Branchenstudie
Sector
Study
WINDENERGIE
Wind
energy
September 2014
2014
Contents
Introduction
2
1
Development of wind energy
5
1.1
Current global situation
1.1.1 Global drivers
1.1.2 A brief presentation of growth markets outside Europe
5
5
7
1.2
Current developments in Europe – Reorganisation of the subsidy schemes
1.2.1 ”Green Certificates” as an alternative to feed-in tariffs
1.2.2 Power purchase agreements as an alternative to feed-in tariffs
1.2.3 Energy prices
8
8
9
10
2
Europe’s wind markets
15
2.1
Core markets under focus
2.1.1Germany
2.1.2France
2.1.3 Great Britain
2.1.4Ireland
2.1.5Finland
15
15
22
25
30
32
2.2
Further regions
2.2.1Benelux
2.2.2Scandinavia
2.2.3 Eastern and South-Eastern Europe
2.2.4 Southern and South-Western Europe
34
34
36
39
42
2.3
A summary of the government assistance schemes
44
3
Global forecast
45
List of abbreviations
47
HSH NORDBANK.Com
Sector Study WIND EnERGy
September 2014
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Sector Study WIND ENERGy
Analysis of prospective international markets
Introduction
Larger, higher, stronger, and cheaper? Or grown up? The use of wind energy is making progress in many respects. Across the globe, wind turbine generators (WTG) with a total rated capacity of about 35 GW were taken into operation last
year. Although the installed base had already grown notably, this represents a growth rate of as much as 12%. Throughout Europe, more than 10 GW of new capacity was installed in each of the past five years, with over 12 GW installed in
each of the past two years. Having gained in regional distribution and looking back on 30 years of use in the “old” wind
power markets, wind power has reached an impressive maturity level. In the recent past, offshore WTG played an increasingly important role; but also an ever more efficient exploitation of weaker wind conditions at inland sites also gives
proof of the ongoing innovation process.
In view of this trend, the Wind Energy Sector Study, two years after the publication of the previous edition, once again
takes a look at the latest developments in the wind energy market. As before, the study primarily addresses the prospects of important European markets. What are the political conditions? What has happened and will happen to the
instruments of government assistance? What are the expansion targets of the individual countries and what are the
framework conditions regarding use, availability and requirements? The study does not address individual manufacturers, nor can examine at all facets of the energy sector. Capacity markets, emission certificates and smart grids are not
analysed in detail; neither are electromobility and storage possibilities. Nevertheless, all these topics are relevant for the
future development. Costs are an issue of great relevance. When it comes to answering the question of what is the cost
of electricity from wind energy, there are many different approaches, each of which is justified and many of which are
driven by specific interests. This study is confined to an approach whose underlying principle is generally accepted, namely a calculation of the cost of electricity generation which takes into account the average cost of capital. This approach
acknowledges the relevance of the initial investment amounts and also benefits from our expertise in project finance.
Everything that has to do with the energy supply issue has a highly political dimension. Whether a greater focus is placed
on environmental or on economic aspects essentially depends on the latest news as well as on the individual situation
of countries, institutions and consumers. This allows researchers to select specific segments for analysis almost at will.
Society clearly supports the move towards green energy. Asides from environmental concerns, political crises in different regions of the world have also led to an increasing interest in becoming less dependent from imports of fossil fuels.
Primarily due to these environmental and economic objectives the reorganisation of energy supplies has been anchored in legal regulations at a national and at a European level. Where Europe is concerned, the creation of a barrierfree
domestic market also plays an important role. This is why the crossborder expansion of power grids should be seen
in the context of both growing technical requirements, which are mainly the result of a growing share of the generally
intermittent electricity generation from renewable energy, and a stronger integration of liberalised electricity markets.
While electricity from wind power is expected to become cheaper thanks to continuously decreasing investment costs
and increasingly efficient plant technology, electricity generation from fossil energy sources is likely to become more
expensive at least in the medium to long term. Under favourable conditions, onshore wind is competitive already today
by pushing down prices at the electricity exchange on windy days thanks to the “merit order effect”, which describes the
order in which the power stations are used depending on their costs. In the long term, wind power will make an important contribution to an affordable energy mix.
Nevertheless, costs are no doubt the most controversially discussed element of the move towards green energy. The
different cost structures of fossil power plants on the one hand and renewables such as wind power on the other hand
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are now in competition. Once taken into operation, the former must cover not only the investment costs but also the
fuel costs and the costs of carbon emission certificates. Wind turbine generators entail only relatively low maintenance
expenses as well as lease and management costs in addition to the investment costs. A fair cost assessment also covers
the environmental burden resulting from emissions, insurance costs or provisions for potential accidents as well as the
decommissioning of the plants. WTG also entail decommissioning expenses after they are taken out of operation, but
the real cost of fossil power plants are usually much higher due to the environmental damage they cause. This is even
more the case for nuclear power plants. Interestingly, this has been emphasised by the large utilities in Germany, which
proposed a publicly financed rehabilitation fund (“Altlastenfonds”) for nuclear power plants. While the unique risks of
this technology do not materialise very often, the catastrophes in Chernobyl and Fukushima have dramatically demonstrated their destructive potential for mankind and the environment. The sheer extent of the economic damage caused
makes it virtually impossible to be quantified in actuarial terms. Ultimately the costs of such catastrophes are borne by
society at large.
The call for an economic integration of wind energy and other renewable energy sources in the energy supply mix is justified, but the expansion of renewable energy must not jeopardise a secure energy supply. When choosing suitable sites,
not only the wind conditions – which are initially the most important aspect for efficiency reasons – but also grid and
consumption aspects should be considered, which ultimately support a certain degree of decentralisation. Accordingly,
statutory conditions and subsidy schemes are regularly adapted to reflect evolving requirements.
The German Renewable Energy Act (EEG) and its fixed feedin tariffs have been copied widely in a number of jurisdictions. Far more than 100 countries now have regulations governing the promotion of renewable energy. The undisputed advantage of fixed compensation is the high income security from an investor’s point of view, which has a positive
impact on the cost of capital. But any form of government assistance will ultimately lead to misallocations. The need to
reconcile the conflicting demands of further capacity expansion and of cost restrictions requires the subsidy schemes to
adjustment continuously.
Growing use is therefore made of direct marketing schemes and inverse auctions – often referred to as tenders. Under
direct marketing schemes, the generators themselves must take care of selling the electricity generated. This is often
done under long-term power purchase agreements (PPA). Tenders essentially also imply a PPA, but the price is determined in an auction, under which the project developer promising to realise a defined project at the lowest electricity price
is awarded the feed-in tariff.
To market electricity generated by wind power successfully, precise forecasts of the electricity production in the immediate future are of great value; all the more so as electricity prices in the spot market can be negative in times of oversupply. This represents a financial disadvantage for the seller. Accordingly, wind farms generating very constant yields are
more valuable. Against this background, turbine development plays an important role, as modern WTG can increasingly
achieve good and consistent utilisation levels also during times of low wind. On the other hand, the development of
offshore wind farms plays an important role in this context, too. These operate profitably in spite of significantly higher
costs thanks to a much higher electricity yield, while displaying a much more constant production profile.
The development of offshore sites and the growing use of lowwind sites are not the only drivers of global wind market
growth. While countries such as Germany and Denmark are increasingly replacing old, lowperformance WTG at attractive sites with larger and more modern turbines (so called “repowering”), more and more countries are discovering the
benefits of wind energy as a source for electricity generation. For many countries, wind power is the key to satisfying
their increasing appetite for energy, induced by their economic growth , in an environmentally compatible manner.
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Against this background, we are very optimistic that the global installed capacity will grow by an average of about 13%
p.a. by 2018 in spite of the already large existing base; we even consider in comparison to 2013 an almost threefold
increase in the installed capacity to be possible by 2023. In view of the relatively large base already installed, we expect
the installed capacity in Europe to increase by an average of “only” 10% p.a. by 2018 and assume that capacity will be
2.4 times higher by 2023.
This summarised outlook on the European wind market will be described in more detail on the following pages by looking at the wind markets in 17 European countries. The analysis focuses on the specific government assistance schemes
in each country.
One conclusion that can be drawn in advance is that the success story of wind power will definitely continue in the coming years.
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1 Development of wind energy
1.1 Current global situation
The wind energy success story continues. Critics could claim, however, that last year’s expansion was lower in comparison to the three years before with an average of over 20% per annum. According to the Global Wind Energy Council
(GWEC), wind turbine generators with a total capacity of 35.3 GW were installed worldwide in 2013, increasing the
installed base by 12.5% to 318.1 GW as of the end of the year. The general trend may still be called successful, however,
even though the growth momentum remained below the prior year levels, not only because of the base effect.
Last year’s decline in growth is mainly attributable to the slump in the US market, where only 1.1 GW of new capacity
was taken into operation, compared to 13.1 GW in 2012. Accordingly, the previous year’s No. 1 on the list of countries
with the highest capacity expansion only made 6th place this time. At 16.1 GW, China returned to the top of the list with
capacity additions accounting for 45.6% of the new capacity installed worldwide in 2013. At 3.2 GW, capacity additions
in the German wind market reached a new record in the same year, making Germany the world’s No. 2. Great Britain
(1.9 GW), India (1.7 GW) and Canada (1.6 GW) made third, fourth and fifth place, respectively.
The 2013 expansion figures do not entirely confirm the trend noted in our last Wind Energy Study, namely that the market is becoming more regionally diversified. However, the figures only show the capacity effectively connected to the grid
in 2013, ignoring projects under construction or initiated. Nevertheless, certain success stories are documented by the
available figures. According to the statistics of the Global Wind Energy Council (GWEC), Brazil and Poland, for instance,
more than doubled their total installed capacity over the past two years, while Pakistan increased its capacity from 6 to
106 MW during the same period. Ethiopia even accelerated its wind energy use from zero to 171 MW. The global trend
towards using renewable energy is again reflected in the latest Renewables 2014 Global Status Report published by the
REN21 Initiative. According to the report, at the beginning of 2014 144 countries (+26 vs. the beginning of 2012) have
set themselves energy policy targets, and 138 countries have launched subsidy schemes to promote renewable energy,
often in the form of feedin tariffs. More than two thirds of these countries are developing countries. The newly created
framework conditions are primarily visible in the construction of large wind farms. In countries such as South Africa
and Uruguay, which have so far played marginal roles in the analysis of worldwide capacities, several hundred MW are
under construction or at the development stage. In South Africa, more than 5 GW is expected on a 10-year horizon. The
same is true of several Asian countries. Moreover, capacity additions in Europe are increasingly taking place outside the
old core markets, e.g. in Poland, Sweden and Turkey.
There have also been some shifts in the established wind markets. While coastal sites used to be preferred for the installation of WTG due to the attractive wind conditions, more and more WTG are being erected at lowwind sites and
offshore. This trend is mainly attributable to the decreasing availability of affordable coastal onshore sites. A positive
aspect of offshore wind energy is the more constant electricity output. Advantages of lowwind sites include the proximity to the electricity consumers; moreover, higher hubs and turbines especially designed for lowwind areas also generate sufficient potential outputs. As a rule of thumb every additional metre of hub height increases the energy yield by
about 1%; however, the gain is somewhat lower at hub heights far above the 100 metre mark, which have become quite
common. Where the rotor diameter is concerned, the rule is that twice the diameter increases the yield about fourfold.
Larger, more modern turbines increasingly replace older, less performant plants at coastal sites in the context of repowering programmes. Against this background, major capacity additions will continue even in established markets such
as Germany.
1.1.1 Global drivers
Wind energy is becoming increasingly important for the generation of electricity around the globe. This is attributable
to several factors, whose relative importance differs from region to region. Asides from growing or changing energy
requirements, these are mostly environmental objectives, although economic and political aspects support investments
in wind energy as well.
Growing energy requirements resulting from global population growth remain an important global aspect. In many
emerging countries this is intensified by a growing prosperity. Annual percapita electricity consumption in the USA
(over 13 MWh), in Germany and France (around 7 MWh in both countries) is still much higher than in China (3 MWh)
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or India (1 MWh). Since 1965, global demand for energy (measured in oil equivalents) has increased by an average 2.6%
p.a., while the global population has grown by an average 1.6%.
Global Energy Consumption in Oil Equivalents
2011
bn people
2013
2007
2009
2005
2003
1999
2001
1997
1995
1991
2
1993
2
1987
4
1989
4
1985
6
1983
6
1981
8
1977
8
1979
10
1975
10
1971
12
1973
12
1969
14
1967
14
1965
bn t
Global energy consumption and population growth
Global Population
Sources: BP Statistical Review, US Census Bureau, 2014
Accordingly, the long-term upward trend in energy consumption is very likely to remain intact in the coming years.
Energy efficiency measures, which have gained importance over the past years, will merely mitigate this trend but certainly not halt it. Temporary fluctuations depending on the global economic situation will continue to occur in future,
but investment decisions in the energy supply sector will have a much longer lasting effect than these relatively shortlived dampers.
A shift in the relative shares of the different sources of energy, e.g. through the partial substitution of electrical energy for
oil products in the transport sector may well be possible. At the same time, there have been some promising attempts to
store excess electricity from renewable energy sources in the form of synthetically produced gas or hydrogen, i.e. as fuels.
Progress has doubtless also been made in storing electricity in batteries (or, technically more precise, accumulators) at
low loss. While these aspects may deserve to be addressed in a separate study, they do not turn around the trend towards
growing energy demand but open up additional scope for using electricity generated from renewable sources.
The fossil energy sources used in the past to cover much of the demand for energy have a significant adverse environmental impact and entail considerable risks regarding both production and consumption. Extreme weather occurrences
are being linked to exhaust emissions in the industrialised world contributing to global warming. The 2010 oil catastrophe in the Gulf of Mexico and the 2011 nuclear catastrophe in Japan demonstrate the risks, which are difficult to
quantify in actuarial terms. As the plans for phasing out nuclear reactors are becoming more concrete, awareness of the
enormous costs entailed by such a shutdown is growing as well. These events have increased the pressure on political
decision-makers. The German term “Energiewende” (move towards green energy) is meanwhile being used also in Anglo-Saxon countries. Many countries have decided to phase out nuclear energy and others have at least put plans for new
nuclear power plants on hold. While 16 new reactors have been taken into operation globally since early 2011, 22 have
been switched off. It is true that these figures may, at first sight, do not underline the global exit from nuclear energy; it
should be noted, however, that the construction of a nuclear power plant takes many years and that horrendous amounts
are invested already at a very early stage. This and the fast growing energy demand in many countries mean that it is not
a realistic option to abandon nuclear power plant projects which have already been launched.
Although the leading industrialised nations and many emerging countries have committed themselves to a more environmentally compatible and sustainable energy supply, the international resolutions actually adopted in this respect are
disappointing. The Kyoto Protocol, the only set of binding climate protection targets, would officially have expired at the
end of 2012. Anyway, the Kyoto Protocol covered only about 15% of global greenhouse gas emissions. The Protocol is
to remain in place provisionally until a new global climate agreement is reached by the United Nations – no later than
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2020. Controversial aspects of the new agreement under discussion primarily include the extent and the distribution
of the future greenhouse gas reductions, the inclusion of emerging and developing countries into binding agreements
regarding the reduction of their emissions and the amount of financial transfers.
In its communication on the “policy framework for climate and energy in the period from 2020 to 2030”, the European
Commission (in short: EU Commission) proposes not only an internal 2030 greenhouse gas reduction target of 40%
compared to 1990 for the EU but also a headline target at European level for renewable energy of at least 27% to be
achieved by 2030.
But climate protection targets are not the only argument in favour of renewable energy. Regardless of the above-mentioned adverse environmental impacts and risks arising from their exploration and use, natural resources will not be
available for conventional energy generation forever as their sources continue to be depleted. Even if oil is available for
many decades (coal, gas and uranium are currently projected to be available for far more than 100 years in some cases),
it is already clear today that the financial and technical resources required to tap such sources are growing significantly;
offshore drillings at extreme water depths, oil and gas exploration from slate or oil sands require the use of increasingly
sophisticated exploration techniques and lead to rising costs and growing exploration risks.
In this context, renewable energy in general and wind power, in particular, are gaining importance from an economic
point of view, as a downward trend in generation costs for renewable electricity contrasts with rising prices of fossil
energy resources (see chapter 1.2.3 Energy prices).
Supply security is another important aspect when it comes to satisfying the demand for energy. The intermittent availability of wind and sunshine is often regarded as a weak point of the energy supply from renewable sources. Where
conventional energy generation is concerned, such a weak point is the dependence on resources from countries or regions which often present a high political risk. This issue has been with us for many years, even if the respective hotspots
continue to shift. While two years ago the main focus was on Iran, the latest developments in Iraq are now giving cause
for concern. But there are political crises which are of great relevance for the energy supply even right on our doorstep
so to speak. The crisis between Ukraine and Russia, which has escalated increasingly since the beginning of the year, is
a threat to Western Europe’s gas supply from Russia. The growing use of wind energy reduces the dependence on imported energy resources; naturally, the same applies to solar energy and other renewable resources. This has an impact
on the respective countries’ balances of trade. The local value creation resulting from the expansion of wind energy and
other renewable energies on the one hand and the savings resulting from less imports of conventional energy feedstock
on the other hand are two of the reasons why governments have refrained from slashing wind subsidies altogether.
1.1.2 A brief presentation of growth markets outside Europe
Reducing the dependence on imported energy resources plays an important role also in many countries outside Europe
which are investing in the expansion of renewable energy. This applies especially to China, the world’s number one wind
market. As outlined above, the Middle Kingdom accounted for over 45% of global capacity additions in 2013. At 16 GW,
capacity additions in 2013 clearly exceeded the prior year level of 13 GW but remained below the 2010 and 2011 record
levels of 19 GW and 18 GW, respectively. It is positive to see, however, that the trend is stabilising at a high level. In
2013, China generated 134.9 billion kWh of electricity from wind power, which is 34% more than in the previous year but
equivalent to only 2.6% of the country’s total output. This was made possible not only by the expansion of the generation
capacity but also by improvements in the power grids, which are still considered a bottleneck factor, however.
Due to the still very dynamic economic growth of the world’s most heavily populated country, China’s demand for energy
is growing strongly. To satisfy this demand, the central government relies on an energy generation mix comprising both
conventional and renewable sources. In addition to promoting the supply of energy, the country also attaches importance to building up a dedicated domestic industry. As a result, three of the largest WTG manufacturers – Goldwind,
United Power and Mingyang – are Chinese companies. At 91.4 GW, total capacity reached the 2015 target of 90 GW
already at the turn of the year. Against this background, new targets of 150 GW and 200 GW have meanwhile been set for
2017 and 2020, respectively, which do not seem overly ambitious. Since 2009, wind power has been subsidised under a
feed-in tariff scheme, whose costs are passed on to electricity consumers, similar to the German system. Two years ago,
the settlement conditions were changed from annual to quarterly payments. The amount of the subsidies depends on the
quality of the site and the province.
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Capacity additions in the USA, which is the world’s second largest wind market, in terms of installed capacity, were very
moderate in 2013. The installation of 1.1 GW of new capacity in 2013 and of 13.1 GW in the previous year very clearly
reflects the boom-and-bust cycle created by the unsteady subsidy mechanism in the form of the Production Tax Credit
(PTC). In the past, the PTC has repeatedly been renewed for only a few years, which temporarily led to considerable
slumps. The slump in 2013 had therefore been expected (see 2012 Wind Energy Sector Study of HSH Nordbank). As this
promotion instrument is relaunched, we expect to see a return to the kind of growth figures which have given the USA a
leading international position. According to the American Wind Energy Association (AWEA), WTG with a total capacity
of over 14.6 GW were under construction at the end of June 2014. Unfortunately, no extension or relaunch of the PTC or
an alternative subsidy scheme had been decided at the time of going to press. However, some states have launched their
own incentive schemes. At the federal level, President Obama, on the basis of an old law, ordered that carbon emissions
shall be reduced by one third within 15 years, which provides at least some kind of direction.
Even though this is – as outlined above – not reflected in the 2013 expansion figures, there is a promising trend towards
increased use of wind energy in many developing and emerging countries. In the coming years this will be seen in Brazil,
where about 4 GW will be installed according to the GWEC, and in South Africa, where almost 2 GW were in the project
pipeline at the end of 2013.
1.2 Current developments in Europe – reorganisation of the subsidy schemes
Although it differs to a certain degree from country to country, there is a Europe-wide commitment to a shift towards
green energy (i.e. an “Energiewende”). Nontheless opinions about and ways towards reasonable promotion schemes for
renewable energy differ considerably. At the same time, conformity with EU legislation needs to be ensured at all times.
The EU Commission tends to take a sceptical view of national “solo efforts”. This is why the German Renewable Energy
Act (EEG) is also viewed critically by the Commission. On the one hand, the criticism is targeted at the apportionment
system and, above all, at existing exceptions; on the other hand, the question recently emerged whether the fact that
subsidies are confined to national electricity generation constitutes an impermissible restriction of the free movement
of goods. The European Court of Justice (ECJ) ruled1, in early July 2014, that the member states of the European Union
are not obliged to financially subsidise renewable energy generated in other EU countries. While the ECJ admits that
this may hinder “imports of electricity from other Member States,” it also notes that “this restriction is justified by the
public interest objective of promoting the use of renewable energy sources in order to protect the environment and
combat climate change.”
While this decision provides at least legal certainty, economic issues remain a critical factor in the further development
of national promotion schemes. Many countries remain in economic crisis mode. And even the economically stronger
European countries are viewing the costs of “green” electricity critically – and often fail to take a fair look at the cost of
conventional electricity generation. During the 2013 federal election campaign in Germany, the increase in consumer
electricity prices was debated in a very biased manner. In many countries, the prospect of a potential further increase
in electricity prices has prompted calls for policy-makers to halt this trend. The critics’ core message is that renewable
energy would make electricity more expensive for private and commercial consumers. This, they claim, would lead to
a competitive disadvantage especially for energy-intensive sectors. The default response from many politicians is that
renewable energy should “grow up” and face competition. The major challenges in this context are the highly different
framework conditions of fossil and renewable electricity generation capacities. The main variants and aspects are therefore described in the following chapters.
1.2.1 ”Green Certificates” as an alternative to feed-in tariffs
The subsidisation via “green certificates” is an established alternative to generally rigid feed-in tariffs. Many countries
such as Great Britain and Sweden (see description of countries) have practised this kind of subsidisation for many years.
Under these schemes, the renewable electricity is marketed directly, which means that it is exposed to supply and demand fluctuation. Depending on the country and the technology, there are additionally a certain number of certificates.
Energy providers must absorb a certain quota of renewable electricity, which usually increases from year to year, by
means of these certificates. Depending on the actual energy generation mix and the electricity demand, the prices of the
certificates are sometimes exposed to considerable fluctuations.
Case: C-573/12
1
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Given that the fluctuations in the certificate prices and, depending on the type of distribution, in the electricity prices represent a risk from an investor’s point of view, higher returns are expected in these markets. At the bottom line, the sum
total of electricity price and certificate price would have to be higher than fixed feed-in tariffs. In some countries such as
Sweden, certificate prices have come under such pressure lately that the revenues were lower than those in comparable
countries with fixed feed-in tariffs.
Marketing the renewable electricity remains a critical element. Marketing in the spot markets (see chapter 1.2.3 Energy
prices) is generally quite challenging, as electricity prices in these markets will usually come under particular pressure
when supply is increased by a particularly large amount of renewable energy. The “merit order effect” describes the economically logical effect that inexpensive electricity replaces more expensive electricity in the market whenever there is
excess supply. However, as it is the variable costs and not the investment costs which are relevant for short-term pricing,
electricity generated by WTG is, in any case, superior to electricity generated by a fossil power plant, which incurs fuel
costs as well as the cost of carbon emission certificates. Renewables thus become the victims of their own success, so to
speak, as they cause prices to decline as the electricity supply grows.
Another critical question of long-term power purchase agreements is how to manage incongruent phases of peak supply and peak demand. As it is extremely difficult to store electricity both technically and economically, forecasts of the
expected electricity yield (in the next hours and days) must be as precise as possible. Given that nuclear and coal power
plants, in particular, require a considerable response time when being started up or shut down, it is impossible for these
plant types to immediately react to supply bottlenecks or excess supply for technical reasons. This technically induced
limited responsiveness is one of the reasons why electricity price fluctuations have amplified. As a consequence of this
technical/economic constellation, electricity is temporarily sold abroad at negative prices. It is plain to see that it makes
economic sense to avoid such market imbalances with the help of precise forecasts.
When it comes to making subsidy schemes with fixed feed-in tariffs suitable for a market economy, certificate systems
are no viable alternative from today’s point of view as they entail the disadvantage of higher yield expectations, which
lead to rising costs. Schemes under which the generators must market the electricity they produce directly are a possible
solution. To mitigate the resulting income risk, compensation is paid for the difference between the market price and
the tariff. The incentive for efficient marketing based on yield forecasts which are as precise as possible lies in the opportunity to achieve a higher price than the mean market price, which forms the basis on which the compensation for the
difference is calculated. This movement away from fixed feed-in tariffs towards a difference-based compensation is also
implemented under the latest amendment of the German EEG.
1.2.2 Power purchase agreements as an alternative to feed-in tariffs
Regardless of legal or contractual conditions, electricity generation from wind power is – save for some minor interventions to ensure grid stability – primarily determined by the amount of available wind resource. While there are values
based on long-term experience and short-term forecasts, the time and the amount of electricity generation cannot be
planned exactly. Where no fixed feed-in tariffs are provided for, long-term power purchase agreements (PPAs) are a
sensible basis for the cost-efficient operation of WTG.
Under these agreements, the risk of fluctuating electricity prices passes from the generator to the purchaser. To compensate for this risk, the purchaser pays a lower price than the expected average electricity price. Moreover, the purchaser
aims to balance the supply of electricity with the demand for electricity by combining electricity generation capacities
from different technologies or regions. In this context, it makes sense to integrate large consumers, who can control the
electricity consumption, e.g. of large cool storage facilities, to a certain extent.
PPAs are quite commonly used in the USA, where the Production Tax Credit (PTC) incentivises the installation of WTG.
The agreed long-term offtake prices are subject to substantial regional differences and vary considerably depending on
the market conditions prevailing at the time the agreements are signed. Rates of between 4.0 and 6.4 US cent per kWh
are quoted as an example by the US Wind Industry Association for the state of Minnesota. While these amounts are far
lower than the compensation granted under Germany’s EEG, they are possible only because of additional government
assistance in the form of the PTC.
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The PPAs usually have a term of 15 to 25 years, however, shorter terms also exist especially in Europe. Renewal options
are a common feature, as are various clauses allowing the agreements to be terminated if certain conditions are not met,
e.g. technical preconditions or complementary grants. The agreements also must specify what happens in case of gridrelated shutdowns and how to cope with transmission costs.
In many cases, PPAs are the consequence of tenders in which potential operators quote, during an inverse auction,
prices at which they can supply electricity from a yet-to-be-developed wind farm over a period of usually 20 years. The
usual rates differ considerably depending on regional conditions. An important aspect is the question whether another
element of assistance exists. To participate in these auctions, operators must meet certain requirements, e.g. proof of financing, guarantees, wind yield estimates etc. The contract is then awarded to the operator quoting the lowest electricity
price, who must then usually submit the relevant installation and financing contracts within a relatively short period of
time. Actual installation must then also take place within a given period, usually 18 months. If this is delayed, a financial
disadvantage arises for the generator at least insofar as the total period during which they receive the agreed price for
the electricity produced is reduced.
Supporters of an electricity market made up of inverse auctions and long-term power purchase agreements primarily
appreciate the fact that the price is the result of supply and demand. Disadvantages include the administrative effort,
which is a cost factor which limits the supply and is therefore likely to lead to higher prices. This is especially the case in
markets where small(er) projects are common, such as Germany At the same time, it is safe to assume that smaller developers with less capital will be at a disadvantage in the auctions compared to larger developers with more capital. The
reasons for this include the fact that it is more difficult for them to provide the guarantees required for the projects and
that they will find it harder to finance the personnel required for the auctions. In the past, there were quite often cases in
some markets where the developer who won the contract in an auction failed to realise the project.
1.2.3 Energy prices
Energy prices in general and electricity prices in particular are influenced by many different factors. The prices of energy
resources such as oil, gas or coal are relatively tangible, although they are subject to strong temporary fluctuations, not
least due to speculation-. The first major way that resources differ from electricity prices is easy storage. When electricity
is stored, storage still entails significant losses. This is why not only spot prices are quoted on the electricity exchange but
also a large number of forward prices for different hours and days in the future. In the past, the situation was as follows:
electricity was cheap at night and expensive at midday. This situation has changed insofar as an especially large amount
of solar electricity is available at midday, which means that the increased electricity supply puts a damper on the rise in
prices during the day.
There are many different ways to match demand and supply. First of all this requires smart grids. There are different
views on the potential volume of electricity which actually could be time-shifted but the growing share of electricity consumed by electromobility applications will certainly help to balance supply and demand during phases of excess supply.
Generally, assessing the competitiveness of alternative electricity generation has two sides: 1. At what cost (and when) is
electricity generated? 2. At what price (and when) is electricity from other sources available?
It is correct that renewable electricity is more expensive than electricity generated in conventional power plants most
of which have already been written off. Moreover, renewable electricity from wind or solar power as such cannot meet
baseload requirements. When building new conventional power plants, the costs are higher, which means that at least
onshore wind is cheaper under favourable conditions. The competitiveness of nuclear power plants cannot be estimated
correctly as the risks are uninsurable and realistic data regarding the cost of the final storage of nuclear waste is not
available. Reports of runaway capital requirements of the few nuclear power plants that are being built worldwide suggest that these are unlikely to produce electricity at lower costs.
The cost of electricity from renewable energy depends primarily on the amount of the investment (plant prices and
installation costs) and, accordingly, on the cost of capital. Fuel costs are negligible, and only moderate maintenance
expenses (this factor is most important for offshore wind power) as well as land lease and administration expenses must
be taken into account These costs are compared with the present value of the electricity yield.
Page 10
Depending on the investment expense, the annual electricity yield and the cost of capital, the following cost of electricity
(in EUR Cent per kWh) arises for onshore WTG:
ct / kWh
Cost of electricity of onshore WTG in relation to the cost of capital in %
16
14
12
10
8
6
4
2
0
3.5%
4.5%
5.5%
6.5%
1.0 mio EUR per MW / 3,000 MWh
7.5%
8.5%
1.3 mio EUR per MW / 2,000 MWh
1.6 mio EUR per MW / 1,500 MWh
Source: Fraunhofer ISE premises, assumptions and computations by Krakau-Research
The general picture is similar for offshore WTG, whose cost of electricity is still significantly higher than that of onshore
plants:
ct / kWh
Cost of electricity of offshore WTG in relation to the cost of capital in %
25
20
15
10
5
0
5.0%
6.0%
7.0%
8.0%
9.0%
10.0%
11.0%
2.7 mio EUR per MW / 4,000 MWh
3.2 mio EUR per MW / 3,200 MWh
4.0 mio EUR per MW / 2,800 MWh
4.2 mio EUR per MW / 4,450 MWh (AV)
Source: Fraunhofer ISE premises, assumptions and computations by Krakau-Research
The relation between investment costs and electricity yield should continue to improve as a result of technological progress and economies of scale. Each of the two charts above shows extreme constellations of high investment costs and
low electricity yields as well as low investment costs and high electricity yields as well as a more average scenario. The
offshore WTG chart additionally shows the investment costs and the 2012 electricity yield of the Alpha Ventus trial field
(grey line).
The cost of capital depends on the financing structure as well as the interest rates on the debt capital and return on equity. Without going into the details of the respective theories, it is safe to assume that, all things being equal, the interest
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rate for a higher risk is higher than the interest rate for a lower risk. This means that the costs of offshore WTG will decline automatically as more experience is gained and costs and yields can be estimated more precisely. The cost of capital
also reflects the legal stability of a country.
In its November 2013 study entitled “Levelized Cost of Electricity Renewable Energy Technologies” (“Stromgestehungskosten Erneuerbare Energien”), the Fraunhofer-Institut für Solare Energiesysteme ISE assumes capital costs of 5.85%
for onshore wind and 9.8% 2 for offshore wind in Germany. In view of the continued low interest rates, these capital costs
can be described as very high. The charts above show that the lower the capital costs, the lower the cost of electricity. We
have nevertheless taken the above cost of capital as well as a learning curve model as a basis to calculate the following
forecast of the cost of electricity (assuming investment costs of EUR 1.3 million per MW (onshore) and EUR 3.2 million
per MW (offshore) and an electrical output per MW of 2 GWh and 4 GWh, respectively).
ct / kWh
Forecast of the cost of electricity of WTG compared to fossil fuels
14
13
12
11
10
9
8
7
6
5
4
2014
2019
Onshore
Offshore
2024
Natural Gas
Lignite
2029
Hard Coal
Source: Fraunhofer ISE premises, assumptions and computations by Krakau-Research
This shows that electricity from onshore WTG is almost competitive already today. In particular, the cost of production
of electricity generated from natural gas is, in some cases, already higher. In the long term electricity generated by offshore WTG will also approach a competitive level. The trend shown above assumes no change in the cost of capital. As
outlined above, however, the cost of capital could lead to a significant reduction in the cost of electricity. The actual cost
trend for fossil energy sources primarily depends on the trend in commodity prices, of course.
Besides the cost of electricity of conventional power plants, market prices may also be analysed as opportunity costs. Basically, a distinction must be made between two prices: prices at the electricity exchange and consumer prices. The latter
are relevant only for consumers who install solar collectors on their roof to reduce their consumption of grid electricity.
In regions were where no power grid exists, a comparison with the diesel-powered generator is also possible.
The analysis of electricity exchange prices is complex. On the one hand, this is due to the fact that a distinction must be
made between spot prices and forward prices, which means that supply security also plays a role. On the other hand,
this is due to the fact that renewable energy reduces the electricity price at the electricity exchange because of the “merit
order effect” described in chapter 1.2.1.
When it comes to assessing the costs and benefits of renewable energy, further aspects must be taken into account from
an economic point of view. In addition to the issue of supply security, the prices of imported energy are a considerable
burden for many countries. Save for a few exceptions such as Norway, the European countries are net energy importers.
Especially in the financially ailing South European countries, the cause and the potential solution are close. The use of
attractive wind conditions to produce energy may reduce the demand for imported energy. To better take the respective
The ISE assumes the following values: onshore wind: 30% equity, return 9.0%, interest rate on debt capital 4.5% / offshore wind: 40% equity, return 14.0%,
interest rate on debt capital 7.0% / useful life: WTG 20 years; conventional power plants 25 years
2
Page 12
macroeconomic influences into account, today’s cost comparisons usually no longer look at the Levelized Cost of Energy (LCoE), on which the above calculations are based, but at the Social Cost of Energy (SCoE). Based on the LCoE, the
SCoE additionally takes environmental pollution as well as geopolitical aspects into account. On this basis, wind energy
is already more than competitive compared to conventional electricity generation. The GWEC’s Global Wind Report, for
instance, quotes SCoE of 5.9 and 6.0 ct per kWh, respectively, for onshore and offshore wind (taking British installations
as an example) as well as LCoE of 10.0, 10.6 and 9.5 ct per kWh, respectively, for nuclear power, coal and gas. While this
assessment is in its tendency certainly correct and reasonable, the underlying assumptions for the social factors may be
disputed, which is why we have not taken the SCoE as the basis for our own computations.
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Page 14
2 Europe’s wind markets
2.1 Core markets under focus
2.1.1 Germany
2012 renewables mix
25%
38%
17%
20%
Wind
Solar
Waste
Other RE
Source: EUROSTAT 3 / Bloomberg
GWh
Coal
Nuclear
Naturalgas
Hydro
Oil
Renewableenergy
Others
Total
GWh
Wind
Solar
Geothermal
Waste
OtherRE
2007
295,180
140,534
79,593
20,530
10,007
79,231
15,498
640,573
2012
275,388
99,460
77,602
21,195
7,627
134,912
13,629
629,813
Change
-6.7%
-29.2%
-2.5%
3.2%
-23.8%
70.3%
-12.1%
-1.7%
Portion2012
43.7%
15.8%
12.3%
3.4%
1.2%
21.4%
2.2%
100.0%
2007
39,713
3,075
0
17,498
18,950
2012
50,670
26,380
25
23,595
34,242
Change
27.6%
757.9%
n.m.
34.8%
80.7%
PortionRE
37.6%
19.6%
0.0%
17.5%
25.4%
Source: EUROSTAT / Bloomberg
2013 was a strong year for the German wind market, which is one of the oldest and largest in Europe. A capacity of 3.0
GW was installed on shore, plus 240 MW of offshore capacity 4. Taking decommissioned WTG into account, the installed
base comprised 23,645 onshore WTG with a total capacity of 33,730 MW and 116 offshore WTG with a total capacity of
520 MW as of the end of the year.
Despite many prophecies of doom, the EEG has been a success story for more than fourteen years. The combination
of fixed tariffs for renewable energy, which, additionally, have to be given precedence over conventional energy when
feeding into the grid, a stable legal framework and a comparatively good infrastructure has led to noticeable shifts in the
energy generation mix since the introduction of the EEG. This trend continued in recent years: in 2007, coal and nuclear energy still accounted for close to 46.1% and 21.9%%, respectively, of the total 640.6 TWh of electricity produced,
compared to 43.7% and 15.8%, respectively, in 2012. The percentage of renewable energy almost doubled from 12.4% to
21.4% during the same period.
Germany’s energy policy, just like the policies of other countries, is challenged to reconcile the conflicting demands of
economy and ecology. The nuclear catastrophe in Fukushima prompted policy-makers to rethink their energy policy.
The then German government had originally planned to phase out nuclear energy over a longer period of time, but these
phase-out plans were accelerated after the catastrophe. Eight nuclear power plants have already been shut down, with
the remaining nine to be switched off until 2022. The capacity gap is to be closed primarily by renewable energy. Along
with solar energy, wind power is a key element in the move towards green energy. Electricity from biomass, biogas,
etc. (included in “Other RE” in the above chart), whose relative share has also increased sharply over the past years, is
increasingly being viewed critically as it leads to monocultures in the agricultural sector. At the same time, efficiency
measures have been initiated to reduce demand for electricity. In the past two years, demand for electricity was stable,
with only minor fluctuations.
As part of the latest EEG amendment, the capacity expansion targets have also been adjusted. The somewhat too ambitious offshore target of 10 GW in 2020 has been lowered to 6.5 GW. A target of 15 GW of offshore capacity has been set
for 2030. The latest adjustment of the targets (a target of 13 GW of capacity to be installed in the North Sea and the Baltic
Sea by 2020 had temporarily been set) should now outline a realistic path.
Percentage of renewable energy without hydropower in accordance with Eurostat. Other RE include (where available) biomass, biogas, landfill and sewage
sludge gases as well as electricity from wave or tidal power plants
4
Figures based on EWEA statistics; DEWI figures differ slightly.
3
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A target range of 2.4 to 2.6 GW p.a. has been defined for onshore capacity additions, which even exceeds the previous
targets. These figures relate to net capacity additions, i.e. net of decommissioned WTG. This pace of expansion will be
exceeded by far at least this year. The medium to long-term development will depend on the availability of suitable sites.
While fewer and fewer attractive coastal sites are available – which is why repowering is gaining importance in northern
Germany – growing use is being made of inland locations. Many inland federal states have meanwhile defined targets for
the expansion of wind energy. Baden Württemberg, for instance, wants to cover 10% of its electricity consumption with
wind energy by 2020, while North Rhine-Westphalia has even set a target of 15%. Of the 1.7 GW installed in the first half
of the year, more than 50% was installed outside the coastal federal states. It should be noted that the southern regions
of Lower Saxony or Mecklenburg-Western Pomerania should also be classified as inland sites.
In the 2013 ranking of federal states, Rhineland-Palatinate deserves special mention as it increased its capacity by an impressive 413.4 MW, making it the No. 2 just behind Schleswig-Holstein and ahead of Mecklenburg-Western Pomerania.
At 251.6 MW, Bavaria ranked sixth just behind Brandenburg. Against this background, the announcement of the State of
Bavaria is all the more alarming that a greater minimum distance between WTG and residential areas will be required in
future. According to what is referred to as the “10-H Rule”, the minimum distance should be at least 10 times the WTG
height up to and including the tip of the rotor blade. In the case of modern, low-wind generators with a total height of
roughly 200 metres, this is equivalent to a distance of two kilometres. A study by the Federal Institute for Research on
Building, Urban Affairs and Spatial Development shows that, under the new rule, WTG could be installed on only 1.7%
of the territory of Bavaria – compared to a potential area of 19% under current conditions. One can only speculate about
the political motives behind this proposal – whether it is residents’ concerns about shadows cast by the WTG or about
noise emissions or a preference for biomass or solar energy. What is for sure, however, is that Bavaria’s industrial sector,
too, relies on a secure and affordable energy supply – an example being a Munich-based car maker, which had 4 WTG
installed at one of its plants – albeit in the neighbouring state of Saxony.
Government assistance
Since the year 2000, government assistance for renewable energy in Germany has been governed by the EEG. It sets
fixed rates for various renewable energy sources. In the context of its first amendment, which came into force on 1 August 2004, the support for onshore WTG was reduced slightly, while the support for offshore turbines was improved and
put into more concrete terms. As part of the second amendment (effective since January 2009), the initial compensation
for new onshore WTG was raised to 9.2 ct/kWh. This amount was reduced by 1% p.a. for new WTG taken into operation
in subsequent years. In addition, a “system service bonus” (SDL-Bonus) of 0.5 ct/kWh was introduced for onshore WTG
that meet certain grid management requirements. SDL certification has meanwhile become a precondition for eligibility
to receive feed-in tariffs under the EEG. The payment for new WTG applies only to the period of the increased compensation. A bonus of 0.7 ct/kWh is paid for retrofits. The initial compensation for new onshore WTG replacing old ones
(repowering) also increased by 0.5 ct per kWh. The replaced units must come from the same or a neighbouring district
and be at least ten years old. The new plant must have at least twice and no more than five times the capacity of the old
plant it replaces. A third amendment was decided in mid-2011 and came into force on 1 January 2012, which raised the
rate of decrease of the compensation from 1.0% to 1.5%. It also abolished the capacity restriction for repowering, the only
condition being that the old plants must date from before 2002.
EEG 2014
The above mentioned bonus regulations were abolished as part of the fourth amendment, which came into force on 1 August 2014. The initial compensation for onshore WTG taken into operation in 2015 is 8.9 ct/kWh. After the period during
which the initial compensation is paid, a basic compensation of 4.95 ct applies. Starting 1 January 2016, both rates will be
reduced by up to 1.2% on a quarterly basis depending on the newly installed capacity.
The basic rule is that wind turbine generators are entitled to a feed-in tariff for wind power for a period of 20 years from
the start of operation (plus the remaining months in the year in which the WTG is taken into operation). The duration of
the initial compensation depends on the energy yield relative to a defined reference value. This value is based on a fictitious
reference location benefitting from an average wind speed of 5.5 m/s at a hub height of 30 metres and a class 1 roughness
(no shear). To determine the duration for which the higher initial compensation is paid, the reference yield is compared
with the actual yield of the new WTG (during the first five years of operation). The duration of the initial compensation is
extended from five years by one month for each 0.36% (previously 2 months for each 0.75%) of the reference yield by which
Page 16
the actual yield at the new site is below 130% (previously 150%) of the defined reference yield. Additionally, this period is
extended by one more month for each 0.48% by which the yield is below 100% of the reference yield. This formula is designed to secure the higher initial compensation primarily for those plants whose economic viability is marginal because of
their locations. Compared to the old version of the EEG, the period during which the initial compensation is paid has been
reduced for sites achieving yields in excess of 80%.
The chart below shows the average compensation in relation to the yield as the benchmark for the site quality based on the
tariffs under the old EEG for 2013 and 2015 as well as the new EEG for 2015. The initial compensation is paid for the full
20 years for those sites which generate up to 80% of the reference yield. The average wind speeds at which this threshold is
exceeded vary from plant to plant but should usually range from 6.5 to 6.8 m/s.
Average compensation for onshore WTG in € per MWh in relation to the reference yield
compensation in €/MWh
100 €
90 €
80 €
70 €
60 €
50 €
75.0%
77.5%
80.0%
82.5%
85.0%
87.5%
90.0%
92.5%
95.0%
97.5%
100.0%
102.5%
105.0%
107.5%
110.0%
112.5%
115.0%
117.5%
120.0%
122.5%
125.0%
127.5%
130.0%
132.5%
135.0%
137.5%
140.0%
142.5%
145.0%
147.5%
150.0%
40 €
% of reference yield
old EEG 2013
old EEG 2015
new EEG
Source: EEG; Krakau-Research computations
The future initial compensation for offshore WTG will amount to 15.4 ct/kWh (previously 15.0 ct/kWh). The initial compensation is paid for a period of at least 12 years and is extended by 0.5 month for each full nautical mile that exceeds a
distance of 12 nautical miles from the coastline and by 1.7 months for each full metre of water depth that exceeds 20 metres.
Alternatively, offshore WTG taken into service before 2020 (previously before 2018) may apply for an “initial compression model” (so-called “optionales Stauchungsmodell”), under which the initial compensation is increased to 19.4 ct/kWh
during the first eight years. After eight years, the above preconditions for an extended initial compensation also apply, but
only the lower initial compensation of 15.4 ct/kWh is paid. After the full initial compensation period, a basic compensation
of 3.9 ct/kWh is paid.
The “Green Electricity Privilege” introduced in the context of the 2009 amendment of the EEG (section 39), which was
already restricted as part of the last amendment, is no longer considered in the current version save for certain special regulations relating to own consumption.
Under the latest EEG amendment, fixed initial compensation will only be paid for smaller plants (up to 500 kW). For all
other plants, the optional market premium model introduced in the context of the 2012 amendment is now mandatory. The
plant operators must now market their electricity generated from wind power themselves. In addition to the revenues thus
generated, they receive a “moving market premium”, which is calculated from the difference between the average monthly
price at the electricity exchange and the regular EEG compensation. A management premium will no longer be paid. The
management costs of direct marketing must therefore be borne by the generator.
A new aspect of the EEG is the prospect that in the medium term – no later than 2017 for onshore WTG – the level of subsidies for renewable energy projects will be determined by way of tenders in order to determine the most favourable form of
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Page 17
energy generation for the respective technologies. This implies the prospect of inverse auctions, which are being practised
quite successfully in many other countries, which are, however, usually characterised by a much lower population density
and relatively large wind projects. In Germany, relatively few projects comprise more than ten WTG, resulting in relatively
higher administrative costs. Even though the exact details are not known yet, it is already obvious that the project development market will change significantly. In particular, it is unclear how community wind farms will function in this context.
Offshore
As mentioned above, the federal government plans to have up to 6,500 MW of offshore power installed by 2020. The
target for 2050 is 30,000 MW, which would cover 15% of German electricity consumption. While the construction of offshore wind turbine generators clearly lagged behind expectations for many years, recent years have seen things accelerate. Including the 48 WTG with a total capacity of 240 MW installed last year, the installed capacity now totals 520 MW.
Moreover, foundations for five wind farms were installed in 2013, plus another three had turbines installed already.
Due to their short track record, the question whether offshore wind farms are cost-efficient cannot be definitively answered. One of the main challenges is the high water depth of up to 40 metres, which results from politically imposed regulations that bar the construction of wind turbines within sight from the coast and within the habitat of sea birds. The
deeper the water, the greater the technical challenges and the higher the construction costs of setting up the foundations
for a wind turbine generator. In contrast to their onshore counterparts, offshore WTG are exposed to harsh weather conditions and a salty environment, which poses particular technical challenges. Installation and maintenance are considerably more complex, resulting in higher investment and operating costs. The grid connection required to transport the
offshore electricity to the shore is no less complex. Everybody will remember last year’s headlines made by the Riffgat
offshore wind farm, which could initially not be taken into operation as planned, as the discovery of World War II bombs
delayed the installation of the underwater cable. Diesel engines were therefore required to move the rotor blades, inviting blanket criticism from wind power opponents. The wind farm was finally connected to the grid in February 2014.
Already back in 2010, Germany’s first offshore wind farm, Alpha Ventus, was taken into operation off the island of
Borkum in the context of the RAVE (Research at Alpha Ventus) initiative. It comprises six WTG each from REpower
and Multibrid (today’s Areva) with a capacity of 5 MW each. After the first full year of operation, the wind farm already
published yield figures that exceeded the forecasts by 15%. A power yield of 267 GWh, which is equivalent to 4,450 full
load hours, and high continuity – no electricity was reportedly produced on only three days of the year 2011 – show that
offshore wind power is increasingly able to cover base load requirements.
Policy-makers have expressed their commitment to expanding the use of offshore wind energy for many years. At the
same time, high environmental requirements, e.g. stricter sound emission requirements to be met when the foundations
are rammed into the seabed, were imposed, thus impeding the expansion. As the Riffgat case mentioned above shows,
grid connection is one of the main problems. While the Infrastructure Planning Acceleration Act, which governs the
responsibilities of the network operator, was legislated already back in 2006, an agreement regarding liability issues
was reached only two years ago. The liability of the transmission network operators vis-à-vis offshore wind farms is
now limited to EUR 100 million per case. In case of damages, the transmission network operator may pass the expenses
incurred for settlement and compensation payments to the final consumer via the EEG apportionment within legally
defined limits. In addition, there will be a system change towards a separate offshore grid development plan for the
connection of offshore wind farms. The latter is currently in the consultation phase. Different scenarios exist, according
to which the expansion requirements of the offshore grid are estimated at between 1,135 km and 2,540 km by the year
2024, which would then provide an additional 3.7 to 7.9 GW.
The actual expansion is likely to tend towards 7.9 GW when the long list of planned projects is finally being implemented
step by step. To provide a rough outline of the total scope, the list below shows the completed and the approved offshore
projects in the North Sea and the Baltic Sea. The first stage of the approved North Sea projects alone has a capacity of
approx. 8 GW, with another 1.2 GW planned in the Baltic Sea. There are also plans for further wind farms, but these have
not been approved yet.
Page 18
Offshore wind farms in operation (North Sea)
EEZ / TW *
Number of
WTGs
Turbine
rated power
[MW]
Total
Power
[MW]
ENOVA Energiesysteme GmbH &
Co.KG
TW
1
4.5
4.5
Hooksiel
BARD Engineering GmbH
TW
1
5
5
Riffgat
Offshore-Windpark Riffgat GmbH
& Co. KG
TW
30
3.6
108
Alpha Ventus
(former: Borkum West)
Stiftung Offshore Windenergie
EEZ
12
5
60
BARD Offshore 1
BARD Holding GmbH
EEZ
80
5
Name of Project
Developer
ENOVA Offshore Ems-Emden
Total
124
400
577.5
* EEZ = Exclusive Economic Zone, TW = Territorial Waters
Source: www.offshore-windenergie.net / BSH
Offshore wind farms in operation (Baltic Sea)
Name of Project
Developer
EEZ / TW *
Number of
WTGs
Turbine
rated power
[MW]
Total
Power
[MW]
Rostock
Nordex AG
TW
1
2.5
2.5
Baltic 1
EnBW Baltic 1 GmbH & Co. KG
TW
21
2.3
Total
22
48.3
50.8
* EEZ = Exclusive Economic Zone, TW = Territorial Waters
Source: www.offshore-windenergie.net / BSH
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Approved offshore wind farms (North Sea)
Name of Project
Developer
EEZ / TW *
Number of
WTGs
Turbine
rated power
[MW]
Total
Power
[MW]
Under construction
Amrumbank West
E.ON Kraftwerke GmbH
EEZ
80
3.6
288
Borkum Riffgrund I
Borkum Riffgrund I Offshore
Windpark A/S GmbH & Co. oHG
EEZ
77
3.6
277
DanTysk
Vattenfall Europe Windkraft GmbH
EEZ
80
3.6
288
Global Tech I
Global Tech I Offshore Wind GmbH
EEZ
80
5
400
Meerwind Süd / Ost
WindMW GmbH
EEZ
80
3.6
288
Nordsee Ost
RWE Innogy GmbH
EEZ
48
6.15
295
Trianel Windpark Borkum
(former: Borkum West II)
Trianel Windpark Borkum GmbH &
Co. KG
EEZ
40 (1. stage,
total: 80)
5
200 (1. stage,
total: 400)
EEZ
80
3.6
288
Expected construction start 2014
Butendiek
OWP Butendiek GmbH & Co.
KG
Expected construction start 2015
Gode Wind I
Gode Wind I GmbH
EEZ
55
6
330
Gode Wind II
Gode Wind II GmbH
EEZ
42
6
252
Expected construction start 2016
Kaikas
wpd Offshore GmbH
EEZ
-
7
581 (max. 600)
Veja Mate
BARD Holding GmbH
EEZ
80
5
400
Albatros
Northern Energy OWP Albatros
GmbH
EEZ
80
5
400
Borkum Riffgrund II
DONG Energy Borkum Riffgrund II
GmbH
EEZ
-
-
-
Borkum Riffgrund West I
DONG Energy Borkum Riffgrund
West 1 GmbH
EEZ
-
-
-
Delta Nordsee I & II
(former: ENOVA Northsea)
OWP Delta Nordsee GmbH
EEZ
67
6
402
Deutsche Bucht
Windreich AG
EEZ
42
5
210
EnBW HeDreiht
EnBW HeDreiht GmbH
EEZ
119
5
595
EnBW Hohe See (former: Hochsee
EnBW Hohe See GmbH
Windpark Nordsee)
EEZ
80
max. 6.15
492
Innogy Nordsee 2
(former: ENOVA 3)
RWE Innogy GmbH
EEZ
48
max. 6.15
295.2
Innogy Nordsee 3
(former: ENOVA 3)
RWE Innogy GmbH
EEZ
60
6.15
369
MEG Offshore I
Nordsee Offshore MEG I GmbH
EEZ
80
5
400
Nordergründe
Windpark Nordergründe GmbH &
Co. KG
TW
18
4-6
ca. 110
Nordsee One
(former: Nordsee One
(former: Innogy Nordsee 1))
RWE Innogy GmbH
EEZ
54
6.15
332.1
Nördlicher Grund
Nördlicher Grund GmbH
EEZ
-
-
-
OWP West
Northern Energy OWP West GmbH
EEZ
41
5
210
Sandbank
Vattenfall Europe Windkraft GmbH
EEZ
72
4
288
Total
* EEZ = Exclusive Economic Zone, TW = Territorial Waters
Source: www.offshore-windenergie.net / BSH
Page 20
1,503 - 1,543
7,592.5 7,811.5
Approved offshore wind farms (Baltic Sea)
Turbine
rated power
[MW]
Total
Power
[MW]
EEZ / TW *
Number of
WTGs
EnBWBaltic2GmbH
EEZ
80
3.5
288
ArkonabeckenSüdost
AWEArkona-Windpark-Entwicklungs
GmbH
(E.ON Climate & Renewables Central
EuropeGmbH)
EEZ
80
5
400
GEOFReE
GEOFReEGmbH&Co.KG
TW
5
5
25
Wikinger
(former:VentotecOst2)
Iberdrola Renovables Offshore
Deutschland GmbH
EEZ
80
5
400
Name of Project
Developer
Under construction
EnBWWindparkBaltic2
(former:KriegersFlak)
Expected construction start 2016
Total
245
1,113
*EEZ=ExclusiveEconomicZone,TW=TerritorialWaters
Source: www.offshore-windenergie.net / BSH
Outlook
Even though Germany has not been among the countries with the highest capacity additions for several years, the country has sent a clear political signal by
deciding the “Energiewende”. Wind power enjoys high acceptance, not least in
view of the high value creation. As a result of the amended EEG, which provides planning certainty for onshore WTG at least until the end of 2016 and for
offshore WTG until the end of the decade, capacity additions should continue at
the high level seen recently and even exceed this level temporarily. Even where
offshore capacity additions are concerned, it is now safe to assume that the federal government’s repeatedly reduced targets will be reached. Germany will thus
remain the most important wind market in Europe for the time being.
Market forecast in MW
New capacity
Base
30,989
2012
2,297
2013
3,238
33,730
2014e
4,200
37,930
2015e
3,900
41,830
2016e
3,200
45,030
2017e
2,000
47,030
2018e
2,400
49,430
60,000
2023e
k.A.
Ø growth p.a.
13-18e
7.9%
As many projects are to be realised before the end of 2014 in view of the EEG
18e-23e
4.0%
amendment, we expect capacity additions to exceed the 4 GW mark this year.
13-23e
5.9%
In the next two years, we expect considerably more than 3 GW of net new caSource: EWEA, own forecast
pacity. This assumes a growing percentage of offshore wind power. In 2017, the
planned reorganisation of the subsidy schemes should lead to a small slump for
onshore capacity added. The actual extent of this slump will depend on the timely start of the tenders for onshore WTG
for the time after the feed-in mechanism. Some 60 GW of wind power should be connected to the grid at the end of 2023,
including 8.0 GW of offshore capacity.
HSH NORDBANK.Com
Sector Study WIND EnERGy
September 2014
Page 21
2.1.2 France
2012 renewables mix
21%
47%
19%
13%
Wind
Solar
Waste
Source: EUROSTAT / Bloomberg
Other RE
GWh
Coal
Nuclear
Naturalgas
Hydro
Oil
Renewable energy
Others
Total
GWh
Wind
Solar
Geothermal
Waste
OtherRE
2007
24,446
439,730
21,987
57,953
6,163
15,754
3,751
569,784
2012
18,922
425,406
21,816
58,717
4,338
31,741
3,335
564,275
Change
-22.6%
-3.3%
-0.8%
1.3%
-29.6%
101.5%
-11.1%
-1.0%
Portion2012
3.4%
75.4%
3.9%
10.4%
0.8%
5.6%
0.6%
100.0%
2007
4,060
18
0
4,924
6,752
2012
14,913
4,015
0
6,192
6,621
Change
267.3%
22205.6%
n.m.
25.8%
-1.9%
PortionRE
47.0%
12.6%
0.0%
19.5%
20.9%
Source: EUROSTAT / Bloomberg
France is considered to be one of the European countries with the highest potential for generating electricity from wind
power. In the past, however, the development of renewable electricity production has lagged behind expectations. So far,
France has firmly believed in nuclear power, which is why electricity produced from renewable energy accounts for only
5.6% of the total electricity production. At 47%, wind power accounts for the biggest share.
Ever since the 1970s, when electricity production from nuclear power plants was expanded significantly, France has
been dependent on nuclear power. At 75.4%, the relative share of nuclear power is the highest in Europe. French President François Hollande has formulated the target to reduce this share to 50% by 2025. France’s existing nuclear power
plants are technologically outdated. About half of the reactors were taken into operation in the late 1970s or early 1980s.
The first two will be switched off in 2016, with a total of 24 active nuclear power plants to be shut down by 2025. This will
leave a large gap in the country’s energy supply. Construction of the new “EPR” plant type (European Pressurized Water
Reactor) in Normandy continues in spite of criticism, with operation scheduled to commence in 2016.
To fill the capacity gap mentioned above, the French government has defined a target of 25 GW of installed wind energy capacity for the year 2020, which breaks down into 19 GW of onshore capacity and 6 GW of offshore capacity. This
would allow wind power to cover about 10% of the country’s electricity production. To reach this target, more than 2
GW would have to be installed per year. The trend of the past three years points in the opposite direction, though. Since
the record year 2010 (1,396 MW), capacity additions declined year by year (2013: 631 MW). Reasons for this downward
trend included a complex approval procedure, a changing legal framework and uncertainty regarding the feed-in tariff
for onshore plants. After a complaint was lodged, the European Court of Justice, in December 2013, ruled in favour of
the plaintiff that the feed-in compensation for onshore plants violates European law in that it is similar to a state subsidy which had not been properly reported to the EU. The French government was therefore forced to reorganise the
subsidy scheme for onshore plants in order to make the scheme compatible with applicable EU regulations. The new
amendments, which are confined to technical details and were published with the new Directive, ensure conformity with
EU legislation.
The government also aims to facilitate the framework conditions for the development and realisation of wind power
projects. The new French Energy and Environment Minister, Ségolène Royal, has defined renewable energy as one of
six priorities. This also includes the creation of one hundred thousand jobs in this sector. Moreover, a set of measures
was adopted in 2013 with the aim of simplifying the regulations. As a result, WTG have to undergo only one instead of
two approval procedures. The simplified procedure is currently being tested in seven regions. Another step towards simplification is the replacement of local plans with national plans, according to which operators must install the plants in
approved zones in order to receive subsidies. The government has also abolished the rule that wind farms must comprise
at least five plants to be eligible for subsidisation.
Page 22
Offshore
Unlike its neighbouring countries Belgium, Germany and Great Britain, France has no offshore wind farms in operation, although the country has very good wind conditions for the erection of offshore WTG. In some areas, however, the
water is so deep that the use of floating foundations is recommendable. This technology is still at the testing stage, for
which some plants have been established along the coast. These are taken into operation only for a few months for test
purposes.
Although contracts for six offshore wind farms have been awarded in two tenders to date, even the most important
French developer, Électricité de France (EdF), believes that the 2020 target of 6 GW of offshore capacity will not be
reached. Contracts for four offshore wind farms in Normandy and Brittany were awarded in the first tender. The investment totals about EUR 7 billion and the capacity amounts to 1.92 GW. A consortium of EDF and Dong Energy won the
contracts for three sites. A total of 238 Alstom turbines with a total capacity of 1,428 MW will be installed in Fécamp
(498 MW), Courseulles-sur-Mer (450 MW) and Saint-Nazaire (480 MW). 100 5-MW Areva turbines will be erected by
Iberdrola at the fourth site, Saint-Brieuc. Construction of the wind farms in Fécamp und Courseulles-sur-Mer is scheduled to commence in 2016, while the Saint-Brieuc and Saint-Nazaire farms are to go on line between 2017 and 2019.
The contracts for another two offshore wind farms were awarded in a second tender; each has a capacity of 496 MW and
the investment totals EUR 3.5 billion. Both farms, Le Tréport and Iles d’Yeu et de Noirmoutier, will be developed by a
consortium comprising GDF Suez (47%), EDP Renewable (43%) and Neoen (10%); a total of 124 8-MW Areva turbines
will be erected. Construction of the two offshore wind farms is scheduled to commence in 2019, with both projects to go
on line in 2021.
The ministry has begun to examine suitable areas for another tender. The areas should be suitable for both fixed and
floating plants.
Government assistance
New French WTG are subsidised by a feed-in tariff, which was last set in 2008. Onshore WTG receive it for 15 years and
offshore WTG for 20 years. The tariff for onshore plants is 8.2 ct/kWh for the first ten years, followed by between 2.8
and 8.2 ct/kWh (depending on the actual full load hours) for the following five years. Offshore WTG receive 13 ct/kWh
for the first ten years and 3 to 13 ct/kWh (depending on the full load hours) for the remaining term. The WTG must be
installed in designated areas. The tariffs are adjusted annually by an inflation factor. The plant operator officially signs a
power purchase agreement (PPA) with the grid operator, who undertakes to purchase the electricity produced. Usually,
EDF is the grid operator. Consumers pay a premium on the normal electricity price, which is calculated by the Energy
Regulation Commission (Contribution au Service Public de l’Èlectricité – CSPE) and reflects the additional costs caused
by renewable energy.
The feed-in tariff for offshore projects is fixed within the framework of tenders. In this context, the above feed-in tariff is
taken as the benchmark for the maximum compensation for offshore farms. As a general rule, a contract is awarded to
the bidder submitting the lowest tariff bid.
Outlook
Thanks to the good wind conditions resulting from the 3,500 km coastline, “La
Grande Nation” has huge potential as a wind power site. Wind conditions are
considered to be the second best – behind Great Britain – in Europe. In terms
of capacity additions and installed base, however, France is lagging far behind
the other large European countries. Good conditions for the installation of large
capacities can be found primarily in the south and off shore.
The past was characterised by political and legal uncertainty, which had an adverse impact. But the French government seems to have become aware of the
many problems and appears to be willing to try and address them. After the
EU state aid proceedings, the new legislation should give operators of onshore
WTG certainty, so that capacity additions should stabilise again.
The pace of development must accelerate considerably to reach the targets set.
HSH NORDBANK.Com
Sector Study WIND EnERGy
Market forecast in MW
New capacity
Base
2012
814
7,623
2013
631
8,254
2014e
800
9,054
2015e
1,100
10,154
2016e
1,326
11,480
2017e
1,700
13,180
2018e
1,800
14,980
2023e
k.A.
24,000
Ø growth p.a.
13-18e
18e-23e
13-23e
12.7%
9.9%
11.3%
Source: EWEA, own forecast
September 2014
Page 23
After all, wind power plays a very important role for future supply security, as the shutdown of outdated nuclear power
plants will increase demand for alternative electricity generation sources. Our forecast is based on the assumption of
sharply rising capacity addition figures. In 2023, France should have an installed capacity of about 24 GW, of which 4.5
GW will be attributable to offshore plants.
Page 24
2.1.3 Great Britain
2012 renewables mix
22%
48%
27%
3%
Wind
Solar
Waste
Other RE
Source: EUROSTAT / Bloomberg
GWh
Coal
Nuclear
Naturalgas
Hydro
Oil
Renewableenergy
Others
Total
GWh
Wind
Solar
Geothermal
Waste
OtherRE
2007
135,945
63,028
165,793
5,077
5,050
20,391
1,546
396,830
2012
143,181
70,405
100,074
5,285
3,064
40,820
1,008
363,837
Change
5.3%
11.7%
-39.6%
4.1%
-39.3%
100.2%
-34.8%
-8.3%
Portion2012
39.4%
19.4%
27.5%
1.5%
0.8%
11.2%
0.3%
100.0%
2007
5,274
14
0
6,074
9,029
2012
19,584
1,188
0
11,204
8,844
Change
271.3%
8385.7%
n.m.
84.5%
-2.0%
PortionRE
48.0%
2.9%
0.0%
27.4%
21.7%
Source: EUROSTAT / Bloomberg
Great Britain is considered the best wind power location in Europe, both for onshore and offshore plants. Due to its geographic location, Great Britain is exposed to strong Atlantic winds, which are ideal for electricity generation from wind power.
Great Britain is a clear leader in offshore wind energy, as the country benefits not only from favourable wind conditions but
also from relatively shallow waters, which offer better conditions for offshore WTG than those found in Germany, Denmark
and Belgium.
In the past, Great Britain’s electricity production was heavily reliant on coal. Coal-based electricity production picked up
sharply again in 2012, when it accounted for 39.4%. The share of nuclear energy increased as well to 19.4%. The increase
in electricity production from these energy sources is attributable to the gas-price-related cost disadvantage of gas power
stations and to the fact that coal-based electricity production benefited from overly cheap CO2 certificates. Renewables
continued to increase their share in electricity production to 11.2%, with wind power accounting for the biggest share
(48%), thus making the biggest contribution to the expansion of renewable energy. 1,883 MW of new wind power capacity was installed in 2013, including 733 MW of offshore capacity.
For many years, the British energy infrastructure has been regarded as technologically outdated. Between 2015 and
2020, numerous fossil power stations will have to be shut down – including ten nuclear power plants as well as coal and
gas power stations. In expanding its electricity generating capacity, Great Britain primarily relies on gas power plants
and renewables. To satisfy the demand for electricity, nuclear energy will also be expanded. The coalition agreement
rules out government assistance to the construction of new nuclear power plants. But the new reactors in Hinkley could
not be realised without government guarantees and fixed compensation. The European Commission has expressed its
doubts that the estimated subsidy of GBP 17.6 billion can be justified. The British government wants renewables to account for up to 30% of the country’s electricity production by the year 2020, with biomass conversion from conventional
power plants playing an important role. Moreover, the power grid needs to be modernised and expanded in order to
cope with future peak loads. To implement the objectives of the Electricity Market Reform (EMR), an amount of GBP
110 billion is to be raised from private investors.
The British government also aims to build up WTG production facilities in Great Britain. Siemens will be the first WTG
manufacturer to build a production and logistic centre for rotor blades in Hull. The EUR 190 million investment project
is scheduled for completion in 2016.
HSH NORDBANK.Com
Sector Study WIND EnERGy
September 2014
Page 25
Government assistance
Late 2013 saw the adoption of the Energy Act, which is designed to reform the energy market. It is linked to the Electricity Market Reform (EMR) and a new subsidy scheme. The current quota system (see below) will be phased out successively by 31 March 2017. New plants will then be subject to the Contract for Difference (CfD), which will be introduced
in 2014. During the transitional phase, operators can choose between the two schemes.
The current quota system involves the allocation of tradable Renewables Obligation Certificates (ROCs). Onshore wind
turbine generators receive 0.9 ROCs per MWh, while offshore WTG receive 2 ROCs per MWh. Electricity suppliers must
feed in a defined proportion of their electricity from renewable sources. This proportion increases steadily and amounted to 0.206 ROC per MWh for the period from April 2013 to March 2014. Suppliers who do not have enough ROCs
must pay an inflation-indexed penalty, which amounted to GBP 42.02 per MWh in 2013/2014. Generators who were
subsidised under the ROC scheme before adoption of the CfFD system will receive the subsidies for the full 20-year term
until expiry of the scheme in 2037 (“grandfathering”).
To make the market more attractive to smaller farms or individual plants, a feed-in tariff for wind farm projects of less
than 5 MW was introduced in 2010. Since April 2014, the feed-in tariff has amounted to GBP 0.1778 per kWh for plants
of up to 100 kW. Plants of between 100 kW and 500 kW receive GBP 0.1482 per kWh, while plants of between 500 kW
and 1.5 MW receive GBP 0.0804 per kWh. A lower feed-in tariff of GBP 0.0341 per kWh applies to plants of over 1.5
MW. The compensation will be adjusted with effect from 1 April 2015. The introduction of the tariff led to a boost in the
construction of small plants, of which 17,000 have meanwhile been installed in Great Britain.
The first CfD auction will be held in autumn 2014. In contrast to the ROC system (20 years), the CfD subsidisation period
is limited to 15 years. The CfDs will be allocated in an auction by the state-owned Low Carbon Contracts Company Limited (LCCC). The generator will continue to sell the electricity produced in the electricity market and will additionally
receive the difference up to a predefined reference price. Should the compensation paid to the generator exceed the fixed
reference price, the difference must be paid to the LCCC. In 2015/16, the reference prices will amount to GBP 93.18 per
MWh for onshore plants and to GBP 152.04 per MWh for offshore plants. Thereafter, they will be reduced steadily and
reach GBP 88.28 per MWh for onshore WTG and GBP 137.32 per MWh for offshore plants in 2018/19. The timetable for
the introduction of the first CfD tender is shown below:
Schedule
Expected date
Budget for 1st round
30/09/2014
Application deadline
28/10/2014
Beginnig of auction
27/11/2014
Deadline for proposal
04/12/2014
Source: Department of Energy & Climate Change
In view of the planned introduction of CfDs, some projects have been suspended. Thanks to the fixed reference price,
the new subsidy scheme gives generators greater planning certainty and hence a more attractive environment than the
ROCs. However, critics have accentuated the shorter subsidisation the period. We project a positive effect on growth in
the foreseeable future.
In addition to the CfD, a “capacity market” will be established, which rewards generators for the provision of reserve
capacity for periods characterised by potential supply bottlenecks. Moreover, a “levy control framework” for an upper
limit of the subsidies achieved will be established in order to protect consumers from excessive electricity prices.
Offshore
Great Britain is currently the biggest market for offshore wind energy. Approx. 10 GW of offshore capacity is to be
established by 2020 to reach the targets set in conjunction with the Energy Act. About 3.7 GW of offshore capacity is
currently connected to the grid. So far, there have been three bidding rounds for the realisation of offshore farms. Numerous projects from the first two rounds have been realised and connected to the grid. In 2013 four offshore farms with
a total capacity of 733 MW were connected to the grid, with 241 MW already connected in 2012 – London Array (630
MW), Lincs (270 MW), Teesside (62.1 MW) and Gunfleet Sands III (12 MW). The three tables below show the completed
projects, the projects under construction as well as the approved projects:
Page 26
Offshore wind farms in operation
Name of Project
Region
Developer
Number of
WTGs
Turbine
Total Power
rated power
[MW]
[MW]
Barrow
North West
DONG Energy & Centrica
30
3.0
90.0
Beatrice Demonstration
Scotland
SSE Renewables
2
5.0
10.0
Blyth Offshore
North East
E.ON UK Renewables
2
1.9
3.8
Burbo Bank
North West
DONG Energy
25
3.6
90.0
Greater Gabbard
Thames Estuary
SSE & RWE Npower
Renewables
140
3.6
504.0
Gunfleet Sands I
East of England
DONG Energy
30
3.6
108.0
Gunfleet Sands II
East of England
DONG Energy
18
3.6
64.8
Gunfleet Sands III Demonstration Project
East of England
DONG Energy
2
6.0
12.0
Kentish Flats
South East
Vattenfall
30
3.0
90.0
Lincs
East Midlands
Centrica / DONG / Siemens
Project Ventures
75
3.6
270.0
London Array I
Thames Estuary
DONG Energy / E.On
Renewables / Masdar
175
3.6
630.0
Lynn & Inner Dowsing
East Midlands
Centrica Renewable Energy
Ltd
54
3.6
194.4
North Hoyle
North Wales
RWE Npower Renewables
30
2.0
60.0
Ormonde
North West
Vattenfall
30
5.0
150.0
Rhyl Flats
North Wales
RWE Npower Renewables
25
3.6
90.0
Robin Rigg
Scotland
E.ON UK Renewables
60
3.0
180.0
Scroby Sands
East of England
E.ON UK Renewables
30
2.0
60.0
Sheringham Shoal
East of England
Scira Offshore Energy Ltd
88
3.6
316.8
Teesside
North East
EdF ER
27
2.3
62.1
Thanet
South East
Vattenfall
100
3.0
300.0
Walney I
North West
DONG Energy / SSE
Renewables/ Ampere Equity
/ PGGM
51
3.6
183.6
Walney II
North West
DONG Energy / SSE
Renewables/ Ampere Equity
/ PGGM
51
3.6
183.6
Total
1,075
3,653.1
Source: www.RenewableUK.com
HSH NORDBANK.Com
Sector Study WIND EnERGy
September 2014
Page 27
Offshore wind farms under construction:
Number of
WTGs
Turbine
Total Power
rated power
[MW]
[MW]
Name of Project
Region
Developer
Gwynt y Mor
North Wales
RWE Innogy / SWM /
Siemens
160
3.6
576.0
Humber Gateway
Yorkshire &
Humber
E.ON UK Renewables
73
3.0
219.0
Methil Offshore Wind Farm
Demo Site
Scotland
Samsung Heavy Industries
1
7.0
7.0
West of Duddon Sands
North West
Scottish Power/DONG
Energy
108
3.6
389.0
Westermost Rough
Yorkshire &
Humber
DONG Energy
35
6.0
210.0
Total
377
1,401.0
Source: www.RenewableUK.com
Approved offshore wind farms:
Name of Project
Region
Developer
Beatrice
Scotland
SSE Renewables / SeaEnergy
Number of
WTGs
Turbine
Total Power
rated power
[MW]
[MW]
277
2.7
750.0
Blyth Offshore Wind
North East
Demonstration site (NAREC)
NAREC
15
6.7
99.9
Dudgeon
Greater Wash
Statoil & Statkraft
67
6.0
402.0
East Anglia One
East of England
ScottishPower Renewables &
Vattenfall
240
5.0
1,200.0
European Offshore Wind
Deployment Centre
(EOWDC)
Scotland
Vattenfall, Technip &
Aberdeen Renewable Energy
Group (AREG)
11
7.0
77.0
Galloper (Greater Gabbard
Extension)
Thames Estuary
SSE & RWE Npower
Renewables
94
3.6
340.0
Kentish Flats II
South East
Vattenfall
15
3.3
49.5
Moray Firth
Scotland
EDP Renovaveis, Seaenergy
Renewables
186
6.0
1,116.0
Race Bank
East of England
DONG Energy
91
6.4
580.0
Rampion
South East
E.ON UK Renewables
175
4.0
700.0
Triton Knoll
Greater Wash
RWE Npower Renewables
150
6.0
900.0
Total
Source: www.RenewableUK.com
Page 28
1,321
6,214.4
Outlook
We continue to believe that Britain remains one of the most promising wind
energy markets in Europe. This is not least attributable to the strong offshore
sector, although the number of offshore farms under construction is currently
relatively low due to the completion of several facilities. But the pipeline of approved projects is promising. Growth may slow down somewhat in the short
term, however, due to the upcoming parliamentary elections in May 2015
and potential uncertainty about the new subsidy scheme. In the longer term,
however, the new schemes and the additional political initiatives should lead
to higher growth and attractive conditions for investors, not least against the
background of the changing energy infrastructure. Offshore wind farms should
account for about half of the future capacity additions.
Market forecast in MW
New capacity
Base
2012
2,064
8,649
2013
1,883
10,531
2014e
1,500
12,031
2015e
1,900
13,931
2016e
2,200
16,131
2017e
2,400
18,531
2018e
2,500
21,031
2023e
k.A.
33,000
Ø growth p.a.
13-18e
18e-23e
13-23e
14.8%
9.4%
12.1%
Source: EWEA, own forecast
HSH NORDBANK.Com
Sector Study WIND EnERGy
September 2014
Page 29
2.1.4 Ireland
2012 renewables mix
GWh
Coal
Nuclear
Naturalgas
Hydro
Oil
Renewableenergy
Others
Total
9%
6%
85%
Wind
Waste
Other RE
Sourcew: EUROSTAT / Bloomberg
GWh
Wind
Solar
Geothermal
Waste
OtherRE
2007
5,499
0
15,465
667
1,919
2,476
2,172
28,198
2012
5,499
0
13,732
802
249
4,708
2,602
27,592
Change
0.0%
n.m.
-11.2%
20.2%
-87.0%
90.1%
19.8%
-2.1%
Portion2012
19.9%
0.0%
49.8%
2.9%
0.9%
17.1%
9.4%
100.0%
2007
1,958
0
0
13
505
2012
4,010
0
0
287
411
Change
104.8%
n.m.
n.m.
2107.7%
-18.6%
PortionRE
85.2%
0.0%
0.0%
6.1%
8.7%
Source: EUROSTAT / Bloomberg
Thanks to its geographic location in the North Atlantic, Ireland benefits from virtually ideal wind conditions for the
operation of wind power plants. Wind speeds average over 8 m/s – a record in Europe. Accordingly, wind energy already accounts for a major portion of Ireland’s electricity supply. Between them, all renewable energy sources account for
17.1% of Ireland’s total electricity production, of which as much as 85,2% is attributable to wind power. At almost 50%,
however, natural gas continues to account for the biggest share.
Ireland has set itself the objective to generate 40% of its electricity from renewable energy by 2020. Wind energy from
onshore WTG is one of the most important parameters. To reach the target, a capacity of 5.5 to 6 GW is required.
In the offshore segment, only one 25 MW pilot wind farm has been constructed to date – the Arklow bank project (phase
1). An active market for offshore WTG is virtually non-existent. This is due to the lack of government assistance, which
would be required to make offshore wind power profitable for investors. One of the reasons for the decision not to subsidise offshore WTG is the fact that the expansion targets can be reached with onshore plants alone; another reason are
the austerity measures imposed on Ireland by the EU as a result of the debt crisis.
The Irish government has considered exporting excess electricity from renewable energy to Great Britain. On the one
hand, this would help Great Britain reach the renewable electricity generation targets, which is permissible under EU
legislation; on the other hand, the domestic wind power market would benefit from higher growth. However, these plans
are said to have been scrapped by the British government because of excessively high costs.
Government assistance
The Irish subsidy system is based on a feed-in tariff, with end consumers bearing the costs. The first programme was introduced in 2006 under the name of “REFIT 1” (Renewable Energy Feed-in Tariff) and has since been amended. REFIT
2 governs onshore wind power, hydropower and biomass from landfill gas, while REFIT 3 merely governs the subsidies
for biomass. The regulations apply to new plants built since 2012. The subsidies paid under REFIT 2 apply to plants for
which an application is filed by the end of 2015 and run for 15 years. Total REFIT 2 subsidies are limited to a maximum
of 4 GW, however. It can be assumed that a new scheme will follow once the limit is reached.
Wind turbine generators sign a power purchase agreement (PPA) with an electricity provider. All providers are obliged
to purchase electricity from subsidised renewable energy. The remuneration for onshore plants depends on the size of
the farm and amounts to EUR Cent 6.96 per kWh for farms of over 5 MW and to EUR Cent 7.20 per kWh for farms up
to and including 5 MW. The rates are adjusted annually by applying an inflation factor.
Page 30
Outlook
We believe that the Irish wind market has considerable potential for expansion,
primarily because of the favourable wind conditions and a stable promotion
scheme. In the coming years, capacity additions will almost exclusively take
place on shore. Good wind conditions and initiatives expected to be launched
by the Irish government should stimulate the market.
Market forecast in MW
New capacity
Base
2012
121
1,749
2013
288
2,037
2014e
320
2,357
2015e
360
2,717
2016e
400
3,117
2017e
420
3,537
2018e
450
3,987
2023e
k.A.
6,000
Ø growth p.a.
13-18e
18e-23e
13-23e
14.4%
8.5%
11.4%
Source: EWEA, own forecast
HSH NORDBANK.Com
Sector Study WIND EnERGy
September 2014
Page 31
2.1.5 Finland
2012 renewables mix
1% 4%
95%
Wind
Waste
Other RE
Source: EUROSTAT / Bloomberg GWh
Coal
Nuclear
Naturalgas
Hydro
Oil
Renewableenergy
Others
Total
2007
13,879
23,423
10,557
14,177
469
10,302
8,397
81,204
2012
7,098
22,987
6,726
16,859
312
11,915
4,423
70,320
Change
-48.9%
-1.9%
-36.3%
18.9%
-33.5%
15.7%
-47.3%
-13.4%
Portion2012
10.1%
32.7%
9.6%
24.0%
0.4%
16.9%
6.3%
100.0%
GWh
Wind
Solar
Geothermal
Waste
OtherRE
2007
188
4
0
10,081
29
2012
494
0
0
11,277
144
Change
162.8%
-100.0%
n.m.
11.9%
396.6%
PortionRE
4.1%
0.0%
0.0%
94.6%
1.2%
Source: EUROSTAT / Bloomberg
For several decades, Finland has generated much of its energy from nuclear power. The four active nuclear power plants
generate 32.7% of Finland’s electricity. The long-term strategy aimed at reducing greenhouse gas emissions builds on renewables and on nuclear power. Unlike most other EU countries, Finland has a clearly defined nuclear programme which
is based on the construction of new power plants in the future. A fifth nuclear reactor, Olkiluoto 3, was originally planned
to be put into service in 2009; however, the project is severely delayed and is now scheduled to be taken into operation by
2018, at a cost exceeding the original budget by far. The government has additionally ratified the construction of two more
nuclear reactors.
The government also aims for a significant expansion of renewable energy, with a special focus on electricity generation
from wood waste and wind power. While the latter accounted for a relatively low share of only 4.1% of electricity production from renewable energies in the past, it has shown a very positive trend. The development in the wind power sector has
accelerated markedly over the past two years. At the end of 2013, WTG with a total capacity of 448 MW were connected to
the grid, of which 89 MW was built in 2012 and 162 MW in 2013.
Annually 6 TWh of electricity is to be produced from wind energy by 2020. Onshore WTG account for by far the biggest
portion of the installed capacity. In the past, the military was able to block the installation of new WTG in military radar
zones, which often cover large areas. This development obstacle was removed in July 2013; in future compensation per
turbine must be paid. The conditions for the construction of offshore farms in Finland are considered to be relatively good
by European standards due to the proximity to the coast and the shallow waters. A certain focus is therefore being placed on
finding suitable sites for offshore farms. So far, however, only few financial incentives for the installation of offshore farms
have been created. Subsidies in the amount of EUR 20 million have therefore been made available for an offshore demonstration project for 2015. This project will receive remuneration in the form of a feed-in tariff and a development bonus.
Government assistance
The Finnish subsidy scheme builds on a fixed premium tariff, which is paid for a period of 12 years. The generators themselves market the electricity generated. After the 12-year period, only the market price is received. The subsidy is capped at
2.5 GW. A reference price of EUR 83.5 per MWh has been fixed for onshore and offshore plants. The compensation takes
the form of a premium which is calculated as the difference between the reference price and the average market price of the
past three months. If the average market price drops below EUR 30 per MWh, the compensation is capped at EUR 53.5 per
MWh. An elevated reference price of EUR 105.3 per MWh applies until the end of 2015.
Page 32
Outlook
We expect a very positive trend for the Finnish wind market and project increasing capacity additions as well as double-digit growth for what is still a small market. The increased feed-in tariff should accelerate capacity additions in 2014 and
2015. We project an installed wind power capacity of 5 GW for 2023. The use of
offshore WTG is indispensable in the long term to reach the political targets. This,
however, would require an increase of the feed-in tariff for offshore wind power as
well as the prolongation of the promotion period.
Market forecast in MW
New capacity
Base
2012
89
288
2013
162
448
2014e
360
808
2015e
520
1,328
2016e
420
1,748
2017e
400
2,148
2018e
400
2,548
2023e
k.A.
5,000
Ø growth p.a.
13-18e
18e-23e
13-23e
41.6%
14.4%
27.3%
Source: EWEA, own forecast
HSH NORDBANK.Com
Sector Study WIND EnERGy
September 2014
Page 33
2.2 Further regions
2.2.1 Benelux
Belgium
2012 renewables mix
16%
21%
17%
46%
Wind
Solar
Waste
For several decades, Belgium has covered most of its electricity consumption with nuclear power. Due to weak economic activity, electricity production in 2012 reached a historical low of approx. 82,874 GWh, with nuclear
power accounting for close to 50%. While natural gas remained the second
most important source of energy at 28,4%, the share of renewable energy
increased to 15.5%. This means that Belgium has already passed the 13%
target to which the government has committed itself towards the EU significantly. At 21%, wind energy accounts for the second biggest share of this
total behind electricity generation from waste. Electricity generation from
wind power has almost tripled since 2009. Equally remarkable is the huge
increase in solar power, which has increased more than tenfold during this
period.
Other RE
The expansion of renewable energy in Belgium is governed by “green certificates”, which are granted to operators of onshore and offshore WTG
for a period of 10 and a maximum of 20 years, respectively. The allocation of the certificates is handled autonomously
by the regions (Flanders and Wallonia). The issuance of certificates for offshore plants is handled at national level. The
minimum price for the certificates is thus dependent on the site of the plant; the minimum price per certificate currently
amounts to EUR 65 in Wallonia and to EUR 93 in Flanders. The minimum price for offshore certificates is EUR 107 for
the first 216 MW and EUR 90 thereafter. The subsidy scheme in Wallonia is currently being debated and a new tender
system is to be introduced in 2014/2105. Details were not known at the editorial deadline.
Source: EUROSTAT / Bloomberg
57 MW of new onshore capacity was built in Flanders in 2013. Although the targets in Flanders are less ambitious than in
Wallonia, capacity additions in Flanders have been much more stable over the past years. In Wallonia, annual capacity
additions have traditionally been much higher, but 2013 saw only 27 MW of new capacity being built. This was due to
uncertainties arising from a political amendment of the subsidy system, which affect the feasibility of projects. By contrast, the planning mechanism for offshore plants is well advanced. As neither fishing nor oil and gas play a role in Belgian waters, the offshore industry has more or less free rein in the nine planned zones. In 2013, the taking into operation of
offshore farms with a total capacity of 192 MW led to continued high capacity additions. A major contribution was made
by the completion of the 325 MW Thornton Bank project. Moreover, construction of the 216 MW Northwind project
started in April 2013. The 360 MW Norther project and the 165 MW Belwind-2 project are scheduled for completion in
late 2015. Two more projects – THV Mermaid (235–490 MW) and Rentel (288–550 MW) – are at the planning stage.
Meanwhile the grid connection of offshore plants remains difficult but should be expanded urgently in order to feed in
the planned capacity. The respective plans are being blocked by the parliament, however. Moreover, the subsidies for
offshore plants are to be reduced in order to cut the costs for consumers.
In view of a generally favourable trend and further efforts to eliminate bureaucratic obstacles in conjunction with construction permits for wind turbine generators, the outlook for the Belgian wind energy market is cautiously optimistic.
Page 34
Netherlands
2012 renewables mix
7%
35%
The Netherlands produced about 102,261 GWh of electricity in 2012, which
represented a decline by over 10% compared to the record year 2010. Electricity generation is dominated by fossil fuels, with natural gas accounting
for the biggest share (54.5%), followed by coal (23.7%). Renewable energy
accounted for 13.6% in 2012. Wind energy was the second most important
renewable energy source (35%) behind waste.
As part of a change in energy policy, the government has adjusted the targets set for renewable energy. The objective to produce 20% of the electri56%
2%
city from renewables was first reduced to 14% and then raised to 16%. The
government also decided to give preference to onshore wind over offshore
wind. 6,000 MW of onshore capacity is to be installed by 2020. 11 areas for
Wind
Solar
Waste
Other RE
the construction of onshore farms with a capacity of at least 100 MW were
chosen at a national level. Wind farms of this size are automatically subject
Source: EUROSTAT / Bloomberg
to government planning. Until 2023 4,500 MW are to be installed offshore.
Presently two projects are under construction: Luchterduinen (129 MW) and Gemini (600 MW), which shall be connected
to the grid by 2015 and 2016/2017, respectively.
The new SDE+ (Stimulering Duurzame Energieproductie) promotion scheme was introduced in 2013. Under this scheme,
wind farm operators receive the difference between a fixed base amount and a corrective amount, which is composed of
the market price, among other things. The provisional corrective amount for 2014 is EUR 0.058 per kWh. The application
period is divided into six phases which determine the amount of the compensation. In addition, only a maximum number of
full load hours is subsidised (see table below). During phase 1, the operator receives an amount of EUR 0.0875 per kWh less
the corrective amount for an annual maximum number of full load hours, i.e. an SDE+ subsidy of EUR 0.0295 per kWh. In
phase 2, the subsidy amounts to EUR 0.042 per kWh. It is advisable to apply for the subsidy at an early stage. As the subsidies are allocated on a “first come, first served” basis, there is a risk that late applicants are rejected as no more funds are
available. Total subsidies for 2014 are capped at EUR 3.5 billion; the maximum subsidisation period is 15 years.
Phase 1
Phase 2
Phase 3
Phase 4
Phase 5
Wind basis price per phase (€/kWh)
0.1000
0.1125
0.1125
0.1125
2,280
1,960
1,960
1,960
Phase 6
Onshore Wind < 6 MW
(max. full load hours)
0.0875
2,800
0.1125
1,960
Onshore Wind ≥ 6 MW
(max. full load hours)
0.0875
2,960
0.1000
2,960
0.1125
2,520
0.1213
2,320
0.1213
2,320
0.1213
2,320
Wind at shore
(max. full load hours)
0.0875
2,560
0.1000
2,560
0.1125
2,560
0.1375
2,560
0.1538
2,560
0.1538
2,560
Offshore Wind
(max. full load hours)
0.0875
3,000
0.1000
3,000
0.1125
3,000
0.1375
3,000
0.1625
3,000
0.1875
3,000
Source: Rijksdienst voor Ondernemend Nederland
Due to the cap and the “first come, first served” principle, uncertainty among investors may initially increase and capacity
expansion be delayed. In the offshore segment, costs should first fall by 35% to 40% to make projects feasible. This also
includes a standardised grid connection procedure. In this respect, it is positive that grid operator Tennet has been asked to
develop a plan for the best possible connection of up to 3.45 GW of offshore capacity. Against this background, stable growth
is expected for the Dutch wind market in view of the favourable wind conditions.
HSH NORDBANK.Com
Sector Study WIND EnERGy
September 2014
Page 35
Luxembourg
2012 renewables mix
6%
3%
7%
84%
Wind
Solar
Waste
Other RE
Source: EUROSTAT / Bloomberg
Being one of the smallest countries in Europe, Luxembourg produced only
3,776 GWh of electricity in 2012. Most of the electricity consumption is
covered by imports (6,732 GWh in 2012). Natural gas accounts for over
63% of the domestic electricity production. Renewables account for 34.2%.
Pumped storage plants account for by far the biggest portion of this, while
wind energy represents 6%. The installed capacity amounts to 58 MW and
is supplied by 15 wind farms.
In 2008, Luxembourg introduced a promotion scheme for renewable energy under which a feed-in compensation is paid. This scheme guarantees
that the grid operators purchase and pay for the electricity provided by
WTG operators. The additional costs are borne by end users. Wind energy
is subsidised at a rate of EUR 82.7 MWh for 15 years.
While the relevance of Luxembourg’s wind power market will certainly remain limited, we expect a number of wind farms
to be realised in the coming years in view of the demand for electricity and the fixed feed-in tariff.
Projected capacity additions in BeNeLux
Belgium
Netherlands
Luxembourg
Newcapacity
Base
Newcapacity
Base
New capacity
Base
2012
297
1,375
119
2,391
14
58
2013
276
1,651
303
2,693
0
58
2014e
250
1,901
360
3,053
0
58
2015e
360
2,261
475
3,528
20
78
2016e
300
2,561
750
4,278
40
118
2017e
350
2,911
700
4,978
20
138
2018e
350
3,261
550
5,528
0
138
Source: EWEA, own forecast
2.2.2 Scandinavia
Denmark
2012 renewables mix
Denmark looks back on over 30 years of wind energy generation. Due
to the excellent wind conditions resulting from the country’s favourable geographic location, wind energy was developed at an early stage. In
2012, electricity generated from wind power alone accounted for 33.5% of
the total production of 30,623 GWh. Between them, renewables account
for 50.4% of the total electricity production. Fossil fuels represent 34.5%
(coal) and 13.7% (natural gas), respectively.
2%
31%
66%
The new government elected in 2011 has clearly the targets for wind energy significantly, which has led to some impetus in the previously hesitant
wind market. By 2020, wind energy is to cover 50% of the country’s electricity consumption. As a result, capacity additions virtually exploded in
Wind
Solar
Waste
Other RE
2013, when 657 MW of new capacity was installed. This was largely driven
by
the taking into operation of the 400 MW Anhalt offshore farm (of which
Source: EUROSTAT / Bloomberg
51 MW was erected/installed already in 2012). 1.800 MW of onshore capacity and 1,500 MW of offshore capacity will be required to reach the ambitious target set for 2020. Offshore capacity will
primarily be added by the Horns Rev 3 project (400 MW) and the Kriegers Flak project (600 MW). Both tenders should
be closed in early and mid-2015, respectively, but the Kriegers Flak tender has been postponed by two years because of
the associated costs. Moreover, coastal areas for a capacity of 450 MW are being examined. Investments by Danish pen-
1%
Page 36
sion funds increasingly help finance large offshore farms, not only in Denmark. Significant amounts have been invested
not only by the two largest funds (PensionDanmark and PKA) but also by a number of smaller funds.
Denmark promotes the generation of renewable electricity primarily by means of a premium tariff, which grants operators a variable bonus in addition to the market price. Generators receive a bonus of DKK 0.25 per kWh, which is,
however, capped by a maximum statutory compensation. The bonus is based on a calculation mix consisting of two
components: full load hours and swept area (area covered by the rotor blades of a WTG). Depending on the quality of
the WTG site the bonus is paid for a period of 6 to 8 years (this is applicable to plants built after 1 January 2014). The
maximum compensation for onshore plants is DKK 0.58 per kWh. The compensation for offshore farms is determined
through tenders based on the bids received.
Capacity additions will focus on onshore plants in the shorter term and be driven by the expansion of offshore plants in
the longer term. Growth will also be supported by repowering activities. The latter is made possible by the new municipal
planning process.
Norway
2012 renewables mix
35%
50%
15%
Wind
Waste
Thanks to its geographic location and geological conditions, Norway is
rich in energy resources. The country’s prosperity is closely related to
the rich offshore oil and gas reserves. Norway’s independence in terms
of electricity production is a consequence of the excellent conditions for
the use of hydropower. In 2012, hydropower accounted for 96% of the
country’s total electricity production of 147,867 GWh. The (other) renewables account for only 2.1% of electricity production5. Wind energy
represents half of this. Norway has 768 MW of installed wind power capacity, all of which is installed on shore. Since 2012, capacity additions
have accelerated notably due to improved subsidy conditions. In the
past, subsidies were merely set from project to project.
Other RE
There has been an integrated Norwegian-Swedish certificates market
since 2012, when Norway joined the subsidy scheme originally established in Sweden in 2003. This common market shall help finance the
planned expansion of electricity production from renewable energy to 26.4 TWh by 2020. Both countries will equally
share the respective costs. The promotion scheme is based on a quota system accompanied by a system of tradable (renewable energy) certificates and shall last for 15 years. In order to be eligible for the full 15 years of support under this
scheme, the WTG must be taken into service until 2020, as the common certificates market will cease to exist by 2035.
The demand for “green” certificates is determined by a regulatory quota, which obligates the utilities to sell a predefined
share of electricity from renewable energy sources. The supply of “green” certificates is influenced by the investments
done into renewable energy plants, which receive a certain amount of certificates for each MW of “green electricity”.
Thus a WTG has two sources of income: the sale of electricity and the sale of certificates.
Source: EUROSTAT / Bloomberg
For both countries a step-up in the quotas is in sight, as new renewable power plants are expected to be built in the
common market. As for Norway the quota for 2014 is set at 6.9% and will be raised to 18.3% in 2020. After 2020, as this
promotion scheme will begin its phase-out, the number of certificates issued annually is to drop gradually. In order to
ensure an even distribution of the financial burden resulting from the promotion scheme, the quota are to be attuned to
each other. This will mean a moderate mark-down of the quota in Norway, and mark-up in Sweden.
In spite of the excellent wind conditions, the Norwegian offshore wind sector is virtually non-existent. Apart from the
fact that hydropower obviates the need for ambitious renewables targets, the oil and gas industry has dominated the offshore sector for decades and competes highly effectively for sought-after sites. As long as oil or gas is suspected at a site,
it is hardly imaginable that a wind farm could be built there. In this context, it is positive to see that several concessions
for the construction of offshore wind farms have been granted. The largest project, the 350 MW Havgul I wind farm, is
still at the planning stage, however.
5
Percentage of renewable energy without hydropower in accordance with Eurostat.
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September 2014
Page 37
Against this background, growing capacity additions are expected only in the onshore segment in the short term. Capacity additions in the offshore segment are likely to happen only in the medium term. In light of the the good wind
conditions as well as of the incentive created in the form of the joint certificates market, we are cautiously optimistic for
the Norwegian wind market up to 2020, beyond which new projects will no longer be allocated “green certificates”. The
quotas should be reduced slightly from 2015, which will probably have only little impact on capacity additions.
Sweden
2012 renewables mix
1%
34%
65%
Swedish electricity production reached a new record level of 166,562
GWh in 2012, which even exceeded the pre-crisis level. At 38.4% and
47.4%, respectively, nuclear energy and hydropower made the biggest
contributions. Renewables accounted for a relatively moderate 12.5%
during the same period. Wind energy (34%) accounted for the second
biggest portion of this behind (wood) waste. Wind energy has grown
strongly over the past years, with capacity increased to close to 4.5 GW.
Since the introduction of the quota system in 2003, the installed base
has increased almost twentyfold.
The most important promotion instrument is the quota system including
certificates trading, which was joined by Norway in 2012 (see “Norway”).
Wind
Waste
Other RE
In Sweden the regulatory quota, which defines the share of renewable
electricity in the total electricity marketed, amounts to 14.2% in 2014
Source: EUROSTAT / Bloomberg
and climbs to 19.5% by 2020. Beyond that year, as mentioned above,
the number of certificates issued will decrease gradually. However, Sweden has indicated a follow-up support scheme
already. While fears that many investors will now prefer Norway because of the better wind conditions have not been
confirmed so far, this risk still exists. The increased liquidity of the certificates trade is a positive effect of the integrated
market.
Nuclear energy still plays a very important role for Sweden’s energy supply. While Sweden will continue to use nuclear
energy in future, the sector is unlikely to receive further subsidies. Towards the EU, the government has set itself a target
of 60% for the generation of electricity from renewables (incl. hydropower) by the year 2020, which has almost been
reached. Between them, Norway and Sweden have agreed a target of 26.4 TWh to be produced from renewables by 2020.
No separate target has been set for wind energy, but it is expected that most of the required expansion will take place
in this segment. Some obstacles could impede the capacity expansion, however. In 2009, Swedish communities were
granted a veto right against the construction of new WTG and have increasingly made use of this right in recent times.
The electricity grid is another obstacle, as the electricity generated from wind energy must be transported from the
north to the south. The government has therefore divided the country into four regions so as to be able to provide more
differentiated incentives and to match electricity production to regional consumption. A new regulation has eliminated a
problem that existed with regard to the necessary expansion of the electricity grid. Under the old regulation, the operator
of a new plant had to bear the costs of the necessary grid expansions, which could lead to investment delays. Now the
costs of the grid expansion are divided between the operators.
Due to low electricity and certificates prices, the current situation in the joint market is precarious. Moreover, the Swedish Energy Agency has highlighted the imbalances in the quota system. To offset these imbalances, the quotas are to be
raised significantly from 2016. If this adjustment is not made, wind power capacity additions are likely to drop sharply
over the next three to four years. We assume that the adjustment will be implemented and that a marked soft patch in
2015 and 2016 will be followed by accelerating growth.
Page 38
Projected capacity additions in Scandinavia
Denmark
Norway
Sweden
New capacity
Base
New capacity
Base
New capacity
Base
2012
220
4,162
166
703
846
3,582
2013
657
4,772
110
768
724
4,470
2014e
320
5,092
250
1,018
750
5,220
2015e
360
5,452
350
1,368
400
5,620
2016e
480
5,932
500
1,868
350
5,970
2017e
500
6,432
600
2,468
650
6,620
2018e
500
6,932
600
3,068
700
7,320
Source: EWEA, own forecast
2.2.3 Eastern and South-Eastern Europe
Poland
2012 renewables mix
6%
31%
Poland’s electricity production has historically depended on coal. Coal
accounted for 83% of the total 2012 production of 162,138 GWh. Renewables represented 9.5% of the total electricity output, which means that
their share almost doubled compared to 2010. The increase is mainly attributable to the strong expansion of wind energy. Wind power accounted for 31% of the total electricity generated from renewables, making it
the second most important renewable energy source.
The current subsidisation is based on a quota system linked to a certificates system. It has recently led to strong growth in the onshore wind
segment. Between 2009 and 2013, wind power capacity increased almost
fivefold from 725 MW to 3,390 MW. In spite of this trend, the scheme
Wind
Waste
Other RE
is currently being revised and will soon be replaced with an auction sysSource: EUROSTAT / Bloomberg
tem. The new regulation, which still needs to be approved by parliament,
is designed to reduce the costs for consumers, as electricity costs are considered an important competitive factor for the
Polish economy. In the new auction system, operators submit bids for the relevant projects in an auction organised by
the Energy Regulatory Office. The bidder requesting the lowest subsidy for a 15-year period wins the contract.
63%
By 2020, renewables are to cover 15.5% of the electricity production. To reach this target, 6.55 GW of wind power capacity is to be installed by 2020, mostly in the onshore segment. Although wind conditions for offshore wind farms are favourable, the offshore target for 2020 is only 500 MW. Construction of the first offshore farms is scheduled to commence
in 2018. In contrast to these targets, Polish Prime Minister Tusk supports plans to install 6 GW of nuclear power. The
cost of the new power plant capacity is to be borne by consumers, which is why some market players doubt that renewable energy will be supported. But the construction of new nuclear power plants has not been decided yet, either, and
is doubtful in view of the high costs. The Polish power grid is another big problem, as there is insufficient free capacity
for transporting additional electricity from wind power on a relevant scale. The situation is aggravated by a bureaucratic
administration and controversial political decisions. A new law is designed to prohibit the installation of WTG within a
three-kilometre radius of residential areas and forests.
In view of the not overly ambitious expansion targets – capacity additions of only 500 MW p.a. are planned at a political
level – capacity additions are expected to slow down for the time being. In the offshore segment, relevant WTG installations will happen only in the medium term. After the adoption of the new subsidy scheme, one will have to wait and see
what influence it will have on investment activity.
HSH NORDBANK.Com
Sector Study WIND EnERGy
September 2014
Page 39
Romania
2012 renewables mix
10%
6%
84%
Wind
Waste
Other RE
Although Romania is considered the most advanced country in Eastern
Europe in terms of renewable energy expansion, most of the country’s
electricity production in 2012 came from fossil energy sources. At
38.8%, coal continues to make the biggest contribution to energy production, followed by hydropower, nuclear energy and natural gas with
20%, 19% and 15%, respectively. Renewables lag far behind at 5.3%, of
which wind power represents 85%. It should be noted, however, that
the development of wind power did not really get off the ground before
2010. The installed base increased from as little as 14 MW in 2009 to as
much as 2.6 GW at the end of 2013. Capacity additions peaked at 923
MW in 2012, only to drop to 695 in 2013, which was far below expectations. The downward trend was primarily due to changes in the subsidy
scheme and the resulting uncertainty among investors.
Government assistance in Romania is based on a quota system and certificates trading. After the coming into force of a new law, the issue of
certificates for plants installed before 2014 was retroactively reduced from two certificates to one certificate per MWh for
the period from 1 July 2013 to 31 March 2017. Two certificates per MWh will again be issued from 1 January 2018. For
plants built after 1 January 2014, operators receive 1.5 certificates per MWh until 31 December 2017; after that date, this
will be reduced to 0.75 certificates per MWh. The subsidisation period is 15 years. A minimum of EUR 27 and a maximum of EUR 55 have been set for the certificates until 2025; these amounts are inflation-indexed. The cost of the quota
system is borne by consumers via the electricity price. The changes were made after the government found out that a
lower number of certificates is sufficient for the further development of the sector. The quota system is complemented
by EU investment grants; in this case, however, no government assistance is granted.
Source: EUROSTAT / Bloomberg
The wind market is dominated by European utilities, who make a major contribution to capacity additions. In 2012,
Czech energy utility CEZ completed the 600 MW Fantanele-Cogealac project, which is the largest wind farm in Europe
to date. Other utilities such as Italy’s Enel also operate large wind farms in Romania. The Romanian grid is considered a
weak point, being designed for only 3 to 3.5 GW of wind power capacity, according to the grid operator.
As a result of the reduced government assistance, the compensation for wind power is hardly attractive any more. From
an investor’s point of view, the lack of legislative stability is even worse, as it affects the planning certainty that is required for a project. In view of the growing electricity requirements on the one hand and the still low share of renewable
energy on the other hand, we expect government assistance to be improved in the long term, which will also lead to more
promising prospects. The next years are expected to be weak, however.
Page 40
Turkey
2012 renewables mix
2%
Thanks to dynamic economic growth and growing prosperity, electricity production in Turkey has increased steadily for several years and
amounted to 239,497 GWh in 2012. At 43.6%, natural gas continues to
make the biggest contribution, followed by coal and hydropower with
27.7% and 24.2%, respectively. While electricity production from renewables has increased strongly over the past years, it still accounts for
only a low 3.1% of the total output. At 78.3%, wind power represents by
far the biggest share of this. In 2013, capacity reached the 3 GW mark,
of which half was installed in the last three years alone.
8%
12%
78%
Since 2011, wind power in Turkey has been subsidised in the form of a
fixed feed-in tariff of USD 73 per MWh for a period of ten years. This
applies to plants taken into operation prior to 1 January 2016. The law
Wind
Geothermal
Waste
Other RE
additionally grants operators up to USD 37 per MWh for a five-year period if locally produced components are used. In addition to the fixed
Source: EUROSTAT / Bloomberg
compensation, plant operators are also allowed to sell electricity directly
to utilities in the national electricity pool or under PPAs. As the terms of this direct sale are more attractive than the feedin tariff, most investors choose the direct sale.
A new regulation introduced in late 2013 has changed the application procedure. The filing of applications is now divided into two phases. In a prequalification round, the operator must obtain all necessary permits (regional planning, construction, land purchase, etc.) within a 24-month period. In the second phase, the Turkish Electricity Network Agency
stipulates how much electricity from wind power may be fed into the regional network per year.
In view of the growing demand for energy, Turkey’s electricity generation capacity must be expanded strongly in the
next ten years. The government plans to install 120 GW of new capacity for nuclear power and coal as well as renewable
energy. Wind power is to contribute a total capacity of 20 GW. The large country therefore offers long-term potential for
strong growth in the wind power market.
Projected capacity additions in Poland, Romania and Turkey
Poland
Romania
Turkey
Newcapacity
Base
Newcapacity
Base
New capacity
Base
2012
880
2,496
923
1,905
506
2,312
2013
894
3,390
695
2,599
646
2,956
2014e
700
4,090
250
2,849
800
3,756
2015e
600
4,690
150
2,999
1,000
4,756
2016e
700
5,390
100
3,099
1,200
5,956
2017e
800
6,190
100
3,199
1,200
7,156
2018e
800
6,990
100
3,299
1,200
8,356
Source: EWEA, own forecast
HSH NORDBANK.Com
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September 2014
Page 41
2.2.4 Southern and South-Western Europe
Italy
2012 renewables mix
18%
25%
13%
10%
34%
At 299,276 GWh, Italy’s electricity production in 2012 was by far insufficient to cover the country’s energy requirements. Accordingly, Italy
depends on electricity imports, which totalled over 45 GWh in 2012. Natural gas (43.1%) accounts for most of the domestic electricity production, followed by renewable energy (18.2%). At 26.4%, wind power makes the second biggest contribution to this behind solar power. Between
2010 and 2012, a bit more than 1 GW of new wind power capacity was
installed on an annual average. Total capacity reached 8.5 GW in 2013,
although annual capacity additions dropped to 444 MW. The strong decline is attributable to the amendment of the subsidy scheme.
Since 2013, plants of 5 MW and more have been subsidised in the form
of a feed-in tariff, which is allocated in an auction. Defined upper and
lower limits exist, which are reduced by 2% annually. The upper limit
Source: EUROSTAT / Bloomberg
for onshore WTG is EUR 124.46 per MWh and the lower limit is EUR
88.9 per MWh. The compensation is guaranteed for a period of 20 years. The compensation for offshore plants ranges between EUR 164.64 per MWh and EUR 117.6 per MWh for a period of 25 years. In addition, the government has
introduced capped capacity additions at 500 MW for onshore plants and at 650 MW for offshore plants between 2013
and 2015. It is doubted that any offshore projects at all will be realised in the coming years. In the first auction, the bids
did not even reach the cap. In the second auction, demand for onshore plants was much higher, whereas no bids were
submitted for offshore plants. This has raised hopes that offshore capacity may be used for onshore WTG in future. The
adoption of the auction system has made the process more difficult for operators.
Wind
Solar
Geothermal
Waste
Other RE
Against this background, the Italian wind market is expected to grow moderately, with capacity additions expected to be
slightly above the 2013 level.
Portugal
2012 renewables mix
8%
20%
1%
3%
68%
Portugal’s electricity production amounted to 46,469 GWh in 2012. At
32.3%, renewables made the biggest contribution. Coal and natural gas,
which used to dominate the electricity market account for 28.1% and
22.9%, respectively. At 68.2%, wind power is the most important renewable energy source by far. Total capacity, which is almost exclusively
installed on shore, amounted to slightly more than 4.7 GW at the end
of 2013. Capacity additions have slowed down markedly over the past
years. Due to the debt crisis, Portugal’s financial stability enjoys greater
political priority than the expansion of renewable energy. At 155 MW and
196 MW, respectively, capacity additions in 2012 and 2013 were much
lower than in the pre-crisis years.
Until 2012, renewable energy in Portugal was subsidised in the form of
a feed-in tariff, which obliges the grid operator to purchase and pay for
Source: EUROSTAT / Bloomberg
the electricity produced. The costs were passed on to consumers. The
compensation was calculated on the basis of a formula, with a distinction
being made between the different energy sources and the performance data of individual plants taken into consideration. The average compensation for electricity from wind power amounted to between EUR 74 and EUR 75 per MWh. The
tariff was limited to 15 years or a maximum of 33 GWh per MW installed. As the tariff for offshore WTG was the same,
only one test plant has been installed so far. A floating offshore test plant is at the planning stage and scheduled to be
taken into operation in 2017.
Wind
Page 42
Solar
Geothermal
Waste
Other RE
Assistance for renewable energy in Portugal continues to be characterised by uncertainty. While Portugal’s Prime Minister Pedro Passos Coelho has confirmed his positive attitude towards renewable electricity, the European Commission
wants the country to suspend the loss-making compensation system in order to receive continued financial support. The
government suspended the subsidisation of new wind power projects already at the beginning of 2012.
The good wind exposure resulting from the country’s geographic location provides good conditions for the installation
of WTG. However, capacity additions depend on the macroeconomic developments. Against this background, growth
in the Portuguese wind market is expected to remain low in the short and medium term. The market should grow a bit
more strongly in the long term.
Spain
2012 renewables mix
7%
A total capacity of close to 23 GW means that Spain is the second largest wind power market in Europe in terms of installed capacity. In 2012,
renewable energy made the second biggest contribution to the country’s
total electricity output of 297,532 GWh accounting for 23.8%. Fossil fuels continue to constitute an important component of the electricity mix.
At 24.6%, natural gas accounts for the biggest share of total electricity
production, while nuclear energy and coal amount to 20.7% and 18.5%,
respectively.
6%
17%
70%
Wind power accounts for 70% of total renewable electricity production,
thus representing an important element of the energy infrastructure. During peak times, more capacity (2.5 and 3.5 GW, respectively) than in Germany was installed per year. As the debt crisis broke out, the wind marWind
Solar
Waste
Other RE
ket came under pressure and finally collapsed completely in 2013. This
Source: EUROSTAT / Bloomberg
is attributable to the huge uncertainty among investors resulting from
retroactive cuts in the compensation for renewable energy. These cuts were eventually decided by the Spanish government
in June 2014. The resulting conditions will keep the wind market in limbo for a certain time.
Under a law of July 2013, which came into force in June 2014, government assistance in Spain has been generally abolished
for new plants, which now receive the usual market price. This regulation is to apply also to plants installed before 2005,
although this means that the previously guaranteed subsidisation period of 20 years will not be met. Plants that were taken
into operation after 2005 continue to be subsidised under a bonus scheme, with the return on investment of a plant currently capped at 7.4% p.a. on average over the useful life. The return is calculated as the average yield of 10-year Spanish
government bonds plus 300 basis points. Moreover, the government assistance is reduced with retroactive effect from the
first draft bill of July 2013, with any excess subsidy counting towards future claims. The legal aspects of the Spanish government assistance scheme are far from being transparent. Legal disputes are certain to continue for a while.
The original targets of 35 GW of onshore capacity and 3 GW of offshore capacity set for 2020 currently seem impossible
to be reached. In view of the abolition of the subsidies, the Spanish wind power market will see hardly any growth in the
short and medium term. In the long term, the market should regain some momentum, not least because of the local content
provided by Spanish WTG manufacturer Gamesa. At present, however, growth rates like those achieved prior to the debt
crisis seem virtually impossible to be reached.
HSH NORDBANK.Com
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September 2014
Page 43
Projected capacity additions in Italy, Portugal and Spain
Italy
Portugal
Spain
Newcapacity
Base
Newcapacity
Base
New capacity
Base
2012
1,239
8,118
155
4,529
1,110
22,784
2013
444
8,551
196
4,724
175
22,959
2014e
480
9,031
80
4,804
10
22,969
2015e
560
9,591
80
4,884
20
22,989
2016e
720
10,311
160
5,044
50
23,039
2017e
960
11,271
360
5,404
250
23,289
2018e
1,250
12,521
560
5,964
400
23,689
Source: EWEA, own forecast
2.3 A summary of the government assistance schemes
For quick reference, the countries presented in the preceding chapters and their government assistance schemes are
summarised in the table below:
FixedFeed-in-tariff
Feed-inpremium
variable
fix
Quota-/
Certificates
Country
Chapter
Germany
2.1.1
France
2.1.2
Great Brittain
2.1.3
Ireland
2.1.4
Finland
2.1.5
Belgium
2.2.1
Netherlands
2.2.1
Luxembourg
2.2.1
Denmark
2.2.2
Norway
2.2.2
onshore
Sweden
2.2.2
onshore
Poland
2.2.3
Romania
2.2.3
Turkey
2.2.3
Italy
2.2.4
Portugal
2.2.4
(onshore)
Spain
2.2.4
(onshore)
onshore until 2014
offshore
onshore
offshore
onshore starting
2015
onshore starting 2017
offshore
onshore
offshore
onshore
offshore
Contract For Difference
onshore
onshore
offshore
onshore
offshore
onshore
offshore
onshore
onshore
offshore
(coming)
offshore
onshore
(coming)
onshore
onshore
onshore
offshore
Sources: RES-Legal, EWEA, GWEC, regional associations, Krakau-Research
Page 44
Price-settingby
Tender process
onshore
offshore
3 Global forecast
Against the background of the anticipated population and economic growth in the emerging and developing countries,
we expect global electricity consumption to increase in the coming years. The International Energy Agency (IEA) expects
total energy consumption to grow by about one third until 2035 (base year 2011), which is equivalent to approx. 1.2%
per year. Given the changes in electricity usage, e.g. the shift towards electromobility, the coming decades are likely to
see electricity consumption grow faster than in the past. Political decisions which propel the use of renewable energy can
help to lessen dependence on fossil fuels and contain the threatening growth of carbon dioxide emissions.
Asides from environmental aspects, which are additionally supported by the globally more critical attitude towards
nuclear energy, it is good to see that economic aspects are increasingly also driving the expansion of wind energy. Wind
power will make electricity generation cheaper in the long term, while fossil energy sources are suffering from rising fuel
costs. Moreover, economic policy-makers are increasingly focusing on the aspect of local value creation as a substitute
for imports of energy or energy resources.
We continue to believe that the wind energy market will gain in regional breadth as numerous countries see their first
turbines installed and others attain relevant volumes for the first time. Being one of the wind power pioneers, Germany
is likely to remain Europe’s No. 1 in the coming years. In this context, offshore wind power will play an important and
established role in Germany, although its relative importance will not reach the same level as in Great Britain.
We expect capacity additions in Europe to reach a good 12 GW in 2014. Our 5-year outlook until 2018 assumes annual
capacity growth of close to 10%, while the long-term scenario shows a slowdown in growth to about 8% p.a. due to the
base effect.
The chart below shows the forecast for the five countries presented in detail as well as the other countries in Europe.
GW
Forecast of annually installed new wind power capacity in Europe
20
18
16
14
12
10
8
6
4
2
0
2012
2013
Germany
2014e
Finland
France
2015e
Great Britain
2016e
Ireland
2017e
2018e
Rest of Europe
Source: EWEA, GWEC, HSH Nordbank AG, Krakau-Research
HSH NORDBANK.Com
Sector Study WIND EnERGy
September 2014
Page 45
On a global scale, we expect a good 47 GW of capacity to be installed in 2014. In our mid-term scenario until 2018, we
project average annual capacity growth of a bit more than 13%. In our long-term scenario from 2018 to 2023, growth will
slow down somewhat to 9.4% p.a. due to the base effect.
Our forecast, which we call “wind model” the results of which you find below, takes a variety of factors into account. We
have focused primarily on forecasts for the individual markets and factored in national targets as well as the national
development plans within the EU. The main factors taken into account were the anticipated growth in electricity requirements, government assistance conditions and legal stability as well as topographic conditions. Data on planned projects has been taken into account in the forecast calculation to the extent that it was available at the time of calculation.
The “wind model”
in MW
Belgium
Denmark
Germany
Finland
France
Great Britain
Ireland
Italy
Luxembourg
Netherlands
Norway
Poland
Portugal
Romania
Sweden
Spain
Turkey
Other*
Total Europe
2011
1,078
3,956
29,071
199
6,807
6,556
1,631
6,878
44
2,272
520
1,616
4,379
982
2,907
21,674
1,799
4,669
97,038
Base
2012
1,375
4,162
30,989
288
7,623
8,649
1,749
8,118
58
2,391
703
2,496
4,529
1,905
3,582
22,784
2,312
5,657
109,370
2013
1,651
4,772
33,730
448
8,254
10,531
2,037
8,551
58
2,693
768
3,390
4,724
2,599
4,470
22,959
2,956
6,361
120,952
2014e
250
320
4,200
360
800
1,500
320
480
0
360
250
700
80
250
750
10
800
736
12,166
New Capacity
2015e
2016e
360
300
360
480
3,900
3,200
520
420
1,100
1,326
1,900
2,200
360
400
560
720
20
40
475
750
350
500
600
700
80
160
150
100
400
350
20
50
1,000
1,200
1,090
1,840
13,245
14,736
2017e
350
500
2,000
400
1,700
2,400
420
960
20
700
600
800
360
100
650
250
1,200
2,350
15,760
2018e
350
500
2,400
400
1,800
2,500
450
1,250
0
550
600
800
560
100
700
400
1,200
2,860
17,420
Base
2018e
2023e
3,261
4,200
6,932
9,000
49,430
60,000
2,548
5,000
14,980
24,000
21,031
33,000
3,987
6,000
12,521
20,000
138
500
5,528
7,500
3,068
5,000
6,990
10,000
5,964
10,000
3,299
4,800
7,320
12,000
23,689
28,000
8,356
16,000
15,237
29,580
194,279 284,580
CAGR
13-18e
18e-23e
14.6%
5.2%
7.8%
5.4%
7.9%
4.0%
41.6%
14.4%
12.7%
9.9%
14.8%
9.4%
14.4%
8.5%
7.9%
9.8%
18.9%
29.4%
15.5%
6.3%
31.9%
10.3%
15.6%
7.4%
4.8%
10.9%
4.9%
7.8%
10.4%
10.4%
0.6%
3.4%
23.1%
13.9%
19.1%
14.2%
9.9%
7.9%
China
USA
RestofWorld
Total World
62,364
46,929
31,681
238,012
75,324
60,007
38,031
282,732
91,412
61,091
44,128
317,583
18,000
5,000
12,016
47,182
18,000
7,000
11,786
50,031
17,000
14,000
14,030
60,790
18,636
12,000
15,626
63,682
179,048
111,091
109,678
594,096
14.4%
12.7%
20.0%
13.3%
16,000
12,000
12,705
55,441
*=Austria,Bulgaria,Croatia,Cyprus,CzechRepublic,Estonia,Greece,Latvia,Lithuania,Ukraine,Switzerland
Source: EWEA, GWEC, HSH Nordbank AG, Krakau-Research
Page 46
270,000
150,000
226,350
930,930
8.6%
6.2%
15.6%
9.4%
List of abbreviations
AWEA
CfD
CO2
CSPE
EEG
EMR
EPR
EU
EWEA
GW
GWEC
IEA
kW
kWh
LCoE
MW
MWh
p.a.
PPA
PTC
RE
REFIT
ROC
SCoE
SDE
SDL-Bonus
TW
TWh
WTG
American Wind Energy Association
Contract for Difference
Carbon dioxide
Contribution au Service Public de l’Électricité
Erneuerbare-Energien-Gesetz (German Renewable Energy Act)
Electricity Market Reform
European Pressurized Water Reactor
European Union
European Wind Energy Association
Gigawatts = 1,000 MW = 1,000,000 kW = 1,000,000,000 Watt
Global Wind Energy Council
International Energy Agency
Kilowatts = 1,000 watts
Kilowatt hour
Levelized Cost of Energy
Megawatts = 1,000 kW = 1,000,000 watts
Megawatt hour
per annum = per year
Power Purchase Agreement
Production Tax Credit
Renewable energy
Renewable Energy Feed-in Tariff
Renewables Obligation Certificate
Social Cost of Energy
Stimulering Duurzame Energieproductie
Systemdienstleistungsbonus (“system service bonus”)
Terrawatts = 1,000 GW = 1,000,000 MW = 1,000,000,000 kW = 1,000,000,000,000 Watt
Terrawatt hour
Wind turbine generator
HSH NORDBANK.Com
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Page 47
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Phone +49 40 3333-14035 Roland Schwab
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Phone +49 40 3333-12307 Copyright / Research:
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Analyst Research
www.krakau-research.de
Phone +49 4171 690850
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