Economic Stimulus: The Case for Clean Infrastructure, Energy

Emerging Markets

Leading Clean Energy Markets

June 2012

Report available online: http://www.dbcca.com/research

Carbon Counter widget available for download at: www.Know-The-Number.com

Climate Change Investment Research

2 Emerging Markets 2012

Mark Fulton

Managing Director

Global Head of Climate Change

Investment Research

New York

Michael Carboy

Director

Head of Brazil, China and India Research

Hong Kong

Camilla Sharples

Assistant Vice President

New York

Jane Cao ( 曹瑱 ) Analyst

Beijing

Lucy Cotter

Associate

London

Reid Capalino

Analyst

New York

Table of Contents


Table of Contents

Editorial Letter 4

Executive Summary 5

Country Specific Conclusions 13

1.0 Brazil – Energy and Sustainability Overview 15

1.1 Renewables 20

Current Status and Outlook 20

Policy Support 25

Manufacturing and Policy Support 32

1.2 Electricity and Biofuels Forecast 33

1.3 Water Sustainability 39

1.4 Challenges 41

2.0 China – Energy and Sustainability Overview 43

2.1 Renewables 47


Policy Support 51

Manufacturing and Policy Support 54

2.2 Electricity and Biofuels Forecast 55


2.4 Challenges 60

3.0 India – Energy and Sustainability Overview 61

3.1 Renewables 65


Policy Support 68

Manuafacturing and Policy Support 80

3.2 Electricity and Biofuel Forecast 80


3.4 Challenges 87

Editorial Letter


Can BICs strength offset OECD weakness? Apart from this being a key question for the overall world economy, we

believe this is also a key for investors in clean energy to consider. Some of the OECD economies’ ability to fund clean

energy incentives is under budgetary pressures and consumer cost constraints while risk aversion continues in capital

markets. Longer term, the improved cost competitiveness of clean energy will prove to be the key driver globally.

China leads growth, Brazil contributes and India uncertain. The BICs economies continue to grow faster than

OECD economies and enjoy comparatively greater budget strength. We believe the BICs countries will be better able

to continue with commitments to decarbonize their energy infrastructures, though not without risks. We expect China,

as the most significant of the BICs countries, to continue expanding wind, solar and hydropower at world scale rates. In

2011 China’s renewables growth alone was 2.5x that of Brazil and India, combined. Brazil, a biofuels world leader,

could expand even further if sustainable practices can be effective in protecting the rainforest. Brazil’s wind and solar

sectors will grow, but may face growth below government forecasts due to problems with reverse auctions. India faces

the greatest challenges with bureaucracy and inadequate infrastructure and less certain policy commitment constraining

its ability to capitalize on rich wind and solar resources.

Incremental 440 GW to be added by 2020. In our “best estimate” analysis based on both IEA forecasts and

government plans, we estimate that in the 2010 - 2020 period the BICs countries will add an incremental 440 GW of

clean energy installed generation capacity, an amount representing 46% of global growth based in the IEA’s global

estimates. Our forecast exceeds the comparable BICs IEA forecast and is modestly below the growth forecast by BICs

governments. We have more confidence in our BICs forecast compared to the near-term OECD outlook. We see the

BICs countries’ demand serving as a significant support for the industry globally.

USD$663 billion invested by 2020. In 2011, Brazil, India and China invested USD$62 billion in clean energy asset

financing, 13% higher than in 2010, and accounted for 42% of global activity. This investment deployed within Brazil,

India and China 11GW, 3 GW and 36 GW of renewables, respectively, in 2011. Looking ahead, cumulative investment

in renewable energy in the BICs countries from 2010-2020 may approximate USD$663 billion and is dependent upon

successful execution of BICs government expansion programs.

Manufacturing rationalization ahead, yet 1.3 million new jobs by 2020. The BICs are in many senses the power

house of manufacturing capacity of the renewable sector. Indeed, there is significant surplus wind and solar equipment

manufacturing capacity in the BICs countries. Solar power manufacturing we estimate now has 40%-54% excess

capacity while the wind power manufacturing sector faces an estimated 41% excess capacity. In the near-term, we

expect these surpluses to be rationalized globally. However, through 2020, we believe Brazil and China, collectively,

could add 1.3 million clean energy jobs given energy needs, declining costs and sustainability commitments.

Electricity Grid and Pipelines to expand. The complimentary energy infrastructure – electricity grid, gas and biofuels

pipelines - also requires expansion as new generation and refining operations are added to national infrastructures.

Without such expansion, investment in these sustainable energy systems could prove moot.

TLC trends mixed, water stress a risk. Within the BICs countries, renewables policies vary in efficacy. China and

Brazil have broad policy support manifest in targets and feed-in tariffs (FiTs) that provide transparency, longevity and

certainty (TLC) for project development and local jobs growth. India’s policies, however, are complex and shifting.

Recent expiration of accelerated depreciation for wind projects in India will likely slow the pace of development. We

believe the major risks facing investors in the BICs countries remain local content requirements, failure to enforce policy

and failure of project development execution. Shifts in water resources for human, agricultural, biofuels and hydropower

use also pose significant risks. Climatological projections point to increasing water stress, a particular risk factor for

countries with significant expanding middle-class populations.

Mark Fulton

Managing Director

Global Head of Climate Change Research

Executive Summary


Executive Summary

Whether clean energy growth in the BICs countries (Brazil, India and China) can offset weakness in the OECD countries is a

key question for investors to consider. The BICs governments’ abilities to implement policy and successfully execute on those

clean energy plans will, we believe, be essential if the BICs are to offset the OECD economies’ budget woes behind their

wavering commitment to clean energy.

The BICs countries play a significant role in the world economy representing in 2010 16% of global manufactured

goods exports and accounting for 40% of total world GDP growth, as depicted in Figure 1. With the BICs contribution

on par or greater than that of the OECD, we believe the BICs countries can help offset the OECD’s wavering support for clean

energy development.

Figure 1: BICs share of world exports and GDP growth

Source: World Bank, IMF, OECD and DBCCA analysis, 2012

China, the most significant of the BICs contributors, we believe, can continue with world-scale development in wind,

solar and hydro power. Brazil, we believe, will continue developing hydro power and biofuels to world-scale levels

while developing wind power and solar power to a lesser extent. India, with rich wind and solar power resources,

faces significant bureaucratic and infrastructure challenges that may constrain the country’s ability to expand those

sectors to meaningful scale. If major structural reforms were promptly enacted by India’s government, we believe wind and

solar power development could flourish, although not to the same scale as in China.

2011 was a difficult year for renewable expansion in most OECD countries with capital invested in the sector growing by a

modest 4%. Budget crises, associated reductions in feed-in tariffs (FiTs) and weakening of other support mechanisms and

uncertainty about the depth of future governmental commitment have caused investors to rightly shift their focus to the still

growing emerging markets, dominated by Brazil, China and India. One measure of the national ability to continue supporting

clean energy programs may be found in the concept of Budget Strength. Figure 2 shows the 2011 budget deficit expressed as

a percentage of 2011 GDP.

0%

20%

40%

60%

80%

100%

2005 2006 2007 2008 2009 2010

Glo

ba

l M

an

ufa

ctu

red

Go

od

s E

xp

ort

s,

%

Sh

are

China Brazil India ROW

-3%

-2%

-1%

1%

2%

3%

4%

5%

6%

-3%

-2%

-1%

1%

2%

3%

4%

5%

6%

2000 2002 2004 2006 2008 2010

An

nu

al

Re

al

GD

P G

row

th,

%

An

nu

al

Re

al

GD

P G

row

th,

%

BICs OECD ROW World GDP YoY Growth

Executive Summary


Figure 2: Budget strength as an indicator of ability to sustain clean energy transitions

Emerging Country

Budget Strength (Budget Deficit as % of 2011 GDP)

Developed Country

Budget Strength (Budget Deficit as % of 2011 GDP)

Brazil -3.1% United States -8.9%

China -1.2% United Kingdom -8.8%

India -5.0% Germany -1.7%

Japan -8.5%

Spain -6.5%

France -5.8%

Source: DBCCA Analysis, 2012. GDP and Budget Strength data: CIA World Factbook; Capital Investment by country: Bloomberg NEF.

With the exception of Germany, the major OECD countries’ budget strength metrics underscore the weakness that we believe

has led to watered-down policies supporting clean energy development. Brazil, China and India do not currently face the

same degree of budgetary pressure; a situation that we believe will allow these three countries to continue on their

transformative trajectories. There are, of course, risks in the BICs economies including inconsistent or unstable policies,

unintended “winner’s curse” problems associated with reverse auctions, bureaucratic dysfunction and gridlock, as well as

impaired essential infrastructure.

Opportunity Tempered with Risks

While these three countries have different renewable resource profiles and areas of renewables development focus, all have

established a range of policy mechanisms to support renewables growth as they seek to reduce their reliance on carbon-rich

fuels and imported fuels while at the same time preparing to power their own expanding economies, building indigenous

businesses and creating higher-value job opportunities for their citizens. Frustratingly, certainty and longevity of

supportive policies is not consistent across the BICs countries, in particular in India where policy expiration and

local content issues cloud opportunities. Growth of clean energy in the BICs countries could be materially

influenced by unpredictable policy and political shifts. Such risks influence financing availability and prices as much as

inadequate infrastructure drives up development costs.

According to Bloomberg New Energy Finance’s year-end analysis, in 2011 the BICs countries collectively invested

approximately USD$62 billion (up 13% YoY) of asset finance in clean energy - representing 42% of total $146 billion

in worldwide asset finance investment in the sector. Comparatively, the BICs financing through venture and private

equity was a modest USD$1 billion, or 11% of global VC/PE activity in the sector in 2011. In looking at these three countries

as significant proponents of global renewable energy investment, several dramatic differences become immediately apparent

as presented in Figure 3, below.

Executive Summary


Figure 3: BIC’s clean energy investment – Who is spending and how fast?

Source: Bloomberg New Energy Finance, 2012 and DBCCA analysis, 2012

China’s annual asset finance investments in the sector dwarf that of Brazil and India. Not surprisingly, Brazil and India,

from their small bases, demonstrate more rapid growth. Before one extrapolates Brazil’s and India’s growth rates under the

assumption they might grow to China’s scale, it is important to consider the significant infrastructure and budgetary

impediments we address in the country sections that follow.

Possible Future Trajectories – IEA vs. Government Plans for 2010-2020

Policy execution is as important as having good clean energy policy. While the governments’ plans and goals sketch out their

ambitions, the comparison of these aspirations with the IEA forecasts draws important contrasts on the scale of opportunity

within the BICs countries. Comparing the governments’ forecast to the IEA’s “New Policies” scenario forecast, as in Figure 4,

differences become apparent. Some of these differences may be attributed to forecasts being prepared at different times and

with different initial assumptions and some differences may be attributed to differing opinions regarding either scale of

development opportunities or execution.

Figure 4: Incremental GW Expansion Comparison between IEA “New Policy” scenario and BICs Governmental Plans

IEA “New Policy” Scenario 2010-2020 BIC Government Plan 2010-2020

Renewable Source

Hydro Biomass Wind Solar Hydro Biomass Wind Solar

Brazil 13 1 2 3 35 5 11 NA

China 121 18 139 20 125 14 171 30

India 27 2 20 15 16 4 24 18

Total BIC 161 21 161 38 176 22 206 47

Source: IEA WEO 2011, Ministry of New and Renewable Energy of India, Government of India Brazil’s 10-Year Energy Expansion Plan, China’s 12th Five Year Plan, CEC’s study of 12th Five Year Plan of Chinese Electricity Sector and DBCCA analysis 2012. Note: Green shading indicates government forecast exceeds IEA forecast. Red shading indicates government forecast is less than IEA forecast.

Given the material policy developments in India, uncertain electricity demand conditions and financing constraints, we have

estimated what we believe to be the most likely development trajectory for renewables expansion in the BICs countries in

Figure 5, below. For each “best estimate” we have noted how this estimate compares to both the IEA’s and respective

government forecasts.

0

20

40

60

80

100

120

140

160

2010 2011

As

se

t F

ina

nc

e U

S$

, b

illi

on

s

ROW Brazil India China

Y/Y Growth

+5%

+20%

+65%

+0%

Executive Summary


Figure 5: DBCCA “Best Estimate” synthesis of IEA and BICs Governments’ plans

Renewable

Resource

Hydro

GW

Biomass

GW

Wind

GW

Solar

GW

Brazil 30 5 9 3

<Gvt, >IEA =Gvt, >IEA <Gvt, >IEA = IEA

China 125 14 171 30

=Gvt, >IEA =Gvt, <IEA =Gvt, >IEA =Gvt, >IEA

India 16 3 16 18

=Gvt, <IEA <Gvt, >IEA <Gvt, <IEA =Gvt, >IEA

Total BICs 171 22 196 51

<Gvt, >IEA =Gvt, >IEA <Gvt, >IEA >Gvt, >IEA

Source: IEA WEO 2011, Ministry of New and Renewable Energy of India, Government of India Brazil’s 10-Year Energy Expansion Plan, China’s 12th Five Year Plan, CEC’s study of 12th Five Year Plan of Chinese Electricity Sector and DBCCA analysis 2012.

Boiling this all down, we believe investors interested in participating in BICs clean energy investment opportunities

must consider the prospect of whether various countries’ governments can effectively execute stable and consistent

policy. We believe China can successfully follow through on its goals, driving clean energy growth along a

trajectory that we believe can achieve government objectives in excess of IEA estimates.

Brazil, we believe, may experience greater execution risk as reverse auctions and policy dilemmas driven by

sustainable stewardship constraints may result in shortfalls to their own goals, suggesting the IEA forecast for Brazil

may be the more prudent outlook.

India, we believe, may suffer the frustration of unrealized potential. Despite significant solar and wind power resources

and a reasonably sized entrepreneurial core, bureaucracy, shifting and expiring policy and Byzantine complexity as well as

substantial basic infrastructure shortcomings, we believe, may cause actual development of wind and biofuels resources to

fall short of government plans and aspirations. Despite this cautionary statement, we believe some states in India may

continue to confound investors: Gujarat, in particular, may prove far more hospitable to wind and solar power development

than other states where corruption, inefficiency and gridlock are more common.

The IEA Outlook

In our analyses of the BICs countries we have looked at both the IEA’s forecasts and the governments’ plans. Figure 6

summarizes the IEA’s “New Policy” scenario data for the BICs countries. For the ten years through 2020, the IEA’s “New

Policies” scenario forecast estimates the BICs will install a cumulative 381 GW of renewable generation. The IEA’s

comparable forecast data confirms that the largest scale opportunity remains China where the cumulative addition of 139 GW

of wind power and 20 GW of solar power exceeds the combined growth of Indian and Brazilian wind power and solar power

development.

Executive Summary


Figure 6: Summary BIC’s renewables overview based on IEA “New Policies” scenario

2009 2015e 2020e 2009 2015e 2020e 2009 2015e 2020e

Total Electricity Generation

(Twh)466 573 647 3,735 5,812 7,264 889 1,319 1,723

All Renewables % 83.9% 74.5% 71.1% 17.3% 20.5% 22.7% 12.0% 11.1% 12.1%

Hydro % 83.9% 74.5% 71.1% 16.5% 15.6% 15.3% 2.0% 3.1% 3.7%

Wind % 0.2% 0.9% 1.2% 0.7% 4.1% 5.3% 0.0% 0.8% 1.5%

Solar* % 0.0% 0.2% 0.6% 0.0% 0.3% 0.5% 0.2% 0.5% 1.1%

Biomass and Waste % 4.9% 5.1% 5.3% 0.1% 0.5% 1.5% N/A N/A N/A

2010e 2015e 2020e 2010e 2015e 2020e 2010e 2015e 2020e

Hydro (GW) 87 93 100 209 270 330 41 49 68

Wind (GW) 1 2 3 41 114 180 13 23 33

Solar (GW) 0 1 3 2 11 22 1 7 16

Biomass and Waste (GW) 3 4 4 2 6 20 2 3 4

Brazil China India

Installed Capacity (GW)

Source: IEA, various government documents and DBCCA analysis, 2012 Note: “Installed Capacity” as used by the IEA presumes grid connection. Note: DBCCA’s forecast for China 2015 and 2020 electricity generation and wind and solar installed capacity materially vary from the IEA’s forecast. We estimate in 2015 China will consume 6,421 Twh and have 111 GW of wind power and 15 GW of solar power installed. By 2020, DBCCA forecasts that China will consume 8,542 Twh and will have 201 GW of wind power and 30 GW of solar power installed, materially above the IEA estimates.

Even as the largest market of the three, China’s forecast forward five year compound average growth rates compare quite

favorably to growth in India’s and Brazil’s markets. We continue to believe China will be the major driver of activity in the

market for wind, solar and hydro power while Brazil is likely to continue as one of the global biofuels heavyweights.

Figure 7: Relative global share of IEA ‘New Policies’ scenario expansion 2010-2020

Source: Governments of Brazil, China and India, IEA, CLSA and DBCCA analysis, 2012

Figure 7 is a “radar plot” depicting the BICs countries’ market shares of total global incremental capacity development in the

key wind, solar, biomass, biofuels and hydropower sectors for the period 2010-2020, based on the IEA’s “New Policies”

scenario contained in the IEA’s World Energy Outlook, 2011. It is evident that China represents a substantial portion of

the global incremental renewables capacity expansion through 2020. The collective efforts of Brazil and India are

easily overshadowed by China’s scale with the sole exception of Brazil’s biofuels efforts.

0%

10%

20%

30%

40%

50%Hydro

Biomass

WindSolar

Biofuel

Brazil

China

India

Executive Summary


The Governments’ Outlook

Shifting from the IEA’s New Policies forecasts to the governments’ forecasts, some caveats are in order. Since China offers

only “data point” targets for 2015 and 2020 that are not directly comparable with other countries, we have developed a year by

year energy and electricity forecast to facilitate comparison with Brazil and India. This DBCCA forecast models a

macroeconomic, energy and electricity trajectory that achieves results consistent with the governments’ articulated policy

goals and targets by 2015 and 2020. Because this forecast serves as a year by year proxy for China’s governmental targets,

we treat it as a “government” forecast comparable to those of Brazil and India.

For India, we have only interpolated 2017 and 2022 targets set forth in various Government of India documents. Lastly,

Brazil’s very recent energy and electricity forecast did not require any interpolation.

Collectively, the BICs countries’ government forecasts envisage up to 452 GW of incremental renewables generating capacity

expansion from 2010 to 2020. This estimate is based on our analysis and interpretation of BICs governments’ forecasts and

remarks made by their public officials.

Figure 8: IEA, BICs Governments’ and DBCCA “Best Estimate” renewables expansion, 2010-2020


The BICs countries’ ambitions reflect the best planning now available from the three governments. These opportunities are

hardly risk free and whether each country capitalizes on their various renewables resource portfolios depends on having

stable, consistent and effective policy, predictable and financially viable project development and the financial resources to

sustain long-term development. To expand the renewables industry, the political, legislative and fiscal capacities of the

countries must be prepared for the long haul and that requires transparency, longevity and certainty of policy.

The “BIC Govt. Plan” portion of Figure 8 above reflects the current thinking of the BICs governments’ plans for renewable

energy development as well as the IEA’s estimates and our DBCCA “Best Estimate” synthesis of IEA and government

estimates.

176 161 171

22 21

22

206

161196

47

38

51

-

100

200

300

400

500

BIC Govt. Plan IEA "New Policy" Scenario

DBCCA Best Estimate

20

10

-20

20

In

cre

me

nta

l In

sta

lle

d

Cap

ac

ity,

GW

Hydro Biomass Wind Solar

Executive Summary


Figure 9: IEA, Government and DBCAA “Best Estimate” renewable forecasts, 2010-2020


Not all governments issue clearly articulated long-term energy forecasts. Brazil has the most current planning through 2020,

issued in late November 2011. China does not issue as comprehensive and clearly articulated energy plan as Brazil’s,

instead announcing generalized targets and goals for 2015 and 2020. Like China, India operates on a five year planning

cycle, yet has not announced India’s 12th

Five Year Plan despite the 11th Five Year Plan having expired on 31 March 2012,

the end of their fiscal year. Consequently, Indian government forecast details are the least current of the BICs countries.

In particular, Brazil issued its Energy plan 2010-2020 just weeks before the IEA issued their current World Energy Outlook

2011 forecast. It is unclear how much of the variance in Figure 9, above, can be attributed to that timing difference or truly

due to differences in opinions of what amounts are likely achievable.

Brazil is, we believe, likely to remain an expanding market for wind power and could similarly expand solar

deployment. We see the greatest threat to Brazil’s wind and solar ambitions being “winners curse” problems with reverse

auctions leading to projects awarded that either are never built or perform poorly as investments. The biggest aspect of the

Brazil story is bioethanol. By 2020 the Brazilian government estimates that exports of Brazilian bioethanol will

increase by 3.8x to 6.8 billion litres from 1.8 billion litres in 2011. At concomitant production levels, we estimate that

Brazil would likely use 18.4 million hectares for cane (more than twice the current 8 million hectare), an amount equal to

approximately 28% of agricultural land zoned for sugar cane. While Brazil certainly could scale its bioethanol operations even

larger, we believe environmental and sustainability problems arising from (1) agricultural displacement resulting in

adjacent deforestation and (2) degradation and water stress associated with cane field expansion and the adverse

environmental footprint of the downstream cane processing operations may restrain how large Brazil’s export

activities may ultimately become. Hart Energy’s February 2012 forecast1 suggests that Brazil’s primary energy bioethnaol

export markets through 2020 may most likely be found among the EU27 countries, baring disruptions in the US’ non-green

corn-fed ethanol sector.

1 “Global Biofuels Outlook to 2020,” L. Nurafiatin, Hart Energy, February 2012

-

50

100

150

200

250

300

350

400

Brazil China India

Inc

rem

em

en

tal G

W's

20

10

to

20

20

IEA Govt. Plan DBCCA Best Estimate

Executive Summary


China seems solidly on track as both a country with enormous potential domestic appetite for renewables and being

capable of establishing a manufacturing base of indigenous companies supplying the global wind and solar power

markets. We do not, however, expect a sizeable biofuels market to develop in China.

Estimating the scale of opportunities for India is particularly challenging. Recent expiration of accelerated depreciation

benefits for wind power projects has tarnished the appeal of generally attractive state-level feed-in tariff and renewable energy

certificate programs. With the expiration of accelerated depreciation, we believe India will find it difficult to achieve

wind power development goals. Solar power may fare better as accelerated depreciation remains available to developers

and the country’s rich solar resources remain largely untapped, awaiting large scale development under both national and

state-level programs. Biofuels initiatives may also fall short of objectives given complex land ownership and land use

problems.

FiTs for Future Wind and Solar

Looking ahead, we believe the discussion over the most effective way to support renewables via either government-set FiTs

or through reverse auctions FiTs will continue. Indeed, FiTs are a better method than capital subsidies as the power

consumers pay for it rather than the national budget. While we believe FiTs are more effective and provide greater

transparency, certainty and longevity (TLC) for developers than reverse auctions might offer, the method used to

determine FiT price - government fiat or reverse auction – is a key question for policy makers. We see the lack of

enforcement of commitments by wind and solar project bidders, and the “winners curse” of lowest marginal price as being the

major failings of reverse auctions when applied to rapidly expanding markets where the delivered services are essential and

non-interruptible. Reverse auctions appear quite successful in reducing the price of renewables electricity. In Brazil, wind

power electricity prices dropped from USD$89/Mwhr in 2009 to recent levels of approximately USD$60/Mwhr. In India solar

power electricity prices dropped from USD$290/Mwhr in 2009 to USD$165/Mwhr exiting 2011. Such price reductions suggest

great progress, but until the awarded wind and solar projects are built and have demonstrated their ability to deliver both

appealing investment returns and electricity at those prices for sustained periods, we think the specter of “bid, not built” may

continue to haunt to debate over reverse auctions as the optimal method for setting FiT prices. The typical problems behind

the “bid, not built” phenomenon are awarded bids proving difficult to finance or development execution failure at the hands of

inexperienced bidders.

Biofuels and the Sustainability Challenge

Biofuels are forecast by the IEA to become an increasingly utilized fuel for transportation. By 2020, the IEA “New Policies”

scenario estimates that global biofuels use will approximate 4% of petroleum-based oil used in transportation of all forms in

2020 and could grow to 7% by 2035. Of the BICs countries, Brazil is far and away the greatest opportunity (and risk)

for developing biofuels.

Biofuels face the well discussed “conflict” dilemma: while they can often be used as direct replacements for vehicle fuel, their

feedstocks often are crops that have either a direct human food value or the land used to cultivate the biofuel crops displaces

human food acreage. Thus, the “holy grail” for the biofuel community remains feedstocks and processes that do not conflict

with the food supply chain – for example, by using feedstocks from inedible plants that can grow on non-agricultural land and

can be scaled in a sustainable manner. The BICs countries are forecast by the IEA to increase their biofuels consumption at

a 6.8% CAGR through 2020, a pace consistent with the rest of the world. The combined BICs demand by 2020 is estimated

to consume approximately 27% of global biofuels production.

Brazil’s contributions to renewables developed via the biofuels pathway could be materially increased if the country

was able to develop and enforce sustainable development policies for bioethanol without ruining the country’s

economic advantages already established in the sector. Brazil’s resources are of such scale that potential growth in

Executive Summary


bioethanol production could exceed levels envisaged by the government’s current energy plan, materially displacing

petroleum fuels in the IEA’s “New Policies” scenario forecasts. Doing so, however, we believe poses significant sustainability

risks to the Brazilian ecosystem. Currently bio-ethanol is derived from a variety of edible starches and sugars which do

conflict with the food supply chain – although sugar based ethanol, which is the dominant alternative fuel in Brazil, conflicts

less with food supply than corn-based ethanol, which is the dominant alternative fuel in the US. Cellulosic ethanol remains a

non-commercialized technology as cost-efficient fermentation remains elusive. Similarly first-generation bio-diesel relies on

oils derived from food crops and animal rendering waste. Second generation bio-diesel based on oils from “non-conflict”

seeds (i.e. Jatropha) is only beginning to be explored for commercialization.

One key dimension to biofuels development is water use. Ideally the perfect biofuels feedstocks will not conflict with the

human food supply chain and that includes not requiring much water for crop growth or processing. We believe that water-

related themes will become more frequently discussed dimensions of sustainability-focused investing in the coming years.

Water scarcity is an issue for many developing economies, in particular India’s and China’s. Figure 10 illustrates the United

Nations’ survey of worldwide water scarcity with India being moderately and heavily exploited and China being moderately

and over- exploited.

Figure 10: Water scarcity – Challenges invite solutions

Source: United Nations Environment Programme and DBCCA analysis, 2012

Sustainability themes and renewable energy – generation and fuels - hold great promise for these three rapidly changing

economies to provide power for economic expansion, to reduce strategic energy and food risks and to serve as a source of

domestic industrial growth and jobs expansion.

Estimated Investment Potential

Collectively, the BICs countries may account for between 381 GW (IEA) and 452 GW (Gvt Plans) of incremental renewables

generation expansion for the 2010-2020 period. The total investment for wind power, solar power and grid necessary

for a 440 GW expansion we estimate to be approximately USD$ 663 billion. General infrastructure investments believed

necessary by the Government of India to support domestic renewables expansion could add another USD$100 billion to this

amount.

Executive Summary


Manufacturing Growth and Job Creation

Wind turbine and crystalline solar module manufacturing capacity now in place in the BICs countries represents the majority of

global capacity: at year-end 2011, 74% of crystalline module capacity and 57% of wind turbine manufacturing capacity

were located in the BICs region with the vast majority in China. Figure 11 illustrates the current and Bloomberg New

Energy Finance2 near-term manufacturing capacity forecasts. For comparative purposes, we have included Bloomberg New

Energy Finance’s relevant global demand forecasts.

Figure 11: Manufacturing capacities exceed demand outlook

Source: BNEF and DBCCA analysis, 2012

Based on current demand forecasts, above, there appears to be significant surplus manufacturing capacity, particularly in

China. If global wind and solar power demand reaccelerates, we believe the BICs countries could experience future

manufacturing expansion only once the current surplus manufacturing capacity is fully utilized. Our best estimate is that such

a condition would occur no sooner than 2015, though local content rules and punitive trade tariffs could shift the pace and

direction of rationalization in ways we cannot predict.

Worldwide, jobs in renewable energy industries exceeded 3.5 million in 2010. China, Brazil and India account for a large

share of global employment in renewables. In addition to manufacturing, many of these jobs are in installations, operations,

2 “Q2 2012 Wind market Outlook” and “PV Market Outlook Q2 2012,” Bloomberg New Energy Finance, May 2012 and DBCCA analysis 2012.

Supply PV Crystalline Module Manufacturing Capacity

Estimates

(MW's of Capacity) 2010 2011 2012 2013 2014

Brazil - 25 25 NE NE

China 21,440 34,320 42,625 NE NE

India 1,171 1,621 1,896 NE NE

ROW 8,873 12,634 14,623 NE NE

Total 31,484 48,600 59,169 NE NE

Demand Global PV Module Demand 21,440 34,320

BNEF Cautious Scenario 23,551 219,096 28,197

Excess Capacity (1-(Demand % of 2012 Supply Capacity)) 60% NE NE

BNEF Optimistic Scenario 31,956 32,364 46,839

Excess Capacity (1-(Demand % of 2012 Supply Capacity)) 46% NE NE

Supply Wind Turbine Manufacturing Capacity

Estimates

(MW's of capacity) 2010 2011 2012 2013 2014

Brazil NE 1,230 1,230 1,830 NE

China 26,274 32,839 37,652 38,172 37,537

India NE 7,975 NE NE NE

ROW 35,958 31,485 42,301 39,008 40,353

Total 62,232 73,529 81,183 79,010 77,890

Demand Global Wind Power Demand 35,700 42,200

BNEF Forecast 48,100 41,300 43,300

Excess Capacity (1-(Demand as % of 2012 Supply Capacity)) 41% NE NE

Executive Summary


and maintenance as well as in biofuel feedstocks. We have not been able to develop a comprehensive estimate of the total

new direct and indirect jobs that might be created within the BICs countries in connection with 381 GW (IEA) - 452 GW (Gvt

Plans) of incremental renewables expansion. Credible quantitative jobs creation data for India for these emerging sectors is

unavailable.

Independent research suggests that for the 2010-2020 period, China’s wind and solar sectors could create 1.1 million

jobs3. Brazil’s efforts might create up to 225,000 jobs

4 in the same approximate period. Realization of such jobs growth

through 2020 is contingent upon resumption of rapid growth in the wind and solar power sectors in order to fully absorb

surplus manufacturing capacity and to create incremental manufacturing expansion. We are unable to forecast the number of

jobs in the wind and solar power sector that may be at risk due to consolidation and rationalization processes that may occur

before surplus capacity is absorbed by reinvigorated demand.

Local Content Rules, Punitive Tariffs and Rationalization of Surplus Capacity

Local content rules have direct interaction with jobs creation and manufacturing growth as well as less directly with tariff

eligibility. Essentially, “local content” or “domestic content” rules are intended to ensure that development of renewable

energy installations in a particular country use a specified percentage of domestically-produced goods in building the project

in order to foster the development of local industry expertise and supply chain resources. Punitive import tariffs are,

ostensibly, used to address perceived “dumping” of manufactured goods (the sale of goods at a price in the consuming

country that is below the cost of manufacture in the originating country). There is no succinct description of how local content

rules are used in the BICs countries (or in the rest of the world).

Brazil and India have in place such practices that are creating inefficiencies and much dialog in the World Trade Organization

(WTO) policy sphere. Brazil, while not having explicit local content rules, still practices such policies through requirements

necessary to gain favorable financing. India, not a signatory to the Government Procurement Agreement of the WTO, argues

that national government solar programs can, in fact, implement local content rules without regard to WTO rules. The more

significant state programs, for the most part, eschew local content rules. While China has no explicit local content rules, we

believe implicit requirements may arise in the course of project negotiation at the provincial level when developers seek tax

and property benefits.

Punitive import tariffs are being discussed by Germany vis à vis China over imported solar panels. India and Brazil have in

place import tariffs of varying degrees that influence the wind and solar project developers. China and the United States are

enmeshed in disputes over solar panels, polysilicon and wind turbine towers with punitive tariffs announced.

These policies can create significant economic inefficiencies and dislocations and restrict access to “best available

technologies” if clumsily formulated or used intentionally as a trade-restrictive element of national industrial policy. We are

unable to estimate in a quantitative way the potential impact these practices may have on the renewables sector. It suffices to

say that such trade friction raises costs, overall, and could impair projects financial returns.

As the BICs countries struggle to balance the development of indigenous renewables manufacturing bases with accepted

global trade policy, the scale and scope of renewables job creation and absorption of surplus manufacturing capacity could be

materially affected. Based on our forecast, we do not believe the significant excess manufacturing capacity now in place will

be fully absorbed until 2015 at the earliest.

The intersection of local content rules, punitive tariffs and the location of surplus manufacturing capacity are all powerful

forces that give rise to the question of where will rationalization actually take place. A simple economic process would lead

manufacturers whose combined manufacturing costs plus required profits exceed current market prices to close surplus

3 “Green Economy and Green Jobs in China: Current Status and Potentials for 2020,” Pan et al, Worldwatch Report 185

4 “Windpower Contribution to Sustainable Development in Brazil,” Simas and Pacca, May 2011

Executive Summary


manufacturing capacity, a "right-sizing" exercise the western manufacturing and service sectors know well. With substantial

portions of current surplus capacity not located in western countries, but in countries where industrial policy decisions are

made along societal and political lines as well as economic lines, there is the risk that the global rationalization process may

play out to greater effects in regions outside those hosting the current manufacturing capacity surplus.

Country Specific Conclusions


We summarize below the key observations and conclusions regarding the BICs role on the world renewables stage.

Brazil

Of the BICs countries, Brazil has the greenest energy mix deriving 45% of energy from renewable sources. Hydro

power and biofuels now dominate the mix with wind power ramping and solar power still nascent. By 2020 Brazil’s

government estimates that renewables will provide 46.2% of total energy needs.

In 2011 USD$7.9 billion of renewable energy asset financing, up 20% YoY, was closed for Brazilian projects as the

country added 4 GW of renewables installed capacity to the electricity fleet.

Through 2020, Brazil’s energy plan estimates an aggregate investment in renewables of USD$123 billion adding 50

GW of installed capacity. Incremental employment growth from wind power alone is estimated to add between

94,000 – 225,000 jobs.

Brazil has demonstrated the efficacy of reverse auctions as a tool to rapidly decrease renewables electricity prices.

However, the risks of developers bidding too aggressively leading to failed projects is a threat as naïve and untested

developers win bids in reverse auctions. Such failures present material sector risks and negative implications for

lenders and investors.

Brazil’s substantial biofuels resources create a unique climate change risk for the country and magnify water risk and

the importance of sustainable development practices. If sustainable development methods can be applied and

enforced, Brazil may be able to scale bioethnaol expansion beyond current government plans to triple production by

2020 from 2009 levels. The likely export market for Brazilian bioethnaol the EU27 market.

Brazil’s economy is growing and the country enjoys a budget strength metric of -3.1% suggesting the ability to

sustain a strong commitment to long-term renewables growth.

China

China’s energy profile is the most-carbon rich of the BICs countries. By 2020, China’s policies intend to reduce

fossil-fuel use to 85% of the energy supply from 87% in 2009. Hydropower and wind power now dominate China’s

renewable profile. Solar power is just beginning to be deployed at the gigawatt scale.

Of the BICs countries, China’s growth in renewables dwarfs the combined growth of Brazil and India. In 2011 China

added 35 GW of capacity. China’s 2011 asset financed investment of USD$44 billion in the sector represented 30%

of global renewables investment compared to Brazil’s 5% and India’s 7% contributions. Despite China’s scale

advantage, growth in asset financed renewables was 5%, slowest of the BICs countries.

Through 2020, to meet national targets, China will likely install 340 GW of renewables. We estimate the investment

in incremental wind and solar power alone (200 GW) plus grid investment could total USD$527 billion potentially

creating 1.1 million new jobs.

China uses a range of government established tiered FiTs rather than using reverse auctions to price renewable

power. To manage poorly coordinated provincial renewables growth, the central government has taken control of

wind and solar power project permitting to ensure what is built can be integrated into an overwhelmed transmission

grid.

The greatest risk to successfully exploiting China’s 1,200 GW renewables resources by 2050 is an institutional failure

to orchestrate a rapid and sizeable expansion of the electricity grid. Without urgent grid expansion, renewables

growth in China will likely be constrained bringing into question the ability of the government to achieve a broad

range of energy targets by 2020.

China is experiencing the early stages of desertification. Water stress will become an increasingly urgent constraint

on urbanization. A dramatic increase in sustainable development practices is likely necessary to ensure stability.

Of the BICs countries, China is in the strongest financial position with a rapidly expanding economy and a budget

strength metric of -1.3%. With clear national policy, we believe China is the best positioned of the BICs countries to

continue an ambitious commitment towards transitioning to a low carbon economy.

Country Specific Conclusions


India

Of the BICs countries, India faces the greatest challenges. In 2009 the country derived 73% of energy from fossil-

fuels. Heavy reliance on coal and oil is buffered by the use of combustion biomass, biogas and biofuels that account

for 25% of energy needs. Wind power is materially more broadly deployed compared to solar power.

India added 5.7 GW of renewables in 2011, including 4.3 GW of wind, solar, biomass and small scale hydropower

and an approximate 1.4 GW of large scale hydro. Total asset finance invested in the sector in 2011 was USD$9.5

billion, up 65% YoY.

India has ambitions to achieve incremental growth of an estimated 62 GW by 2020 with 26% of the growth planned

in hydro, 39% in wind and 29% in solar power. India’s planned renewables growth is the most modest of the BICs

countries and is, we believe, hampered by bureaucratic issues, policy inconsistency and complexity and financing

access challenges. If India is successful in achieving planned growth, we estimate that India will invest

approximately USD$21 billion on renewables through 2020.

Basic infrastructure investment of USD $100 billion is also thought necessary by the Government of India to facilitate

renewables growth. Investment in these basic areas includes rail transportation, ports, roads, electricity grid and

logistics systems.

India has embraced the reverse auction model for solar and wind power projects where development is driven by

state policies since FiTs are set locally. A lack of sophistication and poor program formulation lead to less

experienced developers placing unrealistically low bids that are proving difficult to execute upon once awarded. This

“winner’s curse” problem has created a “bid, not built” situation in India. Program revisions have been undertaken to

address these shortcomings. It is unclear how effective the changes will be.

The greatest challenges we see facing India are twofold: bureaucratic processes are not efficient and the local

financing institutions are not as familiar with renewables financing structures or risks as are international investors.

Recent unexpected non-renewal of critical accelerated depreciation and analogous supplemental tariffs (the GBI) are

likely to dramatically slow wind power growth in India.

India is a highly water-stressed country and long-term growth of the biofuels sector may prove challenging unless

highly sustainable solutions are developed.

India’s financial position is the weakest of the BICs countries with a budget stress metric of -5% placing it in closer

proximity to weakened OECD countries than her BICs peers. With a slowing economy and political gridlock, it is

unclear how predictably India can sustain commitment to the country’s renewables expansion plans.

Emerging Markets: Brazil


1. Emerging Markets: Brazil Energy Overview

With a population of approximately192 million in 2010, Brazil is the ninth largest energy consuming country in the world and

the third largest in the Western Hemisphere after the US and Canada5. Brazil is the largest country in Latin America and a

political leader in terms of international trade. Growing at 7.5% YoY, Brazil’s 2010 GDP (PPP-based, 2005) was $1,907 billion,

making it the ninth largest economy in the world.

In recent years, most local renewable energy companies and conventional energy firms in Brazil have been taken over by

large privatized national companies. As a result of this, Brazil has a concentrated energy market with Petrobras controlling

most of the oil and gas drilling and Electrobras controlling much of the hydro, nuclear and wind companies. According to the

Global Energy Network Institute, these two companies hold the key to Brazil’s shift to more sustainable energy alternatives6.

Figure 12: Brazil’s primary energy mix 1990-2009

Source: CEIC, World Bank and DBCCA analysis, 2012

Brazil’s energy requirements are supplied primarily through combustion of fossil fuels, hydropower and biomass as shown in

Figure 12. Compared to China and India, Brazil’s energy mix is already remarkably green as it derives 43% of total energy

from renewable sources including hydro power (14%), sugar-cane products (ethanol from sugar and combustion fuel from the

sugarcane processing residue known as “bagasse”) (19%) and firewood (10%), as presented in Figure 13.

5 EIA, 2011

6 Global Energy Network Institute, “Renewable Energy Potential of Brazil,” 2010

0

10

20

30

40

50

60

70

80

90

100

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Perc

en

t o

f M

ix

Fossil Fuel Biomass and Waste

Biofuel Hydropower and Nuclear Energy

Other Renewables (Wind and Solar)



Figure 13: Comparative energy supply mixes: China, India and Brazil

Source: International Energy Agency World Energy Outlook 2011; Bloomberg New Energy Finance, 2012 and Agencia Nacional de Energia Electrica (ANEEL); DBCCA analysis, 2012.

The development of new fuel sources in Brazil is influenced by key factors including the country’s huge potential for

hydropower, the founding of its national oil company in 1953 and the 1979 oil crisis which stimulated development of

sugarcane products as an alternative fuel source. Natural gas as a primary energy source has been hampered by a

combination of cost of infrastructure, competition from fuel oil and the lack of a supportive regulatory framework7. Similarly the

country’s nuclear program never really got off the ground owing to concerns about energy security and restrictions on project

financing. Recent oil and gas discoveries in Brazil’s coastal waters that could double or even triple the country’s proved

reserves may create future shifts Brazil fossil fuel and biofuel trajectories. However, with discoveries just months old, it is too

early to say much more than simply to acknowledge them.

Figure 14 shows that total primary energy production in Brazil has increased by close to a third in the last decade, due to

sustained economic growth. Total energy production has increased particularly in oil and ethanol. From 1990-2009, Brazil’s

real GDP grew at an average annual compound rate of 2.38% and energy consumption grew at 2.87%. Total energy

consumption per unit of GDP (energy intensity), measured at purchasing power parity is approximately 31% lower than the

current world average. Unlike in fellow emerging economies in China and India, Brazil’s energy intensity is, for the time being,

stable. This suggests substantial potential for further efficiency programs.

Figure 14: Brazil’s energy trajectory

7 Deloitte, “Brazil’s Energy Matrix and Prospects for Energy Integration with South America,” 2010.

Coal67%

Oil17%

Natural Gas3%

Nuclear1%

Hydro2%

Biomass9%

Others1%

Coal42%

Oil24%

Natural Gas7%

Nuclear1%

Hydro1%

Biomass25%

Other0%

Coal1%

Oil42%

Natural Gas9%

Nuclear1%

Hydro14%

Biomass29%

Others4%

China (2009)2,271 Mtoe

India (2009)669 Mtoe

Brazil (2010)254 Mtoe




However, so long as Brazil can continue to expand renewable energy in proportion to overall energy growth, we see less

pressure for the dramatic energy intensity improvements in Brazil compared to other more carbon-heavy economies.

Brazil is unique as the largest producer of biofuels among the BICs nations. It launched its ethanol scheme in the 1970s and

domestic biofuel production has been a central component to the nation’s energy policy ever since. Use of bio-ethanol is

facilitated by the widespread availability of flex-fuel vehicles, where drivers have the ability to choose any mix of regular

gasoline and bio-ethanol at the pump, depending on relative prices. Use of ethanol is also driven by a mandatory ethanol

blending regime coupled with tax reductions for pure ethanol.

In terms of electricity, Brazil’s overall consumption per capita is 16% lower than the world average, but 45% higher than the

average of non-OECD nations. Electricity represents 17% of final energy consumption, and this share is increasing slightly. In

Figure 15, below, we have extracted electricity use from the end–use segments and shown it on a consolidated basis as an

end use of energy. Transportation consumes the largest shares of Brazil’s energy.

Figure 15: Comparative energy consumption mix for Brazil

-

200

400

600

800

1,000

1,200

1,400

-

50,000

100,000

150,000

200,000

250,000

300,000

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

En

erg

y U

se p

er

Cap

ita a

nd

per

GD

P

To

tal E

nerg

y U

se (

kT

oil e

qu

ivale

nt)

Total Energy Use

Energy Use per GDP (constant 2005 PPP)

Energy Use per Capita



Source: International Energy Agency; Bloomberg New Energy Finance, 2012; Agencia Nacional de Energia Electrica (ANEEL) and DBCCA analysis, 2012.

Brazil has an installed power capacity of 112 GW (2011) and the country is heavily reliant on hydropower, representing 71.5%

of installed capacity as can be seen in Figure 16. Fossil fuels (excluding biomass) represent 19.6% of installed capacity.

Based on 2009 IEA data, Coal-fired capacity represents approximately 2% of total installed capacity; oil-fired capacity

represents approximately 6%; and natural gas represents approximately 8%. Biomass-fired generation, accounting for 6% of

installed capacity, is fueled primarily with bagasse (waste from sugar cane processing) and black liquor (residue from the pulp

and paper sector). Nuclear installed capacity represents approximately 2% and 1.2 GW of wind power accounts for the

remaining 1%. Solar power installed generation capacity is negligible in Brazil.

Figure 16: Brazil electricity installed capacity by source, 2011 – Total 112 GW

Source: Bloomberg New Energy Finance, 2012; Agencia Nacional de Energia Electrica (ANEEL) and DBCCA analysis, 2012

Industry29%

Transport33%

Building9%

Other12%

Electricity17%

Industry

Transport

Building

Other

Electricity

Large Hydro67.0%

Small Hydro4.5%

Fossil19.6%

Nuclear1.8%

Biomass6.1%

Wind1.0%



From an actual electricity production (vs. installed capacity) perspective, Brazil has increased power generation at an

approximate 4% average annual rate since 1990. Figure 17 shows that 79% of electricity production is derived from

hydropower (large and small scale). Natural gas, a low-carbon fuel compared to coal and oil, produced 7% of electricity in

2011. Utilization of coal-fired generation is low with coal accounting for only 1% of electricity production.

Figure 17: Brazil electricity generation by source, 2011 – Total 437,712 GWh


Although Brazil is a global leader in hydropower for electricity and this is by far the dominant source of power generation in the

country, more recently the country has begun to engage in the deployment of wind power, as discussed in more detail in the

following section. Solar power development has yet to take off.

Hydro79% (76%

Large Hydro)

Biomass6%

Wind1%

Natural Gas7%

Oil3%

Coal1%

Nuclear3%



1.1 Renewables

Current Status

Renewable power has always been a visible element of Brazil’s energy and electricity supply owing to its vast natural hydro

resources. Additionally, more rapid adoption of renewable energy helps with security of energy supply and carbon emission

reductions. Total renewable installed capacity in 2011 in Brazil was: 88GW as Figure 18 shows.

Figure 18: Composition of renewable installed capacity in Brazil, 2011 - Total of 88 GW


In 2010 the electricity production from renewable sources increased by a significant 5% YOY in Brazil, as a result of growth in

wind and biomass-fired thermal generation. Wind electricity production accounted for the highest growth with a very

substantial increase of 50.5% followed by biomass at 18.1%. However as a result of disproportionally faster growth in the use

of traditional fossil fuel thermo-electric plants in 2010, the proportion of power from renewable sources decreased from 90.5%

in 2009 to 87.1% in 20108.

8 Energy Policy in Brazil, “Preliminary Report on Brazil’s 2010 Energy Consumption” http://www.energypolicyinbrazil.com/2011/10/preliminary-report-on-brazils-

2010.html 2011

Large Hydro75 GW, 85.3%

Small Hydro5 GW, 5.7%

Suger Cane5 GW, 5.9%

Black Liquor1 GW, 1.5%

Wood0.3 GW, 0.3%

Biogas0.1 GW, 0.1%

Wind1 GW, 1.3%

http://www.energypolicyinbrazil.com/2011/10/preliminary-report-on-brazils-2010.html

http://www.energypolicyinbrazil.com/2011/10/preliminary-report-on-brazils-2010.html



Figure 19: Asset financed renewables projects, 2007-2011

Source: Bloomberg New Energy Finance and DBCCA analysis, 2012

Figure 19 shows that in 2011, Brazil’s renewables projects were financed with approximately USD$8 billion of asset

financings, down from a record of over USD$12 billion in 2008 as Brazil rapidly added biofuels capacity. In restricting our data

screen to just asset finance (as opposed to private or public equity) we believe this gives the most accurate representation of

investment funds flowing into actual projects rather than a mix of projects and corporate development programs.

Hydropower

Large hydropower dominates the base of renewable installed capacity in Brazil. Total hydropower potential in Brazil is

estimated to approximate 260 GW with the greatest undeveloped potential in the north of the country9. The hydropower

industry is left with the legacy of the power shortage crisis of 2001 which arose from record dry weather and underinvestment

in other forms of generation capacity. Additionally, environmental concerns cause major delays in hydropower projects and

long distances to power demand centers have slowed hydropower projects development in the north of Brazil. Obviously all

hydropower development needs to be conducted in an environmentally sensitive way.

Wind Power

Brazil’s wind market grew by 326 MW in 2010, bringing total installed capacity to 931 MW and the country reached 1 GW of

installed wind capacity in May, 2011. This sector has only recently begun to expand rapidly following the implementation of

reverse auctions for energy, discussed below in the Policy section,

In August and December of 2011 Brazil held auctions to procure long-term energy contracts from a combined 5.1 GW of new

electric generation capacity. Wind power developers dominated these auctions, with projects representing 2.88 GW, or 56%

of awarded capacity; moreover, average bidding prices resulting from these auctions were strikingly low – from $62/MWh (in

the August 2011 auction) to $57/MWh (in the December 2011 auction). If constructed, these wind power projects will more

than triple Brazil’s installed wind power generating capacity at a $/MWh cost 62-64% below what Brazil had been paying new

wind power projects under its feed-in-tariff PROINFA program. As we discuss later in this section, whether or not all this

capacity will be actually developed and commissioned remains to be seen given the potential for problems that could arise

from overly aggressive bidding.

9 Deloitte, “Brazil’s Energy Matrix and Prospects for Energy Integration with South America,” 2010

-

2

4

6

8

10

12

14

2007 2008 2009 2010 2011

Co

mp

lete

d A

ss

et

Fin

an

cin

g, $

B

Other

Biomass&Waste

Biofuel

Solar

Wind

Small Hydro



History of Brazil’s Energy and Capacity Auctions

On the theory that short-term market signals provided insufficient incentives to invest in new generation capacity, in 2004

Brazil’s energy regulator - the Agencia Nacional de Energia Electrica (ANEEL) – began holding auctions to procure long-term

energy contracts. These “reverse auctions” essentially follow a three-step process:

1. To start the process, the regulator establishes a $/MWh ceiling energy price for all projects irrespective of

technology. Projects are asked to pre-register their initial $/MWh bids and the ceiling price is used to filter out

technologies whose bids are uncompetitive. This initial phase is used to facilitate price discovery by the regulator.

2. Remaining projects progressively bid down the price, as the amount of energy contracted for rises to meet the

regulator’s target amount.

3. In the final phase, the regulator satisfies the target energy demand by awarding bids to the cheapest contracts. The

format is “pay-as-bid,” meaning that successfully bid projects receive the $/MWh price that they have bid (rather than

all projects receiving a uniform clearing price).

While the fixed-price contracts resulting from these auctions vary in length, the contracts of interest to this paper are 20-year

power purchase agreements (PPAs). Projects are expected to begin generating electricity three to five years from execution

of the auction contract10

.

To discourage submission of unrealistically low bids, Brazil levies penalties for non-compliance ranging from 0.001% to 10%

of the announced investment in each project. Brazilian regulators have, however, traditionally been disinclined to impose

such penalties; this creates risk that contracted projects will not actually be constructed – a topic discussed in detail below.

Wind Power Enters (and Begins to Dominate) Brazil’s Auctions

In response to a projected decrease in the share of renewable electricity in total generation, in December 2009 ANEEL held

its first-ever wind-only auction. The initial auction awarded 20-year, fixed-price PPA contracts for 71 different wind energy

projects (with a combined capacity of 1,800 MW) at an average price of $89/MWh. In August 2010 wind power projects moved

from a “wind only” auction to a “clean energy only” auction in which wind projects competed with small hydro and biomass

units. The auction resulted in the award of contracts for 1,519 MW of wind power (representing 50 projects) at an average

price of $78/MWh. Developers with the most contracted capacity were Impsa-Energimp and Iberdrola.

In August 2011, clean energy generation projects (including wind power) for the first time competed directly with non-

renewable (such as natural gas-fired units) and large hydro projects in government auctions11

. Wind power emerged as the

major winner in these auctions, claiming over half of new contracted capacity (2.88 GW) at an average price of $62/MWh.

The August 2011 auction represented the first time that Brazilian wind projects had under-bid natural gas-fired projects (two of

whom secured contracts for $65/MWh).

Given the dramatic declines in bid-winning wind power prices, wind power projects continued to dominate Brazil’s most recent

auction in December 2011. Of 1.2 GW of capacity qualified for bidding – a mix of wind power, large-scale hydropower and

biomass - wind projects won 81% (976 MW) of total contracted capacity at an average price of $57/MWh as shown in Figure

21 – nearly 40% below the average price in the August 2009 “wind only” auction. Projects slated for the northeast of Brazil in

the states of Bahia, Ceara and Rio Grande do Norte will account for the majority of the 976 MW of wind capacity awarded.

Collective investment in the wind projects in these areas according to Bloomberg New Energy Finance is estimated to

approximate BRL 3 billion (USD$ 1.6 billion). As seen in Figure 20, wind power participation in the December 2011 auction

represented the vast majority of all renewables projects being proposed. Moreover, in Brazil’s next energy auction (now

scheduled for late 2012, with a ceiling price of $65/MWh), wind is expected to play a meaningful role. In these prospective

10

Technically, Brazil holds two kinds of energy auctions: one for primary energy (termed “energy” auctions), and one for energy from reserve capacity (termed “capacity”

auctions). This analysis considers the two kinds of auctions jointly. 11

One for primary energy and one for reserve energy.



auctions, proposed wind projects account for approximately one-half of the 52.2 GW approved for bidding. Winners of the

forthcoming auctions will be required to have commissioned their projects by 2015 and 2017, respectively.

Figure 20: Total capacity and number of registered versus contracted projects participating in the A-5 energy

auction, 20 December 2011 (MW)

Source: Bloomberg New Energy Finance, Empresa de Pesquisa Enérgetica (EPE)

Figure 21: Brazil A-5 auction average contract price by technology, 20 December 2011

Average Contract Price ($/MWh) Contracted Capacity (MW)

Large Hydro $49.47 135

Biomass $53.76 100

Wind $56.90 976.5

Source: Bloomberg New Energy Finance; Câmara de Comercializacão de Energia Elétrica (CCEE)

Bio-energy

Brazil’s use of bio-energy can be segmented into two categories: (1) Biomass for power generation and (2) Biofuels, including

bio-ethanol and bio-diesel.

Brazil’s biomass power generation capacity largely consists of co-generation at sugar mills using sugarcane bagasse and at

pulp and paper mills using black liquor as feedstocks. This type of power generation has been increasing steadily with

installed capacity reaching ~7 GW by the end of 2011.

When biofuels are combined with biomass, these contribute more to Brazil’s primary energy mix than hydropower as depicted

in Figure 13, earlier in the report. This demonstrates the extent to which biofuels have penetrated Brazil’s energy mix, where

ethanol is often competitive with traditional petroleum. Brazilian ethanol has also been a major – although fluctuating – export



product as it is produced very efficiently at low cost and low energy intensity – compared, for example, to corn ethanol

produced in the US.

Bio-ethanol is certainly integral to Brazil’s energy needs, and the increasing role of flex-fuel vehicles in Brazil means that bio-

ethanol will play an even greater role in the nation’s energy mix. Brazil has both the second largest national biofuels

production level and end-use market and is first in terms of resources readily available for further expansion. Recent historical

ethanol production volumes are contained in Figure 22, below.

Figure 22: Recent Brazilian bio-ethanol production

(Million Liters) 2006 2007 2008 2009 2010

Beginning Stock 2,743 3,373 4,829 5,783 4,048

Production 17,782 22,557 27,140 26,105 27,965

Imports 0 4 0 4 76

Total Supply 20,525 25,934 31,969 31,893 32,089

Exports 3,429 3,533 5,124 3,296 1,906

Consumption 13,723 17,573 21,062 24,548 24,267

Fuel 12,698 16,203 19,584 22,823 22,162

Other Uses 1,025 1,370 1,478 1,725 2,105

Ending Stock 3,373 4,829 5,783 4,048 5,916

Production Resources

Capacity 27,500 32,540 38,300 35,600 41,360

Capacity Utilization (%) 64.7% 69.3% 70.9% 73.3% 67.6%

Feed Stock Use (1,000 MT)

Sugarcane 215,196 269,645 335,188 346,070 342,566

Source: Government of Brazil, USDA – Sao Paulo and DBCCA analysis, 2012

Brazil’s ethanol industry faces a complicated series of raw materials and market dynamics not faced by other renewable

energy sources. First, on the supply side, Brazil has an expansive domestic sugarcane industry and it is influenced by an

arbitrage relationship between the value of the cane as a sweetener versus the value as a fuel feedstock. Sugar refiners

typically plan for an approximate 40%/60% split between sugar refining and bio-ethanol distillation. Once plants are set up for

the estimated “sweetener/alcohol” split, it is not practical to reconfigure operations mid-season in response to unexpected

sugar and fuel market shifts. Should producers chose to expand in future seasons, it is cheaper to add capacity to existing

operations compared to building entirely new complexes. New distillation facilities cost approximately USD$120-150/ton of

cane crushing capacity while expansion of existing capacity costs approximately USD$55 - USD$75/ton.

On the end-market side, the nature of flex-fuel vehicles makes Brazil’s bio-ethanol market complex as the vehicles can run on

either gasoline or a range of ethanol blends up to 100% ethanol. As a result the preference between fuels is driven by relative

fuel costs. Generally speaking, when ethanol is priced below 70% of the price of gasoline, drivers typically opt for ethanol. At

prices above 70% of the gasoline price, drivers will typically opt for gasoline. This sensitivity is because of the relative energy

content of the two fuels, whereas gasoline has a higher energy content per unit than ethanol, thereby allowing greater driving

range for the same quantity of fuel.



Bio-Diesel

Brazil’s bio-diesel industry uses “first generation” technology deriving the necessary lipids from soybeans (84% of feedstocks),

animal tallow (15%) and cottonseed (1%). The use of second-generation feedstocks (e.g. Jatropha) remains in

developmental stages. Production is heavily regulated by the national government with only 67 plants permitted for operation

as of May 2011 with an additional 27 projects in various phases of the approval or construction process. Bio-diesel production

costs approximate R$2.40/litre of which raw materials account for 75%. This makes the costs of bio-diesel Brazil’s second

biofuel, sensitive to agriculture prices for soybeans and cottonseed. Bio-diesel refining capacity, as of July 2011, was 2.3x

current regulated demand.

Figure 23: Historical bio-diesel production data

(Million Liters) 2006 2007 2008 2009 2010

Beginning Stock 0 0 45 90 135

Production 69 404 1,167 1,608 2,397

Imports 4 4 5 4 9

Total Supply 73 408 1,217 1,702 2,541

Exports 4 3 1 3 8

Consumption 69 361 1,125 1,565 2,462

Ending Stock 0 45 90 135 71


Capacity 300 1,800 3,600 4,350 5,837

Capacity Utilization (%) 23% 22% 32% 37% 41%

Source: Government of Brazil, USDA – Sao Paulo and DBCCA analysis, 2012

Solar

To date, Brazil’s energy policies have not focused much attention on developing solar power due to concerns over high costs.

Consequently Brazil has only approximately 100 MW of solar PV installed. Looking ahead, solar energy is expected to play

an increasingly important role in Brazil’s power sector, although its current contribution is negligible. Unpublished estimates

suggest that solar potential in Brazil could be four to five times the wind potential. Wind is being explored first as it is currently

a cheaper form of power, but solar, we believe, will emerge as a viable option from 2015 onwards when costs are likely to be

more competitive. As we discuss later in the Forecast section, drafting of solar legislation is now underway.

Policy Support

Brazil has a wide range of policy tools used to support renewables. Some policies (e.g. biofuels) date back to the 1970’s

while others (e.g. wind power) are more recent. In addition to policies, FiTs are determined through reverse auction pricing

processes providing developers with pricing transparency and longevity. Brazil has a range of agricultural policies to aid

sustainable sugar cane development and is now drafting solar power policies to be implemented in the coming year.

Complimenting explicit policy and legislative action is the role of the state development bank, Banco Nacional de

Desenvolvimento Economico e Social (BNDES), whose lending activities dominate the Brazilian renewables sector. While the

Brazilian government does not have explicit “local content” rules, a “soft” form of such practices does exist as a necessary

condition for BNDES funding.



Electricity Tenders Overview

In 2004, Brazil began using auctions with government established FiT prices to encourage wind power development. By 2009

with experience and price refinement, Brazil embarked on the use of reverse auctions to obtain a desired amount of energy at

lowest possible price. This model has proven quite successful in terms of eliciting from the market meaningful volumes of

generating capacity at significantly lower prices, though presents implementation risks.

Tenders or reverse auctions are a relatively new policy approach to renewable energy, in which sellers compete to obtain

power contracts from buyers. As the typical auction process is reversed, the auction starts with a ceiling price and a set

amount of power capacity to be installed. The price typically decreases over time as sellers competitively bid below each

other until the desired amount of capacity has been tendered at acceptable prices.

In terms of reducing costs on incremental expansion, reverse auctions have significant potential, yet still have drawbacks.

Since bidders are invited to offer incremental energy at the lowest price they can afford while still making a profit, the winning

bid price simply reflects the marginal price paid by the utility for the next (nth

) unit of energy. Utility infrastructures require

reserve capacity in order to assure continuity of service and thus a reverse auction results in a marginal price of energy that

does not reflect the need for that necessary subsidization of reserves. In other words, reverse auction pricing can result in an

illusory low cost of energy. Further, the competitive bidding process does pose considerable financing and deployment risks

for projects. In order to appropriately mitigate these risks, reverse auctions should have three key design features:

1. Establish strong penalties for non-deployment by a winning bidder Brazil requires 5% of total project costs to be

deposited up front by winning bidders and imposes certain fines in the case of failure to comply with tender rules, but

Brazil has historically been lax in imposing such penalties;

2. Establish requirements for resource assessment as well as demonstrable experience in the operation of renewable

projects;

3. Focus only on mature technologies that present low variability in costs (i.e. this policy tool would not currently be

suitable for technologies such as solar)".

Brazil’s 2010 and 2011 wind tenders provides a clear example of the pros and cons of using tenders to drive wind energy

deployment, with these tenders only meeting one of the three key design features – a focus on mature technologies. In terms

of penalties, Brazil requires 5% of total project costs to be deposited up front by winning bidders and imposes certain fines in

the case of failure to comply with tender rules. Brazil, however, has typically been lax in imposing these penalties. Also

several projects appear to be based on excessively optimistic wind resource scenarios for novel and untested equipment

deployment, and although the government imposes fines for projects that provide less than 90% of the annual contracted

energy, there are insufficient requirements or evaluations of how wind resource assessments are conducted.

Pros and Cons

The success of wind power bids in Brazil’s latest auctions led to an increasing interest in auction mechanisms (or “tenders”)

as a means to promote investment in low-carbon generation technologies. Proponents attribute $57/MWh contract prices for

wind to the competition and price discovery that auction mechanisms purportedly create. Further, they cite such prices as

evidence that auctions can encourage the deployment of low-carbon technologies by being more cost-effective than policy-

based methods such as a government-set feed-in-tariffs (FiT). Historically, however, in some markets auctions have been

“bid” but then not necessarily “built” as bidders find when it comes to execution they cannot deliver at the agreed-upon price.



These low prices have implications for both the cost-effectiveness of capacity auctions as a policy mechanism and the

economic competitiveness of wind generation relative to other resources. It therefore becomes critical to determine how the

Brazilian bidders managed to achieve winning price of $62-$57/MWh bids. Market analysis has shown the importance of wind

capacity factors. Specifically, our analysis further highlights the role of loans from BNDES in reducing financing costs for

participants in Brazil’s energy auctions. We find that replacing BNDES loans with commercial debt increases the levelized

cost of energy (LCOE) of a typical Brazilian wind project by at least 23%. Indeed the low bid cap that Brazil’s energy regulator

has set for its next energy auction tentatively rescheduled to summer 2012 – $65/MWh, $15/MWh below what we calculate as

the unsubsidized LCOE of a favorably-sited wind power project in Brazil based on commercial loans – underscores the strong

influence of BNDES debt on the contract prices in Brazil’s energy auctions.

Improving financing terms for developers of low-carbon generation is a legitimate and valuable focus of government policy.

Many other countries have “green development banks” such as KfW, the EIB, potentially the UK Green Bank and Australian

CEFC. The role of BNDES loans in driving the success of wind projects in Brazil’s energy auctions, however, yields the

following conclusions: 1) unsubsidized “grid parity” for wind generation remains in most markets a work in progress and

certainly requires very high capacity factors; and 2) low-cost debt can effectively stimulate wind developers to bid into auctions

at attractive prices – but still does not necessarily ensure that the equity returns on such projects will be sufficient for

developers to carry the projects to fruition.

Indeed, as a study by BNEF last August showed12

, the equity returns on some projects bid into the auction are such that there

is still considerable risk that some will not be built.

Will Bid = Built? Problem of Potentially Inadequate Equity Returns

Even given Brazil’s terrific wind resource, the August and December 2011 average contract prices for wind generation of $57-

62/MWh are strikingly low. They represent a 30% reduction from the average contract price of $87.6/MWh that wind

developers secured in Brazil’s A-3 2009 auction.13

Moreover, these prices are below the $70/MWh level that (1) analysts

estimate as a mid-range scenario for the levelized cost of energy (LCOE) from wind generation in Brazil; and (2) is thought to

have been the “minimum bid price” contained in contracts between Brazilian wind developers and their original equipment

manufacturers (OEMs).14

Some developers may be able to renegotiate their supply contracts so that their OEMs accept lower

margins; others may succeed in achieving unprecedented capacity factors (e.g. 55-60%) via use of such novel tactics as

placing high-efficiency turbines (designed for sites with low wind speeds) at sites with high wind speeds. Uncertainty about

such outcomes, however, gives rise to strong prima facie suspicion about the level of equity returns $57-62/MWh contracts

will ultimately yield for project developers.

Analysis from Bloomberg New Energy Finance (BNEF) confirms this concern. Firstly we assume a cost of debt of 8.75% is

used, which relies on state-sponsored BNDES loans, a key dimension of Brazilian policy we discuss later in this section.

Evaluating the 78 wind projects contracted in Brazil’s August 2011 A-3 and capacity auctions BNEF calculates that 32 of

these projects – representing 870 MW of new capacity (40% of total capacity tendered) – will deliver an annual return to

equity of less than 10%.15

Annual equity returns on many of these projects appear to be below 7.5%. Even taking into

account the burden of Brazil’s non-compliance penalties, returns of this magnitude may provide inadequate incentive for

developers to actually construct their projects – hence recreating the specter of “bid but not built” projects that has played out

in the wake of capacity auctions in the UK and elsewhere. Anecdotal evidence for the unattractive economics of investment in

wind generation at Brazil’s recent regulated tariffs can be found in the announcement of Desenvix Energias Renovaveis SA –

12

“Brazil’s 2011 Tenders: Low Prices, High Risks,” E Tabbush et al, Bloomberg New Energy Finance, 25 August 2011 13

By contrast, from 2009-2011 global wind turbine prices declined by between 17% and 28% depending on model status. 14

“Brazil’s 2011 Tenders: Low Prices, High Risks,” E Tabbush et al, Bloomberg New Energy Finance, 25 August 2011 15

Yielding an annual equity return above 10% seems to require a project to have an annual capacity factor of at least 45%; by comparison, for onshore wind in the US, the

Energy Information Administration assumes an average annual capacity factor of 34%.



Brazil’s leading renewable energy developer – that it will forego bidding wind projects into Brazil’s March 2012 auction

because “the returns are far too low for us.”16

Figure 24: Estimated “Winning Bid” equity returns, December 2011 A-3 auction versus capacity factors

Note: Assumes CAPEX costs of nearly $1.9m/MW, fixed OPEX costs of $50,000 per year as well as a $3-$6/MWh hedge structure, 70:30 gearing ratio and an 8.75% cost of debt. Annual inflation fixed at 5% for 20 years. Source: Bloomberg New Energy Finance, 2011.

BNDES debt – the 600 bps subsidy embedded in every wind power bid

From a policy perspective, BNDES plays a key role fostering renewable energy development. The most powerful policy lever

at the bank’s disposal is the ability to provide loans at interest rates that are materially below market-based rates. The second

lever is the 60% local content rule that projects must abide by in order to qualify for BNDES financing.

As a state-owned lender, BNDES is able to provide low-interest loans (“soft dollar” loans) in order to stimulate growth of target

industries such as alternative energy. Since 2000 BNDES has committed roughly $10 billion of loans to support development

of Brazil’s wind resource (Figure 25), based on data provided by BNDES, we calculate another USD$4.6 billion to be

committed through 2013. BNDES loans to Brazilian wind developers appear to carry interest rates 500-750 basis points (bps)

below prevailing commercial rates. Based on current commercial rates for Brazilian wind developers (14% - 15% per annum),

BNDES debt reduces borrowing costs for eligible wind projects by roughly 40%. Nearly every wind project that has bid into

any of Brazil’s auctions has done so with the benefit of debt from BNDES.17

16

“Brazil Desenvix Shifts from Wind to Hydro as Power Prices Fall,” Bloomberg New Energy Finance, 15 Feb 2012, https://www.bnef.com/News/53016. Renova cited a

price of $76/MWh as the floor beneath which returns on wind development became uncompetitive. 17

Developers of other low-carbon technologies (e.g. biomass and small hydro) can access BNDES financing on terms similar to those available for wind projects; hence

BNDES financing is similarly ubiquitous in the bids from developers of these technologies participating in Brazil’s regulated auctions. BNDES low-cost debt is generally not available, however, to developers of more mature technologies such as natural gas-fired turbines or large hydro facilities.

-5%

0%

5%

10%

15%

20%

30% 35% 40% 45% 50% 55% 60%

A-3 Reserve

High

deployment risk

Capacity factor

https://www.bnef.com/News/53016



Figure 25: BNDES wind power asset financing In Brazil

Source: Bloomberg New Energy Finance, 2012 and DBCCA analysis, 2012

BNDES Debt as a Driver of low PPA Prices for Wind Power

To assess the impact of BNDES’ below-market lending rates on project economics, we analyzed a hypothetical “typical” wind

power project similar to those winning bids in recent auctions. The impacts of the BNDES loans appear to us as significant in

their ability to reduce LCOE (Figure 26).

In our analyses a “base case” LCOE is established taking into account the benefit of BNDES debt.18

The LCOE represents

the present value of a project’s lifecycle costs (construction, financing, operating, fuel, decommissioning) divided by the

present value of its lifetime generation; since the resulting $/MWh cost includes the costs of equity and debt, it can be thought

of as the PPA price required for a project to deliver a given level of return to its investors. Our base case assumptions are

then modified to reflect the impact of debt financing on commercial terms (i.e. approximately a 600 bps premium relative to

BNDES rates). We find that use of market-rate debt increases the LCOE of a Brazilian wind project by at least 23%.

Figure 26: BNDES financing impact on LCOE

With BNDES Debt Without BNDES Debt

With Equity Cost Constant Risk Adjusted Equity Cost

Debt Cost 8.75% 14.75% 14.75%

Equity Cost 12.00% 12.00% 18.00%

Capacity Factor 50% 50% 50%

LCOE (USD$/MWh) $65 $80 $95 DBCCA analyses (2012) using California Energy Commission Levelized Cost of Energy model, 2010.

Given the capital-intensity of wind projects, the magnitude of this shift is unsurprising. The resulting LCOE of $80/MWh is

higher than any of the prices recorded in Brazil’s August or December 2011 auctions (which was $65/MWh price for energy

from two combined-cycle natural gas units recorded in August 2011); it is also above the $65/MWh price ceiling that Brazil’s

energy regulator has set for Brazil’s forthcoming auction in March 2012. This suggests that – even with excellent capacity

18

Note that (1) the LCOE of a wind project is highly sensitive to the quality of its wind resource, as measured by its site’s “capacity factor”; and (2) variance in capacity

factors across different sites can lead to a wide range of LCOE values for wind projects (whether in Brazil or elsewhere). That said, calculating the economics of a “typical” project can still illuminate the major influences on the competitiveness of wind generation.

0

1,000

2,000

3,000

4,000

5,000

6,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

Am

ou

nt

Fin

an

ced

, U

SD

bil

lio

ns

BNDES New Project Financing (Completed and Committed)



factors – market-rate debt would price Brazilian wind out of the very auctions that is has so thoroughly dominated over the

past year.

Implications of Pervasive BNDES Lending in Brazil’s Regulated Auctions

Compared with financing available to wind project developers in the US and Europe, loans that carry an 8.75% annual coupon

are hardly “cheap debt”. That said, in the case of Brazil, such loans are very much “below-market” debt. Recognizing this has

implications for how one interprets the low contract prices for wind recorded in Brazil’s recent regulated auctions. We concur

with BNEF that such low prices may indicate modest equity returns for many developers who have bid into such auctions –

and thus presage a wave of project defaults (similar to circumstances following regulated capacity auctions in other countries).

Moreover, we believe low contract prices for wind reflect in large measure the ~600 bps savings in annual debt costs enabled

by BNDES loans to wind developers.19

Had wind developers been forced to bid into Brazil’s recent regulated auctions using

commercial debt finance, it is likely that they would have won contracts for a far smaller volume of energy – and at prices well

above $57-62/MWh. It also encourages developers to seek the very highest debt ratios they can.

This latter conclusion relates to lessons one draws from Brazil’s recent auctions for (1) the cost-effectiveness of auction

mechanisms as a means to promote deployment of renewable resources; and (2) the cost-competitiveness of wind generation

relative to other generation sources. The appropriate lesson appears to be that high capacity wind power can compete

effectively with conventional generation sources – provided that it has stable access to debt financing on terms that are

favorable (or, at least, not as punitive as a ~15% annual coupon). This suggests, in coordination with outlays from a “green”

development bank, large-scale auctions may be well-suited to promote more mature renewable technologies such as wind

power (particularly in markets that have developers with established track records).

The auctions have proven quite successful in terms of stimulating wind power development at lower prices, though execution

risks remain. With slower macro economic growth now forecast in Brazil, the auctions may have become a victim of their own

success. On 26 March 2012, BNEF20

reported that with a possible unneeded 2,500 MW’s of wind power capacity scheduled

for commissioning by 2015, 2012 auctions may be postponed should six planned thermal power stations be built.

Support for solar and biofuels

Solar developers are keen to tap Brazil’s power market but have not been allowed to compete in the government power

auctions largely because government agency EPE has traditionally viewed the technology as too costly. This could change

as EPE has proposed to the Ministry of Mines and Energy that solar to be included in next year’s power auctions. The most

effective way to ensure multiple renewable sectors win bids however may be to hold technology-specific tenders. In March

2012, the national government announced plans to begin drafting legislation to encourage solar power development. Official

details are not yet available, though news reports suggest the support mechanisms may include an 80% profits tax discount

on solar power purchased and resold by utilities. Net metering for both residential and commercial customers is also cited as

a possible action.

Brazil’s policies toward biofuels have been in place since 1975 when “gasohol” (ethanol-gasoline blends) was first promoted.

By 1976 mandated blending requirements were in place and by 2007 the mandatory blending rate had increased to a

maximum of 25% and a minimum of 20%. By 2009, 94% of vehicles sold in Brazil were “flex fuel” capable. To date, Brazil’s

biofuels activities are dominated by sugar-based ethanol with biodiesel remaining a developmental technology.

Biofuels regulation has been recently streamlined. Initially, the Ministry of Agriculture (“MAPA”) supervised the upstream cane

farming activities and the National Agency for Petroleum, Natural Gas and Biofuels (“ANP”) supervised the distillation and

19 It bears repeating that such BNDES also extends such low-cost financing to other alternative technologies such as biomass and small hydro. 20

“Brazil May Not Auction Power Contracts in 2012 Due to Oversupply,” Stephen Nielsen, BNEF, 26 March 2012



downstream processes. In 2011 ANP assumed supervisory responsibilities for both upstream and downstream biofuels

activities. One proposal now being considered is minimum 2 year supply contracts between distillers and fuel distributors.

Under consideration also are rules that would require holding minimum seasonal-end bio-ethanol stocks of 5% to smooth fuel

deliveries in the face of uncertain timing for the commencement of the next cane crushing/refining cycle.

In 2005, Brazil's Mines and Energy Ministry enacted a law establishing the requirement for B2 biodiesel - a mix of vegetable

oil and sugar-cane ethanol with 98% standard diesel. The law was designed to stimulate the market for renewable, clean

burning fuel. The B2 biodiesel requirement went into effect and became mandatory as of 1 January 2008. While in 2007 many

gas stations began offering B2 biodiesel, all stations now offer only B2 biodiesel. The requirement was modified in March

2008, and as of 1 July 2008, the requirement is that all diesel contain 3% rather than 2% biofuel (B3 biodiesel). The

mandatory biodiesel blending content was increased in July 2009 to 4%, and further to 5% (B5 biodiesel) in January 2010.

The B5 biodiesel requirement is being implemented three years ahead of its scheduled implementation date of 2012 as per

the 2005 law.21

Biofuels in Brazil enjoy a range of tax benefits tied to vehicles and fuel taxes compared to traditional fuel options (Figure 27).

Many of the taxes have regional variation making difficult simple taxation rules of thumb.

Figure 27: Bio-ethanol fuel-flex vehicle tax benefits

Bio-Ethanol Flex-Fuel Vehicle Engine Size Vehicle Tax Benefit

1L – 2L displacement 120 basis point lower taxes vs. “gasoline only” vehicle

>2L displacement 330 basis point lower taxes vs. “gasoline only” vehicle

Source: Government of Brazil and DBCCA analysis, 2012

Additionally, bio-ethanol enjoys end-use sale discounts compared to gasoline. The current tax preferences are noted in

Figure 28 below:

Figure 28: Bio-ethanol end-use sale discounts

Tax Category Tax on Bio-Ethanol Tax on Gasoline

CIDE - INR$0.23/litre

PIS/COFINS INR$0.12/litre 9.25% ad valorem (currently ~INR$0.23/litre)


In light of the bio-ethanol and vehicle fuel shortfalls in Brazil, the Government of Brazil has elected to extend the 0% import

tariff on ethanol. This extension is scheduled to expire at the end of 2015.

Bio-diesel enjoys similar end-use tax benefits compared to traditional petroleum-based diesel fuel. The current tax

preferences are noted in Figure 29 below. At the same time, domestic bio-diesel production is protected from imported bio-

diesel by a 14% import tariff.

Figure 29: Bio-diesel end-use tax benefits

Tax Category Tax on B-100 Bio-Diesel Tax on Petroleum Diesel

Family Agriculture INR$0.00 – INR$.152/litre- INR$0.462/litre

Other INR$0.178/litre INR$0.462/litre


As in the wind power sector, state-sponsored financing supports the biofuels sector. The Government of Brazil makes

available up to BRL$1 million (~USD$548,000) to growers seeking to expanding sugar cane fields or to replant exhausted

21

IEA Renewable Energy Database



fields. These loans have an 18 month grace period, a 6.75% interest rate and a 5 year term. For expansion of distillation

capacity, BNDES offers funding at 8.7%. Ethanol storage facilities receive no special tax or financing support.

Manufacturing and Policy Support

Estimates suggest that there are 750,000 people employed in Brazil’s sugarcane and ethanol production sector and 14,000 in

wind power.22

An estimated 300,000 people are employed in the biofuels sector alone23

. Examining the potential for job

creation, Moana Simas and Sergio Paaca, both of the University of Sao Paulo, presented an academic research paper at the

2011 World Energy Congress in Sweden noting their research suggested that Brazil’s wind industry could add ~94,000 jobs

by 2019 should Brazil achieve cumulative installed capacity of 6 GW and up to ~ 225,000 new jobs should Brazil reach a

cumulative installed base of 14 GW by 2019.

Wind Power

Currently Brazil has a domestic wind turbine manufacturing capacity of 1.6 GW per year. Global turbine manufacturers have

a contract market share of 6.6 GW for projects in Brazil, split out between 10 major turbine manufacturers as shown in Figure

30. At the end of 2011, Brazil had approximately 1.6 GW of domestic wind turbine manufacturing capacity. We estimate this

capacity may increase to 1.8 GW by 2013 and is likely adequate to serve domestic market demand.

Figure 30: Brazil turbine contract market share, 2012 (GW)

Source: Bloomberg New Energy Finance, 2012 and Agencia Nacional de Energia Electrica (ANEEL); DBCCA analysis, 2012

Under the PROINFA scheme, over 60% of the renewable equipment was required to be sourced locally. That legislative

requirement was retracted, though there are still various incentives to buy Brazilian manufactured equipment, including a tax

of up to 7.5% on the value of imported equipment and favorable financing terms for the purchase of locally manufactured

equipment. The 60% content rule lives on as a “soft rule” because BNDES will not provide funding for projects that fail to

comply with 60% or more local content.

22

Ren21, Renewables 2011 Global Status Report, 2011 23

Environmental and Energy Study Institute, Fact Sheet, 22 October 2008

IMPSA21%

GE17%

Vestas15%

Enercon14%

Suzlon11%

Gamesa9%

Alstom5%

Fuhrlander4%

Siemens3%

Sinovel1%



In July, 2011 Gamesa started production of wind turbines in Brazil. Local suppliers will account for as much as 60% of the

components used by the company to produce its wind turbines in Brazil.24

Gamesa’s goal is to position itself among the main

industrial groups in Brazil, increasing penetration of local developer contracts, building a meaningful sales and manufacturing

and O&M network. Gamesa predicts strong growth in Brazil’s wind power market forecasting an eight-fold increase in installed

capacity over the next 5 years.

According to the Global Wind Energy Council, historically only one wind turbine manufacturer, Wobben Windpower, was

present in Brazil with 2 manufacturing sites. More recently other suppliers have started to enter the market including Impsa

(Argentina), Suzlon (India) and Vestas (Sweden). Other new market entrants in 2009 and 2010 auctions included Alstrom,

Gamesa, GE Wind and Siemens. These foreign suppliers now become eligible for BNDES funding based on a commitment

to manufacture wind turbine generators in Brazil within a short time frame. In light of these manufacturing developments,

Brazil is well positioned to supply the wider Latin American market as well as the US with completed turbines and/or partly

assembled parts.

The outlook for Brazil’s wind energy sector could prove positive so long as projects contracted in previous auctions are

completed on scheduled timelines and prove to be financially and operationally successful. Some 470 MW of first auctions

should be built in 2011 and another 1800 MW by 2012, together with the remaining 530 MW of PROINFA projects that are set

to become operational between 2011-2012. A further 1500 MW could come online in 2013, according to the schedule of the

2010 auctions, though the “bid, not built” risk and potential related project development and infrastructure problems make this

amount less than certain.

According to the Latin American Wind Association the future tenders for this additional capacity will be more profitable as the

Government is well poised to introduce equipment-import and other tax breaks as well as cheaper financing rates through

BNDES.

Solar Power

Brazil has yet to promulgate solar power policies and has negligible solar manufacturing capacity in place. Although the

government is now formulating solar power policy, it is too early to forecast development of a domestic PV manufacturing

sector.

1.2 Electricity and Biofuels Forecast

Brazil’s population is predicted to rise from 191.5 million in 2010 to 205 million in 2020, while the number of new homes wil l

also increase by around 15 million over the period. Linked to this growth, the average number of televisions sold is expected

to rise from 1.37 to 1.71 per household, the proportion of homes with washing machines increase from 64% to 74% and the

proportion of air conditioning will rise 7% to 27%.25

Production of steel in Brazil could double in the next decade with cement

and aluminum also likely to rise almost two-fold. The industrial and transport sectors will account for two thirds of the country’s

total energy demand in 2020. All told, Brazil’s electricity demand is expected to increase by 58% from 2010 through 2020.

Brazil’s energy and renewables plans were set forth in November, 2011 when a new 10-Year Energy Expansion Plan was

released by the Energy Research Office (EPE) estimating that renewable energy resources as a share of total primary energy

supply in the Brazilian energy matrix will grow from approximately 45.5% in 2010 to 46.2% in 2020. The plan predicts modest

shifts in the relative share of different classes of renewables. Figure 31, below summarizes the shares of the various

renewables sources.

24

Renewable Energy Focus, “Gamesa begins production of wind turbines in Brazil,” 2011 25

Renewable Energy World “Brazil Soars in Clean Energy Rankings,” 2011



Figure 31: Renewables share of energy supply forecast to increase

Fuel 2010 2020e

Large Scale Hydro 13.9% 12.5%

Firewood & Charcoal 10.2% 8.3%

Cane 18.2% 21.8%

Wind, Biomass, Small Hydro 3.2% 3.6%

Total Renewables 45.5% 46.2%

Fossil and Nuclear 54.5% 53.8%

Total 100.0% 100.0% Source: Agencia Nacional de Energia Electrica (ANEEL); DBCCA analysis, 2012

Note: Red shading indicates decreased share; Green shading reflects an increased share

From 2010-2020, demand for energy in Brazil is expected to increase by 57%, as a result of millions of people spending more

on consumer goods for their homes and cars as well as economic growth continuing to outstrip that seen in developed nations

and heavy spending to improve infrastructure. Renewable energy, in all forms, is forecast by the Brazilian government to

increase from 45.5% of total energy to 46.2% in 2020.

Investment of ~BRL190 billion ($122.6 billion) is estimated to be needed for Brazil to meet the challenge, according to the 10-

year Energy Expansion Plan published by Brazil’s Energy Research division, EPE. Of this, around BRL 100 billion ($63.8

billion) will go towards renewable projects not yet contracted, 55% on hydropower and 45% on wind, biomass and small

hydro. No allocations for solar power have yet been made.

The Brazilian government’s electricity plan is depicted in Figures 32 and 33. The successful achievement of these forecasts

is predicated upon effective and timely policy execution, continued macroeconomic growth and commission of projects “won”

under past and prospective reverse auctions.

Figure 32: Planned electricity fleet, 2010 and 2020, by fuel

Source: Agencia Nacional de Energia Electrica (ANEEL) and DBCCA analysis, 2012

83 94

115

4 5

6

16

25

25 2

3

7

9

7

12

-

40

80

120

160

200

2010 2015 2020

GW

's o

f In

sta

lle

d C

ap

ac

ity

Large Hydro Small Hydro Fossil Fuels Nuclear Biomass Wind

110 GW

141 GW

171 GW



Figure 33: Hydropower dominates growth in power supply through 2020

Source: Agencia Nacional de Energia Electrica (ANEEL) and DBCCA analysis, 2012

The above segment labeled Renewables does not yet include solar contribution as the Government’s energy plan through

2020 does not yet forecast a meaningful role for solar power. While we expect this to change, we cannot estimate the

timetable or scale of solar development in Brazil given cost and policy support unknowns. Based just on Brazil’s published

plans through 2020, renewables in all form may create an investment demand of approximately US$ 122.6 billion (BRL$ 190

billion).

IEA vs. Government Forecasts

For perspective, we believe it is useful to compare the Brazilian government’s forecast of incremental capacity expansion with

the IEA “New Policies” scenario contained within the IEA World Energy Outlook 2011 (Figure 34).

Figure 34: Comparison of IEA and Government forecast cumulative growth

Source: Agencia Nacional de Energia Electrica (ANEEL);IEA and DBCCA analysis, 2012

10

35

15

1

-

10

20

30

40

50

60

70

Brazil 2010-2020 Incremental Expansion

Inc

rem

en

tal I

ns

talle

d C

ap

ac

ity, G

W

Traditional Fossil Hydro Renewables Nuclear

-

5

10

15

20

25

30

35

-

10

20

30

40

IEA Forecast Govt. Plan

Bio

fue

ls, M

toe

Inc

rem

em

en

tal G

W's

20

10

to

20

20

Hydro Biomass Wind Solar Biofuel



The Brazilian government plan compared to the IEA’s forecast reflects a more aggressive expansion of both hydro power and

wind power. On the other hand, the IEA forecasts modest solar power development while the Brazilian energy plan makes no

mention of it.

Hydropower Forecast

The 10-Year Energy Expansion plan predicts installed capacity from large-scale hydro plants will rise to 115 GW by 2020 from

75 GW in 2011. Small-scale hydro is forecast to grow modestly to 6 GW from the current 5 GW level. The principal new

hydro project in Brazil is the 11,233 MW Belo Monte dam to be built on the River Xingu in the Amazon, due to start generating

power in 2015. The full potential is expected to be online by January 2019 with the majority of output being expected to serve

industry power consumption.

While hydropower dominates Brazil’s electricity system, it is worth noting that the current development reflects only 34% of

economically developable hydro resources according to the national government. Full development of those resources

suggests a maximum hydropower fleet of approximately 260 GW. Thus there remains strong growth potential for the hydro

sector beyond 2020, though sustainability and climate change dynamics may complicate the outlook. Rainfall shifts arising

from climate change phenomena could create developmental risks requiring additional policy actions to mitigate the complex

balance of riverflows, agriculture, deforestation and biofuels development.

Wind Power Forecast

In 2001 Brazil’s first wind energy atlas was published estimating that there is 143 GW of wind power potential at 50 meter

elevations. In 2008 and 2009 new measurements carried out indicate that the real potential is much higher, estimated at

more than 350 GW. According to the Global Wind Energy Council, large unpopulated areas of land, a coastline of 9,650 km

and excellent natural wind resources help secure Brazil’s position as a potential wind energy leader. Unlike in many other

countries, Brazil’s windiest areas are also located close to the electricity grid and to demand centers. Should water stress

become a problem in Brazil threatening the country’s main electricity source, wind power could help alleviate energy security

concerns.

The new 10-year plan released in 2011 aims to achieve 12 GW of wind power development by 2020. The Brazilian Wind

Energy Association feels that this is conservative and that actually the installed wind capacity in Brazil will be close to 22 GW

by 2020. Most of the wind energy projects competing in the recent government-run reverse Energy Auction processes are

located in Brazil’s northern regions where the wind resources can be developed more economically. Wind energy produced in

these regions mitigates the import of electricity from southern regions and allows the weaker Northern provinces to expand

their own economies. Over time, these regions may begin to produce more energy than they require, thus allowing electricity

exports to neighboring provinces, further boosting local economies.26

Given the execution risks of the currently awarded crop

of bids, we believe these higher estimates may prove optimistic, though perhaps not as modest as the cautious IEA estimates

noted comparatively in Figure 34, above.

Solar Power Forecast

Given the considerable success in developing wind power resources through reverse auctions, Brazil is now beginning to

formulate draft policy to encourage development of the solar PV market. The Government’s energy plan through 2020 does

not yet forecast meaningful solar development and we do expect that to change with issuance of supportive policy. In terms

of practical potential capacity, the Global Energy Network Institute estimates that within the central and northeastern regions

Brazil may have solar resources that could be developed into 114 GW of capacity.

26

Renewable Energy World, “Brazil Soars in Clean Energy Rankings,” 2011



Bio-Ethanol Forecast

Brazil will need to sustain production growth in the ethanol sector to meet increasing domestic demand and maintain its export

share. Increased capacity to produce sugarcane as ethanol feedstock, supportive government policies, improved efficiency in

sugarcane production and ethanol conversion processes have combined to stimulate the development of Brazil’s ethanol

industry.

Figure 35: Recent and forecast Brazilian bio-ethanol production

(Million Liters) 2010 2011e 2012e 2015e 2020e

Beginning Stock 4,048 5,916 7,418 NA NA

Production 27,965 24,198 25,500 47,520 73,349

Imports 76 1,020 770 NA NA

Total Supply 32,089 31,134 33,759 NA Na

Exports 1,906 1,450 1,850 5,252 8,706

Consumption 24,267 22,195 25,050 47,500 73,349

Fuel 22,162 19,845 22,500 40,800 63,100

Other Uses 2,105 2,350 2,550 1,448 1,543

Ending Stock 5,916 7,489 6,859 NA NA


Capacity 41,360 42,800 43,250 NA NA

Capacity Utilization (%) 67.6% 56.5% 59.0% NA Na


Sugarcane 342,566 296,419 312,375 549,000 815,000

Source: Government of Brazil (2015e, 2020e), USDA – Sao Paulo (2010-2012e) and DBCCA analysis, 2012

The 2011/2012 period has been a challenging for Brazil’s bio-ethanol industry. Brazil’s sugar cane fields are old and not

producing at peak capacity (intensively cultivated fields have life spans of ~3 years before declining sugar yields require

replanting by year 5). Further, the 2011 sugar cane crop is down by 4% as reported by Bloomberg New Energy Finance in

August 2011 and the 2012 outlook is not encouraging since announcements on 27 March 2012 that the 2012 crushing season

would be delayed due to “...limited availability of raw material.” Reduced cane production and high global sugar prices has

shifted growers and refiners to optimize for sweetener production rather than fuel production thus reducing forecast production

volumes depicted in Figure 35. As a result, Brazil finds itself in an unusual position relative to its recent history, with a likely

need to import both bio-ethanol and gasoline to satisfy vehicle fuel demands.

We believe demand for ethanol in Brazil will increase over the next 10 years, due to increases in flex-fuel vehicles as well as

the competitiveness of hydrated ethanol prices relative to gasoline prices and increased exports. Consequently, the Brazilian

government forecasts, ethanol demand to nearly triple over the next ten years. Brazil currently cannot meet domestic demand

for fuel ethanol, importing from the USA. Investment in Brazil’s biofuels sector is expected to total up to $61.6 billion by 2020.

Brazil will have to invest in expansion of both cane fields and distillation capacity in a sustainable fashion that does not

exacerbate deforestation trends and create water supply conflicts should rainfall patterns shift. Such development may prove

challenging because of bureaucratic impediments. Gerson Carnerio Leao, president of the National Sugar Cane Commission

at the CNA agricultural confederation notes that “The government is to blame for the shortage of ethanol,” attributing this

problem to “stifling” governmental red tape and “exorbitant” taxes. Producers, too, find themselves in difficult positions hav ing

assumed significant debt levels for expansion. However, current feedstock shortages have exacerbated the servicing of debt

for some refiners.



Brazil’s government has ambitions to bring ethanol to international customers rather than simply serving the domestic market.

The government’s current forecast for ethanol expansion suggests that by 2020 exports worldwide will rise by 3.8x to 6.8

billion litres from 1.8 billion litres in 2011. By then the sugar cane will likely consume 18.3 million hectare, 22% of zoned

agricultural land. Although 46.4 million hectare of additional land will remain available for cane planting, we believe it may not

be exploited due to concerns over resulting deforestation risks arising from the displacement of crops and livestock from those

areas and environmental risk from the ethanol processing infrastructure.

As a hypothetical example, and putting aside the environmental and sustainability risks, we estimate that if Brazil were to fully

plant the suitable approved agricultural lands (ZAE Cana lands) with cane, bioethanol production in Brazil could rise to level a

level that would more than supply the world’s demand for ethanol to meet 15% blending targets on an estimated 2020

gasoline worldwide gasoline demand of 1.55 trillion litres. If Brazil was able to find ways to prevent deforestation from such a

dramatic expansion or materially increase output of current lands in a sustainable manner, Brazil would have the potential to

become a global scale major fuel exporter.

Ultimately, the international success of Brazilian ethanol will depend on continued high oil prices, a new global competitive

dynamic now that US trade protectionist ethanol tariffs have been eliminated, the ability of the Brazilian ethanol industry to

achieve greater process efficiencies and management of sugar cane policies that mitigate deforestation and water resources

constraints. According to Hart Energy’s Global Biofuels Outlook to 202027, Latin Amercan bioethanol exports will likely serve

EU27 demand rather than US demand.

Bio-Diesel Forecast

Figure 36: Historical and forecast bio-diesel production data

(Million Liters) 2010 2011e 2012e 2015e 2020e

Beginning Stock 135 71 91 NA NA

Production 2,397 2,720 2,850 3,021 3,841

Imports 9 12 10 NA NA

Total Supply 2,541 2,803 2,951 NA NA

Exports 8 4 6 NA NA

Consumption 2,462 2,708 2,830 3,021 3,841

Ending Stock 71 91 115 NA NA


Capacity 5,837 6,500 6,750 NA NA

Capacity Utilization (%) 41% 42% 42% NA NA

Source: Government of Brazil (2015e, 2020e), USDA – Sao Paulo (2010-2012e) and DBCCA analysis, 2012

Bio-diesel in Brazil remains a market on the periphery. First generation bio-diesel fuels are based on a combination of

soybean oil, animal fats and other miscellaneous oil crops. Unappealing biodiesel economics has resulted in few programs to

accelerate development or use of this fuel. The sector already has manufacturing capacity in place to meet almost 2x the

government’s forecast demand by 2020. Until high yielding, rapidly fruiting second generation oil crops are available, we do

not expect bio-diesel contributing in any material way to Brazil’s energy plans.

27

“Global Biofuels Outlook to 2020,” L. Nurafiatin, Hart Energy, February 2012



1.3 Water Sustainability

Compared to China and India, Brazil, relatively speaking, has historically had adequate water for development. Brazil’s water

stress indicator is less than 0.3 indicating resources are not even “slightly exploited.” Industrial use of water has remained

fairly constant as a percentage of water used while municipal growth has expanded. Interestingly, despite continued growth in

the agricultural sector, agriculture’s share of water use has been slowly declining (Figure 37).

Nonetheless, Brazil’s energy infrastructure, and therefore the country’s status as a low-carbon economy, is dependent on

continued favorable water availability. Should climate change dynamics adversely influence precipitation patterns and

agricultural policies for ethanol be poorly executed, Brazil could experience problems that could materially change the

country’s “green” profile vis a vis China and India.

Figure 37: Brazil’s water uses

Source: United Nations Food and Agriculture Organization, World Bank and DBCCA analysis, 2012

On a comparative basis with China and India, Brazil is a thrifty user of water when water is viewed as an element of national

economic output. As can be seen in Figure 38, Brazil’s “water intensity” (water use per GDP) is remarkably low in comparison

to water stressed China and India. We believe one reason Brazil enjoys such a low water intensity statistic is because the

country, so far, enjoys adequate rainfall, thus mitigating the need for more intensive irrigation use of water.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1996 2000 2001 2002 2003 2004 2005 2006

Agricultural water withdrawal Industrial water withdrawal Municipal water withdrawal



Figure 38: Brazil – An economy with a modest thirst


Brazil is unique among the BICs countries for both its current low national water stress and the reliance on hydropower and

bioethanol as part of its energy strategy. Although the national water stress index remains low, Brazil is beginning to

experience effects that suggest climate change pressures may be working to reshape the economy.

In particular, key southern sugar cane regions in the southern part of Brazil have experienced significant drought for the past

two years. Figure 39, below, illustrates Brazil’s current and authorized sugar cane growing regions. The red-shaded areas

represent the current regions and the green shaded regions represent those geographic areas authorized for sugar cane

growth.

0

50

100

150

200

250

300

350

400

450

500

0

100

200

300

400

500

600

700

800

1990 1996 2000 2006 2010

Us

e p

er

GD

P C

ap

ita

, M

3/G

DP

Wa

ter

Wit

hd

raw

ls, B

n M

3/y

r

Total - Brazil Total - China Total - India

Per GDP Capita - Brazil Per GDP Capita - China Per GDP Capita - India



Figure 39: Brazil’s “ZAE Cana” authorized cane regions

Source: Government of Brazil and DBCCA analysis 2012

Brazil’s sugar cane regions do not intrude into the Amazonian rainforests in the western part of the country. Current climate

modeling28

suggests that these key growing regions may experience more volatile weather (storms of greater severity, more

often) by 2020 before a general trend throughout the country forecast to become evident by 2030. Thus, cane growth will

have to be undertaken with increasingly stringent sustainability practices to avoid exacerbating the difficulties that adverse

precipitation trends may bring.

1.4 Challenges

While Brazil has made great progress in becoming one of the cleanest power producing countries in the world, it is also likely

to suffer considerably from adverse effects of climate change. Models suggest a warmer and drier environment for the

Amazon, which could result in some eastern parts of the Brazilian Amazon region being converted into desert ecosystems by

the end of the century.29

This could reduce rainfall in the Central-West and Northeast regions, resulting in smaller crop yields

and less available water for hydropower-based electricity. There is also concern that the Amazon could be caught up in a set

of negative feedback loops that could dramatically speed up the pace of forest lost and degradation. Urgent solutions are

therefore needed to reduce Brazil’s vulnerability to climate change and enable the implementation of adaptation actions in the

country.

Like China and India, Brazil faces the dual challenge of encouraging development and reducing GHG emissions. Brazil’s

economy has recovered remarkably well since the dip in 2008-2009, ranked as the 9th largest economy globally in 2010.

Similarly, Brazil faces potential bottlenecks in the electricity transmission system. Brazil’s energy transmission system is

28

“Climate Change and Extreme Events in Brazil,” J. Marengo, Fundacio Brasileira para o Desenvolvimenro Sustenavel (FBDS) and Lloyd’s 29

WWF, “Climate change in the Amazon”

Amazon

Northeastern

Southern

West CentralSoutheastern

Suitable Areas for Sugarcane

production

Sugarcane Producing Regions



expected to grow from around 100,000km in 2010 to around 142,000 km by 2020. The majority of this expansion will be from

connecting plants in the northern region. The estimated investment in the transmission system over the 10-year period is

$29.5 billion.30

Without such parallel investment, further expansion of hydropower, wind power and solar power could result in

frustrated ambitions with both macroeconomic and greenhouse gas emissions consequences.

30

Brazil Works “Energy Policy in Brazil,” 2011

Emerging Markets: China


2. Emerging Markets – China Energy Overview

With a population of 1.34 billion in 2010, China has the largest population in world and is also the world’s largest energy

consumer and second largest economy (after the US). China is the second largest country in Asia and an economic leader in

terms of international trade. Its GDP for 2010 (PPP, current USD$) was $10.2 trillion – this is still smaller than the US ($14.6

trillion), but 2.4 times the size of India’s GDP and 4.6 times the size of Brazil’s GDP.

China’s energy requirements are supplied primarily though fossil fuel. Non-fossil sources, which are currently dominated by

hydropower and nuclear power, supply approximately 10% of China’s energy mix. Solar power is just beginning to be

deployed in China.

Comparing energy statistics for China with other countries can be challenging for two reasons. First, China uses an annually

varying unit of energy measurement known as “Ton, standard coal equivalent (SCE)” while the IEA uses an internationally

agreed upon fixed measurement of “Ton oil equivalent (Toe).” Secondly, China’s own national statistical bureau accounts for

biomass and solid waste combustion by comingling those amounts with coal whereas the IEA estimates are more distinctly

segmented.

The upshot of this is China’s own national primary energy balance represents a different and more carbon-intense energy mix

than that presented in the IEA forecasts. Figure 40, compares the fuel segmentation provided by both China and the IEA for

2009.

Figure 40: China vs. IEA 2009 energy mix – Lost in translation?

Fuel

China

(National Bureau

of Statistics)

IEA/ World

Bank Difference

Coal 77% 67% 10%

Oil 10% 17% -7%

Natural Gas 4% 4% -

Non-Fossil 9% 13% -4%

Source: China National Bureau of Statistics, IEA, World Bank and DBCCA analysis 2012

The major variances between the IEA and China energy mix proportions are in the Oil and Non-Fossil dimensions. Within the

IEA Non-Fossil estimate of 13% we have identified 3% of share relating to biomass and solid waste combustion. Under the

Chinese energy accounting system these amounts are counted under the Coal heading. Further, the issue of China’s SCE

vs. the IEA’s TOE energy content dimensions also results in modest disagreement when renewable electricity is converted for

inclusion in the primary energy balance calculation process. Thus we believe we can understand the differences between the

Non-Fossil contribution data. Similarly under “Oil,” China includes petroleum coke and related petroleum wastes in the Coal

account (as it is burned like coal) rather than in the Oil account as the IEA classifies it (based on where it came from).

We raise early this seeming abstruse energy accounting issue because for the purposes of comparison among countries, we

use the IEA data for comparative consistency. For evaluation of China’s performance compared to stated goals and targets,

we shift our perspective and use China’s measuring and energy accounting methods as that is what is used in setting and

assessing policy.

With the above caveats in mind, as of 2009, China’s largest non-fossil energy source remains hydropower, accounting for 7%

of total energy. While China has substantial domestic supplies of coal, imported coal does account for approximately 4% of

coal consumption and China’s coal reserves are being rapidly depleted through growing domestic consumption – by BP’s



latest estimate China has only 35 years of domestic coal supply remaining31

. Coal is used throughout the economy, though

primarily for power generation and as a fuel for industrial boilers and mills. Petroleum requirements are met primarily by

importing crude oil which accounts for 67% of national consumption. In 2009, 35% of petroleum was used for vehicle fuel with

41% going into the industrial and chemicals sector. Natural gas needs had traditionally been served by domestic supply, but

from 2007 China became a net natural gas importer with imports accounting for 9% of total consumption in 2009. Natural gas

is used for both large-scale heating plants and as an industrial fuel. As a primary raw material, natural gas is consumed by

the chemical sector and for fertilizer production. Figure 41 provides some perspective on China’s primary energy sources.

Figure 41: China’s primary energy mix 1990-2009


Since 1990 through 2009, China’s energy needs have expanded at an average annual rate of 5.2% while the economy has

grown at a far more rapid average annual rate of 10.5%. Consequently, China’s Energy Intensity has declined at an average

annual pace of 3.9% reflecting consistent improvements in extracting additional value from each unit of energy produced.

Figure 42 depicts these historical usage trends.

31

2010 Coal Reserves to Production ratio, “BP Statistical Review of World Energy 2011”

0

10

20

30

40

50

60

70

80

90

100

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Pe

rcen

t o

f M

ix

Fossil Fuel Combustible Renewables and Waste Alternative and nuclear energy



Figure 42: China’s energy trajectory - More efficient energy use


As a comparison, Figure 13 (above in Section 1) depicts the fuel mixes of Brazil, India and China. China’s primary energy

supply mix is demonstrably different compared to either India or Brazil, relying more heavily on coal, and with only modest use

of biomass and natural gas. The government recognizes the significant opportunity for China to develop renewables as a way

to accomplish the multiple goals of (1) increasing domestic energy supply, (2) decarbonizing the energy infrastructure and (3)

building what could be a world-scale domestic renewables industry with substantial export potential.

The composition of generating capacity does not differ meaningfully from the overall national energy appetite; coal is the

dominant fuel source for both primary energy as well as electricity. For electricity production, 78% of kilowatt-hours are

produced with coal. This is a remarkably high level of reliance on one fuel source, and coal consumption for electricity

production has increased at an average annual compound growth rate of 9.9% from 1990-2011.

In Figure 43, below, we have broken out electricity consumed by the various segments and shown that as a discrete end use

of energy. China’s largest end-use consumer of energy is Industry, consuming 35% of primary energy supplied, which is

consistent with the high proportion of heavy manufacturing in China, following by building sector, the second largest energy

user, consuming 25%.

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

En

erg

y U

se

pe

r C

ap

ita

an

d p

er

GD

P

To

tal E

ne

rgy U

se

( k

T o

il e

qu

iva

len

t)

Total Energy Use Energy Use per GDP Energy Use per Capita



Figure 43: Primary energy consumption mix for China, 2009

Source: International Energy Agency and DBCCA analysis, 2012

The first decade of the 21st century, in particular, was a period of tremendous growth and change in China as it rapidly grew

to become a key export manufacturer. Urbanization and a shift toward higher value-add manufacturing drove electricity

demand at an average annual growth rate of 12%, 1.5 percentage points faster than comparable real GDP growth. As a

consequence, China has begun to experience electricity shortages of approximately 15-20 GW in 2011 and these are now

forecast to expand to approximately 70 GW shortfalls in the next two years.

Figure 44: China electricity installed capacity by source, 2011 – Total 1,056 GW

Source: CEC, CEIC and DBCCA analysis, 2012

By the end of 2011, as shown in Figure 44, total installed capacity in China was 1,056 GW, up 9.3% YoY, representing the

largest installation among the BIC countries (5x India’s and 9x Brazil’s). China also relies most heavily on fossil compared to

Brazil and India in terms of electricity installed capacity, deriving 67% from coal, 3% from natural gas and another 2% from oil.

Hydro still has the largest installation in all renewable sources, up 8% from 2010 level, but shows a slower increasing trend

compared to average of 13% growth during 2006-2010 period. Wind and solar continue to show strong and rapid

development while biomass and nuclear being modest.

Industry35%

Transport11%

Building25%

Other11%

Electricity18%

Industry

Transport

Building

Other

Electricity

Fossil72.0%

Hydro21.8%

Nuclear1.1%

Biomass0.4%

Wind4.4%

Solar0.2%



Figure 45: China electricity generation by source, 2011 – Total 4,722 GW

Source: CEC, CEIC and DBCCA analysis, 2012

From an actual electricity production perspective, China has increased power generation at 12% average annual rate since

2000 to 2010 as a result of China’s strong economic growth and fast urbanization. Figure 45 shows that 82% of electricity

production is derived from fossil fuels. Hydro power produced 14% of electricity in 2011, down 2% from 2010 mix due to the

severe drought condition in 2011. The drop in Hydro power was substituted largely by thermal power and rest by wind power.

2.1 Renewables

Current Status

As is evident from Figure 46 below, non-hydro renewables still forms a small component of the overall power mix in China. In

terms of the sources of renewables power in China, this was initially driven by hydropower and modest amounts of biomass.

Only recently has wind power become a more visible element, growing rapidly in five years to 47 GW of grid-connected

capacity by 2011. Solar power has just begun deployment and its contribution is almost negligible compared to the other fuel

sources. Indeed renewable power is becoming an increasingly important element of China’s energy and electricity strategy as

more rapid adoption helps mitigate carbon emissions, address foreign dependency concerns and build domestic industry that

can serve both domestic and export markets.

Fossil82%

Hydro14%

Nuclear2%

Biomass0.4%

Wind2%

Solar0.02%



Figure 46: Composition of renewable installed capacity in China, CY2011 – Total 284 GW


In 2011, China’s renewables projects were financed with approximately USD$ 44 billion of asset financings, up slightly from

USD$42 billion in 2010 as depicted in Figure 47. Most apparent is the slowdown in wind power development as the

transmission grid scrambled (and continues to scramble) to connect and take full advantage of these green resources.

Figure 47: China asset financed renewables projects, 2007-2011

Source: Bloomberg New Energy Finance and DBCCA analysis, 2012

Hydropower

Hydropower in China has expanded by 15 GW in 2011. This resource is primarily represented by large state-owned facilities.

Privately developed hydropower facilities are insignificant, although some may exist at the local level for small-scale

agricultural purposes. Hydropower is an important dimension in renewables development and it is a favorite of provincial and

Hydro231 GW

81%

Wind47 GW

17% Biomass4.36GW

2%

Solar2.14 GW

1%

-

5

10

15

20

25

30

35

40

45

50

2007 2008 2009 2010 2011

Co

mp

lete

d A

ss

et

Fin

an

cin

g, $

B

Other

Biomass&Waste

Biofuel

Solar

Wind

Small Hydro



national officials. Controversy exists over how sustainable are China’s current hydropower practices and future plans. Please

see our report entitled “Hydropower in China - Opportunities and Risks32

” for more details.

Wind Power

Wind power, emerging in the mid-2000’s, so far, has proven to be China’s second largest developed renewable resource. In

recent years China’s annual growth of grid-connected wind power installations has been heady with annual growth rates of

109% and 77% in 2009 and 2010, respectively. In 2010, 13 GW of wind power was connected to the grid and 16 GW

followed in 2011. With strong provincial support driven by “local interests,” growth was so rapid that wind power projects

development occurred at a pace faster than could be absorbed into the electricity grid. The central government took decisive

action to control unbridled growth; a measure that we believe will be a long-term positive despite the near-term disruptions

associated with 15 GW/year growth rates materially slower than the “hot house rates” of several years ago.

Solar Power

Although China is one of the world’s most important participants in the solar power value chain, it has not been a major

developer of domestic projects to date. In terms of technology, China’s initial foray into solar has been with solar PV rather

than solar thermal systems. Exiting 2010, China had a mere 300 MW in solar PV attached to the grid. With rapid price

declines in the solar PV sector, China accelerated solar power project development by installing almost 2 GW in 2011. This is

a sector we expect to grow rapidly through our 2020 forecast period.

For additional details on our opinions concerning China’s wind and solar prospects, please see our report entitled “Scaling

wind and Solar Power in China: Building the Grid to Meet Targets33

.

Bio-energy

As with Brazil, we segment China’s bio-energy resources into two general categories: (1) Biomass for power generation (on

and off-grid) and (2) Biofuels for transportation. In the case of China, the biofuels activity is almost exclusively the domain of

bio-ethanol with only experimental progress made, to date, in the bio-diesel area.

Biomass generation in China is quite modest compared to China’s overall energy profile. Based on 2010 total primary energy

balance, biomass-related energy accounted for approximately 1-2% of China’s total energy appetite. Of this modest amount,

70% was used to produce electricity and 30% for thermal heating uses.

Biofuels faces a scale problem in China. Further, given strict requirements that biofuels activities be developed in a way that

does not conflict with either human-consumption crops or arable land that could be used for food production, China’s biofuels

efforts have not gained significant traction.

Biodiesel remains in early development stages and appears to us to be far from meaningful commercialization - currently bio-

diesel production is negligible and un-named officials suggest production could rise to only 1 million tons per year by 2015.

Within the constraint of ensuring that biodiesel feedstocks do not conflict with food or food production needs, China has

focused early work on Jatropha as non-edible oil seed feedstock. Initial plantings in Yunnan province have taken longer than

expected to reach productive maturity. Other feedstocks include waste oil from the culinary waste chain. Competition for

32

Access this report, “Hydropower in China – Opportunities and Risks,” at http://www.dbcca.com/dbcca/EN/_media/Hydropower_in_China-Opportunities_and-Risks.pdf 33

Access this report, “Scaling Wind and Solar Power in China: Building the Grid to Meet targets,” at http://www.dbcca.com/dbcca/EN/_media/China_Wind_and_Solar-

Feb2012.pdf

http://www.dbcca.com/dbcca/EN/_media/Hydropower_in_China-Opportunities_and-Risks.pdf

http://www.dbcca.com/dbcca/EN/_media/China_Wind_and_Solar-Feb2012.pdf

http://www.dbcca.com/dbcca/EN/_media/China_Wind_and_Solar-Feb2012.pdf



waste oil from both the industrial sector as well as from businesses “recycling” waste kitchen oil back into the culinary sector,

as reported by the USDA, has resulted in insignificant and less than predictable waste oils streams being available to the bio-

diesel sector.

Since bio-diesel remains an experimental or “pilot” fuel in China (15 tons was produced in 2011), we focus our attention on

China’s bio-ethanol activities. Figure 48 shows that in 2011, China produced 2.217 billion litres of first-generation bio ethanol,

an amount equal to approximately 5% of China’s 45 billion litres of gasoline consumption in 2010. For comparative purposes,

China’s 2010 consumption of diesel fuel for transportation was approximately 99 billion litres.

Figure 48: Bio-ethanol historical production and capacity data

2006 2007 2008 2009 2010 2011

Ethanol Production (ML) 1,647 1,736 2,002 2,179 2,129 2,217

Ethanol Production Capacity (ML) 1,824 2,065 2,243 2,179 2,357 2,534

Capacity Utilization 90% 84% 89% 100% 90% 87%


Corn 3,200 3,200 3,700 4,000 3,900 4,120

Wheat 1,050 1,050 1,050 1,050 1,050 1,050

Cassava 340 470 392 336

Rice NA NA NA NA NA NA

Source: United States Department of Agriculture - Beijing and DBCCA analysis, 2012.

Like most other countries that experimented with first generation bio-ethanol, China’s efforts have focused on grain as a

feedstock. China has not made significant progress in commercializing low-cost, high-yield cellulosic ethanol production

methods. Toward the end of the 11th Five Year Plan period (2006-2010), due to concerns over rising food prices, the central

government did not authorization significant expansion of bio-ethanol production. The data in Figure 48 above shows a

historical reliance on corn and wheat in an approximate 80/20 mix as the primary feedstocks for bio-ethanol production.

Table 49: Selected provincial bio-ethanol production and feedstock data

Province Grain Feedstock 2009 Production 2010 Capacity

Heilongjiang Corn/Rice 240,730 253,400

Jilin Corn 633,500 570,150

Henan Wheat 561,281 570,150

Anhui Corn 532,140 557,480

Guangxi Cassava 211,589 177,380

Total 2,179,240 2,128,560


To date, no well-vetted expansion plans have been identified. As an aside, the bulk of China’s agricultural research remains

focused on key sustainability themes of food production and drought/pest resistance (e.g., “super crops”) rather than fuel

crops. As for importing bio-ethanol, China continues to levy a general 30% tariff on imported ethanol, although chemical

sector (non-fuel) buyers have enjoyed a substantial reduction in import tariffs to a modest 5%.

Policy Support

China places great emphasis on renewables as part of the country’s energy planning process and has put in place a wide

range of supportive policies complimented with explicit targets, national and provincial incentive schemes and tax



preferences. China does not, however, enforce prioritization of use rules (enacted in the Renewable Energy Law of 2006) for

renewables-produced electricity versus thermally generated electricity. Hydro power is the most mature of the renewables

technologies now deployed in China with wind power following close behind. Although Chinese manufacturing operations

account for a substantial proportion of global PV production, domestic development remains quite slow and is only now

beginning to accelerate following supportive policy and incentive announcements in 2011.

China’s major policy initiatives are built upon a body of legislation outlining high-level policy goals and objectives.

Supplemental administrative orders and instructions translate higher-level goals into specific targets and supporting

policy/incentive schemes. Figure 50 highlights key pieces of legislation while Figure 51 provides an overview of the major

implementation orders.

Figure 50: China’s supportive legislative framework

Policy Document Key Points

Ethanol and Biodiesel for Automobiles (2001)

Set in place the administrative policies to foster development of the bio-ethanol and bio-

diesel for transportation. Later amplified in the Renewable Energy Work Plan of the 11th

Five Year Plan

Ethanol-blended Gasoline for Automobiles (2004)

Set forth E-10 blending criteria for various regions and provinces. Allocated

responsibilities among 12 agencies and entitites

Renewable Energy Law (2006)

Basic legal framework for the development of renewable energy in China

Guarantees Compulsory interconnection of renewable energy to the grid

Guidelines on the structuring of power tariffs and cost-sharing arrangements

Regulation on Administration of Power Generation from Renewable Energy (2006)

Grid is obliged to purchase full amount of electricity generated from renewable energy

projects within their geographical coverage

Medium and Long-Term Development Plan for Renewable Energy (2007)

Establishes a longer term goal: 15% of China’s total energy generation to be originated

from renewable energy generation by 2020

Specify targets for various renewable energy sources

Provisional Administrative Measures on Pricing and Cost Sharing for Renewable Energy Power Generation

Requires end users to pay a surcharge on electricity to cover price difference between

renewables power and conventional power

Renewable Energy Law Amendments (2009)

Addresses Inadequate coordination between national strategy and local renewables

development

Introduces of quota for electricity generated from renewables

Includes construction of supplementary grid transmission capacity in support of

renewables development as part of plans

Circular on Refining the Policy for On-Grid Pricing of Wind Power (2009)

Divides China into four different types of wind power resource areas and different prices

are set for each of these areas.

FiT prices range between RMB 0.51 – RMB 0.61/kWhr and can be supplemented by

incremental provincial tariffs which can add an additional approximate RMB 0.10/kWhr

Source: People’s Republic of China and DBCCA analysis, 2012.



Figure 51: China’s implementation policies for renewables support

Policy Document

Date Key Points

12 FYP Plan March 2011

16% of reduction in Energy Intensity from 2010 level by 2015

17% of reduction in carbon emission from 2010 level by 2015

Target Non-Fossil fuel as a proportion of total primary energy supply 11.4% by 2015 and rising

to 20% by 2020

8% reduction in SOx and COD emission by 2015, 1.7% YoY

0% reduction in NOx and Ammoniac Nitrogen by 2015, 2.1% YoY

Add 120 GW of Hydro capacity, at least 70 GW of wind capacity and 5 GW of solar capacity by

2015

Strategic emerging industrials accounts for about 8% of GDP by 2015

Industrial Restructuring and Upgrading Plan (2011-2015)

January 2012

8% annual growth in industrial value-added output by 2015

15% share of strategic merging industries in term of value-added output by 2015

By 2015, compare to 2010 level, key targets for energy efficiency improvement and industrial

emissions:

Energy consumption per unit of value added 21%

CO2 emissions per unit of value added output >21%

Water consumption per unit of value added output 30%

Industrial emissions of COD, SO2 10%

Industrial emissions of Ammoniac Nitrogen and NOx 15%

12th FYP Work

Plan for GHG Emissions Control

December 2011 17% reduction of CO2 emissions per unit of GDP by 2015 compare to 2010 level

Breakdown of provincial target of CO2 emissions reduction by 2015

Sector 12 FYP October 2011

- December 2011

12th FYP for environment protection

12th FYP for utilization of coal-methane gas

12th FYP comprehensive utilization of and bulk solid waste

12th FYP comprehensive utilization of biomass

Guidance opinion on development of Natural Gas district energy

Carbon Trading Pilot Program

October 2011 NDRC approved pilot carbon trading program for 7 provinces and cities and encouraged local

government to accelerate the process

Work Plan on 12 FYP Energy Conservation and Emissions Reduction

September 2011 16% reduction of energy consumption per unit of GDP by 2015 compare to 2010 level

Adjustment on Resources Tax Act

September 2011 Expand tax on oil and gas sales national wide to replace old tax on quantity to reduce

consumption

Source: People’s Republic of China and DBCCA analysis, 2012.

Incentives Summary

Initially China’s first subsidy efforts for renewable electricity paralleled those of the West: up-front subsidies to defray project

capital costs. This practice led to overdevelopment of capacity with little regard to efficacy. China has since adopted a more

refined view utilizing FiTs intending to incent green electricity generation rather than “capacity on the ground.” FiTs in China

are multi-faceted with rates varying for both type of technology and for region. Further, additional provincial or locally

negotiated FiTs are available in addition to the national FiT. For solar power, the national FiT is not as finely segmented by



region or quality of resource as it is with wind power. In the case of wind power, China’s FiTs are designed to account for a

combination of circumstances that all influence economic productivity. The major regional aspects that influence the different

FiT levels include: (1) wind resources, (2) local construction difficulty and (3) local construction costs. Figure 52 details the

localities and their respective national wind power FiTs while Figure 53 looks at solar industry policy and other renewable

incentives in China and figure 54 addresses regional supplement FiTs.

Figure 52: Four categories of resource areas defined by NDRC for wind power projects

Category(1)

Benchmark Tariff Price (RMB/kwhr)

Covered Regions

Class I 0.51

Inner Mongolia Autonomous Region except Chifeng City, Tongliao City, Xing’an League and Hulunbeier City

Urumqi Municipality, Yili Kazak Autonomous Prefecture, Changji Hui Autonomous Prefecture, Karamay City and Shihezi City of Xinjiang Uygur Autonomous Region

Class II 0.54

Zhangjiakou City, Chengde City of Hebei Province

Chifeng City, Tongliao City, Xing’an League, Hulunbeir City of Inner Mongolia Autonomous Region

Zhangye City, Jiayuguan City, Jiuquan City of Gansu Province

Class III 0.58

Baicheng City and Songyuan City of Jilin Province

Jixi City, Shuangyashan City, Qitaihe City, Suihua City, Yichun City and Daxing'anling Prefecture of Heilongjiang Province

Gansu Province except Zhangye City, Jiayuguan City, Jiuquan City

Xinjiang Uygur Autonomous Region except Urumqi Municipality, Yili Kazak Autonomous Prefecture, Changji Hui Autonomous Prefecture, Karamay City and Shihezi City

Ningxia Hui Autonomous Region

Class IV 0.61 All other regions

Source: NDRC and DBCCA analysis, 2012. Note 1 – Class number does not correspond to Wind Power Class measures and is instead a Chinese categorization accounting for varying installation costs and wind resources

Figure 53: Solar industry policy and other renewable incentive in China

Policy Key Points

Solar FIT Policy (2011) RMB 1.15/kwhr for solar PV project which is completed before 31

st Dec. 2011

RMB 1.00/kwhr for solar PV project which is completed after 31st Dec. 2011

Provincial supplemental tariffs can add an additional approximate RMB-0.20 – RMB 0.25

Golden Sun Program 2012

2012 program announced in Feb 2012 with a subsidy of RMB 7.00/W, down from RMB

9.00/W in 2011 Golden sun program

Reduce subsidy for old 2011 golden sun program to RMB 8.00/W

The catalog of eligible projects for 2012 golden sun program was published on 3rd May

2012 with a total approved capacity of 1.7 GW and reducing again the subsidy to RMB

5.50/W from RMB 7.00/W announced earlier in 2012

Waste Power Plant RMB 0.65/kwhr for any new project in 2012

Biomass RMB 0.75/kwhr , effectively from July 2010

Geothermal National FIT is still under discussion

Source: NDRC, MOF and DBCCA analysis 2012.

Provincial and local supplemental FiTs and tax preferences are not fully defined for all provinces in China. Further, review of

those supplemental subsidies suggests a fair degree of provincial and local discretion in awarding supplemental FiTs. In

some cases, these supplemental FiTs appear to be negotiated and awarded on a project by project basis making them very

difficult to extrapolate more broadly. Localities grant supplemental subsidies in order to help achieve local electricity,

emissions, economic activity or jobs creation goals.



Figure 54: Provincial incremental tariffs

Province Wind Power (RMB/kwhr) Solar Power (RMB/kwhr)

National

Benchmark Provincial

Electricity Tariff National

Benchmark Electricity

Tariff

Guangdong 0.61 0.61-0.72 1.00-1.15 N/A

Jiangsu 0.61 N/A 1.00-1.15 1.40

Liaoning 0.61 N/A 1.00-1.15 1.27-1.30

Shangdong 0.61 0.61-0.71 1.00-1.15 1.20-1.40

Source: NDRC, provincial documents and DBCCA analysis, 2011.

Reflecting the Chinese government’s concerns over conflicts between biofuels and food security, bio-ethanol makers have

received declining subsidies in since 2008 while biodiesel has not enjoyed any subsidy support. Figure 55, below, illustrates

the declining per litre subsidy offered to bioethanol producers in China.

Figure 55: Bio-ethanol subsidies declining

Producer Subsidy / Litre

2008 USD$ 0.20

2009 USD$0.19

2010 USD$0.17


Manufacturing Resources and Policy Support

While the 10th Five Year Plan (2001-2005) set in motion China’s renewables industry, it was during the 11th Five Year Plan

(2006-2010) that the greatest impact in employment was observed. Based on statistics analyzed by Worldwatch, it appears

that China’s wind and solar farms plus wind turbine OEM’s may have created in China approximately 750,000 jobs in the

2006-2010 period. The solar PV supply chain, in the 2006 and 2007 periods created a cumulative 69,000 jobs. Looking

forward for the period 2011- 2020, we have highlighted some of the major statistics in Worldwatch’s review of China’s green

jobs opportunity in Figure 56.

Figure 56: Estimated aggregate job creations in China, 2011-2020

Sector Direct Jobs Indirect Jobs Total Jobs Creation

Solar Farms (1) 66,800 163,700 230,500

Wind Farms 66,000 300,000 366,000

Wind Turbine OEM 210,000 560,000 770,000

High-speed Rail 2.3 million 4 million 6.3 million

Beijing Urban Rail 1.6 million 2.8 million 4.4 million

Forestry Management ~1.65 million

Total ~13.7 million

Source: Worldwatch Report 185 and DBCCA analysis, 2012 Note 1: Jobs data relates only to solar power farms and does not include solar PV supply chain jobs.

While the combined effect of wind and solar power is estimated to create 1.4 million jobs during the 2011-2020 period, the

major jobs creator appears to be the mass transportation sector, presumptively due to the high ongoing staffing levels

associated with mass transportation. While wind and solar development may create manufacturing jobs that require



sustained levels of business activity to preserve, jobs created by mass transportation expansion may have greater longevity

due to the relatively higher level of personnel-intensity associated with operating and maintaining rail and subway systems.

In total, our interpretation of Worldwatch’s data suggests that China’s intelligent emphasis on green and low-carbon

development could generate approximately 14 million new jobs through 2020 (which does not include new jobs creation

arising from continued expansion of the domestic PV supply chain or the traditional power industry as less efficient units are

replaced with more efficient or natural-gas fueled units.)

In the 2011 period, CLSA34

and Bloomberg New Energy Finance35

estimate China had approximately 31 GW and 33 GW,

respectively, of domestic wind turbine manufacturing capacity. Bloomberg New Energy Finance’s “PV Solar Supply Model”

estimates36

within China approximately 34 GW of PV module capacity for 2011. While China does not have explicit “GW”

targets for domestic manufacturing capacity, national policies do emphasize an 80% local content objective over time.

Further expansion of wind turbine and solar module manufacturing capacity may not occur for another two years as both

markets currently are facing substantial surplus manufacturing capacity as noted in Figure 11 in the Executive Summary.


By 2020, China’s energy needs are forecast to expand by between 53% - 57% from 2009 levels depending on forecast

sources. One of China’s clearly stated national policy goals is to decrease the country’s reliance on fossil-fuels.

The initiatives to decarbonize will likely involve the growth of all low-carbon and renewables resources with particular

emphasis on wind and solar power and biomass. Hydropower is approaching maximum scale of 360 – 410 GW. Please see

our report entitled “Hydropower in China - Opportunities and Risks37” for more details on China’s hydropower strategy.

Wind and solar power represent substantial opportunity for China so long as it can simultaneously expand the electricity

transmission grid at a comparable or faster pace. While wind power has already reached meaningful scale (47 GW exiting

2011) and solar at 2 GW is just beginning to have impact on the system, both energy sources are likely to experience

substantial growth through the 2035-2050 period as wind and solar develop toward long-term goals of 1,000 GW and 85-

100GW, respectively.

By 2020, if China is successful in executing it low-carbon transformation plans, the impact of investment in low-carbon and

renewable energy sources is forecast by China to have material impact on the country’s energy carbon emissions. Figure 57,

below, provides a comparison of China’s 2009 and 2020 primary energy mixes. Assuming that China remains fully committed

to renewables development and is able to reduce growth in fossil-fuel demand through energy efficiency and energy

conservation measures, then it appears that China could successfully increase the share of low-carbon and renewables to

15% of total primary energy supply by 2020 from 8.7% in 2010. Such an achievement would be consistent with goals set forth

in the 12th

Five Year Plan (see our report “China’s 12th

Five Year plan Update38

”) and other national commitments for carbon

and energy use reduction announced in a variety of international forums.

34

“Blowing Hot,” Charles Yonts, Zac Gill, CLSA Asia-Pacific Markets, 5 January 2012 35

“Q2 2012 Wind Market Outlook,” Bloomberg New Energy Finance, May 2012 and DBCCA analysis 2012 36

http://www.bnef.com/Pvsm accessed on 4 June 2012 37

Access this report, “Hydropower in China – Opportunities and Risks,” at http://www.dbcca.com/dbcca/EN/_media/Hydropower_in_China-Opportunities_and-Risks.pdf 38

Access this report, “China’s 12th Five Year Plan Update,” at http://www.dbcca.com/dbcca/EN/_media/China_EE_WorkPlan.pdf

http://www.bnef.com/Pvsm

http://www.dbcca.com/dbcca/EN/_media/Hydropower_in_China-Opportunities_and-Risks.pdf

http://www.dbcca.com/dbcca/EN/_media/China_EE_WorkPlan.pdf



Figure 57: Renewable shares of energy supply forecast to increase

Fuel 2010 2020e

Hydro 7.2% 9.0%

Other renewable 1.5% 3.0%


Fossil Fuel 90.6% 84.4%

Nuclear 0.7% 3.0%

Total 100.0% 100.0% Source: DBCCA analysis 2012.

Estimated Investment

This growth will require substantial investments. We estimate that through 2035 China could make cumulative investments of

between RMB6.3 trillion (USD$1 trillion) – RMB6.8 trillion (USD$1.1 trillion) in wind power, solar power systems and electricity

transmission grid expansion.

Prospective Power Requirements

Urbanization and improving incomes are key contributors to greater per capita electricity consumption. We believe China’s

demand for electricity will rise at an average annual compound rate of 6.6% from 2011-2020 while the economy expands at

an estimated 7.6% rate. China must expand generation and transmission capacity significantly: We estimate from 2010

through 2020, China will have to add approximately 936 GW, almost doubling the 2010 installed capacity base of 966 GW and

renewables generation capacity will add approximately 340 GW in the 10 year period, accounting for 36% of increased

capacity.

Looking ahead, in Figure 58, for the 2010-2020 period, we estimate grid-connected wind power will expand at an annual

average compound growth rate of 21%. In the same period solar power, growing from a very small base, we estimate will

expand at an annual average rate of 65% while hydropower, the most mature and fully-developed of the renewable power

technologies, will grow at only 5%. China’s ability to successfully execute long-term growth plans for up to 1,000 GW of wind

power by 2050 and 100 GW of solar power by 2035 will be contingent upon China simultaneously executing a large-scale

overhaul and expansion of the electricity transmission grid.



Figure 58: DBCCA China electricity base case

Electricity Production (TWhe) Cumulative Installed Generation Capacity (GW)

2010 2015 2020 2010 2015 2020

Thermal 3,330 79% 4,995 78% 6,316 75% 707 73% 1,011 69% 1,254 66%

Nuclear 74 2% 213 3% 469 6% 11 1% 27 2% 61 3%

Wind – Installed Capacity

NM NM NM NM NM NM 45 NM 123 NM 216 NM

Wind – Grid Connected

(1)

43 1% 212 3% 431 5% 30 3% 111 8% 201 11%

Solar 0 0% 16 0.3% 37 0.4% 0.26 Nil 15 1% 30 2%

Hydro 721 17% 935 15% 1,135 13% 216 22% 290 20% 341 18%

Other RE 38 1% 48 1% 63 1% 3.4 1% 13 1% 17 1%

Sub-Total RE

(1)

803 19% 1,211 19% 1,667 20% 249 26% 429 30% 589 31%

Non-Fossil(1)

876 21% 1,425 22% 2,136 25% 260 27% 456 32% 650 34%

All Fuels Total

4,207 100% 6,421 100% 8,452 100% 966 100% 1,467 100% 1,904 100%

Source: National Bureau of Statistics of China and DBCCA analysis, 2012. Note 1: Includes only Grid-Connected wind power. Does not include Installed Capacity amounts that are not grid-connected.

Figure 59, below, provides a visual summary of the data contained in Figure 58. The strong growth in renewables is evident

and could be even greater if China were to materially accelerate solar power development. We note, however, that storage

and transmission remain gating factors for dramatic and rapid acceleration beyond current forecasts for PV development.

Figure 59: Electricity fleet, 2010 and 2020, by fuel

Source: DBCCA analysis, 2012

Figure 60, below, illustrates the cumulative Government/DBCCA forecast change in China’s electricity generation fleet from

2010-2020. Of the total forecast cumulative growth in China’s electricity infrastructure, 23% of the growth is accounted for by

all renewable sources. Including low-carbon nuclear, non-fossil sources would account for 42% of the cumulative increase in

installed generation capacity.

706

1,011 1,254

216

290

341 111

201

-

400

800

1,200

1,600

2,000

2010 2015 2020

GW

's o

f In

sta

lle

d C

ap

ac

ity

Fossil Fuels Hydro Nuclear Biomass Wind Solar

1,467 GW

966 GW

1,094 GW



Figure 60: Traditional fossil fuels still dominate growth in power supply through 2020

Source: DBCCA analysis, 2012.

IEA vs. Government Forecasts

Since China has not yet released a formal and detailed electricity plan through 2020, we have developed our own forecast of

China’s electricity infrastructure. This modeling was done in the context of China’s many related goals and targets for growth,

energy and electricity use.

Figure 61, below, compares our forecast of the cumulative incremental growth of China’s electricity infrastructure vs. the IEA

forecast contained within their “New Policies” Scenario. While our forecast for hydropower, wind and solar power appear to

be modestly higher than the IEA forecasts, we note they are fully consistent with China’s published objectives and policies

through 2020. Given the prospect of increasing power shortages and the continued international pressure to remain on a low-

carbon development trajectory, we believe there is a greater probability that China will exceed our current forecast rather than

track the IEA’s more modest forecast.

548

125

215

50

-

200

400

600

800

1,000

China 2010-2020 Incremental Expansion

Inc

rem

en

tal I

ns

talle

d C

ap

ac

ity, G

W




Figure 61: Comparison of IEA and DBCCA forecast cumulative growth through 2020

Source: IEA and DBCCA analysis, 2012

Biomass & Biofuel

While China has not yet published a detailed renewable energy work plan for the 12th

Five Year Plan period, there are various

forward-looking comments from government officials addressing what may turn out to be official policy targets. Based on

these informal and unofficial disclosures, it appears China may have biomass-fired generation capacities of 15 GW and 30

GW by 2015 and 2020 respectively. As shown in Figure 62, approximately one-third of this capacity will be grid connected

with the remaining two-third used for self-generation and “off grid” community generation.

Figure 62: Biomass: More off-grid than on-grid

Type of Generation

(GW, Installed Capacity) 2015 2020

On-Grid Biomass 5 10

Off-Grid Biomass 10 20

Total Biomass 15 30

Biomass-Fired As % of Total Generation 1.0% 1.6%

Total System Generation 1,467 1,903

Source: National Bureau of Statistics of China, State Forestry Administration, China Securities Journal and DBCCA analysis, 2012.

Overall, we see China’s ambitions to expand biomass-fired generation to be of such small scale relative to the entire energy

appetite that biomass-generation becomes, we think, more concern of localities rather than a driver of national policy.

Although the 12th

Five year Plan does not explicitly address biofuels goals, but with a national objective to reduce dependence

on foreign energy sources, there is discussion by government officials that suggests bio-ethanol could expand to 1.75 million

tons in 2011 to 10 million tons by 2015, representing an average annual compound growth rate of 21% per year (in

comparison to a ~6% average growth rate since 2006). And currently bio-diesel production is negligible and un-named

officials suggest production could rise to only 1 million tons per year by 2015.

-

40

80

120

160

200


Inc

rem

em

en

tal G

W's

20

10

to

20

20

IEA Forecast

Gvt/DBCCA




China has experienced drought conditions 32 times in the past 110 years. Some regions of China suffer water stress rated

from moderate through extreme in a significant northern portion of the country. The 2011 drought season was severe enough

that hydropower production was modestly impaired. Agriculture has also suffered, although China has been able to avert

catastrophic crop failures in recent years. Please see our note entitled “Hydropower in China: Opportunities and Risks”39

for a

more detailed discussion of China’s water use. With China’s recent rapid industrialization, industrial uses of water have

expanded from 10% of total water use in 1990 to 23% in 2010. Further, urbanization trends have increased municipal water

consumption from 7% in 1990 to 14% of share in 2010. We summarize these share shifts below in Figure 63.

Figure 63: China’s water use – Shifting with industrialization


China’s economic growth, though consuming more water, has occurred with steadily improving water intensity as shown in

Figure 64, below. New in the 12th

Five Year Plan, announced in March 2011 (Please see our notes entitled “12th

Five Year

Plan – Chinese Leadership to a Low Carbon Economy” and “China 12th FYP Update”), were targets for improved industrial

water intensity aiming for a cumulative 30% reduction by 2015 from 2010 levels.

39

Access the research note at http://www.dbcca.com/dbcca/EN/investment-research/investment_research_2399.jsp

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%




Figure 64: Comparative water use per GDP Capita – For China, 30% improvement target


As can be seen in the chart, China’s pace of improvement for water utilization in post-2006 has slowed. We believe China will

continue to upgrade and overhaul industrial facilities to achieve these goals.

2.4 Challenges

The tools to solve China’s energy problems are in the hands of the national planning organizations and electricity and grid

operators. While some may focus only on incremental renewable generation capacity expansion, we believe the investment

needed for the electricity transmission grid expansion will be of similar scale and scope. The need to bring market-price

signals into the electricity generation system coupled with the scale of expansion and overhaul in the coming decades may

require a broad restructuring of the electricity sector in China. This would not be a simple task given the influence of the State

–owned enterprises that dominate the electricity sector as well as the complex relationships between provincial and national

governmental bodies and the State-owned enterprises.

0

50

100

150

200

250

300

350

400

450

500

0

100

200

300

400

500

600

700

800

1990 1996 2000 2006 2010

Use p

er

GD

P C

ap

ita,

M3/G

DP

Wate

r W

ith

dra

wls

, B

n M

3/y

r

Total - Brazil Total - China Total - India

Per GDP Capita - Brazil Per GDP Capita - China Per GDP Capita - India

Emerging Markets: India


3. Emerging Markets – India Energy Overview

India’s energy requirements are supplied primarily though combustion of coal, oil and a range of biofuels (primarily solid

biomass, wood and waste). Compared to other major countries, India derives its energy from a relatively broad range of

waste streams. Figure 65 provides some perspective on India’s primary energy sources.

Figure 65: India’s primary energy mix 1990-2009


Although Combustible Renewables and Waste accounted for approximately 35% of national energy needs in 1990, that

proportion has declined steadily to slightly less than 30% by 2009 as the expansion of the economy outpaced growth in

natural waste streams. Fossil fuels accounted for approximately 73% of primary energy in 2009. Segmented into fuel types,

coal provided 42%, oil 24% and natural gas 7% of total primary energy supply. Coal, a domestically available resource, was

relied upon to fill increased energy demands, especially in the electricity production sector. On the other hand, 80% of Oil

used was imported40

. The majority of oil consumed by the country is used for transportation and as an industrial input.

Since 1990 through 2009, India’s energy needs have expanded at an average annual rate of 4.1% while the economy has

grown at an average annual rate of 6.4%. Consequently, India’s Energy Intensity has declined at an average annual pace of

2.2% reflecting consistent improvements in extracting additional value from each unit of energy consumed – this is similar to

China, while Brazil’s energy intensity has actually increased in recent years. Figure 66 depicts these historical energy usage

trends in India.

40

As reported in the Government of India’s “Strategic Plan for New and Renewable Energy Sector for the period 2011-2017,” released in February 2011

0

10

20

30

40

50

60

70

80

90

100

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Pe

rcen

t o

f M

ix

Fossil Fuel Combustible Renewables and Waste Alternative and nuclear energy



Figure 66: India’s energy trajectory: More efficient energy use


As a comparison, Figure 13, (above in section 1) depicts the fuel mixes of Brazil, India and China. Compared to the other two

BICs countries, India’s energy diet is more similar to China’s than to Brazil’s. India draws 73% of energy from fossil fuel (42%

from coal and 24% from oil). In comparison, fossil fuels account for 87% of China’s energy mix and only 51% of Brazil’s.

India and Brazil are similar only in terms of their use of biomass: 25% of India’s energy needs are provided by biomass while

in Brazil biomass delivers 29% of energy needs.

Figure 67 shows that the end use of energy in India is also materially different compared to Brazil and China: 40% of energy

in India is consumed within the Building sector (commercial and residential) while the biggest end-use sector in Brazil is

Transportation (33%) and in China it is Industry (35%). We attribute a relatively high mix of energy consumed in buildings to

reflect the nature of the service sector in India compared to the Industry and Transportation sectors.

-

100

200

300

400

500

600

700

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

En

erg

y U

se

pe

r C

ap

ita

an

d p

er

GD

P

To

tal E

ne

rgy U

se

( k

T o

il e

qu

iva

len

t)

Total Energy Use

Energy Use per GDP (constant 2005 PPP)

Energy Use per Capita



Figure 67: Comparative energy consumption mix for India

Source: International Energy Agency and DBCCA analysis, 2012

From an electricity industry perspective, the composition of generating capacity and electricity production differ meaningfully

from the overall national energy appetite which is influenced by transportation and all forms of energy used in manufacture,

commerce and living.

For years, India has suffered from severe power shortages. In 2010 the Government of India estimated that a 12.7%

electricity production deficit (15 GW) existed and would worsen unless aggressive actions were taken to conserve electricity

and to expand both generation and electricity grid capacity. Such an electricity shortfall was estimated by the government to

have reduced GDP by 6% points, implying a cost of USD$2.24/kWhr shortfall, an amount far in excess of the levelized costs

of electricity from all major generation methods.

Further, the government estimates that greater than 50% of the population is without access to commercial energy systems

for living or work use. Power losses within the system approximate 29% in 2009, suggesting gross inefficiencies and perhaps

significant unbilled consumption compared to 10% leakage and losses in more developed countries. Certainly addressing

energy access is a crucial issue in India and much work is being done by initiatives such as the UN Secretary General ’s

Sustainable Energy for All program. Although we do not address it in detail in this paper, we note that using off-grid solar is

potentially a very interesting sustainable and local solution for energy access subject to cost constraints which should diminish

over time. Based on the Government of India’s forecasts through 2017, the government’s rural solar power electrification

program aims to install a modest 1 GW of off-grid solar power to support 270 villages.

Industry24%

Transport11%

Building40%

Other13%

Electricity12%

Industry

Transport

Building

Other

Electricity



Figure 68: India electricity installed capacity by source, FY 2012 – Total 200 GW

Source: India CEA monthly report and DBCCA analysis, 2012

Figure 69: India electricity generation by source, FY 2012 – Total 877 Twhr

Source: India CEA monthly report and DBCCA analysis, 2012 Note: Bhutan IMP indicates electricity amount imported from Bhutan

India’s electricity is primary fueled by coal and large hydro, together representing 76% of its electricity installation, followed by

oil by 9% and RES (includes small hydro, biomass, wind, solar and other renewable source) by 12%, as depicted in Figure 68

above. From an actual electricity production perspective, 81% of electricity production is derived from thermal power, 15%

from large Hydro, 4% from nuclear and 0.6% imported from Bhutan as shown in Figure 69. The use of thermal fuel in India’s

electricity sector is similar to China where approximately 82% of electricity is provided by thermal. Unfortunately, the CEA, the

Indian electricity authority, doesn’t include RES in their accounting system in electricity generation for disclosure.

Coal56.0%

Gas9.2%

Oil0.6%

Nuclear2.4%

Large Hydro19.5%

RES12.3%

Thermal80.8%

Hydro14.9%

Nuclear3.7%

Bhutan IMP0.6%



In recent years wind power has contributed to the growth of this sector. Solar power is just beginning to have an impact.

Unlike other major developing economies, India’s use of fuel oil as a fuel for electricity production has increased due to use in

local small generator systems when either grid access is not available or when the grid-supplied electricity cannot be relied

upon. However, this is not a positive long term strategy for India’s energy supply given the relatively high and volatile prices

of oil, and the environmental effects of burning this fuel.

3.1 Renewables

Current Status

Renewable power is becoming an increasingly visible element of India’s energy and electricity strategy as more rapid

adoption helps mitigate carbon emissions and address electricity demand necessary for macroeconomic growth. Figure 70

illustrates the composition of India’s renewables generation base at the end of 2010.

Figure 70: Composition of renewable installed capacity in India, 31

st Jan, 2012 – 62 GW


Hydropower, large and small (<25 MW per installation) dominates the current base of renewable installed capacity. As in

other BICs and western countries, large-scale hydro represents the vast majority of India’s hydro resources. Only recently

has wind power expanded to a meaningful scale – 16 GW in 2010 - and solar is just barely beginning to move the needle.

Bio-energy

From a biofuels perspective, bio-ethanol and bio-diesel are both developed in India, but bio-ethanol production, at 1.4 billion

litres of production in the 2010 fiscal year, dwarfs bio-diesel production that ranges between 140 and 300 million litres per

year. The primary feedstocks for India’s liquid biofuels sectors are sugar molasses, a sugar byproduct, for bio-ethanol and

Jatropha for bio-diesel.

Hydro38.7 GW

67%

Small Hydro3.3 GW

5%

Wind16.2 GW

23%

Biomass/gas3.2 GW

5%

Solar0.05 GW0.03%



Figure 71: India’s ethanol production summary statistics

(Million Litres) 2006 2007 2008 2009 2010

Beginning Stock 483 747 1,396 1,673 1,283

Production 1,898 2,398 2,150 1,073 1,435

Imports 29 15 70 320 150

Total Supply 2,410 3,160 3,616 3,066 2,868

Exports 24 14 3 3 3

Consumption

Industrial Use 619 650 700 700 720

Portable Liquor 745 800 850 880 900

Blended petrol 200 200 280 100 50

Other Use 75 100 110 100 110

Ending Stock 747 1,396 1,673 1,283 1,085

Feedstock (1,000 mt) 7,910 9,992 8,958 4,469 5,981

Source: India Biofuels Annual 2011, USDA - Delhi and DBCCA analysis, 2012

Figure 72: India’s bio-ethanol consumption mix - 2010


Bio-ethanol has a wide range of uses in India as in Brazil. Sugar cane availability and the relative price of sugar as a

sweetener versus as a fuel influence the amount of sugar molasses available to bio-ethanol refiners. Recent shortages have

constrained India’s ethanol mix to approximately 3% of fuel volumes despite an ambitious government target for a 20% blend

rate by 2017. Complex land ownership issues and political gridlock have, so far, stymied efforts to improve bioethanol

production and the fuel blend percentage.

In Figure 72, above, 40% of bio-ethanol ends up being used as an industrial input. Currently liquor manufacturing is the

largest consumer, using 51% of annual production. Bio-ethanol for fuel blending accounted for only a modest 3% of volumes

in 2010. This low level reflects a very poor sugar harvest in 2009 and 2010. Comparatively, in 2008 and earlier, bio-ethanol

used for fuel blending accounted for 14% of bio-ethanol use.

40%

51%

3%

6%

Industrial

Liquor

Petrol Blending

Other



India has a very demanding transportation sector, with few domestic traditional fuel sources available as substitutes. In 2009,

India had 65 million vehicles on the road and the fleet has been recently growing between 8%- 10% per year. For

perspective, India is the world’s fourth largest petroleum importer and those imports serve 80% of the national petroleum

needs.

Figure 73: Transportation drives India’s liquid fuel needs


As depicted in Figure 73, transportation use is the greatest consumer of petroleum in India. In terms of biofuels consumption,

bio-ethanol is consumed for transportation purposes while bio-diesel is used almost exclusively in the agricultural sector as an

equipment and irrigation fuel. Commercial sale production of bio-diesel in India is not practical as government approved

selling prices are currently below production costs. For second generation biofuels, Jatropha availability remains challenging.

Lack of feedstocks prevents scaling of the biodiesel sector. Various business entities have signed MOU’s with several state

governments to develop Jatropha plantations although highly fragmented land holdings and disputes over ownership of

feedstock rights for communally-owned lands complicates development. Further, Jatropha requires multiple years to mature

before seeds can be harvested as a biodiesel feedstock.

Policy Support

Pursuant to the National Action Plan on Climate Change, India has eight major policy initiatives that address energy and

sustainability issues. Through these plans, a wide range of supportive policies complimented with explicit targets, incentives

schemes, duty waivers and tax preferences were created and seem constantly in flux. Unfortunately, recent wavering and

cancellation of accelerated depreciation and related feed-in tariffs (national GBI) for wind power sends a chilling message to

those developers contemplating opportunity in India’s ambitions for wind power development through 2017. Further, India

does not offer prioritization of use for renewables-produced electricity versus thermally generated electricity.

In terms of maturity, India views wind power, biomass and small-scale hydro power as adequately mature and commercially

viable technologies. Solar power – photovoltaic (PV) and concentrating solar thermal (CST) - are approaching commercial

viability as costs continue to decrease. Policy actions, collectively, support all the various renewable methods to varying

degrees.

Liquid biofuels policy support, however, is mixed. While there exist ambitious targets for a 20% blending level by 2017 for

both bio-ethanol and bio-diesel, India is able to only achieve a 5% blend rate for ethanol at this time. Sugar molasses

availability problems are compounded by land use, jurisdictional and policy implementation disputes between different



ministries, some of whom have opposing focus (farming and liquor manufacturing constituencies). There are no firm policy

support mechanisms in place to address the cost and feedstock supply problems facing bio-diesel entrepreneurs.

Legislative and Administrative Framework

Underscoring India’s commitment to embracing renewables are at least 10 major pieces of legislation or rule-making that

establish the framework for the formulation and administration of supportive policy. Figure 74 summarizes the roles these

major pieces play in the greening of India.

Figure 74: Summary of renewable energy and energy efficiency legislation

Policy Document Key Points

Electricity Act (2003) Mandates each SERC to have minimum renewable energy purchases

Authorizes creation of national incentive structure

National Electricity Policy (2005)

Authorizes SERC’s to implement incentives schemes

Rural Electrification Program (2005)

Provides 90% capital cost subsidy to bring electricity (renewable or thermal) to those regions falling

below the poverty line

National Tariff Policy (2006)

Mandates each SERC to have time-bound required purchase obligations (RPO’s)

11th

Plan (2007-2012) Targets 10% of electricity generation capacity from renewables by 2012

Phases out most capital cost subsidies in favor of GBIs/FiTs

National Action Plan on Climate Change (2008)

Sets target of 15% of total energy from renewable sources by 2020

Forms 8 administrative commissions dedicated to renewable energy and energy efficiency

Jawaharlal Nehru National Solar Mission (2009)

Establishes 10 GW PV, 10 GW concentrating solar thermal and 2 GW off-grid PV goals by 2022

Establishes 4 GW – 5 GW target for indigenous solar PV manufacture by 2022

National Policy on Biofuels (2009)

Approved policy targets a 20% blend rate for both bio-ethanol and bio-diesel

REC Program (2010)

Establishes framework for either:

- Use of favorable GBI/FiT incentives OR

- Ability to sell emissions credit while receiving average system electricity tariff

National Mission on Enhanced Energy Efficiency PAT Scheme (2012)

Sets industry targets for energy 3% energy intensity savings by 2013 relative to most recent 3 year

average energy intensity

Source: Government of India, NREL and DBCCA analysis, 2012

Incentives Summary

India has moved away from up-front capital cost subsidies as it became apparent that such mechanisms simply encouraged

capacity expansion with little concern for electricity production and efficacy. India has a seemingly broad range of eight

“mission” statements under the National Climate Change Action Plan that set various targets and objectives for improving

India’s sustainability and, in particular, both the quantity and efficiency of energy use within the economy. Contributing to the

funding for these subsidies are monies collected by the National Clean Energy Fund, administered by the Ministry of Finance

(interestingly not the Ministry of New and Renewable Energy). This fund generates approximately USD$600 million per year

(INR30 billion) by collecting INR0.50/ton tax on coal sales. The proceeds are intended to be used exclusively for funding

renewable energy projects.

The purpose of this section is not to provide a comprehensive overview of these eight actions plans. We do, however, focus

on key “missions” that influence both renewable energy and energy efficiency.

Wind and Solar Power – Key Incentives

Indian wind power and solar power incentives fall into two general categories: revenue enhancements (appealing state-level

FiTs) or tax benefits (accelerated depreciation). The interaction of these incentives is complex in that there are varying mixes

of incentives depending on project type (wind or solar), structure and location. The majority of financial benefits are now

manifest through state feed-in tariffs OR use of a renewable energy credit scheme, making a simple overview statement on



the financial magnitude of the various incentive offerings is quite difficult as the mix of various options also depends on use of

specific state programs. However, like other profit driven markets, regardless of the complicated structural mechanics of

incentives, projects are undertaken when the developer sees a positive return above his hurdle rate. The two major decision

branches for both wind and solar incentives can be conceptually segmented as in Figure 75, below.

Figure 75: FiTs vs RECs as primary incentive tools

Under REC Incentives Under FiT Incentives

Pricing Method Bilateral contract pricing or Open Access Market sales

Reverse Auction price set for FiT subject to “Reference Price” maximum

Buyer Can sell to any buyer Can sell only to DISCOMs

Green Credit Can be Bundled or Stripped Only Bundled

Depreciation Benefits

Cancelled for Wind Accelerated treatment still available for Solar

Cancelled for Wind Accelerated treatment still available for solar

Source: DBCCA analysis 2012

The Indian policy support programs have changed materially in the past several months with the passage of the 2012/2013

budget, thus further complicating clear understanding and most likely slowing wind power development in the country to a

pace below that needed to meet government plan objectives. Although major policy support mechanisms like accelerated

depreciation (“AD”) and generation based incentives (“GBI”) for wind have been removed, there is considerable effort

underway now to restore them and thus understanding them is necessary. REC programs remain available for both solar and

wind power projects. As a technicality, the India SERCs refer to “Solar RECs” and “Non-Solar RECs” which are mostly wind

power-sourced REC’s. As shown in Figure 76, below, “Non Solar” RPO requirements reflect the vast majority of India’s

potential market for REC’s in the top 6 states with proactive renewables policies to take advantage of the assessed wind and

solar resources. Please see our discussion of challenges, below, for commentary on difficulties that may lie ahead in using

this method as a catalyst for dramatic renewables expansion.



Figure 76: Top renewable states and RPO requirements – 2013

Source: Government of India and DBCCA analysis 2012

Below we provide a synopsis of what the rules were, recent challenges and the financial implications of possible revisions.

Our discussion will be segmented into “wind” and “solar” as structurally different programs exist for the different energy

sources.

Wind Power Incentives Synopsis

In April 2012 accelerated depreciation benefits for wind power expired. Wind power developers had traditionally benefitted

from governmental support policies through a combination of tools: FiTs provide necessary transparency, longevity and

certainty on the revenue side while accelerated depreciation benefits materially influenced expense and cash flow profiles.

India’s recent decision to not extend accelerated depreciation for wind power projects will, in our estimation, result in some

projects becoming non-viable and not being pursued. Cumulatively, the effect of this expiration may result in wind power

growth missing government targets. (NB: accelerated depreciation for solar power remains available)

Accelerated Depreciation and GBI

Originally only wind projects developed by industrial businesses were able to enjoy 80% accelerated depreciation rules. This

rule was created in 1961 to speed industrial development and provide a way for industrial businesses to shield profits

generated by their core operations. Wind power projects developed by IPPs and utilities, initially, were not eligible. To

address this situation, the national government implemented a modest feed-in tariff called the GBI in the amount of INR

0.50/kwhr (~USD$0.01/kwhr). Compared to the state-level FiTs for the sale of electricity (see Figure 77), the GBI was

comparatively small. In 1987 the rules were changed allowing wind projects, industrial or IPP-developed, to be eligible for

80% accelerated depreciation. Thus the first “decision” point that arose for wind developers: “use AD or GBI?” Use of both

was, unsurprisingly, prohibited. For projects commissioned in 2011, BNEF reports that 61% of projects elected to use

accelerated depreciation with 39% choosing GBI.

Gujarat

Maharashtra

Karnataka

Tamil Nadu

Uttar

Pradesh

0%

6%

12%

0%

6%

12%

0%

6%

12%

0%

6%

12%

Himachal

Pradesh

0%

6%

12%

0%

6%

12%

0%

6%

12%

Rajasthan

“Wind Power & Other” RPO FY 2013

“Solar” RPO FY 2013



Renewable Energy Certificates and Renewable Power Obligations

In 2003 the Electricity Act authorized the creation of a renewable power obligation. The National Action Plan on Climate

Change (NAPCC) in 2008 spurred the state electricity regulatory commissions (the SERCS) in 28 states and 7 territories to

implement renewable purchase obligations that would have to be met by utility companies distributing electricity (DISCOMs)

and large scale industrial and commercial energy users (“obligated Parties”). The NAPCC made recommendations of the

state by state renewable purchase obligation (“RPO”) targets, yet left the final determination to the many state and territorial

SERC bodies. Essentially, the RPO was determined as a percentage of electricity consumed in the state (e.g, 6% of electricity

consumed in FY2013) and the satisfaction of the RPO was to be through creation of renewable energy certificates (REC’s)

denominated in 1 million kwhr units. In theory, the various DISCOMS and Obligated Parties are to be held legally responsible

for failing to meet RPO targets through purchase of “green electricity.” To date, few provinces are in compliance and the

national and state governments have failed to enforce RPO requirements.

Wind Power Tariffs

The tariffs for wind power are determined at the state levels, typically through a reverse auction process where the “reference

price” reflects the maximum price to be paid for electricity for those projects that want a FiT, or through bilateral or open

market pricing for those developers who seek to use the REC scheme.

For the FiT incentives, competition among developers for an opportunity to win business elicits from them bids below the

reference price. In the case of a FiT structure, the counterparty is a not a DISCOM, but instead is the NVVN which is the

national authorized power trading hub operated by NTPC, India’s largest generator. NVVN then bundles the various

contracted power and allocates it, in concert with the grid operators, to the purchasing DISCOMS.

For the REC scheme, developers can contract with Open Access customers (large buyers) or with DISCOMs for the electricity

or simply sell it on the spot market. Power sold under the REC scheme can be sold with the REC bundled or the REC can be

stripped and sold on the market to those in need of REC‘s to satisfy their RPO obligations. Such power transactions must

occur in the same state in order to be counted under RPO obligations. In the national RPO scheme, the RPO requirement for

“Non Solar RECs” dwarfs the requirements for Solar RECs, placing a strong bias on wind power projects. Figure 76, above,

illustrates the comparative RPO targets for key renewables states. Figure 77, below, summarizes recently awarded FiT rates

for those states with active wind power development programs.

Figure 77: Recently awarded wind power FiTs

State

Recent FiT Awarded INR/kwhr

Cumulative Installed Base (MW), 2011

Andhra Pradesh 3.50 NA

Gujarat 3.56 2,175

Karnataka 3.70 1,730

Madhya Pradesh 4.35 NA

Maharashtra (Base – 30% CF) 3.24-5.67 2,311

Rajasthan Jaisalmer, Barmer and Jodhpur districts

4.22 1,525

Rajasthan other districts 4.44 (1)

Tamil Nadu 3.39 (1) 5,904

Other Regions NA 1,855

National Total 15,500 Source: BNEF and DBCCA analysis, 2012 Note 1: Currently subject to revision



Solar Power Incentives Synopsis

States appear to take a more active role in setting targets for solar power compared to wind power where comparable state by

state targets are not available. At the national level, The National Solar Mission Program is currently in its first phase through

2013. Second and third phases are sketched out in the legislation, though “targets” for phase II (2017) and phase III (2022)

appear to us as notional goals rather than firm targets given the time periods involved and the rapid shifting dynamics of the

solar power sector. The plan has a notional 2030 ambition of 100 GW. It is important to note that all targets under the

National Solar Mission reflect total combined PV and solar thermal capacities. The program expects that targets will be split

equally between PV and solar thermal technologies. We believe the rationale for this 50/50 split can be found in national

industrial policy strategies intended to balance solar development.

Figure 78: Solar targets and goals – State and national

Political Body/Policy Disclosed Solar Targets

Gujarat 959 MW in pipeline for completion by 2011

Karnataka 40MW/ through FY16

Madhya Pradesh Developing Targets

Maharashtra (Base – 30% CF) 500 MW installed in 3 years

New Delhi 20 MW Rooftop installed in 3 years

Rajasthan - other districts 200MW Installed by FY13, 400 MW by FY17

Tamil Nadu Developing Targets

National Solar Mission Phase I Incremental 1,000 MW by 2013

National Solar Mission Phase II Est. Incremental 3,000 -9,000 MW by 2017

(Funding Uncertain)

National Solar Mission Phase III Est. Incremental 10,000 MW by 2022

(Funding Uncertain) Source: BNEF and DBCCA analysis, 2012

We included Gujarat’s “pipeline” from 2011 in the above table because of considerable project slippage pushing substantial

quantities into the future, thus rendering them more as “soft targets.” Gujarat’s 959 MW of capacity in the 2011 project

development pipeline was originally scheduled for completion by 31 December 2011. By 5 December 2011 only 51 MW had

been completed. It appears a considerable portion of the pipeline remains an objective to be achieved in FY2013, though it is

unclear if previously bid-based tariffs will be awarded for late-delivered projects.

Accelerated Depreciation and GBI

Solar power projects can use an 80% accelerated depreciation schedule. This aspect did not expire when the similar benefit

for the wind sector expired in April 2012. Solar PV project developers do not have available to them a GBI option as an

alternative to accelerated depreciation, though under the Jawaharlal Nehru National Solar Mission program, the state that

hosted a developer operating under the project could receive a the GBI from the national government to defray the costs

incurred by the state-based feed-in tariff.

Developers can participate in reverse auctions that take advantage of a national feed-in tariff pursuant to reference pricing set

out in the Jawaharlal Nehru National Solar Mission (JNNSM) program on the order of INR 17.9/kwhr (USD$0.36/kwhr) for a

25 year power purchase agreement. As in Brazil, the “reference” price is the maximum price and competitive bidding for

limited opportunity to sell power results in prices below the reference price.



Renewable Energy Certificates and Renewable Power Obligations

Solar REC’s work in ways similar to Non Solar RECs. To date, most developers have chosen to take advantage of the FiT

process rather than the REC scheme. One possible reason for this is the relative immaturity of solar PV and lack of familiarity

by financing partners. Another possibility is the concern over the value of the RECs due to questions over RPO enforcement

as we discuss below.

Solar Power Tariffs

The states have embraced the successful use of reverse auctions in the wind power sector and have begun implementing it in

the nascent solar power sector. One extra level of sophistication seen in the solar power auction structures is the provision

for FiTs based on whether or not accelerated depreciation is used in the project.

Figure 79: Maximum FiT rates by state

State “Reference” Maximum FiT

INR/kwhr

Discount of “FiT with A/D” compared to “FiT

Without A/D”

With A/D Without A/D

Andhra Pradesh 14.95 17.91 -17%

Gujarat 9.28 10.37 -11%

Karnataka NA 14.50 NA

Madhya Pradesh 13.94 NA NA

Maharashtra 14.95 17.91 -17%

Orissa 15.39 18.52 -17%

Rajasthan 13.19 15.32 -14%

CERC 12.94 15.39 -16%

Source: BNEF and DBCCA analysis 2012

It is clear from the data in the above table that the accelerated depreciation incentive serves as a powerful tool for lower

LCOE and shifting that cost (in the form of forgone tax revenue) to the government and away from the electricity buyer. The

reverse auction processes appear to be successful in achieving costs savings compared to the “reference” FiTs participants

must bid against. Comparing the recently awarded bid data in Figure 80 below, to the reference FiTs in Figure 79, it is clear

that recent bid awards are occurring at far more competitive rates. However, as in the case of Brazil, there is concern that the

“winner’s curse” may be afflicting the Indian reverse auctions where projects may be “won” in bids, then may not be built. We

discuss this problem below.

Figure 80: Recently awarded solar FiT’s

State Recent FiT Awarded INR/kwhr

National Solar Mission I 11.86

National Solar Mission II 8.49

Karnataka 8.22

Orissa 7

Madhya Pradesh Not Disclosed


As in Brazil, reverse auctions methods have delivered substantial improvements in the price of solar power in India. When

solar power development began in earnest in 2009, solar power electricity was priced at USD$290/Mwhr rates. By the end of



2011, the prices had declined to USD$165/Mwhr. Although declining solar PV panel costs certainly contributed to the

improved costs, we believe the efficiency of developers competing with each other also helped to bring down costs.

Hydropower and Biofuels Subsidies

The last remaining renewables areas that receive particular support include hydro power and biofuels production. In the case

of hydropower, support is manifest as a traditional upfront subsidy grant to defray construction costs.

Biofuels support is modest, in the case of bio-ethanol, or meaningless for biodiesel. The minimum support price for bio-diesel

of INR26.50/litre is materially below current production costs of INR30 – 40 per litre. Regarding bio-ethanol, there is industrial

resistance to government wishes to increase the minimum support price to INR27 from INR21.50.

Figure 81: Small hydro power incentives in India

Project Region 100 KW- 1 MW 1 MW – 25 MW

State Projects

Northeast USD$1,000/kW USD$1 million for the first MW; USD$100K thereafter

Other USD$500/kW USD$500K for the first MW; USD$80K thereafter

Private Projects

Northeast USD$400/kW USD$400K for the first MW; USD$60K thereafter


Retrofit Projects

Northeast USD$500/kW USD$500K for the first MW; USD$80K thereafter



Figure 82: Biofuel incentives in India

Benefit Details

Bio-ethanol Minimum support price of INR21.50 per litre

Government of India subsidized loans for up to 40% of project cost to expand cane crushing

Bio-diesel Minimum support price of INR26.5 per litre


Green Energy Use Requirements – Ministry of Telecommunications

While feed-in tariffs and tax benefits influence project development economics, policies that create a demand for renewable

energy also serve a useful role in India’s policy toolkit. While the RPO scheme discussed above serves such a purpose, the

Department of Telecommunications has also implemented rules requiring that 50% of rural mobile phone towers and 20% or

urban towers be powered from hybrid grid and renewable sources. To date, the towers are served by grid connections

supplemented with diesel generators or exclusively by on-site diesel units. Thus, the Department of Telecommunications’

requirements for hybrid power utilizing renewables appears to be intended to eliminate as practicably as possible diesel

generation as a power source for wireless telco towers.

Lots of Policy, Lots of Challenges – The FY2013 Budget Problem

Wind Power Accelerated Depreciation and Generation-Based Incentives: Gone for Good?

On 19 January 2012 India announced that in the new fiscal year beginning 1 April 2012, the previous attractive accelerated

depreciation treatment for wind power assets (80% of capital costs expensible in Year 1) was to expire. This expiration,

however, was cancelled with the preliminary FY2013 budget announced in March 2012, suggesting preservation of the



depreciation treatment. Ultimately, and to the surprise of the sector, by the time the budget was agreed upon by the

government, the accelerated depreciation benefit for wind power was, finally, formally removed. Further surprising the

industry, the generation-based incentive (which was originally created as FiT-like analog to accelerated depreciation applied

at the national level) was also cancelled. Such shifts in policy, we believe, are counterproductive to establishing a supportive

framework of policy and incentives to foster the growth of renewables.

Figure 83: Summary on impact on Wind LCOE from loss of incentives


It is immediately evident that the impact caused by loss of these incentives is significant. Based upon a notional “base LCOE”

for typical projects in the several regions, the accelerated depreciation incentive has almost a 3x impact on LCOE compared

to the generation-based incentive (Figure 83).

With the wind sector choosing accelerated depreciation versus GBI at a rate of almost 2:1, the elimination of both schemes is

estimated to have a material impact in the wind power sector. BNEF originally forecast an approximate 3.5 GW of new

installations in FY2013 and 2.5 GW per year of new installations for the two following years under the old policy regime.

Industry and various state powers are trying to find a way to restore these incentives. Should they be unsuccessful, BNEF

estimates that FY2013 installations are likely to fall to less than 2 GW from their originally forecast 3.5 GW level for FY 2013.

Several modified incentive structures have been proposed including a less aggressive (and therefore less expensive one to

the government) accelerated depreciation scheme and a modified GBI scheme. As can be seen in Figure 84, below, these

proposed alternative implementations of accelerated depreciation and generation-based incentives remove the bias that

caused investors to favor the depreciation scheme over the generation-linked scheme.

Figure 84: Proposed concepts for revised incentives41

State

No Accelerated

depreciation and No

GBI (INR/kWh)

"Base LCOE"Typical

LCOE

% Improvemt

from Base LCOE

Typical

LCOE

% Improvemt

from Base LCOE

Tamil Nadu 4.52 4.02 -11% 3.97 -12%

Gujarat 5.65 5.12 -9% 5.09 -10%

Rajasthan 5.72 5.18 -9% 5.14 -10%

Maharashtra 6.03 5.46 -9% 5.45 -10%

Karnataka 4.56 4.11 -10% 4.07 -11%

Proposed Modified GBI at

INR 0.75/kWH (INR/kWh) (2)

Proposed Accelerated

depreciation at 35%/15%

(INR/kWh) (1)


41

“Judgement Day for Indian Wind as Key Incentives Go,” S. Jaiswal et al, Bloomberg New Energy Finance, 11 April 2012

State

Cumulative

Installed

Base

(3/2011)

Annual

Installations

FY11/12

No Accelerated

depreciation and

No GBI (INR/kWh)

MW MW "Base LCOE"Typical

LCOE

% Improvemt

from Base

LCOE

Typical

LCOE

% Improvemt

from Base

LCOE

Tamil Nadu 5,904 1,088 4.52 3.60 -20% 4.22 -7%

Gujarat 2,175 789 5.65 4.59 -19% 5.29 -6%

Rajasthan 1,525 546 5.72 4.63 -19% 5.35 -6%

Maharashtra 2,311 408 6.03 4.89 -19% 5.66 -6%

Karnataka 1,730 203 4.56 3.69 -19% 4.25 -7%

Accelerated depreciation

at 80% (INR/kWh)

GBI at INR 0.5/kWH

(INR/kWh)



We are unable to forecast whether or not these incentive tools will be redeployed and consequently how large India’s wind

power sector might become suddenly becomes quite less certain and most likely smaller than expected unless the national

government acts quickly. Indian bureaucratic and political forces may make prompt action uncertain.

“Reference” Case Capacity Factors Unrealistic

Implicit in the government’s calculations of the “reference FiT” that project developers must bid against are assumptions about

capacity factors for the typical project. If the government is assuming a capacity factor higher than can achieved, then the FiT

reference is likely to be too low to ensure intended financial return. This problem affects both wind and, in particular, solar

where such mistakes can dramatically influence the pace of development. Figure 85, below, illustrates this problem.

Figure 85: Solar capacity factors not as high as expected

State Government Assumed CF

Measured CF Difference as % of Gvt CF

Rajasthan 21.0% 17.7% -16%

West Bengal 19.0% 12.3% -35%

Karnataka 19.0% 14.8% -22%

Maharashtra 19.0% 15.4% -19%

Source: UBS, Government of India MNRE, DBCCA analysis 2012

It is clear from the actual solar capacity factor data measured at various solar projects that the government’s assumptions are

far too optimistic. Such a dramatic error could lead to the government setting too low a reference price. Since current

competitive bid awards are at prices even below the Reference FiTs, it certainly seems possible that some projects may never

be able to get financing and those that do may experience disappointing financial results.

While similar and directly comparable data in the wind sector is not available, we can note that India’s realized wind capacity

factors are also materially lower than those experienced by developed wind power countries. For example, according to

BNEF42

, the volume weighted average wind capacity factor was 21.2%, materially below the US at 32%, China at 23% and

Spain at 25%. Figure 86, below provides state by state insights in to the wind capacity factor. The data suggests that India

wind farms are not experiencing capacity factors comparable with the rest of the world.

Figure 86: Measured state wind capacity factors

State Average Wind

Capacity Factor

Karnataka 24.9%

Tamil Nadu 22.3%

Madhya Pradesh 19.0%

Gujarat 18.3%

Maharashtra 18.3%

Rajasthan 16.7%

Andhra Pradesh 15.9%


42

“India Wind Project Performance: Where, When Why?,” A. Sethia, Bloomberg New Energy Finance, 5 October 2011



PPA’s – What, Exactly, is Behind the Counterparty?

In the case of India, not much.

We noted above that the NVVN is the counterparty for all FiT-based PPA’s. It is nothing more than an administrative clearing

house matching DISCOMs demand for renewable power to the generators. It has few assets and no claim to electricity end-

market revenues. Thus, financial counterparties have expressed reluctance to loan against PPA’s where security and

proximity to revenue streams appear uncertain. In theory, a legal claim might flow down to the purchasing DISCOMs.

However they are almost all under extreme financial strain and the parent state governments in no better financial condition,

so assuaging lenders concerns on what might happen should a PPA not be honored remains a stumbling block. The national

government has attempted to address this problem with a modest surety fund, but we believe that it is no more than a stop-

gap measure as it does not scale effectively with an expanding industry.

RPO’s – The Mouse That Roared?

The RPO scheme intending to create end market demand for renewable power is admirable and can be quite effective so

long as the RPO requirements are enforced. Unfortunately in India, these “requirements” are not enforced. This creates

problems in several dimensions. First and foremost, a policy tool to clean up India’s power infrastructure through

development of wind power and solar power becomes meaningless without enforcement. Secondly, since the RPO scheme

gives rise to RECs, the lack of enforcement results in great uncertainty in the value of the RECs. For those developers (and

their investors and lenders) who have braved the early days of the market, and have elected to use a RECs-based structure,

the uncertainty created in the market due to non-enforcement of RPO requirements (that are serviced with RECs) can play

havoc with the financial success of a project. This uncertainty has also colored the lenders’ perspective and thus is another

point of discomfort of the developer community.

This is not to say that the Indian REC market is moribund. Based on data provided by BNEF, summarized below in Figure 87,

the market, starting in February 2011 had quickly to 95,504 RECs transacted per month in October 2011.

Figure 87: “Non Solar” REC transaction volume grows; unsold RECs grow too

February 2011

March 2011

April 2011

May 2011

June 2011

July 2011

August 2011

September 2011

October 2011

Traded Volume

0 424 260 18,502 16,385 18,658 25,096 46,362 95,504

Unsold RECs

0 0 4,351 1,963 8,129 26,208 32,956 39,226 43,121

Market Size (INR millions)

0 2,818 1,500 1,500 1,505 1,554 1,789 2,300 2,710


Although the market has grown in terms of both transacted volume and monetary value, so too has grown the number of

RECs left unsold each month. We wonder if this point underscores the broader RPO non-enforcement problem.

Financing Costs and Sources of Capital

India’s lending rates are several hundred basis points higher than foreign lending rates. Further, Indian lenders are not as

familiar with renewable energy project structures as more sophisticated foreign lenders. While hard to quantify the

consequences of this situation, we suspect both capital access and lending rates could serve as drags on the market. Some

believe foreign lenders may be able to profitably participate in Indian projects. Recognizing that a foreign lender or investor

may need to incur either foreign exchange risk or hedging costs, it is unclear how foreign participation can influence the

market. We believe that the most efficient way to address this problem would be for the Government of India and those of

renewables concentrated states to begin enforcing the various rules and requirements relating to RPO programs and to



address the accelerated depreciation/GBI issue in order to provide the transparency, longevity and certainty that will attract

investors’ and lenders’ capital. Until supply and demand side policy tools are effectively used and enforced, attempting to

implement policies helpful just to the capital providers is, we believe, akin to pushing on a rope.

Energy Efficiency – New Targets Announced

In April 2012 the Government of India issued energy efficiency targets for 2013 under the Perform Achieve Trade scheme of

the National Enhanced Energy Efficiency Plan. Originally, this plan was drafted to reduce energy intensity of industry by 4.2%

by 2013. However, when finally promulgated, the plan was watered down to only a 3% improvement by 2013, an amount

intended to reduce energy consumption by 6.7 million TOE and CO2 emissions by 29 million tons annually.

This plan targets 478 businesses in 8 industries and is summarized in Figure 88. The targeted industries are, typically,

energy intensive and parallel efforts being made in fellow BICs country China. In India, these business account for 33% of the

entire industrial sector’s 500 million TOE of energy use.

Figure 88: Energy intensity improvement targets by sector

Sector Targeted Annual

Energy Reduction (mTOE)

Percentage Reduction

# of Firms Effected

Thermal Power 3.2 2.1% 144

Iron & Steel 1.5 5.9% 67

Cement 0.8 4.8% 85

Fertilizer 0.5 5.9% 29

Aluminum 0.5 5.4% 10

Pulp & Paper 0.1 5.2% 31

Textiles 0.1 5.5% 90

Chlor-alkali 0.1 6.1% 22


The Government of India estimates the costs necessary to achieve the energy savings will approximate USD$1.97 billion (Rs

100 billion) – USD$2.4 billion (Rs 120 billion). No incentives or forms of governmental financial support were disclosed as

being offered.

The plan sets forth a “ESCerts” framework where energy efficiency credits can be earned and traded so long as benchmark

reductions are achieved. While certainly a well-intended effort, we are skeptical of the impact this plan will have. The reason

for our concern is two-fold and relates to enforcement. Business and political forces may seek to thwart enforcement on

argued economic or competitive bases. What we see as the weakest dimension of the plan is the financial penalty. For every

certificate shortfall (ie 1 ton oil equivalent), a penalty of USD$197 will be levied. Expressed in terms of oil, this is the

equivalent of buying oil at USD$26 per barrel and certainly does not seem to be a significant deterrent to non-compliance.

Manufacturing Resources and Policy Support

At the end of 2011, India had approximately 8 GW of wind turbine manufacturing capacities and approximately 1.6 GW of

solar module manufacturing. While not a firm government target, national aspirations are for 5 GW of wind power

manufacturing capacity and 4 GW - 5 GW of solar PV manufacturing capacity by 2022. This suggests development of India’s

renewable energy resources will be served by both local and foreign equipment suppliers as domestic manufacturing

expands. With current domestic demand for both wind and solar power less than domestic manufacturing capacity, we do not

forecast substantial manufacturing capacity expansion given the significant world-wide supply/demand imbalance described in



Figure 11 in the Executive Summary. If, however, India were to implement and effectively execute policies to accelerate solar

power development, we believe that could be a catalyst for modest domestic manufacturing expansion.

From 2007 through 2010, India offered to solar PV manufacturers a Special Incentives Package (SIP) to encourage the

development of indigenous manufacturing. The plan offered 20% - 25% subsidies to defray capital costs for manufacturing

facilities. Unfortunately, this program expired at the end of 2010. We have been unable to identify comparable programs in

the wind turbine sector.

We have been unable to identify clear incremental job creation estimates arising from India’s plans for renewables expansion.

In 2007 McKinsey and Company reviewed the country’s overall power needs (see Section 3.2 – Future Energy and Electricity

Requirements) and concluded that the government may be materially under-estimating the total amount of generation

capacity necessary to serve peak load in 2017. In this study, McKinsey estimates that in order to approximately triple

generation installed capacity, India would need to train and deploy 300,000 skilled and semiskilled workers. We believe

growth of the solar power and wind power OEM and operating industries would create additional jobs beyond the 300,000

estimated by McKinsey and Company. We are, however, unable to estimate the amount of job creation that could arise from

building a 74 GW renewables infrastructure by 2022.


From 2009-2020, demand for energy in India is forecast by the IEA to increase by 41%, growing at an annual compound rate

of 3.2%. This growth is driven by an economy forecast to grow at 7.7% per year through 2020, a population expanding at

1.3% and a trend toward a higher urbanization level of 36% compared to 30% in 2009. Through fiscal 2017, the Indian

government estimates that it will require USD$21 billion for grid-connected and off-grid renewables in addition to a further

USD$100 billion for general infrastructure viewed as necessary to successfully execute the government’s plans.`

India does not have an energy planning process as transparent as do Brazil or China. In the interests of comparability, we

have elected to use the IEA “New Policies” scenario forecast for India when government data is not available. While India is

planning on expanding the renewables base, aggregate growth in the country’s energy demand is overwhelming that positive

effort. Figure 89, below, shows that by 2020, renewables will account for only 22.3% of India’s energy needs.

Figure 89: India renewable share of energy supply forecast to decrease

Fuel 2009 2020e

Hydro 1.4% 1.9%

Biomass 24.7% 19.4%

Other renewable 0.3% 1.0%


Fossil Fuel 72.9% 75.9%

Nuclear 0.7% 1.8%

Total 100.0% 100.0% Source: IEA WEO 2011, DBCCA analysis 2012.

This compares unfavorably to the 2009 level of 26.4%. By our calculations, India would have to triple its investment through

2020 in renewables over and above the current forecast expansion by 62 GW to 118 GW (all renewables) from the 56 GW

level in 2010 in order for renewables to remain at a steady 26.4% of total primary energy supply share. Given the recent

negative decision to allow the accelerated depreciation benefits to expire and financing and basic infrastructure constraints, it

seems unlikely that India could ever achieve such acceleration.



Figure 90, below, illustrates the forecast composition of India’s electricity generation fleet. All major generation sources are

expected to expand. Low Carbon electricity generation (wind, solar and hyrdo power plus nuclear) are expected to represent

29% of the aggregate incremental capacity expansion through 2020.

Figure 90: India’s forecast electricity fleet, 2010-2020, by fuel

Source: IEA WEO 2011, DBCCA analysis 2012.

Although wind power and solar power are experiencing rapid growth off small initial bases, fossil-fueled generation is forecast

to grow a 9% annual compound rate. Figure 91 below, presents cumulative segmentation of expansion. Wind power

represents 22 GW or expansion and solar power 16 GW with biomass accounting for the residual balance.

Figure 91: Wind and solar growth forecast to exceed hydro

Source: IEA WEO 2011, DBCCA analysis 2012.

Figure 92 illustrates the differences between the IEA forecast and government-based forecasts we are able to deduce from

Government of India documents. In the case of Hydropower, the IEA forecast did not provide a clear and consistent

segmentation between large scale hydro power, which India reports as an explicit category, and small scale hydropower is

110

215 259 40

49

68 23

33

-

100

200

300

400

500

2010 2015 2020

GW

's o

f In

sta

lle

d C

ap

ac

ity

Fossil Fuels Hydro Nuclear Biomass Wind Solar

303 GW

171 GW

390 GW

149

16

46

5

-

50

100

150

200

250

India

Inc

rem

en

tal I

ns

talle

d C

ap

ac

ity, G

W




included with renewables. We have used the hydro power forecast prepared by CLSA as the most comparable proxy of third

party forecasts to what appears to be India’s long-term large scale hydropower ambitions.

Figure 92: Government more optimistic than IEA on wind and solar

Source: IEA WEO 2011, CLSA and DBCCA analysis 2012.

We view the more cautious wind and solar forecasts published by the IEA as reflective of many of the structural difficulties that

exist with building a renewables sector from scratch in India. Further, with the very recent expiration of key accelerated

depreciation benefits and continued political gridlock, we believe there is material risk that India’s actual development cou ld

fall short of the government’s published ambitions. Given the challenges facing India in terms of basic infrastructure,

rationalizing and streamlining the renewables policy structure, bureaucratic red tape, we are not at all surprised to see

aggregate effects of these risks manifesting as a discount to the government’s ambitions. While we would be pleased to see

India significantly exceed its goals, we are suspicious of that happening and see considerable risk in simply executing to their

current plan given financing and policy enforcement challenges.

India’s Electricity Outlook

Controversy exists with regard to India’s future electricity requirements. While India’s Central Electricity Authority estimates

the country will need peak load capacity 226 GW as estimated in the Integrated Energy Policy, McKinsey and Company

estimate that India’s peak load by 2017 could be as high as 315 GW – 335 GW. Such peak load capacity corresponds to 415

GW – 440 GW of total base load capacity once reliability and operational factors are accounted for. Obviously, these

amounts materially exceed the IEA forecasts just discussed. Figure 93 illustrates the divergence of views on India’s

estimated 2017 peak generation requirements.

-

10

20

30


Inc

rem

en

tal G

W's

20

10

to

20

20

IEA Forecast

Govt. Plan



Figure 93: 2017 Peak load surprises ahead?

Source: Government of India, McKinsey and Company, NREL and DBCCA analysis, 2012

Urbanization and improving incomes are both contributing to greater per capita electricity consumption. Such an increase

beyond the government’s own estimates by McKinsey would require the pace of additions to India’s electricity infrastructure

(generation and grid) to occur at a rate 5x the historical rate of construction. Achievement of such a pace would, we believe,

be contingent upon many things including suitable transportation, engineering and construction resources, in addition to

adequate port and logistics capacity to land material.

India’s Ministry of New and Renewable Energy estimates that between 2011 and 2017, an estimated cumulative investment of

USD $18 billion43

would be required to fund deployment of 29.6 GW of incremental grid-connected renewables capacity. Off-

grid renewables are estimated by the government to require an additional US$2.6 billion.

Renewables Segment Forecast FY2011-FY2017 – Take With a Grain of Salt

India formulates energy plans on a five year planning cycle. Much happens, however, in the annual budget cycle that can

lead to great uncertainty in achieving those forecasts. The recent expiration of the accelerated depreciation benefits for wind

power is an example of this.

The Government of India goals through 2020 were prepared when the accelerated depreciation benefits (accounting for 20%

of LCOE) were in place. Now that they are no longer available, we cannot estimate by how much the shortfall vs. goals might

be. It seems evident that if financing, infrastructure and bureaucracy challenges may have imperiled the goals, the cessation

of accelerated depreciation benefits will likely make it even harder to achieve those goals.

With these qualifications in mind, looking ahead, in Figure 94, wind and solar power were hoped to deliver 13% and 157%

average annual growth rates for the March 2011 – 2016/2017 period, respectively. The cessation of wind power accelerated

43 The Government of India estimated a 21.7 GW expansion would cost USD $13 billion. With announcements on 12 January 2012 that India was moving to target 29.6 GW

of renewables by 2017 versus the original 21.7 GW target, we have proportionally scaled up the estimated cost to USD $18 billion from USD $13 billion.



depreciation benefits hurts wind and does not (yet) have an effect on solar development as the sector has its own accelerated

depreciation scheme. Thus given the recent policy monkey wrench in wind power, solar power may be the area that receives

increased investor attention. It would seem logical that there may be a greater probability of achieving the solar power targets

compared to the wind power targets.

Figure 94: India’s estimated renewables expansion roadmap – 41 GW by 2017 and 74 GW by 2022

Fuel

Est. Installe

d Base, March 2011

2011/12 2012/13 2013/14 2014/15 2015/16 2016/17 Cumulative Additions

(1)

2017 Est.

Installed Base

2022 Policy Target

Biomass 1,025 100 80 80 80 80 80 500 1,525 Note 2

Biogas Cogen

1,616 250 300 300 300 250 250 1,650 3,216 Note 2

Waste Combustion

84 20 25 35 45 55 60 240 324 Note 2

Small Hydro

3,040 350 300 300 300 350 360 1,960 5,000 6,500

Wind (1) 13,900 2,400 2,520 2,520 2,520 2,520 2,520 15,000 28,900 40,000

Solar(1) 35 300 1,000 1,000 2,000 3,000 3,000 10,300 10,035 20,000

Total 19,700 3,420 4,225 4,235 5,245 6,255 6,270 29,650 41,400 74,000

Source: Ministry of New and Renewable Energy, Government of India and DBCCA analysis, 2012 Note 1: Updated to reflect announcements of 19 January noting plans by the Government of India to increase the incremental expansion of renewables by 2017 by 29.7 GW, up from the prior targeted 21.7 GW increase. The solar power target, increasing by 6 GW, accounted for the majority of the increase. Wind power target increased by 1. 6 GW to 15 GW. The 2017 targets reflect the new government targets; the annual incremental expansion amounts are DBCCA estimates. Note 2: Collective target of 7,500 MW by 2022 for these three biomass processes

While the above table notes a 2022 combined target of 74 GW of renewables (excluding large scale hydro), it is worth noting

that these targets were formulated by the government assuming what is “practicably achievable”. Such an expansion,

interesting, would require an average 4 GW per year of growth from 2017-2022.

If India is successful in clearing additional barriers relating to financing, infrastructure, administration and skills/expertise, the

Ministry of New and Renewable Energy estimates an “aspirational” renewable goal of 83 GW might be achieved. Further, on

19 January 2012, India revised targets for renewables by 2017 to a cumulative total for the five-year plan of 29.7 GW, up from

the previous 21.7 GW target (new targets reflected in the above table for 2017 with our estimates for the intervening annual

incremental expansion). This upward revision, however, has been made in the face of India having acknowledged missing

hydropower, transmission grid and thermal powerplant expansion in 2012 by 48%, 20% and 17%, respectively. While the

Government of India has not yet released a revised 2022 target, we expect that it is likely to be increased, though execution

inefficiencies, bureaucratic red tape and project development challenges may result in future shortfalls versus targets.

A potential incremental driver of growth may be required repowerings of telecommunications facilities. According to research

published by UBS(Sharma et al, “Can Money be Made From the Indian Sun,” 16 April 2012), this rule could create up to 7.6

GW of demand (of a potential total opportunity of 31 GW) by FY2022 for solar PV just from the telecom industry. There is

some uncertainty over the total scale of the renewables opportunity in India. For example, the Ministry of New and

Renewable Energy (MNRE) has accepted 49 GW as the practicable maximum wind power resource in the country. The

Indian Wind Power Manufacturers Association (IWPMA) suggests a maximum developable resource in the 65 GW – 70 GW

range. The Global Wind Energy Council (GWEC) is even more aggressive: while GWEC’s “Reference Case” for India is 27

GW by 2030, their “Moderate Case” and “Aggressive Case” suggest, respectively, 142 GW and 241 GW by 2030. Thus, with



a history of development falling short of goals and expectations, we believe it may take considerably longer than expected for

optimistic views on market size to be realized.

Growth at these rates will likely require both expanded domestic manufacturing capacity and greater imports, especially in the

near-term. In the 2009-2010 period, India had domestic manufacturing resources for 3 GW – 3.5 GW of wind turbines. While

not a firm government target, national aspirations for 5 GW of manufacturing capacity for wind turbines suggests development

of India’s resources will be served by both local and foreign equipment suppliers. Similarly, with 1 GW of solar module

making capacity and plans to expand to 4 GW – 5 GW by 2022, it seems likely that indigenous solar manufacturing capacity

will have to expand in concert with increasing imports.

Figure 95 lists the estimated potential for the major groups of bio-energy used for power generation. Unique to India is the use

of biogas for distributed home and farm use as either a cooking fuel or as a household/community electricity generation fuel.

Figure 95: India’s biomass generation estimated potential

Bio-energy Type Estimated Potential

Biomass-fired Power Generation (Agriculture residues and plantations)

16,881 MW

Biomass Power Cogeneration (Bagasse)

5,000 MW

Waste to Energy 2,700 MW

Family Type Biogas Plants 12 Million Units

Source: Government of India, USDA- Delhi and DBCCA analysis, 2012

There is no timetable set by the Government of India for development of these combustion biomass resources. The current

IEA forecasts suggest they might be fully exploited in the 2035-2040 period.

India’s motor vehicle fleet grows at 7%-8% annually. By 2015 the Government of India believes there may be 120 million

vehicles on the road. Thus with heavy import dependence on oil for vehicle fuel, it would seem that there is considerable

strategic impetus for India to implement an aggressive biofuels strategy. As an example, the IEA New Policies scenario for

2020 estimates that biofuels (ethanol and diesel) demands might approximate 3.8 billion liters, almost twice the USDA

forecast production capacity in 2012. As shown in Figure 96 approximately 300 million litres of bio-ethanol, or 14% of

2011/2012 production is forecast for use as transportation fuel.



Figure 96: India’s ethanol production summary statistics

(Million Litres) 2010a 2011e 2012e

Beginning Stock 1,283 1,085 1.049

Production 1,435 1,934 2,130

Imports 150 50 100

Total Supply 2,868 3,069 3,279

Exports 3 10 10

Consumption

Industrial Use 720 750 775

Portable Liquor 900 950 1,010

Blended petrol 50 250 300

Other Use 110 110 110

Ending Stock 1,085 999 1,024

Feedstock (1,000 mt) 5,981 8,060 8,875

Source: India Biofuels Annual 2011, USDA- Delhi and DBCCA analysis, 2012

Given the immaturity of the bio-diesel market in India, no reliable forecast is available. We do not foresee any circumstances

that would radically accelerate the indigenous biodiesel market given the multi-year maturation cycle for Jatropha plants.


India faces water stress challenges. As illustrated in Figure 10 in the Executive Summary, significant portions of the country

are measured by the UN as being “over exploited” or “heavily exploited” painting a picture of high water stress for one of the

world’s most populous and hungry countries. In addition to the challenges of building infrastructure and decarbonizing a coal-

based power sector, India must make due with minimal water resources.



Figure 97: Agriculture drives India’s water use

Source: IEA and DBCCA analysis, 2012

Water stress risks should not be underestimated as water is necessary for traditional fossil fuel electricity generation (for

cooling) and for the growing of food and first-generation biofuels feedstocks. Consequently, we believe as India’s economy

expands, the Government will have to develop policy frameworks to encourage more efficient use and re-use of water.

3.4 Challenges

India continues to experience serious and disruptive power shortages. Further, the government acknowledges many

uncompetitive circumstances within the economy. The Ministry of New and Renewable Energy cite shortages of skilled works

and note that the country’s technical education system is not well aligned with the need for skilled labor. Further,

manufacturing processes require upgrading to produce products with quality levels necessary for high-reliability applications

as well as for export markets. By India’s own admission, administrative and governmental processes are snarled in red tape,

the legal system can prove daunting in complexity and duration of process and general import/export infrastructure is

materially behind global standards for port and container handling. We believe India’s success in rapidly and effectively

decarbonizing the economy will be contingent upon simultaneously managing the execution of sizeable infrastructure upgrade

programs.

The Government of India estimates the costs of general infrastructure upgrade and expansion to approximate USD$100

billion of incremental investment. The Ministry of Commerce and Industry believes this amount of investment will be

necessary for port, logistics, highway and rail infrastructure expansion deemed necessary to support the 12th

and 13th Plan.

The estimated USD$100 billion is in addition to an estimate USD$21 billion for grid-connected and off-grid renewables by

2017. We note that India’s nominal GDP in 2011 was USD$1.8 trillion.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%


Disclaimer

92 Investing in Climate Change 2011

DB Climate Change Advisors is the brand name for the institutional climate change investment division of Deutsche Asset Management, the asset management arm of Deutsche Bank AG. In the US, Deutsche Asset Management relates to the asset management activities of Deutsche Bank Trust Company Americas, Deutsche Investment Management Americas Inc. and DWS Trust Company; in Canada, Deutsche Asset Management Canada Limited (Deutsche Asset Management Canada Limited is a wholly owned subsidiary of Deutsche Investment Management Americas Inc); in Germany and Luxembourg: DWS Investment GmbH, DWS Investment S.A., DWS Finanz-Service GmbH, Deutsche Asset Management Investmentgesellschaft mbH, and Deutsche Asset Management International GmbH; in Denmark, Finland, Iceland, Norway and Sweden, Deutsche Asset Management International GmbH ; in Australia, Deutsche Asset Management (Australia) Limited (ABN 63 116 232 154); in Hong Kong, Deutsche Asset Management (Hong Kong) Limited; in Japan, Deutsche Asset Management Limited (Japan); in Singapore, Deutsche Asset Management (Asia) Limited (Company Reg. No. 198701485N) and in the United Kingdom, Deutsche Alternative Asset Management (UK) Limited (formerly known as RREEF Limited), Deutsche Alternative Asset Management (Global) Limited (formerly known as RREEF Global Advisers Limited), and Deutsche Asset Management (UK) Limited; in addition to other regional entities in the Deutsche Bank Group. This material is intended for informational purposes only and it is not intended that it be relied on to make any investment decision. It does not constitute investment advice or a recommendation or an offer or solicitation and is not the basis for any contract to purchase or sell any security or other instrument, or for Deutsche Bank AG and its affiliates to enter into or arrange any type of transaction as a consequence of any information contained herein. Neither Deutsche Bank AG nor any of its affiliates, gives any warranty as to the accuracy, reliability or completeness of information which is contained in this document. Except insofar as liability under any statute cannot be excluded, no member of the Deutsche Bank Group, the Issuer or any officer, employee or associate of them accepts any liability (whether arising in contract, in tort or negligence or otherwise) for any error or omission in this document or for any resulting loss or damage whether direct, indirect, consequential or otherwise suffered by the recipient of this document or any other person. The views expressed in this document constitute Deutsche Bank AG or its affiliates’ judgment at the time of issue and are subject to change. This document is only for professional investors. This document was prepared without regard to the specific objectives, financial situation or needs of any particular person who may receive it. The value of shares/units and their derived income may fall as well as rise. Past performance or any prediction or forecast is not indicative of future results. No further distribution is allowed without prior written consent of the Issuer. The forecasts provided are based upon our opinion of the market as at this date and are subject to change, dependent on future changes in the market. Any prediction, projection or forecast on the economy, stock market, bond market or the economic trends of the markets is not necessarily indicative of the future or likely performance. For Investors in the United Kingdom Issued in the United Kingdom by Deutsche Asset Management (UK) Limited of One Appold Street, London, EC2A 2UU. Authorised and regulated by the Financial Services Authority. This document is a "non-retail communication" within the meaning of the FSA’s Rules and is directed only at persons satisfying the FSA’s client categorisation criteria for an eligible counterparty or a professional client. This document is not intended for and should not be relied upon by a retail client. When making an investment decision, potential investors should rely solely on the final documentation relating to the investment or service and not the information contained herein. The investments or services mentioned herein may not be appropriate for all investors and before entering into any transaction you should take steps to ensure that you fully understand the transaction and have made an independent assessment of the appropriateness of the transaction in the light of your own objectives and circumstances, including the possible risks and benefits of entering into such transaction. You should also consider seeking advice from your own advisers in making this assessment. If you decide to enter into a transaction with us you do so in reliance on your own judgment. For Investors in Australia In Australia, Issued by Deutsche Asset Management (Australia) Limited (ABN 63 116 232 154), holder of an Australian Financial Services License. This information is only available to persons who are professional, sophisticated, or wholesale investors under the Corporations Act. An investment with Deutsche Asset Management is not a deposit with or any other type of liability of Deutsche Bank AG ARBN 064 165 162, Deutsche Asset Management (Australia) Limited or any other member of the Deutsche Bank AG Group. The capital value of and performance of an investment with Deutsche Asset Management is not guaranteed by Deutsche Bank AG, Deutsche Asset Management (Australia) Limited or any other member of the Deutsche Bank Group. Deutsche Asset Management (Australia) Limited is not an Authorised Deposit taking institution under the Banking Act 1959 nor regulated by the Australian Prudential Authority. Investments are subject to investment risk, including possible delays in repayment and loss of income and principal invested. For Investors in Hong Kong Interests in the funds may not be offered or sold in Hong Kong or other jurisdictions, by means of an advertisement, invitation or any other document, other than to Professional Investors or in circumstances that do not constitute an offering to the public. This document is therefore for the use of Professional Investors only and as such, is not approved under the Securities and Futures Ordinance (SFO) or the Companies Ordinance and shall not be distributed to non-Professional Investors in Hong Kong or to anyone in any other jurisdiction in which such distribution is not authorised. For the purposes of this statement, a Professional investor is defined under the SFO. For Investors in MENA region This information has been provided to you by Deutsche Bank AG Dubai (DIFC) branch, an Authorised Firm regulated by the Dubai Financial Services Authority. It is solely directed at Market Counterparties or Professional Clients of Deutsche Bank AG Dubai (DIFC) branch, which meets the regulatory criteria as established by the Dubai Financial Services Authority and may not be delivered to or acted upon by any other person.

I-028211-2.0 Copyright © 2011 Deutsche Bank AG, Frankfurt am Main

Date post:	28-Feb-2022
Category:	Documents
Upload:	others
View:	3 times
Download:	0 times

Economic Stimulus: The Case for Clean Infrastructure, Energy

Documents