20111129 KB107-1 Rapport Bloomberg Offshore Wind_binnenwerk-6[4]

Offshore Wind: Foundations for Growth

29 November 2011

Rabobank / Bloomberg New Energy Finance O!shore Wind: Foundations for Growth

2

Foreword

Sipko Schat &Michael Liebreich

Section 1

Executive summary

Section 2

Support mechanisms & political risk 2.1 EU policy 142.2 Role of o!shore wind according to NREAPs 152.3 National policy 16

Section 3

Costs & supply chain

3.1. Levelised cost of energy (LCOE) 273.2. Capital cost projections 283.3. Supply chain 293.4. Improved "nancing terms 363.5. Change in project environment 37

Contents

p05

p08

p12 p24

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Section 4

Market size projections

4.1. Scenarios 404.2. Markets 404.3. Forecast in context 43

Section 5

Funding require-‐ment & potential investors

5.1 Investment required 465.2 Equity investors 465.3 Debt providers 495.4 Capital structures 505.5 Investment volume by investor type 52

Appendices

Appendix A: O!shore Wind Cost Model 56Appendix B: Forecast methodology 58

Colofon

p39 p44

p59

p54


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Table of Figures

Figure 1 Electricity generation from renewable sources according to NREAPs, 2010 and 2020 (TWh) 15

Figure 2 LCOE of o!shore wind and selected technologies (EUR/MWh) 15Figure 3 Classic EEG 2009 tari! Germany (EUR/MWh) 19Figure 4 Compression EEG 2012 tari! Germany (EUR/MWh) 19Figure 5: UK o!shore wind project LCOE in Central Scenario, 2012-20 (EUR/MWh) 26Figure 6 Experience curves for o!shore and onshore LCOE as a function

of cumulative capacity installations 27Figure 7 Experience curves for o!shore and onshore LCOE over time (EUR/MWh) 27Figure 8 Actual and modelled UK project costs, 2010-20 (EUR/MW) 28Figure 9 Actual and modelled German project costs, 2010-20 (EUR/MW) 28Figure 10 Annual o!shore wind turbine installations by manufacturer, 2011-15 29Figure 11 Expected commercial launches for o!shore wind turbine models 30Figure 12 Annual o!shore wind foundation installations by type, 2010-20 32Figure 13 Estimated cost of foundations for 3MW turbines by water depth, 2011

(EUR/unit & metres) 32Figure 14 Estimated cost of foundations for 5MW+ turbines by water depth, 2011

(EUR/unit & metres) 32Figure 15 Estimated number of operating TIVs by crane capacity, 2010-13 33Figure 16 European high voltage export cable supply/demand balance by year

of cable manufacture, 2010-15 (km) 34Figure 17 Annual European high voltage export cable installations by manufacturer,

2011-14 35Figure 18 UK project change in LCOE due to change in capital structure

and risk profile, 2012-20 36Figure 19 Total cost of debt for euro area onshore wind project 37Figure 20 Project water depth and distance from shore by project status, 1991-2015 38Figure 21 EU o!shore wind installations, 2010-20 (MW) 40Figure 22 Annual o!shore wind installations by country, 2010-20,

BNEF/Rabobank Central scenario (MW) 41Figure 23 Central scenario total o!shore wind investment by country, 2012-20 46Figure 24 Entry and exit timings for equity investors with target risk adjusted returns (%) 47Figure 25 Project finance capital structures and loan guarantee coverage 2006-2011 51Figure 26 Annual investment in o!shore wind by year of commissioning and investor type,

2012-15 by existing commitments and 2016-2020 forecast 53

Table of Tables

Table 1 Role of o!shore wind in the EU according to the NREAPs 16Table 2 O!shore wind RO remuneration to 2017 (GBP/MWh) 18Table 3 Details of extension period 19Table 4 SDE premium for 600MW Bard Nederland (EUR/MWh) 21Table 5 Belgian o!shore wind subsidy based on GCs (EUR/MWh) 22Table 6 French tender tari!s (EUR/MWh) 23Table 7 Notable foundation manufacturers 31Table 8 TIV owners and operators 34Table 9 2020 forecast scenarios 41Table 10 Danish tender results 42Table 11 Policy risks in North Sea countries for BNEF/Rabobank Central scenario 43Table 12 Equity investor profiles 49Table 13 Debt investor profiles 50Table 14 Potential capital structures of o!shore wind farms 51Table 15 Project turbine prices by manufacturer and turbine, 2018 56Table 16 Foundation costs by type, 2018 (EURm per unit) 56Table 17 High voltage cable costs, 2018 57Table 18 TIVs under construction with estimated delivery date 57

Foreword

Foto: Ballast Nedam

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The rationale for fuelling the future with renewable energy has never

been greater. Only this month the Executive Director of the Interna-‐

tional Energy Agency called for drastic policy moves in energy genera-‐

high-‐carbon energy system . The IEA projects that demand for energy

will grow by a third between 2010 and 2035, with coal use rising by

65%. The world will increasingly come to rely on a small number of

Middle Eastern and North African countries, which are forecast to sup-‐

ply 90% of the required output growth. The IEA considers that we are

on track for unprecedented climate change of between 3.5°C to 6°C,

depending on whether more stringent policies will be introduced.

Although their consumption is at a much higher volume, global subsi-‐

dies for fossil fuels are still estimated at over six times those for renew-‐

ably energy.

Europe has been at the forefront of the transition to renewable energy

sources. Now the market has expanded in the US and China, and suc-‐

cess has followed scale: onshore wind power, for instance, has reached

grid parity in a number of markets, and even in cloudy Holland, a num-‐

ber of research institutes this month calculated photovoltaics

are cheaper than conventional electricity.

Offshore wind energy has a big part to play in the transition towards a

more sustainable future: with a growth rate in new installed cumula-‐

tive capacity of 32% targeted between 2010 and 2020 under the imple-‐

mentation plans of the EU’s 20-‐20-‐20 Directive, offshore wind has one

F O R E W O R D

1 http://www.iea.org/press/pressdetail.asp?PRESS_REL_ID=426

2 Amongst which KEMA and ECN, http://www.kema.com/nl/news/pressroom/press-‐releases/2011/Particuliere_zonnestroom_in_Nederland_kan_in_2020_ verveertigvoudigen.aspx

of the highest renewable energy growth rates. However, as a young

technology, it is still relatively more expensive than most other alter-‐

natives on a per MWh basis. The offshore wind industry recognises

the need to lower costs, and thereby subsidies, over time to secure a

sustainable future for offshore wind. The industry believes that with

-‐

tions should be possible, just as have been achieved in other technolo-‐

gies. Rabobank subscribes to this opinion. Europe is leading: virtually

all offshore wind farms so far have been built here. In the Netherlands,

a strong local industry has also grown on the back of the traditional

North Sea oil and gas exploration and dredging expertise. This could

become an even bigger market in line with the current capacity instal-‐

lation forecasts.

Rabobank is keen to work closely together with all relevant stakehold-‐

ers, corporates, institutional investors and governmental agencies to

create a long term viable offshore wind sector.

Bloomberg New Energy Finance provides insight, analysis, news and

data into all clean energy markets including offshore wind.

Sipko SchatMember of the Executive Board Rabobank Group

7

of the highest renewable energy growth rates. However, as a young

technology, it is still relatively more expensive than most other alter-‐

natives on a per MWh basis. The offshore wind industry recognises

the need to lower costs, and thereby subsidies, over time to secure a

sustainable future for offshore wind. The industry believes that with

-‐

tions should be possible, just as have been achieved in other technolo-‐

gies. Rabobank subscribes to this opinion. Europe is leading: virtually

all offshore wind farms so far have been built here. In the Netherlands,

a strong local industry has also grown on the back of the traditional

North Sea oil and gas exploration and dredging expertise. This could

become an even bigger market in line with the current capacity instal-‐

lation forecasts.

Rabobank is keen to work closely together with all relevant stakehold-‐

ers, corporates, institutional investors and governmental agencies to

create a long term viable offshore wind sector.

Bloomberg New Energy Finance provides insight, analysis, news and

data into all clean energy markets including offshore wind.

Sipko SchatMember of the Executive Board Rabobank Group

Michael LiebreichCEO Bloomberg New Energy Finance


8

Section 1Executive summary

Foto: Ballast Nedam

9


10 S E C T I O N 1 E X E C U T I V E S U M M A R Y

17 European Union (EU) countries plan to build 46.4GW of offshore wind by 2020. Bloomberg New Energy Finance and Rabobank understand that the magnitude of this build out plan and the current economic uncertainty in Europe means that there are a wide range of opinions as to whether and how the industry will manage to achieve these goals. This report, launched at the European Wind Energy Association Offshore Wind Conference in Amsterdam, November 2011, provides a roadmap for the industry and investors – what supply chain players need to do, how much capital will be required, from whom and at what rates of return; and whether the political and regulatory situation in place enables the innovation and dynamism of private enterprise to deliver the cost reductions and investment volumes required by society. In our Central scenario we project offshore wind’s levelised cost of energy (LCOE) will fall by 20-‐30% in real terms and that as a result 35.5GW offshore wind will be built by 2020. This entails a compound annual growth rate (CAGR) of 22.4% in 2011-‐20 and EUR 127bn invest-‐ment. If cost reductions in offshore wind follow a similar path to onshore wind with a 26 year lag, its LCOE will be approximately EUR 112/MWh by 2020, EUR 65/MWh by 2030 and less than EUR 50/MWh by 2040. We have been slightly more conservative and expect offshore wind costs to fall to EUR 128/MWh in 2020. The period of greatest cost reductions in the onshore experience cost curve occurred in 1991-‐96. This would transpose to 2017-‐22 for offshore wind – the period when we expect a high capacity installation rate due to UK Round 3 projects and

economies and improve energy security. One such goal is for 20% of energy consumption to come from renewable sources by 2020, putting them squarely at the core of the EU’s energy and climate strategy. In 2008 renewables accounted for just 10% of energy consumption across the EU-‐27, according to the European Commission. In January 2011, the European Commission (EC) said that the EU should be able to meet its renewables target, provided

46.4GW of offshore wind operating in 2020, which would constitute 9.6% of renewable energy capacity and meet 4.1% of the EU’s gross electricity generation. This would entail new installations of 43.4GW of capacity between 2011 and end-‐2020.

Germany – and three secondary markets – the Netherlands, Belgium and Denmark. Each has tariff systems for offshore wind and varying degrees of political support behind the long-‐term growth of the industry. Political support levels and returns available to investors in the major markets are adequate to strong, with slightly higher political risk in the UK than Germany offset by higher returns. In other markets, political risk varies considerably from high in Netherlands to low in Denmark – where high will result in lower volumes of construction.

installations to 2020: the UK and Germany. Cost changes are likely to include step changes

project locations. In the UK we expect the LCOE to fall 22% from EUR 165 to EUR 128/MWh between 2011 and 2020 driven by a doubling in size of the turbines (3.6MW to

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7MW), the mass production of standardised jacket foundations suitable for 45m water

and maintenance. On a per MW basis we expect capital costs to drop 3% from 2012-‐20. In Germany we expect the LCOE to fall 25% from EUR 179-‐133/MWh by 2020 and capital costs to decrease by 17% from EUR 4.3m/MW to EUR 3.5m/MW. Although our calculations indicate a lower learning curve for offshore wind than for onshore wind, it is possible that costs may reduce more – or less – quickly than we foresee today.

economics, supply chain availability and political risk. In our Central scenario government support for offshore wind remains stable and there is no reduction in tariff levels. In this environment we project offshore wind installations to grow at a compound annual growth rate (CAGR) of 22.4% in 2011-‐20 and EU countries to commission 35.5GW of offshore wind by 2020, generating 115.6TWh of electricity, contributing 3.2% of the EU’s gross electricity demand and reaching 77% of the announced NREAP offshore wind generation targets. We believe the NREAP targets are ambitious

wind and associated grid connections is required to build capacity between 2012 and 2020. This ranges from EUR 114bn in our Low scenario to EUR 152bn in our High scenario.

producers, private equity, project developers, turbine manufacturers, and institutional investors), a growing number of commercial banks as debt providers and three to four

wind assets through existing and new deal structures. The primary investors will continue

opportunity without spending beyond their means, they will need to bring on additional investors. Based on recent investment trends we expect two groups to be a key part of this: institutional investors and secondary utilities, which though not primary investors are keen to invest in offshore wind assets investing EUR 3.9bn and EUR 14.2bn each respectively.

From this analysis we expect LCOE to be reduced 20-‐30%, investment returns to be adequate for investment volumes to drive installations of 35.5GW by 2020 and establish offshore wind on a robust path to further industrialisation and roll out.

Notes:

returns.

12


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Section 2Support mechanisms& political risk

In 2007 all EU countries agreed to the 20-20-20 targets, which aim to decarbonise their economies and improve energy security. One such goal is for 20% of energy consumption to come from renewable sources by 2020, putting them squarely at the core of the EU’s energy and climate strategy. In 2008 renewables accounted for just 10% of energy consumption across the EU-27, according to the European Commission.


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Each EU country has developed a National Renewable Energy Action Plan (NREAP), indica-‐ting how they intend to reach their renewables target. Offshore wind is expected to reach an installed capacity of 46.4GW contributing 4.1% of gross electricity generation in 2020. In Janu-‐ary 2011, the European Commission (EC) said that the EU should meet its renewables target,

Offshore wind remains a new and comparatively costly form of electricity generation, making government support critical to attracting the investment necessary to meet NREAP targets. The

targets – rather than reductions in these commitments. In the Netherlands this cost focus has had a negative impact on support for offshore wind. In Germany, the UK and France the lure of job creation, the momentum of the industry and – in Germany’s case – public opposition to nuclear power have instead bolstered political support for offshore wind.

This section gives an overview of the legislative framework and underlying goals which sup-‐port the build-‐out of offshore wind in the EU and then examine the political risk, policy mecha-‐nisms, grid infrastructure and returns investors can expect across the six countries in which 88% of offshore wind installations in the EU are expected to be built in 2011-‐20.

2.1 EU policy

2.1.1 EU 20-20-20In January 2008 the EC proposed the Energy and Climate Package which set the legislative

least a 10% share of energy used for transport

Focusing on renewables, in June 2009, Directive 2009/28/EC on the Promotion of the Use of Energy from Renewable Sources came into force. This piece of legislation outlined the binding renewables targets for each member state, together with reporting requirements. Every coun-‐try must boost its share of renewables by 5.5% on 2005 levels, with the remaining increase calculated on the basis of per capita GDP. It may choose its own ‘mix’ of renewables in order to achieve its objective.The targets apply to three sectors – power, heating and cooling, and transport. To meet the overall 20% outcome therefore, there should be 20% renewable energy, 34% of gross electric-‐ity generation, 21.5% of heating and cooling, and 11% of transport.

2.1.2. National Renewable Energy Action Plans (NREAP)Directive 2009/28/EC required each member state to submit an NREAP, indicating how it intends to achieve its individual target by technology across the three relevant sectors. In this way, the European Commission can assess the country’s progress against its overall target and member states may adjust their choice of technologies according to their circumstances.The EC must approve all revisions to the initial NREAP submissions by 31 December 2011, at which point each country will commence bi-‐annual reports to update the EC on progress towards the 2020 targets.

S E C T I O N 2 S U P P O R T M E C H A N I S M S & P O L I T I C A L R I S K

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2.2 Role of o!shore wind according to NREAPs

Under the submitted NREAPs, the EU would have 46.4GW of offshore wind operating in 2020, which would constitute 9.6% of renewable energy capacity and meet 4.1% of the EU’s gross electricity generation. This entails new installations of 43.4GW of capacity between 2011 and end-‐2020 (Table 1).Offshore wind could, therefore, play an important role in meeting the EU’s 2020 renewable energy targets. However, it is a new and relatively costly form of electricity generation com-‐pared with alternatives, such as onshore wind and biomass. Furthermore its levelised cost of energy (LCOE) is approximately three times higher than the current baseload power price (Fig-ure 2). Therefore, government support remains critical to attract the investment necessary to industrialise the sector, lower its costs and implement the NREAPs. This should then enable the

LCOE

BNEF 2011 EU-ETS EUA Forecast

Central scenario

53.64

43.03

54.94

54.68

79.63

106.80

143.45

159.82

184.18

0 50 100 150 200 250

Electricity Prices

Natural Gas CCGT

Coal Fired

Wind - Onshore

Biomass - Incineration

Biomass - Anaerobic Digestion

PV - c-Si

Wind - O!shore

STEG - Tower & Heliostat

Figure 2: LCOE of o!shore wind and selected technologies (EUR/MWh)

2020

2010

0 100 200 300 400

Other

PV

O!shore wind

Biomass

Onshore wind

Hydropower 370

357

232

150

83

31

Figure 1: Electricity generation from renewable sources according to NREAPs, 2010 and 2020 (TWh)

Source: NREAPs, Bloomberg New Energy Finance, Bloomberg Notes: “Other” includes geothermal and solar thermal electricity generation (STEG).”Electricity prices” uses the average day ahead baseload spot prices in Germany, France and Belgium in the past year.


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Some countries – e.g. the UK and Germany – are actively supporting offshore wind with the expectation that their upfront investment to support the technology’s industrialisation will be

while we expect the LCOE to decrease over the decade (Section 3), some countries may defer

cost renewable alternatives until then. In early 2011, the Netherlands set the tariffs for its subsidy programme (SDE+) too low to be attractive for offshore wind, despite an aim of 5.2GW according to its the NREAP.

2.3 National policy

Offshore wind installations are dominated by two major markets – the UK and Germany – and four secondary markets – the Netherlands, Belgium, France and Denmark. Each has tariff sys-‐tems for offshore wind and varying degrees of political support behind the long-‐term growth of the industry. Political support and returns available to investors in the major markets are adequate to strong, with slightly higher political risk in the UK than Germany offset by higher potential returns. In other markets political risk varies considerably from high in the Nether-‐lands to low in a mature market such as Denmark.

2010 2020 NREAP

Capacity 2010YE (MW)

% of RE capacity

% of RE generation

% of gross electricity

generationNREAP capacity

2020YE (MW)% of RE

capacity% of RE

generation


generationCapacity additions

2011-20 (MW)

UK 1,340 14.7 14.6 1.3 12,990 35.2 39.0 12.1 11,650

Denmark 869 18.8 20.0 6.8 1,339 19.8 25.8 13.4 470

Netherlands 247 6.5 7.5 0.7 5,178 36.3 38.3 14.2 4,931

Belgium 195 9.7 11.3 0.7 2,000 24.2 28.5 6.0 1,805

Germany 72 0.1 0.3 0.0 10,000 9.0 14.6 5.7 9,928

France 0 0.0 0.0 0.0 6,000 10.9 11.7 3.2 6,000

Others 219 0.2 0.1 0.0 8,870 3.5 3.8 1.3 8,651

Total (EU) 2,942 1.2 1.4 0.3 46,377 9.6 12.3 4.1 43,435

Source: Bloomberg New Energy Finance, National NREAPs, Eurostat. Notes: ‘Others’ refers to all other EU member states.

Table 1: Role of o!shore wind in the EU according to the NREAPs

S U P P O R T M E C H A N I S M S & P O L I T I C A L R I S KS E C T I O N 2

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2.3.1 United KingdomPolitical support, political risk: We consider political support in the UK to be adequate. The Conservative-‐Liberal Democrat coalition government has emphasised a desire to be “the green-‐est government ever” and there is widespread political consensus on the existing targets. The

2020s. (The CCC is an independent body set up under the Climate Change Act 2008 to advise the government on setting and meeting carbon budgets.)

To encourage new capacity installations to attain the EU 20-‐20-‐20 Directive at the same time as supporting renewable energy cost reductions, the government is planning to reform the electricity market. On 12 July 2011 the Department of Energy and Climate Change (DECC)

(EMR) and its legislative proposals. The reform package is to secure the transition to a low car-‐bon economy in a cost-‐effective manner. It calls for an increase in the existing 2020 NREAP tar-‐get for offshore wind from 13GW to 18GW, but concedes this aim is only achievable if the LCOE for offshore is reduced to GBP 100/MWh. The EMR announced multiple initiatives to tackle this challenge, including the creation of an industry-‐led task force to coordinate an action plan to aid this cost reduction. This 18GW proposal contradicts the advice of the CCC, which notes that if renewable energy targets can be met in other ways then the existing “offshore wind ambition should be moderated to reduce the costs of decarbonisation”.1 The government views the off-‐shore wind industry as an opportunity to attract investment and create jobs in manufacturing,

aging infrastructure.

The proposed reforms also include the overhaul of the Renewables Obligation (RO) Scheme

-‐

for offshore wind is not under threat.

The implied scale of investment will require the government to not just guarantee adequate

backing of port upgrades and funding the Green Investment Bank.

Policy mechanism: The FiT CfD mechanism would act as a two-‐way contract in which renew-‐able energy generators receive a premium on top of the baseload electricity price to reach a

developers must repay the difference. The strike price, payment period and structure have yet to be determined.

-‐quently, participants will remain eligible for ROCs for 20 years of operation under a ‘grandfa-‐thering’ regime’. Under the Banding Review (announced on 20 October 2011), projects fully permitted between 1 April 2010 and 31 March 2015 will receive two ROCs per MWh. Projects permitted in the 2015/16 and 2016/17 tax years will receive 1.9 ROCs per MWh and 1.8 ROCs per MWh respectively. Projects under the RO scheme are also exempt from paying the climate change levy (CCL), a GBP 4.7/MWh tax on energy delivered to non-‐domestic users that is

Some countries – e.g. the UK and Germany – are actively supporting offshore wind with the expectation that their upfront investment to support the technology’s industrialisation will be

while we expect the LCOE to decrease over the decade (Section 3), some countries may defer

cost renewable alternatives until then. In early 2011, the Netherlands set the tariffs for its subsidy programme (SDE+) too low to be attractive for offshore wind, despite an aim of 5.2GW according to its the NREAP.

2.3 National policy

Offshore wind installations are dominated by two major markets – the UK and Germany – and four secondary markets – the Netherlands, Belgium, France and Denmark. Each has tariff sys-‐tems for offshore wind and varying degrees of political support behind the long-‐term growth of the industry. Political support and returns available to investors in the major markets are adequate to strong, with slightly higher political risk in the UK than Germany offset by higher potential returns. In other markets political risk varies considerably from high in the Nether-‐lands to low in a mature market such as Denmark.

2010 2020 NREAP

Capacity 2010YE (MW)

% of RE capacity

% of RE generation


generationNREAP capacity

2020YE (MW)% of RE

capacity% of RE

generation


generationCapacity additions

2011-20 (MW)

UK 1,340 14.7 14.6 1.3 12,990 35.2 39.0 12.1 11,650

Denmark 869 18.8 20.0 6.8 1,339 19.8 25.8 13.4 470

Netherlands 247 6.5 7.5 0.7 5,178 36.3 38.3 14.2 4,931

Belgium 195 9.7 11.3 0.7 2,000 24.2 28.5 6.0 1,805

Germany 72 0.1 0.3 0.0 10,000 9.0 14.6 5.7 9,928

France 0 0.0 0.0 0.0 6,000 10.9 11.7 3.2 6,000

Others 219 0.2 0.1 0.0 8,870 3.5 3.8 1.3 8,651

Total (EU) 2,942 1.2 1.4 0.3 46,377 9.6 12.3 4.1 43,435

Source: Bloomberg New Energy Finance, National NREAPs, Eurostat. Notes: ‘Others’ refers to all other EU member states.

Table 1: Role of o!shore wind in the EU according to the NREAPs

1 Committee on Climate Change,: The Renewable Energy Review, May 2011 www.theccc.org.uk/reports/ renewable-‐energy-‐review


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The FiT CfD mechanism could provide a lower but predictable and stable revenue stream, offering certainty and transparency to potential investors by removing the price risk and in turn lowering the future cost of capital. However, some industry players have criticised the transition away from the ROC scheme as it was an established, well understood mechanism in which there was potential upside in ROC sales.

Grid:

under the Transitional Scheme – an initiative created before the EMR – whereby developers

winners of the offshore transmission operator tenders, which will own the transmission assets for 20 years. This method of constructing grid connections will evolve from the Transitional Scheme into the Enduring Scheme (also created before the EMR) whereby offshore transmis-‐

removing the burdens of time and cost from the developer.

2.3.2 GermanyPolitical support, political risk: We consider political support in Germany to be strong and risk to be low. Support for offshore wind has been reasonably stable under the chancellorship of Angela Merkel, a former environment minister who leads a coalition of the Christian Demo-‐cratic Union, Christian Social Union and Free Democratic Party. Furthermore, support for the main opposition, the Social Democratic Party and its traditional allies, the Greens, has risen to

coalition has historically supported offshore wind, having introduced the priority purchase obligation for grid connections whilst in power between 1998 and 2002. This obligation facili-‐tated a boom in renewable energy installations.

The rise of the opposition and the Fukushima incident led to a government review of the nuclear phase-‐out programme as well as renewable energy policies in summer 2011. This

renewable sources by 2050. The results of the review are being translated into law and will take effect from 1 January 2012. In conjunction, the German government is taking a proactive

amongst others, introducing a national grid regulator.

Min Max

ROC x2 45 53

Electricity 30 52

CCL 4.7 4.8

Total 124.7 162.8

Source: BloombergNotes: Average of monthly prices 1 Jan 2009 to present

Table 2: RO remuneration to 2017 (GBP/MWh)


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12 years Extension Remaining

Sprinter 20/MWh

Extension150/MWh

Initial130/MWh

Basic 35/MWh

Electricity priceforecast

Electricity price curve

Sprinter 40/MWh

Extension150/MWh

Initial150/MWh

Basic 35/MWh

Electricity priceforecast

Electricity price curve

8 years Extension Remaining

Figure 3: Classic EEG 2009 tari! (EUR/MWh)

Figure 4: Compression EEG 2012 tari! (EUR/MWh)

Source: Bloomberg New Energy Finance. Notes: Projects are likely to choose pool electricity prices (red dotted line) after the initial tari! expires as they are forecasted to be far greater than the basic tari! (EUR 35/MWh). The Bloomberg New Energy Finance electricity price forecast assumes continuous annual increase of 1.8% on current electricity prices.

Water depth Distance to shore

For every m the project is in water greater than 20m depth the initial tari! is extended by 1.7 months.

For every nautical mile (nm) the project is in further than 12nm from shore the initial tari! is extended by 0.5 months.

Source: BNEF

Table 3: Details of extension period

Policy mechanism: On 12 August 2011, the German cabinet passed legislation amending the Erneuerbare Energien Gesetz (EEG), updating the laws supporting the country’s plan to accel-‐erate the expansion of renewable energy. Offshore wind developers now may choose between two feed-‐in tariffs, the classic and compression models:

(Figure 3) resembles the current EEG 2009 tariff, whereby projects receive an initial tariff of EUR 130/MWh for 12 years. Projects commissioned before 1 Janu-‐ary 2016 are also eligible for an additional sprinter bonus of EUR 20/MWh. This initial level of support is continued through the eligible extension period depending on the project environment (Table 3). A basic tariff (EUR 35/MWh) is available for the remaining period – up to the 20th operating year – but instead, developers will likely choose to receive the grey electricity price which we expect will exceed the basic tariff due to increased costs of fossil


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prices to be EUR 79/MWh by 2020(Figure 4) is only available for projects commissioned before

1 January 2018. It awards an initial tariff (EUR 150/MWh) for eight years, plus the eligible extension period (Table 3) before resorting to the basic tariff. A sprinter bonus of

-‐der of the project lifetime.

Grid: The Infrastructure Planning Acceleration Act (2006) stipulates that the national trans-‐mission service operators (TSOs) are responsible for the design and cost of connecting German offshore wind farms – built before 31 December 2015 – to the grid. The associated costs are shared among the four regional TSOs.

2.3.3 DenmarkPolitical support, political risk: We consider political support in the Denmark to be strong and risk to be low. The government has previously planned for 1,339MW of offshore wind in its NREAP, which only requires 470MW to be built this decade. DONG’s 400MW Anholt project (to be commissioned in 2013) will cover 85% of this. Despite a modest NREAP target com-‐pared to the UK and Germany, in 2007 the government proposed plans to commission over 4.5GW of offshore wind by 2025. Had this got beyond the proposal stage this would have been

elected in September 2011, has not yet pushed forward any plans regarding offshore wind. His-‐torically, however it has strongly supported offshore wind projects, having contributed to the conclusion of the Anholt and Rødsand 2 agreements. Government support for renewable tech-‐nology research and development totalled DKK 1.0bn (EUR 134m) in 2010, with former Prime Minister Lars Løkke Rasmussen revealing, at the opening ceremony of Horns Rev 2 offshore wind farm, the government’s ambition to see Denmark become a ‘green growth laboratory’.

Furthermore, the former government was keen to distribute renewable power sources more evenly across the country in order to charge electric vehicles at the 20 proposed Battery Switch Stations and adhere to the EU’s binding target of 10% renewable energy in the transport sec-‐tor by 2020. Denmark is currently testing electric vehicle to grid technologies, in the hope of

greenhouse gas emissions. The Danish Energy Agency Energistyrelsen (ENS) has increased the number of permit applications by establishing clearer guidelines for ‘open-‐door’ submissions, whereby developers can propose their own site.

Policy mechanism: No direct policy mechanism for offshore wind exists in Denmark. Instead, developers compete for reverse auction tenders, managed by ENS, to receive construction permits and a 20-‐year power-‐purchase agreement (PPA). However, these PPAs are limited by

own site – with permission from ENS (mentioned above) – to receive a premium of DKK 100/MWh (EUR 13.5/MWh) for 20 years on top of the baseload electricity price rather than an auc-‐tioned PPA. No developer has exercised this option to date.

Grid:


21

2.3.4 NetherlandsPolitical support, political risk: We consider political support in the Netherlands to be poor and risk to be high. According to its NREAP, the Netherlands aims to commission 5,178MW of offshore wind by 2020 – 49% of its intended renewable energy installations this decade. How-‐ever since the appointment of a new coalition government comprising the Liberal Party and the Christian-‐Democrats in October 2010, these plans have been shelved. The Cabinet led by Prime Minister Mark Rutte has proposed price competition under the Promotion of Renewable Energy Scheme (Stimulering Duurzame Energieproductie + or SDE+ Scheme), whereby the

1.5bn. This favours onshore wind and biomass over offshore wind. This situation replicates the previous abandonment of a Dutch subsidy scheme – MEP programme in 2008 – which resulted in the current hiatus in offshore wind installations.

Policy mechanism: The Netherlands has previously awarded subsidies to renewable energy

budget, from which the project may draw a premium to supplement the baseload electricity price up to a base price – set each year by ECN (Energy Research Centre of the Netherlands) according the LCOE of that technology – for 15 years. The last tender, held in January 2010, awarded EUR 5.3bn to offshore wind projects – EUR 4.4bn to the 600MW Bard/Typhoon/HVC Nederland project and the remaining EUR 0.9bn is yet to be allocated implying a very modest room for growth. If a 42% capacity factor is applied to the Bard Nederland project, it will receive a premium of EUR 133/MWh over 15 years (Table 4). There is therefore no cur-‐rent access to government subsidies, excluding the 600MW BARD Nederland project (now owned by Typhoon and HVC), which is to receive EUR 4.4bn under the former SDE scheme. We therefore expect no further project developments this decade unless there is a change in government. Even if the prices in the tender were more attractive for offshore wind in an SDE+ scheme by a new government, eligible projects are highly unlikely to be commissioned until after 2020 due to the long lead times.

Min Max

Premium 133 133

Electricity 32 60

Total 165 193

Source: BNEF Notes: Monthly averages between 1 January 2010 and 31 December 2010, assuming a 42% capacity factor.

Table 4: SDE premium for 600MW Bard Nederland (EUR/MWh)

Grid: the TSO TenneT is responsible for grid connection, but the project developer must

2.3.5 BelgiumPolitical support, political risk: We consider political support in Belgium to be good but there is some risk primarily related to political instability. Belgium is aiming to commission 2GW of offshore wind by 2020 under its submitted NREAP target, a ten-‐fold increase from the current 195MW. However, the ongoing 2007-‐2011 political impasse – in which no government has formed in over a year – could undermine these targets as the political instability places uncertainty on the commitments made by previous governments to offshore wind. The posi-‐tion of the main parties – Wallonian majority Socialists and the Flemish Christian Democrats


22

– towards offshore wind remains unclear. The recent resignation of the caretaker government

risk.

Capacity EUR/MWh

Up to 216MW 107

Every extra MW 90

Electricity 49

Source: BNEF Notes: Monthly averages between 1 Jan 2009 and present

Table 5: Belgian o!shore wind subsidy (EUR/MWh)

Policy mechanism: Offshore wind operates under a federal scheme managed by the Commis-‐sion de Régulation de l’Electricité et du Gaz (CREG) – which awards permits for construction

107/MWh for projects up to 216MW, and EUR 90/MWh for capacity above 216MW (Table 5). There is no maximum GC price.

Grid:

connection, but the Belgian transmission operator, Elia, is obliged to absorb 33% of the costs – up to a cap of EUR 25m per project.

2.3.6 FrancePolitical support, political risk: We consider political support in France to be adequate. President Nicholas Sarkozy is aware that France has the second-‐largest offshore wind potential in the EU and is keen to see the growth of this sector. A boost in domestic employment is also a

6,000MW of offshore wind capacity by 2020 in two tender rounds. The leading opposition Socialist party – despite its former pro-‐nuclear stance – is seeking to phase out nuclear power and boost renewable energy generation within a Red-‐Green alliance should they win the next election in 2012. This dramatic turnaround in opinion is supported by all Socialist presidential candidates following the 2011 Fukushima nuclear incident. Renewable energy generation build-‐out is supported by the renewable energy law Grenelle 2, which sets a target of 23% of national energy use from renewable sources by 2020.

S E C T I O N 2 S U P P O R T M E C H A N I S M S & P O L I T I C A L R I S K

23

Policy mechanism:

on 11 January 2012, with submissions to the Commission de Régulation de l’Energie (CRE) being scored on three categories:

Priceranges in Table 6 – required to subsidise the project with no limits on load hours.Industrial component: use or creation of a domestic supply chain (through job creation), risk management and developer experience, industrial partnerships, ability of access capital etc.Existing activities and the environment: limiting the environmental impact of the project – eg, reducing the number of turbines by using larger models.

in the tender bid. The advent of the industrial and environmental components to the scoring scheme means that the tenders will not simply be awarded to the bid with the lowest PPA. Instead it will favour bids from consortia offering larger 5MW+ turbines and the creation of French manufacturing jobs.

Zone EUR/MWh

Le Treport 115-175

Fecamp 115-175

Courseulles-sur-Mer 115-175

Saint-Brieuc 140-200

Saint-Nazaire 140-200

Source: BNEF

Table 6: French tender tari!s (EUR/MWh)

24


25

Section 3Costs & equipment supply

Our cost analysis is focused on two markets which we expect to constitute 61% of installations to 2020: the UK and Germany. Cost changes are likely to be a consequence of step changes in technology, improved equipment supply, improved financing terms and a change in project locations. In the UK we expect the LCOE to fall 22% from EUR 165 to EUR 128/MWh between 2011 and 2020 driven by a doubling in size of the turbines (3.6MW to 7MW), the mass production of standardised jacket foundations suitable for 45m water depths and 5MW+ turbines, and significant improvements in installa-tion and operations and maintenance. On a per MW basis we expect capital costs to drop 3% from 2012-20 from EUR 3.8m/MW to EUR 3.7m/MW. In Germany we expect the LCOE to fall 25% from EUR 179-133/MWh by 2020 and capital costs to decrease by 17% from EUR 4.3m/MW to EUR 3.5m/MW.


26

The cost improvements between to 2020 for any project can be broken down into:A step change in turbine size, increased scale, standardisation and experience across

the value chain: the increase in standard turbine sizes from 3.6MW to 6-‐7MW could

capacity and resulting economies of scale in cabling and transformers as well as improved installation rates. Gains made elsewhere in the value chain could amount to EUR 20.11/MWh or 12.2% of current costs. In this study we applied a learning curve to each of the major components (see appendix).Improved equipment supply: -‐ity in all major areas of the physical supply chain. Combined with expected installation rates to 2020 we believe investment in the last three years has cut the danger of supply

informs our equipment cost estimates. the introduction of debt capital to UK projects will increase

post-‐tax equity returns and lower LCOE, but the increased risks due to leveraging the assets

the net LCOE reduction to be EUR 6.46/MWh (3.9%).Change in water depth and distance from shore: UK Round 3 sites are in deeper water and further offshore. Despite improved wind resources, these more challenging sites will incur cost increases across the value chain – causing a net increase in the LCOE by EUR 8.36/MWh (5.1%).

S E C T I O N 3

164.5

128.0

38.4

6.5 8.4

2012 LCOE

Experience & large turbines

Improved!nancing

Depth &distance

2020LCOE

-36.5

Figure 5: UK o!shore wind project LCOE in Central Scenario, 2012-20 (EUR/MWh)

Source: Bloomberg New Energy Finance Notes: ‘Experience & large turbines’ includes a step change in turbine size, increased scale, standardisation and experience across the value chain. ‘Improved "nancing’ will arise from the industry mitigating construction risks to reduce debt margins and leveraging assets to make interest tax deductible. ‘Depth & distance’ represents the increase in costs across the value chain due to the more challenging locations of future sites.

CO S T S & E Q U I P M E N T S U P P LY

>

27

3.1. Levelised cost of energy (LCOE)

The previous section explicates our projection that the LCOE for UK offshore wind projects may fall 22% from EUR 165 to EUR 128/MWh between 2011 and 2020 (Figure 5). Since 2009, the migration of projects further offshore with little competition in the supply chain has increased capex and LCOE. Therefore our forecast represents a reversal of this trend. The scale of installations expected over the next eight years and the size of contracts placed indicate that the offshore wind industry is now entering a phase of rapid industrialisation. Our projected cost reductions in 2012-‐20 translate to a learning rate of 8.8% (Figure 6) – meaning costs will reduce by 8.8% for every doubling of installed capacity. This is lower than the historical learn-‐ing rate of 13.7% for onshore wind – driven by the more limited room for learning in founda-‐tions, substations and export cables. Balance of plant still make up 60% of offshore wind costs compared to 25% in onshore wind.

When comparing offshore and onshore LCOE as functions of time, we see that offshore wind is approximately 26 years behind the onshore wind industry. Onshore wind experienced a fall in LCOE over 1986-‐94 from EUR 175/MWh to EUR112/MWh. If cost reductions in offshore wind follow a similar path to onshore wind with a 26 year lag, its LCOE will be approximately EUR 112/MWh by 2020, EUR 65/MWh by 2030 and less than EUR 50/MWh by 2040. The period of greatest cost reductions in the onshore experience cost curve occurred in 1991-‐96. This would transpose to 2017-‐22 for offshore wind – the period when we expect a high capacity installa-‐

seen. Although our calculations indicate a lower 8.8% learning curve for offshore wind than for onshore wind, it is possible that costs may reduce more – or less – quickly than we foresee today.

10

1.001984

19902000

20042011

2009 2012 2020

Industralisationphase

8,8%

13,7%

1.000

100 1.000 10.000 100.000 1.000.000

Onshore experience curveOnshore LCOE O!shore LCOE

10

100

150

200

50

250

1983 1987 1991 1995 1999 2003 2007 2011

20372033202920252021201720132009Log LCOE (EUR/MWh) Log cumulative capacity (MW) Bottom x-axis (Onshore wind) Top x-axis (O!shore wind)

Onshore LCOE O!shore LCOE

Source: Bloomberg New Energy Finance Notes: Onshore wind LCOE based on BNEF Wind Experience Curves. O!shore wind LCOE for 2011 and 2020 are EUR 165/MWh and EUR 128/MWh (Figure 5).

Figure 6: Experience curves for o!shore and onshore LCOE as a function of cumulative capacity installations

Figure 7: Experience curves for o!shore and onshore LCOE over time (EUR/MWh)


28 S E C T I O N 3 CO S T S & E Q U I P M E N T S U P P LY

3.2. Capital cost projections

Declared capital costs for UK projects to be commissioned in 2011 currently stand at around GBP 3.3m/MW (EUR 3.8m/MW) (Figure 8). We expect these to increase to GBP 3.5m/MW (EUR 4.0m/MW) in the next three years as projects are located in deeper waters and further offshore. The introduction of turbine models in 2015-‐16 will bring a step change in costs and, coupled with learning rates in other areas of the supply chain, should bring costs back down to EUR 3.7m/MW by 2020 (Figure 8). The story is more extreme in Germany as capex is expected to fall by 17% in 2012-‐20 – since its projects will not incur further capex increases with instal-‐lations migrating further offshore (Figure 9).

3.0

3.8 3.6 4.0 4.0 3.9 3.8 3.8 3.7 3.7

2010 2012 2014 2016 2018 2020

4.2 4.3 4.4 4.33.7 3.7 3.6 3.6 3.5

2010 2012 2014 2016 2018 2020

Figure 8: Actual and modelled UK project costs, 2010-20 (EURm/MW)

Figure 9: Actual and modelled German project costs, 2010-20 (EURm/MW)

Source: Bloomberg New Energy Finance Notes: Capex for projects commissioned in 2010-15 (blue) are disclosed capex of "nanced and permitted projects in the short term demand forecast. Capex for projects commissioned in 2016-20 (orange) represent the outputs of our Cost Model, with the expected speci"cations for projects to be commissioned after 2015. The project modelled for Figure 8 is the expected typical project in the UK in 2020 ("nal project in Fig 5).Grid connection and transmission costs are included in UK project costs but excluded for Ger-many - "nanced separately by the four regional TSOs.

29

3.3 Supply chain

Underlying our project cost forecasts are individual cost forecasts for different elements of the project. Costs depend on technology and the supply and demand balance. We believe that sup-‐ply is improving across all segments of the value chain – in particular the potential for 36 new turbine models from 11 EU-‐located companies and 8 companies from outside the EU to come to market by 2017. We expect foundation demand to shift dramatically towards jacket designs after 2015 with multiple suppliers, some with extensive oil and gas experience available. Tur-‐bine installation vessels (TIVs) were once in short supply. However, in the last two years there has been extensive investment in new vessels by independent operators, turbine manufactur-‐ers and utilities, such that by 2013 50 TIVs should be operating – up from 29 in 2010. The sup-‐ply of high voltage export cables remains tight, since lead times on costly new extrusion lines

and competitive situation for each of these sections of the supply chain.

62% 64% 69%

41%

18%

22% 13%

16%

10%

6%

20%

11%

13%

16%

13%

6%

9%

21%

7%

5%

59%

2011 2012 2013 2014 2015

916

Market share (%) Annual installations (MW)

3,316 3,147 2,444 1,522

Non-contracted

Vestas

Areva Multibird

REpower

BARD

Siemens

Figure 10: Annual o!shore wind turbine installations by manufacturer, 2011-15

Source: Bloomberg New Energy Finance Notes: Market shares are based upon con"rmed contracts with projects in our short term demand forecast (see Section 4).

3.3.1 TurbinesWe do not expect the supply of turbines to be a bottleneck. Two turbine manufacturers – Sie-‐mens and Vestas – have dominated the offshore wind market since its inception. We expect

-‐petition should grow (Figure 10) as a number of major onshore wind turbine manufacturers (Alstom, Gamesa) is expected to start commercial production of new turbine models (Figure 11) or build on existing market share (AREVA). New entrants will compete with existing players for 1.9GW of so far non-‐contracted capacity (59% of expected installations) in 2015. While numerous manufacturers are aiming to penetrate this market, many are likely to fail

banks. Manufacturers are currently scouting ports to locate manufacturing facilities, to facili-‐tate transportation of turbines which will be double the size of existing onshore turbines.



Forthcoming next-‐generation offshore wind turbine models will feature larger nameplate

more reliable technology that requires less maintenance. A key differential between the emerg-‐ing models is drive train technology: namely direct drive (DD) vs. medium speed hybrid (MSH). It is still uncertain whether one technology will prevail and proponents of each design argue about their relative merits. MSH requires no substantial alterations to the design of a high-‐speed gearbox, only reducing the number of gears and thus, the frequency of failures in an already proven technology. By keeping a gearbox, the generator can be substantially smaller and require fewer permanent magnets and rare-‐earth element components, of which future supplies from China may be constrained. The main advantage of DD is the complete absence of a gearbox. This should eliminate the lengthy downtime associated with gearbox failures and reduce the top head mass of the nacelle, allowing for taller towers and access to stronger winds.

R&D - but not turbine specific

R&D - turbine specific

Commercial launch

2009 2010 2011 2012 2013 2014 2015 2016 2017

AMSC 10MWMitsubishi 6MW

Sway 10MWGamesa G14-X

Alstom 6MWVestas V164-7.0

Nordex N150Acciona 3MW

BARD 7+XSiemens 6MW

Gamesa G11X-5MWShanghai Electric 2MW

BARD 6.5Dongfang 5MW

GE 4MW-DDAreva Multibrid M6000

REpower 6MSiemens SWT-3.0-DD

XEMC Darwind 5MW-DDDongfang 2.5MWGoldwind 3.0MWGoldwind 2.5MW

REpower 6MShanghai Electric 3.6MW

Sinovel 5MWVestas V112-3.0 MW

BARD 5Sinovel 3MW

Areva Multibrid M5000Nordex N90 2500

REpower 5MSiemens SWT-2.3-93

Siemens SWT-3.6-107Vestas V90-3.0MW

Winwind WWD-3

Figure 11: Expected commercial launches for o!shore wind turbine models

Source: Bloomberg New Energy Finance, companies

The move to larger turbine models should improve project economics. While 5MW+ turbines will be more expensive per unit than current models, installation and maintenance costs will be lower: the reduced number of units will lower overall capex per MW (fewer foundations and array cables); taller towers will gain access to stronger winds; and improved production

prices and spur technological innovation in design and reliability – which manufacturers claim

31

Forthcoming next-‐generation offshore wind turbine models will feature larger nameplate

more reliable technology that requires less maintenance. A key differential between the emerg-‐ing models is drive train technology: namely direct drive (DD) vs. medium speed hybrid (MSH). It is still uncertain whether one technology will prevail and proponents of each design argue about their relative merits. MSH requires no substantial alterations to the design of a high-‐speed gearbox, only reducing the number of gears and thus, the frequency of failures in an already proven technology. By keeping a gearbox, the generator can be substantially smaller and require fewer permanent magnets and rare-‐earth element components, of which future supplies from China may be constrained. The main advantage of DD is the complete absence of a gearbox. This should eliminate the lengthy downtime associated with gearbox failures and reduce the top head mass of the nacelle, allowing for taller towers and access to stronger winds.

R&D - but not turbine specific

R&D - turbine specific

Commercial launch

2009 2010 2011 2012 2013 2014 2015 2016 2017

AMSC 10MWMitsubishi 6MW

Sway 10MWGamesa G14-X

Alstom 6MWVestas V164-7.0

Nordex N150Acciona 3MW

BARD 7+XSiemens 6MW

Gamesa G11X-5MWShanghai Electric 2MW

BARD 6.5Dongfang 5MW

GE 4MW-DDAreva Multibrid M6000

REpower 6MSiemens SWT-3.0-DD

XEMC Darwind 5MW-DDDongfang 2.5MWGoldwind 3.0MWGoldwind 2.5MW

REpower 6MShanghai Electric 3.6MW

Sinovel 5MWVestas V112-3.0 MW

BARD 5Sinovel 3MW

Areva Multibrid M5000Nordex N90 2500

REpower 5MSiemens SWT-2.3-93

Siemens SWT-3.6-107Vestas V90-3.0MW

Winwind WWD-3

Figure 11: Expected commercial launches for o!shore wind turbine models

Source: Bloomberg New Energy Finance, companies

The move to larger turbine models should improve project economics. While 5MW+ turbines will be more expensive per unit than current models, installation and maintenance costs will be lower: the reduced number of units will lower overall capex per MW (fewer foundations and array cables); taller towers will gain access to stronger winds; and improved production

prices and spur technological innovation in design and reliability – which manufacturers claim

The speed of the transition to new turbines will be limited by operating experience but this can – and is – being partly offset by guarantees from the manufacturers. Auxiliary technology required to support larger turbines such as installation vessels (3.3.3) and foundations (3.3.2)

support this in the last three years and banks will require guarantees from the turbine manu-‐

Currently the market is dominated by European suppliers but US and Asian manufacturers are also preparing for market entry, which will further increase competition in the short to medium term. To win sales, new suppliers could:

3.3.2 FoundationsBased on our Central scenario (see Section 4) we expect foundation requirements to increase to over 1,000 units per year by 2020 (Figure 12). While the market today is served by relatively few players, the short lead times required to ramp up supply makes undersupply less likely. Suppliers are mainly construction and steel manufacturing conglomerates with coastal manu-‐facturing yards able to serve multiple industries. As such, they will be able to increase supply within 1-‐2 years to meet demand spikes. There are, however, concerns that suppliers and con-‐

of over EUR 100m. This may require larger projects to split foundation contracts between two or more players.

We expect monopiles to be partly replaced by jacket structures between 2015 and 2020 as they are more cost effective for 5MW+ turbines in deeper waters. Monopiles are likely to dominate through 2014 as projects are mostly limited to water less than 35m deep with turbines less than 5MW. However, based on known project examples and steel prices, we estimate if heavier (5MW+) turbines are deployed, the cost of a monopile in 25m of water increases from EUR 2.7m to EUR 4.0m (Figure 13 and Figure 14). We estimate the cost for jacket structures would go from EUR 2.7m to EUR 3.1m. In the long term, we expect lower learning rates and cost reductions than other parts of the value chain since there are fewer technological and process improvements to be found. Foundation costs are highly sensitive to steel prices. In this esti-‐mate we assume EUR 400/metric ton.Jackets will initially suffer from slower installation times as more deck space is required on

Column

Monopile SIF/SmuldersBladt/EEW

Aarsle! BilfingerTAG

Jacket Burntisland Fabrications

SIF/SmuldersTata Steel

Tripods BARD

Tripiles Cuxhaven Steel

Source: BNEF

Table 7: Notable foundation manufacturers



installation vessels. But this should be more than compensated for by lower unit costs. A resur-‐gence of demand for monopiles is expected in 2017 due to installations in new markets where shallow water sites have not yet been developed, e.g. France.

We believe concrete (gravity) foundations will struggle to gain market share due to a lack of cost-‐effective designs for deep water and a more labour-‐intensive manufacturing process. Floating turbines such as the Siemens/Statoil Hywind project – capable of operating in waters 400m deep – are still in the experimental stage, but we expect them to be used for deeper water sites and onsite power generation to isolated oil and gas platforms not included in this forecast.

Tripod

Jacket

Gravity

Monopile

73%85%

72%

95% 92%

59%

36%43%

35% 32% 31%

25%

2%

5%

7%4% 4%

15%

10%

5% 8%

34%

54%46%

52%58% 59%

2%18%

7% 8% 6% 6% 6% 6%

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

428 195 249 667 816 729 689 796 917 1,063 1,178

Market share (%) Annual installations (units)

Figure 12: Annual o!shore wind foundation installations by type, 2010-20

Source: Bloomberg New Energy Finance

Figure 13: Estimated cost of foundations for 3MW turbines by water depth, 2011 (EUR/unit & metres)


Figure 14: Estimated cost of foundations for 5MW+ turbines by water depth, 2011 (EUR/unit & metres)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

5 25 45

Tripod

Jacket

Gravity

Monopile

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

5 25 45

Tripod

Jacket

Gravity

Monopile

33

3.3.3. Installation vesselsBy end-‐2010, 29 turbine installation vessels (TIV) were available to install turbines and/or foundations. Based on our analysis of vessels in the pipeline we expect a further 21 vessels to be operational by end-‐2013 (Figure 15). All of the new vessels will be jack-‐ups with crane lift-‐ing capacities of over 500 tonnes – the required strength to install 5MW+ turbines. Two years ago vessel supply was earmarked as a potential bottleneck to the industry, but this strong pipe-‐line demonstrates that investors have reacted quickly to the anticipated undersupply. This has been facilitated by a reduction in lead times from 36 to 24 months. As next-‐generation turbines become operational in 2014, many of the 18 vessels with crane lifting capacities of less than

existing projects.

There are 24 vessel owners in the TIV market, offering heightened competition in terms of day rate charges and vessel designs. From the pipeline of vessels:

these will use conventional ship hulls (GustoMSC design) rather than barge hulls.

demand for turbine installations weakens.

vessels need to be able to operate in water depths of over 40m, but recent vessel orders have substantially raised this level: Inwind (65m), Seafox (70m) and Swire Blue Ocean (75m). Cranes will be able to lift over 500t, allowing them to install 5M+ turbines and deep water foundations.

2011, can transport four 6MW turbines at one time. In February Gaoh placed an order with South Korea’s STX to build the Deepwater Installer, a Goliath in comparison, which will be able to transport 16 3.6MW turbines with the aid of under-‐deck storage and incorporat-‐

extreme project locations.

opted for six, and Inwind has chosen three.

> 1000 tonnes

500 - 1000 tonnes

< 500 tonnes

18 18 18 18

49

1519

7

8

1213

2010 2011 2012 2013

29

50

45

35

Figure 15: Estimated number of operating TIVs by crane capacity, 2010-13


installation vessels. But this should be more than compensated for by lower unit costs. A resur-‐gence of demand for monopiles is expected in 2017 due to installations in new markets where shallow water sites have not yet been developed, e.g. France.

We believe concrete (gravity) foundations will struggle to gain market share due to a lack of cost-‐effective designs for deep water and a more labour-‐intensive manufacturing process. Floating turbines such as the Siemens/Statoil Hywind project – capable of operating in waters 400m deep – are still in the experimental stage, but we expect them to be used for deeper water sites and onsite power generation to isolated oil and gas platforms not included in this forecast.

Tripod

Jacket

Gravity

Monopile

73%85%

72%

95% 92%

59%

36%43%

35% 32% 31%

25%

2%

5%

7%4% 4%

15%

10%

5% 8%

34%

54%46%

52%58% 59%

2%18%

7% 8% 6% 6% 6% 6%

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

428 195 249 667 816 729 689 796 917 1,063 1,178

Market share (%) Annual installations (units)

Figure 12: Annual o!shore wind foundation installations by type, 2010-20




A2SEA GeoSea Master Marine Smit Marine Projects

Ballast Nedam Gulf Marine Services RWE Stemat

BARD Engineering Inwind Scaldis Swire Blue Ocean

Beluga Hochtief Jack-Up Barge Seacore Van OordOord

Fred Olsen Windcarrier Jumbo SeaJacks Vroon BV / MPI

GAOH KS Energy Services Seaway Heavy Lifting Workfox BV


Table 8: TIV owners and operators

3.3.4 High voltage export cables

The supply of high voltage export cables to the offshore wind industry is likely to be the tight-‐

Over 4,000km of export cables are required to build out our short-‐term demand forecast for offshore wind projects in 2011-‐14, with cable requirements increasing each year to connect more projects increasingly further from shore. A spike in demand in 2012 is due to the German HVDC clusters BorWin2 and DolWin1. No other cable demand is known for 2012.

Demand - O!shore wind

Demand - Other

Supply

Supply - Extension

405 276

1,015

678

1,016

552

526

415

450

2010 2011 2012 2013 2014

957

1,466

1,093 1,015

802

Figure 16: European high voltage export cable supply/demand balance by year of cable manufacture, 2010-15 (km)

Source: Bloomberg New Energy Finance. Notes: Cable demand has been compiled using commissioning dates from disclosed contracts, and delivery date estimates from our short term demand forecast. Forecast includes demand from o!shore wind projects and ‘other’ – known transnational HVDC contracts for cross border interconnections in north Europe.

Three established players – ABB, Prysmian and Nexans – have dominated the offshore cable market. At current capacity this trio can produce 800km of high voltage cables per year, but this may rise to 1,400km per year with incremental new investment by installing new extru-‐

35

sion lines at existing plants (represented by the dashed supply line in Figure 16) and further -‐ to 1,700km per year -‐ with new entrants.New entrants include NKT, NSW (a subsidiary of General Cable) and JDR Cables, which will

-‐cient to match the increasing demand. If this is not addressed in advance then prices are likely

capital costs (EUR 100-‐200m) and lead times (3-‐4 years) of a new production facility.Installations to date have used less expensive HVAC cables, but future demand will migrate towards HVDC technology as projects move further from shore. HVAC cables will meet the demand outside of Germany up to 2015 as installations remain closer than 60km to shore. HVDC cables will take a larger share of the market from 2013 as transmission tenders for the six German offshore wind clusters – all closed in the past year – are commissioned. Other mar-‐kets, including the UK Round 3 and French tenders, can use HVAC but we expect that they too will increasingly use HVDC technology where it proves economical. HVDC technology reduces transmission losses over great distances because it can carry higher voltages (500kV) than HVAC (300kv). Manufacturers are working to increase the voltage of cross-‐linked polyethylene (XLPE) HVAC cables to extend their economical range against HVDC cables, potentially reduc-‐ing costs for future projects

Non - contracted

Prysmian

NKT

ABB

Nexans

60%

22%

19%

20%

3%18%

22%

20%

14%

11%

32%

53%

14%

6%

30%

57%

2011 2012 2013 2014

1,015 1,093 802 1,466

Market share (%) Cable demand (km)

Figure 17: Annual European high voltage export cable installations by manufacturer, 2011-14

Source: Bloomberg New Energy Finance, companies.

Current prices for HVAC export cables – including supply and installation – are around EUR 0.4m/km, but the majority of contracts, range from EUR 0.5m/km to EUR 0.75m/km. This translates to 6-‐9% of total capex for a 300MW project. HVDC is more expensive than HVAC, as demonstrated by Prysmian’s share of its contracts with Siemens for the BorWin 2, HelWin 1 and SylWin 1 tenders ranging from EUR 1.0m/km to EUR 1.4m/km. We expect the cost of connecting offshore projects to the grid to increase slightly over the next few years.

A2SEA GeoSea Master Marine Smit Marine Projects

Ballast Nedam Gulf Marine Services RWE Stemat

BARD Engineering Inwind Scaldis Swire Blue Ocean

Beluga Hochtief Jack-Up Barge Seacore Van OordOord

Fred Olsen Windcarrier Jumbo SeaJacks Vroon BV / MPI

GAOH KS Energy Services Seaway Heavy Lifting Workfox BV


Table 8: TIV owners and operators

3.3.4 High voltage export cables

The supply of high voltage export cables to the offshore wind industry is likely to be the tight-‐

Over 4,000km of export cables are required to build out our short-‐term demand forecast for offshore wind projects in 2011-‐14, with cable requirements increasing each year to connect more projects increasingly further from shore. A spike in demand in 2012 is due to the German HVDC clusters BorWin2 and DolWin1. No other cable demand is known for 2012.

Demand - O!shore wind

Demand - Other

Supply

Supply - Extension

405 276

1,015

678

1,016

552

526

415

450

2010 2011 2012 2013 2014

957

1,466

1,093 1,015

802

Figure 16: European high voltage export cable supply/demand balance by year of cable manufacture, 2010-15 (km)

Source: Bloomberg New Energy Finance. Notes: Cable demand has been compiled using commissioning dates from disclosed contracts, and delivery date estimates from our short term demand forecast. Forecast includes demand from o!shore wind projects and ‘other’ – known transnational HVDC contracts for cross border interconnections in north Europe.

Three established players – ABB, Prysmian and Nexans – have dominated the offshore cable market. At current capacity this trio can produce 800km of high voltage cables per year, but this may rise to 1,400km per year with incremental new investment by installing new extru-‐


36

3.4 Improved "nancing terms

The introduction of debt capital to UK projects will increase post-‐tax equity returns and lower

equity costs in the form of contingency requirements or higher internal hurdle rates. Lever-‐

a longer track record and better construction and operational management should improve

margins 225-‐250bps just before the onset of the eurozone sovereign debt crisis (July 2011), but decreased liquidity has increased current prices to above 300bps (+50bps). While project spreads have increased, it is imperative to put them into perspective with the total cost of debt – which has actually decreased as term swaps have fallen since April 2011 (Figure 19).

solving the eurozone sovereign debt crisis.

Balance sheet LCOE 2012

Introduction of debt capital

Improved tax shield

Lower risk profile of projects

Increased risk due to leverage

Leveraged LCOE 2020

(EUR/MWh)

126.1 119.6

9.8

3.6 2.9

9.8 -6.5

Figure 18: UK project change in LCOE due to change in capital structure and risk pro"le 2012-20


S E C T I O N 3 CO S T S & E Q U I P M E N T S U P P LY

37

0%

1%

2%

3%

4%

5%

6%

7%

Jan 05 Jan 06 Jan 07 Jan 08 Jan 09 Jan 10 Jan 11

Project Spread

Credit Insurance

Term Swap

6M Euribor

ECB Rate

40-100bpsO!shore wind additional project spread

Figure 19:Total cost of debt for euro area onshore wind project

Source: Bloomberg, Bloomberg New Energy Finance estimates. Notes: O!shore wind assets will typically see project spreads 40-100bps above onshore wind projects.

3.5 Change in project environment

methods which may include onsite accommodation.-‐

mission losses.

time as prolonging more trips will be required by installation vessels transporting fewer turbines.

Despite improved wind resources at these sites, the net change to the LCOE is an increase of EUR 8.4/MWh (5.1%).


38

Announced

Permitted

Financed

Commissioned

0

10

20

30

40

50

60

0 50 100

500 MW

100 MW

Water depth (m) (y-axis) Distance to shore (km) (x-axis)

Figure 20: Project water depth and distance from shore by project status, 1991-2015

Source: Bloomberg New Energy Finance Note: bubble size represents capacity of project, see key on right.

S E C T I O N 3 CO S T S & E Q U I P M E N T S U P P LY

39

Section 4Market size projections

Our market size projections to 2020 combine the research on costs, tari!s, project economics, supply chain availability and political risk. In our Central scenario government support for o!shore wind remains stable and there is no reduction in tari! levels. In this environment we project o!shore wind installations to grow at a compound annual growth rate (CAGR) of 22.4% in 2011-20 and EU countries to commission 35.5GW of o!shore wind by 2020, generating 115.6TWh of electricity, contributing 3.2% of the EU’s gross electricity demand and reaching 77% of the announced NREAP o!shore wind generation targets.


40

4.1 Scenarios

Our forecasts are constructed by combining distinct short (2011-‐15) and long-‐term (2016-‐20) forecasts (see Appendix B). The former is bottom-‐up, driven from the known project pipeline

driven from a calculation of the probability of each country achieving its NREAP target. The probability is primarily driven by the returns with the current policy, our assessment of politi-‐cal support in each market (Section 2.3) and the associated risk of downgrade of the tariff.

In our Central scenario government support for offshore wind remains stable and there is no reduction in tariff levels. In this environment we project offshore wind installations to grow at a CAGR of 22.4% 2011-‐20 and EU countries to commission 35.5GW of offshore wind by 2020.

ongoing need to reduce sovereign debt and electricity prices has a negative impact on political support for offshore wind. Policy adjustments by governments favour other renewable energy technologies, resulting in uncertainty in the offshore wind market that leads to greater inves-‐tor caution. As a result member states fail to achieve their NREAPs by 31% as only 32.2GW are installed by 2020.

In our High scenario, political support remains stable but risks decline more quickly due to greater investment, competition and increased cross company partnerships. This results in higher investment levels, enabling 42.0GW of capacity by 2020.

4.2 Markets

The BNEF/Rabobank Central scenario (Figure 22) expects a strong 38% CAGR in 2011-‐15 as German developers race to complete projects in time to qualify for the sprinter bonus. Around 2016 the market is likely to stabilise at 3-‐3.5GW per year as the culmination of rapid German growth could coincide with a lull of activity in the UK between the end of Rounds 1 and 2 and

S E C T I O N 4

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

BNEF/Rabobank High

BNEF/Rabobank Central

BNEF/Rabobank Low

EWEA High

EWEA Mid

Figure 21: EU o!shore wind installations, 2010-20 (MW)

Source: Bloomberg New Energy Finance, Rabobank, EWEA (Pure Power: Wind energy targets for 2020 and 2030, EWEA, July 2011) Notes: BNEF/Rabobank scenarios all follow the BNEF short-term forecast until 2015.

M A R K E T S I Z E P R O J E C T I O N S

41

the beginning of Round 3. Growth is expected to surge towards the end of the decade (16.8% CAGR in 2016-‐20) as developers install projects in the UK (Round 3) and other European nations – namely France and Sweden. Annual installations by 2020 are likely to be in the order of 5-‐6GW compared with to 1GW today.

United Kingdom: We calculate that the RO scheme gives investors in Round 1 and 2 – with unleveraged project returns in the order of 10-‐15% – the highest returns in the EU. Currently, the scheme remunerates UK projects at GBP 163/MWh (Table 2), while the LCOE for current projects averages at GBP 141/MWh. Future returns will depend on the FiT strike price, which should take into account the future cost situation for Round 3 projects – a balance of location-‐driven cost increases and experience-‐ and scale-‐driven cost decreases.

Scenario2020 installed capacity (MW)

Average assumed capacity factor (%)

2020 annual electricity generation (TWh)

% of 2020 NREAPs generation target

% of 2020 EU gross electricity demand

NREAPs 46,387 37 149.8 n/a 4.13

BNEF/ Rabobank Low 32,170 35 99.5 66 2.74

BNEF/ Rabobank Central 35,506 37 115.6 77 3.19

BNEF/ Rabobank High 42,047 39 144.2 96 3.98

EWEA Mid 40,000 40 139.2 93 3.84

EWEA High 55,000 42 203.8 135 5.58

Source: BNEF, EWEA, NREAPs Notes: Percentage comparisons between scenarios are based on generation rather than capacity installations EU gross electricity demand in 2020 is estimated to be 3,625TWh.

Table 9: 2020 forecast scenarios

0

1,000

2,000

3,000

4,000

5,000

6,000

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

1,087

5,642

4,809

4,100

3,641

3,030 3,316 3,147

2,444

1,522

916

Rest of EU

Netherlands

Denmark

Belgium

France

Germany

UK

Figure 22: Annual o!shore wind installations by country, 2010-20, BNEF/Rabobank Central scenario (MW)

Source: Bloomberg New Energy Finance, Rabobank Notes: ‘Other includes the following countries: Spain, Ireland, Finland, Italy, Poland, Greece, Estonia, Sweden, Latvia, Lithuania, Malta, and Portugal.


42 M A R K E T S I Z E P R O J E C T I O N S

Germany: German projects are situated in more extreme environments than UK sites at present – demanding higher capex and giving a LCOE of EUR 175-‐180/MWh, translating to a return on equity (ROE) of 7-‐10%. The new EEG 2012 tariff may provide leveraged equity returns of 7-‐10%, an increase from previous returns of 5-‐7% under EEG 2009. While these

into deeper waters. As a result returns should improve and the positive outlook is bolstered by strong political support.

Denmark: The LCOE of Danish projects (currently around EUR 158/MWh) is one of the lowest in Europe – thanks to superior wind resources close to shore with an established domestic sup-‐ply chain – and strong political support for wind energy. However, PPAs under the current ten-‐dering scheme (EUR 141/MWh for Anholt) only provides equity returns in the order of 5-‐8% which are some of the lowest in Europe, reducing the attractiveness of the market to external investors. Due to the low targets set by the Danish NREAP and the importance of its domestic supply chain, we feel Denmark may exceed its target.

Belgium: The current GC scheme offers relatively stable revenues and predictable returns in

France: Based on cost assumptions and commissioning dates for the tendered sites the LCOE will be around EUR 163/MWh in 2015. If developers are not required to fund the grid con-‐nection the LCOE will be lower – EUR 143/MWh. These values fall within the range of eligible PPAs (Table 6), indicating that returns of 10% or higher are possible. However, the scheme has attracted a wealth of interest already, and the resulting high level of competition between development consortia could lower the submitted PPA bids – potentially limiting equity returns to less than 10%. This effect will be compounded for bids that do not create a local sup-‐ply chain.

Project Capacity (MW) Year PPA DKK& (EUR)/MWh Limit

Horns Rev 2 209 2009 518 (69.6) 50,000 load hrs

Rodsand 2 207 2009 629 (84.5) 50,000 load hrs

Anholt 400 2013 1,051(141.1) 20,000 GWh

Source: Bloomberg New Energy Finance Notes: DKK-EUR FX rate 0.1343.

Table 10: Danish tender results

S E C T I O N 4

43

4.3 Forecast in context

Our long-‐term forecasts are more conservative than those of the European Wind Energy Asso-‐ciation (EWEA). EWEA’s Mid scenario estimates the EU will commission 40GW of offshore wind capacity by 2020 – 13% more capacity than the BNEF/Rabobank Central scenario of 35.5GW. In terms of generation, EWEA assumes this 40GW will generate 139.2TWh (40% capacity factor) – 20% greater than the BNEF/Rabobank Central scenario of 115.6TWh. The EWEA Mid scenario foresees the EU achieving 93% of its NREAP generation targets and meet-‐ing 3.84% of gross EU electricity generation.

2020 LCOE (EUR/MWh)

Current Project

IRR

Policy in place?

(max 2)Project IRR

(max 4)Political support

(max 4)Total

(max 10)

Required installation 2016-20 to

meet NREAP target (MW)

Probability of meeting

required 2016-20 rate

Resulting 2020 capacity (MW)

% of 2020 NREAP target

UK 128 10-15% Yes (2) Good (4) Adequate (3) 9 7,313 90% 12,193 94%

Germany 133 5-10% Yes (2) Good (3) Strong (4) 9 4,928 90% 9,507 95%

Denmark 127 5-8% Yes (2) Medium (2) Strong (4) 8 70 100% 1,973 147%

Belgium 143 7-12% Yes (2) Good (4) Some risk (2) 8 956 80% 1,809 90%

France 130 5-10% Yes (2) Medium (3) Adequate (3) 8 6,000 80% 4,800 80%

Netherlands 143 N/A No (0) Poor (0) High risk (1) 1 4,172 10% 1,006 19%

Source: Bloomberg New Energy Finance Notes: ‘BNEFBNEF/Rabobank Central 2016-20’ is the capacity our Central scenario requires each country to commission in 2016-20, after the 2015 short-term forecast, to meet our expectations. The probability of meeting 2016-20 targets and 2020 targets are for the BNEF/Rabobank Cen-tral scenario. Is there a subsidy or support mechanism (current or planned) for o!shore wind? (2 = yes, 1 = planned, 0 = no). Given the expected LCOE in 2020 does this subsidy mechanism provide adequate returns to equity investors? (4 = good returns, 3 = adequate returns, 2 = marginal returns, 1 or 0 = inadequate return) How broad is the political consensus behind o!shore wind? What is the risk that support will be downgraded? (4 = strong political support, 3 = adequate, 2 = some risk, 1 or 0 = high risk). The scores translate directly into the estimated probability of each country achieving its NREAP targets from 2016-2020. For further details see Appendix. *Denmark is expected to exceed its NREAP target – explained in Section 4.2.

Table 11: Policy risks in North Sea countries for BNEF/Rabobank Central scenario

44


45

Section 5Funding requirement & potential investors

In our Central scenario we calculate that investment of EUR 127bn of capital in o!shore wind and associated grid connec-tions is required to build capacity between 2012 and 2020. This ranges from EUR 114bn in our Low scenario to EUR 152bn in our High scenario. Existing and new deal structures have opened the market to seven types of equity investor, around twenty commercial banks and three to four public financing institu-tions, such as EIB and KfW, as well as institutional investors and smaller utilities. The primary investors have been - and will con-tinue to be - large multinational utilities such as RWE, Centrica, and Dong. However the capital spending constraints which they have require them to bring on partner investors. Based on recent investment trends we expect two groups to be a key part of this: institutional investors and secondary utilities with esti-mated investments of EUR 3.9bn and EUR 14.2bn respectively.


46

5.1 Investment required

The EUR 127bn required includes grid connection costs, irrespective of which entity (devel-‐oper, utility or TSO) pays for them. This is based on 31.7GW being built (2012-‐20) in our Central scenario and could range from 28.3GW and 38.2GW, which in investment terms is EUR 114-‐152bn.

Investment is likely to be concentrated in the UK and Germany, which will both require EUR 39bn, followed by France with EUR 19bn and then Belgium (Figure 23). Germany’s invest-‐

earlier in the decade – incurring higher capex per MW – and additional grid transmission costs are included.

39.2

16.3

38.6

18.8

6.6

3.9

3.5

EURbn

Rest of EU

Netherlands

Denmark

Belgium

France

UK

Germany

Figure 23: Central scenario o!shore wind investment by country 2012-20

Source: Bloomberg New Energy Finance Notes: Investment volumes include grid connection and transmission costs.

5.2. Equity investors

Currently seven discrete investor types are actively investing equity in offshore wind assets during construction or operation (six in Figure 24and risk management capabilities which enable them to invest in these assets. Some of these investments also have debt-‐like characteristics in terms of risk and return, although there are also three other institutions that provide debt or loan guarantees which facilitate investments.

Utilities: Utilities require returns of 8-‐10%, which current policy mechanisms in the UK, Denmark and Belgium may satisfy. Therefore, we expect utilities to continue to invest in offshore wind as long-‐term assets – from conception through to decommissioning (Figure 24). This investment model has nurtured the industry in its infancy, but continuing to exploit

project duration/ wind farm lifetime is unsustainable. Further equity and debt sources are

S E C T I O N 5 F U N D I N G R E Q U I R E M E T & P OT E N T I A L I N V E S TO R S

47

utilities in projects which have either been commissioned or will be commissioned in our short term forecast 2011-‐2015.

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

20%

Announced 2 yearsCommissionedFinancedPermitted Longterm

Private equity

Turbine manufacturers

Project

IPP

developer

Utility

Pension fund

Figure 24: Entry and exit timings for equity investors with target risk adjusted returns (%)


Project developers: Project developers own assets from their conception, and take them

-‐ers are investing in offshore wind to capitalise on their construction expertise and ownership of site permits, but differ in that they do not need to hold onto assets long term to serve a gen-‐eration portfolio. Developers will aim to sell their equity stakes to utilities or pension funds on or shortly after the project’s commissioning date at a premium – increasing their returns. An estimated EUR 2.9bn has been invested by project developers in projects which have either been commissioned or will be commissioned in our short term forecast 2011-‐2015.

Turbine and balance of plant (BOP) manufacturers: : Turbine manufacturers have invested in project development sites and operational offshore wind farms. By taking part ownership in offshore wind assets, turbine manufacturers:

The latter is the strongest incentive as competition in the turbine market increases with the entrance of new players and related expected oversupply. For example Nordex acquired 40% of the 300MW Arcadis Ost 1 project development site in May 2010. BOP manufacturers such as Van Oord, Deme and Vinci are increasingly involved in construction consortia – alongside tur-‐bine manufacturers, developers and utilities – that are forming to coordinate the development of larger sites in the 3GW French tender and UK Round 3. While BOP manufacturers have not invested equity into assets to date, the aforementioned incentives for turbine manufacturers may still apply to attract future investment.


48 F U N D I N G R E Q U I R E M E T & P OT E N T I A L I N V E S TO R S

Investment once equipment contracts have been secured is less common as the volume of capi-‐

Siemens have made such investments. Siemens Project Ventures is a part owner of three pro-‐jects under construction – Gwynt y Mor (10%), Lincs (25%), and Hornsea (50%).

This equity source is limited as only a small number of manufacturers possess large enough balance sheets or appropriately skilled and mandated investment arms. However some turbine manufacturers are investigating the possibility of raising funds from other investors which they would then put into wind projects. If this strategy is successful this will increase the vol-‐ume of dedicated capital examining the space. An estimated EUR 100m has been invested by turbine manufacturers in projects which have either been commissioned or will be commis-‐sioned in our short term forecast 2011-‐2015.

Independent power producers: IPPs tend to focus on power plant construction and opera-‐tion with the intent of producing a well balanced yield bearing portfolio which they can market as an investment product to institutional investors. The majority are better capitalised than project developers and are therefore able to make the investment required to build a project and manage the risks associated with this. An estimated EUR 650m has been invested by IPPs in projects which have either been commissioned or will be commissioned in our short term forecast 2011-‐2015.

Private equity:

investor so far – Blackstone’s 80% share of the 400MW Meerwind project in Germany and the

funds to take minority stakes in future projects as they are potentially willing to take on devel-‐opment and construction risks. However, the high returns demanded by PE (14-‐20%) need to be realised either through:

PE may therefore participate in offshore wind by acting as a short-‐term investor over the con-‐struction phase. A number of more conservative PE houses are looking to purchase operational assets as longer-‐term investments – diversifying their portfolios with lower but stable returns. An estimated EUR 210m has been invested in projects which have either been commissioned or will be commissioned in our short term forecast 2011-‐2015.

Pension funds/institutional investors:

expertise and low management capability compared to the volume of capital under manage-‐

and gas company DONG Energy has pioneered this approach. It has secured a 50% investment from PensionDanmark in the Danish Rodsand 1 project in 2010, a 25% investment from Dutch investors (Stichting Pensioenfonds PGGM and Triodos Bank) in the UK Walney 1 and 2 projects in 2010, and a 50% investment (PensionDanmark and Pensionskassernes Administration A/S)

to entice the funds -‐ guaranteeing the pension fund’s returns by shouldering the entire oper-‐ating risk. If investments by retail corporations in Dutch and Belgian projects are included, EUR 1.3bn has been invested in projects which have either been commissioned or will be com-‐missioned in our short term forecast 2011-‐2015.

S E C T I O N 5

49

Sovereign wealth funds: Typically able to deploy EUR 100m or more in single investments sovereign wealth funds are not known to be systematically interested in offshore wind. How-‐

well as high level political and corporate relationships which can facilitate investments. They

capital maintenance for the parent country.

5.3. Debt providers

Commercial banks: So far 26 commercial banks have provided debt to offshore wind projects

might become less active as a result. However, many of the banks which suffered during the 2008 crisis have remained active in offshore wind and new banks have entered the market – closing deals in 2010 and 2011. EUR 1.6bn has been invested by these institutions in project

roles alongside the multilaterals.

Multilateral banks: The primary government backed lending bank to offshore wind projects to date has been the European Investment Bank (EIB) – lending more than EUR 1.7bn since

C-‐Power 2 and Borkum West 2. However this group of debt providers also includes Kreditan-‐

Meerwind projects in 2011 alone. The UK’s proposed Green Investment Bank will become active with GBP 3bn of equity in 2012, with the authority to borrow from 2015/16.Export credit agencies (ECAs): Institutions that guarantee commercial lending to exported

Windpower or Vestas is participating. Euler-‐Hermes in turn is geared to supporting German exports. Both EKF and Euler-‐Hermes are involved in the C-‐Power 2 transaction.

InvestorTarget

returns Reason for investmentExample investments

Risk appetite

Utilities 8-10% Renewable energy generation serves to decarbonise its asset portfolio. Rodsand II Variable

Project developers 12-15% Capitalise on ownership of site permits. Sheringham Shoal High

Turbine manufacturers 10-14% Secure turbine sales/demand for turbines. Lincs Medium

Independent power producers 12-15% Focus on building and maintaining a yield bearing power generation portfolio. Variable

Private equity 14-20% Opportunistic. Meerwind High

Pension funds/ institutional investors 6-8% May acquire operational assets providing lower but predictable revenues over a long time period. Note investment can have very similar characteristics to commercial debt or bonds.

Anholt Very low

Sovereign wealth funds 6-12% May acquire assets providing lower but predictable revenues over a long time period and diverse portfolio.

London Array Variable

Source: Interviews, Bloomberg New Energy Finance, Rabobank

Table 12: Equity investor pro"les


50

KfW Programme “O!shore Windenergie”On 8 June 2011, The Federal Ministry for the Environment and the state-owned development bank KfW o#cially launched the O!shore Wind Power Programme, providing EUR 5bn of debt to 10 German o!shore wind projects on a "rst come "rst serve basis – acting as a catalyst to entice capital from the private sector.

The loans may be provided in the following ways:

may not exceed EUR 700m per project or 70% of the total capital.

The scheme signi"cantly reduces the debt capital requirements from commercial banks and dramatically increases the "nancing options available to early projects by "lling into a gap in commercial lending.

5.3 Capital structures

structure. In broad terms the primary structures have either been on-‐balance sheet (all

-‐tional investors – rather than commercial banks – into projects. Similarly utilities have also brought partners in before construction or received commitments before construction that investments will be made after commissioning.

Beyond known expected investments to 2015 we have forecast future investment volume by investor type, projecting from historic average investment rates and assuming steadily increas-‐ing roles for secondary or ‘supporting’ utilities and institutional investors. These groups will invest through the following capital structures:

after commissioning

InvestorTarget

returns Reason for investment Example investmentsRisk appetite

Commercial banks 4-8% Typically the largest provider of debt in a given sector, driven by calculation of risk adjusted return on capital deployed. Cost and willingness to lend can be significantly a!ected by health of wider bank market.

Thornton Bank 1 Low

Public Finance Institutions 4-7% Multinational or national government backed institutions with explicit man-dates to support politically mandated investment goals. In Europe this includes the EIB and Germany's KfW (see box out).

Borkum West II - Phase 1 Low

Export credit agencies n/a National government backed agencies established to support the export of manufactured goods, equipment and services. Able to o!er loan and other guarantees, reducing the risk for other investors and increasing the strength of equipment supplier guarantees.

C-Power I, II & III Medium

Source: Interviews, Bloomberg New Energy Finance, Rabobank

Table 13: Debt investor pro"les

F U N D I N G R E Q U I R E M E T & P OT E N T I A L I N V E S TO R SS E C T I O N 5

51

We will see many more combinations and capital structures however these scenarios have traction and we expect to be used on an ongoing basis.

-‐

costs were expected to rise, EIB stepped in (Figure 25). Where commercial banks have pro-‐vided the majority of the capital this has been facilitated by the provision of loan guarantees by Euler-‐Hermes and EKF covering all or part of the commitments.

Commercial debt

KfW

EIB

Contingency

Equity

Loan guarantees

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Princess Amalia

Thornton Bank I

Belwind Borkum West II - Phase I

Thornton Bank I, II & III

Global Tech 1

Meerwind

2006 2007 2009 2010 2010 2011 2011

Figure 25: Project "nance capital structures and loan guarantee coverage 2006-2011


Pre-commissioning Post-commissioning Description and bene"ts Examples

1 Investor equity/balance sheet

Investor equity/balance sheet The investor maintains full equity and operational ownership.

Rodsand II

2 Investor sponsorship of project finance

Investor sponsorship of project finance

Commercial lending brought in during construction. Reduces actual equity commitment by primary sponsor throughout project lifetime.

Borkum West II – Phase IGlobal Tech 1C-Power I, II & III


Refinance with debt from commercial or development banks & Sale of equity to 3rd party

Commercial or development bank lending brought in post construction. Refinances the asset and allows the primary sponsor to redeploy capital.

Baltic 1LynnInner DowsingGreater Gabbard


Sale of debt like tranche to institutional investor.

Investor maintains operational control and shoulders primary operational risks.

Rodsand IGunfleet SandsWalney 1 and 2 Anholt


Table 14: Potential capital structures of o!shore wind farms


52

5.4 Investment volume by investor type

We have forecast the potential sources of this capital by categorising the current equity own-‐ers of the offshore wind projects in our short-‐term forecast to 2015 into the seven types noted above. The debt portions – whether commercial or public – of projects that have or are attain-‐

and gearing ratios are projected onto our long term investment forecast (2016-‐20).

This represents a shift to a more sustainable equilibrium whereby the industry relies less on the primary utilities to fund assets on balance sheet. Other equity sources are expected

as more municipal utilities (Trianel GmbH, Stadtwerke Muenchen GmbH etc.) and small utilities take partial ownership of assets with equity injections of EUR 100-‐200m.

in 2016-‐20. Developers currently own 53% of equity in projects forecast to be commis-‐sioned in 2015 – a statistic skewed upwards since 68% of these assets are only permitted,

selling equity stakes to other investors during construction or shortly after commissioning.

2020. Pension, insurance and sovereign wealth funds are increasingly looking into offshore wind as a stable and long term investment opportunity.

product demand.

We foresee PE acting primarily as a short-‐term investor over the construction phase, but there are a number of more conservative PE houses looking to purchase operational assets as longer-‐term investments – diversifying their portfolios with lower but stable returns.

This Central scenario forecasts that the required investment volume (2012-‐20) could consti-‐tute EUR 27.0bn from primary utilities, EUR 16.8bn from project developers, EUR 14.2bn from secondary utilities, EUR 3.1bn from independent power producers (IPP), EUR 0.7bn from tur-‐bine manufacturers, EUR 3.9bn from institutional investors and EUR 1.9bn from private equity (Figure 26).

We are forecasting greater ownership of offshore wind assets by secondary utilities and project

capital demands of large future projects. Our analysis estimates debt capital contributions will increase from 40-‐60% in 2016-‐20, while the contribution of commercial banks to this debt capital will increase from 45-‐70% in 2013-‐20. There is a high volume of public bank debt in

its “Offshore Windenergie” programme, but this will subside once this programme ends.

F U N D I N G R E Q U I R E M E T & P OT E N T I A L I N V E S TO R SS E C T I O N 5

53

Debt - Multilateral

Debt - Commercial

Private equity

WTG

Institutional investor

IPP

Developer

Secondary utility

Primary utility

EURbn

1.1

6.3

4.2

2.2

3.3 3.2

2.8 2.4 2.1

1.6

0.9

0.7

1.4

1.4 1.7

1.9 2.2

2.5

0.9

0.4

1.5 4.3

1.9 2.0

2.0 2.0

2.1

0.4 0.3

0.3

0.1 0.4

0.4

0.4

0.4

0.4

0.2 0.4

0.5

0.1 0.3

0.4

0.5

0.6

0.8

0.1 0.1

0.2

0.1

0.1

0.1

0.1

0.1

0.3

0.3

0.3

0.3

0.3

0.3

0.4 1.0

3.5 3.4

2.8 4.0

5.2 6.9

8.6

0.7 1.2

3.8 3.4 2.3 2.7 2.8 3.0 3.7

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2012 2013 2014 2015 2016 2017 2018 2019 2020

5.5 20.5 18.0 16.0 14.8 12.9 15.1 15.0 10.6

Figure 26: Annual investment in o!shore wind by year of commissioning and investor type 2007-15 existing commitments 2016-2020 forecast

Source: Bloomberg New Energy Finance Notes: Data in 2012-15 is based on real ownership data of projects in our short term forecast. Data in 2016-20 is forecast using assumptions described in Section 4.

In our Central scenario government support for offshore wind remains stable and there is no reduction in tariff levels. In this environment we project offshore wind’s levelised cost of

returns – attracting capital from an increasing portfolio of equity and debt with diverging risk

installations of 35.5GW in the EU by 2020. Although this is less than of the targeted 46.6GW, it entails a compound annual growth rate (CAGR) of 22.4% in 2011-‐20 and EUR 127bn invest-‐ment. This scenario will establish offshore wind on a robust path to further industrialisation and roll out across the EU and the world. It requires the right political and regulatory environ-‐ment to enable the innovation and dynamism of private enterprise to deliver these investment volumes and subsequent cost reductions required by society.


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55

Appendices


56

capital and operational costs assessments, we calculate the expected cost for offshore wind projects by country through 2020:

capacity, average wind speed, technical availability, distance to shore, water depth.

turbine model, foundation type, high-‐voltage cable type and length, electrical substations

the experience curve is an empirical economic law govern-‐ing most manufactured goods: for every doubling of cumulative production of a given good,

by doing: the more you make of something, the better you become at it.unlocking greater expected demand may drives investments in larger

Appendix A

O!shore Wind Cost Model

A P P E N D I X A

Manufacturer Model Capacity (MW) Date online EURm per unit EURm per MW

Vestas V90 3.0 Online 3.97 1.32

Siemens SWT 107/120 3.6 Online 4.83 1.34

Areva Multibrid M5000 5.0 Online 7.47 1.49

Repower 5M 5.0 Online 7.47 1.49

BARD 5.0 5.0 Online 7.47 1.49

Alstom 6MW 6.0 2013 9.05 1.51

Siemens SWT 120 6.0 2014 9.33 1.55

Vestas V164 7.0 2014/15 10.51 1.50


Turbine Turbine 3+MW 5+MW

Depth (m) Monopile Gravity Jacket Tripod Monopile Gravity Jacket Tripod

5 1.32 1.37 1.38 1.43 2.73 2.78 1.75 2.31

10 1.43 1.48 1.49 1.54 2.84 2.89 1.86 2.42

15 1.54 1.59 1.60 1.65 2.95 3.00 1.97 2.53

20 1.65 1.70 1.72 1.76 3.06 3.11 2.09 2.64

25 1.75 1.81 1.83 1.87 - 3.22 2.20 2.75

30 1.86 1.91 1.94 1.98 - - 2.31 2.86

35 - - 2.05 2.09 - - 2.42 2.97

40 - - 2.16 2.21 - - 2.53 3.08

45 - - 2.27 2.32 - - 2.64 3.19

Source: Companies, Bloomberg New Energy Finance

Table 15: Project turbine prices by manufacturer and turbine, 2018

Table 16: Foundation costs by type, 2018 (EURm per unit)

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TIV Year TIV Year TIV Year

Inwind Installer 2011 Beluga Hochtief 2 2012 Van Oord 1 2012

Jack Up Barge JB 116 2011 Fred Olsen Windcarrier Bold Tern 2012 Workfox Seafox 5 2012

Master Marine Nora 2011 RWE Seabreeze 2 2012 A2Sea Sea Installer 2013

RWE Seabreeze 1 2011 SeaJacks Scirocco 2012 Fred Olsen Windcarrier Brave Tern 2013

MPI Adventure 2011 SeaJacks Shamal 2012 Jack Up Barge JB 117 2013

MPI Discovery 2011 SeaJacks Zaratan 2012 Swire Blue Ocean Pacific Osprey 2013

Beluga Hochtief 1 2012 Swire Blue Ocean Pacific Orca 2012 GAOH Deepwater Installer 2013

Source: Comnpanies, Bloomberg New Energy Finance, companies

Table 18: TIVs under construction with estimated delivery date

Type Current Voltage (kV) EURm per km

Export AC 132/150 0.55

AC 400 0.64

DC 400 1.28

DC with VSC 400 1.55

Array AC 33 0.15

Source: Companies, Bloomberg New Energy Finance Notes: Cable costs include installation.

Table 17: High voltage cable costs, 2018


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Our forecasts are constructed by combining distinct short-‐ (2011-‐15) and long-‐term (2016-‐20) forecasts. The former is based on the known project pipeline. The latter is driven from a calcu-‐lation of the probability of each country achieving its NREAP.

2015 short-term forecastOur short-‐term forecast to 2015 adopts a bottom-‐up approach, aggregating our expected com-‐missioning dates for individual projects. Initial forecasts are calculated from the current pro-‐

achieve the remaining milestones. These timeframes vary according to the regulatory regime and the tier of the asset developer/owner – a function of industry experience and ability to attract capital. Assets with lower tier developers and in the early stages of development are assigned probabilities for completion, cutting their announced capacity. Our forecast dates also take into account developer’s timelines and analysis of bottlenecks in the supply chain.

2020 long-term forecastThe 2020 forecast combines our 2015 forecast with modelled probabilities of each EU country

stability of the policy mechanism. Using our Offshore Wind Cost Model (Appendix A) we esti-‐mated ranges for the LCOE of offshore wind in each member state and combining this with the political analysis – we scored each country on the following:

(2 = yes, 1 = planned, 0 = no)

returns to equity investors? (4 = good returns, 3 = adequate returns, 2 = marginal returns, 1 or 0 = inadequate returns)

will be downgraded? (4 = strong political support, 3 = adequate, 2 = some risk, 1 or 0 = high risk)

We translate the score into an estimate of the probability that each country will install the necessary capacity 2016-‐20 (without altering our 2015 forecast) required to meet its NREAP targets. Potential supply chain constraints are taken into account through the LCOE detailed in

to growth rates in the 2015 forecast and deployment estimates.

A P P E N D I X B

Appendix B

Forecast methodology

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Colofon

Contact details

Rabobank International

P.O. Box 171003500 HG UtrechtThe NetherlandsWebsite: www.rabobank.com

Renewable Energy & Infrastructure Finance

Marc Schmitz [email protected] +31 (0)30 71 23351Niels de Fijter [email protected] +31 (0)30 71 23347 Food & Agribusiness Research and Advisory

Clara van der Elst [email protected] +31 (0)30 71 24507Susan Hansen [email protected] +31 (0)30 71 23815

Bloomberg New Energy Finance

City Gate House39-45 Finsbury SquareEC2A 1PQ LondonUnited KingdomWebsite: www.bloomberg.com

William Young [email protected] +44 20 3216 4354Fraser Johnston "[email protected] +44 20 7392 0450Michael Wilshire [email protected] +44 20 3216 4643

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