide upside surprises later this year.

Reiterating BUY

Our PT is based on FY10F earnings and a P/E of 22x. We apply a premium to peers as we remain positive on Yingli’s long-term prospects, given its brand equity and cost leadership. Risks include uncertainty over solar energy policy, execution risk, progress on disruptive technology R&D and slow capacity expansion.

Key financials & valuations31 Dec (RMBmn) FY08 FY09F FY10F FY11FRevenue 7,553 7,153 10,050 11,004

Reported net profit 667 (266) 1,029 1,143

Normalised net profit 667 (266) 1,029 1,143

Normalised EPS (RMB) 5.23 (2.32) 6.94 7.70

Norm. EPS growth (%) 34.7 (144.3) na 11.0

Norm. P/E (x) 14.2 na 10.3 9.0

EV/EBITDA (x) 10.0 14.3 5.3 4.7

Price/book (x) 1.9 1.3 1.4 1.2

Dividend yield (%) 0.0 0.0 0.0 0.0

ROE (%) 15.2 (4.9) 15.4 14.7

Net debt/equity (%) 57.5 50.8 41.0 34.0

Earnings revisions

Prev ious norm. net profit (266) 1,029 1,143


Prev ious norm. EPS (RMB) (2.32) 6.94 7.70



1m 3m 6m

9.8 (16.1) (36.1)

9.8 (16.1) (36.1)

0.9 (16.1) (35.4)

H ard


1,559

63.2

18.94/8.41

51.4

Absolute (US$)

Absolute (US$)

Relative to Index


Market cap (US$mn)


Mr. Liansheng Miao (Chairman) 36.8



Stock borrowability

79

111315171921

Jun0

9

Au

g09

Oct

09

Dec

09

Feb

10

Ap

r10

5060708090100110120

Price

Rel MSCI China(US$)


Price target US$23.00(set on 13 Jan 10)


FY10F net profit (RMBmn) 1,029Difference from consensus 23.2%Source: Nomura


Price target US$23.00(set on 13 Jan 10)



Nomura vs consensus We see downside to our estimates amid a weaker euro outlook. Nonetheless, we expect Yingli’s FY10F operating results to beat consensus estimates.

Maintained

BUY


Action We believe Yingli’s capacity expansion plans reflect its confidence in strong

demand throughout FY10F. More resilient ASPs in 1H10F should also boost margins to beat consensus estimates. Although the depreciating euro and weaker European economy are potential concerns, Yingli’s long-term fundamentals remain solid, in our view, underpinned by brand equity and cost leadership. Maintain BUY.

Catalysts Announcement of new sales contracts, smooth ramp up of in-house polysilicon

production, launch of PANDA module, and attainment of long-term debt financing.

Anchor themes

As the solar PV industry turns into a buyer’s market, we expect companies with scale, cost leadership, brand equity, strong distribution channels and quality/ technology differentiation to stand out. We also prefer more vertically integrated players to standalone players.

Yingli Green Energy Clarisse Pan



Expected gross margin expansion in FY10F is a function of more resilient ASP in 1H10F, higher utilisation rates and declining raw material costs

We recently raised our FY10F shipment estimate by 25%

We factor in depreciation from the in-house polysilicon facility starting in December 2009

Income statement (RMBmn)


Revenue 4,059 7,553 7,153 10,050 11,004Cost of goods sold (3,102) (5,923) (5,756) (7,347) (8,094)Gross profit 957 1,630 1,397 2,703 2,911SG&A (277) (476) (759) (895) (891)Employee share expense - - - - - Operating profit 680 1,153 638 1,809 2,019

EBITDA 814 1,368 965 2,487 2,742Depreciation (91) (159) (274) (626) (670)Amortisation (43) (56) (53) (53) (53)EBIT 680 1,153 638 1,809 2,019Net interest expense (51) (136) (348) (401) (379)Associates & JCEs (1) - - - - Other income (33) (62) (381) - - Earnings before tax 595 954 (91) 1,408 1,640Income tax (13) 6 (61) (211) (246)Net profit after tax 582 960 (151) 1,197 1,394Minority interests (193) (293) (114) (168) (251)Other items - - - - - Preferred dividends (11) - - - - Normalised NPAT 378 667 (266) 1,029 1,143Extraordinary items - - - - - Reported NPAT 378 667 (266) 1,029 1,143

Dividends - - - - - Transfer to reserves 378 667 (266) 1,029 1,143

Valuation and ratio analysisFD normalised P/E (x) 21.3 14.2 na 10.3 9.0 FD normalised P/E at price target (x) 46.7 31.1 na 22.5 19.8 Reported P/E (x) 20.6 14.0 na 9.9 8.7 Dividend yield (%) - - - - - Price/cashflow (x) na 9.8 23.2 3.7 4.2 Price/book (x) 1.9 1.9 1.3 1.4 1.2 EV/EBITDA (x) 16.6 10.0 14.3 5.3 4.7 EV/EBIT (x) 19.9 11.9 21.6 7.3 6.3 Gross margin (%) 23.6 21.6 19.5 26.9 26.4 EBITDA margin (%) 20.0 18.1 13.5 24.7 24.9 EBIT margin (%) 16.7 15.3 8.9 18.0 18.3 Net margin (%) 9.3 8.8 (3.7) 10.2 10.4 Effective tax rate (%) 2.2 (0.6) na 15.0 15.0 Dividend payout (%) - - na - - Capex to sales (%) 24.3 26.8 33.2 24.9 20.3 Capex to depreciation (x) 10.9 12.8 8.7 4.0 3.3

ROE (%) 18.6 15.2 (4.9) 15.4 14.7 ROA (pretax %) 14.4 13.9 5.8 14.1 14.3


EBIT 85.2 69.7 (44.7) 183.5 11.6

Normalised EPS 44.8 34.7 (144.3) na 11.0 Normalised FDEPS 44.8 37.6 (146.2) na 11.0

Per shareReported EPS (RMB) 3.9 5.2 (2.3) 6.9 7.7Norm EPS (RMB) 3.9 5.2 (2.3) 6.9 7.7Fully diluted norm EPS (RMB) 3.7 5.2 (2.4) 6.7 7.4Book value per share (RMB) 41.1 37.3 53.7 48.4 56.1DPS (RMB) - - - - - Source: Nomura est imates

Yingli Green Energy Clarisse Pan


We factor in a higher percentage of long-term debt going forward

We expect Yingli to continue expanding module capacity in FY10F

Cashflow (RMBmn)


EBITDA 814 1,368 965 2,487 2,742Change in working capital (2,567) (245) 56 614 123Other operating cashflow (325) (166) (668) (368) (461)Cashflow from operations (2,078) 958 354 2,733 2,404Capital expenditure (987) (2,027) (2,373) (2,501) (2,237)Free cashflow (3,065) (1,069) (2,019) 232 167Reduction in investments (8) (172) 171 - - Net acquisitions - - - - - Reduction in other LT assets (444) (29) 130 200 150Addition in other LT liabilities (593) 110 (8) 43 14Adjustments 843 (94) (338) (296) (217)Cashflow after investing acts (3,267) (1,255) (2,065) 179 114Cash dividends - - - - - Equity issue 3,591 - 1,680 - - Debt issue 994 1,487 1,543 1,250 (900)Convertible debt issue 1,263 - 58 (960) - Others (1,698) 24 (11) - - Cashflow from financial acts 4,149 1,512 3,270 290 (900)Net cashflow 883 257 1,206 469 (786)Beginning cash 78 961 1,218 2,424 2,893Ending cash 961 1,218 2,424 2,893 2,107Ending net debt 1,563 2,731 3,127 2,947 2,833Source: Nomura est imates

Balance sheet (RMBmn)

As at 31 Dec FY07 FY08 FY09F FY10F FY11F

Cash & equivalents 961 1,218 2,424 2,893 2,107Marketable securities - - - - - Accounts receivable 1,245 1,465 2,156 1,652 1,809Inventories 1,261 2,041 2,208 2,415 2,217Other current assets 1,622 1,338 908 758 758Total current assets 5,089 6,062 7,696 7,719 6,892LT investments 21 193 21 21 21Fixed assets 1,480 3,386 5,484 7,360 8,927Goodwill 359 666 626 626 626Other intangible assets 55 63 268 268 268Other LT assets 670 699 569 369 219Total assets 7,674 11,069 14,664 16,362 16,952Short-term debt 1,261 2,044 3,143 2,000 1,500Accounts payable 158 629 631 805 887Other current liabilities 157 156 639 633 633Total current liabilities 1,576 2,829 4,412 3,438 3,020Long-term debt - 663 1,108 3,500 3,100Convertible debt 1,263 1,242 1,300 340 340Other LT liabilities 79 188 180 224 238Total liabilities 2,917 4,923 7,000 7,501 6,698Minority interest 755 1,395 1,509 1,677 1,928Preferred stock - - - - - Common stock 10 10 10 10 10Retained earnings 359 1,026 760 1,790 2,933Proposed dividends - - - - -



Liquidity (x)



Net debt/equity (%) 39.1 57.5 50.8 41.0 34.0




LDK Solar LDK US

SOLAR | CHINA



Solid 1H but 2H remains unclear 1Q10 operating results beat consensus by 80%

LDK’s 1Q10 operating results exceeded consensus estimates by 80%, driven by solid gross margin and better-than-expected revenue. We believe the better gross margin was mainly attributable to a higher wafer OEM contribution and lower-than-expected polysilicon costs.

Guidance implies strength will continue into 2Q10F

Based on company guidance, we believe that LDK’s fundamentals will remain strong in 2Q10F, with rising shipments, ASP and gross margin. Guidance for 2Q10F revenue is about 23% higher than consensus.

But growing uncertainty beyond 2Q10F

LDK expects 3Q10F wafer and module ASPs to remain stable on a sequential basis. We see this as an aggressive assumption, considering the weak euro, subsidy cuts in Germany and major wafer makers’ capacity expansion plans in 2H10F.

Cash remains tight — dilution risk from equity offering

We expect LDK’s cash position to remain tight (net debt/equity at 156%) without any further divestments and equity fund raising in FY10F. We believe the company has the incentive to undertake an equity offering, which could present earnings dilution risk.

Fairly valued; maintain NEUTRAL and PT of US$8.00

Our PT of US$8.00 is based on our FY10F EPS forecast and the average FY10F P/E of Chinese solar companies (13x). Investment risks include progress on in-house polysilicon production, expansion strategy into the downstream, up/downside surprises from policy changes, earnings dilution risks from potential equity financing and whether LDK can continue to improve its balance sheet quality.

Key financials & valuations31 Dec (US$mn) FY08 FY09 FY10F FY11FRevenue 1,643 1,098 1,701 1,879

Reported net profit 70.2 (221.6) 82.3 91.1

Normalised net profit 70.2 (221.6) 82.3 91.1

Normalised EPS (US$) 0.67 (1.71) 0.63 0.69

Norm. EPS growth (%) (55.3) (354.9) na 10.6

Norm. P/E (x) 8.4 na 9.0 8.2

EV/EBITDA (x) 37.8 na 9.9 10.9

Price/book (x) 0.8 0.8 0.8 0.7

Dividend yield (%) 0.0 0.0 0.0 0.0

ROE (%) 9.6 (26.6) 8.9 9.0

Net debt/equity (%) 124.4 157.1 155.9 188.4

Earnings revisions

Prev ious norm. net profit (221.6) 82.3 91.1


Prev ious norm. EPS (US$) (1.71) 0.63 0.69



1m 3m 6m

(1.4) (17.7) (17.9)

(1.4) (17.7) (17.9)

(10.3) (17.7) (17.1)

H ard




Stock borrowability


Xiaofeng Peng 70.7

Absolute (US$)

Absolute (US$)

Relative to Index


Market cap (US$mn) 735

29.0

11.99/5.00

23.05

4.3

6.3

8.3

10.3

12.3

14.3

Jun0

9

Aug

09

Oct

09

De

c09

Fe

b10

Ap

r10

30405060708090100110

Price

Rel MSCI China(US$)


Price target US$8.00(set on 27 Nov 09)


FY10F net profit (US$mn) 82.3Difference from consensus 35.9%Source: N omura


Price target US$8.00(set on 27 Nov 09)


FY10F net profit (US$mn) 82.3Difference from consensus 35.9%Source: N omura

Nomura vs consensus We believe that consensus has yet to factor in LDK Solar’s 2Q10F results and thus we expect upside to current consensus numbers.

Note: price target under review

Maintained

NEUTRAL


Action LDK reported strong 1Q10 numbers, with its operating profit beating market

expectations by 80%. While we expect near-term share price strength on: 1) robust 2Q10F guidance, which is 23% above consensus; and 2) low exposure to euro depreciation, we remain NEUTRAL, on a stretched balance sheet, potential dilution risk from fund raising and a hazy outlook beyond 2Q10F.

Catalysts Further enhancement of balance sheet quality, smooth ramp-up of poly production

and progress on integration into the module business.

Anchor themes

As the solar PV industry turns into a buyer’s market, we expect companies with scale, cost leadership, brand equity, strong distribution channels and quality/ technology differentiation to stand out. We also prefer more vertically integrated players to standalone players.

LDK Solar Clarisse Pan



We expect the effective tax rate will reach a normal level of 15% by FY11F

Management has not provided guidance for FY11F capacity expansion, but we expect LDK to expand wafer capacity by 45% in FY11F, faster than the industry average

Income statement (US$mn)


Revenue 524 1,643 1,098 1,701 1,879Cost of goods sold (354) (1,555) (1,212) (1,418) (1,585)Gross profit 170 88 (114) 282 294SG&A (23) (79) (104) (116) (109)Employee share expense - - - - - Operating profit 147 9 (218) 166 185

EBITDA 162 45 (162) 226 252Depreciation (15) (36) (55) (60) (67)Amortisation - - - - - EBIT 147 9 (218) 166 185Net interest expense (5) (28) (46) (81) (93)Associates & JCEs - - - - - Other income 2 95 23 11 16Earnings before tax 143 75 (241) 95 107Income tax 1 (5) 19 (14) (16)Net profit after tax 144 70 (221) 82 91Minority interests (5) - (0) 1 - Other items - - - - - Preferred dividends - - - - - Normalised NPAT 139 70 (222) 82 91Extraordinary items - - - - - Reported NPAT 139 70 (222) 82 91

Dividends - - - - - Transfer to reserves 139 70 (222) 82 91

Valuation and ratio analysisFD normalised P/E (x) 3.8 8.4 na 9.0 8.2 FD normalised P/E at price target (x) 5.3 11.9 na 12.8 11.5 Reported P/E (x) 3.8 8.4 na 9.0 8.2 Dividend yield (%) - - - - - Price/cashflow (x) na 1.8 6.4 4.2 naPrice/book (x) 0.8 0.8 0.8 0.8 0.7 EV/EBITDA (x) 5.8 37.8 na 9.9 10.9 EV/EBIT (x) 6.4 189.0 na 13.5 14.8 Gross margin (%) 32.5 5.4 (10.3) 16.6 15.6 EBITDA margin (%) 30.9 2.7 (14.8) 13.3 13.4 EBIT margin (%) 28.0 0.5 (19.8) 9.8 9.8 Net margin (%) 26.6 4.3 (20.2) 4.8 4.8 Effective tax rate (%) (0.5) 6.8 na 14.3 15.0 Dividend payout (%) - - na - - Capex to sales (%) 58.2 68.5 69.8 17.2 20.6 Capex to depreciation (x) 20.2 31.3 13.8 4.9 5.8

ROE (%) 37.1 9.6 (26.6) 8.9 9.0 ROA (pretax %) 19.7 0.4 (6.1) 4.0 4.3

Growth (%)Revenue 396.8 213.7 (33.2) 54.9 10.5 EBITDA 305.6 (72.2) (460.4) na 11.2

EBIT 295.2 (93.9) (2,519.4) na 11.2

Normalised EPS 328.6 (55.3) (354.9) na 10.6 Normalised FDEPS 328.6 (55.3) (354.9) na 10.6

Per shareReported EPS (US$) 1.50 0.67 (1.71) 0.63 0.69Norm EPS (US$) 1.50 0.67 (1.71) 0.63 0.69Fully diluted norm EPS (US$) 1.50 0.67 (1.71) 0.63 0.69Book value per share (US$) 7.47 7.40 6.84 7.38 8.07DPS (US$) - - - - - Source: Nomura est imates

LDK Solar Clarisse Pan


Gearing remains high and we see potential dilution risks from equity financing in the near term

Management guides for capex to fall by US$200-300mn in FY10F, based on current capacity expansion plans

Cashflow (US$mn)


EBITDA 162 45 (162) 226 252Change in working capital (319) 263 364 (37) (8)Other operating cashflow 76 25 (87) (12) (344)Cashflow from operations (81) 333 115 177 (100)Capital expenditure (305) (1,126) (766) (293) (387)Free cashflow (386) (793) (651) (116) (487)Reduction in investments - - - - - Net acquisitions - - - - - Reduction in other LT assets (212) (207) 50 - - Addition in other LT liabilities 70 463 (45) 72 (250)Adjustments 119 (377) (84) (72) 250Cashflow after investing acts (409) (914) (731) (116) (487)Cash dividends - - - - - Equity issue 369 6 300 - - Debt issue 97 641 568 293 387Convertible debt issue - 389 - - - Others (4) 50 (8) - - Cashflow from financial acts 462 1,086 860 293 387Net cashflow 53 172 129 177 (100)Beginning cash 30 83 256 385 562Ending cash 83 256 385 562 462Ending net debt 206 965 1,395 1,511 1,998Source: Nomura est imates

Balance sheet (US$mn)


Cash & equivalents 83 256 385 562 462Marketable securities - - - - - Accounts receivable 4 95 214 140 129Inventories 350 617 432 500 281Other current assets 305 270 366 366 366Total current assets 742 1,238 1,397 1,568 1,238LT investments - - - - - Fixed assets 337 1,697 2,609 2,842 3,161Goodwill - - - - - Other intangible assets 1 1 1 1 1Other LT assets 230 438 388 388 388Total assets 1,310 3,374 4,395 4,799 4,788Short-term debt 264 666 980 980 980Accounts payable 18 124 191 97 109Other current liabilities 240 721 1,048 1,099 849Total current liabilities 522 1,511 2,220 2,177 1,938Long-term debt 25 154 408 701 1,088Convertible debt - 400 392 392 392Other LT liabilities 70 533 488 560 310Total liabilities 617 2,598 3,507 3,830 3,728Minority interest - - - - - Preferred stock - - - - - Common stock 11 11 13 13 13Retained earnings 146 205 (22) 60 151Proposed dividends - - - - -

Other equity and reserves 536 559 897 897 897Total shareholders' equity 693 776 888 970 1,061


Liquidity (x)

Current ratio 1.42 0.82 0.63 0.72 0.64 Interest cover 27.6 0.3 (4.7) 2.0 2.0

LeverageNet debt/EBITDA (x) 1.27 21.45 na 6.68 7.94

Net debt/equity (%) 29.7 124.4 157.1 155.9 188.4




China Longyuan Power 916 HK

POWER & UTILITIES/ALTERNATIVE ENERGY | CHINA



An expensive growth story FY09 results: 13% below our expectations

CLYP’s FY09 results were 13% below our estimates and 11% below market consensus. The worse-than-expected results were mainly driven by increased operating expenses (23% higher than expected), caused by higher material costs, repair and maintenance expenses, and administration outlays.

FY10F and FY11F estimates

We recently trimmed our earnings estimates by 7% and 11% for FY10F and FY11F, respectively, to factor in rising operating expenses. Although our FY10F net profit forecast is ~20% below consensus, we regard our assumptions as quite generous compared with guidance, particularly for wind operating hours (up 2.5% h-h vs flattish), wind electricity generation (11,967GWh vs 10,000GWh+), and wind power tariff (up 1.2% h-h vs 0.1%+ y-y).

Challenging environment for wind operators in China

Although wind power is the most promoted renewable energy source by the Chinese government, which provides top-line growth visibility, we believe that the profitability outlook remains challenging for wind operators in China, due to: 1) an unattractive tariff scheme that allows an ROE of 8-10%; 2) grid connection bottlenecks, and; 3) the threat of interest rate hikes.

Demanding valuation; REDUCE reaffirmed

Our PT is based on DCF, with a WACC of 11.8% and terminal growth of 1% after FY19F. Nonetheless, the shares look demanding, at 91% above the average of peer wind operators. Reiterating REDUCE. PT risks: CER VER registration risks, resolution of grid connection bottleneck in China, uncertainties from wind subsidies.

Key financials & valuations31 Dec (RMBmn) FY08 FY09 FY10F FY11FRevenue 8,555 9,744 13,085 16,397

Reported net profit 337 894 1,464 2,351

Normalised net profit 337 894 1,464 2,351

Normalised EPS (RMB) 0.07 0.15 0.20 0.31

Norm. EPS growth (%) 56.9 119.1 32.6 60.6

Norm. P/E (x) 105.8 46.1 33.6 20.5

EV/EBITDA (x) 34.6 17.1 13.8 11.5

Price/book (x) 8.9 1.9 2.1 1.9

Dividend yield (%) 0.0 0.0 0.0 0.0

ROE (%) 10.0 6.9 6.5 9.6

Net debt/equity (%) 542.6 76.7 128.9 189.5

Earnings revisions

Prev ious norm. net profit 894 1,464 2,351


Prev ious norm. EPS (RMB) 0.15 0.20 0.31



1m 3m 6m

10.3 (16.5) (21.6)

10.7 (16.7) (21.9)

1.3 (16.4) (20.8)

H ard


52-week range (H K$)


China Investment Corp

Stock borrowability

12.0


Guodian 67.0

Absolute (HK$)

Absolute (US$)

Relative to Index


Market cap (US$mn) 7,513

81.8

10.90/6.72

27.59

6

7

8

9

10

11

De

c09

Fe

b10

Ap

r10

Jun

10

-10.00010.00030.00050.00070.00090.000110.000130.000

Price

Rel MSCI China(HK$)

Closing price on 23 Jun HK$7.83

Price target HK$8.50(set on 1 Apr 10)


FY10F net profit (RMBmn) 1,464Difference from consensus -19.3%Source: Nomura




FY10F net profit (RMBmn) 1,464Difference from consensus -19.3%Source: Nomura

Nomura vs consensus We are less positive about the outlook for wind tariffs in China as well as the resolution of grid connection issues over the near term.


Maintained

REDUCE


Action CLYP’s FY09 results were 13% below our expectations mainly due to higher

operating expenses, which led us to trim our earnings estimates by 7% for FY10F and 11% for FY11F. We recognise CLYP’s scarcity value as Asia’s largest wind operator, but view the current valuation of 33.6x FY10F P/E as demanding, given the unattractive returns from its wind operations in China. Reiterating REDUCE.

Catalysts Interest rate increases, rising raw material (steel and coal) prices, listing of wind

subsidiaries of other state-owned power companies, may lead to de-rating.

Anchor themes

We see wind as the best investment option, as it is the world’s most commercial green energy. Its low costs and stable output should underpin installed capacity growth of around 30% per annum globally over the next five to ten years. We expect better growth opportunities down the value chain in Asia.

China Longyuan Power Clarisse Pan



We expect minority interests as a percentage of PAT to trend downwards, as the company targets to fully own all of its upcoming wind projects



Revenue 6,963 8,555 9,744 13,085 16,397Fuel costs (2,347) (3,128) (2,290) (2,823) (2,813)Repairs & Maintenance (105) (87) (108) (184) (234)Personnel expenses (384) (384) (540) (737) (936)SG&A (101) (107) (148) (197) (234)Other operating expenses (2,299) (2,735) (2,783) (3,503) (3,919)Employee share expense - - - - -

EBITDA 1,728 2,114 3,875 5,641 8,261Depreciation (778) (1,083) (1,590) (2,420) (3,393)Amortisation - - - - - EBIT 950 1,031 2,285 3,221 4,868Net interest expense (364) (858) (1,020) (1,711) (2,442)Associates & JCEs 18 53 105 153 153Other income 169 390 574 785 1,071Earnings before tax 773 616 1,944 2,448 3,650Income tax (60) (2) (296) (196) (292)Net profit after tax 712 614 1,647 2,252 3,358Minority interests (497) (277) (753) (788) (1,007)Other items - - - - - Preferred dividends - - - - - Normalised NPAT 215 337 894 1,464 2,351Extraordinary itemsReported NPAT 215 337 894 1,464 2,351

DividendsTransfer to reserves 215 337 894 1,464 2,351

Valuation and ratio analysisFD normalised P/E (x) 177.5 105.8 46.1 33.6 20.5 FD normalised P/E at price target (x) 192.7 114.9 50.0 36.5 22.2 Reported P/E (x) 177.5 105.8 46.1 33.6 20.5 Dividend yield (%) - - - - - Price/cashflow (x) 64.5 12.6 9.4 5.3 26.9 Price/book (x) 12.8 8.9 1.9 2.1 1.9 EV/EBITDA (x) 40.5 34.6 17.1 13.8 11.5 EV/EBIT (x) 73.1 69.3 28.4 23.8 19.3 EV per MW (RMB) na na na na naEBITDA margin (%) 24.8 24.7 39.8 43.1 50.4 EBIT margin (%) 13.6 12.0 23.4 24.6 29.7 Net margin (%) 3.1 3.9 9.2 11.2 14.3 Effective tax rate (%) 7.8 0.3 15.3 8.0 8.0 Dividend payout (%) - - - - - Capex to sales (%) 102.9 135.6 149.9 166.7 116.8 Capex to depreciation (x) 9.2 10.7 9.2 9.0 5.6

ROE (%) 8.9 10.0 6.9 6.5 9.6 ROA (pretax %) 5.2 3.8 5.5 5.4 6.1

Growth (%)Revenue 27.9 22.9 13.9 34.3 25.3 EBITDA 16.8 22.3 83.3 45.6 46.5

EBIT 9.2 8.5 121.7 41.0 51.1

Normalised EPS 43.6 56.9 119.1 32.6 60.6 Normalised FDEPS 43.6 56.9 119.1 32.6 60.6

Per shareReported EPS (RMB) 0.04 0.07 0.15 0.20 0.31Norm EPS (RMB) 0.04 0.07 0.15 0.20 0.31Fully diluted norm EPS (RMB) 0.04 0.07 0.15 0.20 0.31Book value per share (RMB) 0.57 0.78 3.62 3.13 3.44DPS (RMB) - - - - - Source: Nomura est imates

We recently raised our revenue forecasts after factoring in a significant contribution from coal sales, which started in 2H09

China Longyuan Power Clarisse Pan


Management guides that given the current expansion plan, the company will not resort to equity financing before mid- FY12F

We have factored in declining wind farm construction costs (~10% y-y), and capacity expansion by 2GW per annum

Cashflow (RMBmn)


EBITDA 1,728 2,114 3,875 5,641 8,261Change in working capital (863) (221) 1,893 3,819 (6,213)Other operating cashflow (274) 947 (1,365) (166) (262)Cashflow from operations 591 2,840 4,402 9,294 1,786Capital expenditure (7,162) (11,603) (14,605) (21,812) (19,147)Free cashflow (6,570) (8,764) (10,202) (12,518) (17,360)Reduction in investments (249) 153 (233) - - Net acquisitions (706) (726) (2,136) 153 153Reduction in other LT assets - - - - - Addition in other LT liabilities - - - - - Adjustments 752 1,090 922 996 1,198Cashflow after investing acts (6,774) (8,246) (11,649) (11,369) (16,010)Cash dividends - - - - - Equity issue 994 1,951 4,301 - - Debt issue 6,970 6,803 10,204 2,411 16,548Convertible debt issue - - - - - Others (483) (315) 12,645 - - Cashflow from financial acts 7,480 8,439 27,150 2,411 16,548Net cashflow 706 193 15,501 (8,959) 539Beginning cash 102 809 1,002 16,503 7,544Ending cash 809 1,002 16,503 7,544 8,083Ending net debt 13,192 21,029 16,803 30,125 48,733Source: Nomura est imates



Cash & equivalents 809 1,002 16,503 7,544 8,083Marketable securities 0 0 - - - Accounts receivable 866 1,241 2,181 2,480 3,360Inventories 205 279 333 963 557Other current assets 1,210 2,358 1,350 3,114 3,776Total current assets 3,090 4,880 20,367 14,101 15,776LT investments 851 698 932 932 932Fixed assets 14,937 24,290 37,305 56,696 72,450Goodwill - - - - - Other intangible assets 2,997 5,083 6,086 6,086 6,086Other LT assets 1,450 1,097 3,264 3,264 3,264Total assets 23,325 36,049 67,954 81,079 98,509Short-term debt 6,156 4,686 17,087 17,087 17,087Accounts payable 1,779 2,729 1,943 6,697 3,437Other current liabilities 1,570 1,998 4,662 6,419 4,604Total current liabilities 9,506 9,413 23,692 30,203 25,128Long-term debt 7,845 17,345 16,219 20,582 39,728Convertible debt - - - - - Other LT liabilities 446 2,219 2,363 2,363 2,363Total liabilities 17,797 28,977 42,274 53,148 67,219Minority interest 2,663 3,198 3,780 4,568 5,576Preferred stock - - - - - Common stock 1,663 3,163 7,464 7,464 7,464Retained earnings 1,202 712 14,436 15,899 18,250Proposed dividends - - - - -

Other equity and reserves - - - - - Total shareholders' equity 2,865 3,875 21,900 23,363 25,714


Liquidity (x)



Net debt/equity (%) 460.4 542.6 76.7 128.9 189.5


Days payable 304.5 256.6 355.5 524.3 607.1 Cash cycle (240.9) (183.2) (242.7) (375.5) (443.4) Source: Nomura est imates


Suzlon Energy SUEL IN

POWER & UTILITIES | INDIA



Smaller-than-expected boost Divestment in Hansen to strengthen balance sheet

Suzlon announced the placement of 236mn shares in Hansen, representing 35.2% of Hansen's issued share capital, at a price of GBp95 per share in 3Q09. The total proceeds before commission and expenses are US$370mn. According to Suzlon, it will not dispose its remaining stake in Hansen (26%) within the next 180 days.

Incrementally positive, but gearing remains high

We believe the divestment will be incrementally positive for Suzlon, as it should relieve cashflow pressure in the near term. As of end-September 2009, Suzlon had net debt of INR125bn at the parent level, and we estimate that Suzlon can eliminate 14% of its debt with the proceeds. However, since the placement is smaller than we expected, we expect Suzlon’s gearing to remain high in FY10F and FY11F.

Bottom in sight, but likely to miss FY10F guidance again

We believe Suzlon is likely to miss the lower end of its FY10F shipment guidance (1,900MW), based on the company’s new international order intake, post its 1H FY10 results announcement. Suzlon’s subsidiary REpower won a significant new order worth 954MW, reflecting improving fundamentals, but we expect the benefits to accrue only in FY12-16F.

Price target under review; keep NEUTRAL

Post the Hansen divestment, clarity on consolidated balance sheet and cashflows is lacking. Our Rs88.8 PT is under review pending details, likely after FY10 results at end-May. Downside risks: uncertainty from policy supports, failure in migrating technology forward, higher-than-expected product liability provisions. Upside risks: earlier than expected recovery in the US wind turbine market.

Key financials & valuations31 Mar (Rsmn) FY09 FY10F FY11F FY12FRevenue 260,817 213,666 243,698 298,262



Normalised EPS (Rs) 7.67 1.33 5.70 10.18

Norm. EPS growth (%) (15.6) (82.7) 329.6 78.7

Norm. P/E (x) 7.9 45.8 10.5 5.9

EV/EBITDA (x) 6.4 9.3 7.7 6.1

Price/book (x) 1.0 1.0 0.9 0.8

Dividend yield (%) 0.0 0.0 0.0 0.0

ROE (%) 2.8 2.3 9.5 14.9

Net debt/equity (%) 137.2 105.4 112.9 98.1

Earnings revisions

Prev ious norm. net profit 2,025 8,868 15,850


Prev ious norm. EPS (Rs) 1.33 5.70 10.18


Share price relative to MSCI India

1m 3m 6m

(1.9) (21.6) (34.8)

(0.4) (22.6) (33.8)

(10.1) (22.4) (38.3)

H ard


52-week range (R s)


Stock borrowability


Promoter and Promoter Group 53.0

Absolute (Rs)

Absolute (US$)

Relative to Index



42.0

123.5/53.5

28.35

46

66

86

106

126

146

Jun

09

Aug

09

Oct

09

De

c09

Fe

b10

Ap

r10

30405060708090100110

Price

Rel MSCI India(Rs)

Closing price on 23 Jun Rs57.6

Price target Rs88.8(set on 3 Dec 09)


FY11F net profit (Rsmn) 8,868Difference from consensus 135.2%Source: Nom ura

Closing price on 23 Jun Rs57.6

Price target Rs88.8(set on 3 Dec 09)


FY11F net profit (Rsmn) 8,868Difference from consensus 135.2%Source: Nom ura

Nomura vs. consensus We believe that consensus estimates have not been adjusted post the divestment, owing to inadequate financial statements disclosure.

Maintained

NEUTRAL


Action Suzlon has been enhancing its cash position through divestment and debt

restructuring since 2009. We believe these moves are incrementally positive but estimate Suzlon’s gearing will remain high, at 105% in FY10F. We also expect Suzlon to likely miss its FY10F shipment guidance. Pending further progress on order inflows and balance sheet clean-up, reiterating NEUTRAL.

Catalysts We would turn more positive on Suzlon in the event of more significant

enhancement in balance sheet quality or more aggressive order intake.

Anchor themes

We see wind as the best investment option, as it is the world’s most commercial green energy. Its low costs and stable output should underpin installed capacity growth of around 30% per annum globally over the next five to ten years. We expect better growth opportunities down the value chain in Asia.

Suzlon Energy Clarisse Pan



We have factored in Hansen disposal gain of INR3bn for FY10F

Income statement (Rsmn)

Year-end 31 Mar FY08 FY09 FY10F FY11F FY12F

Revenue 136,794 260,817 213,666 243,698 298,262Cost of goods sold (88,702) (168,568) (151,620) (169,715) (208,180)Gross profit 48,093 92,249 62,046 73,983 90,081SG&A (27,451) (65,576) (46,745) (52,483) (61,858)Employee share expense - - - - - Operating profit 20,641 26,673 15,301 21,501 28,224

EBITDA 23,535 32,405 19,849 26,180 32,936Depreciation (2,894) (5,731) (4,548) (4,679) (4,713)Amortisation - - - - - EBIT 20,641 26,673 15,301 21,501 28,224Net interest expense (5,969) (10,539) (11,374) (11,425) (10,335)Associates & JCEs - - - - - Other income (15) (1) - - - Earnings before tax 14,657 16,133 3,927 10,075 17,889Income tax (1,633) (2,881) (1,454) (1,713) (3,041)Net profit after tax 13,024 13,252 2,473 8,363 14,848Minority interests (428) (1,947) (550) (373) (460)Other items 558 23 103 879 1,462Preferred dividends - - - - - Normalised NPAT 13,153 11,328 2,025 8,868 15,850Extraordinary items (2,852) (8,963) - - - Reported NPAT 10,301 2,365 2,025 8,868 15,850

Dividends (1,497) - - - - Transfer to reserves 8,804 2,365 2,025 8,868 15,850

Valuation and ratio analysisFD normalised P/E (x) 6.5 7.9 45.8 10.5 5.9 FD normalised P/E at price target (x) 10.1 12.2 70.7 16.1 9.0 Reported P/E (x) 8.1 36.0 43.4 10.1 5.7 Dividend yield (%) 1.8 - - - - Price/cashflow (x) 6.9 na 5.2 na 7.3 Price/book (x) 1.0 1.0 1.0 0.9 0.8 EV/EBITDA (x) 5.1 6.4 9.3 7.7 6.1 EV/EBIT (x) 5.8 7.8 12.0 9.3 7.1 Gross margin (%) 35.2 35.4 29.0 30.4 30.2 EBITDA margin (%) 17.2 12.4 9.3 10.7 11.0 EBIT margin (%) 15.1 10.2 7.2 8.8 9.5 Net margin (%) 7.5 0.9 0.9 3.6 5.3 Effective tax rate (%) 11.1 17.9 37.0 17.0 17.0 Dividend payout (%) 14.5 - - - - Capex to sales (%) 15.5 12.7 (16.1) 3.3 1.9 Capex to depreciation (x) 7.3 5.8 (7.6) 1.7 1.2

ROE (%) 17.7 2.8 2.3 9.5 14.9 ROA (pretax %) 13.4 9.8 4.9 7.2 8.4


EBIT 65.6 29.2 (42.6) 40.5 31.3

Normalised EPS 47.5 (15.6) (82.7) 329.6 78.7 Normalised FDEPS 46.7 (17.1) (82.8) 337.9 78.7

Per shareReported EPS (Rs) 7.1 1.6 1.3 5.7 10.2Norm EPS (Rs) 9.1 7.7 1.3 5.7 10.2Fully diluted norm EPS (Rs) 8.8 7.3 1.3 5.5 9.8Book value per share (Rs) 55.7 57.6 57.4 63.1 73.3DPS (Rs) 1.0 - - - - Source: Nomura est imates

Note: PT basis: one-year forward P/E multiple of 16x FY11F earnings.

Suzlon Energy Clarisse Pan


We expect gearing to remain high in FY10F and FY11F

Cashflow (Rsmn)

Year-end 31 Mar FY08 FY09 FY10F FY11F FY12F

EBITDA 23,535 32,405 19,849 26,180 32,936Change in working capital (2,408) (39,806) 8,562 (21,859) (14,951)Other operating cashflow (9,084) (4,836) (11,578) (5,490) (5,639)Cashflow from operations 12,043 (12,238) 16,834 (1,170) 12,347Capital expenditure (21,205) (33,167) 34,406 (7,954) (5,551)Free cashflow (9,162) (45,404) 51,240 (9,124) 6,796Reduction in investments (31,262) 31,367 (9,988) (879) (1,462)Net acquisitions - (41,776) - - - Reduction in other LT assets (393) (4,689) 89 - - Addition in other LT liabilities 434 2,359 (2,248) - - Adjustments 6,058 (27,313) 10,227 4,656 4,060Cashflow after investing acts (34,324) (85,456) 49,320 (5,347) 9,394Cash dividends (9) (1,514) - - - Equity issue 21,887 1,019 1,025 - - Debt issue 25,393 40,086 (5,742) 7,047 (35,000)Convertible debt issue 20,099 - - - - Others 21,173 6,961 (26,062) (11,425) (10,335)Cashflow from financial acts 88,543 46,552 (30,779) (4,379) (45,335)Net cashflow 54,219 (38,904) 18,541 (9,725) (35,941)Beginning cash 15,383 69,602 30,698 49,240 39,514Ending cash 69,602 30,698 49,240 39,514 3,573Ending net debt 30,034 118,436 94,153 110,925 111,866Source: Nomura est imates

Balance sheet (Rsmn)

As at 31 Mar FY08 FY09 FY10F FY11F FY12F

Cash & equivalents 69,602 30,698 49,240 39,514 3,573Marketable securities - - - - - Accounts receivable 32,013 53,928 35,835 56,674 69,363Inventories 40,848 71,737 56,978 77,143 94,627Other current assets 33,143 62,466 53,278 53,278 53,278Total current assets 175,606 218,828 195,331 226,609 220,842LT investments 31,418 51 10,039 10,918 12,380Fixed assets 56,877 152,654 113,700 116,975 117,813Goodwill - - - - - Other intangible assets - - - - - Other LT assets 1,841 6,529 6,440 6,440 6,440Total assets 265,742 378,063 325,510 360,942 357,474Short-term debt 290 439 439 439 439Accounts payable 30,435 59,962 42,546 56,572 69,393Other current liabilities 42,330 55,123 39,062 44,181 46,582Total current liabilities 73,055 115,523 82,047 101,191 116,414Long-term debt 99,346 148,696 142,953 150,000 115,000Convertible debt - - - - - Other LT liabilities 2,059 4,417 2,170 2,170 2,170Total liabilities 174,460 268,636 227,170 253,361 233,584Minority interest 10,244 23,135 8,998 9,371 9,831Preferred stock 25 25 - - - Common stock 2,994 2,997 2,997 2,997 2,997Retained earnings 77,917 82,216 84,242 93,110 108,959Proposed dividends - - - - -

Other equity and reserves 102 1,054 2,104 2,104 2,104Total shareholders' equity 81,038 86,292 89,343 98,211 114,060


Liquidity (x)



Net debt/equity (%) 37.1 137.2 105.4 112.9 98.1




GCL Poly Energy 3800 HK

SOLAR | CHINA



Execution will be key Poly surplus to persist despite surging demand

While we have witnessed tight supply in the ingot/wafer and cell segments, driven by surging demand before the German subsidy cut, we note that polysilicon supply seems ample since late 3Q09. Going into 2H10, we believe that polysilicon supply surplus will continue, given the expansion plans announced by major players.

High execution risks from in-house wafer ramp

GCL Poly announced its expansion into the wafer business for FY10, ramping up wafer capacity from 0MW at the beginning of FY10 to 2GW by year-end. It expects its wafer production to reach 1.3GW in FY10. We consider this aggressive, given that wafer shipment guidance implies the new lines would constantly run at full utilisation, compared with the industry norm of two to three months ramp time.

FY10F EPS reflect wafer ramp; BVPS restated

We recently raised our FY10F earnings by 49%, mainly to factor in the updated wafer expansion plan. We view guidance for 1.3GW shipment as aggressive and factor in a shipment of 1.2GW, assuming GCL would internally produce 775MW and fulfil the rest through a third-party processing service, which implies lower margins than management guidance. We lowered our FY10F BVPS from RMB1.60 to RMB0.80 post a major accounting restatement, which lowered our book value for FY08 and FY09 from RMB2.4bn and RMB23bn to negative RMB1bn and RMB11bn, respectively.

NEUTRAL rating and price target maintained

Our price target of HK$1.30 is based on earnings estimates and 1.4x FY10F book, in line with the current peer group average. We maintain our NEUTRAL rating on GCL Poly.

Key financials & valuations31 Dec (RMBmn) FY08 FY09 FY10F FY11F

Revenue 3,521 4,356 14,203 14,803

Reported net profit 1,923 (176) 2,149 2,102

Normalised net profit 1,923 (176) 2,149 2,102

Normalised EPS (R MB) 0.41 (0.02) 0.14 0.14

Norm. EPS growth (%) na (103.9) na (2.2)

Norm. P/E (x) 4.8 na 9.8 9.8

EV/EBITDA (x) 11.8 17.6 6.6 6.8

Price/book (x) na 1.5 1.7 1.4

Dividend yield (%) 0.0 0.0 0.0 0.0

ROE (%) na (3.8) 19.0 15.7

Net debt/equity (%) (234.5) 28.1 14.7 20.5

Earn ings revisions

Previous norm. net profit (176) 2,149 2,102


Previous norm. EPS (RMB) (0.016) 0.139 0.136



1m 3m 6m

22.7 (13.8) (24.3)

23.2 (14.0) (24.5)

13.8 (13.7) (23.5)

Hard


3,222

47.5

3.67/1.24

7.77

Absolute (HK$)

Absolute (US$)

Relative to Index


Market cap (US$mn)

20.1


Asia Pacific Energy Fund (Chairman) 32.4

52-week range (HK$)


CIC

Stock borrowability

0.9

1.4

1.9

2.4

2.9

3.4

3.9

Jun

09

Jul

09

Au

g09

Se

p09

Oct

09

No

v09

De

c09

Jan

10

Fe

b10

Ma

r10

Apr

10

Ma

y10

30

50

70

90

110

130

Price

Rel MSCI China(H K$)

Key financials & valuations31 Dec (RMBmn) FY08 FY09 FY10F FY11F

Revenue 3,521 4,356 14,203 14,803

Reported net profit 1,923 (176) 2,149 2,102

Normalised net profit 1,923 (176) 2,149 2,102

Normalised EPS (R MB) 0.41 (0.02) 0.14 0.14

Norm. EPS growth (%) na (103.9) na (2.2)

Norm. P/E (x) 4.8 na 9.8 9.8

EV/EBITDA (x) 11.8 17.6 6.6 6.8

Price/book (x) na 1.5 1.7 1.4

Dividend yield (%) 0.0 0.0 0.0 0.0

ROE (%) na (3.8) 19.0 15.7

Net debt/equity (%) (234.5) 28.1 14.7 20.5

Earn ings revisions

Previous norm. net profit (176) 2,149 2,102


Previous norm. EPS (RMB) (0.016) 0.139 0.136



1m 3m 6m

22.7 (13.8) (24.3)

23.2 (14.0) (24.5)

13.8 (13.7) (23.5)

Hard


3,222

47.5

3.67/1.24

7.77

Absolute (HK$)

Absolute (US$)

Relative to Index


Market cap (US$mn)

20.1


Asia Pacific Energy Fund (Chairman) 32.4

52-week range (HK$)


CIC

Stock borrowability

0.9

1.4

1.9

2.4

2.9

3.4

3.9

Jun

09

Jul

09

Au

g09

Se

p09

Oct

09

No

v09

De

c09

Jan

10

Fe

b10

Ma

r10

Apr

10

Ma

y10

30

50

70

90

110

130

Price

Rel MSCI China(H K$)


Price target HK$1.30(set on 24 May 10)

Upside/downside -19.8%Difference from consensus -23.5%



Price target HK$1.30(set on 24 May 10)



Nomura vs consensus We are more positive on assumptions for the wafer business although our numbers remain lower than management guidance.


Maintained

NEUTRAL


Action Despite the surge in solar demand since late 3Q09, we observe that polysilicon

supply has remained in surplus due to aggressive capacity expansion by players since FY07. In our view, GCL’s guidance for its newly launched wafer business seems aggressive and has high execution risks. We maintain NEUTRAL and a PT of HK$1.30, based on recently revised earnings estimates and FY10F peer group P/B.

Catalysts We would turn more positive on: attainment of solar PV projects overseas, smooth

ramp-up of wafer production, lowered electricity tariffs for its poly production plant.

Anchor themes

As the supply surplus of solar PV continues in 2010, we expect companies with scale, cost leadership, brand equity, strong distribution channels and quality/technology differentiation to stand out among peers. We also prefer more vertically integrated players to standalone players.

GCL Poly Energy Clarisse Pan





Revenue 3,521 4,356 14,203 14,803Cost of goods sold (967) (3,042) (10,764) (11,412)Gross profit - 2,555 1,313 3,439 3,391SG&A (214) (381) (582) (607)Employee share expense - - - - Operating profit - 2,341 933 2,857 2,784

EBITDA - 2,423 1,374 3,445 3,446Depreciation (80) (347) (690) (765)Amortisation (3) (94) 103 103EBIT - 2,341 933 2,857 2,784Net interest expense (72) (307) (364) (350)Associates & JCEs - 9 20 20Other income 39 (684) 149 149Earnings before tax - 2,307 (50) 2,662 2,603Income tax (143) (82) (133) (130)Net profit after tax - 2,164 (132) 2,529 2,473Minority interests (242) (44) (379) (371)Other items - - - - Preferred dividends - - - - Normalised NPAT - 1,923 (176) 2,149 2,102Extraordinary items - - - - Reported NPAT - 1,923 (176) 2,149 2,102

Dividends - - - Transfer to reserves - 1,923 (176) 2,149 2,102

Valuation and ratio analysisFD normalised P/E (x) na 4.8 na 9.8 9.8 FD normalised P/E at price target (x) na 3.9 na 7.9 7.9 Reported P/E (x) na 4.2 na 9.8 9.8 Dividend yield (%) na - - - - Price/cashflow (x) na 1.4 50.3 4.8 40.1 Price/book (x) na na 1.5 1.7 1.4 EV/EBITDA (x) na 11.8 17.6 6.6 6.8 EV/EBIT (x) na 12.2 25.9 8.0 8.4 Gross margin (%) na 72.5 30.2 24.2 22.9 EBITDA margin (%) na 68.8 31.5 24.3 23.3 EBIT margin (%) na 66.5 21.4 20.1 18.8 Net margin (%) na 54.6 (4.0) 15.1 14.2 Effective tax rate (%) na 6.2 na 5.0 5.0 Dividend payout (%) na - na - - Capex to sales (%) na 102.1 48.7 20.1 12.9 Capex to depreciation (x) na 44.9 6.1 4.1 2.5

ROE (%) na na (3.8) 19.0 15.7 ROA (pretax %) na 65.2 7.4 13.7 12.1

Growth (%)Revenue na 23.7 226.1 4.2 EBITDA na (43.3) 150.7 0.0

EBIT na (60.2) 206.3 (2.5)

Normalised EPS na (103.9) na (2.2) Normalised FDEPS na (104.4) na (2.2)

Per shareReported EPS (RMB) na 0.41 (0.02) 0.14 0.14Norm EPS (RMB) na 0.41 (0.02) 0.14 0.14Fully diluted norm EPS (RMB) na 0.36 (0.02) 0.14 0.14Book value per share (RMB) na (0.18) 0.91 0.80 0.94DPS (RMB) na - - - - Source: Nomura est imates

Note: Investment risks include — execution of in-house wafer production ramp up, attainment of approval to procure electricity directly from power producers, potential change in technology platform, and uncertainties from solar subsidies and policies.

We expect revenue growth in FY10F to come from 1) the consolidation of conventional power business; and 2) the launch of the wafer business

We expect the margin to continue trending lower due mainly to a rising contribution from lower-margin wafer business

GCL Poly Energy Clarisse Pan


Cashflow (RMBmn)


EBITDA - 2,423 1,374 3,445 3,446Change in working capital 3,340 (3,457) 2,279 (2,062)Other operating cashflow (19) 2,394 (1,363) (872)Cashflow from operations 5,744 310 4,361 513Capital expenditure (3,595) (2,123) (2,855) (1,904)Free cashflow 2,149 (1,812) 1,505 (1,392)Reduction in investments - (210) (714) (20)Net acquisitions (135) 735 (694) - Reduction in other LT assets - (90) - - Addition in other LT liabilities - 69 (879) (400)Adjustments - 243 1,816 643Cashflow after investing acts 2,013 (1,065) 1,034 (1,169)Cash dividends - - - - Equity issue - 8,006 - - Debt issue 2,319 (2,105) (912) (350)Convertible debt issue - (512) - - Others (47) (1,392) 379 371Cashflow from financial acts 2,271 3,996 (532) 21Net cashflow - 4,285 2,931 501 (1,148)Beginning cash - 1,746 4,677 5,178Ending cash - 4,285 4,677 5,178 4,030Ending net debt 1,981 2,871 1,822 2,970Source: Nomura est imates



Cash & equivalents 1,746 4,677 5,178 4,030Marketable securities - - - - Accounts receivable 102 1,382 2,509 1,546Inventories 67 640 1,863 791Other current assets 577 809 809 809Total current assets - 2,492 7,507 10,358 7,175LT investments - 210 924 944Fixed assets 5,053 13,712 15,877 17,017Goodwill - 480 480 480Other intangible assets 5 36 36 36Other LT assets 1,380 1,104 1,104 1,104Total assets - 8,930 23,050 28,780 26,757Short-term debt 1,479 4,431 3,000 3,000Accounts payable 652 2,109 6,738 2,642Other current liabilities 3,433 604 604 604Total current liabilities - 5,565 7,145 10,342 6,246Long-term debt 2,076 3,117 4,000 4,000Convertible debt 171 - - - Other LT liabilities 1,962 2,031 1,152 752Total liabilities - 9,775 12,292 15,494 10,998Minority interest - 531 910 1,281Preferred stock - - - - Common stock 0 1,371 1,371 1,371Retained earnings 8,856 11,005 13,108Proposed dividends (845) - - -

Other equity and reserves - - - - - Total shareholders' equity - (845) 10,227 12,376 14,478

Total equity & liabilities - 8,930 23,050 28,780 26,757

Liquidity (x)

Current ratio na 0.45 1.05 1.00 1.15 Interest cover na 32.4 3.0 7.9 8.0

LeverageNet debt/EBITDA (x) na 0.82 2.09 0.53 0.86

Net debt/equity (%) na (234.5) 28.1 14.7 20.5

Activity (days)Days receivable 5.3 62.2 50.0 50.0 Days inventory 12.7 42.4 42.4 42.4

Days payable 123.5 165.7 150.0 150.0 Cash cycle - (105.5) (61.0) (57.6) (57.6) Source: Nomura est imates

Capex for FY10F is mostly related to wafer expansion

Leverage has improved since the cash injection from China Investment Corporation (CIC) in FY09


China High Speed Transmission 658 HK

POWER & UTILITIES/ALTERNATIVE ENERGY | CHINA



Demonstration of profitability FY09 results beat expectations by 16%

FY09 results were 16% above our estimates and market consensus, reflecting higher revenue (6% above expectations), better control in operating expenses (as percentage of sales fell from 13% in FY08 to 9% in FY09) and a higher gross margin (33% vs our 31% estimate).

Robust margin outlook despite rising spot steel prices

While the FY09 gross margin of 33% was a positive surprise to us, management was confident of maintaining a flat y-y gross margin in FY10. Despite the recent rise in steel prices in China, we are positive on CHST’s ability to maintain a stable margin, given its cost-control measures and better wind revenue mix in FY10F.

Solid earnings visibility for FY10F

CHST guided that its capacity has been fully booked and estimated that shipment of its wind gearbox would reach 9GW in FY10F, up from 6.35GW in FY09. We believe that this guidance seems conservative given its capacity expansion to 10GW by end-FY10.

Top pick in China wind sector given its ability to export

CHST is one of the few Chinese wind companies that has the ability to tap into international wind markets in FY10F, which is particularly positive as we see growth slowing in the China market. We expect CHST to expand its overseas revenue contribution to 25%, while maintaining its 50% market share in China in FY10F.

Maintain BUY and price target of HK$23.50

Our price target of HK$23.50 is based on DCF valuation. We believe that valuations are attractive at 13.6x FY10F earnings, given CHST’s earnings CAGR of 38% in FY09-11F.

Key financials & valuations31 Dec (RMBmn) FY08 FY09 FY10F FY11FRevenue 3,439 5,647 7,449 9,822

Reported net profit 692 966 1,402 1,829

Normalised net profit 692 966 1,402 1,829

Normalised EPS (RMB) 0.56 0.78 1.13 1.47

Norm. EPS growth (%) 93.3 39.6 45.0 30.5

Norm. P/E (x) 30.5 19.8 13.6 10.4

EV/EBITDA (x) 30.2 14.4 10.1 8.2

Price/book (x) 5.2 4.3 3.3 2.2

Dividend yield (%) 1.4 1.7 2.3 3.0

ROE (%) 20.3 23.7 28.3 26.6

Net debt/equity (%) 43.2 78.4 31.8 29.0

Earnings revisions

Prev ious norm. net profit 966 1,402 1,829


Prev ious norm. EPS (RMB) 0.78 1.13 1.47



1m 3m 6m

6.8 6.4 (5.2)

7.2 6.2 (5.5)

(2.2) 6.5 (4.4)

Easy


52-week range (H K$)


JP Morgan Chase

Stock borrowability

8.1


Fortune Apex (Management Shareholders) 21.6

Absolute (HK$)

Absolute (US$)

Relative to Index



78.0

20.20/14.64

15.64

1415161718192021

Jun0

9

Jul0

9

Au

g09

Se

p09

Oct

09

No

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Dec

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10

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Ma

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Ap

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10

80

90

100

110

120

130

Price

Rel MSCI China(HK$)









Nomura vs consensus We are more positive on CHST’s potential in overseas markets. We also believe that the current consensus does not reflect CHST’s strong margin profile shown in FY09.

Maintained

BUY


Action CHST is our top pick in the Asian alternative energy sector. We are positive on

CHST’s margin outlook, for its cost-control capability and continued product mix improvement. We recently raised our FY10F earnings by 15% after the company reported very strong FY09 results, which beat expectations by 16%. CHST is best positioned among the Chinese wind companies due to its ability to tap into the international markets, in our view. We reiterate BUY.

Catalysts Launch of higher-end wind products, attainment of new sales contracts to overseas

customers, Chinese government’s support on offshore wind development.

Anchor themes

We see wind as the best investment option, as it’s the world’s most commercial green energy. Given its low cost and stable output, we expect installed capacity growth of around 30% per annum globally over the next five to ten years.

China High Speed Transmission Clarisse Pan



We recently raised our gross margin forecasts on benefits from better product mix and cost improvement demonstrated in FY09 results

Despite the slowing China wind market, we believe CHST will be able to ramp up overseas revenue to deliver 32% y-y top-line growth in FY10F



Revenue 1,905 3,439 5,647 7,449 9,822Cost of goods sold (1,352) (2,447) (3,786) (5,027) (6,667)Gross profit 553 992 1,861 2,422 3,155SG&A (384) (447) (528) (741) (1,026)Employee share expense - - - - - Operating profit 169 545 1,334 1,681 2,129

EBITDA 262 706 1,550 1,975 2,473Depreciation (84) (145) (193) (259) (299)Amortisation (9) (16) (23) (35) (46)EBIT 169 545 1,334 1,681 2,129Net interest expense (33) (29) (100) (176) (235)Associates & JCEs (4) 10 16 21 27Other income 192 238 (83) 123 230Earnings before tax 324 764 1,166 1,649 2,151Income tax (18) (72) (200) (247) (323)Net profit after tax 306 693 966 1,402 1,829Minority interests 0 (0) 1 - - Other items - - - - - Preferred dividends - - - - - Normalised NPAT 307 692 966 1,402 1,829Extraordinary items - - - - - Reported NPAT 307 692 966 1,402 1,829

Dividends (88) (274) (329) (420) (549)Transfer to reserves 219 419 638 981 1,280

Valuation and ratio analysisFD normalised P/E (x) 59.6 30.5 19.8 13.6 10.4 FD normalised P/E at price target (x) 79.6 40.8 26.5 18.2 14.0 Reported P/E (x) 59.6 28.9 19.7 13.2 9.9 Dividend yield (%) 0.4 1.4 1.7 2.3 3.0 Price/cashflow (x) 88.1 133.9 na 5.4 naPrice/book (x) 6.6 5.2 4.3 3.3 2.2 EV/EBITDA (x) 78.6 30.2 14.4 10.1 8.2 EV/EBIT (x) 123.0 39.0 16.7 11.9 9.5 Gross margin (%) 29.0 28.8 33.0 32.5 32.1 EBITDA margin (%) 13.8 20.5 27.4 26.5 25.2 EBIT margin (%) 8.9 15.9 23.6 22.6 21.7 Net margin (%) 16.1 20.1 17.1 18.8 18.6 Effective tax rate (%) 5.5 9.4 17.2 15.0 15.0 Dividend payout (%) 28.6 39.6 34.0 30.0 30.0 Capex to sales (%) 35.1 32.5 28.5 11.9 9.5 Capex to depreciation (x) 8.0 7.7 8.3 3.4 3.1

ROE (%) 16.9 20.3 23.7 28.3 26.6 ROA (pretax %) 6.2 10.0 15.4 16.6 17.3

Growth (%)Revenue 60.8 80.6 64.2 31.9 31.8 EBITDA 35.4 169.5 119.5 27.4 25.2

EBIT 26.9 223.3 144.5 26.0 26.6

Normalised EPS 258.1 93.3 39.6 45.0 30.5 Normalised FDEPS 258.1 82.7 46.8 41.3 27.2

Per shareReported EPS (RMB) 0.29 0.56 0.78 1.13 1.47Norm EPS (RMB) 0.29 0.56 0.78 1.13 1.47Fully diluted norm EPS (RMB) 0.29 0.53 0.77 1.09 1.39Book value per share (RMB) 2.49 3.00 3.55 4.41 6.64DPS (RMB) 0.07 0.22 0.26 0.34 0.44Source: Nomura est imates

Note: PT risks — uncertainty of government policies for wind power; tightening global credit market; development of

direct-drive wind turbine technology; the company's failure to improve technology to compete with foreign competitors;

severe shortage of raw materials; delay in capacity expansion.

China High Speed Transmission Clarisse Pan


According to management, rising A/R days in FY09 were related mainly to receivables from state-owned customers including Sinovel and Dongfang and the condition has already improved in 1Q10F

We assume that the remaining convertible bonds will be converted into equity upon maturity in FY11F

CHST has improved its debt structure by obtaining more long-term bank loans in FY09. We expect this trend to continue

We expect capex to become lighter as major expansion of wind capacity (involving construction of a new facility) was carried out in FY08 and FY09

Cashflow (RMBmn)


EBITDA 262 706 1,550 1,975 2,473Change in working capital (23) (1,752) (778) 1,464 (2,535)Other operating cashflow (32) 1,195 (1,471) (35) (136)Cashflow from operations 208 149 (699) 3,404 (198)Capital expenditure (669) (1,119) (1,607) (884) (936)Free cashflow (461) (970) (2,305) 2,520 (1,134)Reduction in investments (39) (558) 5 (41) (54)Net acquisitions (0) (561) (0) (21) (27)Reduction in other LT assets (238) (323) (24) (129) (170)Addition in other LT liabilities 10 336 (233) 16 20Adjustments 251 (945) 1,076 (121) 1Cashflow after investing acts (477) (3,019) (1,482) 2,224 (1,364)Cash dividends (35) (88) (274) (329) (420)Equity issue 2,294 - - - - Debt issue (403) 867 1,208 1,901 441Convertible debt issue - 1,434 437 - - Others (58) (29) (100) (176) (235)Cashflow from financial acts 1,797 2,185 1,271 1,397 (214)Net cashflow 1,320 (835) (210) 3,620 (1,577)Beginning cash 196 1,516 682 471 4,091Ending cash 1,516 682 471 4,091 2,514Ending net debt (1,022) 1,610 3,466 1,747 2,397Source: Nomura est imates



Cash & equivalents 1,516 682 471 4,091 2,514Marketable securities 43 21 - - - Accounts receivable 638 1,294 2,613 2,285 4,173Inventories 646 1,336 1,313 1,653 2,192Other current assets 191 1,529 640 796 849Total current assets 3,035 4,861 5,037 8,825 9,728LT investments 8 588 604 645 699Fixed assets 1,405 2,362 3,845 4,470 5,107Goodwill - - - - - Other intangible assets 55 61 120 158 208Other LT assets 283 606 630 759 929Total assets 4,786 8,478 10,235 14,856 16,672Short-term debt 421 1,292 1,556 1,788 1,964Accounts payable 1,156 2,049 1,566 3,227 3,130Other current liabilities 16 54 166 136 180Total current liabilities 1,592 3,395 3,288 5,151 5,273Long-term debt 73 68 1,012 2,682 2,947Convertible debt - 932 1,369 1,369 - Other LT liabilities 12 349 115 131 152Total liabilities 1,678 4,743 5,785 9,333 8,372Minority interest 3 4 29 29 29Preferred stock - - - - - Common stock 95 95 95 95 100Retained earnings 3,010 3,636 4,326 5,399 8,171Proposed dividends - - - - -

Other equity and reserves - - - - - Total shareholders' equity 3,105 3,731 4,421 5,494 8,271


Liquidity (x)


LeverageNet debt/EBITDA (x) net cash 2.28 2.24 0.88 0.97

Net debt/equity (%) net cash 43.2 78.4 31.8 29.0


Days payable 261.0 239.7 174.3 174.0 174.0 Cash cycle (14.9) 11.4 79.7 53.7 51.2 Source: Nomura est imates






European companies


Electricite De France EDF FP

UTILITIES | FRANCE

Martin Young +44 207 102 1536 [email protected]

Visibility the trigger for value The world’s leading nuclear operator

EDF is the world’s largest nuclear operator and has substantial new build aspirations in a wide range of countries, including France, Italy, the UK, the US and China. It also offers significant exposure to higher power prices and the benefits of lifetime extension. For investors seeking exposure to the nuclear theme, EDF merits a look, we believe.

Quality asset base, but short-term issues

Based on our in-depth analysis of the generation portfolios of each of the European utility companies, we believe EDF is well placed to face the challenges of a changing generation world in Europe, with a well positioned flexible portfolio, low CO2 intensity, critical mass, a retail hedge, and a strong trading platform. However, there are short-term operational issues with the fleet in France, and current availability is sub-optimal. EDF aims to fully resolve these by FY15F.

Considerable upside, triggers possible in 2H

Short-term issues are dogging the stock, with the nuclear availability issue and the lack of clarity regarding the NOME law resulting in weak performance of late. We think indications that these are being resolved — a key catalyst in realising some of the considerable upside implied by our PT of €53 — may emerge in 2H. Extending the life of its existing fleet in France represents a further source of value, in our view, though discussions on this topic may not begin in earnest for some time.

Valuation and risks

We value EDF using a variety of methods, based on a sum-of-the-parts approach, which we use to capture the drivers of each component of EDF’s diverse business mix. The value of generation in France is based on DCF, assuming a 7.2% discount rate and our

Key financials & valuations(€mn) FY09 FY10F FY11F FY12F

Revenue 66,336 69,742 70,649 73,637



Normalised EPS (€) 2.15 1.94 2.49 2.82

Norm. EPS growth (%) (10.6) (9.7) 28.3 13.0

Norm. P/E (x) 13.4 13.5 11.6 11.2

EV/EBITDA (x) 9.6 9.7 9.0 8.7

Price/book (x) 2.0 1.9 1.7 1.6

Dividend yield (%) 3.3 3.3 3.6 4.0

ROE (%) 14.0 12.0 14.1 14.6

Net debt/equity (%) 60.1 59.6 57.8 55.2

Earnings revisions



Previous norm. EPS (€) 1.94 2.49 2.82


Share price relative to MSCI France

1m 3m 6m

2.1 (8.8) (14.1)

(0.0) (17.5) (26.3)

(3.9) (1.9) (7.8)

52-week range (€)

3-mth avg daily turnover 52.1

Stock borrowability



42.14/30.83

79,414

Absolute (€)

Absolute (US$)

Relative to Index

Market cap (US$mn)

French State 83

2931333537

394143

Jun

09

Jul0

9

Au

g09

Sep

09

Oct

09

No

v09

De

c09

Jan

10

Fe

b10

Ma

r10

Ap

r10

Ma

y10

80

85

90

95

100

105

Price

Rel MSCI France

(€)

Closing price on 23 Jun €35.1

Price target €53.0


FY10F net profit (€mn) 3,593Difference from consensus -20.7%Source: Nomura





Nomura vs consensus We are below consensus for FY10F, but in line for FY11-12F. We suspect that some have yet to factor in the TarTam extension.

Maintained

BUY

N O M U R A I N T E R N A T I O N A L P L C

Action We maintain our BUY rating on EDF, as we see significant unrealised value in its

asset base. Steps to realising this value will include finalisation of the NOME law discussions, improved operation of the nuclear fleet, a new equity story and ultimately extension of the life of existing nuclear plants. Our price target is €53.

Catalysts EDF has seen continued uncertainty over the NOME law discussions. Although

expectations of the starting nuclear price appear to have been trimmed, we believe the clarity that would result from a decision has value.

Anchor themes

As the world’s largest nuclear operator, EDF is a name that merits consideration by investors looking for nuclear exposure. It offers significant exposure to higher power prices, plus the benefits of lifetime extensions and new build aspirations in France, China, Italy, the UK, the US and elsewhere.

Electricite De France Martin Young


long-run generation price, which reaches €50/MWh by FY15F. The benchmark index for this stock is the Dow Jones STOXX® 600 Utilities.

Risks. EDF faces a number of risks across its businesses. In France, these include government involvement in the tariff-setting process and low returns for regulated activities. Elsewhere, EDF is exposed to volume, commodity and price risks in its generation activities, and regulatory risk in respect of its infrastructure risks. Re-investment risk should also not be ignored.




OPERATING FORECASTS

Year-end 31st December [UNIT] 2008A 2009A 2010E 2011E 2012E 2013E 2014E

France [EURm] 34,264 34,004 35,718 36,588 38,040 39,792 41,425Europe (UK, Germany and Italy) [EURm] 21,321 23,108 23,515 23,233 24,478 25,809 26,723

- UK [EURm] 8,244 7,728 8,510 8,303 8,943 9,358 9,919

- British Energy - existing [EURm] 0 3,308 3,117 2,839 2,934 3,123 3,276

- Germany [EURm] 7,467 7,195 6,853 6,777 6,885 7,059 7,368

- Italy [EURm] 5,610 4,877 5,035 5,314 5,716 6,270 6,160

Other activities [EURm] 5,218 5,787 5,633 5,789 5,952 6,119 6,292

Other international [EURm] 3,044 3,437 4,876 5,039 5,167 5,295 5,433

GROUP TURNOVER [EURm] 63,847 66,336 69,742 70,649 73,637 77,015 79,873

France [EURm] 9,009 9,434 10,160 11,563 12,235 13,297 14,120

- generation & supply [EURm] 4,968 5,825 6,336 7,511 7,951 8,778 9,371

- transmission [EURm] 1,340 1,220 1,274 1,344 1,422 1,509 1,593

- distribution [EURm] 2,701 2,389 2,551 2,708 2,861 3,010 3,155

Europe (UK, Germany and Italy) [EURm] 2,968 5,056 4,659 4,588 4,871 4,896 4,963

- UK [EURm] 943 1,334 1,164 1,448 1,637 1,598 1,667

- British Energy - existing [EURm] 0 1,728 1,509 1,320 1,427 1,567 1,678

- Germany [EURm] 1,114 1,193 1,223 1,077 958 824 930

- Italy [EURm] 911 801 764 744 850 906 688


Other international [EURm] 505 686 1,121 1,197 1,250 1,296 1,354

GROUP EBITDA [EURm] 14,240 17,466 17,933 19,672 20,739 21,935 22,946

France [EURm] 4,589 5,143 5,418 6,686 7,234 8,175 8,874

- generation & supply [EURm] 3,404 4,468 4,608 5,742 6,157 6,959 7,527

- transmission [EURm] 770 623 654 690 729 777 823

- distribution [EURm] 415 52 155 254 348 438 524

Europe (UK, Germany and Italy) [EURm] 1,472 2,800 2,362 2,197 2,382 2,325 2,310

- UK [EURm] 499 957 741 978 1,121 1,036 1,058

- British Energy - existing [EURm] 747 510 311 404 530 626

- Germany [EURm] 557 796 825 661 523 381 478

- Italy [EURm] 416 300 286 247 334 378 148


Other international [EURm] 399 287 727 795 841 879 929

GROUP EBIT [EURm] 7,910 10,107 10,008 11,431 12,189 13,154 13,932

P & L SUMMARY


Sales [EURm] 63,847 66,336 69,742 70,649 73,637 77,015 79,873

EBITDA [EURm] 14,240 17,466 17,933 19,672 20,739 21,935 22,946

EBIT [EURm] 7,910 10,107 10,008 11,431 12,189 13,154 13,932

Associates and income from investments [EURm] 367 120 172 181 190 199 209

Exceptional items [EURm] 0 0 0 0 0 0 0

GROUP PBIT [EURm] 8,277 10,227 10,180 11,612 12,379 13,353 14,142

Financial charges [EURm] (3,050) (4,525) (4,767) (4,788) (4,683) (4,670) (4,615)

GROUP PBT [EURm] 5,227 5,702 5,413 6,824 7,697 8,683 9,526

Net taxation [EURm] (1,599) (1,614) (1,624) (2,047) (2,309) (2,605) (2,858)

PAT [EURm] 3,628 4,088 3,789 4,777 5,388 6,078 6,668

Minorities [EURm] (144) (183) (196) (168) (181) (199) (213)

Profit for year (ex exceptionals) [EURm] 4,392 3,923 3,593 4,609 5,206 5,879 6,455

Profit for year (reported) [EURm] 3,484 3,905 3,593 4,609 5,206 5,879 6,455

Profit for year (adj - pre Exc and Def tax) [EURm] 4,392 3,923 3,593 4,609 5,206 5,879 6,455

Dividends [EURm] (2,339) (2,126) (2,120) (2,304) (2,593) (2,957) (3,228)

Retained Profit [EURm] 1,145 1,779 1,473 2,304 2,614 2,922 3,228

EPS - basic [EUR/sh] 1.91 2.14 1.94 2.49 2.82 3.18 3.49

Growth [%] -38.0% 12.1% -9.3% 28.3% 13.0% 12.9% 9.8%

EPS - adjusted (Nomura) [EUR/sh] 2.41 2.15 1.94 2.49 2.82 3.18 3.49

Growth [%] -6.0% -10.6% -9.7% 28.3% 13.0% 12.9% 9.8%

DPS [EUR/sh] 1.28 1.15 1.15 1.25 1.40 1.60 1.75

Growth [%] 0.0% -10.4% -0.3% 8.7% 12.5% 14.0% 9.1%

Payout Ratio [%] 53.3% 53.4% 59.0% 50.0% 49.8% 50.3% 50.0%



CASH FLOW SUMMARY


Operating cashflow after Wcap [EURm] 10,360 14,745 17,311 19,065 19,566 20,619 21,749

Dividend income [EURm] 110 143 172 181 190 199 209

Interest [EURm] (1,068) (1,408) (1,327) (1,269) (1,082) (985) (846)

Tax [EURm] (1,720) (963) (1,624) (2,047) (2,309) (2,605) (2,858)

Capex and acquistions [EURm] (16,879) (25,196) (14,857) (14,836) (13,857) (14,028) (14,090)

Disposals [EURm] 214 252 0 0 0 0 0

Group dividends [EURm] (2,528) (1,311) (2,126) (2,120) (2,304) (2,593) (2,957)

Management of liquid resources and other [EURm] 27,056 45,449 467 467 467 467 467

Change in net debt [EURm] 15,545 31,711 (1,983) (559) 671 1,074 1,674

BALANCE SHEET SUMMARY


Fixed assets [EURm] 141,336 180,435 187,367 193,962 199,269 204,515 209,591

Stock [EURm] 9,290 12,662 12,662 12,459 12,928 13,461 13,913

Debtors [EURm] 27,674 27,744 28,174 28,435 29,294 30,266 31,088

Financial assets [EURm] 14,265 14,821 14,821 14,821 14,821 14,821 14,821

Short-term liabilities [EURm] (58,217) (58,628) (58,758) (58,727) (59,515) (60,447) (61,198)

Concession grantors rights [EURm] (38,516) (39,884) (39,884) (39,884) (39,884) (39,884) (39,884)

Nuclear provisions [EURm] (28,572) (37,534) (38,553) (39,617) (40,724) (41,851) (43,009)

Employee provisons [EURm] (12,890) (13,412) (15,505) (17,627) (19,777) (21,955) (24,162)

Other provisions for contingencies and liabilities [EURm] (1,953) (1,188) (1,188) (1,188) (1,188) (1,188) (1,188)

Deferred tax [EURm] (4,134) (7,652) (7,652) (7,652) (7,652) (7,652) (7,652)

Loans and other financial liabilities [EURm] (25,584) (44,755) (46,738) (47,297) (46,626) (45,552) (43,878)

Other Liabilities [EURm] (5,628) (6,136) (6,136) (6,136) (6,136) (6,136) (6,136)

Net assets [EURm] 17,071 26,473 28,609 31,549 34,811 38,399 42,307

Minority interests [EURm] 1,801 4,773 4,969 5,137 5,318 5,518 5,731

Capital Stock [EURm] 911 924 924 924 924 924 924

P&L reserve [EURm] 22,286 27,028 28,501 30,806 33,419 36,341 39,569

Total Shareholders funds [EURm] 23,197 27,952 29,425 31,730 34,343 37,265 40,493

Net debt [EURm] (24,499) (42,124) (44,107) (44,666) (43,995) (42,921) (41,247)

NET ECONOMIC DEBT

Year-end 31st December UNIT 2008A 2009A 2010E 2011E 2012E 2013E 2014E

Net debt [EURm] (24,499) (42,124) (44,107) (44,666) (43,995) (42,921) (41,247)

Nuclear provisions [EURm] (28,572) (37,534) (38,553) (39,617) (40,724) (41,851) (43,009)

Employee liabilities [EURm] (12,890) (13,412) (15,505) (17,627) (19,777) (21,955) (24,162)

Dedicated assets [EURm] 8,604 8,270 9,770 11,270 12,770 14,270 15,770

Net Economic debt [EURm] (57,357) (84,800) (88,395) (90,640) (91,726) (92,457) (92,647)


Fortum Oyj FUM1V FH

UTILITIES | FINLAND

Martin Young +44 207 102 1536 [email protected]

Good assets, but fully valued A green option in the European utility space

Fortum operates 3.2GW of nuclear capacity and 4.7GW of hydro capacity, making it the green option for investors in the European utility space. A consequence of this low variable cost base is that Fortum is significantly exposed to power price variations — we estimate an additional €0.5/share for each additional €1/MWh. Such leverage is greater than the peer group and thus Fortum looks well placed should power prices rise.

Quality asset base in Nordic region

Our in-depth analysis of the generation portfolios of each of the European utility companies leads us to believe that Fortum is well placed to face the challenges of a changing generation world in Europe, with a well positioned and flexible portfolio, low CO2 intensity, critical mass, a retail hedge and a solid trading platform. Russia, on the other hand, remains more of an unknown.

Fully valued; REDUCE

Despite the aforementioned quality of its assets, and a strong balance sheet relative to its peer group, Fortum trades at a premium to both the generator and integrated subgroup on FY11F P/E. Although we recognise that some investors may be attracted to the greater visibility on offer, we believe that the stock is fully valued. The mooted windfall tax remains an additional uncertainty.

Valuation and risks

We take a sum-of-the-parts approach in valuing Fortum to capture the drivers of each component of the business mix. We value Nordic generation using DCF, assuming a 7.6% discount rate and deducting debt held at associates. In the absence of a published RAB (Regulated Asset Base) we benchmark the Nordic regulated business to similar assets across Europe. TGC-10 is valued using a WACC of

Key financials & valuations(€mn) FY09 FY10F FY11F FY12F

Revenue 5,435 6,098 6,131 6,405



Normalised EPS (€) 1.48 1.47 1.31 1.48

Norm. EPS growth (%) (0.2) (11.1) 12.8 9.1

Norm. P/E (x) 12.8 12.8 14.4 12.8

EV/EBITDA (x) 10.5 10.3 10.5 10.0

Price/book (x) 2.0 1.9 1.8 1.7

Dividend yield (%) 5.3 5.3 5.3 5.6

ROE (%) 16.0 15.9 13.5 14.7

Net debt/equity (%) 70.3 70.4 70.2 66.6

Earnings revisions



Previous norm. EPS (€) 1.47 1.31 1.48


Share price relative to MSCI Finland

1m 3m 6m

6.0 (2.8) 2.3

3.7 (12.1) (12.2)

4.8 11.1 2.3

52-week range (€)


Stock borrowability



19.80/15.03

20,495

Absolute (€)

Absolute (US$)

Relative to Index

Market cap (US$mn)

Finnish State 51

1415161718

192021

Jun

09

Jul0

9

Au

g09

Sep

09

Oct

09

No

v09

De

c09

Jan

10

Fe

b10

Ma

r10

Ap

r10

Ma

y10

80859095100105110115120

Price

Rel MSCI Finland

(€)


Price target 19.50



Closing price on 23 Jun





Price target 19.50



Closing price on 23 Jun




Nomura vs consensus Our estimates are below consensus for FY10-12F. We believe that this is a function of the continued strength of the NordPool price, where there is upside risk to our assumptions.

Maintained

REDUCE


Action We reaffirm our REDUCE call on Fortum, though we recognise the quality of its

assets, strength of its balance sheet and solidity of its yield. Our stance is relative, and predicated on our view that the stock is fully valued. Moreover, with a power curve that is in backwardation, we believe current support will wane as Fortum starts contracting at lower 2012F forward power prices.

Catalysts We see potential catalysts in a colder-than-usual winter in 2010/11F and continued

support for power prices.

Anchor themes

Fortum is one way to play the nuclear theme in the European utility space. Its generation portfolio is dominated by nuclear and hydro generation, making it one of Europe’s greenest options, and giving rise to significant power price exposure. In our opinion, other utilities offer better value.

Fortum Oyj Martin Young


15.5%. Other assets and businesses are valued using ratios, DCF and book/market values. The benchmark index for this stock is the Dow Jones STOXX® 600 Utilities.

Risks. Fortum is exposed to a number of risks both in the Nordic region and abroad. In the Nordic area, the key risks include generation prices and regulation. Outside the Nordic region, amongst other things, Fortum is exposed to political risk, namely in Poland and Russia.

Fortum Oyj Martin Young



P & L SUMMARYYear-end 31 December [UNIT] 2008A 2009A 2010E 2011E 2012E 2013E 2014E

TOTAL GROUP SALES [EUR m] 5,636 5,435 6,098 6,131 6,405 6,921 7,712EBITDA - adjusted [EUR m] 2,478 2,292 2,371 2,345 2,460 2,637 3,118EBITDA Margin [%] 44.0% 42.2% 38.9% 38.2% 38.4% 38.1% 40.4%%age growth/(decline) [%] 7.8% -7.5% 3.5% -1.1% 4.9% 7.2% 18.2%COMPARABLE OPERATING RESULTPower Generation [EUR m] 1,528 1,469 1,333 1,168 1,182 1,243 1,607Heat [EUR m] 250 227 254 233 231 240 265Distribution [EUR m] 248 262 271 281 292 304 315Markets [EUR m] (33) 22 22 22 25 25 24Russia [EUR m] (92) (26) 44 160 230 314 384Other [EUR m] (56) (66) (67) (69) (70) (71) (73)TOTAL [EUR m] 1,845 1,888 1,856 1,796 1,891 2,054 2,522

Other [EUR m] 118 (106) 0 0 0 0 0GROUP OPERATING INCOME [EUR m] 1,963 1,782 1,856 1,796 1,891 2,054 2,522Share of pro fit o f associates and jv [EUR m] 126 21 43 45 47 50 52Net financia l expenses [EUR m] (239) (167) (212) (223) (244) (258) (246)PBT [EUR m] 1,850 1,636 1,687 1,619 1,694 1,846 2,329Income tax [EUR m] (254) (285) (337) (324) (339) (369) (466)Windfall tax [EUR m] 0 0 0 (90) (90) (90) (90)Non operating resul t [EUR m] 0 0 0 0 0 0 0PAT [EUR m] 1,596 1,351 1,350 1,205 1,355 1,477 1,863Minor ity Interest [EUR m] (54) (39) (40) (41) (43) (44) (45)Net income - reported [EUR m] 1,542 1,312 1,309 1,163 1,313 1,433 1,818Net income - recurring [EUR m] 1,356 1,312 1,309 1,163 1,313 1,433 1,818KEY PER SHARE DATA

EPS - Reported [EUR/sh] 1.74 1.48 1.47 1.31 1.48 1.61 2.05EPS - Nomura [EUR/sh] 1.53 1.48 1.47 1.31 1.48 1.61 2.05

DPS - recurring [EUR/sh] 1.00 1.00 1.00 1.00 1.06 1.11 1.16DPS - specia l [EUR/sh] 0.00 0.00 0.00 0.00 0.00 0.00 0.00DPS - total [EUR/sh] 1.00 1.00 1.00 1.00 1.06 1.11 1.16Dividend cover [x] 1.7x 1.5x 1.5x 1.3x 1.4x 1.5x 1.8xInterest cover [x] 7.3x 5.7x 5.0x 5.0x 5.0x 5.0x 5.0x

BALANCE SHEET SUMMARYYear-end 31 December UNIT 2008A 2009A 2010E 2011E 2012E 2013E 2014E

FIXED ASSETS [EUR m] 16,517 17,292 17,933 18,428 18,855 19,272 19,628Inventories [EUR m] 444 447 530 538 561 609 653Other short term assets [EUR m] 1,996 1,212 1,403 1,423 1,475 1,586 1,688Cash and cash equivalents [EUR m] 1,321 890 558 357 372 430 952CURRENT ASSETS [EUR m] 3,761 2,549 2,491 2,318 2,408 2,625 3,293TOTAL ASSETS [EUR m] 20,278 19,841 20,424 20,746 21,263 21,897 22,921STOCKHOLDERS EQUITY [EUR m] 7,954 8,034 8,455 8,730 9,154 9,649 10,482

Minor ity Interest [EUR m] 457 457 497 539 581 625 670TOTAL EQUITY [EUR m] 8,411 8,491 8,952 9,268 9,735 10,274 11,152LIABILITIESInterest bearing liabilities [EUR m] 7,500 6,859 6,859 6,859 6,859 6,859 6,859Other liabilities [EUR m] 1,700 1,939 2,061 2,067 2,117 2,212 2,358Nuclear provisions [EUR m] 566 570 570 570 570 570 570Pension provisions [EUR m] 51 23 23 23 23 23 23Other provisions [EUR m] 199 209 209 209 209 209 209Deferred tax [EUR m] 1,851 1,750 1,750 1,750 1,750 1,750 1,750TOTAL LIABILITIES [EUR m] 11,867 11,350 11,472 11,478 11,528 11,623 11,769TOTAL LIABILITIES & SCH EQUITY [EUR m] 20,278 19,841 20,424 20,746 21,263 21,897 22,921NET DEBT - Nomura [EUR m] 6,179 5,969 6,301 6,502 6,487 6,429 5,907KEY FINANCIAL DATABVPS [EUR/sh] 9.48 9 .56 10.08 10.43 10.96 11 .56 12.55 ROCE - Unadjusted Reported [%] 15.0% 12.1% 10.7% 9.8% 10.1% 10.7% 12.9%ROCE - Nomura [%] 11.8% 11.1% 10.7% 9.8% 10.1% 10.7% 12.9%ROE - Nomura [%] 18.7% 16.0% 15.9% 13.5% 14.7% 15.2% 18.1%

CASH FLOW SUMMARYYear-end 31 December UNIT 2008A 2009A 2010E 2011E 2012E 2013E 2014E

NET INCOME [EUR m] 1,596 1,351 1,350 1,205 1,355 1,477 1,863Deprecia tion [EUR m] 515 510 515 549 570 583 595Working Capital [EUR m] (102) 19 (152) (22) (24) (64) (0)Other ad justments [EUR m] 119 466 0 0 0 0 0OPERATING CF [EUR m] 2,002 2,346 1,670 1,687 1,854 1,945 2,405Disposals [EUR m] 115 62 0 0 0 0 0Acquisi tions [EUR m] (1,243) (87) 0 0 0 0 0Capex [EUR m] (1,018) (845) (1,113) (999) (949) (949) (899)Other ad justments [EUR m] (136) (104) 0 0 0 0 0TOTAL INVESTING CF [EUR m] (2,282) (974) (1,113) (999) (949) (949) (899)TOTAL PRE-FINANCING CF [EUR m] (280) 1,372 557 687 905 996 1,506

Financing CF [EUR m] 1,320 (1,671) (888) (889) (889) (938) (985)Increase/(decrease) in CF [EUR m] 1,040 (299) (332) (202) 16 58 522KEY FINANCIAL DATA

FCFPS [EUR/sh] 1.11 1 .69 0.63 0.77 1.02 1 .12 1.70 Gearing (debt/debt+equity) [%] 42.4% 41.3% 41.3% 41.2% 40.0% 38.5% 34.6%Gearing (debt/equity) [%] 73.5% 70.3% 70.4% 70.2% 66.6% 62.6% 53.0%Net Debt/EBITDA - Reported [x] 2.5x 2.6x 2.7x 2.8x 2.6x 2.4x 1.9xNet Debt/EBITDA - Recurring - Nomura [x] 2.5x 2.6x 2.7x 2.8x 2.6x 2.4x 1.9x


Gamesa Corp Tecnologica Sa GAM SM

RENEABLE ENERGY | EUROPE

Catharina Saponar, CFA +44 20 7102 1231 [email protected]

Spanish macro vs global growth Exposure to the largest developers

Gamesa’s business model of multi-year framework agreements gives it visibility on growth through FY11-12F. Other than Iberdrola Renovables as one of the largest global developers with heavy US exposure, this includes major utilities, but also Asian developers such as Long Yuan and Datang who are large customers for Gamesa.

Increasing exposure to new markets and clients

The company’s new strategy of increasing its manufacturing base in China and India should position it well to deliver increasing order momentum in the region. Beyond that, the new focus on small- and medium-sized customers should also result in market share gains and increase volume breadth.

US weakness

Gamesa, like other wind turbine manufacturers exposed to US market weakness, saw only 50% capacity utilisation in 1Q10. We see some risk of the weak PPA situation spilling over into Iberdrola Renovables’s project development and potentially pushing out volumes. That said, we still expect a recovery in late-2010F to sustain the company’s delivery trajectory.

Spanish overhang

Gamesa shares have been hit hard by the Spanish macro overhang and beyond that the lack of clarity over Spanish renewables regulation and tariffs. However, we expect the latter to clear soon.

Valuation reflects pessimism

Gamesa shares are closing back in on trough levels, trading on a P/E of 12.4x FY11F, versus a four-year average of 12.7x, a FY09 trough of 6.5x and a FY08 peak of 14x. Our DCF-based price target is €13.00.

Key financials & valuations(€mn) FY08 FY09 FY10F FY11F

Revenue 3,646 3,229 2,920 3,668

Reported net profit 324 115 89 160

Normalised net profit 324 115 89 160

Normalised EPS (€) 1.32 0.47 0.37 0.66

Norm. EPS growth (%) 0.5 (0.6) (0.2) 0.8

Norm. P/E (x) 6.1 17.2 22.3 12.4

EV/EBITDA (x) 3.9 5.7 8.2 5.8

Price/book (x) 1.3 1.3 1.2 1.1

Dividend yield (%) 0.0 0.0 0.0 0.0

ROE (%) 0.1 0.1 0.1 0.1

Net debt/equity (%) 0.0 0.2 0.2 0.2

Earnings revisions

Previous norm. net profit 89 160

Change from previous (%) - -

Previous norm. EPS (?) 0.37 0.66


Share price relative to MSCI Spain

1m 3m 6m

1.1 (16.6) (29.0)

(1.0) (24.6) (39.1)

(3.9) (6.2) (9.1)


Easy

Iberdrola 14.1

Casa Grande carta



5.0

Absolute (€)

Absolute (US$)

Relative to Index

52-week range (€)


16.45/7.14

Stock borrowability

6

8

10

12

14

16

18

Jun

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Jul0

9

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50

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90

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110

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Rel MSCI Spain

(€)


Price target €13


FY10F net profit (€mn) 89Difference from consensus -16.9%Source: Nomura


Price target €13



Nomura vs consensus We see Spanish macro concerns as a share overhang. Meanwhile, the company stands to benefit from a strong position in recovering wind markets, in our view.

Maintained

BUY


Action We expect Gamesa to be a beneficiary of a global pick-up in wind demand in

2010F and 2011F. The company also appears to be well equipped for growth in Asia through its recent plant expansion. Our DCF-based price target is €13.00. We maintain our BUY call.

Catalysts As the company executes on its strategy to diversify its geographical spread and

client base, it should deliver order flow as a share price driver.

Anchor themes

Growth in the wind sector is a key theme within the global climate change and new energy theme. We believe that poly manufacturers are direct beneficiaries.

Gamesa Corp Tecnologica Sa Catharina Saponar, CFA


Risks. Gamesa may suffer a worse-than-expected price decline or order cancellations. The supply chain may not be able to meet projected growth and the company may be unable to launch new turbines in line with expectations. It may experience problems with its capacity expansion.



Financial statements P&L Year-end Dec [unit] 2008A 2009A 2010E 2011E 2012E 2013E 2014E

Sales [EUR m] 3646 3229 2920 3668 4137 4869 5231%age growth % 27.2% -11.4% -9.6% 25.6% 12.8% 17.7% 7.4%

Gross Profit [EUR m] 1,026 974 817 1,027 1,241 1,461 1,569%age growth % 37.7% -5.1% -16.1% 25.6% 20.8% 17.7% 7.4%Gross margin % 28.1% 30.2% 28.0% 28.0% 30.0% 30.0% 30.0%

EBITDA [EUR m] 495 395 289 405 469 559 616%age growth % 40.2% -20.3% -26.9% 40.3% 15.8% 19.2% 10.2%EBITDA margin % 13.6% 12.2% 9.9% 11.0% 11.3% 11.5% 11.8%

Depreciation [EUR m] (288) (99) (93) (102) (112) (129) (138)

Operating Profit [EUR m] 208 177 168 269 322 392 436%age growth % 56.51% -14.64% -5.17% 60.04% 19.90% 21.62% 11.24%Operating Margin % 5.7% 5.5% 5.8% 7.3% 7.8% 8.1% 8.3%

Net financial Result [EUR m] (41) (47) (48) (52) (56) (61) (66)

PBT [EUR m] 159 122 122 219 268 333 372%age growth % 64.4% -23.2% -0.4% 79.8% 22.5% 24.3% 11.7%PBT Margin % 4.4% 3.8% 4.2% 6.0% 6.5% 6.8% 7.1%

Equity Income [EUR m] 2 2 2 2 2 2 2

Income Tax [EUR m] (2) (7) (33) (59) (72) (90) (100)Tax rate [EUR m] 1.4% 5.7% 27.0% 27.0% 27.0% 27.0% 27.0%

Net Income [EUR m] 157 115 89 160 196 243 272%age growth % 28.35% -26.60% -22.90% 79.75% 22.53% 24.26% 11.68%Minority Interests [EUR m] 1.9 0.0 0.0 0.0 0.0 0.0 0.0Net earnings [EUR m] 324 115 89 160 196 243 272%age growth % 43.5% -64.5% -22.9% 79.8% 22.5% 24.3% 11.7%Net Profit Margin % 8.9% 3.6% 3.0% 4.4% 4.7% 5.0% 5.2%KEY SHARE DATA [unit] 2008A 2009A 2010E 2011E 2012E 2013E 2014E

Number of Shares [in m] 243.3 243.3 243.3 243.3 243.3 243.3 243.3EPS [EUR /sh] 1.32 0.47 0.37 0.66 0.80 1.00 1.12EPS (Cont. Operations) [EUR/sh ] 1.32 0.47 0.37 0.66 0.80 1.00 1.12DPS [EUR /sh] 0.29 0.21 0.09 0.16 0.20 0.25 0.28BPS [EUR/sh ] 6.199 6.476 6.750 7.242 7.845 8.595 9.432



Financial statements BALANCE SHEETYear-end Dec [unit] 2008A 2009A 2010E 2011E 2012E 2013E 2014E

Intangible assets [EUR m] 447 540 584 639 701 749 802Tangible assets [EUR m] 331 417 470 552 647 689 707Financial assets [EUR m] 192 141 143 145 147 149 151Total fixed assets [EUR m] 971 1,098 1,197 1,335 1,495 1,587 1,660

Inventories [EUR m] 828 784 817 880 952 1,071 1,098Receivables [EUR m] 1,378 2,035 1,898 2,201 2,275 2,435 2,615Payables [EUR m] 2,049 1,657 1,460 1,834 2,069 2,435 2,615Working capital [EUR m] 157 1,162 1,255 1,247 1,158 1,071 1,098

Other assets [EUR m] 913 0 0 0 0 0 0Total assets [EUR m] 2,199 2,454 2,645 2,776 2,846 2,851 2,951

Share capital [EUR m] 197 197 197 197 197 197 197Retained Earnings [EUR m] 320 115 181 301 448 630 834Shareholders' funds [EUR m] 1,508 1,576 1,642 1,762 1,909 2,091 2,295

Minorities [EUR m] 7 5 5 5 5 5 5

Provisions [EUR m] 253 223 250 285 320 357 399

Long term liabilities [EUR m] 255 396 396 396 396 396 396Short term liabilities [EUR m] 211 688 757 832 916 1,007 1,108Cash & cash equivalent [EUR m] -530 -801 -481 -433 -389 -351 -1,619Net debt [EUR m] -64 283 380 357 246 30 -114

Other liabilities [EUR m] 443 286 286 286 286 286 286Total liabilities [EUR m] 189 506 1,003 1,014 937 760 657

Total shareholders' funds & liabilities [EUR m] 2,197 2,454 2,645 2,776 2,846 2,851 2,951 CASH FLOW Year-end Dec [unit] 2008A 2009A 2010E 2011E 2012E 2013E 2014E

EBIT [EUR m] 208 177 168 269 322 392 436Depreciation & Amortization [EUR m] 287 217 93 102 112 129 138Change in Provisions [EUR m] 50 -30 27 34 35 38 41Change in Working capital [EUR m] 524 -1,005 -93 8 89 87 -27Tax [EUR m] -2 -7 -33 -59 -72 -90 -100Other movements [EUR m] 0 0 0 0 0 0 0Operating cash flow [EUR m] 1,067 -648 163 354 485 556 488

Capex [EUR m] -158 -129 -190 -238 -269 -219 -209Disposals [EUR m] 0 0 0 0 0 0 0Cash flow from investing activities [EUR m] -158 -129 -190 -238 -269 -219 -209

New project finance [EUR m] 0 0 0 0 0 0 0Interest [EUR m] -41 -47 -48 -52 -56 -61 -66Dividends [EUR m] -71 -50 -22 -40 -49 -61 -68Minority dividends [EUR m] 0 0 0 0 0 0 0Dividends received [EUR m] 0 0 0 0 0 0 0Cash flow from financing activities [EUR m] -113 -97 -70 -92 -105 -122 -134

Net change in cash/debt [EUR m] 796 -874 -97 24 111 215 145


Vestas Wind Systems A/S VWS DC

RENEWABLE ENERGY | EUROPE


A leader coming out of the trough Global market leader

Vestas’ position as the market leading global turbine manufacturer makes it a prime play on long-term global wind market growth. The company has manufacturing facilities in Europe, Asia and the Americas and its geographical breadth gives it an advantage of flexibility and exposure to the most important demand zones. The company’s scale also gives it a profitability advantage vs its peers.

2010 the trough year with view to pick up

We see 2010F being a trough year for Vestas, with flat earnings vs 2009 as spillovers from 2009 have meant a very weak start to the year, with a Q1 loss as the company’s activity levels were extremely low. But we expect order intake to pick up during 2010F, which should provide investors with the prospect of a strong pick-up in activity and earnings in 2011F.

Asia brings order momentum while the US remains slow

Vestas has been impacted by weakness in the US wind market which has led to an absence of new US orders in 2009. A recovery in the US market should be a very important order driver, even though we think that a full recovery might only come through in late 2010F and in 2011F. We believe that given the extent of recession-induced electricity demand destruction, many utilities are already compliant with their renewables obligations for at least 2010F. The expiration of the cash grant scheme, which requires 5% of a project to be invested before year-end, should lead to order momentum, we believe. But most importantly, we think that demand recovery will lead to a return of strong activity from 2011F. There was some order intake, 250MW in Q1/2 this year, but we expect more in late 2010F.

Meanwhile, Asia has been making up for this, with stronger-than-expected order intake so far in 2010F. We see this as a reflection of: 1) very strong market growth; and 2) the market opening to Western


Revenue 6,035 6,636 6,718 8,293



Normalised EPS (€) 2.76 2.91 2.14 3.31

Norm. EPS growth (%) 0.8 0.1 (0.3) 0.5

Norm. P/E (x) 15.4 13.6 18.0 11.6

EV/EBITDA (x) 9.7 7.2 9.5 5.9

Price/book (x) 3.7 2.3 2.1 1.8

Dividend yield (%) 0.0 0.0 0.0 0.0

ROE (%) 0.3 0.2 0.1 0.2

Net debt/equity (%) 0.0 0.0 0.0 (0.1)

Earnings revisions



Previous norm. EPS (€) 2.14 3.31


Share price relative to MSCI Denmark

1m 3m 6m

(1.6) (0.6) (4.7)

(3.7) (10.0) (18.2)

(11.3) (9.1) (27.3)

52-week range (€)

3-mth avg daily turnover 97

Stock borrowability Easy


Thornburg Inv Mgmt 2

Blackrock group 2


398.0/263.6

Absolute (€)

Absolute (US$)

Relative to Index


250270290310330350370390410

Jun

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90100110

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Rel MSCI Denmark

(€)


Price target €390




Price target €390



Nomura vs consensus We are below consensus for 2010F, as we anticipate an earnings miss. But our forecast is above for 2011F, since we expect order momentum to drive earnings.

Maintained

BUY


Action Even though a recovery in the wind sector might not happen until later this year, we

see a positive risk-reward balance, since on our reading Vestas’ share price does not price in any order recovery before 2014F. We see this as an opportunity, given the company’s global leadership position in a market that should return to strong growth. Our DCF share price target is Eur 390. BUY rating reaffirmed.

Catalysts Order flow should improve over the course of the year. In particular, we are looking

for US order momentum in the later quarters of 2010F.

Anchor themes

Vestas is directly leveraged to global wind growth, a central theme of the global climate change and new energy theme.

Vestas Wind Systems A/S Catharina Saponar, CFA


manufacturers more quickly than expected, as technology and cost of energy rather than cost/MW become more important parameters.

Potential winner from offshore growth

In a very timely manner, Vestas has announced it is developing a new 6MW turbine specifically dedicated to offshore. We think the company will be commercialising the turbine from 2012F. Our industry contacts indicate an oligopolistic market in offshore and a desire of many to diversify supply. Given Vestas’ standing in the onshore market, we see it standing a good chance of capturing share in the offshore market.

Trough valuation

In our view, Vestas’ valuation reflects a very high degree of pessimism. The shares are trading on a P/E of 11.6x 2011F, vs a four-year average of 13x, a 2009 trough of 7.4x and a 2008 peak of 21x. We estimate that the current share price implies no order recovery before 2014F, which we find too pessimistic. Our DCF share price target is Eur 390.

Risks. We identify the major risk to our forecast in the invested capital of the business, in that we assume going forward incremental revenue growth exceeds the requirement for incremental capital. We also identify the possibility of legislative changes regarding support for renewable and/or wind power technology in key markets that are not modelled into our forecasts.




Sales [EUR m] 6035 6636 6718 8293 9352 10381 11420%age growth % 24.2% 10.0% 1.2% 23.4% 12.8% 11.0% 10.0%

Gross Profit [EUR m] 1,179 1,441 1,276 1,576 1,777 1,972 2,170%age growth % 42.9% 22.2% -11.4% 23.4% 12.8% 11.0% 10.0%Gross margin % 19.5% 21.7% 19.0% 19.0% 19.0% 19.0% 19.0%

EBITDA [EUR m] 803 1067 833 1250 1411 1616 1778%age growth % 38.2% 32.9% -21.9% 50.1% 12.9% 14.5% 10.0%EBITDA margin % 13.3% 16.1% 12.4% 15.1% 15.1% 15.6% 15.6%

Depreciation [EUR m] 135 211 216 288 309 339 372

Operating Profit [EUR m] 668 856 617 962 1102 1277 1406%age growth % 50.79% 28.14% -27.87% 55.82% 14.56% 15.90% 10.04%Operating Margin % 11.1% 12.9% 9.2% 11.6% 11.8% 12.3% 12.3%

Net financial Result [EUR m] 46 (48) (12) (12) (12) (12) (12)

PBT [EUR m] 714 809 606 951 1091 1266 1394%age growth % 61.2% 13.3% -25.1% 56.9% 14.7% 16.1% 10.1%PBT Margin % 11.8% 12.2% 9.0% 11.5% 11.7% 12.2% 12.2%



Net Income [EUR m] 511 579 436 675 769 886 976%age growth % 75.60% 13.31% -24.66% 54.71% 13.93% 15.25% 10.14%Net earnings [EUR m] 511 579 436 675 769 886 976%age growth % 75.6% 13.3% -24.7% 54.7% 13.9% 15.2% 10.1%Net Profit Margin % 8.5% 8.7% 6.5% 8.1% 8.2% 8.5% 8.5%

KEY SHARE DATA [unit] 2008A 2009A 2010E 2011E 2012E 2013E 2014ENumber of Shares [in m] 185.2 199.1 203.7 203.7 203.7 203.7 203.7EPS [EUR /sh] 2.76 2.91 2.14 3.31 3.77 4.35 4.79EPS (Cont. Operations [EUR/sh ] 2.76 2.91 2.14 3.31 3.77 4.35 4.79BPS [EUR/sh ] 10.56 16.90 18.66 21.97 25.74 30.09 34.88




Intangible assets [EUR m] 644 812 1,121 1,097 1,071 1,047 1,021Tangible assets [EUR m] 1,030 1,461 1,936 2,118 2,378 2,664 2,687Financial assets [EUR m] 147 17 17 17 17 17 17Total fixed assets [EUR m] 1,821 2,290 3,074 3,232 3,467 3,728 3,725

Inventories [EUR m] 1,612 1,663 1,612 1,990 2,244 2,491 2,741Receivables [EUR m] 1,119 759 1,142 1,410 1,683 1,868 2,056Payables [EUR m] 1,030 1,062 1,075 1,327 1,590 1,765 1,941Working capital [EUR m] 212 639 470 498 561 519 571

Other assets [EUR m] 482 1,032 1,032 1,032 1,032 1,032 1,032Total assets [EUR m] 2,627 4,164 4,779 4,964 5,263 5,482 5,531

Share capital [EUR m] 25 27 27 27 27 27 27Retained Earnings [EUR m] 2,008 3,378 3,814 4,489 5,258 6,144 7,120Shareholders' funds [EUR m] 1,955 3,364 3,800 4,475 5,244 6,130 7,106

Minorities [EUR m] 0 0 0 0 0 0 0Provisions [EUR m] 263 233 242 290 327 363 400Long term liabilities [EUR m] 14 339 339 339 339 339 339Short term liabilities [EUR m] 109 12 -13 -13 -13 -13 -13Cash & cash equivalent [EUR m] -162 -488 -293 -831 -1,339 -2,041 -3,005Net debt [EUR m] -39 -137 33 -505 -1,013 -1,715 -2,679

Other liabilities [EUR m] 395 436 436 436 436 436 436Total liabilities [EUR m] 226 98 277 -213 -683 -1,350 -2,277


EBIT [EUR m] 668 856 617 962 1,102 1,277 1,406Depreciation & Amortization [EUR m] 135 211 216 288 309 339 372Change in Provisions [EUR m] -37 -30 9 48 37 36 36Change in Working capital [EUR m] -269 -427 169 -27 -64 42 -52Tax [EUR m] -203 -230 -170 -276 -322 -380 -418Other movements [EUR m] 0 0 0 0 0 0 0Operating cash flow [EUR m] 294 380 841 996 1,063 1,315 1,344

Capex [EUR m] -678 -833 -1,000 -446 -544 -601 -369Disposals [EUR m] 0 0 0 0 0 0 0Cash flow from investing activities [EUR m] -678 -833 -1,000 -446 -544 -601 -369

New project finance [EUR m] 0 792 0 0 0 0 0Interest [EUR m] 46 -48 -12 -12 -12 -12 -12Dividends [EUR m] 0 0 0 0 0 0 0Minority dividends [EUR m] 0 0 0 0 0 0 0Dividends received [EUR m] 0 0 0 0 0 0 0Cash flow from financing activities [EUR m] 46 744 -12 -12 -12 -12 -12

[EUR m]

Net change in cash [EUR m] -338 291 -170 538 508 703 964


Wacker Chemie Ag WCH GR



Quality volumes A volume play

Wacker is our preferred play on solar end market volumes as end market strength (30%-plus pa growth) feeds directly into polysilicon volume growth. Wacker plans to more than double its capacity to over 35,000t over the next two years, with potential for further expansion thereafter.

Sustainable advantage from high barriers to entry

As a sector with high barriers to entry, we see a big divide between Tier-1 and other polysilicon manufacturers, with the former enjoying quality and execution advantages. Wacker is a leading Tier-1 manufacturer and we expect it to sustain above-sector-average volumes and ASPs due to its quality edge, secured contracted volumes and leadership position.

Material cost edge

We believe Wacker has a significant cost advantage by being 3-5 years ahead of competitors. On our estimates, Wacker’s production cost is some 50-60% below that of new-entrant competitors and is set to come down further. Higher reactor yields, lower energy consumption, a closed-loop production process as well as higher purity grades of its product are the main factors. We think the company can sustain its edge over the long term.

Valuation and risk

Wacker is one of the least expensive global large renewables names, with a 2011F P/E of 10x vs our global solar average of 15x, despite its premium quality and positioning. Our DCF fair value is Eur 145 and we expect the shares to re-rate as the company’s edge is increasingly recognised. As for risks, Wacker is operating in a highly complex chemical industry and expanding its capacity. This exposes it to execution and technology risk and to chemical industry-specific operational risk. Wacker may be affected by falling poly-Si prices in the near term, as polysilicon is the most important driver for the company.


Revenue 4,298 3,719 4,491 4,931



Normalised EPS (€) 8.43 3.41 10.17 12.82

Norm. EPS growth (%) 0.0 (0.6) 2.0 0.3

Norm. P/E (x) 14.4 35.7 12.0 9.5

EV/EBITDA (x) 5.8 10.0 5.4 4.5

Price/book (x) 3.1 3.1 2.5 2.1

Dividend yield (%) 0.0 0.0 0.0 0.0

ROE (%) 0.2 (0.0) 0.2 0.2

Net debt/equity (%) 0.0 0.0 0.0 0.0

Earnings revisions





Share price relative to MSCI Germany

1m 3m 6m

20.5 17.1 1.3

18.0 5.9 (13.0)

13.8 15.1 0.1

52-week range (€)



Major shareholders (%) 50

Dr.Alexander

Wacker

Familiengesellschaft


7,760

124.7/77.2

Absolute (€)

Absolute (US$)

Relative to Index

Market cap (US$mn)

72

82

92

102

112

122

132

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130

Price

Rel MSCI Germany

(€)


Price target €145


FY10F net profit (€mn) 490Difference from consensus 25.0%Source: Nomura


Price target €145



Nomura vs consensus We are above consensus for 2010F and 2011F, as we expect the company to hold firmer prices in a strong market context.

Maintained

BUY


Action Wacker is our top pick in the European solar sector as a volume play on global

solar end market strength. It is one of the least expensive global large renewables names, with a 2011F P/E of 10x vs our global solar average of 15x, despite its premium quality and positioning. Our DCF fair value is Eur 145, and we expect the shares to rerate as the company’s edge is increasingly recognised. BUY reaffirmed.

Catalysts We expect the share price to re-rate as investors get comfortable with the

company’s sustainable competitive advantages and as pricing and volumes hold firm.

Anchor themes

Growth in the solar sector is a key theme within the global climate change and new energy theme, and poly manufacturers are direct beneficiaries.

Wacker Chemie Ag Catharina Saponar, CFA



Sales [EUR m] 4298 3719 4491 4931 5245 5677 5742%age growth % 13.7% -13.5% 20.8% 9.8% 6.4% 8.2% 1.1%

Gross Profit [EUR m] 1,188 1,072 1,694 1,934 2,046 2,232 2,148%age growth % 3.1% -9.8% 58.1% 14.2% 5.8% 9.0% -3.7%Gross margin % 27.6% 28.8% 37.7% 39.2% 39.0% 39.3% 37.4%

EBITDA [EUR m] 1055 607 1132 1317 1391 1522 1431%age growth % 5.4% -42.5% 86.6% 16.3% 5.6% 9.4% -6.0%EBITDA margin % 24.6% 16.3% 25.2% 26.7% 26.5% 26.8% 24.9%


Operating Profit [EUR m] 681 154 752 902 945 1048 937%age growth % 4.62% -77.38% 387.67% 20.07% 4.69% 10.91% -10.62%Operating Margin % 15.9% 4.1% 16.7% 18.3% 18.0% 18.5% 16.3%

Net financial Result [EUR m] (2) (24) (21) (2) (1) (4) 3

PBT [EUR m] 642 3 700 891 945 1047 946%age growth % 1.5% -99.5% ns 27.2% 6.1% 10.8% -9.7%PBT Margin % 14.9% 0.1% 15.6% 18.1% 18.0% 18.4% 16.5%

Equity Income [EUR m] (5) 0 0 0 0 0 0


Net Income [EUR m] 438 (75) 491 624 662 733 662%age growth % 3.81% -117.00% -758.81% 27.05% 6.12% 10.81% -9.69%Minority Interests [EUR m] 1 243 (1) (4) (4) (5)Net earnings [EUR m] 439 169 490 620 657 728 658%age growth % 4.1% -116.1% -791.4% 26.6% 6.1% 10.8% -9.7%Net Profit Margin % 10.2% -1.9% 10.9% 12.6% 12.5% 12.8% 11.5%KEY SHARE DATA [unit] 2008A 2009A 2010E 2011E 2012E 2013E 2014ENumber of Shares [in m] 52.2 49.5 49.7 49.7 49.7 49.7 49.7EPS [EUR /sh] 8.43 3.41 10.17 12.82 13.60 15.06 13.65EPS (Cont. Operations) [EUR/sh ] 8.43 3.41 10.17 12.82 13.60 15.06 13.65DPS [EUR /sh] 1.80 1.30 2.00 2.50 3.00 3.50 4.00Dividend Payout % 21% 38% 20% 20% 22% 23% 29%BPS [EUR/sh ] 39.66 38.89 47.78 58.25 68.99 80.65 90.39

Wacker Chemie Ag Catharina Saponar, CFA



Intangible assets [EUR m] 25 22 21 21 21 21 21Goodwill [EUR m]

Tangible assets [EUR m] 2,660 2,780 3,075 3,388 3,957 4,432 4,658Financial assets [EUR m] 369 215 200 190 192 196 199Total fixed assets [EUR m] 3,053 3,018 3,296 3,599 4,170 4,649 4,878

Inventories [EUR m] 505 441 458 481 527 566 570Receivables [EUR m] 467 467 614 645 707 759 764Payables [EUR m] 297 218 248 260 285 306 308Working capital [EUR m] 675 690 824 866 949 1,019 1,026

Other assets [EUR m] 263 244 237 237 237 237 237Total assets [EUR m] 4,124 4,542 5,073 5,560 6,093 6,721 7,234

Shareholders' funds [EUR m] 2,083 1,942 2,393 2,918 3,455 4,039 4,528

Minorities [EUR m] 14 17 20 24 28 33 37Provisions [EUR m] 423 360 310 280 303 325 325Long term liabilities [EUR m] 159 364 412 412 412 412 412Short term liabilities [EUR m] 114 76 91 91 91 91 91Cash & cash equivalent [EUR m] -204 -364 -456 -585 -438 -497 -772Net debt [EUR m] 68 76 47 -82 64 6 -269

Other liabilities [EUR m] 1,188 1,061 1,101 1,101 1,101 1,101 1,101Total liabilities [EUR m] 2,041 2,018 1,977 1,797 1,914 1,878 1,626


EBIT [EUR m] 681 154 752 902 945 1,048 937Depreciation & Amortization [EUR m] 407 580 411 425 444 470 488Change in Provisions [EUR m] 60 158 -56 -50 -30 23 23Change in Working capital [EUR m] 128 191 -126 -92 -113 -47 16Tax [EUR m] -204 -78 -209 -267 -284 -314 -284Other movements [EUR m] -68 -238 20 48 29 -27 -17Operating cash flow [EUR m] 1,005 768 790 966 991 1,152 1,163

Capex [EUR m] -747 -803 -687 -737 -1,013 -945 -714Disposals [EUR m] -338 104 -43 0 0 0 0Cash flow from investing activities [EUR m] -1,085 -699 -729 -737 -1,013 -945 -714

New project finance [EUR m] 59 171 49 0 0 0 0Interest [EUR m]

Dividends [EUR m] -149 -90 -65 -99 -124 -149 -174Minority dividends [EUR m] -0 0 0 0 0 0 0Dividends received [EUR m]

Cash flow from financing activities [EUR m] -88 93 -15 -99 -124 -149 -174

Net change in cash [EUR m] -162 159 49 129 -147 58 275


Solarworld Ag SWV GR



Competition at the high end Price premium to be eroded as premium market gets

crowded

We believe that Solarworld will continue to see the premium for its high-end product eroded vs other competitors. Our recent channel checks have shown that prices in Germany are firmer for Asian than high-end European manufacturers. Beyond that, we think it will not be able to command the same premium in other international markets, leading to a lower global ASP for the company.

We are also seeing an increasing trend of brand equity building by leading Chinese and other manufacturers. As a result, we see the industry shifting towards Solarworld’s model, which will likely result in a reduction in the company’s branding uniqueness and thus consumer proposition, even if it will, as we believe, sustain some edge.

Cost reduction required for standstill

Solarworld recently presented cost-reduction initiatives from scaling up through its US capacity build, improved production, silicon consumption (-30% 2009-13F) and efficiency (to 18% for multi-crystalline by 2013F). We think the company will require this in order to move in line with the industry, and that this will only partly offset margin pressure.

A likely survivor

We believe that Solarworld will be a likely survivor in a consolidating market. In our view it will continue to be a leader in the premium segment. But we are concerned over the price at which it will survive, ie, at what level of profitability.

Premium valuation

Solarworld is trading on a 2011F P/E of 17x, vs our estimated 10.6x average for high-end Asian manufacturers. Given pressure from those competitors, we see the premium as too large. Our DCF share price target is Eur 9.


Revenue 900 1,013 1,262 1,455



Normalised EPS (€) 1.33 0.53 0.48 0.58

Norm. EPS growth (%) 0.3 (0.6) (0.1) 0.2

Norm. P/E (x) 7.8 19.6 21.6 17.0

EV/EBITDA (x) 3.5 7.0 8.1 7.0

Price/book (x) 1.4 1.3 1.3 1.8

Dividend yield (%) 0.0 0.0 0.0 0.0

ROE (%) 0.2 0.1 0.1 0.1

Net debt/equity (%) (0.1) 0.4 0.5 0.5

Earnings revisions






1m 3m 6m

22.9 1.4 (30.4)

20.3 (8.3) (40.3)

16.1 0.9 (27.2)

52-week range (€)





18.23/7.95

Frank Asbeck 25

Absolute (€)

Absolute (US$)

Relative to Index


7

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30405060708090100110

Price

Rel MSCI Germany

(€)


Price target €9




Price target €9



Nomura vs consensus Our forecasts are in line with consensus for 2010 and 2011 but we believe that margin pressure will persist despite the current positive sentiment on end markets.

Maintained

REDUCE


Action While Solarworld will likely be a survivor in a consolidating sector, we reiterate our

REDUCE stance, as we see its premium model being eroded and cost efficiencies only partially compensating for margin pressure. Solarworld is trading on a 2011F P/E of 17x, vs our estimated 10.6x average for high-end Asian manufacturers. Our DCF share price target is Eur 9.

Catalysts We expect news flow on strong solar markets to underpin sentiment, while intense

competition will likely cap share price performance.

Anchor themes

Solarworld is a beneficiary of solar growth within the broader new energy theme. It is also very exposed to the broad theme of competitive dislocation within the solar sector.

Solarworld Ag Catharina Saponar, CFA


Risks

SolarWorld may not meet earnings expectations. The company may face supply chain constraints in sourcing silicon and new technology may not lead to reduction in energy costs. The company may have difficulties with its capacity expansion. The company may achieve better-than-expected pricing.





Gross Profit [EUR m] 506 424 556 641 728 787 842%age growth % 27.8% -16.2% 31.1% 15.3% 13.5% 8.1% 7.0%Gross margin % 52.7% 38.0% 40.0% 40.0% 40.0% 40.0% 40.0%

EBITDA [EUR m] 315 215 203 238 258 271 291%age growth % 30.8% -31.6% -5.8% 17.1% 8.4% 5.3% 7.5%EBITDA margin % 35.0% 21.3% 16.1% 16.3% 15.6% 15.2% 15.3%


Operating Profit [EUR m] 260 152 116 137 151 160 177%age growth % 30.77% -41.63% -23.41% 17.74% 10.24% 6.10% 10.36%Operating Margin % 28.9% 15.0% 9.2% 9.4% 9.1% 9.0% 9.2%

Net financial Result [EUR m] -7.61 -25.36 -42.86 -42.60 -50.79 -46.73 -40.88

PBT [EUR m] 188 132 77 95 101 115 138%age growth % 6.8% -29.9% -41.7% 23.9% 6.5% 13.4% 19.8%PBT Margin % 19.6% 11.8% 5.5% 5.9% 5.6% 5.8% 6.5%

Equity Income [EUR m] (56) 10 8 5 5 5 5


Net Income [EUR m] 148 59 54 65 69 78 94%age growth % 30.61% -60.13% -8.84% 20.36% 6.52% 13.44% 19.80%Net earnings [EUR m] 148 59 54 65 69 78 94%age growth % 30.6% -60.1% -8.8% 20.4% 6.5% 13.4% 19.8%Net Profit Margin % 15.4% 5.3% 3.9% 4.0% 3.8% 4.0% 4.5%

KEY SHARE DATA [unit] 2008A 2009A 2010E 2011E 2012E 2013E 2013ENumber of Shares [in m] 111.7 111.7 111.7 111.7 111.7 111.7 111.7EPS [EUR /sh] 1.33 0.53 0.48 0.58 0.62 0.70 0.84EPS (Cont. Operations) [EUR/sh ] 1.33 0.53 0.48 0.58 0.62 0.70 0.84BPS [EUR/sh ] 7.5 7.7 8.2 8.8 9.4 10.1 11.0




Tangible assets [Eurm] 575 788 1,007 1,066 1,111 1,147 1,138Financial assets [Eurm] 31 50 46 42 38 35 32Total fixed assets [Eurm] 606 838 1,052 1,108 1,149 1,182 1,170

Inventories [Eurm] 524 598 695 737 801 826 842Receivables [Eurm] 71 211 97 99 100 108 116Payables [Eurm] -70 -84 -101 -114 -127 -138 -147Working capital [Eurm] 525 726 692 723 774 797 810

Other assets [Eurm] 22 14 22 26 31 36 41Total assets [Eurm] 1,214 1,623 1,811 1,903 1,999 2,061 2,066

Share capital [Eurm] 112 112 112 112 112 112 112Retained Earnings [Eurm] 469 523 587 656 734 828 931Shareholders' funds [Eurm] 841 865 919 984 1,053 1,131 1,225

Minorities [Eurm] 0 0 0 0 0 0 0Provisions [Eurm] 29 29 31 32 33 33 36Long term liabilities [Eurm] 675 751 751 751 751 751 751Short term liabilities [Eurm] 103 107 177 147 261 232 130Cash & cash equivalent [Eurm] -836 -511 -447 -391 -479 -467 -455Net debt [Eurm] -58 347 481 507 533 516 426

Other liabilities [Eurm] 358 329 329 329 329 329 329Total liabilities [Eurm] 373 757 892 919 946 930 842

Total shareholders' funds & liabilities [Eurm] 1,214 1,623 1,811 1,903 1,999 2,061 2,066 CASH FLOW Year-end Dec [unit] 2008A 2009A 2010E 2011E 2012E 2013E 2014E

EBIT [Eur m] 260 152 116 137 151 160 177Depreciation [Eur m] 55 64 87 101 107 111 115Change in Provisions [Eur m] 6 0 1 1 1 1 2Change in Working capital [Eur m] -94 -201 34 -31 -51 -23 -13Tax [Eur m] -53 -73 -23 -30 -32 -37 -44Other movements [Eur m] 0 0 0 0 0 0 0Operating cash flow [Eur m] 174 -58 215 177 175 212 236

Capex [Eur m] -273 -318 -306 -160 -151 -148 -105Disposals [Eur m] 0 0 0 0 0 0 0Cash flow from investing activities [Eur m] -273 -318 -306 -160 -151 -148 -105

New project finance [Eur m] 0 0 0 0 0 0 0Interest [Eur m] -8 -25 -43 -43 -51 -47 -41Dividends [Eur m] 0 0 0 0 0 0 0Minority dividends [Eur m] 0 0 0 0 0 0 0Dividends received [Eur m] 0 0 0 0 0 0 0Cash flow from financing activities [Eur m] -8 -25 -43 -43 -51 -47 -41

Net change in cash [Eur m] -107 -402 -134 -26 -27 17 90


Centrotherm Photovoltaics Ag CTN GR



Efficiency, innovation and growth Market growth, cost drive and innovation cycle drive

equipment demand

We expect global solar end market growth in excess of 30% to 2015 at least to drive demand for manufacturing equipment. In addition, we see a continued focus on technology improvement and innovation resulting from intense price competition at the end market level. Lastly, we perceive a specific focus on manufacturing efficiencies over the medium term.

All of these will benefit Centrotherm as a leading high-end equipment manufacturer, we believe.

Strong product portfolio to drive new orders

Centrotherm has a broad product portfolio, with recent upgrades that deliver improvement on the parameters on which manufacturers focus. Its most recent products deliver 25-30% throughput increases, 1-2% efficiency improvement and lower electricity consumption. We believe this should trigger order flow over the next few quarters. In the silicon segment, the company has confirmed that it has received downpayment for a Qatar order which could lift order intake above €200mn in 2Q.

Discount valuation

Our DCF-based share price target is €40. Centrotherm shares are trading at a 12.4x 2011F P/E, vs. 14x for our equipment universe and 16x for our solar universe, despite the company’s dominant position. As for risks, Centrotherm enters into contracts with customers through turnkey delivery solutions, while subcontracting parts of cell production lines. This exposes the company’s balance sheet to additional risk through warranty provisions.


Revenue 375 509 576 695



Normalised EPS (€) 2.06 1.35 1.84 2.34

Norm. EPS growth (%) 51 (35) 36 27

Norm. P/E (x) 14.0 21.4 15.7 12.4

EV/EBITDA (x) 8.1 7.6 6.0 4.9

Price/book (x) 1.5 1.8 1.6 1.4

Dividend yield (%) 0.0 0.0 0.0 0.0

ROE (%) 11 8 10 11

Net debt/equity (%) (45) (48) (38) (32)

Earnings revisions






1m 3m 6m

9.2 (16.5) (34.1)

6.9 (24.4) (43.5)

2.7 (15.3) (30.3)

52-week range (€)


Stock borrowability Hard


TCH GmbH 50.53

Autenreith Beteil


5.01

Absolute (€)

Absolute (US$)

Relative to Index

Market cap (US$mn) 747

47.77/24.40

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110120130

Price

Rel MSCI Germany

(€)

Closing price on 23 Jun €29

Price target €40



Closing price on 23 Jun €29

Price target €40



Nomura vs consensus We are above consensus for 2010F and 2011F. We believe that the company’s potential for execution on new orders is underappreciated.

Maintained

BUY


Action We reiterate our BUY recommendation as we see positive momentum for the

shares from strong solar market dynamics and improving order flow. Our DCF-based share price target is €40. The share price trades at a discount to our equipment universe despite Centrotherm’s dominant market position.

Catalysts We expect improving order flow on Asian manufacturers expanding capacity, while

the industry globally upgrades its capacity to improve its cost position.

Anchor themes

Centrotherm benefits from a long-term capacity build requirement in the solar sector and also from the technology innovation theme. The latter is a key topic for adoption and growth of solar within renewables.

Centrotherm Photovoltaics Ag Catharina Saponar, CFA


Financial statements P&LYear-end Dec [unit] 2008A 2009A 2010E 2011E 2012E 2013E 2014E


Gross Profit [EUR m] 111 187 173 209 257 298 351Gross margin % 29.6% 36.7% 30.0% 30.0% 30.0% 30.0% 30.0%

%

EBITDA [EUR m] 57 59 77 96 117 139 165%age growth % 167.5% 1.9% 31.9% 23.7% 22.4% 18.3% 18.7%EBITDA margin % 15.3% 11.5% 13.4% 13.8% 13.7% 14.0% 14.0%


Operating Profit [EUR m] 43 37 52 68 84 98 116%age growth % 105.81% -14.47% 39.75% 31.04% 22.71% 16.73% 19.09%Operating Margin % 11.6% 7.3% 9.0% 9.8% 9.8% 9.8% 9.9%

Net financial Result [EUR m] 3 3 5 4 4 4 5

PBT [EUR m] 49 40 57 72 87 102 121%age growth % 127.4% -18.2% 41.4% 27.1% 21.4% 16.6% 19.1%PBT Margin % 13.1% 7.9% 9.9% 10.4% 10.2% 10.3% 10.4%



Net Income [EUR m] 34 29 40 50 61 71 85%age growth % 142.05% -15.22% 36.27% 27.11% 21.35% 16.56% 19.08%Minority Interests [EUR m] 0 (1) (1) (1) (1) (1) (2)Net earnings [EUR m] 35 29 39 49 60 70 83%age growth % 154.0% -17.4% 36.3% 27.1% 21.4% 16.6% 19.1%Net Profit Margin % 9.2% 5.6% 6.8% 7.1% 7.0% 7.0% 7.1%KEY SHARE DATA [unit] 2008A 2009A 2010E 2011E 2012E 2013E 2014ENumber of Shares [in m] 16.8 21.2 21.2 21.2 21.2 21.2 21.2EPS [EUR /sh] 2.06 1.35 1.84 2.34 2.84 3.30 3.94EPS (Cont. Operations) [EUR/sh ] 2.06 1.35 1.84 2.34 2.84 3.30 3.94BPS [EUR/sh ] 18.92 16.28 18.19 20.62 23.58 27.02 31.11

Centrotherm Photovoltaics Ag Catharina Saponar, CFA



Intangible assets [EUR m] 228 229 222 216 209 199 188Goodwill [EUR m]

Tangible assets [EUR m] 44 71 90 114 143 176 216Financial assets [EUR m] 2 1 1 1 1 1 1Total fixed assets [EUR m] 274 302 314 331 353 377 405

Inventories [EUR m] 23 40 41 50 61 71 84Receivables [EUR m] 118 155 177 214 263 306 360Payables [EUR m] -83 -152 -139 -143 -176 -204 -240Working capital [EUR m] 58 43 80 121 149 173 204

Other assets [EUR m] 69 72 72 72 72 72 72Total assets [EUR m] 402 420 469 529 579 626 685

Share capital [EUR m] 21 21 21 21 21 21 21Retained Earnings [EUR m] 14 49 88 137 197 267 350Shareholders' funds [EUR m] 318 344 385 436 499 572 658

Minorities [EUR m] -0 0 2 4 7 9 13Provisions [EUR m] 14 35 21 25 31 36 42Long term liabilities [EUR m] 27 1 1 1 1 1 1Short term liabilities [EUR m] 11 0 0 0 0 0 0Cash & cash equivalent [EUR m] -181 -168 -141 -138 -156 -186 -220Net debt [EUR m] -142 -167 -144 -141 -159 -189 -224

Other liabilities [EUR m] 171 157 157 157 157 157 157Total liabilities [EUR m] -128 -132 -124 -116 -128 -154 -182

Total shareholders' funds & liabilities [EUR m] 402 420 469 529 579 626 685

CASH FLOW STATEMENTYear-end Dec [unit] 2008A 2009A 2010E 2011E 2012E 2013E 2014E

EBIT [EUR m] 43 37 52 68 84 98 116Depreciation [EUR m] 14 21 25 28 34 41 48Change in Provisions [EUR m] 10 21 -14 4 6 5 6Change in Working capital [EUR m] -29 16 -37 -41 -28 -24 -31Tax [EUR m] -15 -11 -17 -22 -26 -31 -36Other movements [EUR m] 0 0 0 0 0 0 0Operating cash flow [EUR m] 25 84 9 37 69 89 103

Capex [EUR m] -38 -52 -37 -45 -56 -65 -76Disposals [EUR m] 0 0 0 0 0 0 0Cash flow from investing activities [EUR m] -38 -52 -37 -45 -56 -65 -76

New project finance [EUR m] 0 0 0 0 0 0 0Interest [EUR m] 3 3 5 4 4 4 5Dividends [EUR m] 0 0 0 0 0 0 0Minority dividends [EUR m] -0 1 1 1 1 1 2Dividends received [EUR m] 0 0 0 0 0 0 0Cash flow from financing activities [EUR m] 3 3 6 5 5 6 7

Net change in cash [EUR m] -10 36 -23 -3 18 30 34


EDF Energies Nouvelles Sa EEN FP



Efficiency, innovation and growth Impacted by weakness in the US PPA market

The current reluctance to sign PPAs by US utilities could in our view result in an overhang on the share price for another couple of quarters as EDF EN is strongly exposed to the MidWest where we believe the impact of electricity demand destruction on wind demand has hit hard.

Strong solar growth

Besides wind, EDF EN has ambitious targets for growth in solar park development. It is well on track to grow its installed capacity from less than 100MW at the end of 2009 to 500MW by 2012. We think that investors still underappreciate the earnings potential of this business.

Valuation reflects risks

Our DCF-based share price target is €39. We estimate that the current share price reflects assets on the ground and under construction with no value attached to the pipeline beyond that. EDF EN shares are trading at 22.9x 2010F P/E vs 26.8x for the close peer wind developers’ average. The company may face delays in project development and supply of turbines and solar panels. It may not be able to obtain PPAs according to expectations. The company may not be able to secure demand for its project development business or for its retail solar business as expected. Banks may consider the balance sheet tight with negative consequences for project financing. Management continuity is a risk with a successful serial entrepreneur CEO. The company may achieve faster pipeline build-out than we expect.


Revenue 1,007 1,173 1,167 1,289



Normalised EPS (€) 0.89 1.27 1.25 1.62

Norm. EPS growth (%) 0.1 0.4 (0.0) 0.3

Norm. P/E (x) 32.2 21.4 22.9 17.7

EV/EBITDA (x) 16.7 15.1 14.0 12.3

Price/book (x) 1.5 1.4 1.4 1.3

Dividend yield (%) 0.0 0.0 0.0 0.0

ROE (%) 0.0 0.1 0.1 0.1

Net debt/equity (%) 0.9 1.9 2.1 2.5

Earnings revisions





Share price relative to MSCI France

1m 3m 6m

(6.6) (17.7) (20.2)

(8.6) (25.5) (31.5)

(12.5) (9.8) (13.1)

52-week range (€)


Stock borrowability


38.66/27.62


Absolute (€)

Absolute (US$)

Relative to Index


2628303234

363840

Jun

09

Jul0

9

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g09

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70

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110

120

Price

Rel MSCI France

(€)


Price target €39


FY net profit (€mn) 97Difference from consensus -12.3%Source: Nomura


Price target €39


FY net profit (€mn) 97Difference from consensus -12.3%Source: Nomura

Nomura vs consensus We think that there is little appreciation of the company’s solar business, but there might be risk to consensus depending on the development of the US market.

Maintained

NEUTRAL


Action We retain our NEUTRAL stance as we see the company exposed to some risk from

the weakness in the US PPA market. Growth in the solar business could partly offset this weakness. Over the long term, the company will benefit from a strong position in its diversified wind and solar development business.

Catalysts Evidence of a recovery in demand for wind capacity by US utilities should underpin

confidence that the company’s largest growth market is getting back on track. Solar capacity build out will draw attention to the company’s new growth driver.

Anchor themes

EDF EN is a major beneficiary of the US stepping up its commitment to climate change and renewable energy within the broader theme of a changing energy sector moving towards new energy.

EDF Energies Nouvelles Sa Catharina Saponar, CFA



P & L Year-end Dec [unit] 2006A 2007A 2008A 2009A 2010E 2011E 2012E 2013E

Sales [EUR m] 335 561 1007 1173 1167 1289 1603 1737%age growth % -0.4% 67.4% 79.6% 15.5% -0.5% 10.4% 24.4% 8.4%

Gross Profit [EUR m] 156 210 656 758 727 781 1,018 1,094%age growth % 0.3% 34.4% 212.7% 76.2% -4.0% 7.4% 30.5% 7.5%Gross margin % 46.6% 37.4% 65.2% 64.5% 62.3% 60.6% 63.5% 63.0%

EBITDA [EUR m] 92 134 216 307 401 527 650 854%age growth % 47.3% 46.3% 60.8% 33.2% 30.4% 31.4% 23.4% 31.3%EBITDA margin % 27.4% 24.0% 21.4% 29.7% 34.4% 40.9% 40.6% 49.1%Depreciation [EUR m] (30) (39) (67) (118) (112) (137) (173) (228)

Operating Profit [EUR m] 62 95 154 230 289 390 477 625%age growth % 55.37% 54.78% 61.55% 39.05% 25.42% 35.15% 22.19% 31.16%Operating Margin % 18.4% 17.0% 15.3% 19.6% 24.7% 30.3% 29.7% 36.0%Net financial Result [EUR m] (24) (25) (43) (81) (156) (212) (268) (324)Non-Operating Income [EUR m] 0 0 0 0 0 0 0 0

PBT [EUR m] 38 71 112 126 152 197 228 322%age growth % 32.2% 87.2% 57.6% 6.9% 20.3% 30.0% 15.8% 41.0%Equity Income [EUR m] 0.75 1 2 0 1 1 1 1Income Tax [EUR m] (10.77) (18) (37) (21) (46) (59) (69) (97)Tax rate % 28.5% 26.0% 33.2% 33.0% 30.0% 30.0% 30.0% 30.0%

Net Income [EUR m] 28 54 76 105 107 139 161 227%age growth [EUR m] 27.32% 92.95% 42.42% 34.55% 2.38% 29.71% 15.72% 40.69%Minority Interests [EUR m] (6) (2) (7) (7) (10) (13) (15) (22)Income from Discontinued Operations [EUR m] (0) 0 0 0 0 0 0 0Net earnings [EUR m] 22 51 69 98 97 126 146 205%age growth % 31.9% 134.4% 34.6% 39.1% -1.2% 29.7% 15.7% 40.7%KEY SHARE DATA [unit] 2006A 2007A 2008A 2009A 2010E 2011E 2012E 2013E

Number of Shares [in m] 62.1 62.1 77.6 77.6 77.6 77.6 77.6 77.6EPS [EUR /sh] 0.35 0.83 0.89 1.27 1.25 1.62 1.88 2.64EPS (Cont. Operations) [EUR/sh ] 0.36 0.83 0.89 1.27 1.25 1.62 1.88 2.64DPS [EUR /sh] n/a 0.11 0.26 0.36 0.37 0.47 0.47 0.66Dividend Payout % nm 30.0% 29.2% 28.5% 29.2% 29.2% 25.0% 25.0%

EDF Energies Nouvelles Sa Catharina Saponar, CFA



BALANCE SHEET Year-end Dec [unit] 2006A 2007A 2008A 2009A 2010E 2011E 2012E 2013E

Intangible assets [EUR m] 4 4 12 19 11 11 10 9Goodwill [EUR m] 41 78 106 116 106 106 106 106Tangible assets [EUR m] 897 1,303 2,261 3,594 4,078 4,865 5,746 6,662Financial assets [EUR m] 92 130 349 390 351 353 354 355Total fixed assets [EUR m] 1,034 1,516 2,727 4,119 4,546 5,334 6,216 7,133

Inventories [EUR m] 121 128 279 0 0 0 0 0Receivables [EUR m] 52 110 301 0 0 0 0 0Payables [EUR m] -109 -55 -218 0 0 0 0 0Working capital [EUR m] 65 183 362 728 691 865 1,057 1,266

Other assets [EUR m] 116 260 481 582 481 481 481 481Total assets [EUR m] 1,215 1,959 3,571 5,429 5,719 6,680 7,754 8,880

Share capital [EUR m] 99 99 124 124 124 124 124 124Net profit [EUR m] 121 157 206 278 332 421 530 682Shareholders' funds [EUR m] 709 745 1,268 1,310 1,394 1,483 1,592 1,744

Minorities [EUR m] 13 12 223 263 223 223 223 223Provisions [EUR m] 5 9 16 26 16 16 17 17Long term liabilities [EUR m] 442 544 907 2,160 3,499 4,350 5,298 6,257Short term liabilities [EUR m] 201 499 1,104 1,316 0 0 0 0Cash & cash equivalent [EUR m] -403 -369 -632 -466 -101 -81 -65 -52Net debt [EUR m] 240 673 1,379 3,010 3,398 4,269 5,233 6,206

Other liabilities [EUR m] 248 520 685 820 688 689 690 691Total liabilities [EUR m] 493 1,202 2,080 3,856 4,101 4,974 5,940 6,913

Total shareholders' funds & liabilities [EUR m] 1,215 1,959 3,571 5,429 5,719 6,680 7,754 8,880

CASH FLOWYear-end Dec [unit] 2006A 2007A 2008A 2009A 2010E 2011E 2012E 2013E

EBIT [EUR m] 62 95 154 230 289 390 477 625Depreciation [EUR m] 301 39 67 118 112 137 173 228Change in Provisions [EUR m] 1 0 -6 0 0 0 0 0Change in Working capital [EUR m] 13 -11 -199 -193 -158 -174 -192 -208Tax [EUR m] -8 -18 -37 -21 -46 -59 -69 -97Other movements [EUR m] -2 12 5 2 1 1 1 1Operating cash flow [EUR m] 95 116 -15 136 199 295 390 550

Capex [EUR m] -334 -523 -1,070 -1,095 -932 -923 -1,053 -1,144Disposals [EUR m] 0 0 0 0 0 0 0 0Cash flow from investing activities [EUR m] -334 -523 -1,070 -1,095 -932 -923 -1,053 -1,144

New project finance [EUR m] 300 366 749 822 745 785 895 972Interest [EUR m] -26 -28 -31 -104 -137 -193 -249 -305Dividends [EUR m] 0 -15 -20 -28 -28 -37 -36 -51Minority dividends [EUR m] -4 -4 -7 -7 -10 -13 -15 -22Dividends received [EUR m] 0 0 0 0 0 0 0 0Cash flow from financing activities [EUR m] 271 319 690 683 570 542 594 594

Net change in cash [EUR m] 33 -88 -394 -276 -163 -87 -69 -0






Japanese companies


Toshiba Plant Systems & Services1983 JP

TECHNOLOGY | JAPAN

Ryo Tazaki +81 3 5255 1743 [email protected]

Record-high profits look set to rise even further

Nuclear power plants account for 35% of sales

Toshiba Plant Systems & Services has two main segments: power generation systems (nuclear and thermal power) and infrastructure and industrial systems. Sales to nuclear power plant operators accounted for 35% of the total in 10/3.

Price target of ¥1,560

We forecast average annual operating profit growth of 10% over the medium term as the company continues to post record profits, driven mainly by contracts with nuclear power facilities. Reflecting its status as a nuclear power-related stock, we apply a P/E of 18x, the target P/E for the NOMURA 400 (excluding financials), to our 11/3 EPS estimate to calculate our price target for the stock. Based on a P/E of 18x our 11/3 estimate, our price target comes to ¥1,560.

We forecast 9% operating profit growth in 11/3

We expect operating profit growth of 9% y-y in 11/3. We look for healthy sales at the new power generation system segment (formed by combining the power system and nuclear power system segments and transferring the substation business to the infrastructure and industrial system segment) because Japanese electric power companies plan to increase capex by 12%. We also anticipate a contribution from sales to overseas thermal power plants. Among overseas projects, we look for an increase in thermal power plant-related sales, centering on Southeast Asia, where work is progressing on electric power infrastructure projects.

Key financials & valuations(¥bn) 10/3 11/3F 12/3F 13/3F

Revenue 155.1 167.0 178.0 188.0

Reported net profit 7.8 8.3 9.2 10.2

Normalised net profit 7.8 8.3 9.2 10.2

Normalised EPS (¥) 80.5 85.2 94.4 104.7

Norm. EPS growth (%) 7.5 5.8 10.8 10.9

Norm. P/E (x) 14..3 13.5 12.2 11.0

EV/EBITDA (x) 5.7 5.3 4.6 4.0

Price/book (x) 1.4 1.3 1.2 1.1

Dividend yield (%) 1.3 1.3 1.3 1.3

ROE (%) 10.1 10.0 10.0 10.2

Net debt/equity (%) (0.4) (0.4) (0.4) (0.4)

Earnings revisions

Previous norm. net profit 8.3 9.2 10.2


Previous norm. EPS (¥) 85.2 94.4 104.7


Share price relative to MSCI Japan

1m 3m 6m

(6.6) 11.4 4.8

(5.8) 9.7 1.1

1.0 19.3 7.2

52-week range (¥)


Stock borrowability Hard



1,312/992

Toshiba 59.6

Absolute (¥)

Absolute (US$)

Relative to Index


9601,0101,0601,1101,1601,2101,2601,3101,360

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n09

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9095100105110115120125130

Price

Rel MSCI Japan

Closing price on 23 Jun ¥1,175

Price target ¥1,560

Upside/downside 33%Difference from consensus na

FY11F net profit (¥bn) 8.3Difference from consensus naSource: Nomura

Nomura vs consensus We have a slightly more bullish outlook than the consensus because we expect growth in power company capex and maintenance work on aging domestic plants.

Maintained

BUY

N O M U R A S E C U R I T I E S C O L T D

Action We expect profits to keep reaching new highs from 11/3 on growth for operations

focusing on nuclear power plants in Japan and thermal plants overseas. Nuclear plants account for 35% of sales, and we expect nuclear demand to grow. We thus see the company as a nuclear power-related player to watch in the medium term.

Catalysts The company tends to issue conservative guidance and is likely to surpass its 11/3

forecasts, especially in nuclear plant-related business. We see growth in orders related to new nuclear plants in China as a key medium-term share price catalyst.

Anchor themes

Japan's power plants are aging and we expect this to drive increased demand for maintenance. With regard to nuclear power plants, we anticipate stronger demand for maintenance and other work to increase earthquake resistance and upgrade aging facilities. We also expect power company capex to bottom and shift upward.

Toshiba Plant Systems & Services Ryo Tazaki


Orders look set to grow in 11/3

On the order front, we estimate a 5% y-y increase in 11/3. Orders are recovering at the infrastructure and industrial system segment and at the power generation system segment for overseas thermal power plant projects.

We expect big rise in infrastructure and industrial system sales

We think that sales growth will reach 26% at the infrastructure and industrial system segment (or 18% adjusted to exclude the impact of transferring the substation business to this segment). As well as a recovery in Japanese capex, we look for a contribution from work to boost NAND flash memory production capacity at Toshiba and mega-solar power generation facility work for electric power companies.

Continued strong sales to nuclear power plant operators

Sales related to nuclear power facilities should remain high on demand for earthquake reinforcement work and measures to upgrade aging facilities. The company is due to post sales from 11/3 on work at the new Oma nuclear power plant, which is due to start operations in November 2014.

Scheduled inspection work on Kashiwazaki-Kariwa restart

At the Kashiwazaki-Kariwa nuclear power plant, only the No. 6 and No. 7 reactors remain closed as a result of the Niigata-Chuetsu earthquake. We expect Toshiba Plant Systems & Services to post sales on scheduled inspection work on reactors Nos 1–5 as they resume operations. The company's medium-term business plan calls for ongoing orders of over ¥200bn from 12/3 for nuclear power-related and overseas thermal power plant projects.

Risks to price target. Risks include changes in electric power companies’ capex and maintenance spending in areas such as nuclear power, which could affect the power generation systems segment, and trends in capex at companies such as Toshiba, which could affect the infrastructure and industrial system segment.




Toshiba Plant Systems & Services [1983]: consolidated financial data(¥mn, except where noted)

08/3 09/3 10/3 11/3F 12/3F 13/3F178,518 165,420 155,181 167,000 178,000 188,000

% y-y 8.4 (7.3) (6.2) 7.6 6.6 5.661,207 52,536 41,663 - - -

33,047 41,425 54,112 - - -- - - 92,000 100,000 109,000

84,263 71,458 59,405 75,000 78,000 79,000

% y-y

Power systems 14.7 (14.2) -20.7 - - -Nuclear power systems (14.2) 25.4 30.6 - - -

- - - - 8.7 9.015.7 (15.2) (16.9) 26.3 4.0 1.3

171,354 183,436 170,673 179,000 187,000 193,000

% y-y 4.2 7.1 (7.0) 4.9 4.5 3.282,600 99,194 114,125 126,125 135,125 140,125

% y-y (8.1) 20.1 15.1 10.5 7.1 3.7

178,518 165,420 155,181 167,000 178,000 188,000% y-y 8.4 (7.3) (6.2) 7.6 6.6 5.6

157,673 142,316 132,170 142,300 151,200 159,100

20,845 23,104 23,011 24,700 26,800 28,900Margin (%) 11.7 14.0 14.8 14.8 15.1 15.4

10,056 10,408 10,109 10,600 11,100 11,600

As % of sales 5.6 6.3 6.5 6.3 6.2 6.210,789 12,695 12,902 14,100 15,700 17,300

% y-y 20.8 17.7 1.6 9.3 11.3 10.2

Margin (%) 6.0 7.7 8.3 8.4 8.8 9.2

250 73 520 400 400 40011,039 12,768 13,422 14,500 16,100 17,700

% y-y 20.4 15.7 5.1 8.0 11.0 9.9Margin (%) 6.2 7.7 8.6 8.7 9.0 9.4

0 175 106 0 0 0

201 0 197 0 0 06,285 7,303 7,840 8,300 9,200 10,200

% y-y 25.1 16.2 7.4 5.9 10.8 10.9Margin (%) 3.5 4.4 5.1 5.0 5.2 5.4

64.5 74.9 80.5 85.2 94.4 104.7

72.2 82.8 88.0 94.0 103.7 113.415.0 15.0 15.0 15.0 15.0 15.0

705.6 762.7 829.0 899.7 979.1 1,068.8

97.5 97.5 97.4 97.4 97.4 97.4

COGSGross profits

Net nonoperating incomeRecurring profits

Operating profits

SG&A expenses

Shares out (mn)

Extraordinary gains

BPS (¥)

Per-share indicators

Sales

Income statementSales

Power systemsNuclear power systems

Infrastructure & industrial systems

Infrastructure & industrial systems

Extraordinary losses

Orders

Order backlog

Power generation systems

DPS (¥)

Net profits

EPS (¥)CFPS (¥)

Power generation systems




Toshiba Plant Systems & Services [1983]: consolidated financial data(¥mn, except where noted)

08/3 09/3 10/3 11/3F 12/3F 13/3F

136,458 130,871 130,334 138,296 147,884 158,263

Cash & deposits 29,660 23,335 31,227 32,372 35,411 39,836

Accounts receivable 81,521 80,300 76,181 81,983 87,383 92,292Marketable securities 0 0 0 0 0 0

Inventory assets 19,451 20,816 16,207 17,441 18,590 19,635

Other 5,826 6,420 6,719 6,500 6,500 6,50019,735 20,217 20,628 20,927 20,827 20,777

Property, plant and equipment 7,045 6,949 6,457 6,777 6,677 6,627

Investments, other assets 12,590 13,177 14,021 14,000 14,000 14,000

Intangible long-term assets 100 91 150 150 150 150156,192 151,089 150,962 159,223 168,711 179,040

65,148 53,246 44,468 46,560 48,309 49,900Accounts payable 45,317 31,515 24,680 26,560 28,309 29,900

Short-term interest-bearing debt 0 0 0 0 0 0

Other 19,831 21,731 19,788 20,000 20,000 20,00022,179 23,461 25,668 25,000 25,000 25,000

Long-term interest-bearing debt 0 0 0 0 0 0

Other 22,179 23,461 25,668 25,000 25,000 25,000

68,865 74,381 80,825 87,663 95,402 104,140156,192 151,089 150,962 159,223 168,711 179,040

6.8 8.3 8.5 9.1 9.6 9.99.4 10.2 10.1 9.9 10.1 10.2

1.1 1.1 1.0 1.0 1.1 1.1(0.4) (0.3) (0.4) (0.4) (0.4) (0.4)

44.1 49.2 53.5 55.1 56.5 58.2

Net profits 6,285 7,303 7,840 8,300 9,200 10,200

Depreciation 758 768 737 860 900 850Change in working capital (2,542) (13,946) 1,893 (5,157) (4,799) (4,363)

4,501 (5,875) 10,470 4,003 5,301 6,687650 728 330 1,180 800 800

3,851 (6,603) 10,140 2,823 4,501 5,887

Balance sheetCurrent assets

Long-term assets

Total assets Current liabilities

Long-term liabilities

Net assetsTotal liabilities and net assetsROA (%)

ROE (%)Total capital turnover ratio (x/year)Net D/E ratio (x)

Free cash flow

Owners' equity ratio (%)

Cash flow

Operating cash flowCapex



Japan Steel Works 5631 JP

TECHNOLOGY | JAPAN

Shigeki Okazaki +81 3 5255 1719 [email protected]

Parts for nuclear plants firm, but other parts hurt by weak euro

We expect 13% drop in operating profits in 11/3 on rise in depreciation and fall in margins

For 11/3, we project that depreciation expenses will rise roughly ¥6bn y-y, mainly in the steel product segment. We think that margins on oil refinery pressure vessels, made by the steel product segment, will remain high owing to the booking of sales on orders received prior to the global financial crisis in 2008. In contrast, margins are likely to be slim in the machinery product segment, partly because of the booking of sales on plastics machinery orders received in 10/3, after the crisis. In plastics machinery, Japan Steel Works is set to book saIes mainly for pelletisers in 11/3F, but the company’s competitiveness could be hampered in this segment, where German rival Coperion (unlisted) is strong, owing to euro weakness versus the yen.

Rise in depreciation should ease in 12/3 but sharp fall in pressure vessel sales likely to weigh on earnings

We see growth in depreciation easing in 12/3, but look for margins on oil refinery pressure vessels to contract. Again, euro weakness could hamper the company's competitiveness in this market vis-à-vis Italian rivals such as Nuovo Pignone (unlisted), part of the General Electric [GE US] group, and ATB Riva Calzoni (unlisted). We think that sales of parts and materials for nuclear power plants will grow in 12/3, but forecast only a small y-y increase in companywide operating profits. However, for 13/3 we forecast operating profits of ¥37.5bn, which would exceed the peak of ¥36.6bn in 09/3, supported by sharp sales growth for nuclear power plant parts and materials and a roughly ¥3bn y-y drop in depreciation.

Key financials & valuations(¥mn) 10/3 11/3F 12/3F 13/3F

Revenue 201,680 208,000 217,600 235,200



Normalised EPS (¥) 47.2 42.0 42.6 57.1

Norm. EPS growth (%) 9.3 (11.0) 1.4 34.0

Norm. P/E (x) 17.9 20.2 19.9 14.8

EV/EBITDA (x) 6.7 5.9 4.9 4.5

Price/book (x) 3.1 2.7 2.5 2.1

Dividend yield (%) 0.1 0.1 0.0 -0.2

ROE (%) 0.1 0.1 - (0.2)

Net debt/equity (%) 1.4 1.4 1.4 1.9

Earnings revisions






1m 3m 6m

(2.3) (21.1) (27.4)

(2.9) (20.9) (26.1)

(2.0) (13.2) (24.6)

52-week range (¥)


Stock borrowability -


1,286/788

3,492

Absolute (¥)

Absolute (US$)

Relative to Index

Market cap (US$mn)


Japan Trustee Serv ices Bank, Ltd 5.28

750

850

950

1,050

1,150

1,250

1,350

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110

Price

Rel MSCI Japan

Closing price on 23 Jun ¥847

Price target ¥900

Upside/downside 6.3%Difference from consensus na

FY11F net profit (¥mn) 15,600Difference from consensus naSource: Nomura

Nomura vs consensus The QUICK consensus operating profit forecast for 11/3 is ¥26.5bn, while our projection is slightly higher at ¥28.0bn.

Maintained

NEUTRAL


Action Japan Steel Works is competitive in nuclear power plant parts and materials, and

we expect it to benefit from global demand growth in this area. But its oil- and gas-related parts lack the same competitiveness and euro weakness is a negative. We expect earnings to languish until 12/3. Now is not the time to invest in our view. NEUTRAL maintained.

Catalysts Substantial cost reduction and forming a structure that enables the firm to achieve

high margins even with the euro at its current weak level.

Anchor themes

One investment idea for the sector is to focus on companies that help reduce greenhouse gas emissions. Japan Steel Works fits because it has around 80% of the global market for pressure vessels used in nuclear power plants, which have lower CO2 emissions than thermal power plants.

Japan Steel Works Shigeki Okazaki


Company's medium-term plan looks achievable

On 21 May, Japan Steel Works announced a new medium-term business plan ending in 13/3. We think that the plan’s final-year operating profit target of ¥37bn looks achievable. Moves to expand part procurement beyond Europe should have some impact in countering euro weakness. We note also that demand has been recovering recently for high-value-added twin screw extruders. We view this as a positive for Japan Steel Works, this being a segment of the plastics machinery market where European companies have small market shares.

Firm outlook for nuclear power plant parts

The primary components for nuclear power plants that Japan Steel Works manufactures include pressure vessels, steam turbines and pressurisers. Its secondary part line includes steam turbine rotor shafts. In this field, the company has an 80% share of the global market, supported by its advanced manufacturing technologies in ingot casting, forging (using a 14,000t press) and heat processing (temperature control technology, etc). We think that annual sales will rise steadily from parts for six nuclear power plants in 11/3, to nine in 12/3 and 11 in 13/3, driving earnings in the medium term.

Valuation

Our price target is ¥900. We apply to our 12/3 EPS estimate a P/E of roughly 21x, which is higher than the NOMURA 400 benchmark P/E, but we think this is justified by the company's competitiveness, as seen in its roughly 80% global market share for certain parts and materials used in nuclear power plants.

Risks to our price target. Risks include yen appreciation (especially against the euro), a sharp decline in crude oil prices, economic downturn in emerging markets, and a major incident at a nuclear power plant.



Financial statements Japan Steel Works [5631]: consolidated financial data

(¥mn, except where noted)

11/3F 12/3F 13/3F

166,179 227,656 228,804 264,550 240,420 209,843 198,800 214,600 233,200 212,000 255,000 280,000

64,357 105,299 102,700 118,007 120,011 94,342 101,000 110,600 121,000 107,200 118,000 123,000

21,800 27,100 35,800 42,700 59,900 58,500 57,000 62,000 71,000 58,900 68,500 75,000

Nuclear power (est) 9,000 15,000 18,000 34,900 38,500 40,000 46,000 56,000

Thermal power, etc (est) 18,100 20,800 24,700 25,000 20,000 17,000 16,000 15,000

9,200 30,600 19,200 23,500 19,700 2,800 10,000 12,000 12,000 12,000 13,000 11,000

15,200 29,900 27,800 35,000 25,100 20,300 21,000 22,000 23,000 22,500 22,000 23,000

18,157 17,699 19,900 16,807 15,311 12,742 13,000 14,600 15,000 13,800 14,500 14,000

99,363 119,347 124,118 144,461 118,643 113,711 96,000 102,200 110,400 103,000 135,000 155,000

16,800 24,200 26,900 40,300 25,700 26,700 28,000 30,000 32,000 28,000 33,000 36,000

27,200 33,500 30,900 33,800 18,200 15,500 22,000 24,200 25,400 22,000 27,000 32,000

55,363 61,647 66,318 70,361 74,743 71,511 46,000 48,000 53,000 53,000 75,000 87,000

Wind power 6,000 14,200 21,700 27,200 3,000 5,000 10,000 3,000 10,000 15,000

Other (guns, etc) 60,318 56,161 53,043 44,311 43,000 43,000 43,000 50,000 65,000 72,000

2,459 3,010 1,986 2,082 1,766 1,790 1,800 1,800 1,800 1,800 2,000 2,000

117,592 171,895 193,976 237,689 246,209 254,371 245,171 242,171 240,171

39,900 80,833 107,227 132,621 144,805 137,410 130,910 131,910 132,910

71,100 83,900 93,900 94,900 95,900

50,500 28,000 12,000 12,000 12,000

11,100 14,800 14,300 14,300 14,300

12,105 10,710 10,710 10,710 10,710

76,887 89,329 85,994 104,314 100,659 116,206 113,506 109,506 106,506

25,200 29,000 34,000 36,000 38,000

2,000 7,000 7,300 7,300 7,300

73,459 80,206 72,206 66,206 61,206

805 1,733 755 754 745 755 755 755 755

158,274 173,353 207,138 220,851 227,113 201,680 208,000 217,600 235,200 208,000 230,000 260,000

52,339 64,366 76,305 92,613 107,883 101,736 107,500 109,600 120,000 109,000 108,000 120,000

16,200 19,500 25,600 31,200 36,500 45,800 47,000 61,000 70,000 46,800 61,400 70,500

Nuclear power (est) 4,000 7,500 10,000 15,000 27,800 30,000 45,000 55,000

Thermal power, etc (est) 15,500 18,100 21,200 21,500 18,000 17,000 16,000 15,000

6,100 7,200 7,800 14,100 21,900 25,000 26,000 12,000 12,000 26,000 12,000 12,000

14,100 20,700 24,800 31,300 34,900 18,200 21,500 22,000 23,000 21,500 23,000 23,000

15,939 16,966 18,105 16,013 14,583 12,736 13,000 14,600 15,000 14,700 11,600 14,500

102,618 106,906 127,866 126,155 117,462 98,164 98,700 106,200 113,400 97,200 120,000 138,000

16,200 18,000 24,600 30,200 36,900 20,200 23,000 28,000 30,000 23,500 29,000 33,000

24,200 29,600 30,100 34,600 27,200 13,300 21,700 24,200 25,400 20,000 27,000 31,000

62,218 59,306 73,166 61,355 53,362 64,664 54,000 54,000 58,000 53,700 64,000 74,000

Wind power 2,900 4,100 1,800 18,800 11,000 11,000 15,000 11,000 13,000 15,000

Other (guns, etc) 70,266 57,255 51,562 45,864 43,000 43,000 43,000 42,700 51,000 59,000

3,317 2,081 2,967 2,083 1,768 1,780 1,800 1,800 1,800 1,800 2,000 2,000

7,721 12,876 24,678 32,475 36,633 32,185 28,000 28,500 37,500 25,500 26,000 37,000

4,259 7,617 13,971 25,185 31,473 31,640 27,700 26,900 35,100 28,000 24,000 30,500

Nuclear power (est) - - - 3,000 4,500 8,300 8,400 13,500 19,800

Other (est) - - - 22,185 26,973 23,340 19,300 13,400 15,300

7,521 9,791 15,429 13,263 11,435 6,535 6,500 8,000 9,000 4,300 8,500 13,500

1,130 746 868 689 743 733 700 700 700 700 700 700

(5,189) (5,278) (5,590) (6,662) (7,018) (6,723) (6,900) (7,100) (7,300) (7,500) (7,200) (7,700)

4.9 7.4 11.9 14.7 16.1 16.0 13.5 13.1 15.9 12.3 11.3 14.2

8.1 11.8 18.3 27.2 29.2 31.1 25.8 24.5 29.3 25.7 22.2 25.4

7.3 9.2 12.1 10.5 9.7 6.7 6.6 7.5 7.9 4.4 7.1 9.8

34.1 35.8 29.3 33.1 42.0 41.2 38.9 38.9 38.9 38.9 35.0 35.0

20.8 66.8 91.7 31.6 12.8 -12.1 -13.0 1.8 31.6 -20.8 2.0 42.3

1 5 6 9 11 Just over 5 9 11

6 6 9 12 12 9 12 12

Co's

13/3F

Orders by segment

Companywide orders

09/305/3 06/3 07/3 10/308/3 12/3F

Other

Regional development

Plastics machinery

Molding equipment

Companywide order backlog

Sales by segment

Companywide sales

Orders backlog by segment

Steel products (forging & casting + steel plates & structures)

Machinery (plastics machinery + other)


Clad steel pipes & plates

Other



Operating profits by segment

Companywide operating profits

Other


Plastics machinery

Molding equipment

Ref) Nuclear reactor-equivalent production capacity




Companywide ope profit growth (% y-y)


Operating margin (%)

Company wide

Unallocatable expenses

Other

11/3F


Nuclear/electric power

Pressure vessels





Pressure vessels

Ref) Nuclear reactor-equivalent sales (est) (units/yea


Pressure vessels


Other

Plastics machinery

Molding equipment

Other


Note: (1) We estimate that a ¥1 rise against the US dollar would reduce 11/3 operating profits by roughly ¥50mn, and that a ¥1 rise against the euro would reduce profits by roughly ¥20mn. The company is assuming rates of $1/¥90 and €1/¥120 for 11/3 (as do we). (2) According to the medium-term plan announced on 21 May 2010, company guidance for recurring profits is ¥25.5bn and ¥36.5bn for 12/3 and 13/3, respectively. Guidance for net profits is ¥14.5bn (EPS of ¥39) and ¥21bn (EPS of ¥57), respectively. Operating profit guidance for 11/3 is ¥9.5bn for H1 and ¥16bn for H2.




Japan Steel Works [5631]: change in operating profits(¥mn, except where noted)

06/3 07/3 08/3 09/3 10/3 11/3F 12/3F 13/3F11/3Co's

12,876 24,678 32,475 36,633 32,185 28,000 28,500 37,500 25,500Operating profit growth (%) 67 92 32 13 -12 -13 2 32 -21

+5,155 +11,802 +7,797 +4,158 -4,448 -4,185 +500 +9,000 -6,685+0 +1,300 +1,000 -1,300 -1,600 -200 +0 +0 -200

+3,739 +8,700 +7,500 +4,500 -7,900 +4,800 +5,500 +6,400 +2,700+4,400 +5,700 +7,600 +4,500 +900 +0 -5,700 +0 -100-2,600 -3,000 -3,300 -2,400 +4,300 -2,500 +0 +0 -3,000

-384 +100 -179 +54 -10 -33 +0 +0 +0+0 -998 -4,824 -1,196 -138 -6,252 +700 +2,600 -6,085

Depreciation -4,621 -2,489 -2,600 -6,000 -600 +3,000 -6,000Other -203 +1,293 +2,462 -252 +1,300 -400 -85

107 115 115 101 95 90 90 90 90

Operating profits

Y-y change

$/¥ rate

ForexVolumeSales prices and cost cutsRise in raw materials pricesProfits on regional developmentIncrease in fixed costs, other

Note: Most of the company’s overseas sales are denominated in yen. We estimate that a ¥1 rise against the US dollar will reduce 11/3 operating profits by just over ¥50mn.




Japan Steel Works [5631]: consolidated financial data(¥mn, except where noted)

05/3 06/3 07/3 08/3 09/3 10/3 11/3F 12/3F 13/3F

158,274 173,353 207,138 220,851 227,113 201,680 208,000 217,600 235,2007,721 12,876 24,678 32,475 36,633 32,185 28,000 28,500 37,5006,210 11,770 23,459 30,864 35,949 31,246 28,000 28,500 37,5003,284 6,586 12,515 17,484 16,034 17,528 15,600 15,800 21,2003,820 5,520 10,200 16,100 38,700 31,800 34,900 10,500 6,0004,230 4,100 4,690 9,311 11,800 14,400 20,400 21,000 18,000

371 371 371 371 371 371 371 371 3718.7 17.6 33.7 47.1 43.2 47.2 42.0 42.6 57.1

20.4 28.8 46.3 72.2 69.1 86.0 97.0 99.1 105.6154.7 177.2 203.1 228.9 242.1 296.1 329.5 359.9 401.2

3 5 9 12 12 12 12 12 1634 28 27 26 28 25 29 28 28

184,683 196,656 232,444 262,452 296,908 322,986 341,000 355,800 378,600116,232 122,100 147,774 168,663 174,258 171,518 175,000 200,300 235,10023,901 18,572 27,881 36,552 39,957 45,646 45,600 65,600 90,600

573 0 0 0 0 0 0 0 042,425 45,754 53,753 52,062 49,497 42,431 43,800 45,800 49,50044,488 50,583 58,228 66,815 72,586 69,626 71,800 75,100 81,200

4,845 7,191 7,912 13,234 12,218 13,815 13,800 13,800 13,80068,450 74,556 84,670 93,789 122,650 151,467 166,000 155,500 143,50052,227 53,103 58,642 61,277 91,327 111,166 125,700 115,200 103,200

1,265 1,444 1,578 623 1,318 1,236 1,200 1,200 1,20014,958 20,009 24,450 31,889 30,005 39,065 39,100 39,100 39,100

127,222 130,803 156,823 177,221 206,783 211,836 218,700 222,200 229,70035,824 41,697 49,532 48,732 42,552 36,232 37,400 39,100 42,30029,952 20,003 13,702 8,323 8,520 24,389 30,100 31,900 36,20021,027 16,890 8,344 10,239 27,917 28,170 28,200 28,200 28,200

7,000 7,000 7,000 7,000 7,000 0 0 0 033,419 45,213 78,245 102,927 120,794 123,045 123,000 123,000 123,00057,461 65,853 75,621 85,231 90,125 111,149 122,300 133,600 148,900

115,440 109,746 104,667 110,793 133,562 163,708 180,600 193,700 213,3006.7 11.7 23.6 29.3 27.4 19.7 15.5 14.7 17.64.2 6.5 10.6 12.4 12.3 10.0 8.2 8.0 9.95.7 10.0 16.5 20.5 17.8 15.8 12.8 11.8 14.24.9 7.4 11.9 14.7 16.1 16.0 13.5 13.1 15.93.9 6.8 11.3 14.0 15.8 15.5 13.5 13.1 15.9

8.75 7.60 6.06 6.02 7.06 9.74 10.42 10.68 10.8814.00 13.61 13.47 14.26 15.69 19.22 19.67 19.62 19.32

1.9 1.3 1.6 2.0 2.1 2.7 2.6 3.6 4.63.2 3.2 3.1 2.8 2.6 2.5 2.5 2.5 2.53.4 3.5 3.4 3.6 3.8 4.1 4.1 4.1 4.12.7 2.9 2.9 2.6 2.2 2.2 2.2 2.2 2.23.9 3.8 3.6 3.8 4.2 4.5 4.5 4.5 4.5

57,979 43,893 29,046 25,562 43,437 52,559 58,300 60,100 64,4001.01 0.67 0.38 0.30 0.48 0.47 0.48 0.45 0.4331.1 33.5 32.5 32.5 30.4 34.4 35.9 37.5 39.3

33,505 25,321 1,165 (10,990) 3,480 6,913 12,700 (5,500) (26,200)0.58 0.38 0.02 (0.13) 0.04 0.06 0.10 (0.04) (0.18)

7,921 5,854 35,630 42,040 26,319 45,668 33,625 33,200 32,60013,611 (6,534) (9,679) (24,765) (33,148) (37,287) (34,900) (10,500) (6,000)21,532 (680) 25,951 17,275 (6,829) 8,381 (1,275) 22,700 26,600

Income statement

CapexDepreciationShares out (mn)

SalesOperating profitsRecurring profitsNet profits

EPS (¥)CFPS (¥)BPS (¥)


LiabilitiesInvestments, other assets

Accounts payable Short-term debtLong-term debt

Other

Cash & deposits

Payout ratio (%)

Marketable securitiesAccounts receivable

DPS (¥)

Balance sheetTotal assetsCurrent assets

Long-term assets

Inventory assetsOther

Recurring margin (%)

Net assets

Invested capitalROIC (%)

Property, plant & equipment Intangible long-term assets

Net interest-bearing debt

Turnover periods (months)

Corporate bonds, etc

Investment cash flow

Key indicators

Invested capital

Operating cash flow

Working capital

Cash & equivalentsAccounts receivable

Free cash flow

ROA (%)

Inventory assetsAccounts payable

Total assets

ROE (%)

Net D/E ratio (x)

Interest-bearing debtD/E ratio (x)Owners' equity ratio (%)



NPC Incorporated 6255 JP

TECHNOLOGY | JAPAN

Tetsuya Wadaki +81 3 5255 1797 [email protected]

At the forefront of strategic initiatives within the industry

Production equipment market is in recovery phase

The solar cell market is over the worst, and prices have begun to recover after falling consistently after the Lehman Brothers collapse. Orders in 10/8 Q2 were back above the levels seen in 08/8 Q4, thanks to a sharp recovery in module production equipment inquiries and a rise in NPC's market share. Although the company has said that Q2 orders were excessively high and projects orders of around ¥4-5bn in Q3, it still expects orders to be close to where they were prior to the fall of Lehman Brothers.

Introduction of new production systems

NPC is currently the price leader in the industry, but it nevertheless is introducing new production systems rather than resting on its laurels. To be more precise, it will be shifting to batch production from built-to-order production and increasing the proportion of in-house production. This will increase inventory risk, but should also help bring down lead times and manufacturing costs. Although the introduction of new systems will increase fixed costs, we think that it will also lower variable costs, which means the company should see an improvement in margins if it can secure a certain level of sales. We expect it to reduce lead times by modularising equipment and increasing the proportion of in-house production. It is seeking to halve lead times for equipment that previously required four to six months to manufacture and to achieve cost savings of 15%. It also appears that the new systems incorporate the company's expertise in areas such as market and order forecasting in order to reduce inventory risk. We think that this will help differentiate it from competitors. With the booking of large-scale orders and increase in technical strength and introduction of new production systems that go with that, the company is now forecasting a return to a recurring margin in excess of 15% in 11/8 Q3.


Revenue 14,164 17,000 18,700 20,500

Reported net profit 1,575 808 1,627 2,071

Normalised net profit 1,575 808 1,627 2,071

Normalised EPS (¥) 89.9 46.1 92.8 118.2

Norm. EPS growth (%) - - - -

Norm. P/E (x) - 32.9 16.3 12.8

EV/EBITDA (x) - 16.3 8.1 6.5

Price/book (x) - 3.2 2.7 2.3

Dividend yield (%) 0.0 0.0 0.0 0.0

ROE (%) 21.0 9.8 16.7 13.1

Net debt/equity (%) 0.0 0.0 0.0 0.0

Earnings revisions

Previous norm. net profit 808 1,627 2,071





1m 3m 6m

(9.4) (26.0) (29.4)

(8.7) (27.1) (31.9)

(3.2) (18.8) (27.1)

52-week range (¥)




Chikaki Yoshiro 13.0


2,635/1,430

Ito Masafumi 10.4

Absolute (¥)

Absolute (US$)

Relative to Index

Market cap (US$mn) 314.7

1,3001,5001,7001,9002,1002,3002,5002,7002,900

Ju

n09

Jul

09

Au

g09

Se

p0

9

Oc

t09

No

v09

De

c09

Jan

10

Fe

b10

Ma

r10

Apr

10

Ma

y10

50

60

70

80

90

100

110

Price

Rel MSCI Japan


10/8F net profit (¥mn) 808Source: Nomura


Action The solar cell production equipment market is in a recovery phase. NPC is likely to

see higher sales but lower profits in 10/8 owing to weak orders last year, price competition and a recent large strategic order. But we view strategic orders as investments for future growth that should help boost the firm’s competitiveness.

Catalysts New large-scale projects and production systems should improve cost

competitiveness, cut manufacturing times, and improve technologies, boosting its already strong market share.

Anchor themes

The solar cell market has been expanding rapidly since last year, led by Japan and Europe. Cuts in German subsidies are a negative, but we expect growth in China, Japan and the US. We think pricing, lead times and reliability will be the main differentiators for production equipment makers.

NOT RATED

NPC Incorporated Tetsuya Wadaki


Differentiation and survival strategies

Margins have been dented in 10/8 by NPC taking on several low-margin orders involving substantial development work. Although the company has not disclosed any details of the orders in question, the products themselves automate the transportation of solar cells between module equipment. We expect the company's market share to rise further thanks to improvements in product competitiveness and the ability to sell packages of module equipment currently sold individually. We have identified the emergence of Chinese competitors as the main medium-term risk for NPC and we like the way that these automated systems have raised the barriers to entry for emerging economy companies. NPC has stated its wish to be at the forefront of initiatives within the industry, with the main aim of cost savings and capex efficiency gains being to reduce costs for solar power systems and achieve grid parity more rapidly, rather than simply boosting its own profit margins. We think that its focus on services and its clients should help NPC to gain their trust and ensure it continues to garner large market share.




NPC [6255]: consolidated financial data(¥mn, except where noted)

Co's 10/8F

4,189 6,554 9,373 14,164 17,029 17,000 18,700 20,500% y-y 56.5 43.0 51.1 20.2 20.0 10.0 9.6

3,578 5,958 8,837 13,676 16,600 18,300 20,100

% y-y 66.5 48.3 54.8 21.4 10.2 9.8611 596 536 487 400 400 400

% y-y -2.5 -10.1 -9.1 -17.9 0.0 0.01,462 1,921 2,936 4,644 3,678 5,240 5,953

Margin (%) 34.9 29.3 31.3 32.8 21.6 28.0 29.0816 1,097 1,550 2,017 2,420 2,563 2,632645 824 1,386 2,626 1,205 1,258 2,677 3,321

% y-y 27.8 68.2 89.5 -54.1 -52.1 112.8 24.1838 1,213 1,907 3,343 2,058 3,477 4,121

% y-y 44.7 57.2 75.3 -38.4 68.9 18.5(30) (78) (5) 19 0 0 0

% y-y(163) (310) (515) (735) (800) (800) (800)

17 19 80 51 100 100 1001 2 13 19 19 19 19

69 52 35 54 50 50 5010 1 0 0 0 0 0

593 791 1,431 2,623 1,253 1,308 2,727 3,371% y-y 33.4 80.9 83.3 -52.2 -50.1 108.5 23.6

0 11 0 0 0 0 0

0 0 0 0 0 0 0593 802 1,431 2,623 1,308 2,727 3,371

246 319 627 1,145 500 1,100 1,300(3) 15 (30) (97) 0 0 0

0 0 0 0351 467 834 1,575 849 808 1,627 2,071

% y-y 33.0 78.6 88.8 -46.1 -48.7 101.4 27.3

3 72 110 165 270 320 370332 364 1,895 1,084 1,000 2,000 2,000

17 33 93 166 200 300 400

55,100.7 133.5 50.5 89.9 46.6 46.1 92.8 118.2106,977.6 494.2 339.1 425.8 470.3 557.2 667.3

53,844.0 127.9 52.9 99.3 57.5 110.0 141.01,750.0 6.0 2.0 5.0 3.0 6.0 8.0

0.007 3.910 17.525 17.525 17.525 17.525 17.525

11/8F 12/8F06/8 07/8 08/8 09/8

CFPS (¥)DPS (¥)

Shares out (FY-end, mn)

DepreciationPre-share indicatorsEPS (¥)BPS (¥)

Minority interestsNet profits

R&D expenses

Capex


Pretax profitsCorporation tax, etcAdjusted corporation tax

Nonoperating expensesInterest paid & discounts

Recurring profits

Extraordinary gains

Vacuum packaging machines

Eliminations/companywideNonoperating income

Interest & dividends received

Gross profits

SG&A expensesOperating profits

Photovoltaic manufacturing equipmen


Photovoltaic manufacturing equipmen

Vacuum packaging machines




NPC [6255]: consolidated financial data (continued)(¥mn)

06/8 07/8 08/8 09/8 10/8F 11/8F 12/8FBalance sheet

1,091 1,711 5,033 5,376 9,990 9,512 9,543

644 476 1,349 1,271 1,500 1,700 1,9001,595 1,568 4,371 3,921 4,700 5,200 5,700

(18) (2) (5) (21) 0 0 0

197 204 586 659 700 700 7003,509 3,957 11,334 11,206 16,890 17,112 17,843

591 860 2,577 3,452 4,252 5,952 7,5525 60 86 123 100 100 100

125 141 194 218 200 200 200721 1,061 2,857 3,793 4,552 6,252 7,852

4,231 5,018 14,191 14,999 21,442 23,364 25,695Accounts payable 1,241 1,872 4,203 3,471 4,200 4,600 5,000Short-term borrowings 75 0 0 0 5,000 5,000 5,000

Bonds maturing within one year 40Other current liabilities 2,029 1,209 4,045 4,000 4,000 4,000 4,000

3,385 3,081 8,248 7,524 13,200 13,600 14,000Long-term borrowings 0 0 0 0 0 0

Bonds 100 0 0 0 0 0 0Other long-term liabilities 14 1 1 13 0 0 0

114 1 1 13 0 0 03,500 3,083 8,249 7,537 13,200 13,600 14,000

Legal capital 180 550 2,158 2,158 2,158 2,158 2,158

Capital surplus 103 473 2,080 2,080 2,080 2,080 2,080Profit reserve 441 897 1,708 3,249 4,004 5,526 7,457

725 1,921 5,947 7,487 8,242 9,764 11,695(2) 10 4 (25) 0 0 0

5 13 (5) (25) 0 0 0731 1,935 5,942 7,462 8,242 9,764 11,695

4,231 5,018 14,191 14,999 21,442 23,364 25,695

Cash flow530 554 2,039 1,585 729 1,627 2,171593 802 834 1,575 808 1,627 2,071

17 33 93 166 200 300 400

(137) 173 (880) 58 (229) (200) (200)(694) 28 (2,803) 439 (779) (500) (500)

368 619 2,333 (727) 729 400 400383 (1,101) 2,462 74 0 0 0

(315) (782) (1,481) (4,146) (3,949) (4,967) (4,967)(17) (319) 402 (2,967) (2,967) (2,967) (2,967)

0 0 0 0 0 0 0

(279) (408) (1,811) (1,150) (1,000) (2,000) (2,000)0 0 0 0 0 0 0

16 (1) 12 0 18 0 0(35) (54) (84) (29) 0 0 0

(461) 513 3,164 (35) 4,947 (105) (140)74 (75) 0 0 5,000 0 0

(588) (140) 0 0 0 0 057 740 3,180 0 0 0 00 0 0 0 0 0 0

(5) (11) (23) (34) (53) (105) (140)1 (1) 7 (1) 0 0 0

5 15 0 (27) 0 0 0(240) 301 3,723 (2,622) 1,727 (3,445) (2,936)

1,095 854 1,155 4,879 2,256 3,983 538854 1,155 4,879 2,256 3,983 538 (2,398)

Share buybacksDividends paid

Other

Other

Change in short-term borrowings

Change in bonds and long-term borrowingsChange owing to issuance of shares

Change in marketable securitiesL-T assets (PPE/intangible) acquisition

L-T assets (PPE/intangible) saleChange in investment securities & long-term loa

Forex adjustmentsAccumulated other comprehensive income

Pretax profits

Net assetsTotal liabilities and net assets

Other current assets

Property, plant and equipment

Intangible long-term assetsTotal investments, other assets

Cash & deposits

Accounts receivableInventory assets

Bad-debt reserves

Change in cash & equivalentsCash & equivalents at FY-startCash & equivalents at FY-end

Current assets

Long-term assetsTotal assets

Total liabilities

Operating cash flow

Investment cash flow

Financial cash flow


Current liabilities

Foreign currency translation difference in cash & equivalents

DepreciationChange in accounts receivable

Change in inventory assetsChange in accounts payableOther

Change in time deposits

Shareholders' equity



Hitachi 6501 JP

TECHNOLOGY | JAPAN

Masaya Yamasaki +81 3 5255 0571 [email protected]

Increasing power system focus on environment-friendly fields

Hitachi targets 16/3 power system sales of ¥1.2tn and operating margin of 6%

Hitachi targets power system sales of ¥900bn in 13/3 and ¥1.2tn in 16/3, versus ¥882.1bn in 10/3, and an operating margin of 5% in 13/3 and 6% in 16/3, versus 2.5% in 10/3. The sales figures are effectively a downward revision from its previous 12/3 target of ¥1tn, but we consider the adjustment an appropriate response to recent changes in the business environment. We anticipate firm short-term earnings based on the order backlog for overseas thermal power projects and domestic nuclear power projects. Orders appear to have slowed owing to financial market turmoil, and we need to focus on order acquisition going forward. Nevertheless, we anticipate the adoption of clean coal technology, promotion of nuclear power and continued growth in wind power, solar power and other renewable energy sources as part of efforts to create a low-carbon society over the medium to long term.

Greater priority on emerging markets and environment-friendly businesses

Power system sales totaled ¥882.1bn in 10/3, with the thermal power business accounting for 57%, the nuclear power business 24% and other businesses 19%. The segment incurred losses through 08/3 as a result of unprofitable orders and poor project management, but has been profitable since 09/3 due to subsequent efforts to emphasise profitability in orders and strengthen project management, with the operating margin rising to ~2.5% in 10/3. The company plans to place greater priority on emerging markets with strong growth prospects and on businesses that contribute significantly to the environment. As noted, it targets 16/3 sales of ¥1.2tn and an operating margin of 6%. We expect profitability to gradually improve. Although this segment is


Revenue 8,969 9,300 9,600 9,900

Reported net profit (107) 140 180 210

Normalised net profit (107) 140 180 210

Normalised EPS (¥) (29.2) 31.3 40.2 46.9

Norm. EPS growth (%) - - 0.3 0.2

Norm. P/E (x) - 11.2 8.7 7.5

EV/EBITDA (x) 6.7 5.5 4.9 4.4

Price/book (x) 1.2 1.1 1.0 0.9

Dividend yield (%) 0.0 2.3 2.8 2.8

ROE (%) (9.2) 10.3 11.8 12.4

Net debt/equity (%) 1.8 1.6 1.3 1.1

Earnings revisions

Previous norm. net profit 140 180 210





1m 3m 6m

(13.4) 7.1 47.3

(12.7) 5.5 42.0

(7.1) 13.8 46.8

52-week range (¥)




Mitsubishi UFJ Trust and 5.0


Master Trust Bank of Japan 4.2

418.0/231.0

17,182

Absolute (¥)

Absolute (US$)

Relative to Index

Market cap (US$mn)

210

260

310

360

410

460

Jun

09

Jul

09

Aug

09

Se

p09

Oct

09

No

v09

De

c09

Jan

10

Fe

b10

Mar

10

Ap

r10

Ma

y10

708090100110

120130140

Price

Rel MSCI Japan

Closing price on 23 Jun ¥351.0

Price target ¥500


FY11F net profit (¥bn) 140Difference from consensus naSource: Nomura

Nomura vs consensus Our 12/3 EPS forecast of ¥40.2 is above the QUICK consensus forecast of ¥37.7.

Maintained

BUY


Action Hitachi is restructuring problem businesses while focusing on its social innovation

business. Power system business (ie, thermal and nuclear power; new energy fields) is focusing on emerging markets and environment-friendly regions. A swift move to shareholder return-based management should see ongoing margin improvement. BUY reiterated.

Catalysts We think the share price has been hurt excessively by concerns that the weak euro

and UK fiscal retrenchment will impact Hitachi’s prospects for winning railway projects. Margins looks set to improve sharply on the increased focus on the social innovation business and restructuring and we expect the share price to reflect this.

Anchor themes

The power system business has strong growth potential in a range of fields. Coal-fired thermal power is not seen as environment friendly, but remains a key source of electric power and we expect companies to upgrade to more efficient technology.

Hitachi Masaya Yamasaki


affected by forex risk, we do not anticipate a major impact due to the long-term nature of its operations and progress in localisation, assuming appropriate forex rates.

Thermal power business: expand environmental and gas turbine businesses

The company seeks to expand its thermal power sales from ¥500bn in 10/3 to ¥650bn in 16/3. Coal-fired thermal power seems to have poor growth prospects compared with nuclear power and renewable energy sources, including solar and wind power, but we actually anticipate growth for coal-fired thermal as a core power source. In particular, for highly efficient coal-fired thermal power, the latest commercial systems have a thermal efficiency of 45%, versus the global average for systems in operation of 35%. The company targets 50% or higher in the development of next-generation systems and when this is combined with CO2 recovery technologies, we expect demand to grow. Hitachi operates globally based on the three pillars of Japan, Hitachi Power Europe (accounts for over 40% of sales), and Hitachi Power Systems America.

Nuclear power business: bolster overseas sales outside US

Hitachi aims to expand its nuclear power sales from ¥210bn in 10/3 to ¥380bn in 21/3. It is steadily acquiring new business in Japan and participating in the construction of all advanced boiling water reactors. Hitachi-GE Nuclear Energy is responsible for acquiring orders overseas, but we think that its performance has lagged behind those of other companies. We believe that this reflects the development of a sales structure that focuses on the US in anticipation of market growth driven by the US. As expectations for demand growth in other regions have increased, the company has expanded its joint sales facilities with GE (GE US) and started to actively seek orders. Hitachi targets orders for at least 38 new plants by 2030. This target seems somewhat high and it breaks down into at least 10 plants in North America, at least 10 plants in Asia and the Middle East, five plants in Europe, and under 10 plants in Japan. We think that the company needs to step up efforts in the area of fuels and in the acquisition of equipment orders.

Renewable energy business: expand as system integrator

The company is targeting expansion of its renewable energy sales from ¥60bn in 10/3 to ¥200bn in 16/3. It plans to be active as a system integrator for wind and solar power generation and has already received a complete order for a large solar power plant for an electric power company. Hitachi is also aggressively pursuing smart grid-related operations, including control systems, storage batteries and other technologies for limiting power fluctuations of natural energy sources, high-efficiency and high-performance power conditioners, and micro grid control technologies.

Valuation

We look for a recovery in EPS owing to a shift to focusing on profitability at the net level, and we apply a P/E of 15x, which we consider appropriate for the industrial electronics sector, to our adjusted 12/3 EPS estimate. Our price target is ¥500.

Risks to price target

Risks include execution risk on social infrastructure and other projects, and further yen appreciation.




Hitachi[6501]: consolidated financial data(¥bn, except where noted)

08/3 09/3 10/3 11/3F 12/3F 13/3F11,227 10,000 8,969 9,300 9,600 9,900

% y-y 9.6 -10.9 -10.3 3.7 3.2 3.1

Info. & Telecommunication Systems 1,945 1,706 1,740 1,770 1,800

Power Systems 862 882 885 890 900Social Infrastructure & Industrial Systems 1,334 1,250 1,115 1,150 1,200

Electronic Systems & Equipment 984 999 1,100 1,110 1,090Construction Machinery 725 584 730 750 770

High functional materials & components 1,561 1,249 1,420 1,500 1,600

Automotive Systems 682 639 680 700 720

Components & Devices 978 755 870 950 1,000

Digital media & consumer products 1,104 929 920 900 900

Financial services 401 420 360 380 400

Others 831 764 780 800 820Elimination (1,407) (1,207) (1,300) (1,300) (1,300)

% y-yInfo. & Telecommunication Systems -12.3 2.0 1.7 1.7

Power Systems 2.3 0.3 0.6 1.1Social Infrastructure & Industrial Systems -6.3 -10.8 3.1 4.3

Electronic Systems & Equipment 1.5 10.2 0.9 -1.8Construction Machinery -19.5 25.1 2.7 2.7

High functional materials & components -20.0 13.7 5.6 6.7Automotive Systems -6.3 6.4 2.9 2.9Components & Devices -22.8 15.2 9.2 5.3

Digital media & consumer products -15.8 -1.0 -2.2 0.0Financial services 4.6 -14.2 5.6 5.3

Others -8.1 2.1 2.6 2.5

11,227 10,000 8,969 9,300 9,600 9,900% y-y 9.6 -10.9 -10.3 3.7 3.2 3.1

8,778 7,816 6,849 6,985 7,185 7,386

2,449 2,184 2,119 2,315 2,415 2,514Margin (%) 21.8 21.8 23.6 24.9 25.2 25.4

2,104 2,057 1,917 1,955 1,995 2,034As % of sales 18.7 20.6 21.4 21.0 20.8 20.6

346 127 202 360 420 480% y-y 89.3 -63.2 59.0 78.1 16.7 14.3

Margin (%) 3.1 1.3 2.3 3.9 4.4 4.8

(21) (417) (139) (25) (20) (20)325 (290) 64 335 400 460

% y-y 60.5 - - 5.3x 19.4 15.0Margin (%) 2.9 -2.9 0.7 3.6 4.2 4.6

(58) (787) (107) 140 180 210% y-y - - - - 28.6 16.7

Margin (%) -0.5 -7.9 -1.2 1.5 1.9 2.1

-17.5 -236.9 -29.2 31.3 40.2 46.9145.4 -92.8 91.4 122.9 134.1 143.0

6.0 3.0 0.0 8.0 10.0 10.0

652.9 315.9 287.1 321.9 357.7 400.23,325 3,324 3,663 4,474 4,474 4,474

COGSGross profits

Net nonoperating incomeNet profits before tax

Operating profits

SG&A expenses

Shares out (mn)

Extraordinary gains

BPS (¥)

Sales



DPS (¥)

Net profits

EPS (¥)CFPS (¥)


Note: segmentation has been changed since 09.3




Hitachi[6501]: consolidated financial data(¥bn, except where noted)

08/3 09/3 10/3 11/3F 12/3F 13/3F

5,402 5,065 4,775 4,892 4,973 5,085

Cash & deposits 561 808 578 559 543 559

Accounts receivable 2,530 2,133 2,242 2,325 2,400 2,475Marketable securities 61 9 9 9 9 9

Inventory assets 1,441 1,456 1,222 1,267 1,282 1,296Other 809 659 724 732 739 746

Property, plant and equipment 2,654 2,394 2,220 2,175 2,155 2,135

Investments, other assets 1,043 693 713 713 713 713

Other 1,611 1,700 1,507 1,462 1,442 1,42210,531 9,404 8,952 9,036 9,110 9,2144,753 4,622 3,931 3,928 3,939 3,950

Accounts payable 1,668 1,179 1,255 1,302 1,344 1,386

Short-term interest-bearing debt 1,110 1,530 755 705 655 605Other 1,975 1,913 1,921 1,921 1,940 1,959

2,465 2,602 2,753 2,685 2,587 2,490

Long-term interest-bearing debt 1,422 1,290 1,612 1,562 1,482 1,402

Other 1,043 1,313 1,141 1,123 1,105 1,088

3,313 2,179 2,268 2,423 2,583 2,77410,531 9,404 8,952 9,036 9,110 9,214

3.6 1.6 2.4 4.4 5.0 5.6-2.5 -48.9 -9.2 10.3 11.8 12.4

1.1 1.1 1.0 1.0 1.1 1.10.9 1.9 1.4 1.2 1.0 0.8

20.6 11.2 14.4 15.9 17.6 19.4

Net profits -58 -787 -107 140 180 210Depreciation 541 479 442 410 420 430

Change in working capital -17 -74 129 -82 -48 -47466 -383 464 468 552 593474 422 265 300 330 330

-8 -805 199 168 222 263


Long-term assets

Total assets Current liabilities



ROA (%)

ROE (%)Total capital turnover ratio (x/year)

Net D/E ratio (x)

Free cash flow


Cash flow




Toshiba Corp 6502 JP

TECHNOLOGY | JAPAN

Masaya Yamasaki +81 3 5255 0571 [email protected]

Strengthening integrated nuclear power business

Social infrastructure systems changing from stable to growth business

Toshiba’s growth businesses include storage devices, including NAND flash memory; social infrastructure, mainly nuclear power; and new businesses, including new rechargeable batteries and new lighting. The social infrastructure segment includes the power and industrial system business (including power generation systems and transmission, distribution, and industrial systems), the social infrastructure system business, the elevator business, the medical system business and the IT solutions business. Social infrastructure segment sales fell 3.9% y-y to ¥2,302.9bn in 10/3, but operating profits rose 20.3% to ¥136.3bn, accounting for 116% of the companywide total. The social infrastructure segment has a relatively long business cycle and works through an order backlog. Consequently, earnings tend not to deviate significantly from company forecasts. We expect sales to grow 10.7% y-y to ¥2.55tn and operating profits to expand 10.1% to ¥150bn in 11/3. Social infrastructure systems are transforming from a stable business into a growth business on the expansion of infrastructure investment, and the company has medium-term targets of ¥3.11tn in sales and ¥210bn in operating profits in 13/3.

Power and industrial systems account for 57% of social infrastructure segment

The power and industrial system business, the largest in the social infrastructure segment, had sales of ¥1,303.6bn and operating profits of ¥77.9bn in 10/3. We estimate a sales breakdown at over ¥800bn for power generation systems and under ¥500bn for transmission, distribution, and industrial systems. We estimate nuclear energy business sales at over ¥600bn, and the company targets sales of ¥1tn in 16/3.


Revenue 6,382 7,000 7,500 8,000

Reported net profit (19.7) 100 150 200

Normalised net profit (19.7) 100 150 200

Normalised EPS (¥) (4.9) 23.6 35.4 47.2

Norm. EPS growth (%) - - 0.5 0.3

Norm. P/E (x) - 20.5 13.7 10.3

EV/EBITDA (x) 8.4 6.2 5.1 4.4

Price/book (x) 2.6 2.3 2.0 1.8

Dividend yield (%) 0.0 1.0 1.2 2.1

ROE (%) (3.2) 11.9 16.0 18.5

Net debt/equity (%) 1.7 1.4 1.2 0.9

Earnings revisions






1m 3m 6m

(6.9) 6.8 (6.9)

(6.2) 5.2 (10.3)

(0.6) 13.5 (5.4)

52-week range (¥) 564/322.




Japan Trustee Services 8.0


21,703

Absolute (¥)

Absolute (US$)

Relative to Index

Market cap (US$mn)

Master Trust Bank of Japan 6.5

290

340

390

440

490

540

590

Jun

09

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100

120

140

160

180

Price

Rel MSCI Japan


Price target ¥700


11/3F net profit (¥bn) 100Difference from consensus naSource: Nomura


Price target ¥700



Nomura vs consensus Our 12/3F EPS forecast of ¥35.4 is higher than the QUICK consensus forecast of ¥33.0.

Maintained

BUY


Action Toshiba is emphasising ROI more. Having acquired Westinghouse and positioning

nuclear power as a growth business, it plans to cultivate the BWR and PWR markets. It is strengthening its integrated nuclear power business with moves into various fields and displays strong medium- to long-term growth potential. BUY.

Catalysts Euro weakness hurts PC and TV sales, but profitability is improving in problem

areas due to restructuring. Plans are to spin off mobile phone ops and focus on globally competitive businesses. Focus will be on new businesses (new lighting technology; rechargeable batteries) as well as NAND flash and nuclear power ops.

Anchor themes

We see opportunities in nuclear power in North America and China and also expect growth elsewhere, so attention should focus on projects where the company can win orders. It aims for stable profits from aggressive expansion of its fuel business.

Toshiba Corp Masaya Yamasaki


Aiming for rise in nuclear power orders from 14 now (including unofficial ones) to 39 by 2015

Toshiba and subsidiary Westinghouse Electric have in hand orders for 14 nuclear power plants, including unofficial orders, and are targeting cumulative orders for 39 plants by 2015. Project financing and profitability have been problems in the US, but the Obama administration has decided to provide government loan guarantees, which we believe has alleviated concerns about the order received for a third and fourth unit at the Vogtle nuclear power plant. The company also plans to start plant construction in China and Japan. We think that progress with construction plans in the UK, Finland and Kazakhstan, in addition to the US and China, could increase the company’s chances of winning orders.

Bolstering integrated structure by expanding fuel and service businesses

Responding to the increase in nuclear power demand, Toshiba is working to expand its production capacity as well as its fuel and service businesses. The company has expanded the Isogo Engineering Center, augmented production facilities at Keihin Product Operations, and agreed to establish a turbine equipment joint venture with IHI [7013 JP]. Toshiba is actively working to expand its fuel business, including: the forming of a UK-based uranium supplier, Advance Uranium Asset Management, to strengthen its supply chain; acquiring UK-based fuel supplier Springfields Fuel; concluding a memorandum of understanding with Tenex of Russia to commercialise enriched uranium products; and concluding a memorandum of understanding with Kazatomprom to acquire uranium interests and cooperate in the field of rare metals.

Expanding nuclear energy business in all directions

Toshiba plans to cover the entire range of front-end fuel operations, from uranium mine development and mining rights acquisition to uranium production, enrichment, and fabrication. It plans to enter back-end operations as well, including the reprocessing of spent fuel. We expect these fuel businesses to generate large earnings and make a stable contribution to earnings.

Targeting solar power generation system sales of ¥200bn in 16/3

Toshiba is focusing on solar power generation systems as a new business and targets sales of ¥200bn in 16/3. Although it does not operate a panel business, Toshiba has launched a solar power generation system business based on the strength of its power system construction technologies and power electronics technologies. It has already received orders for three large plants in Japan, comprising the Taketoyo Mega Solar Power Plant of Chubu Electric Power [9502 JP], the Ukishima Solar Power Plant Facility of Tokyo Electric Power [9501 JP], and the Miyako Island Microgrid Verification Test Facility of Okinawa Electric Power [9511 JP]. Overseas, it has informally received a licence in Yambol, Bulgaria. Toshiba is also involved in residential solar power generation systems and had received orders for 10,000 homes as of May 2010. It plans to aggressively expand this business.

Valuation

Our price target of ¥700 is based on fair shareholder value derived from a sum-of-the-parts valuation of operating profits in each segment in three to five years’ time. In addition to Toshiba gaining the lion's share of profits from NAND flash and the long-term growth potential of the nuclear power business, we see solid prospects for the startup of new businesses.

Risks to price target

Risks include yen appreciation against the euro (we estimate a ¥1 change depresses operating profits by ¥3.5bn) and a greater-than-expected decline in NAND flash prices.




Toshiba [6502]: consolidated financial data(¥bn, except where noted)

08/3 09/3 10/3 11/3F 12/3F 13/3F7,668 6,655 6,382 7,000 7,500 8,000

% y-y 7.8 (13.2) (4.1) 9.7 7.1 6.7

Digital products 2,951 2,468 2,364 2,610 2,780 2,960

Electronic device 1,739 1,325 1,309 1,410 1,540 1,670Social infrastructure 2,419 2,396 2,303 2,550 2,770 2,960

Consumer electronics 774 674 580 600 625 650

Others 385 334 316 370 365 370

Elimination (600) (543) (490) (540) (580) (610)

% y-y

Digital products 5.2 (16.4) (4.2) 10.4 6.5 6.5Electronic device 4.9 (23.8) (1.2) 7.7 9.2 8.4Social infrastructure 17.0 (0.9) (3.9) 10.7 8.6 6.9

Consumer electronics 3.2 (12.9) (14.0) 3.5 4.2 4.0Others (1.8) (13.1) (5.5) 17.2 -1.4 1.4

7,668 6,655 6,382 7,000 7,500 8,000

% y-y 7.8 (13.2) -4.1 9.7 7.1 6.7

5,760 5,366 4,922 5,348 5,712 6,0851,908 1,288 1,459 1,652 1,788 1,915

Margin (%) 24.9 19.4 22.9 23.6 23.8 23.91,670 1,539 1,342 1,382 1,438 1,495

As % of sales 21.8 23.1 21.0 19.7 19.2 18.7

238 (250) 117 270 350 420% y-y (7.8) - - 130.4 29.6 20.0

Margin (%) 3.1 (3.8) 1.8 3.9 4.7 5.3

17 (29) (92) (60) (40) (30)256 (279) 25 210 310 390

% y-y (14.4) - - 8.4x 47.6 25.8

Margin (%) 3.3 (4.2) 0.4 3.0 4.1 4.9

127 (344) (20) 100 150 200

% y-y (7.3) - - - 50.0 33.3

Margin (%) 1.7 (5.2) (0.3) 1.4 2.0 2.5

39.5 (106.2) (4.9) 23.6 35.4 47.2157.2 1.9 69.7 89.0 106.2 120.412.0 5.0 0.0 5.0 6.0 10.0

315.9 138.3 188.3 206.9 236.3 273.53,229.1 3,235.8 4,004.8 4,235.4 4,235.4 4,235.4

DPS (¥)

Net profits

EPS (¥)

CFPS (¥)


Sales



COGS

Gross profits

Net nonoperating incomeOperating profits before tax

Operating profits

SG&A expenses

Shares out (mn)

Extraordinary gains

BPS (¥)




Toshiba [6502]: consolidated financial data(¥bn, except where noted)

08/3 09/3 10/3 11/3F 12/3F 13/3F

2,929 2,721 2,762 2,889 3,031 3,194

Cash & deposits 249 344 267 263 249 257

Accounts receivable 1,312 1,083 1,184 1,260 1,350 1,440Inventory assets 851 758 796 847 907 967

Other 517 535 514 519 524 530

3,006 2,733 2,690 2,744 2,849 2,945

Property, plant and equipment 1,332 1,090 979 1,022 1,122 1,212

Investments 593 535 623 635 642 648

Other 1,081 1,108 1,088 1,087 1,086 1,0855,936 5,453 5,451 5,634 5,880 6,139

2,986 3,068 2,488 2,625 2,739 2,844

Accounts payable 1,224 1,004 1,192 1,307 1,401 1,494Short-term interest-bearing debt 520 1,034 257 257 257 257

Other 1,241 1,030 1,039 1,060 1,081 1,092

1,557 1,626 1,835 1,802 1,810 1,807

Long-term interest-bearing debt 923 907 1,109 1,069 1,069 1,059

Other 635 719 726 733 740 7481,392 759 1,128 1,206 1,331 1,489

5,936 5,453 5,451 5,634 5,880 6,1394.5 (4.2) 2.3 5.0 6.1 7.0

12.5 (76.8) (2.5) 11.4 15.0 17.31.3 1.2 1.2 1.2 1.3 1.3

0.9 2.1 1.0 0.9 0.8 0.723.5 13.9 20.7 21.4 22.6 24.2

Net profits 127 (344) (20) 100 150 200Depreciation 380 350 299 277 300 310

Change in working capital (151) 65 43 (11) (57) (57)357 71 322 366 393 453619 425 210 320 400 400

(262) (354) 112 46 (7) 53Free cash flow


Cash flow


ROA (%)ROE (%)

Total capital turnover ratio (x/year)Net D/E ratio (x)

Current liabilities




Long-term assets

Total assets



Ulvac Inc 6728 JP

TECHNOLOGY | JAPAN

Tetsuya Wadaki +81 3 5255 1797 [email protected]

Recovery at existing operations, bottoming solar cell equipment

Ulvac secured higher profits than it expected in 10/6 Q3

In 10/6 Q3, sales reached ¥58.1bn (up 49.4% y-y), operating profits were ¥2.2bn (vs a loss of ¥2.6bn a year earlier), recurring profits hit ¥2.4bn (vs loss of ¥3.1bn), and net profits were ¥2.5bn (vs loss of ¥1.3bn). Sales and orders were slightly short of company estimates, reflecting the delay of some FPD production equipment sales and solar cell production equipment orders to Q4 FY10. However, operating profits were slightly better than expected thanks to efficiency gains.

Strong operating climate for core businesses

The market environment has continued to improve. Ulvac is also in negotiations with manufacturers in Korea and China for production equipment for LTPS TFTs and OLEDs, seen as likely drivers for medium-term earnings. In its best-case scenario, management thinks that these two could be ¥10bn businesses in two or three years' time. We also have seen signs of a pick-up in inquiries for the company's solar cell production equipment, which had been faring poorly. Ulvac has been fielding inquiries for its well-received production equipment for tandem thin-film silicon solar cells. Some customers that use its systems have moved to full-scale production of these solar cells. The company has even won orders from customers in Europe, where rival manufacturers are based. We see this as evidence of an improvement in the competitiveness of Ulvac’s products.

Expectations looking ahead to 11/6

Heading toward 11/6, we expect a modest rise in orders and sales of FPD production equipment, flat orders for solar cell production equipment or perhaps a slight decline, and a sharp rise in orders and sales of SPE. It looks as though Ulvac has increased its share of the


Revenue 223,825 246,500 279,000 320,700

Reported net profit 811 3,000 6,100 8,400

Normalised net profit 811 3,000 6,100 8,400

Normalised EPS (¥) 18.9 65.2 123.8 170.5

Norm. EPS growth (%) - - - -

Norm. P/E (x) - 29.0 15.3 11.1

EV/EBITDA (x) - 8.9 8.4

Price/book (x) - 0.8 0.9 0.8

Dividend yield (%) 0.0 0.0 0.0 0.0

ROE (%) 1.0 2.9 5.6 7.3

Net debt/equity (%) 0.0 0.0 0.0 0.0

Earnings revisions






1m 3m 6m

(0.9) (17.6) (15.1)

(0.1) (18.8) (18.2)

5.5 (10.5) (13.3)

52-week range (¥)




Nippon Life Insurance 7.3


2,830/1,815

Taiyo Fund Management 7.2

Absolute (¥)

Absolute (US$)

Relative to Index


1,700

1,900

2,100

2,300

2,500

2,700

2,900

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80

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100

110

Price

Rel MSCI Japan




10/6F net profit (¥mn) 3,000Difference from consensus naSource: Nomura




10/6F net profit (¥mn) 3,000Difference from consensus naSource: Nomura

Nomura vs consensus Earnings remain healthy, backed by a recovery in semiconductor production equipment (SPE) and FPD capex. We maintain our bullish view of the company.

Maintained

BUY


Action Orders have been recovering for mainstay FPD production equipment and SPE. PV

production equipment demand may be in a rut, but we expect a rise in orders for tandem thin-film, CIGS and crystalline PVs, as well as a resumption of investment in China. We see signs of Ulvac increasing its share of the SPE market in Korea. BUY reaffirmed.

Catalysts We expect strong medium-term growth thanks to equipment for environmentally

friendly products, such as solar cells. If this growth potential is recognised, it should be valued more highly than SPE, which is in a medium-term contractionary cycle.

Anchor themes

We see signs of an SPE order recovery. With Korean and Japanese makers stepping up capex, we expect orders to recover without another major bottom. We expect Taiwanese memory makers to lift capex in H2 2010. Our medium-term focus is on low-cost production technologies and LED and solar cell equipment.

Ulvac Inc Tetsuya Wadaki


Korean market for semiconductor sputtering equipment, possibly owing to competitors’ missteps. We also think that LED production equipment orders could double y-y to ¥5.0bn in 10/6. Ulvac's earnings recovery has been helped by a pick-up in the semiconductor and LCD production equipment markets, and we have also seen signs of recovery and growth in environment-related businesses. That said, recovery momentum is slower than at other sector companies, likely reflecting the diversity of Ulvac’s businesses and its use of work-in-progress accounting.

Valuation

We expect strong medium-term growth to be driven by production equipment for environmentally friendly products such as solar cells, and we therefore use a different P/E ratio than for makers of semiconductor production equipment, the market for which has entered a medium-term cyclical contraction. For 13/6, when we expect the next peak in earnings, we estimate EPS of ¥205.1, to which we apply a peak P/E of 19x, extrapolated from historical trends. This yields our target price of ¥3,896.

Risks to our price target

Risks include a failure for silicon thin-film solar cells to regain competitiveness over the medium term, and weak LCD capex owing to oversupply of flat-panel TVs.




Ulvac [6728]: consolidated financial data(¥mn, except where noted)

07/6 08/6 09/6 10/6F 11/6F 12/6F 13/6F

239,151 241,212 223,825 246,500 279,000 320,700 350,200

% y-y 12.6 0.9 -7.2 10.1 13.2 14.9 9.2

206,648 200,461 178,325 200,000 230,000 269,700 297,200

% y-y 14.1 -3.0 -11.0 12.2 15.0 17.3 10.2

120,633 127,174 128,353 142,000 161,000 183,700 210,200

% y-y 9.6 5.4 0.9 10.6 13.4 14.1 14.4

86,832 89,040 72,353 95,000 114,000 129,700 142,700

% y-y -12.3 2.5 -18.7 31.3 20.0 13.8 10.0

2,400 11,400 40,000 47,000 47,000 54,000 67,500

% y-y 475.0 250.9 17.5 0.0 14.9 25.0

38,184 32,043 14,150 24,000 31,000 45,000 45,000

% y-y 36.9 -16.1 -55.8 69.6 29.2 45.2 0.0

27,111 23,041 21,321 20,000 23,000 25,000 25,000

% y-y -1.7 -15.0 -7.5 -6.2 15.0 8.7 0.0

20,720 18,203 14,500 14,000 15,000 16,000 17,000

% y-y 32.4 -12.1 -20.3 -3.4 7.1 6.7 6.3

32,503 40,752 45,500 46,500 49,000 51,000 53,000

% y-y 3.8 25.4 11.7 2.2 5.4 4.1 3.9

192,700 195,092 184,134 202,100 225,400 259,700 282,600

COGS ratio (%) 80.6 80.9 82.3 82.0 80.8 81.0 80.7

46,451 46,120 39,691 44,400 53,600 61,000 67,600

Margin (%) 19.4 19.1 17.7 18.0 19.2 19.0 19.3

29,826 37,040 36,208 36,100 40,000 43,400 47,100

SG&A expense ratio (%) 12.5 15.4 16.2 14.6 14.3 13.5 13.4

16,625 9,081 3,483 8,300 13,600 17,600 20,500

% y-y 12.4 -45.4 -61.6 138.3 63.9 29.4 16.5

Margin (%) 7.0 3.8 1.6 3.4 4.9 5.5 5.9

14,663 8,377 7,138 11,311 16,772 21,507 24,324

% y-y 23.4 -42.9 -14.8 58.5 48.3 28.2 13.1

Margin (%) 7.1 4.2 4.0 5.7 7.3 8.0 8.2

8,182 5,769 8,931 12,941 16,795 18,050 20,895

% y-y 21.1 -29.5 54.8 44.9 29.8 7.5 15.8

Margin (%) 6.8 4.5 7.0 9.1 10.4 9.8 9.9

3,810 3,047 (1,401) (1,310) (550) 2,022 1,933

% y-y 98.1 -20.0 - - - - -4.4

Margin (%) 10.0 9.5 -9.9 -5.5 -1.8 4.5 4.3

1,953 (342) (185) (372) 255 622 122

% y-y -24.5 - - - - 144.3 -80.3

Margin (%) 7.2 -1.5 -0.9 -1.9 1.1 2.5 0.5

718 (98) (208) 52 272 813 1,374

% y-y 16.8 - - - 428.5 198.6 69.0

Margin (%) 3.5 -0.5 -1.4 0.4 1.8 5.1 8.1

1,567 (135) (4,168) (3,524) (3,685) (4,420) (4,337)

% y-y -44.6 - - - - - -

Margin (%) 4.8 -0.3 -9.2 -7.6 -7.5 -8.7 -8.2

396 839 513 513 513 513 513

% y-y 365.9 111.9 -38.9 0.0 0.0 0.0 0.0

Margin (%) 491.5 1,037.3 623.6

(520) (4,006) (2,648) (2,500) (2,700) (2,900) (3,100)

(610) (893) (1,142) (1,500) (1,700) (1,900) (2,100)

90 (3,113) (1,506) (1,000) (1,000) (1,000) (1,000)

16,105 5,075 835 5,800 10,900 14,700 17,400

% y-y 9.0 -68.5 -83.5 594.6 87.9 34.9 18.4

Margin (%) 6.7 2.1 0.4 2.4 3.9 4.6 5.0

(2,478) 1,375 (2,435) (1,000) (1,000) (1,000) (1,000)

402 3,115 214

2,880 1,740 2,649

13,627 6,451 (1,600) 4,800 9,900 13,700 16,400

% y-y -7.6 -52.7 - - 106.3 38.4 19.7

Margin (%) 5.7 2.7 -0.7 1.9 3.5 4.3 4.7

7,307 2,953 1,561 1,800 3,800 5,200 6,200

1,148 0 2,829 0 0 0 0

45.2 45.8 79.3 37.5 38.4 38.0 37.8

133 (112) (1,142) 0 0 100 100

7,335 3,610 811 3,000 6,100 8,400 10,100

% y-y -9.5 -50.8 -77.5 269.9 103.3 37.7 20.2

Margin (%) 3.1 1.5 0.4 1.2 2.2 2.6 2.9

7,980 10,932 12,320 12,200 12,500 12,800 13,100

32,109 23,382 19,567 19,000 19,000 19,000 19,000

171.0 84.2 18.9 65.2 123.8 170.5 205.1

2,105 2,052 1,961 2,277 2,213 2,330 2,470

47 21 21 21 39 54 65

Sales

Income statement

Components

Semiconductor production equipment

Display and electronic component product

Vacuum-related

By segment

FPD production equipment

of which, Solar cell production equip

Gross profits

COGS

Industrial equipment

Vacuum application

D isplay and electronic component production equip

Semiconductor production equipment

Components

Industrial equipment

Operating profits

SG&A expenses

By segment

Vacuum equipment

Vacuum application

Adjustment to tax (subtract)

Corporation tax, etc

Pretax profits


Extraordinary gains

Extraordinary gains/losses

Recurr ing profits

Other net nonoperating income

Net interest income

Internal eliminations/companywide

Tax rate (%)

DPS (¥)

Depreciation

Capex

EPS (¥)

BPS (¥)

Net profits

Minority interest

Net nonoperating income




Ulvac [6728]: consolidated financial data (continued)(¥mn)

07/6 08/6 09/6 10/6F 11/6F 12/6F 13/6F

207,876 186,578 199,307 228,731 252,911 280,151 306,64911,889 17,603 22,985 41,738 41,918 39,158 44,656

87,399 76,193 77,430 85,000 96,000 110,000 120,0000 0 0 0 0 0 0

96,561 81,728 86,219 95,000 108,000 124,000 135,0004,723 4,711 5,6957,558 6,517 7,293 7,293 7,293 7,293 7,293

(253) (175) (315) (300) (300) (300) (300)109,701 116,491 118,769 125,173 131,673 137,873 143,773

81,822 93,799 96,545 103,345 109,845 116,045 121,9453,811 3,838 3,828 3,828 3,828 3,828 3,828

24,068 18,854 18,396 18,000 18,000 18,000 18,000317,577 303,069 318,076 353,904 384,584 418,024 450,422169,467 150,771 151,753 170,491 196,991 224,691 250,191

Accounts payable 72,099 63,873 38,763 43,000 49,000 56,000 61,000

Short-term interest-bearing debt 43,715 42,588 82,091 97,091 117,091 137,091 157,091

Other current liabilities 53,653 44,310 30,899 30,400 30,900 31,600 32,10053,745 60,445 76,165 76,449 76,449 76,449 76,449

Long-term interest-bearing debt 40,626 44,115 54,049 54,049 54,049 54,049 54,049

Other long-term liabilities 13,119 16,330 22,116 22,400 22,400 22,400 22,400

223,212 211,216 227,918 246,940 273,440 301,140 326,64086,111 87,477 87,981 104,824 109,004 114,744 121,642

Legal capital 13,468 13,468 13,468 20,873 20,873 20,873 20,873Legal capital surplus 14,695 14,695 14,695 22,100 22,100 22,100 22,100

Other retained earnings 57,948 59,313 59,818 61,851 66,031 71,771 78,669

4,208 567 (3,860) (3,860) (3,860) (3,860) (3,860)0 0 0 0 0 0 0

4,047 3,810 6,036 6,000 6,000 6,000 6,00094,365 91,854 90,158 106,964 111,144 116,884 123,782

317,577 303,069 318,076 353,904 384,584 418,024 450,422

Balance sheet

Total assets

Other

Reserve for bad loans

Property, plant & equipment

Total liabilities and net assets

Current assets

Long-term assets

Total liabilities

Intangible long-term assets

Net assets

Cash & deposits Accounts receivable

Inventories

Deferred tax assets

New stock rightsMinority interests

Marketable securities

Investments & other assets

Current liabilities


Owners' equity

Accumulated other comprehensive income




Ulvac [6728]: consolidated financial data (continued)(¥mn)

07/6 08/6 09/6 10/6F 11/6F 12/6F 13/6F

1,131 32,068 (31,891) 24,812 146 (1,839) 7,15813,627 6,451 (1,600) 4,800 9,900 13,700 16,4007,980 10,932 12,320 12,200 12,500 12,800 13,100

982 1,446 1,023 329 0 0 0Increase in bad-debt reserves 212 (81) 288 15 0 0 0Increase in retirement benefit reserves 1,084 1,123 1,222 264 0 0 0

Increase in directors' retirement bonus reserves (391) 64 98 9 0 0 0Increase in warranty reserves 77 340 (585) 41 0 0 0

(2,837) 10,089 2,463 (7,570) (11,000) (14,000) (10,000)(18,739) 10,607 (16,105) (8,781) (13,000) (16,000) (11,000)

2,687 (8,082) (24,280) 4,237 6,000 7,000 5,000(2,569) 625 (5,712) 19,597 (4,254) (5,339) (6,342)

Losses on disposal of long-term assets 533 522 1,098Equity in net income of affiliates 560 (36) (14) 0 0 0 0Corporation tax paid (8,413) (6,808) (2,399) (1,561) (1,800) (3,800) (5,200)Interest & dividends received 383 417 259Interest payable (905) (1,333) (1,406) (1,500) (1,700) (1,900) (2,100)Other 5,273 7,863 (3,250) 22,658 (754) 361 958

(26,850) (25,944) (14,051) (19,000) (19,000) (19,000) (19,000)(2,125) (20) 20 0 0 0 0

Income from sale of investment securities 23 462 32Acquisition of investment securities (2,122) (440) (12)Spending on loans (253) (289) 0Income from the recovery of loans 227 247 0

(27,809) (27,241) (14,696) (19,000) (19,000) (19,000) (19,000)2,965 1,948 2,470

119 (631) (1,845)23,404 (1,750) 51,325 14,099 19,033 18,079 17,3407,435 (446) 32,770 15,000 20,000 20,000 20,000

17,614 689 13,061 0 0 0 0Income from issuing bonds 15,500 0 0Spending on redemption of bonds 0 0Net change in CP (4,000) (1,000)Revenues from long-term borrowings 14,222 17,416 28,140Spending on repayment of long-term loans (12,108) (12,727) (14,079)

(1,645) (1,993) 5,494 (901) (967) (1,921) (2,660)Share buybacks 0Income from issung shares 0Dividend payments (1,587) (2,016) (901) (901) (967) (1,921) (2,660)Payments to minority shareholders (58) (46) (26)Other 0 69 6,421

658 (526) (604)(1,322) 3,849 4,779 19,911 179 (2,760) 5,49910,515 11,664 16,977 21,827 41,738 41,918 39,1582,472 1,464 71

11,664 16,977 21,827 41,738 41,918 39,158 44,656

Cash flowOperating cash flow

Pretax profitsDepreciationIncrease in bad-debt and other reserves

Change in accounts receivableChange in inventory assetsChange in accounts payableOther

Investment cash flowChange in investment securities, etc

Expenditure on acquiring long-term assetsIncome from sale of long-term assetsOther

Financial cash flowChange in short-term borrowings

Cash & equivalents at FY-startChange due to change in scope of consolidationCash & equivalents at FY-end

Change in bonds and long-term borrowings

Other

Foreign currency translation difference in cash & equivalentsChange in cash & equivalents



Mitsubishi Heavy Industries 7011 JP

TECHNOLOGY | JAPAN

Shigeki Okazaki +81 3 5255 1719 [email protected]

Need to secure margins We expect improved operating profits from 11/3

For 11/3, we forecast a 39% y-y rise in operating profits to ¥91.0bn, driven by a rebound in product demand and cost reductions for economy-sensitive products. Such products include printing machinery (part of machinery & steel structures in the new segment classification), general machinery and special vehicles (the GM & SV segment), which include fork lifts and automotive turbo chargers, and air conditioning & refrigeration systems (the air-con segment). Our 11/3 operating profit forecast is higher than the company’s projection, reflecting management’s more cautious cost reduction, mainly at the shipbuilding and power system businesses.

Recovery in power system orders is likely, but margins are below pre-financial crisis levels

We expect orders at the mainstay power system segment to return to growth in 11/3. The company appears to have started attracting inquiries for projects that could turn into orders in 11/3, including desalination plants and gas turbines for emerging economies. US subsidies for wind power systems are ending in 2010, and we expect a related rush in demand. That said, demand remains lower than before the 2008 financial crisis, and with order margins also below pre-crisis levels because of yen appreciation, we think the segment is unlikely to contribute to overall profit growth until 12/3. Meanwhile, in the aerospace segment, yen appreciation is a negative, but we think that 11/3 losses will be in line with those in 10/3 as one-time development costs for the Mitsubishi Regional Jet project decline and the company cuts costs on production of parts for the Boeing 777. Despite a forecast y-y increase in Mitsubishi Regional Jet development costs again in 12/3, we look for operating losses at the segment to narrow next fiscal year on expected improved earnings from parts for the Boeing 787.


Revenue 2,940.9 2,900.0 3,024.0 3,062.0



Normalised EPS (¥) 4.20 9.10 13.40 16.40

Norm. EPS growth (%) (41.7) 116.7 47.3 22.4

Norm. P/E (x) 77.1 35.6 24.2 19.8

EV/EBITDA (x) 11.2 9.9 9.1 8.7

Price/book (x) 0.8 0.8 0.8 0.8

Dividend yield (%) 1.2 1.9 1.9 1.9

ROE (%) 1.1 2.3 3.3 3.9

Net debt/equity (%) 0.9 0.9 0.9 0.9

Earnings revisions

Previous norm. net profit 14.2 30.6 45.0 55.2

Change from previous (%) - - - -

Previous norm. EPS (¥) 4.2 9.1 13.4 16.4



1m 3m 6m

(0.3) (11.5) 0.9

(0.9) (11.2) 2.8

(0.0) (3.6) 4.3

52-week range (¥)




401.0/274.0


Japan Trustee Serv ices Bank, Ltd 4.5

12,130

Absolute (¥)

Absolute (US$)

Relative to Index

Market cap (US$mn)

260280300320340360380400420

Jun

09

Jul

09

Au

g0

9

Sep

09

Oc

t09

No

v09

De

c09

Jan

10

Feb

10

Ma

r10

Apr

10

Ma

y10

707580859095100

105

Price

Rel MSCI Japan


Price target ¥360



Nomura vs consensus The QUICK consensus operating profit forecast for 11/3 is ¥79.9bn, while our projection is higher at ¥91.0bn.

Maintained

NEUTRAL


Action We expect operating profit improvement from 11/3 as Mitsubishi Heavy Industries

(MHI) cuts printing and general machinery costs, but look for operating losses at these businesses. For us to turn more bullish, the company needs to improve earnings by shifting production for low-margin projects overseas. NEUTRAL.

Catalysts We forecast global demand growth for nuclear power plants. Order wins could be a

catalyst for the shares. One issue, however, is securing margins by enhancing project management on construction overseas. We think MHI needs to work with US partner UPS [UPS US].

Anchor themes

Like many of its peers, MHI is susceptible to yen appreciation and needs a strategy that would make it more resistant to FX fluctuations, such as increasing overseas production and / or boosting margins by cutting costs on low-margin projects.

Mitsubishi Heavy Industries Shigeki Okazaki


Medium-term plan looks slightly ambitious

We think the medium-term business plan released along with 10/3 results – calling for 13/3 operating profits to reach ¥160bn and grow to ¥250bn in 15/3 – is slightly ambitious in terms of its profit figures for the power system and air-con segments. However, the company should push forward with the move away from a vertically integrated structure, in our view, and increase its overseas production, as detailed in the medium-term plan. We will monitor developments.

Order expectations for nuclear power plant

In May 2010, MHI won an order from US electric power company Dominion Resources [D US] for a US-APWR reactor – its third order won in the US market. Dominion Resources probably will carry out safety and reliability checks up until the plant is commissioned. We also expect MHI to win orders from customers in Jordan and for its ATMEA1 medium-sized reactor (1.1GW) being jointly developed with France’s Areva [CEI FP].

Valuation

Based on historical trends, we apply a P/BV of 0.9x to our forward (end-11/3) BPS estimate to derive our price target of ¥360.

Risks to our price target. Risks include yen appreciation against the US dollar or euro and an economic downturn in emerging markets.




Mitsubishi Heavy Industries [7011]: sector breakdown of financial data(¥mn, except where noted)

11/3F 13/3F 15/3F

2,476,200 2,965,000 3,240,000 3,520,000 3,100,000 3,800,000 4,400,000

150,800 150,000 170,000 200,000 190,000 230,000 230,000

982,200 1,130,000 1,230,000 1,400,000 1,230,000 1,680,000 1,920,000

404,300 520,000 600,000 650,000 570,000 640,000 810,000

435,500 600,000 600,000 600,000 600,000 510,000 590,000

291,000 330,000 380,000 400,000 300,000 450,000 520,000

138,400 145,000 160,000 160,000 140,000 200,000 240,000

113,400 140,000 150,000 160,000 120,000 150,000 160,000

(39,400) (50,000) (50,000) (50,000) (50,000) (60,000) (70,000)

2,940,887 2,900,000 3,024,000 3,062,000 2,850,000 3,400,000 4,100,000

230,600 270,000 270,000 220,000 270,000 220,000 210,000

1,066,100 1,050,300 1,037,500 1,068,600 1,050,000 1,350,000 1,700,000

625,700 550,000 582,000 604,000 550,000 600,000 730,000

500,200 465,000 494,900 499,600 460,000 500,000 650,000

286,800 330,000 380,000 400,000 310,000 450,000 520,000

137,400 145,000 160,000 160,000 140,000 200,000 240,000

146,800 140,000 150,000 160,000 120,000 130,000 140,000

(52,800) (50,300) (50,400) (50,200) (50,000) (50,000) (90,000)

65,660 91,000 114,000 130,000 75,000 160,000 250,000 3,600

14,544 13,200 12,200 5,200 8,000 5,000 7,000 900

82,603 77,900 74,500 79,700 70,000 95,000 125,000 700

3,000 18,000 23,700 28,400 18,000 32,000 40,000 300

(6,424) (6,000) (3,600) 1,400 (10,000) 0 17,000 1,300

(23,200) (12,400) (2,400) 1,600 (11,000) 13,000 35,000 400

(9,900) (6,600) (100) 1,400 (6,000) 4,000 11,000 0

5,100 7,100 10,100 13,100 6,000 11,000 15,000 0

(63) (200) (400) (800) 0 0 0 0

2.2 3.1 3.8 4.2 2.6 4.7 6.1

6.3 4.9 4.5 2.4 3.0 2.3 3.3

7.7 7.4 7.2 7.5 6.7 7.0 7.4

0.5 3.3 4.1 4.7 3.3 5.3 5.5

(1.3) (1.3) (0.7) 0.3 (2.2) 0.0 2.6

(8.1) (3.8) (0.6) 0.4 (3.5) 2.9 6.7

(7.2) (4.6) (0.1) 0.9 (4.3) 2.0 4.6

3.5 5.1 6.7 8.2 5.0 8.5 10.7

0.1 0.4 0.8 1.6 0.0 0.0 0.0

(41,651) (40,000) (39,000) (38,000) (40,000) (50,000) (50,000)

(419) (7,000) (7,000) (7,000)

(2,074) (500) (1,300) (1,300)

of which, Mitsubishi Motors 700 2,300 1,500 1,500

(39,158) (32,500) (30,700) (29,700)

24,009 51,000 75,000 92,000 35,000 110,000 200,000

14,163 30,600 45,000 55,200

4.2 9.1 13.4 16.4

95 90 90 90 90 90 90

129 120 120 120 130 - -

3,806,200 3,871,200 4,087,200 4,545,200

574,800 454,800 354,800 334,800

1,747,400 1,827,100 2,019,600 2,351,000

589,100 559,100 577,100 623,100

795,900 930,900 1,036,000 1,136,400

41,600 41,600 41,600 41,600

16,200 16,200 16,200 16,200

18,400 18,400 18,400 18,400

22,800 23,100 23,500 23,700

Full-yearforex

sensitivi ty

Co's

10/3 11/3F 12/3F 13/3F

GM & SV

Machine tools, other

Operating margin (companywide, %)

Aerospace


Reconciliations


Reconciliations

Shipbuilding & ocean development

Power systems

Machinery & steel structures

Aerospace

Total orders

Reconciliations

Sales

GM & SV

Air-con



Power systems


Aerospace


Power systems


Aerospace

EPS (¥)

$/¥ assumptions

€/¥ assumptions

Order backlog total


Power systems


Aerospace

Reconciliations

Air-con


GM & SV

Air-con


Reconciliations

Operating profits


Power systems

GM & SV

Air-con

GM & SV

Air-con

Equity in earnings of affi liates

Other nonoperating items

Recurring profits

Net profits

Nonoperating income

Foreign exchange gains/losses

Note: Business segments revised from 11/3. Printing machinery and industrial machinery moved from former industrial machinery business to machinery & steel structures segment, machine tools moved from former industrial machinery business to others segment. Exchange rate sensitivity is degree to which ¥1 rise in the value of the yen against the US dollar dents 11/3 operating profits. Every ¥1 rise in the value of the yen against the euro dents 11/3 operating profits by around ¥500mn over the full year. Main products at machinery & steel structures segment are: chemical plants (sales of ¥115bn in 10/3), steelmaking equipment (we estimate ¥95bn), plant compressors (¥48bn), public transit systems (¥47bn), paper printing machinery, expressway toll systems and waste disposal plants. MHI announced the following numerical targets in its 2010 medium-term business plan released in April 2010: ROE of 5% in 13/3 and 8% in 15/3; ROIC of 3% and 8%; D/E ratio of 0.9x and 0.8x; interest-bearing debt of ¥1.3trn and ¥1.2trn; and DPS of ¥6 and ¥10.




Mitsubishi Heavy Industries [7011]: factors behind y-y changes in operating profits (1)(¥bn, except where noted)

08/3 09/3 10/3 11/3F 12/3F 13/3F

11/3FCo's

3,715.2 3,268.7 2,476.2 2,965.0 3,240.0 3,520.0 3,100.03,203.1 3,375.7 2,940.9 2,900.0 3,024.0 3,062.0 2,850.0

136.0 105.9 65.7 91.0 114.0 130.0 75.0+27.1 -30.1 -40.2 +25.3 -2.0 +3.2 +9.3

+2.5 -48.2 -47.1 -20.0 +0.0 +0.0 -23.5+8.0 +38.0 -20.0 +0.4 -0.0 +4.7 -0.5

-14.0 -25.0 -8.0 +5.5 -6.0 +0.0 +6.0+30.6 +5.1 +34.9 +8.6 +4.0 -1.5 +27.3-21.2 -3.8 -6.3 +1.5 -5.0 +0.5 +0.0

+51.8 +8.9 +41.2 +7.1 +9.0 -2.0 +27.3Margins +34.7 +27.7 +7.1 +9.0 -2.0Cumulative effect of accounting changes -25.8 +13.5 +0.0 +0.0 +0.0

353.6 271.3 150.8 150.0 170.0 200.0 190.0

283.9 240.1 230.6 270.0 270.0 220.0 270.04.1 1.6 14.5 13.2 12.2 5.2 8.0

+9.5 -2.5 +12.9 -1.3 -1.0 -7.0 -6.5

+0.8 -8.4 -5.2 -6.3 +0.0 +0.0 -7.0+0.0 +0.0 +0.0 +2.0 +0.0 +0.0 +2.0

-3.5 -3.5 -7.0 +6.0 -4.0 +0.0 +6.0+12.2 +9.4 +25.1 -3.0 +3.0 -7.0 -7.5

-2.8 +0.0 +0.2 +0.0 +0.0 +0.0 +0.0+15.0 +9.4 +24.9 -3.0 +3.0 -7.0 -7.5

Margins +10.5 +23.8 -3.0 +3.0 -7.0Cumulative effect of accounting changes -1.1 +1.1 +0.0 +0.0 +0.0

1,214.9 1,148.8 982.2 1,130.0 1,230.0 1,400.0 1,230.0

946.9 1,209.1 1,066.1 1,050.3 1,037.5 1,068.6 1,050.058.3 80.0 82.6 77.9 74.5 79.7 70.0

+1.5 +21.7 +2.6 -4.7 -3.4 +5.2 -12.6-1.1 -13.1 -10.3 -8.7 +0.0 +0.0 -9.5

+5.5 +43.0 -13.0 +0.0 -1.9 +4.7 +0.0-3.0 -8.5 -0.5 +0.0 -2.0 +0.0 +0.0+0.1 +0.3 +26.4 +4.0 +0.5 +0.5 -3.1

-8.1 -3.0 -0.6 -5.0 -1.5 -1.5 -5.0+8.2 +3.3 +27.0 +9.0 +2.0 +2.0 +1.9

Margins +0.5 +29.8 +9.0 +2.0 +2.0Cumulative effect of accounting changes +2.8 -2.8 +0.0 +0.0 +0.0

All-company orders

Margins, R&D expenses, etc

R&D expenses

Forex impactImpact of change in sales

All-company salesAll-company operating profitsChange in profits (y-y)

Materials

Impact of change in sales


R&D expensesMargins

Forex impact

Impact of change in sales

Change in profits (y-y)Forex impact

MaterialsMargins, R&D expenses, etc

(2) Power systems sales

Power systems operating profits

Margins

(1) Shipbuilding & ocean development salesShipbuilding & ocean development operating profitsChange in profits (y-y)

(1) Shipbuilding & ocean development orders

(2) Power systems orders

Materials

R&D expenses

Margins

Note: All bookings and drawdowns of loss reserves (for forex and steel products) are included in the item marked "margins" under factors affecting profits. We estimate MHI uses 300,000–400,000tpy of thick steel plate for ships. We calculate that a ¥10,000/t price increase pushes costs ¥3–4bn higher per year. The company made roughly ¥7.3bn in loss provisions at the shipbuilding & ocean development segment in 09/3.




Mitsubishi Heavy Industries [7011]: factors behind y-y changes in operating profits (1) (continued)(¥bn, except where noted)

08/3 09/3 10/3 11/3F 12/3F 13/3F11/3FCo's

557.3 527.8 323.8472.5 542.2 542.0

11.3 31.6 30.1+8.4 +20.3 -1.5-0.3 -2.4 -9.1-4.0 +5.5 +2.0-0.5 -3.0 -0.5

+13.2 +20.2 +6.1-1.8 -1.3 -1.2

+15.0 +21.5 +7.3Margins +22.1 +6.7Cumulative effect of accounting changes -0.6 +0.6

404.3 520.0 600.0 650.0 570.0625.7 550.0 582.0 604.0 550.0542.0 470.0 500.0 520.0 470.083.7 80.0 82.0 84.0 80.0

3.0 18.0 23.7 28.4 18.030.1 33.0 34.0 35.0 30.0

-27.1 -15.0 -10.3 -6.6 -12.0+15.0 +5.7 +4.7 +15.0

-1.0 -1.0 -1.0 -1.0-9.0 +3.2 +2.2 -9.0+0.0 -2.0 +0.0 +0.0

+25.0 +5.5 +3.5 +25.0-1.5 -1.5 -1.5 -1.5

+26.5 +7.0 +5.0 +26.5615.8 510.8 435.5 600.0 600.0 600.0 600.0500.5 512.3 500.2 465.0 494.9 499.6 460.0

14.7 -10.3 -6.4 -6.0 -3.6 1.4 -10.00.0 -6.5 -15.0 -8.5 -12.0 -10.0 -8.5

14.7 -3.8 8.6 2.5 8.4 11.4 -1.5+0.3 -25.0 +3.9 +0.4 +2.4 +5.0 -3.6-1.4 -13.8 -9.8 -5.0 +0.0 +0.0 -5.0+0.5 +1.0 +0.0 -1.7 +1.9 +0.0 +0.0-0.5 +0.0 +0.0 -0.5 +0.0 +0.0 +0.0+1.7 -12.2 +13.7 +7.6 +0.5 +5.0 +1.4-4.5 -0.1 -7.7 +6.5 -3.5 +2.0 +6.5+6.2 -12.1 +21.4 +1.1 +4.0 +3.0 -5.1

Margins +11.0 +6.4 +1.1 +4.0 +3.0Cumulative effect of accounting changes -23.1 +15.0 +0.0 +0.0 +0.0

115 103 95 90 90 90 90159 145 129 120 120 120 130€/¥ rate

$/¥ rate

Margins, R&D expenses, etcR&D expensesMargins


R&D expensesMargins

(4) Aerospace sales

Change in profits (y-y)Forex impactImpact of change in sales

Aerospace operating profitsMRJExcl MRJ

(4) Aerospace orders


(3) New machinery & steel structures sales

Change in profits (y-y)Forex impactImpact of change in salesMaterials

R&D expenses

Forex impactImpact of change in salesMaterials

Margins

(3) New machinery & steel structures orders

Former machinery & steel structures ordersFormer machinery & steel structures salesMachinery & steel structures operating profits

Former machinery & steel structures salesFormer printing & industrial machinery sales

Operating profits

Former machinery & steel structures salesFormer printing & industrial machinery sales

Change in profits (y-y)

Note: All bookings and drawdowns of loss reserves (for forex and steel products) are included in the item marked "margins" under factors affecting profits. We estimate MHI uses 300,000–400,000tpy of thick steel plate for ships. We calculate that a ¥10,000/t price increase pushes costs ¥3–4bn higher per year. The company made roughly ¥7.3bn in loss provisions at the shipbuilding & ocean development segment in 09/3.




Mitsubishi Heavy Industries [7011]: factors behind y-y changes in operating profits (2)(¥bn, except where noted)

08/3 09/3 10/3 11/3F 12/3F 13/3F11/3FCo's

901.7 767.0 541.3913.6 805.4 544.340.1 -7.0 -62.5+8.7 -47.1 -55.5+4.5 -10.5 -12.7+6.0 -9.5 -9.0-6.5 -10.0 +0.0+4.7 -17.1 -33.8-4.0 +0.4 +3.0+8.7 -17.5 -36.8

Margins -15.3 -39.0Cumulative effect of accounting changes -2.2 +2.2

465.2 439.3 291.0 330.0 380.0 400.0 300.0474.4 432.7 286.3 330.0 380.0 400.0 310.0

% y-y 10 (9) (34) 15 15 5 820.8 -1.3 -23.2 -12.4 -2.4 1.6 -11.0+4.2 -22.1 -21.9 +10.8 +10.0 +4.0 +12.2+2.4 -7.5 -9.6 -2.8 +0.0 +0.0 -1.0+2.5 -2.5 -4.0 +6.6 +5.0 +2.0 +4.5-4.0 -7.5 +0.0 -2.0 +0.0 +0.0 +0.0+3.3 -4.6 -8.3 +9.0 +5.0 +2.0 +8.7-1.1 -0.4 +1.8 +0.0 +0.0 +0.0 +0.0+4.4 -4.2 -10.1 +9.0 +5.0 +2.0 +8.7

Margins -2.8 -11.5 +9.0 +5.0 +2.0Cumulative effect of accounting changes -1.4 +1.4 +0.0 +0.0 +0.0

212.1 186.2 138.4 145.0 160.0 160.0 140.0211.8 187.5 137.4 145.0 160.0 160.0 140.0

% y-y 7 (11) (27) 6 10 0 26.2 -2.4 -9.9 -6.6 -0.1 1.4 -6.0

+3.0 -8.6 -7.5 +3.3 +6.5 +1.5 +3.9+1.7 -1.6 -2.0 -0.5 +0.0 +0.0 +0.0+3.0 -1.5 -2.0 +0.8 +1.5 +0.0 +0.5-1.5 -1.0 +0.0 -1.0 +0.0 +0.0 +0.0-0.2 -4.5 -3.5 +4.0 +5.0 +1.5 +3.4-1.8 +0.5 -0.3 +0.0 +0.0 +0.0 +0.0+1.6 -5.0 -3.2 +4.0 +5.0 +1.5 +3.4

Margins -4.6 -3.6 +4.0 +5.0 +1.5Cumulative effect of accounting changes -0.4 +0.4 +0.0 +0.0 +0.0

224.3 141.5 111.9227.2 185.2 120.6

% y-y 4 (18) (35)13.1 -3.3 -29.4+1.5 -16.4 -26.1+0.4 -1.4 -1.1+0.5 -5.5 -3.0-1.0 -1.5 +0.0+1.6 -8.0 -22.0-1.1 +0.3 +1.5+2.7 -8.3 -23.5

Margins -7.9 -23.9Cumulative effect of accounting changes -0.4 +0.4

113.4 140.0 150.0 160.0 120.0146.8 140.0 150.0 160.0 120.0

5.1 7.1 10.1 13.1 6.0+3.0 +3.0 +3.0 +0.9+0.0 +0.0 +0.0 +0.0+3.0 +3.0 +3.0 +1.5-1.0 +0.0 +0.0 +0.0+0.0 +0.0 +0.0 -0.6+0.0 +0.0 +0.0 +0.0-1.0 +0.0 +0.0 -0.6

115 103 95 90 90 90 90159 145 129 120 120 120 130€/¥ rate

(7) Machine tools, ohter sales


R&D expensesMargins

Operating profitsChange in profits (y-y)


R&D expensesMargins

(7) Machine tools, ohter orders

Forex impactImpact of change in salesMaterialsMargins, R&D expenses, etc

(5) GM & SV sales

(5) GM & SV operating profitsChange in profits (y-y)

Former mass & medium-lot manufactured machinery ordeFormer mass & medium-lot manufactured machinery salesFormer mass & medium-lot manufactured machinery operChange in profits (y-y)

(5) GM & SV orders

(6) Air-con orders

Materials


R&D expensesMargins

(6) Air-con sales

(6) Air-con operating profits

R&D expensesMargins


Change in profits (y-y)Forex impactImpact of change in sales


$/¥ rate

Margins, R&D expenses, etcR&D expensesMargins

Materials

Former industrial machinery ordersFormer industrial machinery sales

Former industrial machinery operating profitsChange in profits (y-y)





Mitsubishi Heavy Industries [7011]: sales at MHI's power systems segment (¥mn, except where noted)

09/3 10/3 11/3F 12/3F 13/3F1,209,100 1,066,100 1,050,300 1,037,500 1,068,600

319,000 363,000 372,300 359,900 381,400of which, parent 190,000 226,000 226,000 203,400 213,600of which, maintenance services 129,000 137,000 146,300 156,500 167,800

300,000 231,000 210,000 190,000 180,000106,000 98,000 98,000 117,600 137,200320,000 251,000 240,000 250,000 250,000164,100 123,100 130,000 120,000 120,000Other

Wind power

SalesGas turbines

Conventional

Nuclear power


Mitsubishi Heavy Industries [7011]: Boeing-related orders and sales

99/3 00/3 01/3 02/3 03/3 04/3 05/3 06/3 07/3 08/3 09/3 10/3F 11/3F 12/3F

Orders 63 59 64 53 46 42 42 51 83 86 67 61 84Sales 77 59 61 61 36 39 39 49 75 81 67 82 66 84

Orders - - - - - - - - 30 48 24 6 24Sales - - - - - - - - 0 4 4 15 31 48

Boeing777

Boeing787

Note: We assume sales of around ¥700mn per B777 (MHI's participation ratio 10%) and about ¥1bn for the B787 (MHI's projected participation ratio 18%). B777 production volume fell in Oct–Dec 2008 because of a strike. Boeing will change its monthly production plans for the B777 from seven aircraft to five from June 2010, but is due to revert to seven aircraft from mid-2011 (announced on 19 March 2010). The B787 completed its maiden flight in December 2009, and first deliveries to customers are slated for Oct–Dec 2010. Mitsubishi Regional Jet inaugural flight scheduled for 2011, commercial operations due to start in 2012.


Mitsubishi Heavy Industries [7011]: quarterly financial data (former segment)(¥mn, except where noted)

08/3 09/3 10/3

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

674,600 1,095,000 649,100 1,296,500 1,054,200 787,500 771,500 655,500 582,700 533,000 380,400 980,100

Shipbuilding & ocean development 33,100 179,200 15,400 125,900 174,500 6,000 12,000 78,800 5,900 49,200 5,600 90,100

Power systems 249,500 326,800 211,200 427,400 477,300 342,700 260,000 68,800 346,800 180,000 130,700 324,700

Machinery & steel structures 103,000 227,000 78,600 148,700 124,400 98,900 225,900 78,600 71,200 70,000 61,700 120,900

Aerospace 69,300 106,600 114,100 325,800 55,900 86,700 100,900 267,300 35,200 83,500 51,300 265,500

Mass & medium-lot manufactured machinery 210,600 236,100 209,700 245,300 211,800 239,700 165,200 150,300 118,500 139,100 119,400 164,300

Other 9,100 19,300 20,100 23,400 10,300 13,500 7,500 11,700 5,100 11,200 11,700 14,600

685,710 760,690 682,000 1,074,685 698,342 876,310 804,948 996,074 603,300 718,300 677,700 941,587

Shipbuilding & ocean development 68,900 69,200 54,300 91,500 71,000 56,556 58,944 53,600 34,600 70,900 60,100 65,000

Power systems 227,400 222,300 178,400 318,800 226,400 315,100 305,700 361,900 233,000 254,200 231,900 347,000

Machinery & steel structures 86,500 91,500 108,100 186,400 83,700 135,400 135,400 187,700 93,800 121,100 150,700 176,400

Aerospace 83,000 114,000 108,300 195,200 98,300 117,600 109,200 187,200 90,100 123,600 107,100 179,400

Mass & medium-lot manufactured machinery 203,900 241,100 211,400 257,200 206,300 241,900 181,800 175,400 118,400 141,100 122,300 162,500

Other 16,010 22,590 21,500 25,585 12,642 9,754 13,904 30,274 33,400 7,400 5,600 11,287

24,745 31,127 38,103 42,055 22,270 50,452 27,778 5,359 3,800 21,300 20,900 19,660

Shipbuilding & ocean development 1,682 936 1,355 91 4,800 2,040 1,760 (6,959) 8,400 4,100 (2,000) 4,044

Power systems 14,559 10,205 12,437 21,086 13,800 28,813 23,987 13,401 13,400 18,300 25,600 25,303

Machinery & steel structures (2,748) 2,863 6,756 4,457 (2,200) 5,711 13,989 14,105 (3,900) 7,700 12,600 13,748

Aerospace 1,112 4,036 5,730 3,779 (2,500) 2,844 (6,344) (4,340) 0 3,100 (4,000) (5,524)

Mass & medium-lot manufactured machinery 7,907 10,125 8,307 13,719 6,300 9,238 (7,538) (15,030) (15,000) (14,300) (14,300) (19,023)

Other 2,233 2,962 3,518 (1,077) 2,070 1,806 1,924 4,182 900 2,400 3,000 1,112

3.6 4.1 5.6 3.9 3.2 5.8 3.5 0.5 0.6 3.0 3.1 2.1

Shipbuilding & ocean development 2.4 1.4 2.5 0.1 6.8 3.6 3.0 -13.0 24.3 5.8 -3.3 6.2

Power systems 6.4 4.6 7.0 6.6 6.1 9.1 7.8 3.7 5.8 7.2 11.0 7.3

Machinery & steel structures -3.2 3.1 6.2 2.4 -2.6 4.2 10.3 7.5 -4.2 6.4 8.4 7.8

Aerospace 1.3 3.5 5.3 1.9 -2.5 2.4 -5.8 -2.3 0.0 2.5 -3.7 -3.1

Mass & medium-lot manufactured machinery 3.9 4.2 3.9 5.3 3.1 3.8 -4.1 -8.6 -12.7 -10.1 -11.7 -11.7

Other 13.9 13.1 16.4 -4.2 16.4 18.5 13.8 13.8 2.7 32.4 53.6 9.9

119 115 114 111 106 110 101 96 101 94 92 93

160 160 157 160 159 166 136 119 132 139 132 111

$/¥ rate

€/¥ rate

Orders

Sales

Operating profits

Operating margin (all-company, %)

Source: Nomura, based on company data



Mitsubishi Heavy Industries [7011]: consolidated financial data(¥mn, except where noted)

04/3 05/3 06/3 07/3 08/3 09/3 10/3 11/3F 12/3F 13/3F

2,373,440 2,590,733 2,792,108 3,068,504 3,203,085 3,375,674 2,940,887 2,900,000 3,024,000 3,062,000

% y-y -8.5 9.2 7.8 9.9 4.4 5.4 -12.9 -1.4 4.3 1.3

66,630 14,772 70,912 108,912 136,030 105,859 65,660 91,000 114,000 130,000

% y-y -42.2 -77.8 380.0 53.6 24.9 -22.2 -38.0 38.6 25.3 14.0

29,772 12,538 50,365 83,048 109,504 75,306 24,009 51,000 75,000 92,000

% y-y -61.9 -57.9 301.7 64.9 31.9 -31.2 -68.1 112.4 47.1 22.7

21,787 4,049 29,816 48,839 61,332 24,217 14,163 30,600 45,000 55,200

% y-y -36.5 -81.4 636.4 63.8 25.6 -60.5 -41.5 116.1 47.1 22.7

109,800 112,200 140,500 175,900 191,400 196,600 177,100 160,000 180,000 180,000

98,800 99,200 100,810 106,700 129,200 153,800 140,400 140,000 145,000 145,000

6.5 1.2 8.9 14.6 18.3 7.2 4.2 9.1 13.4 16.4

35.8 30.8 38.9 46.3 56.8 53.0 46.1 50.8 56.6 59.7

393.2 390.4 410.2 425.5 423.2 369.9 380.8 399.0 406.5 416.9

6.0 4.0 4.0 6.0 6.0 6.0 4.0 6.0 6.0 6.0

209,805 211,911 195,185 244,233 274,885 435,038 274,061 274,100 274,100 274,100

1,759 2,571 1,549 2,772 3,569 3,010 9 0 0 0

995,306 1,048,892 1,097,403 1,166,702 1,086,580 1,082,569 948,200 935,000 975,000 987,200

975,976 958,513 971,508 1,048,586 1,164,853 1,268,616 1,240,061 1,222,800 1,275,100 1,291,100

220,141 243,758 277,840 325,022 406,999 375,826 364,331 364,300 364,300 364,300

743,231 736,500 765,236 824,744 875,653 892,347 896,350 916,400 951,400 986,400

33,728 33,726 35,769 33,444 29,037 30,991 29,149 29,100 29,100 29,100

535,412 595,273 702,632 746,361 675,572 437,816 510,698 510,700 510,700 510,700

3,715,358 3,831,144 4,047,122 4,391,864 4,517,148 4,526,213 4,262,859 4,252,400 4,379,700 4,442,900

630,970 649,144 669,667 746,591 733,500 699,678 646,538 637,500 664,800 673,200

1,101,268 1,172,894 1,198,663 1,273,571 1,365,392 1,612,800 1,495,324 1,483,400 1,558,500 1,578,200

644,405 683,917 784,732 925,266 977,827 930,484 792,225 792,200 792,200 792,200

14,216 15,211 17,770 0 0 0 0 0 0 0

1,324,497 1,309,977 1,376,289 1,446,436 1,440,429 1,283,251 1,328,772 1,339,300 1,364,200 1,399,300

2.7 0.6 2.8 4.0 4.8 3.7 2.3 3.2 3.9 4.4

1.8 0.4 1.8 2.5 3.0 2.3 1.5 2.1 2.6 2.9

1.6 0.3 2.2 3.4 4.3 1.9 1.1 2.3 3.3 3.9

2.8 0.6 2.5 3.5 4.2 3.1 2.2 3.1 3.8 4.2

1.3 0.5 1.8 2.7 3.4 2.2 0.8 1.8 2.5 3.0

2,425,765 2,482,871 2,574,952 2,720,007 2,805,821 2,896,051 2,824,096 2,822,700 2,922,700 2,977,500

Invested capital 12.26 11.50 11.07 10.64 10.51 10.30 11.52 11.68 11.60 11.67

Total assets 18.78 17.75 17.39 17.18 16.92 16.09 17.39 17.60 17.38 17.41

Cash & equivalents 1.07 0.99 0.85 0.97 1.04 1.56 1.12 1.13 1.09 1.07

Accounts receivable 5.03 4.86 4.72 4.56 4.07 3.85 3.87 3.87 3.87 3.87

Inventories 4.93 4.44 4.18 4.10 4.36 4.51 5.06 4.51 5.06 4.51

Accounts payable 3.19 3.01 2.88 2.92 2.75 2.49 2.64 2.64 2.64 2.64

Working capital 6.78 6.29 6.01 5.74 5.69 5.87 6.29 6.29 6.29 6.29

889,704 958,412 1,001,929 1,026,566 1,086,938 1,174,752 1,221,254 1,209,300 1,284,400 1,304,100

0.83 0.90 0.87 0.88 0.95 1.26 1.13 1.11 1.14 1.13

0.67 0.73 0.73 0.71 0.75 0.92 0.92 0.90 0.94 0.93

35.6 34.2 34.0 32.9 31.9 28.4 31.2 31.5 31.1 31.5

165,430 113,972 171,722 215,612 265,230 259,659 206,060 231,000 259,000 275,000

3,369 3,355 3,355 3,356 3,356 3,356 3,356 3,356 3,356 3,356

ROE (%)


Recurring margin (%)

Invested capital

Turnover period (months)

Shares out (mn)

Net interest-bearing debt

D/E ratio (x)

Net D/E ratio (x)


EBITDA

Short-term securities

Accounts receivable

ROIC (%)

ROA (%)

Key financial indicators

Minority interests

Net assets

Total assets

Income statement

Capex

Depreciation

EPS (¥)

Net profits

Recurring profits

Operating profits

Intangible long-term assets

Accounts payable

Interest-bearing debt

Cash & deposits

Balance sheet

Sales

Other liabilities

CFPS (¥)

BPS (¥)

DPS (¥)

Other assets

Inventories

Other current assets

Property, plant & equipment

Note: Actuarial differences in pension benefit accounting stood at ¥259,640mn as at end 09/3, equivalent to 20% of net assets.



Tokyo Electric Power Co 9501 JP

TECHNOLOGY | JAPAN

Shigeki Matsumoto +81 3 5255 1605 [email protected]

Expecting rapid earnings rebound on rise in nuclear capacity factor

Kashiwazaki-Kariwa plant

Reactors Nos. 6 and 7 have already resumed normal operation at the Kashiwazaki-Kariwa plant, while reactor No. 1 was restarted (for test operation) at the end of May. We expect reactor No. 5 to be restarted (for test operation) sometime in 3Q10. We think that the remaining three reactors will probably be restarted during 12/3 because the company will need time to complete earthquake reinforcement work. We forecast a capacity factor for the plant of 45% in 11/3, 77% in 12/3, and 81% in 13/3, when we expect the plant to be fully operational for the full year.

Adjusted EPS estimates

Our adjusted EPS estimate of ¥205 for 11/3 provides the basis for our price target (on a P/E of 17x). The revised EPS forecast is calculated by taking our unadjusted estimate of ¥67.5 (recurring profits of ¥208.1bn) and factoring in 1) ¥60.0bn in shortfalls in past reserves for the dismantling of nuclear power generating facilities as part of asset retirement obligations and in depreciation reserves (because extraordinary losses are not included in recurring profits); 2) a ¥155.0bn boost from a higher nuclear capacity factor; and 3) ¥140.0bn for losses incurred under the fuel cost adjustment system and the amortisation of actuarial differences in pension accounting and (until 12/3) of residual value accompanying tax system revisions, and then stripping out 4) ¥47.1bn from factors such as increased costs.

Miscellaneous costs should be held in check

The company has deferred miscellaneous costs such as maintenance and repair costs and overhead in order to make up for the losses that it incurred as a result of the shutdown of the Kashiwazaki-Kariwa plant. Although it intends to keep miscellaneous costs under control, we think that they could increase again as the plant resumes normal


Revenue 5,016 5,318 5,479 5,533



Normalised EPS (¥) 99.2 67.5 172.7 206.0

Norm. EPS growth (%) - (0.3) 1.6 0.2

Norm. P/E (x) - 36.0 14.1 11.8

EV/EBITDA (x) - 10.5 8.9 8.8

Price/book (x) 1.3 1.3 1.3 1.2

Dividend yield (%) - 2.5 2.7 2.9

ROE (%) 5.5 3.7 9.1 10.2

Net debt/equity (%) 3.1 3.1 3.0 2.7

Earnings revisions

Previous norm. net profit 91.1 233.0 277.9


Previous norm. EPS (¥) 67.5 172.7 206



1m 3m 6m

5.3 (0.1) 4.8

6.1 (1.6) 1.1

11.7 6.7 5.9

52-week range (¥)




Japan Trustee Services Bank 7.0


Dai Ichi Life Insurance 4.1

2,496/2,095

36,513

Absolute (¥)

Absolute (US$)

Relative to Index

Market cap (US$mn)

2,000

2,100

2,200

2,300

2,400

2,500

2,600

Ju

n09

Jul

09

Au

g09

Se

p0

9

Oc

t09

No

v09

De

c09

Jan

10

Fe

b10

Ma

r10

Apr

10

Ma

y10

80

85

90

95

100

105

110

Price

Rel MSCI Japan





Nomura vs consensus We are bullish on the impact of the fuel cost savings likely to be achieved by the restart of the Kashiwazaki-Kariwa nuclear power plant.

Maintained

BUY


Action We expect all reactors at the Kashiwazaki-Kariwa nuclear plant to be operating by

end-12/3 and look for recurring profits to reach a new peak in 13/3, when fuel cost savings will be felt for a full year. The near-record gap between dividend yield and long-term interest rates suggests limited downside in the share price. BUY.

Catalysts The company's New Management Vision, due to be published in August, should

cast some light on how it intends to achieve profit growth over the long term (eg, by investing more in overseas projects).

Anchor themes

This defensive stock is unlikely to attract much interest during the economic upturn, but the recent correction presents a good longer-term opportunity. If the government promotes nuclear energy as means to a low-carbon society, the company could attract attention for its high reliance on nuclear power.

Tokyo Electric Power Co Shigeki Matsumoto


operations. Thus, we forecast a higher level in 13/3 than before the shutdown. However, the company may have succeeded in structurally reducing some miscellaneous costs.

First Japanese power company involved in overseas nuclear plant project

On 10 May, the company announced that it would be involved in extension work to the South Texas Project nuclear power plant. The new unit will be a 1,350MW advanced boiling water reactor and is due to come on-line in 2017−18. The company will initially have a stake of just over 9%, which it has the option of increasing by a similar amount.

Risks include lower fuel costs

Excluding the impact of the time lag in the fuel cost adjustment system, lower fuel costs have a negative impact on the company's profits. The company's fuel cost savings (we define fuel costs as fuel consumption volume x average fuel price) from the Kashiwazaki-Kariwa plant's improved capacity factor diminish if the price of fuel declines. We estimate that adjusted recurring profits (see (2) above) are reduced by ¥6.7bn for each US$1/bbl decline in the crude oil price and by roughly ¥6.4bn by each ¥1 appreciation of the yen versus the US dollar.




Tokyo Electric Power [9501]: financial data(¥bn, except where noted)

06/3 07/3 08/3 09/3 10/3 11/3F 12/3F 13/3F

113 117 114 101 93 90 90 9056 63 79 91 69 85 85 8566 74 45 44 53 63 79 81

94 103 94 96 95 100 100 100

10.0 8.0 14.0 19.0 12.0 17.0 - -26.0 8.0 16.0 17.0 15.0 16.0 - -

8.0 9.0 12.0 15.0 10.0 13.0 - -1.0 1.0 1.5 1.5 1.0 1.5 - -

288.7 287.6 297.4 289.0 280.2 287.0 290.7 293.6% y-y 0.7 -0.4 3.4 -2.8 -3.0 2.4 1.3 1.0

401.0 458.9 337.7 483.4 481.3 448.0 425.3 437.01,040.0 1,062.7 1,755.1 2,078.7 1,192.6 1,453.8 1,385.2 1,390.0

469.3 459.0 432.1 381.3 373.9 432.1 467.0 477.0153.7 148.0 143.0 134.6 129.5 129.2 129.2 129.2

753.4 704.5 726.2 708.6 709.8 674.8 674.8 629.5629.3 650.6 773.2 842.5 722.5 722.5 722.5 722.5

1,134.4 1,201.7 1,120.1 1,143.9 1,084.1 1,122.8 1,158.2 1,159.7

5,255.5 5,283.0 5,479.4 5,887.6 5,016.3 5,317.5 5,479.4 5,533.14,895.6 4,952.3 5,168.5 5,553.7 4,732.8 5,020.1 5,182.1 5,235.7

359.9 330.7 310.9 333.8 283.5 297.4 297.4 297.4576.3 550.9 136.4 66.9 284.4 288.1 471.0 541.9572.7 526.3 94.4 21.7 245.9 260.1 437.0 507.9

0.5 23.4 40.9 35.5 38.0 27.5 33.5 33.53.1 1.2 1.2 9.7 0.5 0.5 0.5 0.5

52.6 67.0 69.8 63.5 73.2 82.0 73.2 73.2201.9 176.6 173.0 165.1 153.3 162.0 162.0 162.0427.0 441.3 33.1 -34.6 204.3 208.1 382.2 453.1

-3.3 6.0 -5.0 -3.9 -8.4 0.0 0.0 0.0- - - - - 10.0 10.0 10.0

51.1 60.7 18.6 0.0 10.7 0.0 0.0 0.07.6 0.0 269.3 68.8 0.0 50.0 0.0 0.0

473.8 496.0 -212.5 -99.6 223.5 148.1 372.2 443.1163.4 197.9 -62.4 -15.0 89.7 57.0 139.2 165.2310.4 298.2 -150.1 -84.5 133.8 91.1 233.0 277.9

Extraordinary lossesPretax profitsTax, etcNet profits

Nonoperating expensesRecurring profits

Nuclear power plant depreciation reservesExtraordinary gains

Drought reserves

ElectricityOtherEliminations

Nonoperating income

Sales

Electricity

OtherOperating profits

Consolidated income statement

DepreciationPurchased electricityOther

Parent income statementAssumptions

Sensitivity

Electricity sales volume (bn kWh)

Main recurring costsPersonnel expenses

Fuel costsRepair costs

Interest paid

Forex ($/¥)Crude oil price ($/bbl)

Nuclear power capacity factor (%)Water flow rate (%)

Forex

Crude oil priceNuclear power capacity factorWater flow rate

Note: (1) Sensitivity is sensitivity to cost and sensitivity figures are as calculated by management. (2) Expected costs arising from closure of Kashiwazaki-Kariwa nuclear power plant are not based on these sensitivity figures and for sake of convenience have been included in fuel costs. (3) Negative values for drought reserves and nuclear power plant depreciation reserves indicate drawdown of reserves (positive impact on profits).




Tokyo Electric Power [9501]: consolidated financial data(¥bn)

06/3 07/3 08/3 09/3 10/3 11/3F 12/3F 13/3F

12,848.6 12,670.7 12,697.5 12,351.3 12,221.4 12,524.2 12,868.0 13,077.0

10,170.5 9,779.0 9,543.6 9,305.4 9,024.0 8,946.3 8,923.0 8,938.7917.1 893.8 921.8 915.9 903.0 982.1 1,056.4 1,129.1

1,760.9 1,997.9 2,232.1 2,130.0 2,294.5 2,595.8 2,888.6 3,009.2

Long-term investments 744.6 864.5 646.4 499.0 527.1 539.7 552.4 565.0Nuclear fuel processing reserves 262.2 346.5 517.9 667.5 824.4 1,089.1 1,365.3 1,469.2

Deferred tax 316.1 305.9 461.7 443.5 435.8 459.8 463.8 467.8Other 438.6 481.6 606.6 520.6 507.8 507.8 507.8 507.8

Bad-debt reserves -0.7 -0.6 -0.5 -0.6 -0.7 -0.7 -0.7 -0.7745.3 850.7 981.5 1,208.0 982.6 956.5 967.8 971.5

109.5 143.9 154.6 301.4 180.2 180.2 180.2 180.2363.9 388.5 388.7 430.1 348.8 369.7 381.0 384.7271.9 318.3 438.2 476.5 453.6 406.6 406.6 406.6

0.3 0.0 0.0 0.0 0.0 0.0 0.0 0.013,594.1 13,521.4 13,679.1 13,559.3 13,204.0 13,480.7 13,835.7 14,048.5

8,432.4 8,073.8 8,602.6 9,067.8 8,769.4 9,009.1 9,199.9 9,216.3Interest-bearing debt 6,277.9 5,870.7 6,156.2 6,624.6 6,354.0 6,485.0 6,578.3 6,462.9

Pension reserves 441.6 445.3 430.9 428.9 420.9 420.9 420.9 420.9Provisions for reprocessing of spent nuclear fuel 1,634.7 1,686.6 1,739.2 1,746.0 1,756.4 1,925.2 2,055.4 2,187.2

Other 78.2 71.1 276.2 268.3 238.1 178.1 145.3 145.32,329.8 2,351.4 2,363.6 2,058.6 1,913.0 1,929.8 1,938.8 1,941.8

Liabilities due in less than one year 1,051.8 897.8 847.2 694.6 747.6 747.6 747.6 747.6

Short-term borrowings 376.5 362.9 382.2 389.2 363.6 363.6 363.6 363.6Accounts payable 213.7 201.2 390.7 242.0 279.1 295.9 304.9 307.9

Accrued taxes 133.2 213.0 58.2 75.9 78.4 78.4 78.4 78.4Other 554.5 676.4 685.2 656.9 444.2 444.2 444.2 444.2

16.5 22.4 17.4 13.5 5.1 5.1 5.1 5.1- - - - - 10.0 20.0 30.0

10,778.7 10,447.6 10,983.6 11,139.8 10,687.5 10,954.0 11,163.8 11,193.135.7 - - - - - - -

2,779.7 - - - - - - -

- 3,073.8 2,695.5 2,419.5 2,516.5 2,526.7 2,671.9 2,855.47,840.1 7,388.6 7,675.7 7,938.0 7,523.9 7,654.9 7,748.1 7,632.8

935.6 1,073.7 509.9 599.1 988.3 742.9 855.7 1,071.1310.4 298.2 -150.1 -84.5 133.8 91.1 233.0 277.9824.0 751.6 772.5 757.1 759.4 724.6 732.0 693.0

-198.8 23.9 -112.5 -73.4 95.1 -72.8 -109.3 100.2-623.7 -574.7 -664.3 -696.0 -640.9 -792.9 -861.3 -861.3311.9 499.0 -154.4 -96.8 347.4 -50.0 -5.6 209.8

Working capital, etcCapexFree cash flow


Net profitsDepreciation

Minority interests

Shareholders' equityNet assetsInterest-bearing debt

OtherDeferred assetsTotal assets

Total liabilities


Current liabilities

Drought reservesNuclear power plant depreciation reserves

Investments, other

Current assets

Cash & depositsAccounts receivable

Balance sheetLong-term assets

Power division long-term assets, etcNuclear fuel



Kansai Electric Power Co 9503 JP

POWER & UTILITIES | JAPAN

Shigeki Matsumoto +81 3 5255 1605 [email protected]

Higher crude oil prices boost benefits of new thermal plants

Upgrading and constructing thermal plants with total capacity of 5.8GW

The Sakaiko thermal power plant is being upgraded to become an LNG-fired combined cycle facility. Capacity will remain at 2GW, but thermal efficiency will rise from 41% to 58% (on a lower heating value (LHV) basis), with CO2 emissions likely to fall from 0.51kg/kWh to 0.36kg/kWh. The start-up at the Maizuru coal-fired thermal power station's No. 2 unit (capacity of 900MW) will enable less oil to be used. In the medium term, the Himeji No. 2 power plant is due to be upgraded to an LNG-fired combined cycle facility from October 2013 through October 2015. Total capacity is set to increase from 2,550MW to 2,919MW, with thermal efficiency rising from 42% to 60% (LHV basis) and CO2 emissions falling from 0.470kg/kWh to 0.327kg/kWh.

We expect nuclear capacity factor to improve

Kansai Electric Power's nuclear capacity factor is only 81% as a result of work to improve earthquake resistance, but it expects this to rise to 84% in 13/3. We forecast a nuclear capacity factor of 81% and remain cautious on the risk of suspended operations, but the company's high weighting toward nuclear power means any improvement in the nuclear capacity factor should have a major impact. Kansai Electric Power estimates that each 1ppt fluctuation in the nuclear capacity factor affects recurring profits by ¥5.5bn.

Adjusted EPS estimates

We derive our 11/3 adjusted EPS estimate of ¥148 (adjusted recurring profits of ¥215bn) by adding the following to our unadjusted EPS estimate of ¥84.7 (unadjusted recurring profits of ¥156.0bn): 1) shortfalls in past reserves for the dismantling of nuclear power generation facilities as part of asset retirement obligations (one-time extraordinary losses of ¥36bn); 2) improvement in the nuclear


Revenue 2,607 2,707 2,755 2,788



Normalised EPS (¥) 140.2 84.7 138.2 162.2

Norm. EPS growth (%) - (0.4) 0.6 0.2

Norm. P/E (x) - 25.2 15.5 13.2

EV/EBITDA (x) - 8.4 8.1 8.0

Price/book (x) 1.1 1.1 1.0 1.0


ROE (%) 7.3 4.3 6.8 7.6

Net debt/equity (%) 1.9 2.0 1.9 1.8

Earnings revisions






1m 3m 6m

5.3 (0.1) 4.8

6.1 (1.6) 1.1

11.7 6.7 5.9

52-week range (¥)




City of Osaka 8.9


2,205/1,943

Kansai Electric Power 5.3

Absolute (¥)

Absolute (US$)

Relative to Index


1,9001,9502,0002,0502,100

2,1502,2002,250

Jun

09

Jul0

9

Aug

09

Sep

09

Oct

09

No

v09

De

c09

Jan

10

Fe

b10

Ma

r10

Ap

r10

Ma

y10

80859095100

105110115

Price

Rel MSCI Japan


Revenue 2,607 2,707 2,755 2,788



Normalised EPS (¥) 140.2 84.7 138.2 162.2

Norm. EPS growth (%) - (0.4) 0.6 0.2

Norm. P/E (x) - 25.2 15.5 13.2

EV/EBITDA (x) - 8.4 8.1 8.0

Price/book (x) 1.1 1.1 1.0 1.0


ROE (%) 7.3 4.3 6.8 7.6

Net debt/equity (%) 1.9 2.0 1.9 1.8

Earnings revisions






1m 3m 6m

5.3 (0.1) 4.8

6.1 (1.6) 1.1

11.7 6.7 5.9

52-week range (¥)




City of Osaka 8.9


2,205/1,943

Kansai Electric Power 5.3

Absolute (¥)

Absolute (US$)

Relative to Index


1,9001,9502,0002,0502,100

2,1502,2002,250

Jun

09

Jul0

9

Aug

09

Sep

09

Oct

09

No

v09

De

c09

Jan

10

Fe

b10

Ma

r10

Ap

r10

Ma

y10

80859095100

105110115

Price

Rel MSCI Japan









Nomura vs consensus We are bullish on fuel cost savings achieved via the introduction of new thermal power facilities and an improvement in the company’s nuclear capacity.

Maintained

BUY


Action Thermal power plants are becoming more efficient. The higher fuel prices go, the

better the outlook for profitability at new thermal plants, and operations are resuming at nuclear plants following suspensions. Relatively high dependence on nuclear power means earnings could get a boost long term if nuclear power usage is promoted as a means to a low-carbon society. BUY Kansai Electric Power.

Catalysts The Mihama No. 2 reactor is expected to resume operation by end-July 2010, and

new thermal plants due to ramp up include the Maizuru No. 2 unit (coal) expected in August and the Sakaiko No. 5 unit (LNG combined cycle) slated for October.

Anchor themes

Defensive stocks are unlikely to attract much investor attention but the company merits consideration for its efforts to secure medium-term profit growth with new thermal plants, upgraded nuclear plants and investment in utility services.

Kansai Electric Power Co Shigeki Matsumoto


capacity factor (just over ¥39bn); and 3) a decline in residual value amortisation (just under ¥23bn), while subtracting 4) overall gains of just over ¥3bn from the fuel cost adjustment system and other factors (emission rights, etc).

Valuation

We derive our price target of ¥2,500 by applying the sector target P/E of 17x to our adjusted 11/3 EPS estimate (excluding gains realised under the fuel cost adjustment system and other factors not expected to have a medium-term impact on earnings) of ¥148.

Risks to price target. Excluding the impact of the time lag in the fuel cost adjustment system, lower fuel costs have a negative impact on profits at Kansai Electric Power. We estimate that every US$1/bbl fall in the price of crude oil results in a ¥1.2bn decline in the combined fuel cost reduction benefit realised from new thermal power plants and an increased nuclear capacity factor, with the full amount of that change carrying through to adjusted recurring profits as defined in the above paragraph. We estimate that each ¥1 appreciation of the yen against the dollar has an impact of around ¥1bn.




Kansai Electric Power [9503]: financial data(¥bn, except where noted)

06/3 07/3 08/3 09/3 10/3 11/3F 12/3F 13/3F

113 117 114 101 93 90 90 9056 64 79 91 69 85 85 8575 77 75 72 77 76 81 81

89 101 87 88 103 100 100 100

3.2 3.6 5.7 7.6 4.3 4.8 - -3.4 3.8 6.0 5.0 3.8 3.5 - -

4.8 5.8 7.5 8.8 5.2 5.5 - -0.8 1.0 1.2 1.5 0.9 1 - -

147.1 147.3 150.4 145.9 141.6 145.1 146.8 148.0

% y-y 1.5 0.1 2.1 -3.0 -2.9 2.5 1.1 0.8

246.2 206.9 211.9 235.8 236.3 238.8 238.3 242.1300.2 358.3 556.7 638.2 351.4 431.4 426.9 441.0

208.7 235.4 229.5 263.5 286.2 263.2 300.0 300.062.6 56.5 52.6 51.4 49.8 49.8 49.8 49.8

338.3 310.4 312.7 314.0 322.8 342.8 337.8 311.2404.6 415.8 379.3 471.3 352.9 352.9 352.9 352.9636.3 649.7 648.8 671.7 627.2 650.2 627.2 632.2

2,579.1 2,596.4 2,689.3 2,789.6 2,606.6 2,706.9 2,755.1 2,788.32,358.7 2,338.2 2,410.9 2,487.5 2,281.7 2,366.9 2,410.2 2,438.4

220.3 258.2 278.4 302.1 324.9 339.9 344.9 349.9327.2 271.6 187.1 31.0 227.7 190.6 235.0 267.0299.7 230.0 148.1 -20.2 169.5 140.4 179.8 211.825.7 41.6 40.0 52.5 58.1 50.1 55.0 55.0

1.7 0.0 -1.0 -1.2 0.1 0.1 0.1 0.117.8 30.7 31.6 33.5 32.7 32.7 32.7 32.7

97.4 70.7 66.3 77.1 67.3 67.3 67.3 67.3247.6 231.7 152.4 -12.6 193.1 156.0 200.4 232.4

-9.6 -0.1 -8.5 0.0 0.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00.0 0.0 24.1 0.0 0.0 36.0 0.0 0.0

257.1 231.8 136.9 -12.6 193.1 120.0 200.4 232.496.1 83.8 51.6 -3.8 66.0 44.4 78.2 90.3

161.0 147.9 85.3 -8.8 127.2 75.7 122.3 142.1

Eliminations, companywide

ElectricityOther

Electricity

Other

Net profits

Nonoperating expensesRecurring profitsDrought reservesExtraordinary gains


Tax, etc

Parent income statementAssumptions

Main recurring costs

Pretax profits

Consolidated income statementSales

Operating profits

Nonoperating income

Forex ($/¥)Crude oil ($/bbl)

Depreciation

Nuclear power capacity factor (%)Water flow ratio (%)

ForexCrude oil

Purchased electricityOther

Sensitivity

Personnel expensesFuel costs

Repair costsInterest paid

Nuclear power capacity factorWater flow ratio

Electricity sale volume (bn kWh)

Note: (1) Sensitivity figures are rough estimates of the impact on fuel costs. (2) A minus figure for drought reserves indicates a reversal (a profit-boosting factor).




Kansai Electric Power [9503]: consolidated financial data

(¥bn)06/3 07/3 08/3 09/3 10/3 11/3F 12/3F 13/3F

6,464.7 6,339.6 6,284.0 6,429.5 6,558.2 6,784.6 6,971.2 7,098.4

5,021.2 4,863.4 4,748.4 4,752.4 4,749.2 4,740.3 4,719.1 4,723.6512.4 483.8 484.2 507.2 499.1 533.0 568.6 604.2931.0 992.4 1,051.4 1,169.9 1,309.9 1,511.4 1,683.5 1,770.6

Long-term investments 313.8 318.2 269.2 265.7 292.0 300.7 309.4 318.1Reserves 136.3 183.4 273.3 358.3 447.3 610.7 774.1 852.5

Deferred tax 282.8 275.7 295.4 319.3 319.4 333.8 333.8 333.8Other 199.5 216.7 215.1 228.8 252.7 267.7 267.7 267.7

Bad debt reserves -1.4 -1.5 -1.4 -2.2 -1.5 -1.5 -1.5 -1.5391.8 487.7 505.6 540.6 558.4 564.3 567.1 569.0

66.8 127.6 82.6 69.6 78.2 78.2 78.2 78.2

147.9 158.8 161.8 166.6 151.7 157.5 160.3 162.3177.1 201.2 261.2 304.4 328.5 328.5 328.5 328.5

6,856.5 6,827.2 6,789.6 6,970.1 7,116.6 7,348.9 7,538.3 7,667.4

4,187.7 4,079.3 4,012.2 4,261.6 4,312.5 4,534.4 4,670.5 4,728.6

Interest-bearing debt 2,841.1 2,726.8 2,632.5 2,826.8 2,821.5 2,908.6 2,945.8 2,905.1Pension reserves 377.2 348.9 332.1 339.9 347.5 347.5 347.5 347.5

Provisions for the reprocessing of spent nuclear fu 899.4 939.3 961.9 1,001.1 1,025.0 1,159.8 1,258.6 1,357.4Other 70.0 64.3 85.7 93.8 118.6 118.6 118.6 118.6

869.3 862.1 931.7 1,001.8 1,014.7 1,019.0 1,021.0 1,022.4

Liabilities due in less than one year 334.4 370.0 429.4 413.4 357.8 357.8 357.8 357.8Short-term borrowings + CP 150.8 105.8 99.4 223.2 212.2 212.2 212.2 212.2

Accounts payable 96.6 94.6 144.9 96.4 111.6 115.9 117.9 119.4Accrued taxes 66.3 69.4 38.1 40.2 94.8 94.8 94.8 94.8

Other 221.2 222.1 219.8 228.6 238.3 238.3 238.3 238.38.6 8.5 0.0 0.0 0.0 0.0 0.0 0.0

5,065.6 4,949.9 4,943.8 5,263.4 5,327.2 5,553.4 5,691.5 5,751.0

4.9 - - - - - - -1,786.0 - - - - - - -

- 1,877.4 1,845.8 1,706.7 1,789.4 1,795.5 1,846.8 1,916.43,324.0 3,207.2 3,166.4 3,466.9 3,391.6 3,478.7 3,515.9 3,475.2

528.9 541.8 411.7 281.3 667.2 505.5 527.4 606.8161.0 147.9 85.3 -8.8 127.2 75.7 122.3 142.1

402.7 378.1 383.3 382.3 403.1 430.0 426.0 400.4-34.9 15.8 -56.9 -92.2 136.9 -0.2 -21.0 64.3

-268.7 -297.5 -354.0 -510.9 -430.6 -504.8 -490.4 -490.4260.2 244.3 57.7 -229.6 236.6 0.8 37.0 116.4

Net profitsDepreciation

Working capital, etc

Free cash flowCapex

Net assetsInterest-bearing debt

Drought reserves

Total liabilitiesMinority interests

Shareholders' equity

Accounts receivable

OtherTotal assets


Current liabilities

Balance sheet


Long-term assets

Power division long-term assets, etcNuclear fuel

Investments, other

Current assets

Cash & deposits

Note: In principle, capex does not include investments and financing.




Any Authors named on this report are Research Analysts unless otherwise indicated

ANALYST CERTIFICATIONS

Each of the research analysts referenced on the cover page or in connection with the section of this research report for which he or she is responsible hereby certifies that all of the views expressed in this report accurately reflect his or her personal views about any and all of the subject securities or issuers discussed herein. In addition, each of the research analysts referenced on the cover page or in connection with the section of this research report for which he or she is responsible hereby certifies that no part of his or her compensation was, is, or will be, directly or indirectly related to the specific recommendations or views that he or she has expressed in this research report, nor is it tied to any specific investment banking transactions performed by Nomura Securities International, Inc., Nomura International plc or by any other Nomura Group company or affiliates thereof.

ISSUER SPECIFIC REGULATORY DISCLOSURES Conflict-of-interest disclosures Important disclosures may be accessed through the following website: http://www.nomura.com/research/pages/disclosures/disclosures.aspx. If you have difficulty with this site or you do not have a password, please contact your Nomura Securities International, Inc. salesperson (1-877-865-5752) or email [email protected] for assistance.

Three-year stock price and rating history

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Explanation of Nomura's equity research rating system in Japan published prior to 6 January 2009 (and ratings in Europe, Middle East and Africa, US and Latin America published prior to 27 October 2008):

Stocks:

• A rating of "1", or "Strong buy", indicates that the analyst expects the stock to outperform the Benchmark by 15% or more over the next six months. • A rating of "2", or "Buy", indicates that the analyst expects the stock to outperform the Benchmark by 5% or more but less than 15% over the next six months. • A rating of "3", or "Neutral", indicates that the analyst expects the stock to either outperform or underperform the Benchmark by less than 5% over the next six months. • A rating of "4", or "Reduce", indicates that the analyst expects the stock to underperform the Benchmark by 5% or more but less than 15% over the next six months. • A rating of "5", or "Sell", indicates that the analyst expects the stock to underperform the Benchmark by 15% or more over the next six months. • Stocks labeled "Not rated" or shown as "No rating" are not in Nomura's regular research coverage. Nomura might not publish additional research reports concerning this company, and it undertakes no obligation to update the analysis, estimates, projections, conclusions or other information contained herein. Sectors:

A "Bullish" stance, indicates that the analyst expects the sector to outperform the Benchmark during the next six months. A "Neutral" stance, indicates that the analyst expects the sector to perform in line with the Benchmark during the next six months. A "Bearish" stance, indicates that the analyst expects the sector to underperform the Benchmark during the next six months. Benchmarks are as follows: Japan: TOPIX; United States: S&P 500, MSCI World Technology Hardware & Equipment; Europe, by sector — Hardware/Semiconductors: FTSE W Europe IT Hardware; Telecoms: FTSE W Europe Business Services; Business Services: FTSE W Europe; Auto & Components: FTSE W Europe Auto & Parts; Communications equipment: FTSE W Europe IT Hardware; Ecology Focus: Bloomberg World Energy Alternate Sources; Global Emerging Markets: MSCI Emerging Markets ex-Asia.



Explanation of Nomura's equity research rating system for Asian companies under coverage ex Japan published prior to 30 October 2008:

Stocks:

Stock recommendations are based on absolute valuation upside (downside), which is defined as (Fair Value - Current Price)/Current Price, subject to limited management discretion. In most cases, the Fair Value will equal the analyst's assessment of the current intrinsic fair value of the stock using an appropriate valuation methodology such as Discounted Cash Flow or Multiple analysis etc. However, if the analyst doesn't think the market will revalue the stock over the specified time horizon due to a lack of events or catalysts, then the fair value may differ from the intrinsic fair value. In most cases, therefore, our recommendation is an assessment of the difference between current market price and our estimate of current intrinsic fair value. Recommendations are set with a 6-12 month horizon unless specified otherwise. Accordingly, within this horizon, price volatility may cause the actual upside or downside based on the prevailing market price to differ from the upside or downside implied by the recommendation. • A "Strong buy" recommendation indicates that upside is more than 20%. • A "Buy" recommendation indicates that upside is between 10% and 20%. • A "Neutral" recommendation indicates that upside or downside is less than 10%. • A "Reduce" recommendation indicates that downside is between 10% and 20%. • A "Sell" recommendation indicates that downside is more than 20%. Sectors:

A "Bullish" rating means most stocks in the sector have (or the weighted average recommendation of the stocks under coverage is) a positive absolute recommendation. A "Neutral" rating means most stocks in the sector have (or the weighted average recommendation of the stocks under coverage is) a neutral absolute recommendation. A "Bearish" rating means most stocks in the sector have (or the weighted average recommendation of the stocks under coverage is) a negative absolute recommendation.

Price targets

Price targets, if discussed, reflect in part the analyst's estimates for the company's earnings. The achievement of any price target may be impeded by general market and macroeconomic trends, and by other risks related to the company or the market, and may not occur if the company's earnings differ from estimates.

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AP80b/82c/d/87

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