Offshore Wind Development Potential 2011

Offshore Wind Development Potential 2011
Renewable energy consultants
GL Garrad Hassan
Written on behalf of the Sustainable Energy
Authority of Ireland
Offshore
Industrial Development Potential
of Offshore Wind in Ireland
Issue: February 2011
Status: Final
Classification: Client’s Discretion
INDUSTRIAL DEVELOPMENT POTENTIAL OF OFFSHORE
WIND IN IRELAND
Client
Contact
Document No
Issue
Status
Classification
Date
Author:
Sustainable Energy Authority of Ireland
Eoin Sweeney
104991/BR/03
C
Final
Client’s Discretion
24 March 2011
D Williams, J Clayton, P Gardner,
G Gibberd
Checked by:
D Argyropoulos, J Phillips
Approved by:
P Gardner
Garrad Hassan & Partners Ltd
St Vincent’s Works, Silverthorne Lane, Bristol BS2 0QD, UK Tel: +44 (0)117 972 9900, Registered in England 1878456
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Industrial Development potential of offshore wind in Ireland
REVISION HISTORY
Issue
Issue date
A
07.02.11
Original issue.
B
16.02.11
First revision.
C
24.03.11
Final issue.
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Summary
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Industrial Development potential of offshore wind in Ireland
March 2011
LIST OF ACRONYMS
€
Euros
BERR
Former UK Department for Business, Enterprise and
Regulatory Reform
BoP
Balance of Plant
CAPEX
Capital Expenditure
CER
Commission for Energy Regulation
CPM
Capacity Payment Mechanism
CPT
Cone Penetration Test
DEVEX
Development Expenditure
EEZ
Exclusive Economic Zone
EIA
Environmental Impact Assessment
ENTSO-E
European Network of Transmission System
Operators for Electricity
ERGEG
European Regulators Group for Electricity and Gas
ESB
Electricity Supply Board
FAQ
Firm-Access Quantity
FEED
Front End Engineering and Design
FUI
France-UK-Ireland
GBS
Gravity Based Structure
GDP
Gross Domestic Product
GLGH
GL Garrad Hassan
GW
Gigawatt
GWh
Gigawatt-hour
IPP
Independent Power Producer
ITC
Incremental Transfer Capability
ITC
Investment Tax Credit
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Industrial Development potential of offshore wind in Ireland
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ktoe
Kilo-tonnes of oil equivalent
kW
Kilowatt
kWh
Kilowatt hour
LIDAR
Light Detection and Ranging
MW
Megawatt
MWh
Megawatt hour
NIAUR
Northern Ireland Authority for Utility Regulation
NREAP
National Renewable Energy Action Plan
O&M
Operations and Maintenance
OPEX
Operational Expenditure
OREDP
Offshore Renewable Energy Development Plan
PMG
Permanent Magnet Generator
R&D
Research and Development
RA
Regulatory Authority
REFIT
Renewable Energy Feed-In Tariff
ROI
Republic Of Ireland
SEA
Strategic Environmental Assessment
SEAI
Sustainable Energy Authority Ireland
SEM
Single Electricity Market
SEMO
Single Electricity Market Operator
SMP
System Marginal Price
SONI
System Operator Northern Ireland
TLP
Tension-Legged Platform
TSO
Transmission System Operator
TWh
Terawatt-hour
VOLL
Value Of Lost Load
WTG
Wind Turbine Generator
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CONTENTS
REVISION HISTORY
I
CONTENTS
I
EXECUTIVE SUMMARY
1
PART A: CURRENT STATUS
1
CONTEXT SETTING
8
1.1
Electricity Generation in Ireland: Historical and Political Context 8
1.2
Irish Electricity Market
13
2
OFFSHORE WIND AND ENERGY RESOURCE
2.1
Approach and Assumptions
2.2
Wind Energy Resource
2.3
Conclusion
18
18
24
28
3
ELECTRICITY NETWORK ISSUES
3.1
Background
3.2
Transmission system development
3.3
Grid Connection
3.4
Charging
3.5
Principles of dispatch
3.6
Implications for offshore wind projects.
3.7
Offshore wind for exporting electricity
29
29
30
30
30
31
31
32
4
IRELAND’S OFFSHORE WIND MARKET DEVELOPMENT
4.1
European Context
4.2
Offshore Wind Policy Mechanisms and Measures in Ireland
4.3
Project Activities
4.4
Reasons for Failing to Meet the 2004 Targets
34
34
35
37
40
5
IDENTIFIED BARRIERS AND POSSIBLE DRIVERS
5.1
Drivers
5.2
Barriers
41
41
41
6
CONCLUSIONS
42
PART
B: INTERNATIONAL SUPPLY CHAIN
1
ANATOMY OF AN OFFSHORE WIND FARM
44
2
OFFSHORE WIND SUPPLY CHAIN
47
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2.1
2.2
2.3
2.4
2.5
2.6
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Background
Developers and owners
Wind turbine suppliers
Wind turbine sub-component suppliers
Offshore design trends
Equipment installers/Balance of plant equipment suppliers
47
48
49
54
55
58
PART C: SCENARIOS AND OPPORTUNITIES
1
DEFINING SCENARIOS
67
2
DEMAND FOR EQUIPMENT AND SERVICES (ROI)
2.1
Development
2.2
Construction Phase
2.3
Operations and Maintenance Phase
2.4
Decommissioning Phase
71
71
77
86
89
3
MARKET OPPORTUNITIES BEYOND ROI WATERS
3.1
Forecast for ROI and adjacent waters market
3.2
Forecast of market around the UK
3.3
European offshore market
3.4
North American offshore market
3.5
European onshore market
90
90
93
96
96
97
4
RECOMMENDATIONS
4.1
Key infrastructural investment required
4.2
Measures aimed at industry / supply chain development
4.3
Policy support at Irish and EU levels
4.4
R&D actions aimed at gaining market share
REFERENCES
APPENDIX 1 - WIND SPEED MAPS FOR IDENTIFIED BATHYMETRIC CLASSES
APPENDIX 2 – MAJOR OFFSHORE WIND TURBINE MANUFACTURERS
APPENDIX 3 – MAJOR OFFSHORE WIND DEVELOPERS
APPENDIX 4 – WTG SUB-COMPONENT SUPPLIERS
APPENDIX 5 – PROVEN FOUNDATION CONCEPTS
APPENDIX 6 – DEMONSTRATED FOUNDATION CONCEPTS – FIXED
APPENDIX 7 – DEMONSTRATED FOUNDATION CONCEPTS - FLOATING
APPENDIX 8 – POTENTIAL NEW FOUNDATION CONCEPTS, FIXED AND
FLOATING
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99
99
100
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ANNEXES
ANNEX A - INTERNATIONAL OFFSHORE WIND REGULATORY FRAMEWORKS
ANNEX B – CASE STUDY ON UK OFFSHORE WIND DEVELOPMENT
ANNEX C – INDUSTRIAL SYNERGIES FOR WAVE AND TIDAL SECTORS
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EXECUTIVE SUMMARY
The Sustainable Energy Authority of Ireland (SEAI) appointed GL Garrad Hassan (GLGH) to
undertake an assessment of the industrial development potential of offshore wind in Ireland. The
assessment is intended to assist SEAI and the Government of Ireland in analysing and developing
targets, programmes and policies to develop Ireland’s offshore wind energy resources.
The scope of work covered three broad areas; the current situation for offshore wind in Ireland, a
review of international technology and supply trends in the industry, and scenario modelling to
analyse the industrial development potential associated with varying degrees of future offshore
wind deployment activity in Irish waters.
The report finds that offshore wind development in Ireland to date has been hampered by issues
surrounding project economics, consenting and grid connection and that strong political will is
required to address existing barriers and align procedures. If Ireland is to compete for notable
industrial development along the offshore supply chain it is necessary that such political action
occurs in a timely fashion and offshore wind is not seen in post-2020 terms. The report investigates
demand levels for major equipment and services under three build-rate scenarios for offshore wind
in Ireland through to 2030; Low, Medium and High. It also looks at demand levels under a
combination of each of these scenarios with expected development in UK waters adjacent to the
Irish Exclusive Economic Zone through to 2020, thus creating an expanded potential market for
Irish equipment and services. The report finds that if looking at the Irish market in isolation, supply
chain opportunities will likely be based around development services, and operations and
maintenance (O&M) activities, with major construction components limited to the possibility of a
relatively small foundation and or tower fabricating facility under the High scenario. However
when the greater Irish and adjacent UK waters market is considered, aside from significantly
ramping up such development and O&M opportunities, demand becomes notable under all
scenarios for foundation and tower supply, and installation vessels. Indeed it is the demand
emanating from this expanded area, encompassing the Irish Sea and adjacent UK waters, which is
likely to be assessed by companies when considering the development of facilities and capabilities
to supply and service the offshore wind sector from an Irish base. These opportunities,
representing an estimated 6 GW of cumulative capacity and over €20 billion related capital
expenditure by 2020 (and possibly ramping up beyond), have already been widely noted in the UK
and as such delay in implementing enabling actions could see fabrication facilities and ports in the
UK capture ‘first mover’ advantage.
The layout of the report and the major conclusions are summarised here.
Part A, Current Status of Offshore Wind in Ireland
1. Context setting.
The section includes an overview of Ireland’s electricity supply and demand situation, the current
fuel mix, targets and forecasts through to 2020, and introduces principal entities involved in
formulating and implementing energy policy. It also covers the electricity market structure in
Ireland, the impact of increasing wind penetration on this structure, and details the policy support
framework for incentivising the installation of offshore wind in particular.
2. Offshore wind and energy resource.
This section quantifies the potential of offshore wind in Irish waters. A wind resource map for the
Irish Exclusive Economic Zone has been produced, and technical limitations on deployment are
applied. This shows that the wind resource even in relatively shallow waters (up to 50 m) is
enormous: well in excess of total electricity consumption on the island of Ireland.
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3. Electricity network issues.
This section summarises network issues as they may affect offshore wind development. The
prospect of using offshore wind farms in Irish waters for direct export to the UK and France is also
discussed.
4. Ireland’s offshore wind market development.
This section provides the international context, reviews the current project pipeline of the offshore
wind industry in Ireland, and provides an overview of the industry.
5. Identified barriers and possible drivers.
This section summarises the key issues which may act as potential barriers or drivers for the future
development of offshore wind in Ireland. The main drivers are:



Ireland’s agreed 2020 emissions target and associated renewable energy target is the main
driver for all renewables generation, though there is also a significant political desire to
reduce fuel imports.
The opportunity to gain for Ireland some employment and industrial development
benefits, if the development of offshore wind is managed. The alternative would be
piecemeal developments without an overall programme, which are likely to be constructed
on a ‘one-off’ basis, and therefore less likely to result in significant economic development
benefits for Ireland. Also, development in the near future would help to avoid companies in
other countries (in particular the UK) establishing ‘first mover’ advantages.
If onshore wind fails to be developed at the rate necessary to meet the 2020 targets,
offshore wind has the potential to fill the gap. Public acceptance may be easier than for
onshore wind projects.
The main barriers to offshore wind are:
 A perception of unattractive project economics, both in comparison to onshore wind in
Ireland and to offshore projects in UK waters.
 Grid connection process.
 Lengthy consenting process.
 Lack of clear policy direction and political will to remove these barriers.
 No major established heavy engineering, shipbuilding or offshore oil & gas industries on
which industrial development could be based.
6. Conclusions.
In addition to the conclusions on drivers and barriers, the main conclusions for Part A are:
 The offshore wind resource in Irish waters is very large.
 Under some circumstances, Ireland’s 2020 targets might be feasible using only a limited
amount of offshore wind, principally by using onshore wind, which is seen as cheaper and
less risky. Possibly because of this, there is a lack of political will to resolve the major
barriers to offshore wind. However there is substantial uncertainty regarding the viability of
many of the onshore wind projects currently in the Gate 3 pipeline and should significant
delays and cancellations occur, increased levels of offshore wind would be one means to
meet the 2020 target.
 For offshore wind to be part of the ‘2020’ solution, strong political will is necessary to
resolve
 the major barriers of economics, grid connections and consenting.
 If offshore wind is seen as a ‘post 2020’ resource, it is likely that Ireland will not gain much
economic development benefit from establishment of elements of an offshore wind
industry, as other countries will already have established industries.
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Part B, International Offshore Wind Industry Supply Chain
This Part contains a detailed description of the elements and activities that make up an offshore
wind farm, and analysis of the offshore wind industry supply chain, including contracting
structures, main participants, and design trends for major items. The scale of the European
offshore wind market is estimated to see around 50 GW of cumulative installations representing
approximately €175 billion of capital expenditure by 2020.
Part C, Scenarios and Opportunities for Offshore Wind Industrial Development Potential in
Ireland
In this Part, scenarios to represent possible development paths were used to estimate the demand
for equipment and services that could lead to industrial development in Ireland.
1. Defining scenarios.
Three build-rate scenarios (Low, Medium, and High) through to 2030 were agreed with SEAI, based
on the 2030 offshore wind installed capacity scenarios included in the draft Offshore Renewable
Energy Development Plan (OREDP).
 Low: assumes development only of existing Gate 3 offers.
 Medium: based on a moderately optimistic assessment of what could be achieved by 2020,
with adequate political will, followed by continued expansion to 2030.
 High: based on maximum realistic contribution of offshore wind to 2020 targets, with
continued expansion to 2030.
2. Demand for equipment and services (Republic of Ireland).
In this section, the scenarios are used to generate estimates of the demand for major components
and services, for projects in Irish waters. This is done for each of the project phases: Development,
Construction, Operation and Decommissioning. The estimates are quantified in financial terms or
in demand for specific items (for example, number of borehole surveys by year). For each project
phase, a commentary is provided on the opportunities for participation in the supply chain of
businesses based in Ireland.
Development expenditure (DEVEX)
The results indicate that at the peak of the High scenario, development expenditure of €20 m per
year on Irish projects can be expected. This is sufficient to support project development teams and
consultancy and similar services in Ireland. The requirement for knowledge of the consenting
process and legal and policy background should ensure that a significant part of this work is
actually done in Ireland, rather than by development teams and consultants elsewhere in Europe,
especially the UK. Even the Low scenario is likely to justify work by development teams and
consultants based in Ireland.
Capital expenditure (Capex)
When looking at the stand-alone Republic of Ireland market demand is only sufficient within the
High scenario for the possible establishment of a small foundations manufacturing facility capable
of around 50 units per year. A foundation manufacturing facility for monopiles could also produce
towers and transition pieces. This may be a way to increase the facility’s size and therefore reduce
unit costs to compete with larger facilities elsewhere. Under the High scenario, there may well be a
case for at least one Irish-based installation vessel, capable of installing both foundations and
turbines. However potential market entrants are likely to consider possibilities in the greater Irish
Sea and adjacent waters market which could substantially incarese opportunities as noted below.
Provision of construction support services offers a more flexible opportunity but businesses
pursuing these will have similar disadvantages of lack of a home market and geographic separation
from the main hub of activity in the North Sea. Nevertheless, it is entirely feasible that good quality
dynamic businesses could build a good position in the offshore wind sector.
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Operational expenditure (Opex)
In the High deployment scenario, up to one additional turbine repair vessel will be required,
working full time. The specifications of this vessel overlap with those of the foundation and turbine
installation vessels, meaning that total jack-up demand could be around three vessels. This
represents a significant market, perhaps tempered if projects are dispersed between east and west
coasts.
From 2015 onwards, in all three scenarios, there is sufficient value in O&M activities to justify
establishing O&M facilities in Ireland. This is likely to be on a project-specific basis. With further
expansion (i.e. the High and Medium scenarios after 2020), there may be opportunities for facilities
common to several projects.
3. Market opportunities beyond ROI waters.
This section provides GLGH’s forecasts for offshore wind sector growth in international waters
separated into sections on the ‘adjacent waters’ (i.e. Irish waters and the UK west coast, which are
likely to function as one market distinct from North Sea markets), the UK, Europe, North America
and also onshore wind in Europe. For each of these markets, a commentary is provided on future
supply chain export possibilities for Ireland.
The main conclusions are listed here:
Foundation, tower and transition piece supply, UK waters
The forecasts show a substantial increase in requirements for foundations in UK waters from
around 2015 onwards, and the majority of these are for water depths similar to those that will be
required for Irish projects. There will be substantial competition for this work, but location does
offer some advantage in this market. A substantial part of this market is in waters adjacent to
Ireland. Therefore there may be an opportunity to build a foundation supply business mainly for
projects in western UK waters from around 2015, before the requirements for Irish projects would
justify such a facility. Furthermore, as in the irish only market scenario, such a facility for monopiles
could also produce towers and transition pieces.
Vessels for turbine installation, foundation installation and O&M, UK waters
The demand for new vessels for foundation installation, turbine installation and repairs is
substantial. Vessels based on the east coast of Ireland should be able to compete for work on UK
west coast projects, and possibly further afield.
O&M service, UK waters
Apart from vessels, there is the possibility of providing O&M services to projects in western UK
waters from bases in Irish east-coast ports. As there are likely to be benefits in centralising spares
holdings, management and staffing, and as UK ports are already the first-movers, this is only likely
to happen if there is some cost advantage in an Irish location, such as labour costs, or tax
treatment.
Rest of Europe
While there is currency in common, it is hard to see how that will place Ireland at any real
advantage against mainland Europe, and challenges of entering non-UK markets are at least as
high as entering the UK market.
North America
No significant opportunities are foreseen.
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European onshore market
The established onshore wind developers and contracting companies in Ireland have continuing
opportunities in European onshore markets. Indeed, Ireland’s onshore wind programme (and
perhaps also the early Arklow Bank Phase 1 offshore project) drove the development of the
Airtricity, Mainstream ESBI and other businesses which continue to have a significant Irish presence
for the wind sector although their focus is now on other markets. Ireland has an established
expertise in project development and these types of business can continue to prosper and grow
across the wind business generally – onshore and offshore.
4. Recommendations.
Key infrastructural investment
Investment in ports is treated as infrastructure investment. Investment for the construction phase
is likely to follow the projects, i.e. investment in port facilities required for installation vessels,
workboats and transhipment of major components is not justified until projects commence. The
large UK Round 3 Irish Sea project (4200 MW) is a possible exception: advance investment in an
Irish port might conceivably gain business that would otherwise go to a UK port. This seems a risky
strategy, and detailed investigation would be necessary before committing significant investment.
The same argument applies to port investment for O&M services: advance investment is unlikely to
gain a significant advantage for Irish ports. Service ports are selected for location and accessibility –
after which investment to bring these up to standard can be made.
Measures aimed at industry and supply chain development
The following major options for the involvement of Irish companies in the offshore wind supply
chain were identified:
 Foundation manufacturing, aimed at projects in ROI and western UK waters. Tower
manufacturing could be included.
 A concerted effort from Irish Industrial Development Agencies to promote Irish facilities to
the entire offshore wind supply chain similar to that undertaken by Invest NI and DETI in
the UK could be successful in attracting some supply chain companies to Ireland.
 Vessels for foundation and turbine installation, and turbine repair, again aimed at projects
in ROI and western UK waters. Providing a home and support services for such vessels may
be more attractive than Irish ownership, as owners of fleets tend to have an advantage.
 Provision of O&M bases. As noted above, no support measures for this are recommended
at this stage.
Policy support at Irish and EU levels
Policy measures to open opportunities for Irish offshore wind are:
 Opening market for trading of renewable energy (or possibly carbon credits) across Europe.
 Harmonisation of transmission system rules and mechanisms across Europe.
 Build of key interconnectors.
 Developing streamlined regulatory framework (leasing, environmental assessment and
consenting) for offshore wind projects within Irish waters including the whole economic
zone and not just territorial waters.
R&D actions aimed at gaining market share
Short-term actions proposed are:
 Foundation demonstration to promote foundations optimised for Irish Sea sites
 Turbine demonstration onshore and offshore, or combined foundation and turbine
demonstration. Turbine and foundation manufacturers are currently looking for sites to
carry out these activities both onshore and offshore.
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
Investigation of floating turbine demonstration possibilities in the extreme wind and wave
climate off the West coast.
 Demand-side system management measures to allow increasing penetration of
renewables into the Irish island system
Long-term actions are:
 Collaborative work with neighbouring nations on interconnection to support the policy
harmonisation and market opening efforts but also to define the optimum topology for
interconnection
 Floating wind R&D, possibly collaborative with other countries sharing same deep water
characteristics e.g. Spain, Norway, Scotland.
Annexes
Separate annexes are provided on specific issues.
Annex A summarises and compares the regulatory frameworks for offshore wind development and
operation in several jurisdictions.
Annex B is a case study of the UK offshore wind development programme, identifying the interplay
between policy drivers and domestic industrial development.
Annex C considers possible synergies with wave and tidal developments, in particular for industrial
development potential.
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Part A. Current Status
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Industrial Development potential of offshore wind in Ireland
1
March 2011
CONTEXT SETTING
1.1 Electricity Generation in Ireland: Historical and Political Context
1.1.1 Power supply and demand in Ireland
Following a period of growing demand for power through the 1990s as Ireland’s economy and
population expanded, the last decade has seen substantial success in decoupling electricity
consumption from economic growth. This has been largely attributed to changes in the structure
of the Irish economy and improvements in energy efficiency [2]. Generation remains primarily
sourced from fossil-fuels with natural gas taking an ever increasing share from coal. Further
notable contributions to the mix come from domestic peat reserves, imported oil (albeit a
declining share) and, more recently, wind power. Figure 1.1 presents the breakdown of primary
fuel for electricity in Ireland over the last 15 years, in ktoe (kilo-tonnes of oil equivalent).
200000
180000
5,000
160000
140000
4,000
120000
3,000
100000
80000
2,000
60000
40000
1,000
20000
0
Irish GDP at current prices [€million
Primary energy for electricity [ktoe]
6,000
0
1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
Year
Natural gas
Coal
Peat
Petroleum
Wind
Other renewables
Net imports
Irish GDP at current prices
Figure 1.1: Energy content of primary fuel for electricity in Ireland 1995 – 2009
{Sources: Central Statistics Office Ireland [3], OECD Statistics [4]}
Due to the differing conversion efficiencies of different fuel types the picture varies somewhat
when one considers instead the split of electricity production by fuel type. In the above graph
wind power accounted for approximately 5 % of primary energy input for electricity in 2009 but
more than 10 % share of generated electricity [5].
Expected electricity consumption forecasts through to 2020 for both a “Reference Scenario” and an
“Additional Energy Efficiency” scenario were included in Ireland’s National Renewable Energy
Action Plan (NREAP) submitted to the European Union (EU) under Directive 2009/28/EC [7]. Table
1.1 presents these forecasts, which were derived from the SEAI’s “Energy Forecasts for Ireland to
2020”. It is noted this analysis also modelled two more ambitious scenarios inclusive of additional
measures yet to be taken by government [6].
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Industrial Development potential of offshore wind in Ireland
Year Ending
Consumption
[ktoe]
March 2011
2010
2012
2014
2016
2018
2020
Reference
Scenario
2,511
2,574
2,697
2,806
2,872
2,937
Additional
Energy
Efficiency
2,473
2,500
2,587
2,677
2,746
2,813
Table 1.1: Expected final energy consumption for electricity in Ireland 2010-2020
{Source: NREAP Ireland [7]}
1.1.2 Renewable energy in power generation
With only a small contribution from hydropower, renewable energy has historically played a
limited role in electricity generation in Ireland. However over the last five years and especially since
2006 when Ireland replaced its Alternative Energy Requirement (AER) scheme for the auction of
renewable PPAs with a feed-in tariff support mechanism, “REFIT”, wind powered generation has
seen a significant year-on-year increase in its share of the mix. The breakdown for electricity
generation from renewable energies for 2009 is presented in Figure 1.2.
Wind
75.8%
Biomass
4.7%
Hydro
19.5%
Figure 1.2: Breakdown of renewable electricity generation in Ireland 20091
{Source: SEAI [8]}
Note 1: Biomass comprises of solid biomass, landfill gas and biogas
1.1.3 Targets and forecasts for renewable energy
14.4 % of electricity generation was sourced from renewable power plants in 2009, surpassing the
target provided in EU Directive 2001/77/EC which required 13.2% of electricity consumption in
Ireland to come from renewables by 2010. This development also puts Ireland on track to exceed
its own national target of 15% of electricity consumption to be met by renewable energy in 2010
[7]. This latter target was expressed in the 2007 Energy White Paper, which also introduced a
further target of 33% by 2020, subsequently amended to 40 % in the 2009 Carbon Budget. Under
EU Directive 2009/28/EC Ireland is required to source 16 % of total energy consumption from
renewables by 2020. As part of Ireland’s NREAP submitted in summer 2010, Ireland outlined a
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trajectory for meeting this target which included an estimated 42.5 % of electricity sourced from
renewable generation in 2020 [7].
In order to achieve the 2020 targets using demand projections as outlined above, the Irish
government in its NREAP estimated gross final electricity consumption from renewable sources will
reach 1,196 ktoe in 2020. Depending on the exact demand projections the NREAP estimated
between 4,630 MW and 5,800 MW of installed renewable generation capacity will be required [7].
However due to the recent severe economic recession in Ireland demand forecasts have been
revised downwards and it is now estimated the EU Directive target of 16 % can be met with an
estimated 1,032 ktoe sourced from renewables with a corresponding drop in the capacity
requirements [8]. It is also now believed that a contribution of 40 % of electricity sourced from
renewable generation, in line with the 2007 White Paper, will be sufficient for meeting the EU
Directive 2009/28/EC target of 16 % total energy consumption from renewables by 2020, rather
than the slightly higher figure of 42.5 % provided in the NREAP [8].
In terms of the projected breakdown by renewable technology, onshore wind is expected to
dominate in the near-term and provide the majority of the renewable electricity required to meet
the EU Directive targets. The NREAP also reflects government policy and shows how the 2007
White Paper target of 500 MW for Ocean Energy (wave and tidal but not inclusive of offshore wind)
along with increased wind and biomass deployment, surpass the EU obligations under an “Export
Scenario” [7] [9]. No specific government target for offshore wind has been announced, however
approximately 800 MW of capacity was included in the recent “Gate 3” round of connected offers
[11]. Indeed, depending on the exact level of demand, the 4 GW of onshore and offshore wind
capacity scheduled under Gate 3, added to existing installations, should be more than enough to
meet the 40 % target. Nevertheless significant uncertainty remains over planning considerations
for many onshore wind Gate 3 projects, given it has been estimated over half are proposed to be
sited in environmentally sensitive areas1. Should there be a significant level of attrition to Gate 3
onshore applications due to planning rejections then depending upon the viability of alternative
onshore sites, additional offshore development could play a vital role in assisting Ireland achieve its
2020 targets.
A further area of consideration is the uneven trajectory of the expected growth of renewable
generation as outlined both in the NREAP and by EirGrid for their ITC (Incremental Transfer
Capability) programme schedules [11]. The ITC Program is a software program used by EirGrid to
determine the amount of extra power that the transmission system can accommodate from the
Gate 3 generators without breaching thermal network limits [12]. As shown in Figure 1.3, due to
the grid improvements required to take place before projects can be offered connection on a firm
access basis, there is a significant weighting towards the years 2017 to 2020. While it is possible for
generators to connect to the grid on a non-firm basis prior to their firm access dates, eligibility for
compensation payments under these conditions is limited should generator dispatch be
constrained, thus increasing the risk to a project. This highlights the related issue of priority
dispatch for renewables (thus greatly reducing the chances of an offshore wind farm being
constrained-off) as described further in Section 3.5. It should also be noted that the location of the
majority of the proposed offshore wind farms in the Irish Sea, close to the east coast where the grid
is more developed than remote western locations, further reduces the chances of a wind farm
being constrained-off.
1
Defined as areas of Natural Heritage Area (NHA), Special Areas of Conservation (SAC) and Special Protection Areas
(SPA)
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4500
4000
1000
3500
800
3000
2500
600
2000
400
1500
1000
200
500
0
Cumulative installed capacity [MW]
Annual installed capacity [MW]
1200
0
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
Year
Annual onshore
Annual offshore
Cumulative Onshore
Cumulative Offshore
Figure 1.3: EirGrid ITC programme firm access connection schedule for wind generation
{Source: EirGrid [11]}
1.1.4 Regulatory and support entities
Minister for Communication, Energy and Natural Resources
The Minister for Communication, Energy and Natural Resources is responsible for determining and
drafting legislation on energy policy in Ireland as well as the incentive mechanism for renewable
energy facilities [13]. The department also oversees the activities of the semi-state energy
companies and organisations such as ESB, Bord Gáis, SEAI, Bord na Móna, CER and EirGrid.
Minister for the Environment, Heritage and Local Government
The Minister for the Environment, Heritage and Local Government is responsible for planning
policy and legislation. For all onshore projects planning is administered by local planning
authorities with possible recourse to the Planning Appeals Board (An Board Pleanala) which sits
independent of government interference. The consenting process for offshore wind farms is
regulated in accordance with the Foreshore Acts 1933 – 2009 [14] following the latest of which
certain functions, including those relevant to the licensing procedure for offshore wind farms, were
transferred to the Minister for the Environment, Heritage and Local Government in January 2010
[15]. Previously licence approvals were conducted by the Minister for Agriculture, Fisheries and
Food.
Commission for Energy Regulation (CER)
Established in 1999 as Ireland began the liberalisation of its power sector, the Commission for
Energy Regulation is the independent regulator for the gas and electricity markets in Ireland. CER is
also responsible for regulating electricity supply prices to consumers from the semi-state company,
ESB Customer Supply, while sufficient competition is being established to allow full deregulation.
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Sustainable Energy Authority of Ireland (SEAI)
Established by the government in 2002, Sustainable Energy Ireland (now SEAI) is Ireland’s national
energy authority. SEAI conducts and supports research and analysis in the energy sector and
promotes and assists in the development of renewable energy and implementation of energy
efficiency measures [16].
1.1.5 Principal semi-state commercial entities
EirGrid
EirGrid is the state-owned licenced national transmission system operator (TSO) in Ireland and is
the owner of System Operator Northern Ireland (SONI), the licenced TSO in Northern Ireland [17].
EirGrid is also the owner of Single Electricity Market Operator (SEMO) which operates the Single
Electricity Market (SEM) for the entire island of Ireland [17]. The Energy White Paper of 2007
outlined that transfer of the transmission system assets from ESB Networks to EirGrid would take
place by end 2008 although this has yet to occur. EirGrid is responsible for the development of the
transmission system and manages connection offers to renewable generators of over 20 MW in
capacity.
Electricity Supply Board (ESB)
ESB is the former monopoly utility for electricity generation and supply in Ireland. It remains a
semi-state body acting as a commercial entity in the liberalised electricity markets but owned by
the state and having its retail tariff regulated by the CER. ESB consists of a number of sub-entities
which operate largely independently. These include:



ESB International (ESBI), which operates generation facilities both domestically and
internationally in the deregulated power generation market;
ESB Customer Supply, which operates in the electricity retail market where their customer
tariffs remain regulated by the CER while sufficient competition is established;
ESB Networks, which owns and operates distribution networks and performs meter reading
services. ESB Networks is also responsible for the connection of renewable energy
generators of less than 20 MW capacity to the distribution network.
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1.2 Irish Electricity Market
1.2.1 Liberalisation and creation of the Single Electricity Market (SEM)
1999/2000 – Initial liberalisation of the Irish electricity market
Market reform towards a liberalised Irish electricity market began with the Electricity Regulations
Act 1999 and the European Communities Internal Market in Electricity Regulation of 2000 [18]. In
line with these developments an independent regulator of the new market was established, the
Commission for Energy Regulation (CER) as well as a Transmission System Operator (TSO), called
EirGrid, which became fully independent in 2006 [19].
From 1999 to 2007 Ireland operated a bilateral trading wholesale market with ESB Power
Generation, the incumbent semi-state entity, balancing any un-contracted energy demand. Due to
its dominant position in the market for this period ESB had both its generation and retail prices
tightly regulated.
2005/2006 – Unbundling of ESB’s portfolio
Regulated division of ESB’s portfolio of interests was undertaken in earnest in 2005/2006. ESB
Public Electricity Supplier (ESB PES) and ESB Power Generation (ESBPG) received electricity supply
and generation licences respectively from CER. These businesses were separated from ESB
Networks which in turn comprised of two divisions; distribution network operator (DSO), and
owner of the transmission system assets (now operated by a fully independent EirGrid) whose legal
and accounting procedures were required to be separated. Given the dominant position of the
retail and generation businesses within their respective markets, under the Bulk Power Agreement
(BPA) of 2000, the CER regulated the sale of electricity from ESB’s generation business to ESB’s
supply business [20]. However proactive divestment of ESB’s generation portfolio was agreed
between the CER and ESB in 2006 [20] and by the time the Single Electricity Market (SEM) went live
in November 2007 (see below) ESB PG no longer had its revenues regulated.
2007 – Creation of the Single Electricity Market (SEM)
The Single Electricity Market (SEM) for the island of Ireland began with a memorandum of
understanding signed in 2004 between the CER and the Northern Ireland Authority for Utility
Regulation (NIAUR). The SEM Establishment Programme managed by EirGrid and SONI (System
Operator for Northern Ireland) commenced in 2005, and the SEM went live in November 2007 [21].
The Single Electricity Market Operator (SEMO) administers the market and constitutes a joint
venture between EirGrid plc and SONI Ltd.
It should be noted that while under the SEM, the CER no longer regulates ESB’s generating
revenues, due to their sustained dominance in the retail market, ESB PES (also called ESB Customer
Supply) still has regulated customer tariffs.
1.2.2 Electricity market structure and pricing
The SEM utilises a gross mandatory pool market system with a capacity payment mechanism and
harmonised all-island arrangements for ancillary services [21]. No bilateral trading of energy takes
place.
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Generators bid into a central pool and a market clearing price, or system marginal price (SMP), is
established for the marginal generator against the market schedule. In order to incentivise an
efficient portfolio of generation plant the actual payment made to generators is calculated as
follows [24]:
GP = (SMP – BP).MSQ + BP.DQ
Where:
GP
SMP
BP
DQ
MSQ
=
=
=
=
=
Payment to generators;
System marginal price;
Bid price;
Dispatch quantity; and
market schedule quantity.
From the above equation it can be seen that, assuming an economically rational bid at the
marginal cost of production, generators receive their production costs (BP.DQ) plus an “inframarginal” rent in order to cover the fixed costs and provide a profit. It is noted that an “SMP Uplift”
mechanism is also calculated and applied to the “shadow price” (estimated normal incremental
operating cost), to allow generators to cover start-up and no-load costs [22]. The calculation
mechanism is designed to minimise deviation from the lowest revenue solution and minimise
deviation from the shadow price schedule, thereby avoid distorting underlying economic signals
[23]. The formula parameters for the Uplift mechanism are calculated and consulted on by the
SEMO on an annual basis in advance of their implementation.
Further revenue is derived from the Capacity Payment Mechanism (CPM). This is calculated via the
use of an annual “Pot” determined as the fixed cost of a “Best New Entrant Peaking Plant” (BNE
Peaker) multiplied by the capacity by volume judged to be required to meet adequacy standards.
This sum is then collected from suppliers and paid to generators in accordance with the rules of the
Trading and Settlement Code.
It is noted that the design of the market schedule incorporates modelling for generator dynamics
and transmission capacity to ensure the real-world dispatch can be achieved as designated.
However current design allowing generators with non-firm access dispatched above their firm
access quantity (FAQ) to access the market schedule at their dispatched quantity, does allow the
possibility of inefficient appropriation of infra-marginal rents [24]. This is due to non-firm access
generators behind an export constraint being included in the market schedule and receiving an
infra-marginal rent despite being constrained-off. Meanwhile a generator on the import side of the
constraint is constrained-on but only receives the bid price (BP.DQ) as it was not included in the
market schedule. In order for the generator on the import side of the constraint to make a return it
would need to have inflated production costs, i.e. a peaking plant. However this could result in
incentivising over-construction of peaking plant, leading to an inefficient portfolio of generation
plant [24].
Other related issues with the current payment mechanism include whether flexible generators
(which will become increasingly necessary as the volume of variable-output renewables on the grid
increases) are rewarded adequately, particularly when they have not been included in the market
schedule. General depression of prices by the inclusion of low cost of production but constrainedoff non-firm access plant in the market schedule, and the general incentive to build generators
unable to dispatch, are also current concerns.
The SEMO recently published a position paper on a consultation addressing options for dealing
with these issues as well as others including curtailment, principles of dispatch (noted in Section
3.5), the construction of the market schedule and the treatment of variable price takers in the
market schedule [25]. The outcome of this process will have significant implications for the level of
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future incentives to construct wind powered generation in Ireland. At the time of writing (January
2011) a final position paper on these issues is expected imminently from SEMO.
1.2.3 Impact of wind integration
In 2009 the Regulatory Authorities (RAs) of the SEM conducted an analysis of the “Impact of high
levels of wind penetration in 2020 on the single electricity market” [26]. The report modelled five
theoretical generation portfolios for Ireland in 2020 with three capacity levels of wind (one at 2 GW,
three at 4 GW and one at 6 GW). The central level of 4 GW was modelled with three differing
portfolios of conventional generation.
The model was based on the unconstrained market and thus had notable limitations with respect
to assuming perfect foresight, and therefore not modelling constraint costs associated with
deviations between schedule and dispatch, and costs associated with ancillary services.
Nevertheless a number of significant conclusions were identified:

Under the majority of scenarios the annual average SMP was reduced due to the
downward pressure of zero marginal cost wind generation. Nevertheless this finding did
depend upon the portfolio of complementary conventional base-load and peaking plant
assumed.

Under the central scenario for future fuel prices the total sum of fixed and variable costs for
all Irish electricity generation actually reduced as wind penetration increased for most
portfolio choices. Nevertheless it was noted the central scenario fossil fuel costs were
based on a time of historically high prices in March 2008, subsequent to which a significant
price drop occurred, bringing prices comparable to the RA’s “low fuel scenario”. Under this
scenario increased wind penetration resulted in marginally increased total generation
costs.

The net effect on CO2 emissions with increased wind penetration depends upon the
complementary generation portfolio that exists.

Price volatility as indicated by the standard deviation in the SMP rises with respect to 2009
levels. This is before considering the effects that assuming perfect foresight and not
accounting for system constraints and ancillary services might have on the results.

Negative prices were not observed for any of the generation portfolios although that with
the highest level of wind penetration did see prices close to zero.

Electricity export through the interconnectors only began to occur in limited volumes
under the high wind penetration scenario.
1.2.4 Interconnection and implications of coupling arrangements
Impact of high wind penetration levels in UK and Ireland
A further report conducted in 2009 by Pöyry Energy Consultants assessed the effect of high levels
of wind penetration on both the Irish and UK electricity markets and interaction therein [27]. The
report assumed 6 to 8 GW of wind installed in Ireland and 35 to 45 GW in the UK in the year 2030.
Principal findings included:

Potential for periods of negative prices in both markets at times of extreme weather, and in
greater number in the Irish market.
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
More frequent and extreme price peaks, although this effect was not as pronounced as in
the UK due to the Capacity Payment Mechanism with the Irish market design, as adequate
incentive for continued investment in peaking plant in Ireland should persist.

For Ireland, an “almost critical” importance of interconnection with the UK, allowing for
substantial export opportunity during high wind periods. It is noted however that such
interconnection does mean the more extreme price spikes in the UK market, due to its
design, will filter to some extent into the Irish market.

An expected need for incentives to dispatch-off wind in the Irish market, and other market
rule changes for dealing with divergence between market schedule and dispatch to
adequately reward flexibility.

An expected manageable increase in reserve requirements.
While the Pöyry report looks specifically at a high wind penetration scenario in both the UK and
Ireland, the findings do show that as wind capacity rises beyond the levels outlined in Gate 3 and
required to meet Ireland’s 2020 renewables targets, the role of interconnection with the UK and
potentially elsewhere becomes much more critical to the viability of ongoing growth of the wind
sector in Ireland. This point is of particular importance to large proposed offshore developments
currently outside of Gate 3 and their potential role in creating a renewable energy export industry
in Ireland.
European initiatives towards a single electricity market
Ireland is included in the France-UK-Ireland (FUI) region under the Electricity Regional Initiative
(ERI) launched in 2006 by the European Regulators Group for Electricity and Gas (ERGEG). The
ERGEG is the European Commission’s advisory body on internal energy market issues set up by a
European Commission Decision (2003/796/EC) [28].
The regional groupings, of which FUI is one of seven in total, deal with issues surrounding
harmonisation and enhancing congestion management on interconnections, harmonising
regional market transparency, and developing balancing market exchanges at borders. These
initiatives are intended to form an interim step towards creating a single EU electricity market [28].
Measures thus far have largely been undertaken in a voluntary manner, however following
adoption of the “Third Package” of energy liberalisation legislation in 2009 there will be
transformation of the Regional Initiatives to a context of binding and enforceable rules [28].
While not undertaken as part of the FUI initiative, the SEM in Ireland covering two jurisdictions has
been noted by the ERGEG as a strong example of cooperation between regulatory bodies and
political commitment to market integration [28].
Given the potential importance of the electricity export market to the growth of offshore wind in
Ireland, together with the prospects of offshore mesh grids with multiple interconnection routes
between nations, such harmonisation of electricity markets in Europe could play an important role
in the future viability of Irish offshore wind growth.
North Sea grid
There is considerable interest at European level in substantial increases in interconnection capacity
between Member States. This interest is primarily related to the drive to increase competition in
electricity markets. However, it is also clear that interconnection increases the opportunities for
renewables, and reduces the costs of integrating variable renewables. Recent studies at European
level [29][30] have considered very high renewables penetration in Europe, based largely on wind
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in the north and solar in the south, and in North Africa, and showed that the costs of the substantial
transmission reinforcement required need not be prohibitive.
Interconnections around and across the North Sea are of particular interest, because of the large
offshore wind resource, the onshore wind resource in Scotland and Ireland, and the reservoir hydro
in Scandinavia. The North Seas Offshore Grid Initiative was established by Norway and nine
Member States including Ireland. A Memorandum of Understanding was signed on 3 December
2010.
Eirgrid is known to be conducting market modelling work for ENTSO-E, in conjunction with other
European countries, to identify additional interconnection opportunities for the North Sea in 2020.
Eirgrid is also undertaking technical studies on the best means of combining connections for
offshore wind farms in the Irish Sea with interconnections to the UK and France.
Technical issues of interconnections are considered further in Section 3.
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March 2011
OFFSHORE WIND AND ENERGY RESOURCE
2.1 Approach and Assumptions
In order to estimate the potential offshore wind resource in the Irish EEZ (Exclusive Economic
Zone), the following process has been adopted:



Production of a wind resource map covering the whole EEZ showing annual mean wind
speeds at a representative hub height
Derivation of the characteristics of a representative generic offshore wind turbine, in order to
calculate the potential energy production
Derivation of technical limitations on deployment, namely:

Bathymetry (water depth)

Restricted areas (military, port approaches)

Restrictive areas (busy shipping lanes)
2.1.1 Wind map
Two primary sources were used to produce a wind map of the Irish EEZ: satellite scatterometer data
was used for areas far from shore; and the wind atlas created for SEAI by Truewind and ESBI was
used for near-shore areas (within about 25 km of the coast) [31]. This wind atlas was created using
mesoscale modelling calibrated with historic wind measurement records over a period of at least
10 years. Being designed primarily for onshore wind resource characterisation, it is subject to
increased levels of uncertainty in offshore regions. Nevertheless, it is considered that the
uncertainty in mesoscale modelling of coastal regions is less than that of satellite scatterometer
measurements in these regions. For a technical report detailing the wind atlas creation, see [32].
Further from the shore, ERS satellite scatterometer data were used. The ERS-1 satellite was
launched in July 1991, and was equipped amongst other sensors, with a scatterometer designed to
measure wind speed to a target accuracy of +/- 2 m/s. The width of the band over which the
instrument operates (known as the swath) is 500km for the ERS-1 scatterometer. Wind vectors are
resolved to a nominal resolution of 50km, although measurements are taken every 25km within
the Swath. ERS-2 was launched as the successor to ERS-1 in April 1995 and was equipped with an
identical wind scatterometer. Data from both these satellites have been combined to give a near
continuous record from 1991 to 2000.
Given the swath width of ERS-1 and 2 and their repeat cycle of 35 days, the ERS data yields an
approximate average of 1 measurement every 3-14 days at any given location. The intermittency of
Earth Observation data for any one location means that even aggregated data over many years
would fail to adequately capture the characteristics of the wind climate in an absolute sense. In
addition, significant question marks remain over the absolute accuracy of each individual
measurement given inherent uncertainties associated with the technique. In particular,
scatterometer measurements of wind speed are known to be sensitive to the effects of rain and
spray. Furthermore, the empirically derived relationships between backscatter intensity and wind
speed are subject to a significant degree of uncertainty due, in no small measure, to the relatively
poor quality of the observation data utilised.
Despite these uncertainties, the ERS data are generally held to be appropriate for measuring
relative trends. Having extracted data over the Irish EEZ area, the resulting wind map was
calibrated against the BERR Renewable Atlas [33]. This atlas, covering the UK EEZ, gives annual
mean wind speeds at 100m, on a variable resolution depending on distance to shore. Due to the
proximity of the data sets, a number of overlapping points were obtained to the North of Northern
Ireland and off the coast of Cornwall. The difference in wind speeds between these two areas
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allowed a correlation to be derived, Figure 2.1. The two clusters of values can clearly be seen,
representing the two areas of overlap, with points lying near to the shore removed, due to
increased uncertainty in the scatterometer data in these areas. The ERS data could not be
calibrated to the SEAI wind atlas, as the near-shore region covered by this atlas is the area in which
the ERS data are most uncertain.
12.00
11.50
BERR Wind Speed
11.00
y = 8.83x + 2.00
10.50
2
R = 0.97
10.00
9.50
9.00
Annual Mean Wind Speed (100m)
8.50
Linear Best Fit
8.00
0.80
0.85
0.90
0.95
1.00
1.05
1.10
1.15
ERS Data Values
Figure 2.1: Correlation between ERS scatterometer data and BERR Renewable Atlas for wind
speed at 100m above MSL
Once the satellite data had been calibrated, the spatial resolution of the data was increased to
smooth the resulting wind map. This was performed using a process of distance-weighted
averaging for each point at the desired resolution. The grid spacing was reduced from around 45
km to 5 km. Any remaining gaps between the satellite measurement data offshore and the SEAI
wind atlas near shore were filled using a similar process of distance weighted averaging between
the two data sets. The resulting wind map is shown in Figure 2.2.
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Figure 2.2: Wind map of the Irish EEZ – 100m above MSL
2.1.2 Power production
For a first approximation, a 5 MW wind turbine has been assumed, with rotor diameter of 150 m
and a hub height of 100 m. This is similar to the specifications of certain offshore turbines available
today, and is assumed to be reasonably representative of the current and future commercial
market for offshore wind turbine technology. Furthermore, it has been assumed that an
approximate optimal wind farm density is 5 MW per km2, equating to 1 km separation between
turbines, or 8 rotor diameters. This is comparable with offshore wind projects completed to date.
Using common values for other turbine parameters, such as tip speed, a generic power curve may
be produced. This is shown in Figure 2.3.
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6,000 kW
5,000 kW
Power
4,000 kW
3,000 kW
2,000 kW
1,000 kW
0 kW
m/s
5 m/s
10 m/s
15 m/s
20 m/s
25 m/s
30 m/s
35 m/s
Wind Speed [m/s]
Figure 2.3: Generic 5 MW (150 m rotor) wind turbine power curve
The wind climate is assumed to conform to a Rayleigh distribution – this allows the wind speed
distribution to be calculated from a single parameter, i.e. mean wind speed. This can be multiplied
with the power curve to give the expected gross power output from a single turbine at each given
mean wind speed. The power output was multiplied by the number of hours in a year (8760), and
reduced by the assumed loss factors detailed Table 2.1 below. This gives an overall reduction
factor of 83.8%.
Loss Factor
As Efficiency
Availability
95%
Proportion of time turbine is unable to produce output; covers
breakdowns, maintenance etc.
Electrical Losses
99%
Only to offshore substation; not taking into account transmission and
conversion losses from the substation onwards
Array Efficiency
90%
Average losses for all turbines in a wind park due to effects of
neighbouring turbines on wind flow
Other Losses
99%
Including blade surface deterioration, high wind hysteresis etc.
Total
Comments
83.8%
Table 2.1: Assumed loss factors
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2.1.3 Bathymetry
The GEBCO 1-minute world bathymetry dataset [34] was queried to derive banded areas of water
depth, corresponding to current and future zones of technically potential offshore development.
The zones in Table 2.2 have been grouped on the basis of current and emerging foundation
technology:
Depth Range
Development Potential
0 – 50 m
Current fixed foundation technology limits
50 – 100 m
Future fixed foundations and selected floating foundation technologies
100 – 500 m
Current prototype floating foundation technology applications
500 – 1500 m
Future floating foundation application – existing installation technology
1500 m+
Future floating foundation application – new technology development
Table 2.2: Offshore development zones split by water depth
For graphics displaying the annual mean wind speed in the various zones, see Appendix 1.
2.1.4 Spatial limitations
There are numerous other sea uses which preclude the development of offshore wind energy,
ranging from the minor (e.g. shipwrecks) to the major (e.g. military exclusion zones). For the scope
of this report, it is impractical to attempt to eliminate all such areas; this level of analysis would be
carried out at a national/regional level through Strategic Environmental Assessment and by
individual developers performing Environmental Impact Assessments (EIAs) during the site-finding
and consenting phase of a project. A Strategic Environmental Assessment has been produced for
much of the Irish EEZ as part of the Offshore Renewable Energy Development Plan (OREDP) for
Ireland [35].
A number of the more obvious spatial constraints have been included however. The largest of
these is the busy shipping routes between major ports. While the presence of shipping does not
absolutely rule out the development of wind parks, it is certainly a barrier that must be overcome.
In some cases, ship routes may be deviated to avoid the wind development; in many cases,
however, it is possible that wind project applications would not succeed if they were overly
disruptive to shipping traffic. For this reason, a 70% reduction in development was applied to the
areas identified as having major shipping traffic. Shipping routes, based on the COAST database,
were obtained from [36], Figure 2.4.
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Figure 2.4: Major shipping routes identified in the Irish EEZ
Other major areas of restriction to offshore wind development that were considered include
military practice/danger zones, subsea cables and gas pipelines, and areas of shipping and marine
traffic and port approaches, Figure 2.5. These data were provided by SEAI, based on the Irish wind
atlas [31]. These regions were assumed to be no-go areas for offshore wind.
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Figure 2.5: Restricted-use sea areas around Ireland
2.2 Wind Energy Resource
Taking the above approach and methodology, the baseline offshore wind resource for the Irish EEZ
was calculated. It should be noted that these figures should be treated with caution, and are not
representative of realistic development potential. There are numerous technical, political and
economic constraints on offshore wind siting, some of which are listed at the end of this section.
Most of these restrictions are outside the scope of this investigation, and should be dealt with via
Strategic Environmental Assessment (e.g. government-led) and by the Environmental Impact
Assessment (at a developer level).
Table 2.3 shows the initial wind resource estimate, should no limitations or restrictions be taken
into account. Table 2.4 shows the resource estimate after subtracting the following restricted
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regions: Department of Defence danger/practice zones; Department of Marine shipping traffic
zones; navigation channels; and subsea cables and gas pipelines, Figure 2.5. Table 2.5 shows the
resource after taking account of these restrictions, and also applying a 70% reduction in
development in areas identified as major shipping routes, Figure 2.4.
Available Area
[km2]
Installed Capacity2
[GW]
Annual Energy
Production [TWh]3
0m – 50m
20,370
102
658
50m – 100m
47,680
238
1,627
100m – 500m
124,550
623
4,321
500m – 1500m
58,400
292
2,035
1500m+
162,250
811
5,672
Entire EEZ
413,250
2,066
14,313
Water Depth Range
1. Figures may not sum due to rounding
2. Installed capacity based on 5 MW/km2; see Section 2.1 Approach and Assumptions for details
3. TWh = terawatt-hour, i.e. 1012 watt-hours, or 1000 GWh
Table 2.3: Baseline wind resource without spatial restrictions
Available Area
[km2]
Installed Capacity2
[GW]
Annual Energy
Production [TWh]3
0m – 50m
18,360
92
594
50m – 100m
45,380
227
1,549
100m – 500m
124,530
623
4,320
500m – 1500m
58,400
292
2,035
1500m+
162,250
811
5,672
Entire EEZ
408,930
2,045
14,171
Water Depth Range
1. Figures may not sum due to rounding
2. Installed capacity based on 5 MW/km2; see Section 2.1 Approach and Assumptions for details
3. TWh = terawatt-hour, i.e. 1012 watt-hours, or 1000 GWh
Table 2.4: Baseline wind resource accounting for selected spatial restrictions
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Available Area
[km2]
Installed Capacity2
[GW]
Annual Energy
Production [TWh]3
0m – 50m
15,510
78
502
50m – 100m
35,650
178
1,221
100m – 500m
123,550
618
4,287
500m – 1500m
58,350
292
2,034
1500m+
161,150
806
5,633
Entire EEZ
394,200
1,971
13,675
Water Depth Range
1. Figures may not sum due to rounding
2. Installed capacity based on 5 MW/km2; see Section 2.1 Approach and Assumptions for details
3. TWh = terawatt-hour, i.e. 1012 watt-hours, or 1000 GWh
Table 2.5: Baseline wind resource accounting for selected spatial restrictions and major
shipping routes
2.2.1 Constraints not considered
Whilst various high-level constraints have been considered within this resource assessment,
numerous other project-specific constraints, which will ultimately dictate the potential or viability
of a site, have been omitted. Some of these constraints have been quantified on a national level in
the OREDP strategic environmental assessment (SEA) [35]. Preliminary findings from this SEA
suggest an opportunity for a maximum of approximately 12.5GW of conventional fixed-structure
capacity and a further 27GW of floating turbine capacity with minimal negative environmental
impact. However, the OREDP SEA has been limited to up to 200m water depth and hence should
not be used to assess the potential for deep sea floating technologies. The constraints identified in
the OREDP SEA result in a potential of approximately 10% of the capacity identified in Table 2.5 in
less than 200m water depth.
Constraints may be divided into two primary categories; social / environmental constraints and
techno-economic constraints. Social and environmental constraints are generally associated with
consenting issues relating to the potential impact of the project or supporting infrastructure on the
local environment and population. Typically such consenting issues cannot be solved with
increased expenditure except where compensation to local communities or businesses becomes
an option. Social and environmental constraints may include:

Economic constraints;

Effects on employment and the local economy

Effects on leisure pursuits

Effects on marine fisheries and other users of the sea

Environmental - onshore

Coastal habitats and species

Sediment transport, long-shore drift, geomorphology, disturbance at cable
landfall

Proximity of protected areas
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



March 2011
Bird migratory routes or feeding grounds etc
Archaeological heritage
Visual impact
Noise, vibration, lighting and the effects of these on wildlife, view etc

Environmental - offshore

Marine habitats and benthic (seabed) communities

Bathymetry, sediment transport paths, bedforms, scouring, mixing, turbidity,
changes in wave or tidal current characteristics

Water quality and pollution incidents during construction and maintenance

Designated areas and proximity of protected areas

Fish resources, migration patterns, nursery areas

Birds – distribution, disturbance, mortality

Archaeological heritage (e.g. ship wrecks etc)

Visual impact

Marine mammals – distribution, disturbance, displacement, impacts of noise and
vibration

Noise, vibration, lighting and turbine installation

Social issues

Effects on employment (other than the purely economic)

Effects of environmental changes on local residents

Health and safety of the workforce, other users of the sea and members of the
public

Sea and air navigation
There are also a variety of techno-economic constraints not included in the above assessment,
which are likely to impact on the number of projects which prove ultimately viable. It should be
noted that, unlike consenting constraints, most of these issues can be resolved with greater
budget, but that often such an increase will render the project uneconomic or encumbered with
unacceptable residual risks. Some example techno-economic constraints are listed as follows:

Grid infrastructure

Proximity of connection point to site

Capacity at connection point

Connection windows and current waiting list

Sea bed conditions

Mobility of sediment and likelihood of scour

Sediment or rock technical characteristics (to foundation depth)

Variation in depth across proposed site

Viability of cable burial

Spatial constraints

Underwater obstacles (pipelines, cables, unexploded ordnance etc)

Dredging areas

Shipping routes

Civil or military radar zones

Military practice and exercise areas

Oil and gas lease areas

Met Ocean conditions

Wave and current loading of proposed foundation structures

Height of 50-year waves
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
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Accessibility

Wave and current limitations on access during construction and maintenance

Proximity of viable construction and O&M ports
2.3 Conclusion
It can be concluded from Table 2.5 that, even with very conservative allowances for social and
environmental constraints, there is an enormous offshore wind resource in the Irish EEZ, even
within 50 m water depth. Therefore the dominant limitation on the extent to which this resource is
exploited is cost.
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3
March 2011
ELECTRICITY NETWORK ISSUES
3.1 Background
This section covers electricity network and connection issues relevant to offshore wind in Ireland.
Electricity market issues are covered in Section 1.
EirGrid runs the transmission system, i.e. from 110 kV upwards, and it can be assumed that all new
offshore wind projects will be transmission-connected. It is technically feasible that smaller
offshore projects could be connected to the distribution system (38 kV and below), most likely with
multiple connections, but even in this case the technical issues would be mainly to do with the
transmission system.
EirGrid is deeply involved in the study of wind integration issues, due to the very high wind
penetration levels anticipated on the island of Ireland; most of these issues apply equally to
onshore and offshore wind. Wind generation is a major issue for planning and future operation of
the power system [38][39].
Figure 3.1 shows wind generation and system demand on 5 April 2010, the day of maximum
recorded wind generation to date2 [37]. Around 6am, wind penetration reaches 49%, and over the
full day wind supplies 38% of electricity demand. These are amongst the highest recorded figures
in the world, for large electricity systems.
Eirgrid system, 5 April 2010
System demand, wind generation [MW]
3500
3000
2500
2000
System Demand MW
Wind Generation MW
1500
1000
500
0
00:00
06:00
12:00
18:00
00:00
Time
2
A marginally higher figure was recorded on 28 October 2010, but occurred at a time of high electricity demand. These
figures are likely to be exceeded during winter 2010/11.
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Figure 3.1: EirGrid system demand and wind generation on day of maximum wind
generation
3.2 Transmission system development
In response to the strains on the electricity grid network, EirGrid has published its “Grid25”
document [42], a strategy document entailing plans for reinforcement of the electrical network,
including two new interconnectors, one northwards to Northern Ireland and one eastwards to
Wales, as well as longer term priorities and strategy until 2025. Work began on the construction of
the connection to Wales in summer 2010 and it is due to be completed by 2012.
Grid 25 is a strategy document, which sets out issues and possible solutions. EirGrid also has a
statutory obligation to publish annual Transmission Forecast Statements [39]. These Statements
are based on known applications for connections by generators, and anticipated changes in
electricity demand. They show the parts of the transmission system which are expected not to
conform to design standards in future, and which therefore require reinforcement or some other
mitigating actions. Both documents make the point that transmission reinforcements are likely to
take considerable time and may meet public opposition.
3.3 Grid Connection
EirGrid manages grid connection applications to the transmission system for renewable generators
via a group processing approach, with each group of applications received by a stated deadline
referred to as a “Gate”. This group approach replaced the earlier ‘first come first served’ principle,
because the volume of applications was such that treating each in isolation (i.e. effectively ignoring
possible interactions between projects) introduced major delays, uncertainty for applicants, and
was unlikely to lead to optimum network development.
The most recent set of offers under Gate 3 totalled close to 4 GW of new renewable generation
capacity. Given this additional capacity alone may be enough to meet Ireland’s 2020 renewable
generation targets and covers connection offers through to 2023, it is unclear if or when a further
“Gate 4” may take place.
However it is commonly believed that many connection applications were submitted for projects
for which very little development work has been done. There is currently no process to reward
projects which are making progress in other areas (financing, permitting, contracting), or to
penalise projects which are not demonstrating progress.
As is shown in Section 4, the timetable for grid connection of the Gate 3 projects is a major factor
affecting the rate at which wind generation will grow.
3.4 Charging
Charging for use of the transmission system is calculated on a marginal locational pricing basis.
This favours generation close to centres of demand.
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3.5 Principles of dispatch
To date under the 1999 Electricity Regulation Act, renewable energy generators have received
priority dispatch over fossil fuel generators [7]. Due to the relatively low levels of wind currently on
the grid (as compared to that envisaged for 2020) and the low marginal cost of wind generation,
this has so far not created any problems. However in consideration of potential high future
balancing costs if priority dispatch is treated as an absolute principal, a wide ranging consultation
process currently being conducted by the SEM Committee is reviewing the regulatory framework
for dispatch procedures [24][25]. A number of options were proposed and following receipt of
industry responses the SEM Committee recently issued a Proposed Position Paper in which it
indicates preference for an option of dispatching at an “effective price” such as cost minus the
value of lost load (VOLL). Nevertheless the document states that SEM’s position will be kept under
review while Directive 2009/8/EC is transposed into domestic law [25].
This issue is clearly important in the context of this report. It is helpful to consider it in two separate
timescales.
In the short term, wind generators with firm access will be recompensed for any constraints. Those
who choose to have non-firm access, i.e. by connecting in advance of transmission system
reinforcements, will risk constraint without compensation. This risk will depend greatly on
individual project circumstances and location, and cannot be quantified here. The energy volumes
constrained in this way could be a substantial risk to an individual project, but will be insignificant
in terms of meeting Ireland’s renewables targets.
In the long term, i.e. when all necessary transmission connections and reinforcement have been
built, constraint of wind generation is likely to occur occasionally because of a technical
requirement for some minimum capacity of conventional generation to be in operation, for
‘balancing’ or related issues. The ‘priority dispatch’ principle allows wind generation to be
constrained for reasons of system security. This limit is not yet well understood, and Ireland is likely
to be amongst the first systems to face it. Increased interconnection capacity to other systems
clearly influences this but does not remove the fundamental issue. It is these issues that the SEM
work mentioned above is primarily aimed at. EirGrid has recently commissioned ‘Facilitation of
Renewables’ studies to consider these issues [40]. The results show that to achieve the 2020
renewables targets for the island of Ireland, wind generation can expect constraints of the order of
5% of annual production. The result depends on the level of interconnection to other systems, and
on the assumed limit on instantaneous penetration (i.e. wind output as a fraction of total demand
plus exports).
Further, it is clear that total wind capacity in Ireland will eventually exceed minimum demand,
which means that, even if there were no technical constraints, for some part of the year there will
be no market for excess wind. Interconnection to other systems clearly reduces the effect, but it is
very unlikely that economics will justify building enough interconnection capacity to export during
rare extreme combinations of high wind production and very low electricity demand in Ireland.
3.6 Implications for offshore wind projects.
In principle, offshore wind projects are treated as for any other new generation, including onshore
wind. The major difference is that the projects are considerably larger than all onshore wind
projects.
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As things stand, all generation projects which are not already in the ‘Gate’ process will face major
delays in obtaining a connection. These delays may be extended if there is public opposition to
any EirGrid transmission reinforcement works that may be necessary.
3.7 Offshore wind for exporting electricity
3.7.1 Justification
Because of the issues discussed above, it has been suggested that offshore wind farms in Irish
waters could be developed primarily for exporting electricity to other countries. In practice this
would mean connection to the southern part of Britain, or to north-western France.
The advantages would be:

The timetable for construction would not be determined by the programmes for
connection application and transmission reinforcement in Ireland;

The projects would (in principle) not affect operation of the Irish electricity system, i.e.
would not contribute to balancing and scheduling problems

The projects would produce export earnings.
3.7.2 Issues
There are three main issues to be addressed:
Administrative
There is a significant administrative issue to be overcome: in order for the emissions savings to be
attributed to the importing country (which would be very important in order to achieve the
maximum economic benefit), a bilateral agreement between Governments would be necessary.
However, GLGH understands discussions have already been held between UK and ROI
governments, and a recent announcement by the UK Energy Minister makes it clear that the
Government intends that renewable generation outside UK territory will be admissible for the
purposes of the UK Renewables Obligation.
Timing
In order for this to be attractive to Governments in the UK or France, offshore projects in Irish
waters have to be available to meet the 2020 targets. This will be determined by:
 the time to get consents, which is entirely within the control of Irish government and
organisations;

and by the availability of finance, skilled contractors, vessels and other hardware for
offshore wind installation.
Costs
If the UK or France appears unlikely to meet their 2020 targets, and Irish offshore wind projects can
be delivered in time, then cost may not be the highest priority. In other circumstances, Irish
offshore wind will be competing against alternatives in the UK and France, including offshore wind.
Relative costs are not clear at this stage, though it should be noted that some sites in Irish waters
are closer to the UK, and in more benign conditions, than some UK Round 3 sites.
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3.7.3 Connection options
It should be noted that, if this option appeared attractive, there are several options for providing
the connection to the importing country.
The simplest would be a direct connection to the importing country. However, if the offshore wind
farm is relatively close to the Irish coast, almost certainly this would not be optimal. A connection
between the national electricity systems is likely to add significant additional value at relatively low
cost. If so, it would be necessary to reach technical and commercial agreement with EirGrid, in
order to prevent the connection to the EirGrid system being treated as a generator connection and
therefore falling within the Gate process.
The connection could be achieved either by a land-to-land interconnector, with the wind farm
being connected to the landfall point, or (more likely) by providing a connection from the wind
farm to both countries. Recent studies by EirGrid on optimal interconnections for offshore wind
farms and to neighbouring systems indicate that in many cases the latter option is preferable [41].
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4
March 2011
IRELAND’S OFFSHORE WIND MARKET DEVELOPMENT
4.1 European Context
As shown in Figure 4.1, at present almost all commercial offshore wind energy installations in the
world are located in European waters. Furthermore growth in the European offshore wind market
is likely to outpace the rest of the world for some years yet (with the exception of China, see Part B
Section 2). The supply chain dynamics of the offshore industry in Europe will have the greatest
impact on development in Ireland. This section therefore focuses on the four European markets
which have, or are set to have, a predominant influence on the overall development of offshore
wind energy in Europe.
Operational [2187 MW]
United Kingdom,
45%
Sweden, 7%
Norway, 0%
Netherlands,
11%
Ireland, 1%
Belgium, 1%
Germany, 3%
Denmark, 30%
Figure 4.1: Contribution, by Country, to European Offshore Wind Energy Capacity
In Denmark, a successful indigenous wind turbine industry along with generally high levels of
political support have been identified as the most important drivers for offshore wind. Denmark
has led the world in the development of offshore wind and has in place a relatively stable and
mature regulatory regime which has been achieved through simplification, centralisation and longterm strategic planning.
In Germany, the successful deployment and impending saturation of onshore wind has led to a
shift in political focus to offshore wind deployment. Highly ambitious plans are in place for
deployment over the next two decades with the feed-in tariff having been raised recently to levels
which generated a flurry of project transactions. The effects of the predominance of relatively
small companies in the offshore arena in Germany has delayed to a certain extent the initiation of
large scale construction of offshore wind farms; however the presence of several large European
utilities and developers with offshore wind experience elsewhere means the first projects are
expected to be on-line soon. It can be argued that the small developers did play a major role in
achieving a relatively high degree of consenting success.
In the Netherlands, offshore wind represents the most promising means of achieving significant
deployment of renewables given the limited potential for onshore wind capacity. However, given
that in the short-term the country is on track to achieve international commitments on climate
change, and the apparent high costs associated with necessary grid reinforcement works, political
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support for offshore wind remains questionable. In the absence of clear political support,
deployment will be limited and the necessary reforms to regulation will be difficult to implement.
In addition, the historical and ongoing instability and unnecessary complexity of incentive support
for renewable energy constitutes a significant barrier for the offshore wind industry in this country.
There are good prospects for offshore wind in the United Kingdom despite the much slower-thananticipated development of the industry. The strong level of political support for the technology
has been proven through successive rounds of concessionary awards, streamlining of the
consenting process and in 2009, the announcement of additional revenue support for offshore
wind projects. Access to the grid has been a significant barrier for some offshore wind projects.
The non-alignment of electricity regulation with government energy policy has been a problem.
Inherent deficiencies in a non-technologically differentiated RE certificate trading system have
been discussed in the context of experience in the UK where the cheapest renewable technology
(currently onshore wind) has dominated. In general, Government has been receptive to reform in
order to facilitate and encourage offshore wind power deployment.
Projection to 2020
Figure 4.2 shows a forecast of overall market growth for all European markets up to 2020. The
forecast is built up from a combination of known projects, based on GLGH’s own project database
and understanding of policy targets for longer term market development.
As can be seen from the figure, the European market itself is likely to be dominated by British
projects, although, with efforts to develop a British supply chain having met with mixed success
recently, the industry is likely to remain heavily dependent on German and Danish equipment
suppliers for the foreseeable future. Significant market contributions are also expected from
German and Dutch projects over the coming decade.
5,000
4,000
40
BE
35
DK
30
FR
25
3,000
20
15
2,000
Cumulative [GW]
Wind Farm Capacity (New
Installations) [MW]
6,000
10
1,000
5
0
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
0
Year
EI
ES
NO
SE
NL
DE
UK
Cumulative
Figure 4.2: Projected Growth in European Offshore Wind Energy Installations
4.2 Offshore Wind Policy Mechanisms and Measures in Ireland
Following is an overview of the principal mechanisms or measures currently in place, or being
undertaken, to support and administer renewable energy projects in Ireland and which are
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relevant to offshore wind projects. These measures fall into two broad categories; financial support
mechanisms, and spatial planning and construction permitting procedures. Grid issues are
discussed in Section 3.
4.2.1 Financial support mechanisms
Renewable Energy Feed-in Tariff scheme (REFIT)
As noted in Section 1, since 2006 Ireland has offered a feed-in tariff support mechanism “REFIT” to
wind generators and this represents the principal driver behind the recent development of
renewable generation. However, up until February 2008, offshore wind farms attracted the same
feed-in tariff as onshore wind farms, currently equal to €66/MWh (annual adjustment referenced to
consumer price index), payable over 15 years [9]. This level was clearly far too low to instigate the
commercialisation of the technology in Ireland.
In February 2008 the Irish Energy Minister announced a fixed feed-in tariff for offshore wind with a
reference price of €140/MWh, valid for the first 15 years of production. This support mechanism is
valid until 2024 although currently subject to state aid clearance from the EU [7].
A further balancing payment equivalent to 15 % of the reference feed-in tariff price for large
onshore wind (currently 15 % of €66.353/MWh = 0.99€c/kWh) is available in the SEM [36]. Initial
indications from developers suggest that this tariff level is not sufficient to move the existing
development pipeline of projects forward to construction.
Tax relief
Ireland offers Corporate Tax Relief for investment in renewable generation capped at a total of
50 % of the capital cost (excluding land) of a project net of grants, or €9.525 million, whichever is
the lesser [44].
4.2.2 Spatial planning and construction permitting
Foreshore planning
In Ireland, the consenting process for offshore wind farms is regulated in accordance with the
Foreshore Acts 1933 – 2009 [14], following the latest of which, certain functions - including those
relevant to the licensing procedure for Offshore Wind - were transferred to the Minister for the
Environment, Heritage and Local Government in January 2010 [15]. The process consists of two
main steps:
1
2
A foreshore licence, which assigns exclusive rights to the developer to perform an in-depth
site assessment within four years, and allows the developer legitimate expectations that it
will have priority with regard to the grant of a foreshore lease; and,
A foreshore lease, which assigns exclusive site development rights.
The purchase, or lease, of suitable land for the construction of an onshore substation to connect to
the electricity grid, is normally required prior to the grant of a foreshore lease.
Strategic Infrastructure
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The Strategic Infrastructure Act 2006 established a fast-track consenting process for certain
proposed development deemed of “strategic importance to the State”. The majority of TSO
infrastructure projects are included under this Act while proposed amendments to the threshold
level allowing major wind-energy developments to qualify are currently being considered [7]. It is
unclear at present whether permitting of offshore wind projects is likely to be included under the
Act in the future – it is noted some onshore wind farms have actually avoided inclusion due to the
upfront cost requirements [45].
Other regulatory and permitting arrangements
Prior to construction, a developer must also obtain a licence to construct a new generating station,
and a licence to generate electricity must be obtained prior to commencing electricity generation.
The two licences are issued by the CER.
There are no wind-industry-specific health and safety or certification requirements in Ireland.
However, as with all workplaces, wind farms must conform to the requirements of the Safety,
Health And Welfare At Work Act 2005.
4.3 Project Activities
4.3.1 Current market status
Ireland has a single offshore wind farm consisting of seven 3.6 MW wind turbines located on
Arklow Bank, 10 kilometres off the east coast. It was developed by Airtricity, in partnership with the
wind turbine supplier GE, and it was commissioned in 2004. At that time no offshore framework
existed in Ireland; hence, this can be considered to be a demonstration project for Ireland, as well
as for both parties involved. Plans for the subsequent phases of this project have been delayed,
awaiting the creation of a suitable framework with sufficient financial support to make offshore
wind viable; the overall project consent is for 500 MW.
In addition to Arklow Bank, there are five additional offshore wind farms currently proposed for
Irish waters. These are shown in Table 4.1, below:
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Developer
Capacity
(MW)
Arklow Bank 2
Scottish and Southern
Energy
500
Codling Wind
Park
JV (Fred. Olsen
Renewables and Treasury
Holdings)
Wind Farm
1,100
1,000
(extension)
Oriel Windfarm
Oriel Windfarm Ltd
330
Dublin Array
Saorgus Energy Ltd
520*
Skerd Rocks
Fuinneamh Sceirde
Teoranta
100
March 2011
Location
Approximately 10 km to the east of
Arklow
13 km off the east coast, between
Greystones and Wicklow
North west Irish Sea near Dundalk,
5.5 km from Cooley Point
10 km off the east coast, between
Dublin and Greystones
Off the west coast, around 14 km
southwest of Killkerin
Note *: Connection application under Gate 3 is for seven 52 MW phases totalling 364 MW
Sources: www.nowireland.ie; www.saorgus.com; www.fsteo.com; www.codlingwindpark.ie; www.orielwind.com
Table 4.1: Irish Offshore Wind Project Development Pipeline
None of the projects listed in Table 4.1 are nearing construction at the time of issuing this report.
This lack of current activity in the Irish offshore wind industry is due to a combination of factors
including obtaining a foreshore lease, grid connection, and project economics. Table 4.2 provides
an outline of the current permitting status, grid connection agreements and nominal
commencement of operation.
Foreshore Lease
Nominal1
Year of
Operation
Applied
Granted
Arklow Bank 2
-
Jan 2002
Not scheduled
2014
2016
Codling Phase 1
-
Nov 2005
Not scheduled
2013
2015
Codling Phase 2
Mar 2009
-
Not scheduled
2017
2019
Dublin Array 1
Jun 2009
-
2010-20132
2013
2015
Oriel
Feb 2007
-
2017-2018
2013
2015
Skerd Rocks
May 2008
-
2018-2020
2016
2018
Project
1
2
Nominal1
Year of
Construction
Gate 3
Schedule
Based upon published figures and/or anticipated timelines. These dates are subject to a large degree of uncertainty.
52 MW granted for 2010, then 312 MW granted for 2013
Table 4.2: Irish Offshore Wind Project Development Timeline
As can be seen, both Arklow Bank 2 and Codling Phase 1 wind farms have been granted a
foreshore lease, but are still awaiting a firm grid connection agreement from EirGrid. Given no
connection agreements have been granted under Gate 3 for these projects, it is unlikely that a firm
access connection will be scheduled before 2020. In order for these projects to go online
beforehand and service the Irish market, generators will have to connect on a non-firm access
basis. The viability of such an approach will depend upon individual project circumstances,
including location and availability of finance, as well as any revision of the principles of dispatch as
discussed in Section 3. Otherwise the only option for the developers will be to try to negotiate
export agreements to the UK either via direct connections (possibly with prior landfall on the Irish
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mainland in readiness for a future firm connection offer to the Irish grid), or through large new
interconnectors, such as the planned East-West Interconnector. The chances of the latter
alternative, however, are remote.
Meanwhile the Dublin Array 1, Oriel and Skerd Rocks projects are due to receive an offer of grid
connection under Gate 3, but are still awaiting a foreshore lease, without which these projects are
unable to progress significantly.
120
600
100
500
80
400
60
300
40
200
20
100
0
Year
20
20
20
19
20
18
20
17
20
16
20
15
20
14
20
13
20
12
20
11
20
10
0
Ireland
By Mean Water Depth
Cumulative capacity (MW)
Wind Farm Capacity (New
Installations) [MW]
From the timelines outlined in Table 4.2, an impression of the ramp up in construction of Irish
offshore wind energy plant may be estimated using an assumed probability of meeting these
targets. Figure 4.3 shows a graph of estimated capacity installation between 2010 and 2020. It
should be emphasised that this is based on a “Business-As-Usual” assumption regarding the
current political, financial and industry climate. Due to these current industry trends, GLGH has
assumed a low probability of construction and hence, out of the potential 3,394 MW listed in Table
4.1, GLGH estimates that unless a significant change in direction occurs, around 600 MW is likely to
be installed by 2020. This figure is broadly consistent with the “Non-Modelled Export Scenario” of
the NREAP and the “Low” Scenario outlined the SEA [7][35]. Both these sources also outline more
ambitious scenarios with greater offshore wind installation capacities dependent upon a
sufficiently favourable political and financial climate.
>75m
50-75m
40-50m
30-40m
20-30m
10-20m
0-10m
Cumulative
capacity (MW)
Figure 4.3: Estimated New Installation Timeline and Associated Water Depths
Based upon this estimated installation ramp-up, it is possible to assess the likely requirements for
vessels in order to install and maintain these projects. The bar chart in Figure 4.4 provides an
indication of the average number of large installation and maintenance vessels necessary to
support the projected activity. It should be noted that this graph illustrates average annual
demand, and does not capture instantaneous vessel requirement. Furthermore, smaller support
vessels and crew transfer vessels are not accounted for here.
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Industrial Development potential of offshore wind in Ireland
0.8
March 2011
Wind Turbine Repairs Vessel Demand
Wind Turbine Installation Vessel Demand
Support Structure Installation Vessels Demand
Geotechnical Survey Vessel Demand
Environmental & Geophysical Survey Vessel Demand
Ireland
0.7
Vessels
0.6
0.5
0.4
0.3
0.2
0.1
0
2010
2011
2012
2013
2014
2015
Year
2016
2017
2018
2019
2020
Figure 4.4: Projected Major Vessel Requirement to 2020
Clearly the ramp-up in installation estimated in Figure 4.3 and the subsequent vessel demand
projected in Figure 4.4 are speculative and will depend greatly on the probability figures which
have been applied to the pipeline of proposed projects, as well as government incentives and grid
connection opportunities as 2020 approaches.
4.4 Reasons for Failing to Meet the 2004 Targets
In 2004 [1], forecasts were made for the future expansion of offshore wind. From internal
knowledge, and discussions with the wind industry, GLGH believes the major reasons these
forecasts have not been achieved are as follows.
Economics
Capital costs of offshore wind projects have risen rather than fallen, and electricity purchase prices
are low in comparison to the UK and other European countries.
Consenting
As noted in previous sections, the consenting process is slow and complex.
Connection
The Gate process is dominated by onshore wind, which is cheaper and less risky than offshore
wind.
For these reasons, organisations interested in developing offshore wind find other EU countries
more attractive.
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Industrial Development potential of offshore wind in Ireland
5
March 2011
IDENTIFIED BARRIERS AND POSSIBLE DRIVERS
5.1 Drivers
Ireland’s agreed 2020 emissions target is the main driver for all renewables generation, though
there is also a significant political desire to reduce fuel imports.
It appears that Ireland is likely to meet or exceed the 2020 targets, principally through onshore
wind. It must be noted that there is a risk that many of the onshore wind projects currently in Gate
3 appear to have had relatively little development effort expended, and may not be developed on
time, or at all.
Additional drivers for offshore wind are:

The opportunity to gain for Ireland some employment and industrial development
benefits, if the development of offshore wind is managed. The alternative would be
piecemeal developments without an overall programme, which are likely to be constructed
on a ‘one-off’ basis, and therefore less likely to result in significant economic development
benefits for Ireland. In such a scenario it is possible Irish Sea projects operations and
maintenance activities may be served from UK ports.

Offshore wind is the renewable source which is most likely to be economic for direct export
of electricity to other countries.

The resource is very large.

Ireland already has two major international wind developers (Airtricity and Mainstream).
Developing and operating offshore wind farms in Irish waters would assist them to
compete for offshore wind farms elsewhere (though as these companies also have strong
organisations elsewhere, there is no guarantee that offshore wind development jobs would
locate in Ireland).

As it is typically sited away from populated areas, public acceptance can be easier to obtain.
If offshore wind is left to the post-2020 period (because Ireland can meet its obligations using other
renewables), other countries will have established offshore wind industries that are likely to get the
majority of the work.
5.2 Barriers
The main barriers are:

A perception of unattractive project economics. While the power purchase tariff is
comparable to other markets the peripheral nature of the Irish market, lack of scale,
requirement for developer to meet costs of grid connection upfront, and uncertainty
concerning grid and permitting issues (see below) render Irish projects relatively
unattractive compared to the UK in particular.

Grid connection process.

Lengthy consenting process.

Lack of clear policy direction and political will to remove these barriers.

No major established heavy engineering, shipbuilding or offshore oil & gas industries.
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Industrial Development potential of offshore wind in Ireland
6
March 2011
CONCLUSIONS
The main conclusions from this Section relevant to subsequent sections are:

The offshore wind resource in Irish waters is very large.

Ireland’s 2020 targets appear achievable without using offshore wind, principally by using
onshore wind, which is seen as cheaper and less risky. Possibly because of this, there is a
lack of political will to resolve the major barriers (see Section 5). However there is
substantial uncertainty regarding the viability of many of the onshore wind projects
currently in the Gate 3 pipeline and should significant delays and cancellations occur,
increased levels of offshore wind are likely to be required to meet the 40 % by 2020 target.

If offshore wind is seen as a ‘post 2020’ resource, it is likely that Ireland will not gain much
economic development benefit from establishment of elements of an offshore wind
industry, as other countries will already have established industries.

For offshore wind to be part of the ‘2020’ solution, strong political will is necessary to
resolve the major barriers of economics, grid connections and consenting.
Offshore wind projects specifically for export to the UK and France appear feasible and would
avoid the grid connection issue. However the relative economics of Irish Sea projects compared to
those in the UK Round 3 including consideration of resource, bathymetry and grid connection
options are not clear, and this is an area worth further investigation.
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Industrial Development potential of offshore wind in Ireland
March 2011
Part B. International Supply Chain
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Industrial Development potential of offshore wind in Ireland
1
March 2011
ANATOMY OF AN OFFSHORE WIND FARM
An offshore wind farm demands input from a large number of contractors and other stakeholders,
the various components and activities being presented in A Guide to an Offshore Wind Farm,
published by The Crown Estate [46]. A high level overview of the major phases in the value chain
from primary design through to decommissioning of an offshore wind farm is shown in Figure 1.1.
Figure 1.1: Overview of the value chain
It is important to appreciate the production volumes and levels of quality for the various
components, and to match those to each company’s own capabilities. Within a wind farm, there is
a diverse range of products and services, from project-specific bespoke-designed single items, to
multiple, mass-produced generic parts.
In terms of production volumes, quality and cost, the wind industry falls between the aerospace
and automotive industries, as shown in Figure 1.2, or perhaps agricultural / construction plant
manufacture. Conventional power industries tend to align more closely with the aerospace
business, in these respects.
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Industrial Development potential of offshore wind in Ireland
March 2011
Figure 1.2: Cost, quality, volume positioning
For wind, this is driven by the demands in terms of reliability (especially important offshore), as the
value of energy generated by a wind turbine through its lifetime will far exceed its capital cost.
Quality is also driven by the very high level of fatigue loading for components along the primary
load path, from the tip of the rotor blades to the toe of the foundation. During its operating life, a
wind turbine will experience over 108 primary fatigue load cycles, which exerts a significant
demand upon designs, materials, fabrication, assembly methods and monitoring.
When assessing supply chain opportunities and potential Irish capabilities one should consider not
only the products or services to be provided, but also when these would be required in the lifecycle
of an offshore wind project. The programme shown in Figure 1.3 indicates a more detailed
breakdown of the times and points when contractual negotiations and works are carried out in the
lead up to the operational date of an offshore wind project. This highlights at which point major
first tier contractors will be involved in tendering to projects, therefore at what point they will be
soliciting enquiries from their suppliers and at what point those orders will be required to be
fulfilled, in order for them to carry out fabrications and installations.
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Industrial Development potential of offshore wind in Ireland
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Operational
Date
PROJECT TIMELINE
7 Years before
Operational
PROJECT
Site Allocation
Environmental
Consents
Grid Connection
6 Years before
Operational
4 Years before
Operational
5 Years before
Operational
Application
3 Years before
Operational
2 Years before
Operational
Approval
Agreement
SURVEY & FEED
Geophysical
Geotechnical
"FEED" Study
PORT
Supply Contract
Preparatory Works
Construction/Marshalling
O&M Utilisation
FOUNDATIONS
Supply Contract
Design Work
Manufacture
Installation
WIND TURBINE
Supply Contract
Manufacture
Installation
Commisioning
O&M
OFFSHORE EXPORT
Supply Contract
Design Work
Manufacture
Installation
On-Site Testing
ARRAY CABLES
Supply Contract
Design Work
Manufacture
Installation
On-Site Testing
OFFSHORE SUBSupply Contract
Design Work
Manufacture
Installation
On-Site Testing
O&M
ONSHORE CABLE
Supply Contract
Design Work
Manufacture
Installation
On-Site Testing
ONSHORE SUBSupply Contract
Design Work
Manufacture
Installation
On-Site Testing
O&M
ITT
Contract
ITT
Contract
ITT
Contract
ITT
Contract
ITT
Contract
ITT
Contract
ITT
Contract
ITT
Contract
Figure 1.3: Project Implementation Programme
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1 Year before
Operational
46
Grid Available
Industrial Development potential of offshore wind in Ireland
2
March 2011
OFFSHORE WIND SUPPLY CHAIN
2.1 Background
To facilitate the rapid growth of wind turbine installations observed since the widespread
commercialisation of the onshore wind industry, the last decade has seen an equally large
expansion in the corresponding supply chain for equipment and services in the wind power sector.
By 2009 it was estimated that the European wind industry directly or indirectly employs around
192,000 people [47]. With the current globalisation of the onshore industry, and as the offshore
industry stands ready to fulfil predictions of similarly spectacular growth over the next one to two
decades, it is therefore of no surprise that governments around the world are looking at potential
ways to capture some of this expanding market.
High up-front costs and relatively low operational expenditure render wind farms capital-intensive
ventures. In addition the wind turbine generators (WTGs) themselves swallow 60 to 70 % of this
capital expenditure for onshore projects and around half when offshore. Denmark, Germany and
Spain have used their position as the early movers of the onshore wind industry in Europe to
become home to the world’s highest selling wind turbine suppliers and the bulk of the associated
supply chain. Markets which arrived later including the UK, Italy and France then imported most of
their supply chain requirements from these established players.
With the offshore industry poised to take off as indicated in Figure 2.1, there is an overdue
development of offshore-specific designs arriving on the market. The size of some of the
components used for offshore turbines, including rotor blades and towers, add incentive to reduce
transportation distances and build closer to site. Furthermore due to the greater balance of plant
(BoP) requirements for offshore projects such as foundations and cables, a greater proportion of
supply chain value rests beyond the wind turbine units than is the case for onshore projects. Given
the potential for this new offshore industry it is unsurprising that countries which missed out on
substantial supply chain capture during the initial onshore boom are seeking to capitalise this time
around.
9,000
60
BE
DK
8,000
FI
7,000
FR
EI
6,000
40
ES
5,000
30
4,000
Cumulative [GW]
Wind Farm Capacity (New Installations) [MW]
50
NO
SE
NL
DE
3,000
20
UK
CA
2,000
10
1,000
US
Other Europe
CN
0
20
2
9
20
1
8
20
1
7
20
1
6
20
1
5
20
1
4
20
1
3
20
1
2
20
1
20
1
20
1
1
0
0
0
Cumulative
Year
Figure 2.1: Forecast of global offshore wind farm capacity new installations to 2020
Garrad Hassan & Partners Ltd
{Source: GLGH}
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Industrial Development potential of offshore wind in Ireland
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The following sub-sections provide an overview of the main players in the wind industry supply
chain and describe the international industrial development of the offshore wind supply chain
historically and how this is set to change in the coming decade.
2.2 Developers and owners
2.2.1 Supply chain context
The European onshore wind industry boom coincided with tentative energy market liberalisation
policies being adopted across the continent. The industry has shifted from early pioneers
consisting of small scale community and farmer-based ventures in Denmark and Germany to
Gigawatt-scale portfolios owned by some of Europe’s large utilities, many of which have been
recently privatised or partially-privatised.
In general the development phase may be undertaken either by specialist developers who go on to
sell their sites prior to construction / just after construction, integrated independent power
producers (IPPs) or utilities with the necessary in-house expertise. The latter two of these along
with outside investors (both private and institutional in nature) also make up the ownership of
operating wind farms. The regional market strength of incumbent electricity generators and lower
technical barriers to entry have allowed the developer and owner landscape to shift and expand
alongside the geographical expansion of wind farm installations. Nevertheless after gaining
substantial experience in their domestic markets many of the larger IPPs and more renewablesdriven utilities are now looking to aggressively expand in the new markets of Eastern Europe and
offshore in Northern Europe. Given the scale of the investment necessary for offshore projects,
ownership during construction and operation is increasingly limited to large corporations, the
overwhelming majority being utilities and/or oil and gas majors.
2.2.2 Market overview
Figure 2.2, Figure 2.3 and Figure 2.4 present the size of development portfolios of the major
industry developers and owners.
Operational Offshore Wind Farms
Others, 501 MW, 21%
DONG, 738 MW, 30%
Eneco, 120 MW, 5%
EdF, 10 MW, 0%
Centrica, 191 MW, 8%
E.On, 293 MW, 12%
BARD, 5 MW, 0%
Vattenfall, 387 MW, 16%
RWE, 158 MW, 7%
SSE Renew ables, 25 MW,
1%
Figure 2.2: Operational Offshore Wind Farms – by Owner
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Under Construction Offshore Wind Farms
E.On, 212 MW, 9%
RWE, 252 MW, 11%
SSE Renew ables, 252 MW,
11%
Others, 1250 MW, 55%
Vattenfall, 300 MW, 13%
EnBW, 25 MW, 1%
Figure 2.3: Offshore Wind Farms under construction – by Owner
Contracted / Committed Offshore Wind Farms
Others, 559 MW, 18%
DONG, 652 MW, 21%
EdF, 42 MW, 1%
Centrica, 124 MW, 4%
E.On, 189 MW, 6%
BARD, 600 MW, 19%
Vattenfall, 150 MW, 5%
SSE Renew ables, 92 MW,
3%
RWE, 674 MW, 22%
Figure 2.4: Offshore Wind Farms contracted – by Owner
An overview of each of the main developers is presented in Appendix 2.
2.3 Wind turbine suppliers
2.3.1 Supply chain context
Following substantial optimism over the offshore industry during the early part of the last decade,
slower growth rates than expected occurred in the years 2003 to 2008. This was due to a number
of factors, with perhaps the main factor being that the forecasts themselves were used for industry
lobbying for effective support measures, and when those support measures were not fully
implemented, the forecasts were not achievable. In the UK that trend has changed in the past two
years with delivery meeting predictions.
The slow initial growth, relative high risk of supplying offshore wind projects and continued
onshore boom led to a lack of incentive for turbine manufacturers to supply to the offshore market
and expedite development of offshore-specific wind turbine designs. Indeed three key industry
events reduced competitive pressure within the offshore wind turbine supply market to a period
when Siemens Wind Power was effectively the single supplier for commercial scale projects. Firstly,
the merger of NEG Micon with Vestas in late 2003 ultimately eliminated the offshore-specific
product line of the former, given the obvious overlap with Vestas' own product development
programme. Secondly, the absence of GE Wind Energy from the offshore turbine supply market
since 2004 removed the world's second largest supplier of wind turbines from the game. Then in
2007, the temporary withdrawal from the market of Vestas' principal offering for offshore projects
(the V90 model) due to technical difficulties relating to the gearbox [48] reduced supply
competition to an all-time low during the period mid-2007 to mid-2008.
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Industrial Development potential of offshore wind in Ireland
March 2011
However with the renewed confidence in the offshore industry, and signs of sustained activity in
the UK, interest in supplying turbines to the offshore market has reignited. Figure 2.5 illustrates the
anticipated future trend of a bifurcation or decoupling of the supply market, with offshore specific
products and eventually, specialist offshore suppliers becoming increasingly prevalent. Such a
trend should mitigate the historical 'resource diversion' suffered by the offshore wind industry,
particularly as suppliers commit to significant investment in bespoke production facilities. There is
some evidence for this with all three suppliers with near-market products in the 5-6 MW range
commissioning substantial production facilities in the last 2 years. Whilst production is yet to rampup to serial levels at these sites (all in northern Germany), the development signals that this critical
part of the supply chain now has the confidence in long-term sustainable markets.
Onshore
Acciona
GE (12.4%)
Wind
Turbine
Sinovel
Vestas
Gamesa
Nordex
Offshore
Wind
Turbine
Clipper
Multibrid
3MW
M5000
Britannia
Potential New
Entrants &
V90
V80
GE
Products
Siemens
N90
REpower (3.4%)
Enercon
5M
Vestas
Darwind
Siemens (5.9%)
SWT-2.3-93
Suzlon
SWT-3.6-107
Goldwind
SWT-3.6-120
6M
BARD
V112–3.0MW
DD115
5.0
Market entry date
2007
2008
2009
2010
2011
2012
2013
2014
- Circles represent product offerings
- Bracketed percentages represent global market share in 2009 (Source: BTM Consult)
- Top 10 global suppliers (by market share) included only for onshore wind supply market, with exception of inclusion of
Nordex in place of Dongfang
Figure 2.5: Onshore-Offshore WTG market overlap and bifurcation
That even the new players to the offshore turbine supply industry have based themselves in
northern Germany indicates the strong pull of a readily available skilled workforce, existing
manufacturing capabilities and also the strategic location of German ports for serving North Sea
projects. However the scale of proposed development for the UK along with substantial political
support including a specific “Ports fund” has been enough to attract 5 turbine manufacturers; GE,
Siemens, Clipper, Mitsubishi Heavy Industries and Gamesa, to confirm plans for establishing UKbased manufacturing facilities [49][50][51][52][53], while the South Korean new entrant Doosan is
also reportedly planning to use the UK as their North Sea manufacturing base [54]. In all cases, final
investment decisions are imminent but yet to be made.
2.3.2 Market overview
Figure 2.6 and Figure 2.7 provide a historical context and a summary of the current state of
offshore wind development in terms of turbine suppliers. Figure 2.6 shows that after a promising
start, construction rates fell off in the middle of the last decade but in recent years development
has started to ramp up once more.
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Industrial Development potential of offshore wind in Ireland
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800
Other
Commissioned [MW]
700
BARD
600
Vestas
500
Siemens
400
REpow er
Nordex
300
Areva/Multibrid
200
GE
Enercon
100
19
90
19
91
19
92
19
93
19
94
19
95
19
96
19
97
19
98
19
99
20
00
20
01
20
02
20
03
20
04
20
05
20
06
20
07
20
08
20
09
0
Figure 2.6: Worldwide Offshore Wind Capacity – Installation to Date
Figure 2.7 shows how Vestas and Siemens have achieved significantly greater market penetration
into the offshore sector than any other turbine supplier; however in terms of current projects or
those scheduled for construction in the immediate future, activity is distributed amongst a wider
field. Over the last 2-3 years, Siemens has led the market in terms of installation and sales for future
projects by a wide margin.
Under Construction / Contracted /
Announced [MW]
Supplier Experience [unit years]
Areva/Multibri
d
200 MW
4%
Siemens
3,100 MW
56%
Vestas,
2432
Siemens,
1506
Vestas
705 MW
13%
REpower,
24
Enercon, 6
Nordex, 11
Areva/Multi
brid, 6
REpower
535 MW
10%
BARD, 2
GE, 112
Sinovel
102 MW
2%
BARD
800 MW
15%
Other, 5
Figure 2.7: Worldwide Offshore Wind Capacity – Installed and Under Construction
In terms of wind turbine models, Table 2.1 lists the leading designs currently in operation at
offshore sites. It can be seen that generating capacities range from 2 to 5 MW and rotor diameters
range between 80m and 126m.
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Industrial Development potential of offshore wind in Ireland
Manufacturer
Model
Rated
Power
[MW]
Rotor
Diameter
[m]
Commercial
Timeline1
March 2011
Offshore Wind farms (number of turbines)
Operational
Contracted / Announced
BARD
BARD VM
5
122
2010
Hooksiel (1)
BARD Offshore 1 (80)
Aquamarin
Austergrund
Bernstein
Citrin
Deutsche Bucht
Diamant
Euklas
Veja Mate
BARD Offshore NL1
EP Offshore NL1
GWS Offshore NL1
Multibrid
M5000
5
116
2008
Alpha Ventus (6)
Borkum W 2 (80)
Global Tech 1
C. d'Albâtre (21)
REpower
5M
5
126
2007
Beatrice (2)
Thornton B. (6)
Alpha Ventus (6)
Ormonde (30)
Thornton B. II (24)
Nordergründe (18)
Siemens
SWT-2.3-82
2.3
82
2003
Nysted (72)
Samsø (10)
SWT-2.3-93
VS
2.3
93
2005
Lillgrund (48)
Horns Rev 2 (91)
Nysted II (90)
Baltic 1 (21)
SWT-3.6107
3.6
107
2006
Burbo (25)
Lynn/I.D. (54)
Rhyl Flats (25)
Gunfleet S. (48)
G. Gabbard (140)
Sheringham Sh (88)
London Array (175)
Walney I (51)
Borkum Riffgat
Butendiek
Gwynt y Môr (160)
SWT-3.6120
3.6
Avedøre (3)
Lincs (75)
Baltic 2 (80)
Walney II (51)
Anholt (111)
Burbo Bank Extension
Walney Extension
Galloper Wind Farm
Vestas
120
2012
V80
2
80
2001
Horns Rev (80)
North Hoyle (30)
Scroby Sands (30)
Pr. Amalia (60)
V90
3
90
2005
Kentish F (30) &
extension
Barrow (30)
Egmond (36)
Robin Rigg (60)
Thanet (100) & ext.
Belwind I (55)
Godewind II
Table 2.1: Overview of deployment of Offshore Wind Turbine models
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Table 2.2 summarises future Offshore Wind Turbine Designs currently under Development. GE’s reentry to offshore wind is arguably the most significant.
Prototype
Manufacturer
Country
Size
(generator)
Size
(rotor)
Onshore
2B Energy
Holland
6 MW
130 m
2011
AMSC Windtec
USA/AT
10 MW
170 m
Areva/Multibrid
FR/DE
5 MW
116 m
√
√
√
Bard
Germany
5 MW
122 m
√
√
√
6.5 MW
122 m
7.5MW
Enercon
Germany
126 m
√
1
150 m
2012
Offshore
Demonstration
Withdrawn
Clipper
USA/UK
10 MW
Gamesa
Spain
4.5 MW
128 m
√
GE (Scanwind)
USA
4 MW
110 m
√
GoldWind 2
China
3 MW
100 m
√
90 m
√
√
√
√
5 MW
Hyosung
Korea
5 MW
MHI
Japan
5 MW
Nordex
Germany
2.5 MW
×
5 MW
Samsung
Korea
5 MW
SeWind
China
3.6 MW
Siemens
Denmark
3 MW
101 m
√
100 m
√
6 MW
Sinovel
China
3 MW
5 MW
√
√
2010
Sway
Norway
10 MW
145 m
Vestas
Denmark
3 MW
112 m
√
2010
6 MW
XEMC-Darwind
WinWind
China /
NL
3 MW
5 MW
115 m
Finland
3 MW
90 m
1. Britannia
2. 1.5MW offshore demonstration turbine installed in 2008
× Not being actively marketed currently
Table 2.2: Overview of Prospective Future Offshore Wind Designs currently under
Development
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An overview of each of the main turbine suppliers is given in Appendix 2.
2.4 Wind turbine sub-component suppliers
2.4.1 Supply chain context
The rapid development of wind power over the last decade saw supply chain issues arise over a
number of key components as manufacturers struggled to keep pace with demand. Most notable
among these were the components that incorporated high technical and market entry
requirements including bearings, gearboxes and rotor blades.
In response to these events there has been a trend among a number of established manufacturers
towards greater vertical integration (more in-house production) as they seek control over their
supply chain. Table 2.3 presents the supply chain position of a number of principal turbine
manufacturers. It is noted that newer manufacturers tend to still buy-in most components as they
have yet to acquire the necessary in-house expertise and capability.
Manufacturer
Buy all components
In-house production
of key turbine
components
In-house production
   
Vestas

GE
  

Enercon

Gamesa
Siemens

Repower

BARD

Multibrid

 

   

 - Main position today
 - Position today but in process of changing direction
 - Anticipated position in coming years
 - Previous position
Table 2.3: Supply chain of principal turbine suppliers
As turbines grow increasingly large in size, transportation becomes an ever more important
consideration. This is especially true for the 5 MW-plus models currently being developed for the
offshore industry. Table 2.4 summarises the current supply chain outlook for principal subcomponents along with selected market and product characteristics.
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Global supply chain
outlook to 2013
March 2011
Technical
barriers to
entry
Market
barriers to
entry
Logistical
incentive to
produce
locally
Towers
Offshore supply less optimistic
than onshore [55]
Low
Low
High
Castings
Significant supply but there
could be regional constraints
particularly for offshore [55]
High
Mid
Low
Rotor Blades
Sufficient capacity <5MW but
>5 MW limited [55]
High
High
High
Generators
No constraints [55]
Mid
Low
High for larger
direct drive
machines
Gearbox
No constraints [55]
High
High
Mid
Bearings
Supply is delicately balanced
but industry should be able to
raise production to meet
demand [55]
High
High
Low
No constraints
Mid
High
Low
Control
Table 2.4: Supply chain characteristics of key WTG sub-components
2.4.2 Market overview
There is a very wide array of organisations involved at all stages in the supply chain. Appendix 3
contains a list of the main WTG sub-component suppliers, categorised by component, which
supply the offshore industry.
2.5 Offshore design trends
General
Unlike onshore turbines, there is less consensus on optimum size offshore. Turbines of up to 10
MW capacity are under development (Clipper) and offshore machines are generally noticeably
larger than their onshore counterparts. There are many extrapolations of current trends to suggest
sizes of even greater than 10 MW in the future. The transport restrictions which are so dominant
onshore do not apply offshore, provided assembly facilities are on the coast. Furthermore
consenting issues due to noise and visual pollution are greatly reduced opening up the
opportunity for larger machines still further.
However, at the current time, GLGH believes the evidence suggests that optimum size is around 5
to 6 MW, and there is no justification for rapid development of very large offshore turbines.
Turbine cost per MW tends to increase with size, whereas the Balance of Plant (BoP) costs per MW
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tend to come down as turbine size increases. Therefore an optimum size must exist. It is notable
that the established turbine manufacturers are not pursuing rapid size increases: the large turbine
developments are by new entrants. GLGH believes there will be few commercial offshore wind
turbines above 7 MW in the next five years. This is a tentative conclusion, and is not supported by
detailed published economic analysis. There may also be different optimum sizes for different
conditions, specifically for different water depths and different wind regimes.
Blades
The trend of increased turbine size and capacity offshore has seen a corresponding increase in the
maximum length and weight of turbine blades (see Table 2.1 for current rotor diameters). There
are a host of challenges associated with designing and manufacturing the largest blades currently
specified (see Table 2.2 for proposed rotor sizes). There are a limited number of facilities capable of
manufacturing such long structures in a single piece, as most turbine blades are made. Enercon
have developed a two-section blade for the E-126, comprising a glass-fibre reinforced composite
outer section bolted to a shorter steel inner section. While designed to alleviate transport issues,
this approach may gain popularity due to the reduction in manufacturing specifications.
Investment in new blade manufacturing facilities can be significant, and use of existing facilities
may be preferred.
As blade lengths increase, weight increases with volume – the relationship between length and
weight therefore being close to cubic. For this reason, weight reduction strategies become key
when designing ever-larger offshore turbines. The cost-benefit trade-off between the more
expensive carbon fibre and the heavier glass fibre-reinforced composites would appear to favour
the use of at least some carbon fibre in blades. Of the current eight offshore turbine models
offered to market, Table 2.5, at least five are believed to use carbon fibre-reinforced blades, with
only Siemens making a clear decision against using this material.
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Supplier
Turbine Model
Known blade
supplier(s)
Known use of
carbon fibre
Siemens
SWT3.6-107
Siemens
No
Siemens
SWT3.6-120
Siemens
Not known
Vestas
V90-3.0MW
Vestas
Yes
Likely that this model will be
withdrawn from the offshore
market
Vestas
V112-3.0MW
Not known
Not known
GLGH expects Vestas to use
carbon fibre in the blades for
this model.
REpower
6M
LM Glasfiber; Yes
PowerBlades
GmbH
REpower
5M
LM Glasfiber
Comment
Siemens do not normally use
carbon fibre in their blades
Yes
Repower
(internal
production)
ArevaMultibrid
M5000
ArevaMultibrid
Yes
PN Rotor purchased by
Areva in Aug 2009 from
Prokon Nord
Bard
Engineering
5.0
SGL Rotec
Not known
Bard Engineering
Table 2.5: Use of Carbon Fibre in Offshore Turbine Models
Gearboxes and generators
The drive towards generally larger turbines offshore naturally requires that the size of the internal
mechanical workings are similarly increased to withstand the greater operating loads. However,
the fundamental gearbox and generator designs are, to date, much the same as those found in
onshore machines.
The rapid deployment of larger turbines offshore has led to diminished prototype and
demonstration trial periods with a resultant impact on the reliability of many commercial projects.
Turbines have been installed in large, commercial offshore wind farms before the number of
prototype turbine running hours have reached maturity. Together with higher mean wind speeds
offshore, and therefore longer periods operating at full load, as well as difficult access to the
turbines, this design immaturity has led to frequent mechanical failures and a poor offshore
availability record.
This trend highlights a key difference between onshore and offshore lifecycle costs. Whilst costs
are generally higher offshore, the ratio of operational expenditure (OPEX) to capital expenditure
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(CAPEX) is also significantly higher, reflecting the difficulty in accessing offshore structures. As a
direct result of this, new generations of offshore turbines are re-evaluating the way in which the
main shaft, bearings, gearbox and generator are designed and manufactured with the aim of
improving reliability and therefore reducing visits to turbines and expensive lifting operations.
In principle the same onshore design options are available offshore. However the larger turbine
size is likely to shift the balance against the high-speed (HS) generator options, because of the
increased cost and mass of the gearboxes required to provide these speeds, and possibly a lack of
manufacturing capacity and suppliers. Nevertheless REpower use this tried and tested HS
approach involving a main shaft, a 3-stage gearbox and a doubly-fed asynchronous generator
configuration in their 5MW offshore turbines. At the opposite extreme, Siemens has taken the
decision to use a low speed (LS) direct-drive concept offshore, aiming for 5-6 MW size, emphasising
the advantages of reduced parts count and therefore predicted higher reliability. Vestas,
meanwhile, has chosen a conventional gearbox arrangement for its 112m diameter turbine, with a
permanent magnet generator (PMG) and full converter. The choice for their next larger turbine
development has not yet been announced.
Clearly no optimal solution has been reached in terms of offshore drive train configuration, but the
impact of increased scale and a demand for improved reliability are likely to drive the decision
making towards lower speed generators, with fewer mechanical components and full converters.
2.6 Equipment installers/Balance of plant equipment suppliers
2.6.1 Supply chain context
As noted in Section 2.1, installing wind farms offshore involves equipment and installation services
of an order of magnitude more complex than onshore wind farms. Thus the balance of plant (BoP)
expenditure for an offshore wind farm is typically around half the total capital expenditure with an
associated increase in supply chain opportunities.
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Global supply chain
outlook to 2013
March 2011
Technical
barriers to
entry
Market
barriers to
entry
Logistical
incentive
to resource
locally
Supply
No constraint, except in
short term if peaks in
demand
Low
Mid
High
Install
No
constraints
likely:
substantial numbers of
suitable
new
vessels
expected.
Mid
Mid
Low
Supply
No constraints
Mid
High
Low
Install
Short term constraints
possible. New vessels on
order.
Mid
Low
Low
Supply
Lead times >18 months
recently, but easing with
new entrants anticipated.
High
High
Low
Install
Short term constraints
possible. New vessels on
order.
High
Mid
Low
No
constraints:
vessels expected.
Mid
Mid
Low
Foundations
Array Cables
Export
Cables
Installation Vessels for
WTGs and Foundations
new
.
Table 2.6: Supply chain characteristics of principal BoP equipment and services
2.6.2 Foundation supplier market overview
A non-exhaustive list of current foundation suppliers is provided in Table 2.7, along with the types
of foundations and projects with which they have been involved.
Projects2
Contractor
Foundation
Type1
Aarsleff
Monopile, GBS
√
AMEC
Monopile, Jacket
√
Blyth, Beatrice
Ballast Nedam
Monopile
√
Lely, Irene Vorrink, Egmond,
Nysted
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Installation Fabrication
√
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Nysted, Nysted 2, Horns Rev
2, London Array (with
Bilfinger Berger)
Industrial Development potential of offshore wind in Ireland
Contractor
Foundation
Type1
Bard
Engineering
Tri-pile
BiFab
Jacket
Bilfinger Berger Monopile, GBS
March 2011
Projects2
Installation Fabrication
Hooksiel, Bard Offshore 1
√
√
Beatrice, Alpha Ventus
Horns Rev 2, London Array,
Nysted 2 (with Arsleff)
√
Bladt
Monopile
√
Samsø, Egmond, Horns Rev
2, London Array
Cuxhaven Steel
Construction
Tri-pile
√
Hooksiel, Bard Offshore 1
DEME
Monopile, GBS
EEW
Monopile
Fugro Seacore
Monopile
√
Gunfleet Sands, Bockstigen,
Blyth, Yttre Stengrund
Hochtief
GBS
√
Lillgrund
KBR
Monopile
√
Barrow
MBG
GBS
MT Højgaard
Monopile, GBS
Utgrunden, Samsø,
Thornton Bank
√
√
√
Belwind, Walney
√
Thornton Bank
√
Middelgrunden, Horns Rev,
Kentish Flats, Burbo, Lynn &
Inner Dowsing, Rhyl Flats,
Robin Rigg, Gunfleet Sands,
Greater Gabbard,
Sheringham Shoal
SIF
Monopile
√
Horns Rev, North Hoyle,
Arklow, Kentish Flats,
Barrow, Burbo, Princess
Amalia, Lynn & Inner
Dowsing, Rhyl Flats, Thanet,
Sheringham Shoal, Robin
Rigg, Gunfleet Sands
Skykon
Monopile, Jacket
√
New to offshore market
√
Horns Rev, North Hoyle,
Arklow, Kentish Flats,
Barrow, Burbo, Princess
Amalia, Lynn & Inner
Dowsing, Rhyl Flats, Thanet,
Sheringham Shoal, Robin
Rigg, Gunfleet Sands
√
Hywind
Smulders
Monopile
(Transition Piece)
Technip
Floating
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Industrial Development potential of offshore wind in Ireland
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Projects2
Contractor
Foundation
Type1
Van Oord
Monopile
√
Princess Amalia, Belwind
Vestas
Monopile
√
North Hoyle, Scroby Sands,
Barrow
ZPMC
Monopile
1
2
Installation Fabrication
√
Greater Gabbard
Foundation types installed to date
Projects which are operational or under-construction
Table 2.7: Current Foundation Suppliers
2.6.3 Foundation technology
There are currently three generic support structure / foundation design solutions that are
commonly selected and likely to be the principal candidate technologies for offshore wind projects
over the next five years; these proven concepts are discussed in more detail later.
1
Monopile;
2
Space frame structures, specifically jackets; and,
3
Gravity base structures (GBS).
In addition a number of further foundation types have already been used in a limited number of
cases and may gain more widespread usage depending on performance of the demonstration
projects. These technologies are also discussed in more detail later, as ‘demonstrated’ concepts.
1
Other space frame structures, specifically tripods;
2
Tri-piles, including the Bard patented concept;
3
Battered piles, suitable for particular site conditions such as prevalent in Chinese waters; and,
4
Floating spar, suitable for very deep water conditions such as off the Norwegian coast.
In the medium term, a number of additional foundation types are potential candidates for
demonstration projects once the technical viability has been sufficiently assessed. These ‘potential’
concepts are described in more detail later.
Choice of foundation type depends on a wide range of factors, which can broadly be divided into
technical limitations, cost considerations and environmental constraints. These may include factors
such as:

Contractor capability and appetite; in terms of:

General confidence and experience

Monopile / jacket lifting and handling

Driving / drilling equipment

Fabrication limits
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Industrial Development potential of offshore wind in Ireland

March 2011
Permit and Regulatory Limits

Noise limitations (piling)

Impact on sediment transfer

Coverage of seabed (footprint)

Wind turbine size (in terms of rotor diameter, hub height, rated power and nacelle weight)

Water depth

Likelihood of sea ice

Ground conditions

Metocean conditions
However the final decision is likely to be made on cost and risk grounds, i.e. the lowest cost
solution with acceptable risk. Hence project developers tend to attempt to keep open all viable
foundation options right through to Invitation to Tender. Evidence that this trend continues can
be seen in current EIA (Environmental Impact Assessment) studies that support licensing and
permitting submissions.
It is also possible that some projects, with multiple turbine types or which spread across a wide
range of water depths, will be built on two or more different types of foundations. GLGH has seen
such a strategy actively pursued during the design stages but as yet such projects have not
reached construction.
Proven foundation concepts
Detailed descriptions of proven foundation concepts are given in Appendix 4.
Examining the offshore wind turbine foundations built to date, it can immediately be seen that
monopiles form the majority and indeed have steadily gained share over recent years, Figure 2.8.
80%
GBS
60%
Tripod
Tri-pile
40%
Jacket
Monopile
20%
20
12
20
10
20
08
20
06
20
04
20
02
20
00
19
98
19
96
19
94
19
92
0%
19
90
New Installed Capacity - Market
Share
100%
Year
Note that sample size in early years is small, typically consisting of a single wind farm with maybe 10 or so turbines
Figure 2.8: Historic Offshore Wind Turbine Foundation Selection (by year)
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Summating all offshore wind turbine foundations constructed to date illustrates the dominance of
the monopile foundation which comprises 80% of installed foundations to date, as shown in Figure
2.9. GBS have been the second most popular type at 14% of the total, with other foundations less
suitable due to the shallow waters in which most wind farms have been built to date.
Tripod
6
0%
Tri-pile
82
4%
GBS
258
14%
Jacket
39
2%
Monopile
1,489
80%
Figure 2.9: Historic Offshore Wind Turbine Foundation Deployments
As a base case, it is assumed monopiles will be the preferred default foundation option for the
immediate future; however the cost-effectiveness of monopiles is likely to be limited by a
combination of turbine size and water depth (as well as ground conditions to a lesser extent).
Other fixed foundations – demonstrated
Detailed descriptions of ‘demonstrated’ foundation concepts are given in Appendix 5. The list
consists of:



Tri-piles
Battered piles
Suction buckets
Floating foundations - demonstrated
The coming few years will see large offshore wind farms built in unprecedentedly deep waters, in
particular within the German sector of the North Sea. The cost of the support structures needed, in
terms of fabrication as well as installation, are significantly higher than the monopiles and GBSs
used for the offshore wind farms currently under construction. As depths increase further, the
costs of such support structures increases similarly and it is apparent that costs must become
prohibitively expensive at some point if the same technology is used. However as depths and costs
increase, alternative options for supporting the turbine become viable, including floating support
structures. Hence the question of the impact this will have on overall costs arises, and how will
these compare with the alternatives.
This can be examined in a preliminary indicative manner by considering how the wind turbine
loads are reacted to. The conventional classic approach is to use a rigid structure to transmit these
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Industrial Development potential of offshore wind in Ireland
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loads in to the ground. This provides a stable platform and is now well understood but requires a
strong, stiff structure. However it is also possible to transfer the loads to the water, water having
two important advantages: firstly it is much closer, hence the load path is shorter and peak
bending moments commensurately less, and secondly, water is compliant, hence there is flexibility
and the peak forces may be lower. Note that clearly the mean horizontal loads need to be
transmitted to ground, otherwise the vessel will float away, however the more onerous bending
loads need not.
Utilisation of floating support structures will deliver a number of important benefits, principally:

greater choice of sites & countries, including the Mediterranean (France, Spain, Italy),
Norway, US (East and West coast) and East Asia (China, Japan, Korea).

greater choice of concepts; a wide variety of technology solutions are currently being
proposed

cost is probably similar to fixed structures in medium depths; however this does remain to be
demonstrated in practice for both floating as well as fixed structures

greater flexibility of construction & installation procedures

easier removal / decommissioning
However the dynamic foundation introduces a number of new challenges, including:

minimisation of turbine and wave induced motion

the additional complexity for the design process, including understanding and modelling
the coupling between the support structure and the wind turbine (moorings & control)

the electrical infrastructure design and costs, in particular the flexible cable

the construction, installation and O&M procedures, in particular similar attention should be
paid to installation strategy as to the operation.
A floating support structure can be broken down in to the following systems:

Structure (floater): maintain buoyancy and structural integrity

Mooring: connect the floater to the seabed, typically chain or cables

Anchoring: attach the mooring lines to the seabed

Electrical cable: export of power
There are three primary classes to floating structures; the spar, the tensioned-leg platform (TLP)
and the floating jacket structure as illustrated in Figure 2.10. To date only the spar approach has
been demonstrated at full size offshore.
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Industrial Development potential of offshore wind in Ireland
TLP Class
Spar Class
March 2011
Jacket Class
Source: Jacket MSCGusto/ECN/TUDelft; others: GLGH
Figure 2.10: Support Structure Classes
All three of the floating foundation variants are technically and practically viable and indeed are
being actively pursued. Each class has different characteristics and strengths: the spar and jackettype floaters have the benefit of using predominantly widely used and proven technology, while
the TLP and jacket type floaters can be used in shallower waters than the spar (down to 50m or
less) and for the TLP floater, a lightweight elegant design should be achievable in time.
Further details are given in Appendix 6.
Potential new foundation concepts
There are considerable risks associated with the development of new foundation concepts; for
example in the oil and gas industry, a new floater concept needs to deliver a significant cost saving
against the proven alternatives before it can be selected for a project, possibly in the order of 20%.
The offshore wind case is arguably no different; in particular, with the cost of the foundation
consisting of indicatively 20% of the total capital expenditure, the opportunity for significant and
risk-controlled cost reductions is limited. Hence new foundation concepts may require
sponsorship from government or quasi-governmental bodies.
Potential new fixed and floating concepts are described in Appendix 7.
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Industrial Development potential of offshore wind in Ireland
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Part C. Scenarios and Opportunities
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Industrial Development potential of offshore wind in Ireland
1
March 2011
DEFINING SCENARIOS
The built-rate scenarios developed by GLGH and used in this analysis are based on the 2030
offshore wind installed capacity scenarios included in the draft Offshore Renewable Energy
Development Plan (OREDP) [3]. These are summarised in Table 1.1.
Scenario Capacity [MW]
Low
Origin
800 Offers under Gate 3
Medium
2,300 Table 10 non-modelled scenario of the NREAP
High
4,500 SEA scoping document
Table 1.1: Offshore wind capacity scenarios for 2030, OREDP
The build-rates for each scenario have been developed by GLGH as ‘scripted futures’ which are
plausible, internally consistent and opportunity-led, given the resources available in the Republic
of Ireland for further deployment, industrial development and export of offshore wind products
and services.
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Scenario A: Low offshore wind development
40 % RES-E target for 2020 is met with emphasis placed on Hydro-power and Onshore Wind.
Contributions from Offshore Wind and other marine renewable energy sources are limited to a
Business As Usual approach. Offshore wind capacity is limited to offers under Gate 3, and reaches
800 MW before 2030.
120
1200
100
1000
80
800
60
600
40
400
20
200
0
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
0
Figure 1.1: Projected build-out: low offshore wind scenario
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Cumulative Capacity [MW]
Installed Capacity [MW]
Note that while limited to offers under Gate 3, the rate of build-out is influenced by probability
profiling on current project pipelines, accounting for unforeseen delays and the possibility of
earlier connection on a non-firm basis.
Industrial Development potential of offshore wind in Ireland
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Scenario B: Medium offshore wind development
250
2500
200
2000
150
1500
100
1000
50
500
0
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
0
Figure 1.2: Projected build-out: Medium offshore wind scenario
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Cumulative Capacity [MW]
Installed Capacity [MW]
40 % RES-E target for 2020 is met with significant contribution of Offshore Wind and other marine
renewable energy sources, based on a moderately optimistic assessment of what could be
achieved by 2020 with adequate political will. Offshore wind then expands to 2,300 MW by 2030.
Industrial Development potential of offshore wind in Ireland
March 2011
Scenario C: High offshore wind development
500
5000
450
4500
400
4000
350
3500
300
3000
250
2500
200
2000
150
1500
100
1000
50
500
0
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
0
Figure 1.3: Projected build-out: high offshore wind scenario
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Cumulative Capacity [MW]
Installed Capacity [MW]
40 % RES-E target for 2020 is met with maximum realistic contribution of Offshore Wind and other
marine renewable energy sources. Offshore wind then expands to 4,500 MW by 2030. Possibility
of future exporting of products and services related to Offshore Wind.
Industrial Development potential of offshore wind in Ireland
2
March 2011
DEMAND FOR EQUIPMENT AND SERVICES (ROI)
2.1 Development
2.1.1 Description of services and materials required
Development Expenditure, or DEVEX, covers the expenditure up to the point where the major
construction contracts are signed for any project or project phase. Activities during the
development phase can loosely be grouped under the categories; technical, consenting and
funding.
1
Technical includes initial site investigations/measurements, negotiation of a grid connection
offer, front-end engineering design, construction planning and development of
specifications;
2
Consents and Concessions covers sea bed lease, land lease for cable route / substation
works, environmental impact assessment and related work and stakeholder engagement /
PR;
3
Funding the arrangement for the equity and / or debt finance required to construct the
project.
Whilst this is a reasonably protracted phase (mainly due to the extensive environmental
assessment work required), the spend rate for the overall scheme is modest, from UK experience to
date typically in the order of €50k, per MW of capacity, and occurring 3 to 4 years prior to project
operation. The most expensive aspects typically involve the wind resource assessment due to mast
installation costs, the geotechnical surveys and the environmental assessment work.
The following provides generalised categories of principal participants in the supply chain during
the development phase. However it should be noted that substantial cross-over between these
areas is commonplace.
1
Engineering consultants may be responsible for a number of activities including front-end
engineering and design (FEED) studies, grid connection feasibility / application and energy
production analyses. May also act as project managers subcontracting for other elements.
2
Technical surveyors, responsible for specialist technical surveys such as sea bed surveys
(geotechnical and geophysical) and navigaitonal surveys etc.
3
Environmental consultants, responsible for conducting environmental impact assessment
(EIA) which may include benthic, pelagic, ornithological and sea mammal surveys. Individual
elements may be subcontracted to specialist surveyors and analysts.
4
Specialist environmental surveyors and analysts may conduct one or more specific
surveying tasks under an EIA.
5
Financial consultants are responsible for assisting with fund-raising and financial planning
providing market pricing advice.
6
Legal consultants and representatives provide necessary legal advice including regarding
land lease negotiations.
Table 2.1 provides an outline of the principal services and products involved in the supply chain
during the development phase.
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Technical work
Category
FEED Study /
Engineering
Support
A/S
Metocean
Measurement
s
A/s/i
as / ss
As / Ss / Is
Grid
connectio
n surveys
A
Human
impact
studies
Project
Manage.
A
A
A/S
Financial Consultants
A
A
A/S
Legal advisors
A
A
A/S
As
Environmental
surveys / analysis
Cross-cutting
Equity
Technical Surveyors
Lease
application
Funding
Debt
Engineering Consultants
Sea bed
surveys
Concessions and Consenting
a
Legal
Support
a
Environmental Consultants
As / Ss
Specialist Surveyors
as / ss
A/S
A – Analysis / Advice (probable), S - Supply (probable), I - Installation (probable), a - Analysis (possible/in part), s - Supply (possible/in part), i - Installation (possible/ in part). Subscript s indicates scope
delivered via major sub-contract.
Table 2.1: Outline map of current contracting possibilities within the offshore wind sector at project development phase
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2.1.2 Quantification of principal services and materials required
Under the assumption of €0.05m per MW, occurring 3 years before installation, the average annual
DEVEX costs are projected to be as shown in Table 2.2.
Average DEVEX
2010-15
2015-20
2020-25
2025-30
Low scenario
€3.0m
€3.7m
€1.2m
€0.1m
Medium scenario
€3.0m
€8.5m
€9.1m
€2.4m
High scenario
€3.0m
€14.7m
€18.7m
€9.0m
Table 2.2: Projected average annual DEVEX costs in the Irish market
In terms of FEED studies and environmental impact surveys, these will in general be required once
per project. For a quantification of such services, it is therefore preferable to examine the project
pipeline rather than to analyse on a market-wide capacity basis. GLGH has however analysed the
demand for geotechnical and geophysical survey services associated with the projected capacity
installation scenarios outlined in Section 1. GLGH knowledge and experience of such activities over
a broad range of projects has been used to predict future levels of demand associated with each
projected build-out scenario.
Geophysical surveys involve non-intrusive methods of investigating the seabed, such as sonar.
Normally the entire project site will be surveyed in this manner, so that a detailed picture of the
terrain can be produced, and an overview of the geological structure of the ground. Geotechnical
surveys involve physical investigation of the seabed – either through grabbing a sample of soil
from the seabed surface, performing a CPT, or cone penetration test, or by performing a much
more complex borehole test. This latter activity involves drilling a hole many metres into the
seabed, in order to retrieve a stratified sample of soil, and gain a great deal of information about
the geological properties of the ground. These types of survey take a considerably greater
investment than geophysical surveys, and as such will normally only be carried out over a certain
proportion of the site.
It can be seen in Figure 2.1 and Figure 2.2, that demand for geophysical and geotechnical surveys,
even in the high development scenario, is not forecast to reach a level of full utilisation for one
vessel. This implies that Ireland will be reliant on importing these services, as demand will not
support a domestic player with Irish development alone. Alternatively, an Irish company could
export services to the UK and beyond to maintain workload, or else specialise in support services to
the activity rather than focussing on asset provision.
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0.16
0.14
0.12
0.1
0.08
0.06
0.04
0.02
29
30
20
27
26
25
24
28
20
20
20
20
20
23
20
22
21
Medium
20
20
20
19
18
17
16
15
14
13
12
Low
20
20
20
20
20
20
20
20
20
11
20
20
20
10
0
High
Figure 2.1: Demand for environmental / geophysical survey vessels [no. of vessels]
0.3
0.25
0.2
0.15
0.1
0.05
20
10
20
11
20
12
20
13
20
14
20
15
20
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20
17
20
18
20
19
20
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22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
0
Low
Medium
High
Figure 2.2: Demand for geotechnical survey vessels [no. of vessels]
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70
60
50
40
30
20
10
Medium
29
28
27
30
20
20
20
25
24
26
20
20
20
22
21
23
20
20
20
20
19
18
17
16
15
14
Low
20
20
20
20
20
20
20
12
11
13
20
20
20
20
20
10
0
High
Figure 2.3: Demand for CPT surveys [no. of surveys]
18
16
14
12
10
8
6
4
2
Figure 2.4: Demand for borehole surveys [no. of surveys]
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20
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High
20
20
20
20
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20
22
21
Medium
20
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20
20
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Industrial Development potential of offshore wind in Ireland
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2.1.3 Commentary of Irish supply chain possibilities
Table 2.2 shows that, at the peak of the High scenario, development expenditure of €20 m per year
can be expected. This is sufficient to support project development teams and consultancy and
similar services in Ireland. The requirement for knowledge of the consenting process and legal and
policy background should ensure that a significant part of this work is actually done in Ireland,
rather than by development teams and consultants elsewhere in Europe, especially the UK. Even
the Low scenario is likely to justify work by development teams and consultants based in Ireland.
Figures 2.1 to 2.4 demonstrate that, even under the High scenario, there is not enough work to
justify establishing vessels and related equipment. The work may go to existing Irish vessels,
perhaps multi-purpose in nature, or to vessels based elsewhere in northern Europe.
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2.2 Construction Phase
2.2.1 Description of services and materials required
Capital Expenditure (CAPEX) covers the major construction costs, including procurement of all the
generating plant and infrastructure. From UK experience CAPEX is typically in the order of €3.5 m
per MW of capacity. An indicative breakdown of costs, by component, is given below.
Installation of Offshore
Electrical Systems
6%
Surveying & Construction
Management
Insurance
4%
2%
Installation of Turbines and
Support Structures
9%
Offshore Electrical Systems
9%
Turbines and ancillaries
51%
Support Structures
19%
Figure 2.5: Indicative breakdown of offshore wind farm capital costs
Participants in the upper tiers of the offshore wind supply chain during the construction phase can
generally be categorised into 7 main categories, as follows:
1
Wind Turbine OEMs, responsible for supply of the wind turbine technology, with a broader
scope of work in some instances. Examples; Siemens Wind Power, Vestas, REpower Systems.
2
Structural Fabricators, responsible for at least the fabrication of foundations for the wind
turbines, and possibly also the offshore sub-stations. Examples; SIF, Smulders, Bladt, BiFAB,
Weserwind.
3
Electrical Equipment Suppliers, responsible for at least the electrical system design and
supply of all electrical equipment for the onshore and offshore substations. Examples; ABB,
Areva T&D, Siemens T&D.
4
Marine Contractors, responsible for various aspects of the offshore installation works
including one or more of wind turbine, wind turbine foundation and offshore substation
foundation / topsides. Examples; A2SEA, MPI, SHL.
5
Cable Suppliers, responsible for at least supply of export or array cables with partial market
segmentation into these two categories, which are typically demarcated at 33kV. Examples;
Prysmian, Nexans, NSW, Draka, JDR.
6
Cable Installers, niche marine contractors responsible for array and export cable installation.
Examples; Subocean, Global Marine, Visser & Smit.
7
EPC Contractors, large construction firms or joint ventures between parties from one or
more of the above categories taking responsibility for a broader scope of work, in some cases
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comprising the vast majority of the capital spend. Examples; Fluor, Van Oord, KBR, MT
Højgaard, Arsleff, Bilfinger Berger.
In addition to these main categories, smaller contract lots will be awarded to specialist design
houses (primarily for foundation design), certification authorities, project management companies,
Health & Safety consultants, marine warranty surveyors, insurance providers and other minor works
contractors. The position of any individual company amongst the above mentioned categories
within the value-chain is highly uncertain, with a wide variety of approaches to procurement
strategy being adopted to date. Table 2.3, below provides an outline indication of this fluidity in
the form of map of current contracting practices.
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FENCE
Transition
Pit
GRID
Category
Wind Turbine OEMs
Structural
Fabricators
Electrical Suppliers
HAT
Onshore
Substation
Onshore
Export
Cable(s)
Offshore
Joint
LAT
Offshore
Export
Cable(s)
March 2011
Offshore Sub Station(s)
Topside
Foundation
Equipment
Steelwork
Array
Cables
WTG
Foundations
WTGs
D / S / is
ds / S
D / S / Is
D / S / Is
ds / S
D / Ss / i
ds / S
D / S / is
Marine Contractors
I
I
D / Ss / i
I
Cable Suppliers
S
S
S
Cable Installers
I
I
I
ds / ss / is
Ds / Ss / Is
EPC Contractors
I-Tube
I-Tube
J-Tube
ds / ss / is
Ds / Ss / Is
Ds / Ss / Is
ds / ss / is
Ds / Ss / Is
I
I
Ds / Ss / Is
Is
D - Design (probable), S - Supply (probable), I - Installation (probable), d - Design (possible), s - Supply (possible), i - Installation (possible). Subscript s indicates scope delivered via major sub-contract.
Table 2.3: Outline map of current contracting possibilities within the offshore wind sector during construction phase
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2.2.2 Quantification of services and materials required
Assuming €3.5m per MW CAPEX expenditure, the average annual investment for the various
scenarios is projected as in Table 2.4.
Average CAPEX
2010-15
2015-20
2020-25
2025-30
Low scenario
€72m
€313m
€156m
€44m
Medium scenario
€72m
€386m
€631m
€543m
High scenario
€72m
€468m
€1264m
€1292m
Table 2.4: Projected average annual CAPEX costs in the Irish market
Of the principal elements identified in the construction of a wind project (Table 2.3), the number of
offshore substations required will be on a per-project basis; hence this demand is better analysed
with reference to project pipelines. However, with a typical offshore substation being rated in
excess of 200 MW, it is evident that the market for these plants will be constrained to little more
than one per year even at the peak of the High scenario.
GLGH has analysed the projected quantities of electrical cable required (Figure 2.6 and Figure 2.7),
the associated vessel demand to install these cables (Figure 2.8 and Figure 2.9), and the demand
for foundation installation vessels (Figure 2.11). Array cable links are a function of the expected
number of turbines installed each year, while export cabling is a function of distance to shore and
project size. It is expected that earlier projects will take the areas closest to the coast, while later
projects will be built further from the shore; hence export cabling demand is expected to rise in
later years. In the high deployment scenario, a few floating-technology projects have been
assumed, in deep waters distant from land. Should such projects go ahead, these will increase
demand for associated materials and services, such as export cables.
Vessel demand has been derived from GLGH knowledge and experience of previous project
installations, and relating this to project capacities and characteristics. In the high development
scenario, it can be seen that cable installation vessel demand is projected to rise to between one
and two vessels throughout the second decade, while the market could require more than one
foundation installation vessel. This is demand for a jack-up crane vessel, capable of installing
monopiles or jacket structures. These vessels are large and require significant investment both in
terms of CAPEX to build them, and consequently in terms of daily hire rates to use them.
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80
70
60
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40
30
20
10
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20
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Medium
20
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Low
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20
18
17
20
20
20
16
15
14
20
13
20
12
20
20
20
20
10
11
0
High
Figure 2.6: Demand for array cables [km of cable]
180
160
140
120
100
80
60
40
20
Low
Medium
Figure 2.7: Demand for export cables [km of cable]
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26
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0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
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Medium
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Low
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20
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20
20
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20
20
20
20
10
0
High
Figure 2.8: Demand for array cable installation vessels [no. of vessels]
1.6
1.4
1.2
1
0.8
0.6
0.4
0.2
Figure 2.9: Demand for export cable installation vessels [no. of vessels]
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26
25
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High
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20
20
20
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20
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Medium
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60
50
40
30
20
10
Medium
29
28
27
26
25
24
30
20
20
20
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20
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20
Low
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20
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13
20
12
20
20
20
20
10
11
0
High
Figure 2.10: Foundations installations [units]
1.4
1.2
1
0.8
0.6
0.4
0.2
Medium
Figure 2.11: Demand for foundations installation vessels [no. of vessels]
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27
26
25
24
High
20
20
20
20
20
20
23
20
20
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20
Low
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60
50
40
30
20
10
Medium
30
28
27
26
25
24
29
20
20
20
20
20
20
23
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21
20
Low
20
19
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20
18
17
20
20
20
16
15
14
20
13
20
12
20
20
20
20
10
11
0
High
Figure 2.12: Wind turbine installations [units]
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
Medium
30
28
27
26
25
24
29
20
20
20
20
20
20
23
20
20
21
22
20
20
Low
20
20
18
17
19
20
20
20
15
14
16
20
20
20
13
20
11
12
20
20
20
10
0
High
Figure 2.13: Demand for wind turbine installation vessels [no. of vessels]
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2.2.3 Commentary of Irish supply chain possibilities
Even under the High scenario, there is insufficient volume to justify establishing manufacturing
facilities for offshore substations, array cables or export cables. New subsea cable manufacturing
facilities are needed, and several are being planned in Europe and Asia, but there is no comparative
advantage that would favour construction of such a plant in Ireland.
Similarly, there is insufficient volume to justify a cable installation vessel being dedicated to the
Irish market at any point.
Under the High scenario, there may be a case for establishing a foundation manufacturing facility
capable of around 50 units per year. This is smaller than the average facility size anticipated by
GLGH elsewhere (over one hundred per year), but the local advantage may allow this facility to
compete with larger facilities.
A foundation manufacturing facility for monopiles could also produce towers and transition pieces.
This may be a way to increase the facility’s size and therefore reduce unit costs to compete with
larger facilities elsewhere. Towers have smaller diameters and thinner plates than monopiles, so
would not require substantial additional equipment. A facility designed to manufacture jacket
structures would be much less suited to also producing towers.
Under the High scenario, there may well be a case for at least one Irish-based installation vessel,
capable of installing both foundations and turbines. See also Section 2.3 for the O&M market.
Note that both these identified opportunities occur late on (i.e. to cover the period 2020-2030), and
therefore would compete against facilities already established by other countries. This is a direct
consequence of the scenarios defined, i.e. lack of substantial construction in Irish waters before
2020.
Provision of construction support services offers a more flexible opportunity but businesses
pursuing these will have similar disadvantages of lack of a home market and geographic separation
from the main hub of activity in the North Sea. Nevertheless, it is entirely feasible that good quality
dynamic businesses could build a good position in the offshore wind sector.
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2.3 Operations and Maintenance Phase
2.3.1 Description of services and materials required
While a wind farm project has no fuel costs, it does require significant ongoing expenditure, in
terms of management, operation and maintenance (scheduled service, unscheduled repair and
overhauls), insurances and other business overheads. Operational expenditure, or OPEX, is
assumed here to be in the order of €300k/annum per wind turbine unit. Primary activities within
wind turbine O&M are: scheduled service (annual or semi-annual); project base provision;
unscheduled fault-finding and repair; remote monitoring; major repairs; retrofit; spares handling at
project base; operational reporting; and spares sourcing. Potential O&M Providers include;
1
Wind Turbine Suppliers: These are typically the O&M Provider for offshore wind farms –
offering a five-year warranty, operations and maintenance package in association with the
wind turbine supply contract. Five-year extension options are commonly offered, so it is
normal for wind turbines to spend the first ten years of their operating life under the care of
the OEM.
2
Independent O&M providers and in-house O&M owners: Both are common in onshore
wind, but have little presence in offshore wind, as yet.
Core activities tend to be undertaken by OEM staff, including management and technician staffing.
During periods of intense activity, such as summer scheduled service campaigns, supplementary
technician support can be used. Non-core activities, such as transport, vessel provision and
crewing, are typically subcontracted by the O&M Provider. Some highly specialised tasks are also
subcontracted. For example, roped access to rotor blade cleaning and checking, or on-site
investigation and repair of major sub-supplied components (generators, transformers, gearbox,
switchgear, converters), for which the relevant sub-suppliers will be subcontracted.
There are around three indirect jobs for every direct job in the operation of an offshore wind farm
[91], so with one direct post for approximately every 10-20 turbines installed, there are diverse
business support opportunities. These would be focussed around the project service base, the
location of the spares providers, transport and vessel providers and monitoring base (this could be
anywhere in the world).
Project owners, in addition to employing a main O&M Provider, will also typically maintain an asset
management function, which would involve having staff dedicated to the project, both at the
service base and in their headquarters in a supervisory / monitoring capacity.
For future projects, the approach to O&M will change significantly from that on current projects,
owing to their increasing size and isolation. This is likely to result in more manned accommodation
platforms on the project sites, and more widespread use of helicopters for movement of
technicians to and around the field.
The breakdown of the O&M spend (including for balance of plant) is represented, below, for a
simulated 750 MW offshore project, with two separate access strategies – one in which the crew
are based on an offshore platform and one in which daily helicopter pickups and drop-offs are
used.
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Service vessel(s)
7%
Helico pter
0%
Scheduled M aint. Vessel(s)
3%
Insurance
26%
Crane barge
18%
B o P M aintenance
4%
Repair Staff (full-time)
9%
Offsho re base
0%
Scheduled M aint. Staff
9%
P arts and co nsumables
19%
Onsho re base / staff
5%
(a) Shore-based maintenance
Service vessel(s)
5%
Helico pter
0%
Scheduled M aint. Vessel(s)
2%
Insurance
20%
Crane barge
13%
B o P M aintenance
3%
Repair Staff (full-time)
8%
Scheduled M aint. Staff
5%
Offsho re base
28%
Onsho re base / staff
1%
P arts and co nsumables
15%
(b) Maintenance from offshore platform base
Figure 2.14: Breakdown of O&M spend
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2.3.2 Quantification of services and materials required
Assuming €0.2m/a per wind turbine of maximum potential localised OPEX costs (essentially the
O&M component of OPEX costs), the projected expenditure is as in Table 2.5. Note that while
DEVEX and CAPEX are “one-off” costs, and can be counted on a per-project basis, OPEX is an
ongoing cost, and is dependent on the cumulative number of turbines in operation.
Average OPEX
2010-15
2015-20
2020-25
2025-30
Low scenario
€1.4m
€17.3m
€32.1m
€36m
Medium scenario
€1.4m
€18.3m
€49.5m
€74.5m
High scenario
€1.4m
€19.4m
€71.1m
€125.3m
Table 2.5: Projected average annual OPEX costs in the Irish market
In terms of offshore operations, Figure 2.15 shows the projected demand for wind turbine repair
vessels; i.e. jack-up crane vessels, such as may be used for replacement of major components. As
the cumulative number of operational turbines increases, and the fleet ages, then vessel demand
rises accordingly. In the high deployment scenario, up to one additional vessel will be required,
working full time. The specifications of this vessel overlap with those of the foundation and turbine
installation vessels, meaning that total jack-up demand could be around three vessels. This
represents a significant market, perhaps tempered if projects are dispersed between east and west
coasts.
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
20
10
20
11
20
12
20
13
20
14
20
15
20
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20
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20
18
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22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
0
Low
Medium
High
Figure 2.15: Demand for wind turbine repair vessels (crane required) [no. of vessels]
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2.3.3 Commentary of Irish supply chain possibilities
From 2015 onwards, in all three scenarios, there is sufficient value in O&M activities to justify
establishing O&M facilities in Ireland. This is likely to be on a project-specific basis. With further
expansion (i.e. the High and Medium scenarios after 2020), there may be opportunities for facilities
common to several projects.
Figure 2.15 reinforces the case for at least one installation vessel to be based in Irish waters (from
Section 2.2), to cover also turbine repair and maintenance.
2.4 Decommissioning Phase
To date the only offshore wind farm which has undergone decommissioning was the Nogersund
0.2 MW single turbine project in Sweden. Given this demonstration project cannot be considered
particularly representative of the large commercial projects currently under development and
construction, decommissioning cost estimates remain highly uncertain. Assuming a minimum
wind farm life span of 20 years the only Irish wind farm under any of the scenarios outlined here
which may undergo decommissioning prior to 2030 is Arklow Bank.
Principal activities expected to be involved in the decommissioning of an offshore wind farm
include:




Environmental review
Mobilisation of vessels and cranes to remove wind turbines and foundations
Haulage
Waste and site management
Initial estimations are that the dominant cost will be the removal of turbines and foundations
which will be in the same order as the cost of the erection aspects of their installation. A degree of
cost offset may result via the residual value of the wind turbine equipment and scrap value of
foundations / towers.
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March 2011
MARKET OPPORTUNITIES BEYOND ROI WATERS
3.1 Forecast for ROI and adjacent waters market
3.1.1 Description of development potential
The UK leads world offshore development, with over 1 GW of installed capacity, and a further
40 GW of project awards in the pipeline. While not all of this potential capacity is expected to be
realised, nonetheless the UK is expected to dominate offshore wind within Europe for the
foreseeable future. This market will be important for Irish players, due to the proximity of many
locations. Irish Sea, Bristol Channel and Scottish West Coast projects will form something of a
regional market rather isolated from the main North Sea market by a fairly demanding sea transit.
Two sub-sections are therefore presented here; Section 3.1 assessing the potential of Ireland and
the West coast of the UK (or “adjacent waters”) to act as a single market for Irish suppliers, and
Section 3.2 following which assesses the potential of the whole UK market.
The following three charts therefore present GLGH’s central installation forecasts for projects in
adjacent waters around the west coast of the UK added to each of the three scenarios for Irish
development described in Sections 2 and 3. The graphs provide projections over the next 11 years.
It has been decided not to extend projections beyond this timeframe, as uncertainty increases
beyond a reasonable level.
7000
1000
6000
800
700
5000
600
4000
500
400
3000
300
2000
Cumulative [MW]
Wind Farm Capacity (New
Installations) [MW]
900
200
1000
100
0
0
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Year
North West England
Republic of Ireland
N Ireland
Scotland South
Scotland West
Cumulative
Figure 3.1: Projected capacity for ROI and adjacent waters under Low Scenario [MW]
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1000
7000
6000
800
700
5000
600
4000
500
400
3000
300
2000
Cumulative [MW]
Wind Farm Capacity (New
Installations) [MW]
900
200
1000
100
0
0
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Year
North West England
Republic of Ireland
N Ireland
Scotland South
Scotland West
Cumulative
1000
7000
900
800
6000
700
5000
600
500
4000
400
3000
300
2000
200
100
1000
0
Cumulative [MW]
Wind Farm Capacity (New
Installations) [MW]
Figure 3.2: Projected capacity for ROI and adjacent waters under Medium Scenario [MW]
0
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Year
North West England
Republic of Ireland
N Ireland
Scotland South
Scotland West
Cumulative
Figure 3.3: Projected capacity for ROI and adjacent waters under High Scenario [MW]
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3.1.2 Quantification of services and materials required
The following charts present for each scenario the demand within this Ireland and adjacent waters
market for foundation supply and installation vessels, identified in Section 2 as the most promising
major elements for Irish industrial development during the construction phase.
180.0
160.0
140.0
120.0
100.0
80.0
60.0
40.0
20.0
11
20
12
20
13
20
14
20
15
20
16
20
High
17
20
Medium
18
20
19
20
20
20
21
20
20
20
21
20
Low
Figure 3.4: Foundations installations [units]
4.0
3.5
3.0
2.5
2.0
1.5
1.0
0.5
11
20
12
20
13
20
14
20
15
20
16
20
High
17
20
Medium
18
20
19
20
Low
Figure 3.5: Demand for foundations installation vessels [no. of vessels]
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2.5
2.0
1.5
1.0
0.5
11
20
12
20
13
20
14
20
15
20
High
16
20
17
20
Medium
18
20
19
20
20
20
21
20
Low
Figure 3.6: Demand for wind turbine installation vessels [no. of vessels]
A commentary concerning the Irish supply chain possibilities for the “adjacent waters”
market is provided in conjunction with assessing the UK market as a whole in Section 3.2.3
below.
3.2 Forecast of market around the UK
3.2.1 Description of development potential
The following figures illustrate GLGH’s forecasts for installation activity across the whole UK as an
independent market over the next 12 years. It is apparent that current licensed rounds of activity
are expected to begin tailing off at the end of the decade; whether or not a further “Round 4” of
development is introduced to maintain activity levels is presently unknown.
Evidence of political support for offshore wind can be seen in the fact that the Crown Estate (the
seabed owner in the UK) quickly implemented “Round 2.5”, an invitation to Round 1 and 2 projects
to develop extensions to existing projects. This development made use of existing permits and
licenses to ensure no hiatus in installations between rounds 2 and 3.
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25,000
3,000
20,000
2,500
2,000
15,000
1,500
10,000
1,000
5,000
500
Round 3
Round Ext
1&2
Round 2
Round 1
Cumulative
0
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
0
Scottish
Round
ad-hoc
Cumulative capacity (MW)
Wind Farm Capacity (New
Installations) [MW]
3,500
March 2011
Year
Figure 3.7: Projected capacity installed by phase in the UK [MW]
3500
25000
Scotland
20000
2500
2000
15000
1500
10000
1000
5000
500
Cumulative
Wind Farm Capacity (New
Installations) [MW]
N Ireland
3000
NW
NE
Wash
Bristol Chan
Thames
0
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
0
Year
South
Cumulative
Figure 3.8: Projected capacity installed by region in the UK [MW]
3.2.2 Quantification of services and materials required
With many of the Round 3 developments located far from the mainland, installation is expected in
deeper waters than seen previously, Figure 3.9. This will present new challenges to the industry,
both in terms of operational logistics and in terms of budgeting.
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Support Structure Installations
600
March 2011
United Kingdom
>75m
500
50-75m
400
40-50m
300
30-40m
20-30m
200
10-20m
100
0-10m
20
22
20
21
20
20
20
19
20
18
20
17
20
16
20
15
20
14
20
13
20
12
20
11
20
10
0
Year
Figure 3.9: Foundations installations by water depth in the UK [units]
The large number of vessels required to service the UK industry, Figure 3.10, could provide an
important market for any Irish operator wishing to export capabilities and services.
25
Wind Turbine Repairs Vessel Demand
Wind Turbine Installation Vessel Demand
Support Structure Installation Vessels Demand
Geotechnical Survey Vessel Demand
Environmental & Geophysical Survey Vessel Demand
United Kingdom
Vessels
20
15
10
5
0
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Year
Figure 3.10: Vessel demand in the UK [no. of vessels]
3.2.3 Commentary of Irish supply chain possibilities
Foundation supply
Figure 3.9 indicates a substantial increase in requirements for foundations in UK waters from
around 2015 onwards, and the majority of these are for water depths similar to those that will be
required for Irish projects. There will be substantial competition for this work, but location does
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offer some advantage in this market. Figure 3.4 shows that a substantial part of this market is in
waters adjacent to Ireland. Therefore there may be an opportunity to build a foundation supply
business mainly for projects in western UK waters from around 2015, before the requirements for
Irish projects in 2020-2030 would justify such a facility, as identified in Section 2.
It should be noted that some projects have sourced their foundations from Asia, so location alone
will not offer sufficient competitive advantage in this market.
Vessels for turbine installation, foundation installation and O&M
Figure 3.10 indicates that, together with demand in Irish waters, there is unlikely to be a case for
establishing new vessels for environmental, geophysical and geotechnical surveys in Irish waters,
unless there is some existing competitive advantage.
However, the demand for new vessels for foundation installation, turbine installation and repairs is
substantial. Vessels based on the east coast of Ireland should be able to compete for work on UK
west coast projects (see Figure 3.5 and Figure 3.6), and possibly further afield.
O&M services
Apart from vessels, there is the possibility of providing O&M services to projects in western UK
waters from bases in Irish east-coast ports. As there are likely to be benefits in centralising spares
holdings, management and staffing, and as UK ports are already the first-movers, this is only likely
to happen if there is some cost advantage in an Irish location, such as labour costs, or tax
treatment.
3.3 European offshore market
3.3.1 Description of development potential
In the rest of Europe, Germany looks set to lead the way, with large potential development also in
the Netherlands, France and Spain. The uncertainty involved in predicting development in many
of these secondary European countries is large, as often the political stance on offshore wind has
not been clarified. Nonetheless, taking these markets in aggregate, they are expected to constitute
a significant level of activity. Many countries however have strong domestic players, who will hold
an advantage over new Irish entrants to the scene; hence barriers to entry may be considered high.
3.3.2 Commentary of Irish supply chain possibilities
While it is useful to have the context of the wider European market, this too is likely to pre-date
development of offshore wind in Ireland albeit running behind the UK programme. While there is
currency in common, it is hard to see how that will place Ireland at any real advantage against
mainland Europe and challenges of entering these non-UK markets are at least as high as entering
the UK market.
3.4 North American offshore market
3.4.1 Description of development potential
Both the USA and Canada have been slow in developing an offshore wind industry, with currently
no installations, and only a very few projects holding permits. There are a number of load centres
on the American seaboard, making offshore wind potentially attractive, however political
ambivalence and complex consenting procedures have so far prevented any development
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reaching construction. The coming decade could see some activity, however this is unlikely to be
major, and in any case will be mostly unavailable to European operators – American preference for
domestic players combined with the large physical distance of the market makes entry impractical.
3.4.2 Commentary of Irish supply chain possibilities
No significant opportunities are foreseen.
3.5 European onshore market
3.5.1 Description of development forecasts
The European onshore market includes the most mature wind energy markets of the world. These
include Germany, Denmark and Spain who are often seen as the pioneering nations for large-scale
wind installation. Nevertheless saturation levels are being reached for suitable sites particularly in
Germany and Denmark, as well as in their densely populated western neighbours of Belgium and
the Netherlands. Attention for future development is therefore turning towards offshore and
repowering. Meanwhile Spain has seen concerns over the grid and system balancing result in
limitations on new capacity being imposed.
Other Western European markets still have significant room for expansion and can expect to see
continued steady growth in their onshore installations over the coming 5 years at least. These
markets, led by the UK, Italy and France have been classified here as “scaling markets”.
Eastern European countries are typically newer to wind and thus many of the best sites remain
open to development as increasing numbers of governments put in place favourable support
mechanisms and regulatory structures to attract developers. Poland has already seen notable
growth over the last 3 years while Romania and Bulgaria both have ambitious project pipelines
already in development and construction.
Figure 3.11 presents GLGH’s forecasted growth for each of these market segments through the
next decade. The values are based on a desk-top review of national wind programs, the strength of
political support and noted activity by developers. It should be noted that predictions beyond
2015 typically include a much higher degree of uncertainty as this is generally beyond the scope of
developers’ declared project pipelines, and the effect of any policy direction change by national
governments in the intervening period will be amplified.
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Annual Installed Capacity [MW]
14000
12000
10000
8000
6000
4000
2000
0
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Western Europe Mature
Year
Western Europe Scaling
Eastern Europe
Figure 3.11: Forecast of European onshore new installations to 2020
{Source: GLGH}
3.5.2 Commentary of Irish supply chain possibilities
The established onshore wind developers and contracting companies in Ireland have continuing
opportunities in European onshore markets. Indeed, Ireland’s onshore wind programme (and
perhaps also the early Arklow Bank Phase 1 offshore project) drove the development of the
Airtricity, Mainstream and ESBI businesses which continue to have a significant Irish presence for
the wind sector although their focus is now on other markets. It is perhaps in these ‘softer’ skillsets that businesses based in Ireland can prosper best across the wind business generally – onshore
and offshore.
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4
March 2011
RECOMMENDATIONS
4.1 Key infrastructural investment required
Infrastructure issues for grid connection were discussed in Part A.
Investment in ports is treated here as infrastructure investment. Investment for the construction
phase is likely to follow the projects, i.e. investment in port facilities required for installation vessels,
workboats and transhipment of major components is not justified until projects commence. The
large UK Round 3 Irish Sea project (4200 MW) is a possible exception: advance investment in an
Irish port might conceivably gain business that would otherwise go to a UK port. This seems a risky
strategy, and detailed investigation would be necessary before committing significant investment.
The same argument applies to port investment for O&M services: advance investment is unlikely to
gain a significant advantage for Irish ports. Service ports are selected for location and accessibility
– after which investment to bring these up to standard can be made.
4.2 Measures aimed at industry / supply chain development
Three main options have been identified for the involvement of Irish companies in the offshore
wind supply chain:
 Foundation manufacturing, aimed at projects in ROI and western UK waters. Tower
manufacturing could be included.
 A concerted effort from Irish Industrial Development Agencies to promote Irish facilities to
the entire offshore wind supply chain similar to that undertaken by Invest NI and DETI in
the UK could be successful in attracting some supply chain companies to Ireland.
 Vessels for foundation and turbine installation, and turbine repair, again aimed at projects
in ROI and western UK waters. Providing a home and support services for such vessels may
be more attractive than Irish ownership, as owners of fleets tend to have an advantage.
Foundation and tower manufacturing
A study of the comparative advantages of foundation manufacture in Ireland may be justified. The
Irish Sea is not just separated from the North Sea by distance, it is also characterized by very
demanding seabed conditions – suggesting that there may be an opportunity for an innovative
local solution. Added to this, there are several Irish firms well-placed to play a part in delivery of
some candidate solutions although some industry acquaintance work is needed – perhaps
achievable through a demonstration project programme.
If monopiles are the preferred foundation type, a manufacturing facility may gain some advantage
by also making towers.
Such a facility should aim at projects in ROI and western UK waters. In particular, gaining work
from western UK projects prior to 2020 would be an advantage.
Vessels for foundation and turbine installation, and turbine repair
The analysis in earlier sections indicates a need for one to three vessels for Irish projects, from
around 2020 onwards. The requirement for UK projects is much greater, and starts earlier, and
should be open to vessels based in Ireland. However, operating such vessels tends to favour larger
organisations operating a fleet, and the large vessel sector in Ireland is weak. On balance, support
measures may best be directed towards support services.
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O&M bases
No measures are considered to have value on this front.
Other
As a background activity, regular updating of forecasts for progress of offshore projects in
European waters would be useful for government and industry in Ireland.
4.3 Policy support at Irish and EU levels
The main thrusts of policy to open opportunities for Irish offshore wind are:




Opening market for trading of renewable energy (or possibly carbon credits) across Europe
Harmonisation of transmission system rules and mechanisms across Europe
Build of key interconnectors
Developing streamlined regulatory framework (leasing, environmental assessment and
consenting) for offshore wind projects within Irish waters including the whole economic
zone and not just territorial waters (noting that after 2025 floating offshore wind may be a
commercially viable technology)
4.4 R&D actions aimed at gaining market share
Short-term:
 Foundation demonstration to promote foundations optimised for Irish Sea sites
 Turbine demonstration onshore and offshore, or combined foundation and turbine
demonstration. Turbine and foundation manufacturers are currently looking for sites to
carry out these activities both onshore and offshore
 Investigation of floating turbine demonstration possibilities in the extreme wind and wave
climate off the West coast
 Demand-side system management measures to allow increasing penetration of
renewables into the Irish island system
Long-term:
 Collaborative work with neighbouring nations on interconnection to support the policy
harmonisation and market opening efforts but also to define the optimum topology for
interconnection
 Floating wind R&D, possibly collaborative with other countries sharing same deep water
characteristics e.g. Spain, Norway, Scotland.
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[67] Blue H website http://www.bluehgroup.com
[68] Blue H Press Release, Blue H’s GEOMA Project selected by Italian Government, 24. February
2009, http://www.bluehgroup.com/company-newsandpress-090224.php
[69] Blue H Press Release, Blue H’s Deepwater Floating Wind Turbine Project selected by UK
Government, 14. January 2009, http://www.bluehgroup.com/company-newsandpress090114.php
[70] ETI Press Release, Energy Technologies Institute Unveils First Projects To Benefit From £1.1
Billion Initiative, 13/01/2009, http://www.energytechnologies.co.uk/home/news/09-0113/ENERGY_TECHNOLOGIES_INSTITUTE_UNVEILS_FIRST_PROJECTS_TO_BENEFIT_FROM_1_
1_BILLION_INITIATIVE.aspx
[71] Pôle Mer Bretagne, DIWET: Deep-water offshore wind turbine floating on a semi-submerged
platform anchored using a tension leg system, http://www.pole-merbretagne.fr/diwet_1.php
[72] Blue H Press Release, Massachusetts Deepwater Wind Energy Project - Blue H USA
Announces its Application to the US Army Corps Of Engineers for a Deepwater Offshore
Wind Platform, 5 October 2009, http://www.bluehgroup.com/company-newsandpress091005.php
[73] Blue H Press Release (source ANSA), Tricase Floating Wind Farm Authorization,11 September
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2009, http://www.bluehgroup.com/press/ANSA_Sky_Saver_Tricase_11Sep09.pdf
[74] Blue H Press Release, Consortium NORTHWESTER applied for offshore wind concession to
CREG, 23. October 2008, http://www.bluehgroup.com/company-newsandpress-081023.php
[75] Bertacchi, P. Di Monaco, A., de Gerloni. M., Ferranti, G., (1994). Eolomar - a moored platform
for wind turbines; Wind Engineering Vol. 18, No. 4, p189
[76] Hannevig, D., Bone, D., Low cost self-installing offshore wind turbine support structures for
deeper water, Workshop on Deep Water Offshore Wind Energy Systems, NREL / Department of
Energy, Washington, 2003
[77] Molin B., Remy F., Facon G., Etude Expérimentale du comportement Hydro-Aéro-Elastique
d'une Eolienne Offshore sur Ancrages Tendus (translation: Experimental study of the hydroaeroelastic behaviour of an offshore wind turbine on tensioned moorings), Ocean Energy
Conference, Brest, France, 2004
[78] Musial W., Overview: Potential for Offshore Wind Energy in the Northeast, Offshore Wind
Energy Collaborative Workshop, Washington D.C., February 10-11, 2005
[79] Sclavounos P. D., Deep Water Floater Concepts for Offshore Wind Turbines. Design,
Modeling and Testing, Workshop on Deep Water Wind Energy Research & Development
Planning, NREL / Department of Energy, Washington, 2004
[80] Le journal Ouest-France, Énergies marines, le pari en manque d'argent, mardi 13 octobre
2009, http://www.ouest-france.fr/actu/actuDet_-energies-marines-le-pari-en-manque-dargent-_8619-1107844_actu.Htm
[81] Pôle Mer Bretagne, WINFLO: Deep-water offshore wind turbine floating on a semisubmersible platform anchored using catenary mooring cables, http://www.pole-merbretagne.fr/winflo_0.php
[82] Principle Power Inc - Column-Stabilized Offshore Platform with Water-Entrapment Plates
and Asymmetric Mooring System for Support of Offshore Wind Turbines, Patent
WO2009131826
[83] Principle Power Press Release, Principle Power and EDP Sign MOA for Phased Offshore Wind
Power Project, February 18, 2009,
http://www.principlepowerinc.com/news/press_EDP_MOA.html
[84] Principle Power Press Release, Tillamook Offshore Wind Energy Demonstration Project –
Principle Power Signs Memorandum of Agreement, November 24, 2008,
http://www.principlepowerinc.com/news/press_TPUD_MOA.html
[85] Windsea website, http://www.windsea.no
[86] Bulder, van Hees, Henderson, Huijsmans, Pierik, Snijders, Wijnants, Wolf, Studie naar
haalbaarheid van en randvoorwaarden voor drijvende offshore windturbines (translation:
Study of the feasibility and boundary conditions of floating offshore wind turbines), “DrijfWind”,
TNO Report 2002-CMC-R043, Netherlands, 2002
[87] Halfpenny, A., Dynamic analysis of both on- and off-shore wind-turbines in the frequency
domain; PhD Thesis, University College London, 1998
[88] Henderson, A. R., Analysis Tools for Large Floating Offshore Wind Farms, PhD Thesis,
University College London, 2000
[89] Lagerwey, Freely floating wind power plant, Patent NL1008318
[90] Lagerwey, Artificial wind turbine island, Patent WO9902856
[91] The Scottish Government, User Guide – Multipliers,
<http://www.scotland.gov.uk/Topics/Statistics/Browse/Economy/InputGarrad Hassan & Partners Ltd
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Output/Mulitipliers>
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APPENDIX 1
WIND SPEED MAPS FOR IDENTIFIED BATHYMETRIC CLASSES
Figure A1: Wind map of the Irish EEZ at 100m above MSL for water depths of 0 - 50m
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Figure A2: Wind map of the Irish EEZ at 100m above MSL for water depths of 50 - 100m
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Figure A3: Wind map of the Irish EEZ at 100m above MSL for water depths of 100 - 500m
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Figure A4: Wind map of the Irish EEZ at 100m above MSL for water depths of 500 - 1500m
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Figure A5: Wind map of the Irish EEZ at 100m above MSL for water depths of 1500m+
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APPENDIX 2
MAJOR OFFSHORE WIND TURBINE SUPPLIERS
BARD
The BARD group have taken a complete turnkey approach to the development of offshore wind
projects, spanning the full scope of works from design and procurement through construction and
operation. They are currently proving this philosophy through the development of BARD Offshore
1 in the German Bight where they will install 400MW of their own turbines. At this stage their
concept of total involvement remains to be proven.
Clipper
Through the Brittania model, US based supplier Clipper Wind hope to enter the offshore market,
with the assistance of One North East, the regional development agency. This is an upscaling and
marinisation of their (onshore) Liberty design to create a model which will be in the 7.5MW to
10MW range. At this stage unproven, however Clipper’s plans include developing a blade
production plant and turbine manufacturing facilities in the north east of England.
General Electric
GE (General Electric) had a brief foray into offshore wind, noteably with the Arklow Bank project,
where 7 of their 3.6MW wind turbines are installed. However, since this time, they have had little
further involvement within the UK offshore industry until the announcement earlier this year that
they plan to build an offshore wind turbine manufacturing plant in Britain. The plant forms part of a
10 year, €340m investment plan into the wind industry in Europe by GE. With the purchase of
Norwegian technology developer ScanWind in 2009, GE has acquired a wind turbine design
suitable for offshore deployment and is currently going through the process of re-engineering and
prototyping a 4MW unit, specifically aim at the offshore wind market.
Mitsubishi
The Japanese firm unveiled plans earlier this year to invest £100m in building a new WTG factory in
the north-east of England. No further details of their proposed technology had entered the public
domain at the time of writing.
Multibrid (Areva)
Until September 2007, Multibrid were owned by German wind developer, PROKON Nord. At this
time, French engineering giant Areva acquired a 51% stake in the company, providing massive
financial strength to the company and enabling the potential for a ramp up of production
capabilities. Located at Bremerhaven in Germany with a dedicated M5000 manufacturing and
assembly facilities, the company has installed four onshore versions of the M5000 turbine at the
Bremerhaven offshore wind test field. As such there has been a lack of offshore specific data
however, with the deployment of six wind turbines offshore at Alpha Ventus during the summer
and autumn of 2009, firm evidence will now start to become available. Moving into 2010 and
beyond, the experience level with the M5000 will continue to grow as 21 units are installed at Cote
d’Albâtre off the North French coast (originally scheduled for installation starting in 2010), along
with 80 at Borkum West II (scheduled for installation starting in 2012), to the west of Alpha Ventus.
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REpower Systems
REpower has been operating in the wind industry since 2001 when the company was formed
through the merger of two German turbine manufacturers, an engineering design house and a
wind farm developer. In the decade since its inception, REpower has exhibited strong and
sustained growth moving steadily from installations of ~100MW / annum in 2001 up to ~1,300MW
/ annum in 2009, corresponding to a 10th position in terms of global market share (3.4%). Sales
have seen a significant acceleration since the takeover by Suzlon in May 2007. REpower has
focused attention on a small number of premium national markets; Germany, France, USA and the
UK.
The REpower 5M and 6M constitute the RS range of offshore wind turbine products. Both are
exclusively designed for the offshore market with the first prototype of the former being deployed
onshore in 2004. Steady and successive deployment of further 5M units in the context of offshore
R&D / demonstrator projects has been implemented since at; Beatrice (2006) 2 units, Thornton
Bank 2008 6 units, Alpha Ventus 2009 6 units. RS are yet to deploy either 5M or 6M products in the
context of a utility scale commercial offshore wind project.
Siemens Wind Power
SWP (formerly Bonus Energy A/S) has been operating continuously in the wind industry since 1980.
Strong growth through the late 1990s on the back of an upscaled product line (1MW and 1.3MW)
and strong demand in DK and DE markets was followed by flatish growth through the period 2000
- 2005 with an annual installation rate of ~500MW / annum. Following the acquisition of Bonus by
Siemens in late 2004, sales growth and production ramped up substantially with installations in
2009 reaching 2,300MW, corresponding to a 9th position in terms of global market share (5.9%).
Following the maturation of the home market (DK), SWP has focused attention on a relatively
narrow range of premium national markets, principally the UK and USA.
The larger end of the current SWP product line are all suitable and marketed for offshore
deployment, although only the 3.6MW range is predominantly designed for this market. SWP
currently offers 6 models for potential offshore deployment albeit grouped into 3 distinct product
lines; 2.3MW (3 models), 3.0MW ( 1 model - direct drive) and 3.6 MW (2 models). The latter is
currently the principle product offering for the offshore wind sector though, with the smaller
models designed to service niche sites and the broader onshore market.
At the time of writing, ~400 SWP offshore wind turbines are operational (offshore) with a further
~1,000 under construction or contract.
Vestas
Vestas has been operating in the wind industry since 1980 and since a merger with a rival Danish
manufacturer in 2004 (NEG Micon) has been the overall global market leader with strong, if at times
fluctuating, sales and production capacity growth. The last three years has seen a stabilisation of
growth with annual installations averaging at ~4,700MW / annum. Because of this, Vestas are
losing market share, although they still hold a (narrow) leading position for 2009 installations,
which stood at 12.5%. Vestas has targeted a wide range of national markets and has to a much
greater extent broadened the supply base to follow geographic market trends.
Following early deployments on R&D based projects in Sweden and the UK, the product range
deployed offshore has consisted of V80-2.0MW (2003-2006) and V90-3.0MW (2006 - 2010) units.
The first offshore deployment of the V80 unit was at Horns Rev in 2003 (80 units) followed by North
Hoyle also in 2003 (30 units) and Scroby Sands (30 units 2004) and latterly Q7 in 2007 (60 units).
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The offshore roll-out of the V90 unit began at Kentish Flats (30 units, 2005), Barrow (30 units, 2006),
Egmond (36 units, 2007) and Robin Rigg (60 units, 2008). A further 2 projects (Thanet, 100 units and
Bligh Bank, 65 units) are under construction with the V90 platform.
At the time of writing, ~350 VO offshore wind turbines are operational (offshore) with a further
~150 under construction or contract.
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APPENDIX 3
MAJOR OFFSHORE WIND DEVELOPERS
Accíona
Accíona renewable energy business is being built on the foundations of EHN, a pioneer in wind
energy in Spain, which Accíona bought in 2003/5. From its head-quarters in Pamplona, the
company has built wind farms initially in the Navarra region, then throughout Spain and now
across the world. Offshore ambitions are currently restricted to plans at the Cabo de Trafalgar site
in Southern Spain.
BARD
BARD is unique amongst wind energy project developer in that not only is it developing its own
wind turbine, but also its own installation vessel and support structure concept. The philosophy is
that an integrated solution covering all aspects of the offshore wind farm will be cheaper and more
reliable ultimately and although there is perhaps merit to this argument, BARD is the only company
currently putting it into practice.
BP
BP is one of the largest oil and gas companies in the world and together with Shell, the two
European giants of this industry. To date, BP’s involvement in renewable energy has been
restricted to a long term investment in solar PV, however recently a wind energy business unit has
been created and the size of the company means that European onshore projects are of little
interest. After a brief flirtation with offshore wind energy, BP has reduced activity to supporting the
development of a new offshore wind turbine, Helm Wind, in the ETI programme.
Centrica
Centrica plc was formed in February 1997 as a result of the demerger of British Gas plc into Centrica
and BG, and remains the largest residential supplier of gas and electricity in the UK. Centrica Energy
is the branch in charge of upstream gas production, electricity generation, renewable asset
operations and wholesale.
Centrica is currently investing in seven offshore wind farm developments, all in the UK, three of
which (Barrow Offshore Wind, co-owned with Dong, Lynn and Inner Dowsing) from the UK Round 1
are operational with 191MW installed capacity. In addition, Centrica has rights to three Round 2
projects, with Lincs being contracted for construction in 2011, and two further, Race Bank and
Docking Shoal, awaiting consent. Centrica successfully bid for a UK Round 3 zone in the Irish Sea,
and will be installing more than 1,200MW in the next ten years through their portfolio of sites.
DONG
DONG (Danish Oil and Natural Gas) is owned by the Danish State. In 2005, DONG merged with
Elsam and E2, the Danish electricity generation operators in West Denmark and East Denmark
respectively, while selling a number of assets in Denmark to Vattenfall (Sweden). DONG owns the
largest portfolio of any offshore wind developer. Through Elsam and E2, DONG owns the majority
of Nysted (DK) and 40% of the Horns Rev (DK) offshore wind farm. Through its purchase of E2,
DONG has won the bid to build a 200 MW extension of Horns Rev. In the UK, DONG is the operator
of Barrow (50% owned by Centrica) and Burbo Round 1 offshore wind farms, with Gunfleet Sands
currently under construction and Walney and London Array contracted. DONG was highly active
towards the end of 2009, purchasing a share in Lincs and SSE’s Dutch portfolio and buying out the
partners from the previously jointly owned German projects. Their operational projects amass to
around 700MW of installed capacity. DONG appears to have focused on shallow water sites, no
doubt due to their superior economics, and does not currently have any projects in average water
depths greater than around 30m. The lack of success in the UK Round 3 means that currently
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DONG’s portfolio may be completed before the end of this decade. It is unlikely that an offshore
wind farm developer with DONG’s success and experience will not find further opportunities.
EDF
EDF (Électricité de France), the French national electricity utility, has holdings in Germany (as
EnBW), the United Kingdom (as SWEB, Seeboard, and EDF Energy, formerly London Electricity), and
numerous other countries, mainly in Europe. EDF is developing projects in France, in the UK
(Teesside and the abandoned Cromer project), and in Germany.
EDP
EDP’s (Energias de Portugal) substantial appetite for wind energy now includes a UK offshore wind
project in the North of Scotland. EDP has formed a joint venture with SeaEnergy, a Scottish
company including veterans of the Beatrice demonstrator. EDP’s other publically announced
venture is to develop wind farms on floating support structures off Portugal, where waters are
similarly deep as off the North-East of Scotland.
EnBW
EnBW (Energie Baden-Württemberg) announced their entry in a major way into offshore wind with
the purchase of a portfolio of offshore wind farms in German waters from WPD. The company,
based in South-West Germany, is part owned by EDF and until this point had shown relatively little
interest in renewables including wind energy. The first project consisting of 21 wind turbines,
Baltic I, is scheduled for construction during 2010.
Eneco
With the purchase of the wind project assets of Econcern and its development arm Evelop, Eneco
became the Netherlands largest renewable energy company with interests across all major
technologies. In the last years attention has turned to offshore wind with the first project Q7, of
120MW, now operational and further projects planned in Belgium (AirEnergy), the Netherlands and
the United Kingdom (Round 3 Isle of Wight Zone).
E.ON
E.ON Climate & Renewables brings together all E.ON’s renewable generation activities into a single
integrated business. E.ON is also holds stakes in some German and Swedish offshore projects, but
to date most of the companies offshore wind capacity is in the UK with 260MW currently operating.
With the part share in Alpha Ventus, Germany is now included, and once Nysted II is operational,
Denmark will also be included in the portfolio. Future plans include further sites in Sweden,
Germany and the United Kingdom, including the Round 3 site off Hastings on the southern coast of
England.
GEO
GEO is a project development bureau specialised in developing German wind farm projects,
including those offshore, through to consent but with no interest or capability in construction or
operation of wind farms.
Iberdrola
Due to its strong position base in Spain, one of the most important onshore wind energy markets
of recent years, Iberdrola has grown to be arguably the largest renewable energy company in the
world. Until the purchase of Scottish Power, its interests in offshore wind were limited to a
speculative project at Cabo de Trafalgar off southern Spain. Now it owns a stake in West of
Duddon (Round 2) and the 7,200 MW Norfolk site (Round 3).
PNE WIND
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PNE WIND (formerly Plambeck Neue Energie) is a German project developer with around half a
dozen offshore wind projects in German waters, both in the North and Baltic Seas. No doubt due
to is part ownership by institutional investors (Credit Suisse and Fidelity) and its relatively small
size, its focus has been on the high value pre-construction development phase of offshore wind.
Prokon Nord
Prokon Nord is a German project developer, previously with ownership of the turbine
manufacturer Multibrid (now sold to Areva). It is developing a number of offshore wind farms in
the German North Sea, which will use the Multibrid M5000 turbine. They are owners of the only
consented French offshore wind farm, Côte d’Albâtre.
RWE Innogy (npower)
RWE Innogy, is the second largest utility in Germany (after E.ON) and, with npower renewables of
the UK, is one of the leading renewable energy developers with a wide ranging portfolio that
includes both onshore and offshore wind farms.
RWE built the first UK offshore wind farm, at North Hoyle, and today is the third largest operator of
offshore wind farms, with a similarly large and diverse portfolio contracted and under construction.
Over the coming decade, development is currently anticipated to focus on the three main
European markets: Germany, the Netherlands and the United Kingdom.
Shell Wind Energy (SWE)
SWE is part of Shell Renewables, one of the five core businesses of the Shell Group.
Regarding offshore wind, SWE is active through its NoordZeeWind project off the Dutch coast. It
subsequently announced its decision to withdraw from offshore wind and focus on US onshore
wind projects and hence disposed of its holdings.
SSE
SSE (Scottish & Southern Energy; with the renewables arm previously known as Airtricity) is a
world-leading renewable energy company, developing and operating onshore wind farms in
Ireland, Scotland, England, Wales and the United States. As an integrated utility, the company is
both a generator and supplier of green electricity and currently supplies green electricity to over
50,000 commercial customers in Ireland.
SSE has co-developed the Arklow Offshore Wind Farm in Ireland, which has been operated by GE
Energy since 2003. SSE is currently constructing the UK Round 2 Greater Gabbard Offshore Wind
Farm and has a portfolio of further projects under development in Germany, Ireland the
Netherlands and the United Kingdom.
Stadtwerke München
A relatively new entrant to the field of offshore wind, this German state utility company has taken a
30% stake in the Gwynt y Môr project in the UK and also a 49% stake in the DanTysk project in
Germany.
Statkraft
The Norwegian state-owned utility Statkraft can claim to be the world’s largest operator of
renewable energy through its portfolio of hydroelectric schemes. Statkraft have 50% ownership of
the under-construction Sheringham Shoal UK Round 2 project and are part of the Forewind
Consortium which holds development rights for the Round 3 Dogger Bank Zone.
Statoil
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Norwegian Oil & Gas giant Statoil (previously Statoil-Hydro) have been active in wind energy for a
number of years including the development of their Hywind floating wind technology.
In addition to their 50% owner ship of the UK Round 2 Sheringham Shoal project, they are one of
four partners constituting the Forewind consortium which is currently developing the UK Round 3
Dogger Bank Zone.
Vattenfall
Vattenfall is Europe's fifth largest generator of electricity and the largest generator of heat. They
are also a close second to DONG in terms of offshore wind capacity ownership. Vattenfall owns the
Utgrunden and Lillgrund (Sweden) and Kentish Flats (UK) offshore wind farms and 60% of the
Horns Rev project. Vattenfall has also recently completed the construction of the Thanet Offshore
Wind Project in the greater Thames Estuary which is currently the world's largest offshore wind
project. Arguably, Vattenfall has the most diversified of all portfolios, in terms of country, as well as
turbine supplier and foundation type. Their current shallow water focus will mature along with
much of the rest of the market to include the deeper waters of their Norfolk Round 3 Zone which
they are developing in partnership with Scottish Power/Iberdrola.
Warwick Energy
WEL (Warwick Energy Limited) is an independent power producer, whose current asset base
includes small scale "embedded" generation capacity, and a number of onshore and offshore oil
and gas licences. WEL developed the Barrow offshore project in the UK before selling it to
Centrica/DONG. WEL was awarded the Thanet and Dudgeon East UK Round 2 offshore projects,
with Thanet recently commissioned following a sale to Vattenfall, and Dudgeon recently submitted
for permit approval.
WPD
WPD is arguably the most successful German wind energy developer in terms of delivering
onshore wind projects in Germany and abroad. The offshore wind business is based in Stockholm,
Sweden. It remains to be demonstrated whether WPD will have the financial resources to take
offshore wind farms through construction or whether the currently high valuations will prove an
excessive temptation, as was demonstrated with the sale of the German offshore portfolio to
EnBW.
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APPENDIX 4
WTG Sub-Component Suppliers
The lists below show the main WTG sub-component suppliers, categorised by component, which
supply the offshore industry. This is not an exhaustive list, however it gives an idea of the wide
array of organisations involved within the supply chain. The * denotes an organisation with major
market share.
Nacelle
Bedplate
Felguera Melt
Fonderia Vigevanese
Metso
Meuselwitz
Rolls Royce Foundry
Siempelkamp
Vestas
Eisengiesserei Torgelow
Siempelkamp Giesserei
Gusstec
Wilhelm Guss-Engineering
& Projektmanagement
www.durofelguera.com
www.vigevanese.it
www.metso.com
www.meuselwitz-guss.de/index.php?id=365&L=1
www.rolls-royce.com
www.siempelkamp.com/index.php
www.vestas.com
www.eisengiesserei-torgelow.de
www.siempelkamp.de/Giesserei.716.0.html
www.gusstec.de
www.w-g-p.de
Main Bearing
FAG
IMO
Liebherr
NSK
NTN
Rollix
Rothe Erde
Kaydon
SKF
Timken
KOYO(JTEKT)
Luoyang LYC
www.fag.com
www.imo.de
www.liebherr.com
www.nsk.com
www.ntn.co.jp
www.rollix.com
www.rotheerde.com
www.kaydon.com
www.skf.com
www.timken.com
www.koyo.co.uk
www.lycbearing.com
Main Shaft
Bruck
Euskal
Thyssen
Forgiatura Mame
Celsa Huta Ostrowiec
www.bruck-uk.com
www.euskalforging.com
www.thyssenkrupp.com
www.forgiaturamame.it
www.celsaho.com
Gearbox
Bosch-Rexroth
Eickhoff
Hansen
www.boschrexroth.com
www.eickhoffcorp.com
www.hansentransmissions.com
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Moventas
Winergy
Renk
Voith Turbo
Ishibashihi
David Brown
Jahnel Kestermann
Wikov MGI
Dalian Heavy Industry
www.moventas.com
www.winergy-ag.com/index.php
www.renk.de
www.voithturbo.com
www.ishibashi-mfg.com
www.davidbrown.com
www.jake-gear.com
www.wikov.com
www.dhidcw.com
Generator
Leroy Somer
ABB
Vestas
Siemens
VEM
Enercon
Ingeteam
Cantarey
Toshiba
Weier
Elin
Winergy
The Switch
Converteam
www.leroy-somer.co.uk
www.abb.co.uk
www.vestas.com
www.siemens.co.uk
www.vem-group.com
www.enercon-eng.com
www.ingeteam.eu/ingles/productos_servicios/energia/eolica.asp
www.cantarey.com
www.toshiba.com
www.weier-electric.de
www.elinmotoren.at/Home.12.0.html?&no_cache=1&L=1
www.winergy-ag.de/index.php
www.theswitch.com
www.converteam.com
Power Take-off
Power Converters
ABB*
Alstom
GE
Enercon
Ingeteam
AMSC
Converteam
The Switch
Winergy
PCS
KK Electronic
Windtec
Transformers
ABB*
GE
CG (Pauwels)
Schneider
Siemens*
SGB
Maschinenfabrik
Reinhausen
Areva T&D*
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www.abb.co.uk
www.alstom.com
www.ge.com
www.enercon-eng.com
www.ingeteam.eu/ingles/productos_servicios/energia/eolica.asp
www.amsc.com
www.converteam.com
www.theswitch.com
www.winergy-ag.de/index.php
www.pcs-converter.co
www.kkelectronics.co.uk#
www.amsc-windtec.com
www.abb.co.uk
www.ge.com
www.pauwels.com
www.schneider-electric.co.uk
www.siemens.co.uk
www.powersystempartners.com
www.reinhausen.com
www.areva-td.com
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Switchgear
Areva T&D*
CG (Pauwels)
S&C
Siemens*
www.areva-td.com
www.pauwels.com
www.sandc.com
www.siemens.co.uk
Cabling
Nexans
Prysmian
DRAKA
www.nexans.co.uk
www.prysmian.com
www.draka.com
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Control System
Bachmann*
DEIF
Vestas
KK - Electronic
GE
Enercon
Ingeteam
REpower
DeWind
Ecotecnia
Mitsubishi
Mita Teknik
www.bachmann.com
www.deif.com
www.vestas.com
www.kkelectronics.co.uk
www.ge.com
www.enercon-eng.com
www.ingeteam.eu/ingles/productos_servicios/energia/eolica.asp
www.repower.de
www.dewind.de
www.ecotecnia.com
www.mitsubishi.com
www.mita-teknik.com
Yaw System
ABB
Bosch Rexroth
Bonfiglioli
VEM
www.abb.co.uk
www.boschrexroth.com
www.bonfiglioliuk.co.uk
www.vem-group.com
Yaw Bearing
IMO
Liebherr
Rollix
Rothe Erde
www.imo.de
www.liebherr.com
www.rollix.com
www.rotheerde.com
Nacelle Auxiliary Systems
Brakes
Svendborg
Stromag
Siegerland
www.svendborg-brakes.com
www.stromag.com
www.sibre.de
Cooling
Hydac
Windsyn
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Anemometry
Climatronics
Gill Instruments
FT Technologies
NRG Systems
Vector Instruments
www.climatronics.com
www.gill.co.uk
www.fttech.co.uk
www.nrgsystems.com
www.windspeed.co.uk
Fire Protection
Danfoss
Firetrace
Minimax
www.danfoss-semco.com
www.firetrace.co.uk
www.minimax.de
UPS
AKI Power Systems
www.aki-usv.com
Internal Service Crane
Effer
Hiab
Liftra
Palfinger Marine
www.effer.it
www.hiab.co.uk
www.liftra.com
www.palfinger.com
Nacelle Cover
Bach Composites
Eikboom
www.bach-ci.dk
www.eikboomgmbh.de
Fasteners
August Friedberg
Cooper & Turner
Fuchs & Sanders
Gexpro Services
Wind-Fix
www.august-friedberg.com/unternehmen/unternehmen_e.asp
www.cooperandturner.co.uk
www.fuchs-sanders.de/fus/opencms/html/de/index.html
www.gexproservices.com/gexproservices/
www.multifixgroup.nl
Condition Monitoring Systems
WTG Manufacturers
Bruel & Kjaer Vibro
www.bkvibro.com
Gram & Juhl
www.gramjuhl.dk
SKF
www.skf.com
SecondWind
www.secondwind.com
Rotor
Blades
Siemens
Vestas
LM Glasfiber*
Tecsis
GE
Enercon
Euros
Polymarin
Mitsubishi
Suzlon
Umoe Group
Garrad Hassan & Partners Ltd
www.energy.siemens.com
www.vestas.com
www.lmglasfiber.com
www.tecsis.com
www.ge.com
www.enercon.de
www.euros.de
www.polymarin.com
www.mitsubishi.com
www.suzlon.com
www.umoe-blades.com
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SGL Rotec
SINOI Ltd
Zhongfu Lianzhong
Huiteng
www.sglrotec.de
www.sinoi.de
www.lzfrp.com
www.htblade.com
Hub Casting
Felguera Melt
Fonderia Vigevanese
Metso
Meuselwitz
Rolls Royce
Siempelkamp
Vestas
Rolls Royce Foundry
Eisengiesserei Torgelow
Siempelkamp Giesserei
Gusstec
Wilhelm Guss-Engineering
& Projektmanagement
Heavycast Karistad
www.w-g-p.de
www.heavycast.se
Blade Bearings
IMO
Liebherr
Rollix
Rothe Erde
SKF
Roballo
www.imo.de
www.liebherr.com
www.rollix.com
www.rotheerde.com
www.skf.com
www.roballo.co.uk
Pitch Systems
Hydraulic
AVN Hydraulic
Bosch Rexroth
Fritz Schur
Moog
Parker
Electric
Moog
SSB
Spinner
Bach Composites
Eikboom
www.durofelguera.com
www.vigevanese.it
www.metso.com
www.meuselwitz-guss.deindex.php?id=365&L=1
www.rolls-royce.com
www.siempelkamp.comindex.php
www.vestas.com
See above
www.eisengiesserei-torgelow.de
www.siempelkamp.de/Giesserei.716.0.html
www.gusstec.de
www.avn.dk
www.boschrexroth.com
www.fst.dk
www.moog.com
www.parker.com
www.moog.com
www.ssb.eu
www.bach-ci.dk
www.eikboomgmbh.de
Rotor Auxiliary Systems
Automatic Lubrication Systems
Lincoln
www.lincolnindustrial.com
SKF
www.skf.com
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Blade Load Sensing
Insensys
www.insensys.com
Tower
Ambau*
BiFab
Bladt
SIAG
Vestas
Skycon Towers*
Gamesa
Suzlon
Mitsubishi
DMI
Valmont
Hendricks Industries
DS SM
Win & P
www.ambau-gmbh.com
www.bifab.co.uk
www.bladt.dk
www.siag.de
www.vestas.com
www.wtowers.com
www.gamesacorp.com
www.suzlon.com
www.mitsubishi.com
www.dmimfg.com
www.valmont.com
www.hendricks-industries.com
www.ds-sm.dk
www.winnp.co.kr
Steel Suppliers
Corus
Dilinger Hutte*
Ilsenburger
Rukki
Salzgitter
Thyssen
Hempel
www.corusgroup.comen
www.dillinger.de/dh/index.shtml.en
www.ilsenburger-grobblech.de
www.ruukki.com
www.salzgitter-ag.de/en/
www.tkmna.thyssenkrupp.com/tkmna/index.htm
www.hempel-metals.com
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APPENDIX 5
PROVEN FOUNDATION CONCEPTS
Monopiles
The monopile has the benefit of simplicity of fabrication and ease of installation. In addition, the
monopile structure, partly due to its simplicity, offers potentially good fatigue resistance against
the very high fatigue loads transferred from the wind turbine.
A monopile foundation consists of a single, cylindrical, steel pile, which is embedded into the sea
bed. The depth of pile penetration into the sea bed and the pile diameter / wall thickness are
determined principally by the maximum water depth, sea bed conditions and the loading
characteristics of the wind turbine.
Figure A6 below shows a typical monopile foundation design.
Transition piece
Pile
D
Figure A6: Example of a typical monopile foundation design
Typically, the turbine tower is mounted onto the foundation via a transition piece which itself is
fixed on to the pile using a specialized grouted joint. The purpose of the grouted joint is to take-up
any misalignment tolerances that inevitably occur during installation of the monopile. While
grouting has proved to be reliable and risk-free during installation, recent experience has
highlighted the start of grout failure under high stresses imposed by the turbine. New design
standards are being drafted to prevent this issue in future.
The level of the top of the transition piece, or more specifically the level of the platform, is
determined by the necessity to maintain adequate clearance over the crests of waves during storm
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conditions. On exposed sites with high tidal ranges this can place the platform up to 20 m or more
above the water level shown on navigation charts.
Table A1 below provides indicative pile diameters for the anticipated turbine range of interest for
future north European offshore wind projects. These diameters are typical for a maximum design
water depth of up to 15 metres.
Turbine installed capacity
3-4 MW
Indicative pile diameter, D
4-5m
5-6 MW
5-6m
7-10 MW
6-8m
Table A1: Indicative pile diameters as a function of turbine capacity
A disadvantage of the monopile is its high flexibility in deep waters. This type of structure is well
suited for sites ranging in water depth from 0 to 25 metres. It is possible however, that future
developments in fabrication capabilities and size of installation equipment will mean that very
large diameter monopile structures can be fabricated and installed making the monopile structure
also the preferred solution for deeper water sites.
Advantages
Disadvantages
Minimal fabrication required.
Rapid to fabricate.
Proven and familiar concept.
Can accommodate seabed migration
Well suited for smaller turbines in all water
depths.
Deep water case for 5 MW turbine requires
very large diameters approaching practical
limits for monopiles.
Heavy.
Substantial scour protection often required.
Tower diameter variation required.
At limits of fabrication and handling,
particularly for deep water.
Opportunities
Risks
Feasibility and economics substantially
improved with alternative smaller turbines.
Adopt minimum target fatigue lives with a
maintenance strategy.
Structure weights for 3-4MW turbines can
be reduced with design to site specific data.
Natural frequencies and hence fatigue
sensitive to changes in conditions (scour,
soil etc.)
Pile driveability.
Reliant on high workmanship levels.
Table A2: Monopile: Summary of Advantages & Disadvantages
Gravity Base Structures
Unlike piled foundations, Gravity Base Structures (GBS) are designed with the objective of avoiding
tensile or uplift forces between the bottom of the support structure and the seabed. This is
achieved by providing sufficient weight in the foundation that the structure retains its stability in
all environmental conditions.
GBSs are constructed in fabrication yards and transported to site. Once in position on the seabed,
their weight is increased by filling the structure with pumped-in sand, concrete, rock or iron ore as
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required. Gravity structures are usually competitive when the environmental loads are relatively
modest or when additional ballast can be provided on site at a modest cost.
To date, GBSs have been implemented for offshore wind projects using cylindrical reinforced
concrete caissons which are mounted directly on to a prepared area of the seabed, as illustrated in
Figure A7 below.
Figure A7: Example of typical Gravity Base Structure designs
Again, the dimensions of gravity base foundations will scale mainly with turbine installed capacity,
the site wave climate and water depth. The indicative caisson diameter for the turbines with
installed capacities in the range 3 to 5 MW is 30 to 40m. This type of structure is suited for sites
ranging in water depth from 0 to 30 metres, although some designs are being considered for
deeper sites. To date these designs have been implemented for many of the offshore wind farms
in Baltic Sea, where water depths and metocean conditions are suitable.
A variation of the gravity based foundation is the gravity-piled foundation. This structure is
designed such that the variable loads are shared between gravity (i.e. weight of the foundation)
and a series of piles which act to further pin the foundation to the sea bed.
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Advantages
Disadvantages
Reduced fatigue sensitivity compared to
other concepts evaluated.
Can readily be internally J-tubed/cabled.
Minimal corrosion protection requirements.
Relatively straightforward fabrication.
No piling required.
Potentially very heavy and difficult
transport/lift/install.
Substantive scour protection can be
required.
Possible requirement to dredge/excavate.
Sloping seabed-levelling difficult.
Not suitable at locations where seabed
surface material is soft.
Slow to fabricate.
Suitable fabrication facilities within
economic transport range may be limited.
Some form of seabed preparation likely.
For deeper waters, requires specialized
operation.
Large storage space required for completed
structures.
Opportunities
Risks
Alternative installation methods such as
float-out, buoyant assisted lift or selfinstalling could be developed.
Can be optimized for installation
methodology. For example shape and
aspect ratio are easily altered.
Pre-stressing could reduce concrete
weights further (~10%)
Existing & future seabed stability.
Cyclic degradation of soil strength and
stiffness.
Dependence on strength and stiffness of
surface soils. Silts within buried channels or
banded silts likely to preclude use.
Raised seabed profile may affect wave and
current hydrodynamics.
Table A3: Gravity Base Structure: Summary of Advantages & Disadvantages
Space Frame Structures
For locations of greater water depth, Space Frame Structures are likely to be considered. Broadly
speaking, these concepts fall into two categories: (i) Multipods, including Tri-pods Figure A8; and
(ii) Jackets, Figure A9. These designs transmit forces to the foundations in the sea-bed via a multimember structure, with the aim of minimising the ratio of mass to stiffness. Typically, small
diameter piles are proposed for the method of fixing Space Frame Structures to the seabed,
although suction caissons have also been suggested.
Space Frame Structures – Tripods
Until recently, the most commonly proposed Space Frame Structure was the Tripod, with
applications at Alpha Ventus and Cote d’Albâtre (to be constructed), however Jackets have now
been used at Beatrice and Alpha Ventus, and are under construction for Ormonde, hence would
appear to be gaining acceptance as the preferred alternative in deep waters.
The Tripod is a standard three-legged structure made of cylindrical steel tubes. The central steel
shaft of the Tripod makes the transition to the turbine tower. The tripod can have either vertical or
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inclined pile sleeves. The base width and the pile penetration depth can be adjusted to suit the
actual environmental and ground conditions. The piles in this case would be relatively small, say 2
to 3 m in diameter.
As with monopile designs, the dimensions of multi-pod foundations will increase with turbine
installed capacity but will also be linked to the site wave climate and water depth. The pile
separation for the anticipated turbine range of interest for offshore wind projects which are
planned to come online in the next 5 years, assuming a tripod multi-pile arrangement, is
indicatively 20 to 40 m. This type of structure is well suited for sites ranging in water depth from 20
to 50 m.
An alternative design solution makes use of a tripod structure in conjunction with suction caisson
foundations in place of the piles. Although this concept is at a relatively early stage of
development for wind turbines, it may be considered for some offshore wind projects. The caisson
or bucket is installed by means of suction and will in the permanent case behave as a gravity
foundation, relying on the weight of the soil encompassed by the steel bucket with a skirt length of
approximately the same dimension as the width of the bucket. This solution may, however, be
regarded as relatively risky by offshore contractors and vulnerable to variability in ground
conditions.
Figure A8: Example of a typical Tripod design
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Advantages
Disadvantages
No scour protection required.
Can be (largely) internally J-tubed/cabled.
Can accommodate some seabed migration
with pile changes.
Relatively lightweight (see opportunities)
Impractical in shallow water.
Fatigue susceptible design.
Potential castings, forged tubulars and/or
ring stiffened joints.
Relative fabrication complexity.
Wide structures. Number that can be
transported per vessel limited.
Feasibility and economics rule out use with
alternative smaller turbines.
Slow to fabricate
Large area required for storage
Opportunities
Risks
Scope for weight reduction with fatigue
design using finite element methods.
Castings may be precluded using a finite
element analysis approach.
Other space frame concepts (variant) may
be economic subject to fatigue adequacy.
Adopt minimum target fatigue
lives/maintenance.
Pile driveability and potential need for
drilling.
Reliant on high workmanship levels.
In mid or shallow water depths braces
emerging through sea surface would
present hazard to vessels within the wind
farm.
Table A4: Tripod: Summary of Advantages & Disadvantages
Space Frame Structures – Jackets
Jackets, Figure A9, differ from tripod-type structures in that the design has:



A large plan area through the majority of the structure; the positioning of steel further from
the centre of axis results in significant material savings;
A more complex structure, hence greater welding and fabrication effort will be needed;
A more consistent cross-section for the tubular elements, with potential to avoid conical
elements.
The Beatrice offshore wind project in Scotland makes use of a Jacket substructure, similar to those
implemented in the offshore Oil & Gas sector. As with the Tripod design, the structure is "pinned"
to the seabed using piles. It is argued that the increased fabrication and assembly costs of such a
structure when compared to the Tripod are offset by a significantly lower mass for the same
stiffness characteristics.
From GLGH’s design work experience, GLGH believes that the jacket foundation is superior to the
tripod in terms of costs and hence is likely to prevail for deeper water sites. The steel savings
versus tripod type designs compensate for the additional fabrication costs due to the more
complex geometry. Marginally lower crane-vessel hire costs due to the lower lift weights are likely
to provide a further potential advantage. Note that there is a shortage of suitable installation
vessels for jackets, hence the use of over-specified and expensive floating cranes to date, such as
the Rambiz.
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Note that jacket designs can be implemented with either three or four legs.
Transition Piece
Legs
Node
Braces
Pile Sleeves
Piles
Figure A9: Example of a typical Jacket design with nomenclature
Advantages
Disadvantages
No scour protection required.
Can accommodate some seabed migration
with pile changes.
Lightweight.
Structural redundancy.
Impractical and not economically viable in
shallow water locations.
Fatigue susceptible design with thick walled
and/or cast sections potentially required.
Complex connection at transition to tower.
Relative fabrication complexity.
Larger number of joints required when
compared to a tripod/quadpod.
Opportunities
Risks
Other jacket based concepts (variant) may
be economic subject to fatigue adequacy.
i.e. 4 leg jacket.
Adopt minimum target fatigue
lives/maintenance.
Feasibility and economics improved with
alternative smaller turbines.
Pile driveability and potential drilling
required.
Reliant on high workmanship levels.
Lightweight sections susceptible to impact.
Table A5: Jacket: Summary of Advantages & Disadvantages
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APPENDIX 6
DEMONSTRATED FOUNDATION CONCEPTS – FIXED
Tri-piles
In this design, three foundation piles are connected via a transition piece to the turbine tower with
the transition piece being located above the water level. BARD has patented a specific version of
this concept which consists of a transition piece with three pins that slot in to the three preinstalled piles. A design objective was to balance the weight of these four components to ease the
challenges of handling and installation. It is understood that this design is relatively heavy and that
the transition piece will be challenging to fabricate due to the complex load paths and heavy
welding required, hence the tripile concept is likely to be more expensive than alternatives. Note
that the first offshore wind turbine to be constructed, a 220kW Windworld unit at Nogersund in
Sweden in 1990, was constructed on a tripile type design.
Figure A10: Generic Tri-pile Foundation Design
Battered Pile
This foundation design solution comprises a reinforced concrete pile cap sitting on battered
(inclined) driven steel piles.
The loads from the turbine tower are transferred through the pile cap to the piles. The pile cap
resists mostly bending moments and shear forces, whilst the piles resist mostly axial forces, though
the latter are also subject to some bending moments. This foundation design would generally be
used in shallow sheltered waters hence the wave loading on the structure accounts for a very small
proportion of the total loading; in this respect the foundation is essentially an onshore foundation,
the main difference being the foundation is to be constructed from an offshore perspective rather
than for land use.
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The pile cap is reinforced concrete and is mainly governed by the extreme loads or ULS (Ultimate
Limit State). An area often of concern relates to the transfer of forces from the bottom of the tower
into the pile cap. The transfer of forces can be achieved by the use of either an embedded tower
section or holding down bolts. Substantial amounts of vertical reinforcement will be required
around the embedded tower section or holding down bolts.
Work
platform
Boat
landing
Pile cap
Pile
Figure A11: Example of a typical Battered Pile design
Suction Bucket
The suction bucket foundation, Figure A12, has been utilised for a number of demonstrations,
specifically:



Frederikshavn, Denmark; wind turbine
Horns Rev II met mast
An unsuccessful attempt to install a near shore Enercon demonstration turbine at Hooksiel,
North Germany.
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Source: DONG presentation at Hamburg Offshore Wind 2009
Figure A12: Suction Bucket
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APPENDIX 7
DEMONSTRATED FOUNDATION CONCEPTS – FLOATING
Spar
Examining the spar in greater detail, Figure A13 shows the key characteristics and components.
Heels over when
turbine is operating
Narrower section at
water-plane (reduces
wave loads and
improves motion
behaviour generally)
Three lines: lower cost but may
lose position, if one breaks;
buoy is inherently stable
(i.e. When without moorings)
Ballast at base of spar
provides stability;
If this is a fluid, stability
can be adjusted
Slack mooring
Choice of anchors
(depends on ground)
Flexible export cable
Figure A13: Spar Buoy - Summary of the Technical Details
In summary, the principal challenges in delivering a successful spar buoy concept are anticipated
to be:



controlling the size of the spar buoy structure,
strengthening the wind turbine tower to cope with the bending moment induced by the
heel, as well as the motion,
mounting of the wind turbine on to spar; in the deep waters of the Norwegian fjords, this has
been done in the vertical, but most locations will not allow this; in such cases horizontal towout and upending will be necessary; this is the conventional approach in the offshore
engineering industry but could induce high loads on the turbine.
On the positive side, the spar concept can be compared with the monopile, in terms of structural
design (i.e. a simple steel tube) and loosely with dimension, Figure A14, the spar and tower clearly
being larger compared with monopiles designed for shallow waters.
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Figure A14: Monopile (left) compared to a Spar Buoy
Examining current activity of spar-class floating offshore wind technology, the two leading
concepts are both being driven in Norway, no doubt due to the very deep waters that surround the
coasts there:


SWAY [56] is investigating supplying electricity from floating wind turbines to offshore oil
and gas platforms in order to help meet the imposed CO2 emissions limits. The concept
consists of a deep spar tethered to the seabed either via a single tensioned line or via direct
fixing to the seabed with a universal joint [57];
Most significantly, Statoil recently installed the first full scale grid-connected prototype off
Karmøy island on the south-west coast [58]. A 2.3MW Siemens turbine has been used, a wellestablished commercial turbine model, of which over two hundred units have been installed
offshore on fixed foundations. The spar was fabricated at Technip’s yard in Finland, from a
steel tubular supplied by SIF. Examining the dimensions of the spar, it appears that it may
have been design for a larger turbine unit, i.e. over-designed, which is highly commendable
for a world first prototype and should improve the probability of a successful two-year trial
period. This HyWind concept [59] has a number of interesting aspects but is fundamentally
based on proven concepts and technology and hence has good prospects of success in the
medium term if target costs can be achieved.
Historical ballast-stabilised concepts include the first floating wind energy concept of all, proposed
by Heronemus in the early 1970s [60] [61], a finned-spar concept developed in Japan [62] / [63] and
the GLGH-Technomare FLOAT concept [64].
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APPENDIX 8
POTENTIAL NEW FOUNDATION CONCEPTS, FIXED AND FLOATING
Novel GBS Technologies
Züblin have proposed a GBS derivative consisting of a concrete X or Y lying on the seabed,
supported on pads at the ends of the arms, Figure A15. The Arcona-Becken met mast was installed
on this foundation type however it has not been utilised for offshore wind turbines to date.
Recently Wetfeet announced a collaboration with Züblin to use this foundation type for the
GlobalTech 1 offshore wind farm, however further details regarding progress to developing the
offshore fabrication facilities are awaited.
Source: Züblin
Figure A15: Züblin GBS
Concrete Drilled Pile
Ballast Nedam, a Dutch offshore contractor with plenty of offshore wind farm experience, has
proposed a drilled concrete monopile, Figure A16 and Figure A17. This would be installed with
Ballast Nedam’s bespoke vessel Svanen (“Swan”), Figure A17. Conversely, there are only a limited
number of vessels that could install Concrete Drilled Piles in a cost effective manner, indeed the
Svanen possibly being the only such vessel.
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V
VI
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VII
Source: Ballast Nedam, European Offshore Wind Conference Stockholm 2009
Figure A16: Concrete Drilled Monopile
Source: Ballast Nedam, European Offshore Wind Conference Stockholm 2009
Figure A17: Installing Concrete Drilled Monopile – Svanen (vessel) and detail of Drilling Plant
Concrete Transition Pieces
Siemens presented the results of a study at a recent Offshore Wind Conference (Stockholm 2009)
which concluded that the Concrete Transition Piece was the most attractive foundation type. The
principal driver is that it removes the need to design the foundation to achieve natural frequencies
since the transition piece is now rigid. Effectively the natural frequency will be driven by the tower,
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and to a smaller extent by the monopile section within the water and within the upper section of
the ground.
However the transition piece is likely to be heavy and an effective manner of fabrication, transport
and installation needs to be developed. This concept would need to resolve the same challenge as
GBS structures of developing solutions that contractors are happy to deliver.
Figure A18: Concrete Transition Piece
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TLP (Tensioned Leg Platform)
Turning to the TLP concept and examining this in greater detail, Figure A19 shows the key
characteristics and components.
Turbine always
vertical
Legs provide stability during
tow-out;
once legs submerged, vessel
has no stability;
various possible solutions
including buoyancy sacks
and collars (shown)
Small structure – hence
long term prospects for
costs appear good
Tensioned mooring limits
vertical movement
If one mooring line (group)
fails, structure will flip over
(i.e. total loss)
Flexible export cable
Choice of anchors
(depends on ground)
Figure A19: TLP - Summary of the Technical Details
The challenges in developing a successful design are significant, in particular:


installing the structure safely, reliably and cost-effectively; the principal focus will be on

maintaining stability throughout the process, including during tow-out,
preparation work and while the cable is being tensioned and the structure is
being submerged,

developing a low-cost tensioned-mooring system; to date applications have
been for large high-performance systems;
developing anchoring for ground conditions at the site; numerous technical solutions have
been proposed including

gravity anchors (a large concrete block),

piled anchors

and suction anchors,
However none are particularly easy to design or cheap to handle and involve a degree of technical
innovation and hence risk; in contrast, conventional drag anchors are a candidate for spar and
jacket-class structures, depending on the seabed conditions.
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Examining current activity of tensioned-moored floating offshore wind technology,


In Germany, the engineering consultancy Arcadis has developed a floating concept suitable
for the relatively shallow waters, such as those in the Baltic Sea. It may be that the
motivation for a floating support structure was the soft seabed conditions found in many
locations in that sea [65]. The patent and the limited publicity indicate that a taut or
tensioned design with a steel main structure and concrete gravity anchoring is being
considered [66].
BlueH [67], a multi-national group of companies based in the Netherlands, have developed a
TLP concept consisting of a larger structure with multiple surface-piercing members, with
the potential advantage of improved stability, including in damaged conditions, but at the
detriment of greater structural size and cost. An off grid prototype with an inactive turbine
for visualisation purposes was installed 21km off Brindisi, Italy in 100m waters during 2007/8.
BlueH have been successful in obtaining research funding in Italy [68], the United Kingdom
[69]/[70] as well as France [71] and apparently obtaining planning consent in Italy [72], with a
further application under consideration in the USA [73] and Belgium [74].
Historically proposed concepts include: Eolomar toroidal shaped floater [75], Sure / Ocean Energy
and Resource’s tensioned quadruple-floater with a telescopic tower [76], a French TLP tested in
Marseille wave tanks [77] and a TLP concept under development by MIT and NREL [78] / [79].
Floating Jacket
Turning to the floating jacket concept and examining this in greater detail, Figure A20 shows the
key characteristics and components of a four column floater.
Heels over when
operating
Vessel is
stable without
mooring lines
Wave loads will be relatively
high due to large structure
at the water surface
Catenary
mooring
lines
Choice of anchors,
including drag anchors
(depends on ground)
Heave
suppression
discs to reduce
vertical motion
Figure A20: Floating Jacket - Summary of the Technical Details
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The challenges in developing a successful design are significant, in particular:


Minimising wave loads and consequential

motion response

and structural loads of the floater
design of catenary moorings suitable for shallow waters
Like the spar, this concept can be assembled from proven subsystems however the initial size and
hence cost of the concept can appear prohibitive. A successful implementation of floating jacket
will require optimisation of the complete system, for example in terms of the number of columns
(three appears to have the edge), minimising wave induced motion (through heave plates and
semi-taut moorings) as well as other more original solutions proposed by the candidates
summarised below.
Examining current activity of hydrostatically-stabilised floating offshore wind technology, projects
of note include:



Winflo [80] [81], a catenary moored floating jacket under development by a French
consortium led by Nass & Wind (wind farm developer), Saipem (offshore engineering
contractor and operator) and DCNS (shipyard).
WindFloat, a three-column concept conceived by Marine Innovation & Technology and now
owned by Principle Power [82], with a novel aspect of pumping water between the columns
to ensure the turbine remains vertical irrespective of wind direction and strength. This will
allow a smaller floater to meet the wind turbine’s operating envelope. Demonstration units
are planned for Portugal [83] or North West USA [84]
WindSea [85], a Norwegian multiple turbine concept under development by Statkraft, NLI
and FORCE. It is also based on a tri-floater design, but with a turbine on each column
inclined outwards and the third turbine in a downwind position.
Historical concepts include the original Dutch Tri-floater Drijfwind [86], the MUFOW multiple
turbine concept [87] / [88] and the Lagerwey / Herema multi-turbines including twin rows [89] /
[90].
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ANNEXES
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ANNEX A – INTERNATIONAL OFFSHORE WIND REGULATORY FRAMEWORKS
A1
Denmark
Financial support mechanisms
Following the February 2008 Energy Policy Agreement between the Government and the
opposition parties (except the Danish Red-Green Alliance), it was decided that the next offshore
wind development would consist of a single 400MW project, to be commissioned by 2012. In a
change to procedure, the Danish Energy Authority (DEA) requested the grid operator Energinet to
carry out site investigations and EIA for the site. Taking into account Energinet’s preferences, the
site was designated as Anholt, in Kattegat. This change in procedure, compared to previous
projects, was designed to remove some of the uncertainty before the tender for the project, in
order to encourage a lower price for the project in the tender to follow.
This policy evidently had limited success, as DONG was the only bidder for the concession; other
developers cited difficult conditions, more attractive UK and German projects, and hefty fines for
missing deadlines as reasons for avoiding the Danish development. The final go-ahead was given
to DONG Energy in June 2010; the accepted price was DKK 1.051/kWh (€0.14/kWh) for the first
20 TWh of production (corresponding to approximately half the lifetime of the wind farm).
Nevertheless all future planned projects are expected to be subject to a tender even if not with
prior project preparation by Energinet. The number of full load hours and the price for these are
subject to competitive tendering for each offshore wind farm.
Grid connection and development
The financing of the grid connection for offshore wind farms depends on the route taken to
licensing: through the tendering process or through the “open door” policy (see below). In the first
case, the connection will be financed by the grid operator, including the establishment of a step-up
transformer. If the “open door” route has been taken, however, responsibility falls to the developer
to provide the connection to the nearest defined shore connection point, along with the required
step-up transformers. Costs of any necessary grid reinforcement may also be expected to be borne
by the developer, in this case.
The three private offshore wind farms established in Denmark to date (Samsø 23 MW; Rønland
17 MW and Middelgrunden 40 MW) have followed the second procedure, and no special problems
have been noted. These projects are, however, all within about 3 km of the coast, and it can be
assumed that grid connection costs were not prohibitively expensive.
The significant expenses associated with grid reinforcement could make it prohibitive to start a
large project, independent of tender announcements from the Danish Energy Authority.
Therefore, further independent development of non-sanctioned future sites is considered to be
unlikely.
Power off-take in Denmark is largely handled via the Danish Energy Authority, as part of the
incentive scheme. In some cases, the owner may choose to sell the electrical power to utilities or
other power suppliers through a Power Purchase Agreement (PPA).
The system operator has established rules where it can demand the wind power plant to be
switched on and off in a smooth and timely manner, meaning that the wind turbine must have
such capabilities. The grid operator can also demand a lower production than the wind farm is able
to yield, for a short period, if the security of the grid is in danger - as regulated by law.
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Planning and licensing
The conditions for offshore wind farms are outlined in the Danish Electricity Supply Act 2008. All
permissions are granted by the Danish Energy Authority, which is the body responsible for
licensing use of the seas around Denmark. The Danish consenting process for offshore wind can, in
this sense, be considered as a one-stop-shop approach.
There are three steps to the issuance of offshore wind farm consent from the DEA:
1
2
3
Licence to conduct preliminary studies, including environmental and technical.
Licence to establish the offshore wind farm, on certain specified conditions, is granted after
application delivering the preliminary investigation reports.
Permission for energy production must be obtained before commissioning of the farm,
typically for 25 years. The application must be followed by a documentary report
demonstrating that the conditions given have been followed. When a project is larger than
25 MW, the operator needs concession for production of electricity.
There are two application routes for a license:
1.
2.
Following the Danish Government’s action plan for offshore wind development, the Danish
Energy Authority will invite bids to tender for pre-specified sites.
The “open door principle”: independent applications can be made at any time, for any site.
The DEA will then assess the site, and if the conclusions are positive, an invitation for
Expression of Interest will be announced. Successful registrants will then be invited to
tender for the site. This helps ensure competition outside of the Government’s action plan.
The main differences between the two procedures are that the cable connection to shore from the
wind farm in situation 2) has to be carried by the operator, and that the revenue is based on the
onshore rules. In situation 1), the grid operator will cover the cost to the defined farm grid
connection point, and the revenue is subject to negotiation (tender). Projects following the “open
door principle” must furthermore offer 20% ownership to the local population, in accordance with
the rules for onshore wind.
Both methods have been utilised by developers in Denmark. Experience has shown the most
important factor to be the requirements regarding the financial strength of the applicant, to cover
risks during construction and 25 years of operation.
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A2
March 2011
Germany
Financial support mechanisms
To facilitate the deployment of renewable electricity, Germany has one of the world’s most
successful financial support schemes for renewable energy, in terms of capacity installed. The
Renewable Energy Act (Erneuerbare Energien Gesetz, EEG) removes much of the power price risk
from offshore wind, with the provision of fixed tariffs for the sale of the generated power.
There is a clearly planned rating structure, outlining the level of support available to offshore wind
projects over the project lifetime, with adjustments made depending on the distance to shore.
Projects must lie a minimum of three nautical miles from the coast to apply.
The 2009 revision of the EEG (1 January) stipulates a starting tariff, payable for at least 12 years from
turbine commissioning, beyond which the tariff drops to the base level. This 12-year minimum
period is extended by half a month, for each nautical mile beyond the 12 nautical mile boundary,
and by 1.7 months, for each additional full metre in depths beyond 20 m, on a turbine-by-turbine
basis. The starting tariff is set at €c13/kWh, with an additional premium of €c2/kWh for turbines
commissioned before the end of 2015. From 2015, there will be a degression of 5%, per annum, on
the combined tariff and bonus. The basic rate is currently set at €c3.5/kWh. The tariff structure is
summarised in Figure A2.1.
Source: GLGH
Figure A2.1: Overview of the Financial Support to Offshore Wind in Germany.
The EEG 2009 provides the option to step out of the EEG regime, with a month’s notice, and to sell
the electricity on the open market. Hence, once the starting tariff period comes to an end, most
project owners will probably opt to sell their energy on the open market, where it is very likely that
they will receive a higher income than the basic rate of €c3.5/kWh. However, it is possible to step
back into the EEG regime, on a month-by-month basis.
The most recent improvement in project economics has been the decision to socialise the offshore
grid costs by the Betreiber der Übertragungsnetze / Transmission System Operators (TSO), for
projects within the EEZ where construction commences before the end of 2015. This will have a
major impact on project finances, reducing the capital costs by around 30%, with the income
remaining the same. The decision appeared to trigger a number of sales of offshore wind projects,
which suggests that incentives may now be at a sufficient level for widespread offshore wind
development.
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Grid connection and development
There are no payments for system usage in Germany. Furthermore, the costs of the offshore and
onshore transmission cabling are borne by the utilities.
In general, the German grid already operates close to capacity in most parts of Northern Germany,
because (due to lack of large industries) the grid was traditionally weak in that region and that is
where most of the onshore wind turbines have been located. A program of transmission upgrades
is being undertaken, in particular to relieve bottlenecks to the load centres of Rhine/Ruhr,
Frankfurt, Stuttgart and Munich. The unprecedented capacity of the new offshore transmission
lines means that new solutions may be needed, with even novel technologies such as gas insulated
lines (GIL) being considered.
With the Infrastrukturplanungsbeschleunigungsgesetz, (InPBeschlG/IPlanG) Infrastructure Planning
Acceleration Law 2006 (in force since 17.12.2006), the German government defined that a grid
connection for offshore wind farms is obligatory. In order to provide more detail on the
requirements for receiving the grid connection, the Bundesnetzagentur (BNetzA, Federal Grid
Agency) issued a position paper called “Positionspapier zur Netzanbindungsverpflichtung” in
September 2009. The paper sets out the requirements and timelines a developer must adhere to,
in order to achieve a “free” grid connection. Although the legal status of the position paper is still
under discussion, and the details are susceptible to interpretation from both developers and TSOs,
the main elements are as follows.
The developer needs to fulfil four criteria, in order to receive the grid connection. The criteria are
set in order to ensure that the projects are developed far enough to justify investment in a grid
connection. The intention of the paper is also to ensure that wind farm developments receive
clustered grid connections, where possible. In summary, the four criteria are:
1. Consent: the developer must deliver a copy of the building consent;
2. Project Program: the developer must deliver a plausible project time schedule;
3. Site Investigation: the developer must deliver proof of having performed a full soil
investigation of the site, following the standard “Ground Investigation for Offshore Wind
Farms” issued by the Bundesamt für Seeschifffahrt und Hydrographie (BSH: Federal
Maritime and Hydrographic Agency); and
4. Supply Contracts & Financing: the developer must submit a contract for the supply of
turbines (or a binding Reservation Agreement), together with evidence demonstrating the
project has fulfilled one of the two following criteria:
a) Sufficient financing is in place to construct the wind turbines scheduled for construction
in the first year of the project; or
b) The Reservation Agreements (or full contracts) for the balance of plant (foundations,
cables and sub-station).
Planning and licensing
German offshore wind farms need a construction permit for the wind farm itself, as well as for the
transmission cable. Hence, a wind farm in the EEZ will require a wind farm and cable permit from
the federal authorities, as well as a cable permit from the regional authorities. The authority
responsible for the offshore wind farm permitting process depends on the location: within the
Territorial Sea (twelve nautical mile zone) it is the regional (Bundesländer) authorities, i.e.
Mecklenburg-Vorpommern, Schleswig-Holstein or Niedersachsen (Lower Saxony), whilst in the
EEZ, it is the federal authorities.
The federal permitting process is relatively clear today, and is led by the BSH, who also co-ordinate
cable permit applications within the Territorial Sea. The primary consent for a wind farm in the EEZ
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is the SeeAnlV (Marine Facilities Ordinance), which will also require that the facility complies with
the requirements of the SeeAufgG (Maritime Federal Responsibilities Act). The SeeAnlV allows
permission to be granted for construction and operation of commercial structures offshore. A
revision to the ordinance, Article 3a, covers the specification of regions as being suitable for
offshore wind farms; however, this does not remove the need for the developer to demonstrate
that the impacts are acceptable.
A3
Netherlands
Financial support mechanisms
Under the Stimulering Duurzame Energieproductie (SDE – Stimulation of Sustainable Energy
Production) scheme introduced in 2007, projects which have received consent participate in a
tender process for state subsidy. Each project bids a fixed tariff, with adjustment for increased
distance from shore, as per Table A3.1. Note that, since the majority of the SDE has already been
granted, subsidy now remains for only 100MW of project capacity. The project bidding the lowest
tariff will win the tender. Should the “last in” not accept the partial subsidy, it will be offered to the
next in line, and so on, until the full subsidy is issued. The subsidy will be available for fifteen years.
Distance
€ / kWh
Distance
€ / kWh
< 30 km
-
60 km << 65 km
0.00875
30 km << 35 km
0.00125
65 km << 70 km
0.01000
35 km << 40 km
0.00250
70 km << 75 km
0.01125
40 km << 45 km
0.00375
75 km << 80 km
0.01250
45 km << 50 km
0.00500
80 km << 85 km
0.01375
50 km << 55 km
0.00625
85 km <
0.01500
55 km << 60 km
0.00750
Table A3.1: Feed-in Tariff Bonus by Distance from Offshore Substation to Onshore
Connection Point
Previously, “lowest tariff” tenders have been criticised for resulting in the selection of uneconomic
projects, which do not subsequently get built. The Dutch system is seeking to avoid this, by
requiring bidders to post a bond of €20 million, which is surrendered if the project does not
proceed to construction in a timely fashion.
In addition to the SDE tender, it is understood that an `Innovation Grant’ will be available to
developers (in receipt of the SDE subsidy), where they utilise innovative turbine or foundation
technology.
Grid connection and development
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The Netherlands has a well-developed electricity grid, with respect to security of supply and crossborder interconnections. The system does include some ageing components, and there is a
distinct lack of space onshore for more high voltage lines and underground cables, which increases
the challenge of providing grid upgrades in the long term.
The Transmission System Operator is TenneT, which operates the 380 kV and 220 kV transmission
system. Regional operators then distribute power at 150 kV, and lower. With an offshore wind
target of 6 GW by 2020, and a total generating capacity of around 21 GW (mainly fossil fuelled
plant), the Netherlands will require good control of the grid and sound interconnections with the
rest of Europe. These include a new 700 MW link with Norway, NorNed, which became active in
May 2008, and the interconnector with the UK, BritNed, planned to complete construction in 2011.
Further, TenneT is currently developing a new link with Germany (2014), and two additional links
with Norway are being investigated.
A direct current power link with Denmark, named COBRA, with the specific remit of facilitating the
integration of renewable energy generation into both networks, is currently being developed by a
combination of Tennet and Danish Energinet; for this, both parties signed an agreement in April
2009 which forms the start of the Concept design phase. This link is planned to be operational in
2016/17. More information on these projects is provided on the TenneT website [1].
On 5 March 2008, the Dutch Minister of Economic Affairs undertook to investigate the provision of
offshore grid connection points to wind energy facilities by TenneT, under what has been referred
to as “the Samson motion”. Subsequent to the Samson motion, the Ministry of Economic Affairs
has undertaken a study of options for developing an offshore transmission grid for the connection
of wind farms, including examination of the technical, commercial and legal implications.
The study identifies a number of potential connection scenarios, based around four likely
connection points for the offshore grid: Eemshaven, Ijmuiden, the Maasvlakte and Borsele.
The Minister for Economic Affairs has subsequently clarified that wind farms competing for the
current round of SDE funding will not be offered the possibility of connecting to TenneT-provided
offshore grid assets. Due to the time required to establish the legal basis and plan the roll-out of
any such transmission network, this option will only be available to projects developed
subsequently.
Planning and licensing
The key applicable law, under which Dutch offshore wind energy projects are consented, is the
Water Management Act (Wet Beheer Rijkswaterstaatswerken - WBR); this law is applicable to the
whole Dutch Exclusive Economic Zone (NEEZ), but not freshwater areas.
The National Water Department for the North Sea (Dienst Noordzee van Rijkswaterstaat - DNR), part
of the Ministry of Transport, Public Works and Water Management (Ministerie van Verkeer en
Waterstaat - MVW), is the body responsible for the permitting of activities within the NEEZ.
The Ministry of Housing, Spatial Planning and the Environment (Ministerie van Volkshuisvesting,
Ruimtelijke Ordening en Milieubeheer - VROM) [2] is responsible for spatial planning in the
Netherlands, including the NEEZ. The Ministry ‘promotes a strong role for municipalities’, implying
that it will involve local authorities in some planning decisions - notably those relating to onshore
connection works.
Through the WBR, offshore wind energy has to take into account the environment and ecosystem
of the North Sea, as well as considering other users of the sea (e.g. military areas, shipping routes,
disposal sites, search areas, coarse sand resources and cable routes etc.). The law, in principle,
opens up the entire NEEZ to the permitting of wind farms; however, this has been limited by the
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draft National Water Plan (NWP) which was published in December 2008, identified areas suitable
for development and targeted 450 MW of additional offshore wind energy capacity in the current
parliamentary period. The WBR now guides the central government (specifically MVW) in spatial
planning in the NEEZ. Under the WBR process, an Environmental Impact Assessment (EIA) must be
submitted, together with the request for consent. The procedure starts when the applicant
submits a startnotitie for the EIA to the DNR.
If successful, the process ends with the Ministry of Transport, Public Works and Water Management
awarding exclusivity and a Public Works Act (PWA) permit. More information is available in Dutch
at the noordzeeloket website [3].
Seabed concessions are awarded on an exclusive basis, and consents are awarded through the
same broad process outlined above. In this sense, only a single process need be followed to gain
all necessary permits to construct, commission and sell power from a wind farm.
It has been recognised in the Netherlands that a number of other detailed permits will have to be
issued, e.g. for landing ships during installation and maintenance, cabling through the dunes,
working conditions, etc., and, as far as possible, a ‘one desk’ policy has been developed, to
streamline the process.
A4
United Kingdom
Financial support mechanisms
The Renewables Obligation (RO) was implemented in England, Wales and Scotland in 2002, and
Northern Ireland in 2005, as the primary mechanism for achieving the UK Government target of
10% of electricity from renewable sources by 2011, and 15% of all energy supply from renewable
sources by 2020. The RO places an obligation on electricity retailers to source an increasing
proportion of electricity from eligible renewable energy sources. Retailers must prove compliance
through the surrender of Renewable Obligation Certificates (ROCs). These are issued to generators
according to their power production, and are then saleable on the open market.
As an alternative to buying ROCs, electricity suppliers may opt to pay the “buy-out” price, which is
the price charged per megawatt-hour, where the supplier fails to surrender sufficient ROCs to cover
its RO. Where a supplier opts to pay the buy-out price, the payment feeds into the “buy-out fund”,
which is redistributed (or “recycled”), on a pro-rata basis, to parties who surrendered ROCs within
the given compliance period. The buy-out price is linked to the Retail Price Index (a national
measure of inflation) and is revised annually.
The price of a ROC is the driving force behind the market for renewable energy generation in the
UK. Factors determining the price of a ROC are the RO level, buy-out price and the so-called
“recycle benefit”, as well as the scale of renewable generation deployment in any given year. The
more suppliers pay the buy-out, and the less the obligation is met through bona fide renewable
energy generation, the more valuable a single ROC becomes.
As well as the annual recycling of the buy-out fund, quarterly auctions of ROCs are held by the NonFossil Purchasing Agency, offering the opportunity for electricity suppliers to buy ROCs, rather than
opting for the buy-out route. Figure A4.2 shows the average price achieved at the 26 ROC auctions
held to date, alongside the average value of a ROC to suppliers, and the percentage compliance to
the RO, both respective to the appropriate compliance period. It can be seen that the level of RO
compliance has been within the range of 55-75%, and the market price of ROCs has remained
relatively stable.
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80.00%
£60.00
76.0%
£50.00
70.00%
£40.00
68.9%
67.6%
65.4%
65.00%
64.4%
60.00%
£30.00
ROC Value/Price
Percentage Compliance
75.00%
£20.00
58.9%
55.8%
55.00%
50.00%
Jul-02
Jul-03
Jul-04
Percentage Compliance
£10.00
Jul-05
Jul-06
Jul-07
Average ROC Price at Auction
Jul-08
Jul-09
£0.00
Jul-10
Average ROC Value
Figure A4.2: Historical ROC Values and Compliance Levels
Since its inception in 2002, the RO system has been under almost continual review, with regular
consultations taking place between government and industry. In April 2009, the latest Renewables
Obligation Order was published, outlining the methodology of implementation of the RO, and the
level of support available for various technologies. In order to help reassure investors, and permit
long-term planning, the life of the RO system has been extended to 2037, while support for any
individual project will last for 20 years.
Previously, suppliers were obliged to source a certain percentage of their electricity from
renewable sources; now the requirement is to surrender a specified number of ROCs. This allows
for the introduction of “banding”: certain renewable technologies will receive more or less than 1
ROC / MWh, making that technology more or less valuable, and stimulating market growth in more
expensive technologies, such as tidal and solar generation. At present, offshore wind is banded as
receiving 1.5 ROCs / MWh. A special bonus rate of 2 ROCs has been applied to offshore wind
projects gaining accreditation under the scheme before March 2014.
Calculation of the obligation level (the number of ROCs that will be demanded over the obligation
period) will depend on forecast levels of electricity supply and renewable generation. In the first
instance, the total projected electricity production for the period is multiplied by a factor to give
the RO in that period. This factor, revised annually, is currently 0.097 ROCs / MWh, and will rise to
0.154 in April 2015. As renewable generation deployment increases beyond this factor, the RO is
calculated as 108% of the total number of ROCs expected to be issued to generators within
compliance period. This “headroom” means that demand for ROCs will always outstrip supply,
helping to keep the value of ROCs from crashing, should renewable generation deployment be
higher than anticipated. The amount of headroom is expected to be reviewed on a regular basis.
Advantages of the 2009 Renewables Obligation Order include stimulus for technologies such as
offshore wind, wave and tidal, which at present have a higher cost of energy than other established
technologies, such as onshore wind and landfill or sewage gas generation. The banding system
will encourage the market to develop these more costly technologies, rather than relying on “easy
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ROCs” from established technologies which may have less potential for future development. This
move has been of concern to onshore wind developers, who fear a crash in the market value of
ROCs; however, the “headroom” clause has (in part) been designed to alleviate such concerns.
The Government will review the ROC bandings at four-yearly intervals, beginning in October 2010,
and will reserve the right to review at any time. This means that developers will not necessarily
receive the level of ROC support promised at the outset of project development, although once a
project is in operation the concept of “grandfathering” should mean a consistent level of support is
provided. Additionally, ongoing lobbying will be required from each sector to fight for its
continued level of ROC support, taking up further resources.
Grid connection and development
In the UK, the basic process for obtaining a grid connection is to submit an application to the
relevant network operator - this may be the local Distribution Network Operator (DNO), for
relatively low voltage connections, or the National Grid, for direct connection to the transmission
system. Following submission of this application, an agreement offer is developed on the basis of
the required capacity, the nature of the generating plant, and status (current and planned future)
of grid infrastructure in the region. The network operator is obliged to issue the offer to the
applicant within a statutory three-month period. If there is a dispute in relation to the offer, which
cannot be settled between the two parties, the case is referred to the regulatory body, Ofgem, for
determination.
Obtaining a viable grid connection for offshore wind projects in the UK has been a major source of
difficulty, and has presented a significant barrier to the acceleration of the offshore wind sector. In
this context, it is important to recognise that, in contrast to Denmark and Germany, the UK does
not grant priority access to the grid to renewable energy generation facilities.
In addition, developers in the UK are required to pay the network operator an upfront security
bond (known as final sums liability), in order for any upgrade works to commence. This is because
the network operator can only recover the cost of extending the transmission system through Use
of System charges, once the project is operating, and therefore requires protection against the
project not proceeding after significant sums have been expended. An alternative method that
requires payments generally in line with expenditure on the transmission work is also available.
The problem is that the long lead time associated with such work has forced developers to attempt
to secure a grid connection at a relatively early stage in the development process and, in many
cases, prior to the award of planning consents. Such securities, which have escalated massively due
to the volume of applications from offshore wind projects, are therefore at risk if a project is
rejected during the consenting process, or for some technical / economic reason. The reluctance of
developers to take on such a risk has led to dispute over several offers.
The UK Office of the Gas and Electricity Markets (Ofgem) is currently implementing a new system to
“unbundle” offshore transmission assets from generation assets, in line with the European Union
energy policy. The regime for Offshore Transmission Owners, or “OFTOs”, will relate to assets of
132kV, or greater, relevant for almost all large offshore wind farms.
Currently, the tender process for the first, “transitional”, phase of the regime is under way. This
involves OFTOs bidding to purchase transmission assets from developers, who have already either
partly or completely built them, for the financing and maintaining these assets over twenty years.
The OFTOs bid a future revenue stream, required to take ownership of the assets from the
generator at a fixed price, or “Regulated Asset Value” (RAV) to be determined by Ofgem. Decisions
on successful bidders were recently published.
The second, “enduring”, phase of the OFTO regime, which will apply to all Round Three projects,
will see potential OFTOs bid to design, build and operate offshore transmission assets for a
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regulated revenue stream, based on “use of system” charges to be paid by operators of offshore
generation assets. This process is still in a state of flux, with the new Government having agreed to
allow a new option where the offshore generator will supply the transmission connection. The
details of this are still under discussion.
This new regulatory regime is likely to have a significant impact on the feasibility of offshore
renewable generation. It will essentially allow developers to convert the high capital costs of
offshore electrical assets into an operational cost. Furthermore, being a price-controlled asset, the
net present value of those operating costs would be significantly lower than if financed by the
project. As a downside, however, the process brings uncertainty regarding technical specifications
and the programme, and perhaps undue capital expenditure. The OFTO process, and its
implications for the broader question of grid access for Round Three projects, is one of the primary
sources of uncertainty for developers of Round Three projects, and is currently causing some
ructions in the industry.
Planning and licensing
The seabed within UK Territorial Waters, as well as rights to exploit resources throughout the UK
Exclusive Economic Zone (EEZ), is controlled by the Crown Estate (CE). CE is essentially a
landowner, and an independent department within the UK Treasury, whose primary objective is to
enhance its asset portfolio and to generate revenue for the UK Treasury. In conjunction with the
Department for Trade and Industry (DTI), the Crown Estate has played a central role in the creation
of a viable regulatory framework for offshore wind in the UK. This has principally been conducted
in the form of three “rounds” of site leasing for offshore wind projects. Information on UK rounds
and projects can be found on the CE website [4].
For Round Two, the Crown Estate charged successful applicants a one-off option fee, which varies
according to the spatial area of the seabed for each site. This varied from £25,000, for a small
extension, to £0.5M, for a project within an area of between 150 and 250 km2. Once operational,
Round Two projects are subject to rental payments for their lease at a rate of £0.88 / MWh (indexed
to inflation), which is likely to constitute approximately 1% of gross revenues from power sales,
plus incentives.
Round Three site awards were announced early in 2010. Details of Round Three leasing
agreements have not yet been publicised; hence, it is not possible to determine the leasing costs
attributable to developers at this stage, although CE’s co-development approach (see below) is
likely to mean that leasing costs will be higher than for previous rounds. It is also not known what
the duration of the site leases will be, at this stage, although since CE announced an offer of 50year leases to Round One and Two projects, it could be expected that Round Three leases will be
comparable.
CE has stipulated that it will engage only one Partner Company for each of the nine identified
development zones. Unlike previous rounds, CE is intending to take a much more active role in
Round Three. A significant investment has been made in early identification and extensive
investigation of suitable development zones, and the adoption of a “co-development” approach
will see CE working side-by-side with project developers to achieve the planning consents
necessary to move Round Three projects forward; CE has indicated that they will be willing to fund
up to 50% of pre-consent development costs. Once these consents have been granted, it is
understood that the involvement of the Crown Estate will end, leaving the zone developer to
manage construction and operational activities.
Achieving planning permission for offshore wind farms in the UK, despite having reasonably high
success rates and short evaluation periods, has until recently required developers to obtain
multiple permits and licences.
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The Planning Act 2008 has sought to streamline this process, by establishing the Infrastructure
Planning Commission (IPC), which is responsible for the issuance of a single consent for Nationally
Significant Projects in England and Wales. In the case of offshore wind farms, this has been defined
as any project of a size greater than 100 MW. In Scotland and Northern Ireland, these
responsibilities rest with the appropriate ministers.
The change of government in April 2010 to a Conservative-Liberal coalition has resulted in a
change to the structure of the IPC, as it has now been absorbed into the “Major Infrastructure Unit”.
The new department is still planned to centralise planning for nationally significant projects.
Due to the uncertainty around the new coalition government’s planning infrastructure shake-up,
the form of the planning permission process that will confront Round Three projects is not
presently known. Assuming that it is no more onerous than that which currently exists, however, it
should not be prohibitive to offshore wind development.
A5
Offshore wind regulation best practice conclusions
On the basis of review work on the four countries of interest, this study presents some generic
findings which constitute best practise for offshore wind project regulation, as relevant to the case
of Ireland.
Strong Political Will
While effective industrial coordination and lobbying can play an important role on specific
regulatory issues, in the absence of genuine political ambition to deploy renewable energy and
specifically offshore wind, little progress can be made.
Political and Regulatory Stability
Repeated reform of regulations has hindered development. This can be avoided if regulations are
well drafted in the first instance. New markets for offshore wind should draw heavily on experience
in other countries. A stable regulatory regime engenders higher investor confidence.
Effective Industry Coordination
The development of strong, united and influential industry associations provides the coordination
necessary to have a significant impact on Government policy and regulation of offshore wind
deployment.
Strategic Spatial Planning
Long-term strategic planning for the future use of offshore regions can improve the prospects for
offshore wind deployment through the avoidance of potential stakeholder conflicts and
improvement in grid connection efficiency.
Appropriate Site Awards
Techno-economic and environmental feasibility for offshore wind should be assessed at a national
strategic level prior to the award of any sites for development. The system for such award would
benefit from allowing for a mix of large companies and small entrepreneurial developers to
stimulate growth.
Pre-Screening of Sites
A systematic evaluation of potential sites is a helpful starting point. This should be a technically
rigorous assessment of the wind resource through both computational modelling and full scale
assessment. This evaluation of wind resource should be coupled to the identification and
evaluation of constraints. Compilation of all these data in to a single GIS system has been
demonstrated to be very helpful.
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Coordination of Stakeholder Interests
There are many stakeholders, both commercial and governmental, with interests in and influence
on offshore wind development. Identification of these stakeholders and coordination of them is
essential.
International Competition
Any new national market for offshore wind requires a regulatory framework and market incentives
which are sufficiently attractive to international developers and contractors to be competitive with
existing markets.
A5
References
[1] TenneT, Dutch Transmission System Operator, <http://www.tennet.org/english/index.aspx>
[2]
The Ministry of Housing, Spatial Planning and the Environment (Ministerie van
Volkshuisvesting, Ruimtelijke Ordening en Milieubeheer – VROM), <http://www.vrom.nl/>
[3]
North Sea Counter, <http://www.noordzeeloket.nl/>
[4]
Crown Estate, offshore wind, <http://www.thecrownestate.co.uk/offshore_wind_energy>
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ANNEX B – CASE STUDY ON UK OFFSHORE WIND DEVELOPMENT
B1
Policy Drivers
The UK is a signatory to the Kyoto Protocol, committing the country to reducing a basket of six
greenhouse gases by 12.5% (compared with 1990 levels), by 2012. Despite rising CO2 emissions
since signing the protocol, the UK is on course to meet the Kyoto target, due largely to a move
away from coal to gas-fired electricity generation throughout the 1990s.
In February 2007, all 27 EU states agreed to cut overall CO2 emissions by 20%, and to increase the
share of final energy consumption supplied by renewable energy to 20%, by 2020. To help achieve
the Europe-wide CO2 target, the UK has committed to a 30% reduction in CO2 emissions by 2020
(based on 1990 levels). This challenging target is expected to require a substantial shift away from
carbon intensive electricity generation technologies.
Another important legislative driver in the longer-term timeframe is the UK Government's Climate
Change Act, which became law in November 2008. The Act commits the UK to cutting CO2
emissions by 80% before 2050 (again referenced to 1990 levels). The Act also provides for “carbon
budgeting”, which entails the setting of emissions caps at five yearly intervals.
The UK Renewable Energy Strategy (RES) was published in July 2009 by the Department of Energy
and Climate Change (DECC). This presents the policy drivers for achieving the UK’s 2020 renewable
energy targets. These targets include 15% of final energy consumption from renewable sources by
2020, implying 30% of electricity supply from renewable generation, of which about two thirds is
expected to come from wind (onshore and offshore). For offshore wind, there is a target of 33 GW
installed capacity by 2020. The Office for Renewable Energy Deployment (ORED) has been set up,
in order to increase the pace of implementation of renewable generation. The Renewables
Obligation (RO) remains the key driver for renewable energy development, and is discussed in a
following section.
The 2010 change in government appears to involve continued support for renewables even in a
context of deep public spending cuts. However, bottom-up reviews have been kicked off looking
at renewables support mechanisms, the planning framework and reform of the electricity market.
These are scheduled to come to some conclusions mid-2011.
B2
Historical Offshore Development
The first offshore wind project to be constructed in the UK was at Blyth Offshore, in the North Sea,
1 km off the coast of Northumberland. Blyth was primarily an R&D project, with significant capital
support from the EU through the European Commissions Thermie Programme. The UK
Government had some involvement with the project, funding a monitoring and evaluation
programme through the Department of Trade and Industry. Above and beyond the R&D value and
technical innovation emerging from the project, its outcomes were to inform policy towards
offshore wind development in the UK.
Subsequent to the development of the Blyth project the Crown Estate (CE), the entity responsible
for leasing of rights to use the seabed in UK waters, commenced its first “round” of site leasing for
offshore wind projects. Outwith these rounds, activity has been limited, with only a very few
independently developed projects in existence.
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Round One
CE launched the first round of offshore wind development in the UK in late 2000. Bids were invited
for development rights to sites of up to 10 km2 within English and Welsh territorial waters; projects
of up to 30 wind turbines were permitted. Eighteen projects were awarded leases for development
in April 2001, constituting a potential installed capacity of ~1.5 GW. Effectively, all applicants were
awarded leases. However, the smaller, or less experienced, developers sold the project rights on to
owners more capable of completing construction, and 12 of the proposed Round One projects are
now complete, the others mostly having come up against insuperable consenting (3) or technical
issues (2) and the last one which will commence construction in 2011.
Round Two
For the second round of offshore wind deployment, in 2003, Strategic Environmental Assessments
(SEAs) were commissioned by the UK Government, for three regions identified as promising for
development: the Thames Estuary; the Greater Wash; and the North West - again within English
and Welsh waters.
Round Two was designed to be much more ambitious than its predecessor, with no limit on size, or
restriction to territorial waters. Of the 70 proposed projects, a total of 15 were granted leases.
Unlike Round One, the successful companies were overwhelmingly large utilities and international
Oil & Gas firms.
Although Round Two projects are being progressed, there is some uncertainty among developers,
due to the recent history of upward spiralling costs for offshore wind and questions over
workability of the new OFTO regulatory regime for ownership of offshore transmission assets. For
Round Two projects, the additional support offered to offshore wind through special treatment in
the UK RO scheme has provided sufficient support for development and construction activity
within Round Two. Consenting has slowed with no consent issued since autumn 2008 – mainly
due to a collective objection to several projects in the Greater Wash.
In July 2009, the Crown Estate announced an offer to operators of Round One and Two wind farms
to extend their site leases to 50 years, affording developers greater certainty when considering lifeextension and re-powering of their projects. This move was also designed to instil greater
confidence in the supply chain.
Round 2.5
In May 2010, CE announced the award of a further 2GW potential capacity, in the form of
extensions to existing Round 1 and 2 site leases and developments. It was planned that these
developments would bridge the potential hiatus between the winding down of Round 1 and 2
work (as projects come to completion), and the ramp up in Round 3 development later in the
decade. In reality, some of these Round 2.5 projects could be realised before many Round 2
projects tied up in planning.
Round Three
In December 2007, the Department for Business, Enterprise and Regulatory Reform (BERR)
announced the commencement of a Strategic Environmental Assessment (SEA), aimed at
facilitating significant further expansion for offshore wind. A target of 25GW of additional capacity
by 2020 was also announced.
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In January 2009, the UK Offshore Energy SEA Environmental Report was issued for public
consultation. The SEA indicates that the preferred approach of the Department of Energy and
Climate Change 1 (DECC) is to apply spatial and operational limitations to offshore wind
development zones, where required, to mitigate unacceptable environmental impacts, whilst
supporting the overall use of the UK marine environment for achievement of the UK Government’s
overall energy policy objectives. The tender awards were announced in January 2010, and went to
a number of large utilities, reflecting current requirements for a strong balance sheet to develop
projects.
Scottish Territorial Waters
Following expressions of interest to the Crown Estate from developers considering wind farms in
Scottish territorial waters, the Scottish Government carried out an SEA as a priority. On 16 February
2009, CE announced the award of ten site leases for offshore wind energy developments, with a
total installed nameplate capacity of 6.4GW, once developed. The development timeline for these
projects is likely to be similar to that of Round Three projects.
B3
Support Mechanism Development
Before 2001 there was no specific support scheme for offshore wind projects in the UK and indeed
there was no framework for the issue of leases.
Initial Support Measures – The Capital Grants Scheme
Initial market support for offshore wind development in UK waters was provided through BERR’s
Capital Grants Scheme. Capital grants were awarded to a number of UK projects, with eligibility
deemed to occur once they were in receipt of all relevant consents. To date, only Round One
offshore wind projects in the UK are eligible for Capital Grants Scheme funding, with each project
eligible for grants of up to £10M from a total fund of £102M. As the UK offshore wind industry has
matured the Capital Grants Scheme method of funding has been replaced with the Renewables
Obligation, which provides a more “market-based” method of funding for renewable energy
generation.
The Capital Grants scheme was certainly helpful in the initial Round 1 projects but as capital costs
escalated they proved inadequate and it took preferential treatment of offshore projects under the
RO to make projects economic. With that treatment, it is believed all projects have now repaid
their Capital Grant and opted into the enhanced RO.
The Renewables Obligation
The Renewables Obligation (RO) was implemented in England, Wales and Scotland in 2002, and
Northern Ireland in 2005, as the primary mechanism for achieving the UK Government target of
10% of electricity from renewable sources by 2011. The RO places an obligation on electricity
retailers to source an increasing proportion of electricity from eligible renewable energy sources.
Retailers must prove compliance through the surrender of Renewable Obligation Certificates
(ROCs). These are issued to generators according to their power production, and are then saleable
on the open market.
1
DECC is a recently formed UK Government Department that has assumed responsibility for energy policy from BERR and climate change
mitigation policy from the Department for Environment, Food and Rural Affairs (DEFRA).
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As an alternative to buying ROCs, electricity suppliers may opt to pay the “buy-out” price, which is
the price charged per megawatt-hour, where the supplier fails to surrender sufficient ROCs to cover
its RO. Where a supplier opts to pay the buy-out price, the payment feeds into the “buy-out fund”,
which is redistributed (or “recycled”), on a pro-rata basis, to parties who surrendered ROCs within
the given compliance period. The buy-out price is linked to the Retail Price Index (a national
measure of inflation) and is revised annually.
The price of a ROC is the driving force behind the market for renewable energy generation in the
UK. Factors determining the price of a ROC are the RO level, buy-out price and the so-called
“recycle benefit”, as well as the scale of renewable generation deployment in any given year. The
more suppliers pay the buy-out, and the less the obligation is met through bona fide renewable
energy generation, the more valuable a single ROC becomes.
As well as the annual recycling of the buy-out fund, quarterly auctions of ROCs are held by the NonFossil Purchasing Agency, offering the opportunity for electricity suppliers to buy ROCs, rather than
opting for the buy-out route. Figure B3.1 shows the average price achieved at the ROC auctions
held to date, alongside the average value of a ROC to suppliers, and the percentage compliance to
the RO, both respective to the appropriate compliance period. It can be seen that the level of RO
compliance has been within the range of 55-75%, and the market price of ROCs has remained
relatively stable.
80.00%
£60.00
76.0%
£50.00
70.00%
£40.00
68.9%
67.6%
65.4%
65.00%
64.4%
60.00%
£30.00
ROC Value/Price
Percentage Compliance
75.00%
£20.00
58.9%
55.8%
55.00%
50.00%
Jul-02
Jul-03
Jul-04
Percentage Compliance
£10.00
Jul-05
Jul-06
Jul-07
Average ROC Price at Auction
Jul-08
Jul-09
£0.00
Jul-10
Average ROC Value
Figure B3.1 - Historical ROC Values and Compliance Levels.
Reform of the RO
Since its inception in 2002, the RO system has been under almost continual review, with regular
consultations taking place between government and industry. In April 2009, the latest Renewables
Obligation Order was published, outlining the methodology of implementation of the RO, and the
level of support available for various technologies. In order to help reassure investors, and permit
long-term planning, the life of the RO system has been extended to 2037, while support for any
individual project will last for 20 years.
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Previously, suppliers were obliged to source a certain percentage of their electricity from
renewable sources; now the requirement is to surrender a specified number of ROCs. This allows
for the introduction of “banding”: certain renewable technologies will receive more or less than 1
ROC / MWh, making that technology more or less valuable, and stimulating market growth in more
expensive technologies, such as tidal and solar generation. At present, offshore wind is banded as
receiving 1.5 ROCs / MWh. A special bonus rate of 2 ROCs has been applied to offshore wind
projects, gaining accreditation under the scheme before March 2014.
Advantages of the 2009 Renewables Obligation Order include stimulus for technologies such as
offshore wind, wave and tidal, which at present have a higher cost of energy than other established
technologies, such as onshore wind and landfill or sewage gas generation. The banding system
will encourage the market to develop these more costly technologies, rather than relying on “easy
ROCs” from established technologies which may have less potential for future development. This
move has been of concern to onshore wind developers, who fear a crash in the market value of
ROCs; however, the “headroom” clause has (in part) been designed to alleviate such concerns.
The Government will review the ROC bandings at regular intervals with the first review currently
underway and a decision expected in autumn 2012 [1]. This means that developers will not
necessarily receive the level of ROC support promised at the outset of project development,
although once a project is in operation the concept of “grandfathering” should mean a consistent
level of support is provided. Additionally, ongoing lobbying will be required from each sector to
fight for its continued level of ROC support, taking up further resources.
The RO reaches its maximum value of 15% at the end of 2015 when, without “headroom” a collapse
in ROC values was seen as a distinct possibility. The “headroom” concept was introduced in late
2009 to the RO and effectively means that in any year where the RO level is exceeded nationally,
the level will be aligned to delivered levels. This modification means that any MWh of renewable
generation will minimally earn a ROC valued at the buy-out price. Offshore wind projects will
minimally earn 1.5 or 2 ROCs (depending on date of commissioning) and, also the “recycle”
component until such time as the RO level is achieved.
Other Benefits and Incentives
The Climate Change Levy (CCL) was introduced in April 2001, and is essentially a tax on business
and public sector energy users in the UK. Electricity generated from renewable sources is exempt
from this tax, which adds up to £4.30 / MWh to the value of such electricity.
All generators of electricity in the UK are subject to charges levied by the network operator. Such
“use of system” charges are applied, either by distribution or transmission network operators or by
both, depending upon the location of the grid connection point for the project. The magnitude of
the system usage charges depends upon the region of interest and can, in some cases, be negative,
with the project owner receiving payments from the network operator. This system is designed to
help pay for the additional infrastructure costs associated with accommodating additional
generation in areas of low demand.
More recently, the government has pledged a certain amount of investment in offshore wind
infrastructure, in order to ensure deployment targets are met. These grants come under the
umbrella of the Environmental Transformation Fund (ETF), a budget established to stimulate
transition to a low-carbon economy. Examples of funds awarded include a £60 million port
infrastructure investment program, as well as £10 million awarded to various individual companies
investing in UK facilities. These stimulation measures seem to have helped guarantee
development from some major players: Siemens, GE, Mitsubishi, Gamesa and Clipper are all
expected to create UK manufacturing facilities. On the other hand, when pre-budget speculation
put the funds in doubt, there were indications from some major players that this would cause them
to change their plans. These announcements were of course intended to put pressure on the
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government to keep the full amount of the funds, but they do serve as an example of the potential
influence of public spending in these areas. This spending has been re-affirmed by the new
government and the investment plans have also been re-affirmed.
B4
Licensing development
The Energy Act 2004
In order to establish a legal framework for renewable energy projects outside of UK territorial
waters, new legislation was required. This was enacted in the Energy Act 2004, which established a
Renewable Energy Zone adjacent to territorial waters, encompassing the UK Exclusive Economic
Zone (EEZ). The Act requires developers to apply for consents under the Electricity Act 1989 and
extends the jurisdiction of the CE, to encompass the granting of leases within the Renewable
Energy Zone.
Energy Act 2008
The Energy Act 2008 contains a number of legislative changes, required in order to allow
implementation of the ROC banding system, as well as some to facilitate development of the
Offshore Transmission Network Owners (OFTO) regime.
The Planning Act 2008
The Planning Act 2008 has sought to streamline the consenting process, by establishing the
Infrastructure Planning Commission (IPC), which will be responsible for the issuance of a single
consent for Nationally Significant Projects in England and Wales. In the case of offshore wind
farms, this has been defined as any project of a size greater than 100 MW. In Scotland and
Northern Ireland, these responsibilities rest with the appropriate ministers.
The change of government in April 2010 to a Conservative-Liberal coalition has resulted in a
change to the structure of the IPC, as it has now been absorbed into the “Major Infrastructure Unit”.
The new department is still planned to centralise planning for nationally significant projects
although it is to be brought back under direct political control.
The Marine and Coastal Access Bill
The Marine and Coastal Access Bill is designed to consolidate existing legislation affecting the
marine environment, as well as to facilitate strategic planning, taking account of both
environmental and economic concerns. It will also provide for the formation of the Marine
Management Organisation (MMO), a body which (in England and Wales) will be consulted by the
IPC, for projects greater than 100MW, and will be directly responsible for the consent of projects of
less than 100MW capacity. In Scotland and N. Ireland, the relevant ministers will remain
responsible for issuing consents.
The combination of the Planning Act 2008 and the Marine and Coastal Access Bill will replace the
requirement for licences under the Food and Environmental Protection Act (1985) and the Coastal
Protection Act (1949), with a single marine licence.
The licensing framework in the UK is complex and to that extent adds cost and some delay to all
projects, although consenting success rate is good. Into the future, it is widely-accepted that the
most serious consenting issue is for onshore grid infrastructure.
Offshore Transmission Owners (OFTOs)
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The development of a competitive market for power transmission assets has introduced another
variable for project developers to consider. Under this regime, parties may be invited to bid to
construct and operate the offshore grid connection for a project (for assets that are already built,
they are bidding to buy those assets from the developer); the revenue stream being based on
power sales to the grid utility. As OFTOs are competitively-selected based on return demanded
and exposed to low risk, this was seen as a way of having a large component of the plant financed
at low cost. Unfortunately, the OFTO system complexities have threatened to de-rail project
programmes so it is likely that the system will be watered down to allow developers to sell-off their
transmission system in an OFTO auction after the project goes on-line.
B5
Associated Industrial Development
The UK, despite having a strong record in offshore project developments, has not so far had a
matching domestic industry. Much manufacturing and contracting is imported from other
European countries, and a large number of principal components are foreign-built. This situation
has both failed to provide full potential benefit to the British economy from the offshore activity,
and also left the UK industry vulnerable to interplay between foreign and domestic markets. The
late-2008 financial collapse highlighted this weakness, with a devaluation of the pound increasing
certain project costs.
One contributory factor to this lack of domestic industry is the historically slow and uncertain
onshore wind sector. Projects suffer planning delays and application rejections to a high degree, in
part due to Nimby-ism2, and the political will towards onshore wind has not been consistent. The
UK has in these terms been a higher risk market, and major manufacturers have preferred to
remain based elsewhere in Europe.
Before 2004, the initial high degree of optimism over the long-term prospects for offshore wind led
to fierce competition between contractors for the early demonstration projects. In an attempt to
establish a good market position, optimistically low EPC contract prices were offered. Be it due to a
deliberate policy of 'loss-leading' or inadvertent cost optimism, it is considered unlikely that the
principal contractors turned a profit on these early engagements. Evidence for this is demonstrated
through the subsequent insolvency or buy-outs of several key second tier contractors – notable
examples including Dutch Sea Cable, CNS Renewables and Mayflower Energy.
B6
References
[1] Department of Energy and Climate Change (DECC), <http://www.decc.gov.uk>
2
“Not in my back yard” – the opposition of locals to development in their specific region
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ANNEX C – INDUSTRIAL SYNERGIES FOR WAVE AND TIDAL SECTORS
C1
Introduction
This section summarises the present state of the wave and tidal stream industry, the main issues
facing it, and the development potential around Ireland. It is not a detailed study to the extent that
has been presented above for offshore wind, but rather as a brief commentary on the likely
development scenarios and timescales, any synergies which may exist with offshore wind, and the
supply chain implications for Ireland.
The status of the wave and tidal stream industry is well summarised in the March 2010 Renewable
UK report Marine Renewable Energy – State of the Industry Report [1]. This covers amongst other
things the technology status, resource and environmental constraints, and investment potential.
Local studies of resource and development potential around the Irish and Northern Irish coasts are
summarised in the following:
C2
(i)
The Northern Ireland (NI) Strategic Environmental Assessment (SEA) for marine
renewable energy (completed) [2];
(ii)
The Draft Offshore Renewable Development Plan (OREDP) put out for public
consultation by the Irish Department of Communications, Energy and Natural
Resources (DCENR) in November 2010 [3]. This summarises the outcome of the
SEA commissioned for Irish waters.
Wave and tidal stream technology status
Wave and tidal stream technologies are still at an early stage of development. There are over
ninety known tidal stream device developers worldwide, and a similar number of wave devices. As
yet there has been little technology convergence, and a multitude of concepts for foundations,
prime movers, installation and O&M are being proposed. There is much R&D activity and a
reasonable number of laboratory, tow tank and smaller scale field devices have been built and
tested; only a handful, however, of large scale (i.e. multi-hundred kilowatt) grid-connected
machines have been installed in representative ocean sites. One of the large scale tidal stream
plants (Marine Current Turbines Limited’s 1.2MW SeaGen machine) is located in Strangford Lough
in Northern Ireland. Two quarter-scale wave devices have been tested in the Galway Bay test site –
Wavebob and OE Buoy.
This situation has advanced slowly over the last five years (see for example the DCENR’s 2005
report Ocean Energy in Ireland [4]), and it is fair to say that industry progress has been much slower
than was initially predicted. There are various reasons for this including technical difficulties (it has
proved much harder than was thought to design and build reliable devices); the risk and expense
of offshore marine operations; capital, grid and environmental constraints; and seabed leasing
processes (The Crown Estate and others). Whilst work is underway in all these areas, there is still no
commercial tidal stream or wave array anywhere in the world, and technology risk continues to be
dominant.
A further issue is that project developers have tended to adopt a technology-neutral waiting game,
biding their time until technology suppliers are capable of providing reliable and warranted plant;
for many small entrepreneurial device developers (which constitute the majority) it is difficult to
provide substantive warranties, and it is only relatively recently that major manufacturers capable
of doing so (such as Rolls Royce, Alstom, Voith and Siemens) have invested in the technologies to a
significant extent.
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Historically, the UK has been the global leader in technology development, however this has
changed over the last few years as credible developers have emerged in all corners of the world
including the USA, Canada, Ireland, Germany, France, Australia and Japan. The UK has a very
strong (and growing) research asset base including both laboratory tanks (Queens University
Belfast, the PRIMaRE wave and tidal flume tank in Plymouth, and Edinburgh and QinetiQ’s tow
tanks) and ocean test sites (e.g. NaREC, EMEC and the Wave Hub).
The Republic of Ireland has a strong indigenous wave energy research base, and its assets include a
test tank at the HMRC in Cork, a quarter scale test site in Galway Bay, and the full scale grid
connected test site which is currently under development near Belmullet in Co. Mayo. Details can
be found at www.seai.ie/oceanenergy.
Ireland and Northern Ireland are home to a handful of wave device developers and a smaller
number of tidal stream developers, the main one being Openhydro who has established
manufacturing bases at Dublin and Greenore. There is therefore already some indigenous industry
in Ireland.
In summary, wave and tidal stream technologies are some way behind offshore wind, and the
feasible development scenarios are more uncertain. Offshore wind developments are likely to
dominate over the next five to ten years.
C3
Wave and tidal stream development scenarios
Broadly speaking, the majority of the tidal stream resource is located off (or in the case of the
Western British Isles, serviceable from) Northern Ireland, and the majority of the wave energy sites
are in ROI waters.
Given that technology risk is still dominant, and that there are also environmental and grid
constraints on many of the wave and tidal stream sites, there is considerable uncertainty in
evaluating the extractable resource and predicting credible development scenarios. By way of
indicating possibilities, however, predicted scenarios from recent SEA’s are summarised below:
C3.1 Irish waters
The available wave and tidal stream resource in Irish waters has been assessed in the ongoing SEA
(see [3]), and the credible development scenarios out to 2030 accounting for environmental and
other physical constraints are summarised in Table C3.1. The data sources and assumptions in
these scenarios are detailed in [3] and are not repeated here; the most comprehensive supporting
resource assessment is the SEI’s 2005 Ocean Energy in Ireland report [4].
Low scenario (MW)
Medium scenario
(MW)
High scenario
(MW)
Offshore wind
800
2,300
4,500
Wave & tidal stream
75
500
1,500
Table C3.1: Marine renewables development scenarios from the Irish SEA
(Source: SEAI [3])
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C3.2 Northern Irish waters
The available wave and tidal stream resource in Northern Irish waters has been assessed in the
completed NI SEA [2]. It was concluded that there is around 300MW of technically and
environmentally extractable tidal stream resource, out of a total resource of ~550MW. No estimate
was made of the extractable wave capacity, owing to the technical and resource uncertainties.
C4
Synergies with offshore wind for Irish developments
C4.1 Present synergies
Table C4.2 summarises the supply chain synergies that exist between offshore wind, and wave and
tidal stream installations. The first column shows the technical synergies, and the second
highlights the likely opportunities for Irish industry.
Area
Technical synergy with
offshore wind
Industrial opportunity
for Ireland
EIA / consultancy
S
S
Site surveys
S
S
P/W
P/W
Device fabrication / assembly
S
Depends on whether
device developers locate in
the region
Foundation design & fabrication
S
S
Port, assembly & storage areas
S
S/P
Device design
(but note that three major
ports in NI have access
advantages and existing
facilities)
Installation
O&M infrastructure / services
P/W
P/W
S
S
(note additional onshore
O&M opportunities)
(S=strong; P=possible; W=weak)
Table C4.2: Summary of synergies between wave & tidal stream, and offshore wind
The logic behind Table C4.2 is as follows:
(i)
For tidal stream, although there are many similarities with wind engineering, the
loading on the rotors is different and the drivers for foundation design are also
different. Many tidal stream sites are on rocky sea beds or close to underlying bedrock,
and the installation processes and plant are therefore very different. With regard to site
surveys, environmental assessment, planning support, H&S and general farm
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development consultancy, there are strong synergies with offshore wind, and also
existing Irish capacity.
(ii)
Regarding device construction, wind turbines tend to be shipped as completed
nacelles, so there is limited opportunity for Irish industry which has little indigenous
capacity. Wave and tidal stream devices need similar assembly plants to wind –
electro-mechanical systems integration essentially – and there may be scope for Irish
industry, depending on the ultimate location of the device developers.
In June 2010 the Carbon Trust commissioned a report into the prospects for Northern
Ireland ports in supporting renewable energy developments [5]. Although this focuses
on the NI and Western British Isles, it gives an idea of the facilities available, and how
and from where the identified sites for offshore wind, wave and tidal stream can
credibly be supported. There are three NI ports which are likely to be capable of
developing a strong marine renewables support base: Belfast, Londonderry, and
Warrenpoint. Of these, Londonderry is also well placed to serve the NW Irish wave
resource, there being no major facilities on the W coast. Dublin and Dun Loaghaire are
well placed to serve the low speed tidal stream resource off the E Irish coast.
(iii)
Both wave and tidal stream foundations require similar heavy fabrication, craneage and
load-out facilities as are needed for offshore wind (or space for quayside concrete
batch plants if using gravity base foundations). There is scope for Irish ports here,
making use of the quayside workshops and lay-down and storage areas; there is a
reasonably strong synergy with offshore wind here.
(iv)
Given the size and configuration of the proposed plant concepts, it is likely that a
significant amount of wave and tidal stream device maintenance will be done at
quayside workshops rather than stripping and returning plant to inland OEMs. The
vessels needed for O&M are likely to be small locally-based workboats (multi-cats,
catamaran barges, vessels with rear A-frames). This creates additional opportunities for
port operators and local O&M contractors.
(v)
The vessels needed for tidal stream installation, however, are in the main different from
those needed for offshore wind, because of the requirement to hold station in strong
tidal currents. Wind turbines need stable fixed platforms, heavy lift cranes with high
reach, and have tight placement tolerances on the foundation and nacelles. Tidal
turbines on the other hand generally have much less onerous tolerances, and can
operate from floating (barge or Dynamic Positioning (DP)) platforms. They are required
to place equipment on the sea bed and don’t need high-lift cranes, in fact it is the
maximum lowering rate of the hook which tends to govern because sensitive overboarding operations can only be carried out over slack water periods.
Wind turbines are therefore generally installed from jack-up barges or stabilised ships.
Tidal turbines cannot generally be installed from jack-ups because of the vortex
loading on the solid legs, the water depth (most tidal stream is in 30-60m which is
classed as deep water in terms of offshore wind) and stability issues under the current
drag. Tidal sites are generally on rock or stiff sea beds, so there is minimal fixity for the
legs provided by soil penetration as there is at wind sites.
(vi)
Wave energy can generally be installed from similar vessels to offshore wind, although
since there is such a range of device concepts, water depths and distances from
shoreline it is difficult to generalise. The Pelamis device is installed using an anchor
handler to install gravity moorings and a multi-cat to tow to site and hook up to grid.
Aquamarine’s Oyster device was installed at EMEC using a jack-up (Deep Diver) to
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install the piles and a shearleg crane barge (GPS Apollo) to place the device onto the
foundation.
(vii)
Cabling vessels are likely to be similar for all types of marine renewables, as are the
small support craft needed - ROV, shallow surface dive, personnel transfer, site safety /
guard vessels etc.
C4.2 Additional future synergies subject to technology developments
There are some early stage technical concepts which have the potential to increase the synergy
between tidal stream and offshore wind:
(i)
Low-speed deep water generation devices.
(ii)
Combined offshore wind and tidal stream installations.
Most tidal stream device developers are designing devices to harness the high-speed high-energy
resource in moderate water depths (i.e. mean spring peak flow speeds in excess of 5kt and water
depths up to 50m). This is because the economics of conventional turbine systems become
unfavourable in slower and deeper water – the drive train and structural loads increase
disproportionately and in deeper water the technical difficulties of foundation installation also
increase.
There are some devices under development, however, for example the Minesto device [6]. This
device is based on novel energy extraction concepts which potentially enable the problems to be
overcome, and in doing so open up the possibility for a large additional resource to be harvested.
The middle of the Irish Sea happens to be one of the best European sites, with the potential for
1000MW+ of installed capacity.
It must be emphasised that these are novel early stage devices, with significant technology
challenges; they are identified for the sake of completeness, and for now it is probably prudent to
maintain a watching brief and not include the low speed resource in development scenarios until
further proving has been completed. Strictly, these devices do not represent increased synergy
with offshore wind, but rather increased opportunity to apply the synergies identified in Table
C4.2.
Certain sites with technically and environmentally extractable tidal stream resource, also have
offshore wind resource (see e.g. [3]). One developer is currently considering a combined tidal /
wind device, based around the use of their tidal turbine mounted on a surface-breaking monopile
which extends upwards to support a wind turbine [7]. This would enable the cost of foundation
and grid infrastructure to be shared between the two machines, improving the economics of each.
The technology is likely to be of only limited application, however, because in general tidal stream
and offshore wind are not readily co-locatable, and where they are, the array layouts and spacings
are very different so that only the occasional machine would be able to share foundations.
C5
References
[1] RenewableUK, Marine Renewable Energy: State of the Industry Report, March 2010.
[2]
Department of Enterprise, Trade and Investment (DETI), Strategic Environmental Assessment
(SEA) of Offshore Wind and Marine Renewable Energy in Northern Ireland. Environmental report
volume 1: Main Report, December 2009.
[3]
Sustainable Energy Ireland (2010), Draft Offshore Renewable Energy Development Plan, viewed
23 November 2010,
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<http://www.seai.ie/Renewables/Ocean_Energy/Offshore_Renewable_SEA/Environmental_
Report/>
[4]
Sustainable Energy Ireland (2005), Ocean Energy in Ireland
[5]
GL Garrad Hassan (2010) Northern Ireland Renewable Energy Ports Prospectus
[6]
Minesto, <www.minesto.com/>
[7]
Marine Current Turbines, <http://www.marineturbines.com/>
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