STUDY OF THE COSTS OF

OFFSHORE WIND GENERATION

A Report to the Renewables

Advisory Board & DTI

URN NUMBER: 07/779

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 STUDY OF THE COSTS OF OFFSHORE WIND GENERATION
A Report to the Renewables Advisory Board (RAB) & DTI

URN NUMBER 07/779

Contractor
Offshore Design Engineering (ODE) Limited

This report was carried out for RAB and DTI by ODE Ltd
and, as such, reflects the views and judgments of the
authors and do not necessarily reflect those of RAB or DTI.

First published 2007

 Crown Copyright 2007

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 TABLE OF CONTENTS

1.0 INTRODUCTION ....................................................................................................... 6

1.1 Background................................................................................................................ 6

1.2 Scope & Objective ..................................................................................................... 6

1.3 Study References/Contributors .................................................................................. 6

2.0 RESULTS/EXECUTIVE SUMMARY ......................................................................... 7

3.0 WIND ENERGY IN EUROPE..................................................................................... 9

3.1 The Onshore Wind Industry ..................................................................................... 10

3.1.1 General ............................................................................................................. 10

3.2 Offshore Wind Energy.............................................................................................. 13

3.2.1 General ............................................................................................................. 13
3.2.2 Round 1 Projects .............................................................................................. 15
3.2.3 Round 2 and Round 3 Projects......................................................................... 17

3.3 Factors affecting the cost of Onshore and Offshore wind ........................................ 19

3.4 Cost comparison – onshore/offshore ....................................................................... 21

4.0 REVIEW OF INSTALLATION LIMITATIONS.......................................................... 23

5.0 REVIEW OF DECOMMISSIONING REQUIREMENTS ........................................... 24

6.0 FUTURE COST OF WIND GENERATION .............................................................. 26

6.1 CAPEX..................................................................................................................... 26

6.2 OPEX ....................................................................................................................... 28

7.0 TIMING OF FUTURE OFFSHORE DEPLOYMENT ................................................ 29

7.1 Research and development ..................................................................................... 29

8.0 ODE OWF COST MODEL ....................................................................................... 31

8.1 Introduction .............................................................................................................. 31

8.2 Fixed Parameters..................................................................................................... 32

8.3 Input and Results Sheet........................................................................................... 32

8.3.1 User Input section ............................................................................................. 33

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 8.3.2 Results Section................................................................................................. 33

8.4 Schedule and Costs................................................................................................. 34

8.5 Sheet – Trends ........................................................................................................ 42

8.5.1 General ............................................................................................................. 42

8.6 Assumed Turbine cost ............................................................................................. 46

8.6.1 Steel.................................................................................................................. 47
8.6.2 Copper .............................................................................................................. 48
8.6.3 Learning Curves ............................................................................................... 48
8.6.4 Supply & Demand ............................................................................................. 48
8.6.5 Research and development .............................................................................. 49

9.0 AREAS FOR FUTURE COST REDUCTIONS......................................................... 50

9.1 Research and development ..................................................................................... 50

9.1.1 General ............................................................................................................. 50
9.1.2 Turbines............................................................................................................ 51
9.1.3 Transition piece ................................................................................................ 52
9.1.4 Access .............................................................................................................. 52
9.1.5 Foundation........................................................................................................ 53
9.1.6 J Tube entry configuration. ............................................................................... 53
9.1.7 Installation vessels............................................................................................ 54
9.1.8 Cabling from offshore to onshore...................................................................... 54
9.1.9 Materials ........................................................................................................... 54

9.2 Learning gains ......................................................................................................... 55

10.0 REFERENCES ........................................................................................................ 56

APPENDICIES ................................................................................................................... 57

APPENDIX 1 ROUND 1 FEEDBACK ............................................................................ 58

APPENDIX 2 – STRUCTURAL WEIGHT STUDY.............................................................. 75

APPENDIX 3 – SENSITIVITY OF LOAD FACTORS AND MODEL TRENDS ................. 104

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 LIST OF FIGURES

Figure 1: Source: EWEA website (Ref #1) 9

Figure 2: Worldwide Installed Wind Capacity (World Wind Energy Association – Ref
#2) 10

Figure 3: Percentage by Region of Worldwide Installed Wind Capacity (World Wind

Energy Association – Ref #2) 11

Figure 4: European Wind Atlas, Onshore. Source, Risø National Laboratory. (Ref #3) 12

Figure 5: European Wind Atlas, Offshore. Source, Risø National Laboratory. (Ref #3). 13

Figure 6: Source: Offshore Wind At Crossroads (Ref #6) 14

Figure 7: Source: Europe’s Energy Crisis – The No Fuel Solutions. (Ref #7) 17

Figure 8: Location of Round 2 Developments 18

Figure 9: Differences in Installed Costs Between Onshore (Ref #11) and Offshore
Wind Farms 21

Figure 10: Historical Costs for Onshore and Offshore Wind Energy (Ref #12) 22

Figure 11: OWF Cost Breakdown 51

LIST OF TABLES

Table 1: Growth in Worldwide Installed Wind Capacity from 2004 - 2005 (World Wind
Energy Association – Ref #2) 10

Table 2: Offshore Wind Energy Estimates – Europe. (Ref #3) 14

Table 3: Details of Round 2 Offshore Wind Farms (Ref #8) 19

Table 4: UK R&D Investment Estimate 30

Table 5: Fixed Parameters in ode Offshore Wind Farm Cost Model 32

Table 6: Explanation of Cost and Schedule Assumptions in ode Offshore Wind Farm
Cost Model 37

Table 7: Assumed Turbine Cost 46

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Nomenclature

BWEA – British Wind Energy Association

CAPEX – Capital Expenditure

DEFRA – Department for Environment, Fisheries and Rural Affairs

DFT – Department for Transport

DTI – Department of Trade and Industry

E&I – Electrical and Instrument

EPCI – Engineering, Procurement, Construction and Installation

ES – Environmental Statement

FEED – Front End Engineering Design

FEPA – Food and Environment Protection Act

HSE – Health, Safety and Environment

MCEU – Marine Consents and Environment Unit

ode – Offshore Design Engineering Ltd

OFGEM – Office of Gas and Electricity Markets

OPEX – Operating Expenditure

ORCU – Offshore Renewables Consents Unit

OWF – Offshore Wind Farm

PTC – Production Tax Credit

R&D – Research & Development

ROC – Renewables Obligation Certificate

SCADA – Supervisory Control and Data Acquisition

WTG – Wind Turbine Generator

WTGS – Wind Turbine Generator System

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1.0 INTRODUCTION

1.1 Background

The Department of Trade and Industry (DTI) commissioned ode to study the trend in
future costs of offshore wind generation, and the potential for cost reductions in the
future. This would build on work already undertaken within the Department and on
practical experience gained within the UK and worldwide since 2000.

1.2 Scope & Objective

Considerable work has already been undertaken on the costs of offshore wind
generation. In addition there is much data and practical experience gained from the
First Round of offshore wind projects constructed in the UK since 2003.

The Scope of Work had the following objectives:

• Estimation of the future costs of offshore wind generation.

• Assessment where cost reductions in offshore wind projects are most likely to be
realised.

• To use the information gathered to provide an estimate of the timing and

deployment of future offshore wind generation.

• An interim report, which reports on the feedback from both developers and wind
farm component supplier companies for Round 1 developments. This is attached
as Appendix 1.

An additional study was carried out to ascertain the variability of the foundation
structural weight with water depth, under different turbine loadings and in variable soil
conditions. This allowed accurate assessment of structural weights for cost estimations
in the cost model. This is documented in Appendix 2.

Further study has also been conducted on the sensitivity of load factors and on the
individual trends used in the ode cost model. The results of this study can be found in
Appendix 3.

1.3 Study References/Contributors

As part of the project and in order to obtain accurate and updated information from the
industry ode carried out an extensive research into the industry. The research also
involved preparation of a detailed questionnaire, which was sent to numerous parties
involved in the Offshore Wind Industry including Project Developers, Installation
Contractors, Financial Institutions, Turbine Manufacturers and suppliers and service
providers with follow up interviews in many cases. The information requested focused
on project costs, schedule, future predictions and requested views on the outlook of the
industry. The following companies/organisations were contacted during the study:

A2SEA, BWEA, Centrica, DTI, Elsam, E-ON, GE, Npower Renewables, OFGEM

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2.0 RESULTS/EXECUTIVE SUMMARY

This study was commissioned by the Department of Trade and Industry (DTI) in order to
determine an estimate in future costs of offshore wind generation, and the potential for
cost reductions in the future.

Currently, given the strong market demand for wind turbines and cables, project costs
are rising for an industry that is already borderline in terms of economical viability.
Hence, the industry and the Government needs to be convinced that there is potential to
make this industry more economically attractive and to ensure that it is able to contribute
to meet future UK targets of energy from renewable sources.

The focus of this report is on the ode Offshore Wind Farm Cost Model, which was
specifically developed to allow such specific estimates of future wind generation costs to
be produced and to allow the user to carry out “what if” scenarios for changes in the
primary trends.

Following extensive research six parameters were identified has having the most
significant effect on overall project costs. Those are supply and demand, steel costs,
copper costs, the effect of learning, research and development and supply and demand
of turbines. These trends have been developed based on, where applicable, historical
data, previous study work and an extensive Industry Research carried out by ode.
Three trend lines were identified for each trend, a normalised trend line, which ode
perceived would be the most likely and then an upper and lower bound.

The cost model is based on a level 2 schedule with calculated and fixed costs and
durations to individual activities. These costs and durations have been based on
information garnered from representatives right across the industry from developers to
financiers to cable manufacturers to installation contractors.

In parallel with the cost model, a structural study was run with the aim of identifying
foundation weights with varying water depths and soil types. It was determined that the
monopile, the preferred foundation structure, would become too expensive as water
depths increased to circa 25m and that alternative structural solutions such as a tripod,
would be more effective. This information was fed into the cost model.

When running the cost model for a 30 turbine project starting in 2006, employing the
perceived trend lines and with zero inflation, there is an initial rise in overall costs per
installed MW. This increases from approximately £1.6M to about £1.75M in 2011 before
reducing to about 80% of the original cost by 2020.

The perceived cost reducing impacts of research and development and learning
curve far override the cost increases attributed to steel, copper and supply and
demand.

Industry benefit can be accelerated if funding is identified for the main areas where cost
savings can be realised.

Major savings can be realised if turbines are made of lighter more reliable materials and
where turbine components such as gearboxes are developed to be more fatigue
resistant. This latter development would lead to reductions in offshore operating and

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maintenance costs. The other significant areas worthy of R&D investment include
foundations, access, transition piece and installation vessels.

The cost reductions from learning curves will only be realised if the industry actually
progresses. This trend is based on the fact that for every doubling of installed capacity
there is a 10% reduction in cost based on current plans. Without continued interest in
the industry this learning will not come to fruition.

The study noted that whilst there are many common factors between the oil and gas
offshore industry that the challenges presented to the offshore wind industry are very
different, representing a new challenge to make R&D benefits sufficient for economic
viability.

Further study was also conducted on the sensitivity of load factors to wind farm output
and on the individual effects of the perceived trends on CAPEX.

It was determined that a 15% change in load factor could lead to a 60% change in
output and hence location of the wind farm is paramount and initial detailed study into
the site wind profile by use of met masts is imperative.

The analysis of the trends indicated that the R&D and Learning trends reduce the
CAPEX costs significantly without which the CAPEX would almost double by year 2020.

The parametric study also showed just less than a 30% reduction in CAPEX cost for
both R&D and Learning, offset by a 46% increase due to Steel cost and 18% due to the
cost of copper. Turbine cost in the long term tends to reduce the CAPEX by some 15%.
Clearly without the benefits of R&D and industry learning the development costs will
make the industry uneconomic.

The Learning trend is proportional to the level of activity in the industry; the positive
benefits of this can only be amplified by ensuring that the industry remains active. R&D
benefit and Financial support to the industry are primary motivators to ensure continued
development.

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3.0 WIND ENERGY IN EUROPE

The development of the Wind Energy industry has been significant over the last 20
years. Figure 1 identifies that currently Europe has over 40GW of installed wind energy
capacity, with Germany and Spain having the greatest installed capacity accounting for
approximately 50% of total European capacity.

However, about 97% of the European Wind installed capacity is onshore.

Figure 1: Source: EWEA website (Ref #1)

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3.1 The Onshore Wind Industry

3.1.1 General

The onshore wind industry is a relatively more mature industry than offshore. The first
large scale onshore wind farms were developed during the 1970’s including the wind
farm at Altamont Pass in California, which is composed of 6,000 turbines.

Worldwide, the installed onshore capacity is approximately 58,000MW. The figures

below include offshore installations, which account for only about 1000MW currently.

58.982
60.000

47.671
50.000

39.288

40.000

31.163

30.000
24.320

18.039
20.000
13.696
9.663

10.000 7.475

0
1997 1998 1999 2000 2001 2002 2003 2004 2005

Figure 2: Worldwide Installed Wind Capacity (World Wind Energy Association – Ref #2)

As can be seen below, the majority of installed wind farms are in Europe, representing
approximately 70% of global capacity. However, there has been significant growth in
both Asia and America.

Table 1: Growth in Worldwide Installed Wind Capacity from 2004 - 2005 (World Wind Energy Association – Ref #2)

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Figure 3: Percentage by Region of Worldwide Installed Wind Capacity (World Wind Energy Association – Ref #2)

The European onshore wind energy resource is significant with some estimates putting
it at ~ 600 TWh. This estimate takes into account population density and available land
area for wind farm use. (Ref #3).

Figure 4 below, shows the onshore wind energy profile for Europe. It highlights the
significant potential of Scotland, which is where the majority of the UK onshore wind
farms are located.

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Figure 4: European Wind Atlas, Onshore. Source, Risø National Laboratory. (Ref #3)

The first UK commercial onshore wind turbines were erected in 1991. Currently there
are 129 operational onshore wind farms in the UK producing 1,636MW of renewable
energy (Ref #4).

Some industry estimates anticipate that by 2010, the UK onshore wind industry will
generate 50 per cent more electricity than previously predicted, and will have installed
6,000 megawatts (MW) of wind power capacity, generating almost 5% of UK electricity
supply and reducing up to 13 million tonnes of CO2 emissions from fossil fuel sources.
This would achieve nearly half of the Government's 2010 renewable energy target on its
own (Ref #5).

Worldwide, the onshore market is currently developing strongly as it is seen as a lower

risk option for those involved in the supply chain and it’s setup costs are less to develop
than offshore. Hence, turbine manufacturers are currently focusing on this market.

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3.2 Offshore Wind Energy

3.2.1 General

The UK and Europe have a significant offshore wind resource. Figure 5 identifies
discrete bands of wind speed for various heights above sea level for European waters.

Some experts estimate that the European offshore resource alone, could generate up to
~ 3000 TWh of electricity which would more than satisfy the current consumption of ~
2,900 TWh (2006 estimate) – Ref #3.

A modern wind turbine produces electricity 70-85% of the time, but it generates different
outputs dependent on wind speed. Over the course of a year, it will generate about 30%
of the theoretical maximum output. This is known as its load factor. The load factor of
conventional power stations is on average 50%.

Figure 5: European Wind Atlas, Offshore. Source, Risø National Laboratory. (Ref #3).

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The UK has the greatest resource of offshore wind in Europe with nearly three times its
current consumption available, as is shown in Table 2 below.

Table 2: Offshore Wind Energy Estimates – Europe. (Ref #3)

Currently, there is about 1,000MW (or 1GW) of installed offshore wind energy globally,
with over 20% of that installed in the UK. Figure 6, below shows the breakdown of
installed offshore wind capacity to date by country.

Figure 6: Source: Offshore Wind At Crossroads (Ref #6)

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The first offshore wind project was installed off Denmark in 1991. The UK instigated the
Blyth Offshore project in 2000 as its pilot phase and first foray into the offshore market.

3.2.2 Round 1 Projects

The first phase of the UK’s offshore wind industry was launched in December 2000 with
the release of selected areas around the UK to be leased by the Crown Estate as a pilot
phase.

The lease term for Round 1 projects was of 22 years and includes timing requirements
for the construction of the wind farm, and also covers rent and issues of wind farm
operation, maintenance and decommissioning.

In April 2001, following the pre-qualification process, 18 companies were awarded

agreements for leases by the Crown Estate (CE) in the first round of offshore wind farm
sites on the UK seabed. Under the agreements, the companies were given a three-year
period in which to obtain the necessary consents for a lease to be granted by the CE.

Developments had to comply with a number of conditions:

• Sites had to be within the 12-nautical-mile territorial limit around the UK.

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• Sites had to be at least 10 kilometres apart.

• Sites had to have a minimum generating capacity of 20 megawatts.
• Sites were restricted to a maximum of 30 turbines.

Of the 18 sites, five were combined into two and one was withdrawn, so that 14
remained. Of these, there are now three in operation, North Hoyle, Scroby Sands and
Kentish Flats, with Barrow under going commissioning, and Burbo Bank in construction.
The remaining are either in the consenting and approval process or are out to tender.

As such there is a limited experience base of the process of design and implementation,
but a fairly significant experience base of the problems associated with the preliminary
proceedings to approval, which should enable future costs to be reduced. This area is
examined in more detail in Appendix 1 of this report, which looks at the feedback from
the Round 1 developments.

To date, developers have had a challenge to provide a commercially viable solution in

an environment where there are constraints on supply due to:

• Raw materials
• Turbine availability
• Cable demand

with consequential significant increases in cost.

However, installed offshore wind capacity is anticipated to rise significantly over the next
few years as the larger Round 2 and other large European projects obtain consent.
Figure 7 below shows that by 2030 the EWEA target for installed offshore capacity is
150,000 MW.

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Figure 7: Source: Europe’s Energy Crisis – The No Fuel Solutions. (Ref #7)

3.2.3 Round 2 and Round 3 Projects

In July 2003 the Secretary of State for Trade and Industry asked the Crown Estate (CE)
to invite developers to bid for site option agreements in the second offshore wind farm
round. Arrangements for Round 2 were designed to facilitate development in three
strategic areas in territorial waters and in the Renewable Energy Zone on a much more
ambitious and larger scale than in the first round in 2001 in water between 8-13km
offshore, some of which would be outside territorial waters.

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Figure 8: Location of Round 2 Developments

Bids for site options were assessed against a range of criteria, including financial
standing, offshore development expertise and wind turbine expertise, and against the
constraints set by the Strategic Environmental Assessment (SEA). On 18 December
2003, the CE offered 12 companies/consortia options for 15 site Agreements for Lease
spread across each of the three strategic areas.

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Location Maximum capacity Developer

(MW)
Docking Shoal 500 Centrica
Race Bank 500 Centrica
Sheringham 315 Ecoventures/Hydro/SLP
Humber 300 Humber Wind
Triton Knoll 1,200 npower renewables
Lincs 250 Centrica
Westermost Rough 240 Total
Dudgeon East 300 Warwick Energy
Greater Gabbard 500 Airtricity/Fluor
Gunfleet Sands II 64 GE Energy
London Array 1,000 Energi E2-Farm Energy/Shell/ E.ON UK
Renewables
Thanet 300 Warwick Energy
Walney 450 DONG
Gwynt y Mor 750 npower renewables
West Duddon 500 ScottishPower
TOTAL 7,169
Table 3: Details of Round 2 Offshore Wind Farms (Ref #8)

Developers were strongly advised to take into account the advice given in the SEA
Environmental Report, including the possible impact on fishing, navigation and other
users of the sea. They were also informed of the need for consents from the relevant
statutory consenting authorities before these projects could proceed.

The CE Round 2 Agreements for Lease grant developers a development option for
seven years. During the seven years, the developers have to obtain the relevant
statutory consents. Once the necessary statutory consents are in place, developers will
be able to convert their Agreements for Lease into full leases.

Target for the commencement of the first Round 2 projects is as early as 2007 and it is
anticipated that costs for implementation will be upto 20% less than for the Round 1
projects on a MW installed basis, reflecting the learning, R&D and other factors since
Round 1.

It is hoped that Round 3, yet to be defined in location, will provide further impetus to
achieve government targets and will reflect R&D and industry learning benefits tending
towards similar costs to the current onshore market.

3.3 Factors affecting the cost of Onshore and Offshore wind

Installation
Offshore installation requires heavy lift vessels (HLV), which are not only expensive, but
need to be booked out well in advance of requirement. Offshore installation also suffers
from significant weather risk with most developers agreeing that they anticipate between
20% and 25% downtime during any phase. The onshore installation does not suffer from
weather downtime to the same degree; a crane spread is all that is required.

Wind Speed
One major advantage offered by offshore wind is that wind speeds are generally higher
and less prone to fluctuation than onshore wind sites. This gives offshore wind a

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significant advantage in terms of energy productivity. The power available from the
wind is a function of the cube of the wind speed (Ref #9). Therefore if the wind blows at
twice the speed, its energy content will increase eight fold. Onshore wind farm sites are
affected by topography, which reduces the wind speed on land, not an issue offshore.

WTGS

Offshore wind turbines are more expensive (circa 20 per cent), as they need additional
protection against salt spray and are required to be engineered for an offshore
environment where greater reliability and reduced operational costs are a pre-requisite.
In particular, salt spray protection takes various forms, including pressurised nacelles to
ensure that electronic equipment is protected.

Currently, the need to increase the tip speed is seen as an important task for turbine
manufacturers. However, these developments may be restricted in onshore application
as increased tip speed leads to increased noise levels, which are carefully monitored
onshore. Offshore, there is less concern over noise (Ref #10).

Foundation

There are major differences in the foundation requirements between onshore and
offshore. Onshore foundation loads are derived from wind load on a tower where the
height is determined by the size of the blades. In an offshore structure, the foundation
loads are derived from the wind load on the WTG plus the hydrodynamic loading i.e.
wave and current on the tower subsea on a tower height which is determined by blade
length, wave height and water depth.

Consequently, both horizontal load and overturning moment are far greater for an
offshore foundation than for an onshore foundation.

Access to an onshore foundation area is straightforward and allows excavation as

required and concrete raft or piled foundation to be easily installed. In an offshore
location, there is no ready access subsea and foundations, where gravity based, suction
pile or traditional pile has to be installed from a vessel using sophisticated and costly
equipment. As developments are sited further offshore, deeper waters and harsher
environments are encountered increasing the risk of downtime and transportation time
to site during installation of foundations which in themselves will be more extensive.

Due to the loads imposed, the size of the foundation offshore is far greater than an
onshore one.

It is difficult to give accurate comparison of cost between onshore and offshore

foundations since this is primarily so dependant on soil type, water depth etc, but it is
considered that the cost of an offshore foundation will be at least two and a half times
the cost of an onshore one.

Typically, for a 3.6MW WTG onshore tower this may be in the order of circa £400K, for
an offshore more than circa £1M

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3.4 Cost comparison – onshore/offshore

The CAPEX for an onshore wind farm is significantly less than for an offshore farm,
primarily due to the differences in the forces that the structure has to resist, the size of
the structure and the logistics associated with the installation of the towers.

OPEX is also significantly more expensive for offshore installations as access to the
wind farm is dependent on the availability of a vessel and the weather. If any sizable
equipment needs changing out, then the HLV will need to be mobilised again. Onshore,
access to the wind farm is not a problem and equipment change out can be more easily
arranged.

The cost of offshore foundations, installation and construction costs, and grid connection
costs are usually significantly more expensive for offshore applications than for onshore
applications. An indicative representation of the cost structure of onshore and offshore is
shown in Figure 9, below. Percentages costs will vary depending upon the project but it
is clear that there is a significant difference in the capital assets involved between
onshore and offshore.

Figure 9: Differences in Installed Costs Between Onshore (Ref #11) and Offshore Wind Farms

Overall, the impact of long-term industry maturity has been seen in the onshore wind
industry and will be seen in the offshore industry so long as there is impetus to maintain
momentum to learn, research and develop industry knowledge. The graph below shows
historical costs for onshore and postulates the offshore wind farm costs.

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Figure 10: Historical Costs for Onshore and Offshore Wind Energy (Ref #12)

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4.0 REVIEW OF INSTALLATION LIMITATIONS

The promise of large-scale offshore work has encouraged the offshore service industry
to develop a number of installation and maintenance vessels. A2SEA, a major
installation contractor of offshore wind farms, will be launching a new larger ship in 2008
- the M/V Sea Installer.

The Jumping Jack, a cable jack-up barge with four expandable legs and fitted with a
1200 tonne crane, is suitable for hammering in foundations as well as installing turbines,
a job it performed at the Arklow Bank project.

The Marine Projects International vessel, The Resolution, has six expandable legs, can
operate in depths of up to 35 metres and is suitable for installing foundations and
turbines. Its latest contract has been on the UK Barrow project.

Another vessel, the self-propelled barge HLV-Svanen, owned by Ballast Nedam,

comprises two interconnected catamaran type hulls. Its superstructure is capable of
hoisting up to 8700 tonnes, with 75 metres free lifting space. This is enough to be able
to install complete offshore wind turbines with rotor diameters in the range of 130-140
metres (Ref #13).

However, given the number of planned wind farms both in the UK and worldwide, there
is still expected to be a deficit in available vessels if all the planned wind farms go
ahead. The ode report Offshore Wind Farm Installation Vessel Capability Study (Ref
#14), which was carried out for the DTI, identifies that from 2008 vessel availability could
be a significant problem for the UK. It is noted that with the UK analysed independently
from Europe, then sufficient capacity should exist for foundation and WTG installation.
However, the impact of the developing market offshore Europe and particularly in
Germany is anticipated to be significant.

It is also stated that with the intention for Round 2 and beyond to be located further
offshore and in deeper water, the number of vessels able to operate in these depths are
severely limited. Also, as distance offshore increases the installation times will be
affected by the greater travelling time from the holding port to the site.

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5.0 REVIEW OF DECOMMISSIONING REQUIREMENTS

Provisions for the decommissioning of offshore renewable energy installations including

offshore wind farms are provided in the Energy Act 2004. These requirements are
applicable to those Round 1 developments yet to obtain consent and all Round 2
developments. Consented Round 1 developments are not subject to these
requirements, but must adhere to the decommissioning obligations (reinstatement of the
site) included in their lease contract with the Crown Estate and in the conditions
attached to the consent received from the Government.

The Government currently has a consultation document out “Decommissioning Offshore

Renewable Energy Installations – Consultation on Guidance Relating to the Statutory
Decommissioning Scheme for Offshore Renewable Energy Installations in the Energy
Act 2004.” (Ref #15)

The main points from the Energy Act 2004 include the need for approval of a
decommissioning programme prior to offshore installation. The Secretary of State can
demand the developer to submit a costed programme as soon as consent is awarded.
This programme must identify that the developer (or responsible person) has allocated
and safeguarded sufficient funds to carry out the full decommissioning programme.

As the programme needs to be developed and approved well in advance of any actual
decommissioning work, it needs to be flexible enough to adapt to any future industry or
regulatory changes. Either the Secretary of State or developer can amend the
programme, albeit with initial proposal to the other party for approval.

Offshore decommissioning relates to removal of the superstructure (i.e. blades, nacelle,

towers and transition piece), foundation, scour protection and any offshore cables.

Removal of the superstructure is fairly straightforward although a heavy lift vessel and
transport vessel or barge would be required on site.

Driven monopiles are most often used as foundations for offshore wind farms. These are
usually cut below the mudline. Oil and gas installations usually stipulate that they need
to be cut a minimum of 3 metres below the seabed. This can be achieved by use of a
jetting tool or mechanical cutter. However, the DTI decommissioning consultation
document recommends that the entire structure should be removed.

Removal of the entire foundation from the seabed is likely to be extremely costly due to
the forces that are needed to overcome the skin friction of a driven pile that had been in
place for some years. If this is to be a pre-requisite then the option of using suction piles
may be more appropriate for foundations. Suction piles benefit from the fact that they
can be easily decommissioned by pumping air into the pile to overcome the pressure
differential.

As wind farms move further offshore into deeper water, the need to remove
infrastructure completely to avoid navigation issues reduces.

The removal of the scour protection can be achieved by dredging or lifting. However,
removal of scour protection may be questionable as its removal will lead to significant
seabed disturbance and release of particulate matter and other contaminates that could
have an impact on the ecology of the area.

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The offshore cables could be left buried, with just the ends cut depending on the
requirements. If this were the case, then costs would be negligible. If however, the entire
cable were required to be removed then removal costs would be similar to installation
costs. Again, it is inferred in the DTI consultation document that the entire cable should
be removed from the seabed.

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6.0 FUTURE COST OF WIND GENERATION

6.1 CAPEX

Since 1990, global wind energy capacity has been doubling every three years, along
with a corresponding fall in the cost of wind turbines (measured per kWe of output) by
about 15 per cent for each doubling of global capacity. This decline in cost has been
brought about by a number of factors, the two most dominant being the trend towards
larger machines, and significant improvements in energy productivity.

The global growth in wind capacity slowed in 2004, with the annual increase falling to 20
per cent, although this increased to approximately 40% during 2005. Nonetheless, the
downward trend in prices for wind-generated electricity looks set to continue for the
foreseeable future.

The study identified the primary influence in the future cost trend for OWF’s to be the
cost of raw materials, in particular steel since the turbine, foundation, ancillaries are all
essentially made from steel. The turbine, which has circa 90% steel, whilst open to
price fluctuations due to trend in market forces, design premiums etc will still be primarily
open to increase due to the cost of raw materials.

On the worldwide market therefore every opportunity must be made to secure

these raw materials early on.

It is clear however that the cost of raw materials at the time of development are driven
by supply and demand and cannot be readily influenced. However the efficiency/cost of
turbines, blades, foundation configuration, installation methods and reliability are by
industry investment in R&D and industry learning and will also significantly impact the
CAPEX/OPEX costs. It is therefore in this area that focus is required.

The future price of WTG’s will decline as time progresses and as research and
development and industry learning gains are realised. It is believed that with
appropriate investment and financial support that the cost of turbines will drop
significantly to 2020. The turbine cost represents anywhere from 35-50% of the project
cost and so these gains hold the key to the future financial viability of the industry.

It is expected that offshore costs will fall faster than onshore costs, as this industry is
newer, and more benefit will accrue as the industry gains more experience in this sector.
Generation costs are also expected to fall a little faster as the larger machines capture
higher wind speeds.

The ode OWF Cost Model, developed as part of this study, allows the user to estimate
the future costs of wind generation for OWF projects starting from 2006-2020. This
estimation is based on a number of trends devised from the OWF market research
conducted by ode. A number of these trends, such as Copper Cost Steel Cost and
Supply and Demand (up to year 2012) inflate the OWF costs. Trends such as Research
& Development, Learning Curves, Turbine cost and Supply and Demand (from year
2012) reduce the OWF costs, although there is expected to be an increase in costs over
the next few years.

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The graph below shows the CAPEX behaviour from 2006 to 2020 of a typical 108MW
(90x3.6MW) OWF project obtained from the cost model. The results exclude inflation
and therefore the graph shows the Net Present Values (NPV)

108MW OWF CAPEX Variation

110%

100%

90%
CAPEX Variation (%)

80%

70%

60%

50%
2004 2006 2008 2010 2012 2014 2016 2018 2020 2022
Year

Chart 1: 108MW OWF CAPEX Variation (2006-2020)

As it can be seen from the graph above the CAPEX cost rises until 2010 and from then
onwards decreases by 30% until the year 2018. The main reasons for the reduction are
the R&D, Learning Curves, which is proportional to the maturity of the industry, and
Supply and Demand for the Turbines, which decreases with time as Developers will opt
for higher capacity WTGS in the future. Those trends surpass the effects of cost of
Steel, Copper and Supply and Demand rising by 47%, 19% and 2% respectively by year
2020.

Therefore, continuous investment in R&D will drive the OWF costs down and this, in
turn, will make the OWF industry more appealing to the investors, which will result in
more investment in developing new OWFs. As the industry continues to grow and the
total OWF installed capacity increases this will increase the learning gains, which are
predicted to decrease the OWF costs by 10% for every doubling in global capacity (Ref
#16).

The main cost component of an OWF is the WTGS, which has a 35-45% slice on a
OWF CAPEX pie chart. The cost of WTGS is mainly driven by cost of materials and
technology and therefore is highly influenced by R&D activities.

Installation costs represent the second major cost of an OWF development and can
represent up to 25% of the total CAPEX cost. This cost is highly dependent on the
maturity of the Industry as more OWF are built there is higher learning rate.

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6.2 OPEX

Currently the OPEX cost of maintaining an offshore wind farm are estimated to be in the
range of 23% of the CAPEX cost, spread over the lifetime of the farm with initial costs
being low due to warranty and final costs being higher as the farm comes to its life end
and maintainability and reliability issues increase (Ref #17). Given the limited
operational life of all offshore wind farms to date, this value is highly open to discussion.
This however, does not take account of the reduction in operational costs due to the
ability of operators to reduce on these costs through ingenuity, careful planning, R&D
and industry learning. When these are taken into account the NPV percentage for
OPEX will be less than the 23% perceived at this time.

For a development commencing in the future, not only will the CAPEX cost of that
development be less, but the OPEX costs will reduce from the current 23%

The chart below gives an indication of the split of the costs associated with
operating the farm based on 2-vessel
availability.

In the future, as turbine technology develops

to provide greater reliability, gearbox and
generator O&M costs will reduce partially
due to reduced use of vessels. Blade
technology is also progressing to provide
greater availability with varying wind speeds.
However, conversely, as wind farms are
sited further offshore, vessel time will
increase for each visit due to greater
transport time and potentially greater risk of
weather downtime.

For current Round 1 WTG, operational costs are in the range £1.1-£1.3M per annum for
a 30 turbine development.

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7.0 TIMING OF FUTURE OFFSHORE DEPLOYMENT

Critical to the success of offshore wind is ensuring that funding is released at the right
time to allow R&D and learning to have a positive impact in reducing costs. When
running the ode cost model for a 100 turbine wind farm, with 3% inflation and assuming
best cases for the trends, funding is required now in order to realize the modeled benefit
in circa 2010. Costs per MW installed reduce from £1.56M to £1.44M between 2006
and 2010. From 2010 to 2020 these costs fall to £1.20M/MW installed. However, this
scenario is driven by the benefits of R&D and learning which need both investment and
positive steps by Government and industry in order to be realised.

The industry is currently sluggish. It is known that there is potential to develop a

significant energy source that would contribute to support the security of supply issues
currently facing the UK. Offshore wind costs will not reduce without additional funding
and expenditure into R&D. It is only with significant reductions in component costs that
installed costs will reduce. Procured costs account for approximately 70% of CAPEX
and of that percentage; turbines make up 65% of it. Therefore, the most significant
savings can be realised by investing in alternative, cheaper materials for turbines and by
increasing the output from turbine manufacturers.

7.1 Research and development

The table below is extracted from the ode cost model and signifies the R&D trends in
the model. Cumulative project costs are based on estimated installed UK capacity (MW)
multiplied by £1.4M. The industry is assumed to be 100% mature after 50 years from
1991 when the offshore industry first started. This implies an industry maturity of circa
75% mature by 2020. It is assumed that R&D investment will be inversely proportional
to the industry maturity, i.e. by 2042 R&D investment will be zero. The R&D investment
is estimated at 4% of cost.

It highlights the fact that investment in the industry is greatly needed now. The most
significant investment is identified as being required in 2009/10. However, the gains
from this investment will not be realised until two or three years down the line.
Therefore, by bringing this investment forward to 2006/07 it would allow significant cost
reducing effort to be implemented in time to impact in 2009/10. This is the timeframe
when much of the industry anticipates a surge in growth.

It is estimated that £600M is required to be spent on R&D in the next five years and a
further £1.7B by 2020. The more R&D investment that can be achieved now, the
greater the possibility of reaping the reductions from it early. These estimates are based
on there being a comparable allowance to R&D compared with the overall CAPEX
investment in the industry.

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%age
Cumulative
Assumed £M cost of CAPEX
Year Capacity £M (cum)
maturity R&D cum saving
(MW)
appl yr

2006 891 1247 1% £ 49 11.6%

2007 1268.4 1776 2% £ 70 8.2%
2008 2844.2 3982 4% £ 155 2.4%
2009 5176 7246 7% £ 276 0.7%
2010 10510.5 14715 15% £ 531 -0.5%
2011 14055.8 19678 20% £ 691 1.6%
2012 19425.9 27196 27% £ 910 3.1%
2013 22204.4 31086 31% £ 1,017 7.0%
2014 30954.1 43336 43% £ 1,295 6.4%
2015 35651.9 49913 50% £ 1,427 7.4%
2016 39115.9 54762 55% £ 1,515 7.5%
2017 47198.9 66078 66% £ 1,669 7.6%
2018 47198.9 66078 66% £ 1,669 8.2%
2019 51698.9 72378 72% £ 1,739 7.8%
2020 55698.9 77978 78% £ 1,789 7.6%

Table 4: UK R&D Investment Estimate

The negative value is spurious but indicates the potential that more could be spent on
R&D than would be gained from R&D benefits three years prior to that year. However
this is considered insignificant in the overall cost model.

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8.0 ODE OWF COST MODEL

8.1 Introduction
The cost model has been built to give a reflection of the cost of a development if it were
to commence at any time up to 2020. The model has been formulated in Microsoft Excel
and has been constructed in a manner such that it is versatile to allow the user to
calibrate it as required.

The model is constructed around a typical level 2 development plan and contains all key
activities.

OWF projected costs were based on a number of essential trends, estimates and known
costs gathered, digested and extrapolated, from an extensive OWF Industry research
carried out by ode. Each of these trends has impact on the cost of the wind farm
development.

No allowance is made for the benefit of Capital Grant.

The trends identified and modelled are supply & demand, benefit of learning, research &
development, turbine cost and cost of commodities, copper and steel.

For each of these trends there is a lower and upper trend-line (trend-line A and C,
respectively) and a notional best guess trend (trend-line B). To allow the user to
understand dominant trends and the impact of the trend, the user can select from either
trend-line A, B or C for each of trends.

The model produces detailed CAPEX costs and a Cost Profile throughout the OWF life
for a specific project starting year, chosen by the user.

The model is composed of four main sheets plus the trend sheets. The four main sheets
are:

Ø Input, which also includes Results

Ø Schedule and Costs
Ø Accuracy
Ø Structural Weight

All sheets are protected so that no changes or additions can be made by the user with
the exception of the input cells, highlighted in yellow.

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8.2 Fixed Parameters

Below is a list of the fixed parameters used in the costing analysis. These are
changeable by the user if required.

Fixed Parameters 2006

Start Date 01/01/06
Steel Fabrication Costs £1,500 Tonne
Cable Costs £270,000 km
Cable Laying Costs (Offshore) £195,000 km
Cable Laying Costs (Onshore) £125,000 km
Main Installation Vessel Day Rate £75,000 Per Day
Secondary Installation Vessel Day Rate £45,000 Per Day
Met Mast Installed Cost £1,800,000 Each
Man Hour Cost £60 Per Hour
Mob/De-Mob £240,000 Rate
No days to transport each Foundation & WTG 0.5 Per Item
No of days to install foundations 1.5 Per Item
No of days to install transition piece 1.5 Per Item
No of days to install scour protection 1.5 Per Item
No of days to install turbine 1.5 Per Item
No of days to terminate cables in foundation 3.0 Per Item
Downtime 25.00% %
Cable Lay Downtime 10.00% %
Decommissioning Cost £ 275,000.00 Per Turbine
Availability (Load Factor) 35.0% %

Table 5: Fixed Parameters in ode Offshore Wind Farm Cost Model

Load Factor

Load factor is an essential parameter in the returns expected from WTGs and relates
directly to the topographical factors noted above. Information from the 2006 Digest of
UK Energy Statistics (DUKES) indicate that load factors for onshore wind have
averaged 26.7% over the last five years (Ref #18). Load factors for offshore wind from
the same source average 25.7%, although this is only based on two years worth of data.

A review of available literature indicates that a typical load factor assumed for onshore
wind farms is 30% and for offshore wind farms, 35% is normal. The 5% difference
between offshore/onshore is considered significant. Based on the above, the cost
model generated by ode utilises a 35% load factor. Load factors are further examined in
the sensitivity analysis in Appendix 3.
8.3 Input and Results Sheet

This sheet contains a User Input Section where the user defines the characteristics of
the OWF, inflation and trends, a Results Section, where the results are shown, and a
section with Trend Graphs demonstrating the variation of costs with trends to help the
user when choosing from the trend-lines.

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8.3.1 User Input section

In this sheet the characteristics of the OWF are provided by the user:-

Ø Number of Turbines – the total number of turbines planned for the wind farm
Ø Distance of export cable to shore – total length in km of the export cable to
shore.
Ø Distance to Port/Holding bay – distance from OWF to the Port or Holding bay, to
be used to estimate transportation times and subsequently its costs
Ø Length of inter-array cables – total length in km of the inter-array cables
Ø Length of onshore cable – total length in km of the export cable from shore to the
grid connection point
Ø Life of Field – estimated life of OWF in years
Ø Capacity of Turbine – Turbine capacity in MW
Ø Total Nr of Onshore Substation – Total number of onshore substations to be
used in the OWF
Ø Total Nr of Offshore Substation – Total number of offshore substations to be
used in the OWF
Ø Water Depth – Average wind farm water depth in metres, this will be used to
estimate the foundations characteristics
Ø Number of Met Masts – Total number of Met Masts to be used in the OWF
Ø Cost of Steel – Procured cost in pound sterling per tonne of steel
Ø Scour Depth – Depth of scour used for the piles

The inflation value to be used in the model can be chosen from three options, 0% for
NPV results, 3% common inflation rate, and user input value which can be chosen by
the user. The inflation value chosen will be used by the model on the projection of costs
from 2006 – 2020. It must be remembered that this inflation cost is not a UK inflation
rate but a normalised inflation rate relative to where the cost arises.

These trends were forecasted up to the year 2020 and beyond for activities such as
Decommissioning and O&M as these activities take place in the last phases of an OWF
life.

The methods adopted for the derivation of trend lines are explained below.

8.3.2 Results Section

This section contains the results for the project in accordance with OWF characteristics
specified by the user under the User Input section. The first section of the results shows
some of the key results of the OWF including:

Ø Project Duration in years

Ø OWF Total output in MWh
Ø Total CO2 Reduction, if the same output was generated by a typical coal-fired
plant and using a factor of 860g of CO2/kWh obtain from the BWEA website
(http://www.bwea.com/edu/calcs.html)
Ø Weight of Foundation, obtained from the Structural Weight sheet, explained in
Appendix 2
Ø CAPEX, including an accuracy factor and CAPEX range
Ø OPEX

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The second section of the results shows variation of costs for CAPEX, OPEX, Cost per
MW Installed, Cost per MWh and Cost per Tonne of CO2. The variation of costs, which
range from 2006 to 2020, are in the form of graphs and are accessed by clicking on the
respective button.

The third section of the results is entitled CAPEX costs and requests the user to input a
project start-up year, to be chosen from 2006-2020, for cost analyses. Once this is done
the model produces a range of CAPEX costs for the project starting at the chosen year.
Apart from the CAPEX costs the model also provides a cost for decommissioning and a
normalised Grid Connection cost. A cost profile is also produced in the form of a graph,
which is accessed by clicking on the ”Cost Profile” button, and this provides total costs
per year ranging from the start-up year up to the de-commissioning year, this excludes
the Grid connection costs which is only applicable if the project is discontinued after the
Grid upgrade has been agreed.
8.4 Schedule and Costs

The first action on this sheet is to derive a baseline cost in accordance with the User
Input Data and Model Database. In order to facilitate this and since many of the costs of
the activities are duration dependent the “Schedule and Costs” sheet produces an
indicative level 2 plan for the OWF given certain parameters specified by the user on the
input sheet.

The Level 2 Project plan for a typical project can be seen overleaf.

The sheet then calculates costs for each activity based on a criterion, which has been
identified from the study work.

In order to extrapolate these costs for future years the relevance of each activity to each
of the trends is assigned. For example, it is reasonable to assign 80-90% of the steel
trend to the turbine price on the basis that 80-90% of the turbine is based on steel.

These costs are then extended in accordance with the specified trends and inflation
value. Since the model covers estimation of costs for project starting from 2006 to 2020,
it was necessary to project the costs of the activities beyond 2020, for certain activities
which take place during the last years of an OWF life, such as Decommissioning and
Operation & Management, which run throughout the project life, the costs were
extended until 2070.

The other calculations which take place in this sheet include Cost per MW, Cost per
MWh, Cost per Tonne of CO2 and Cost profile in which the costs are aligned according
to the probable year the monies will be required to be spent.

Within the calculations it has been assumed that the costs associated with connection to
the grid are excluded from the CAPEX cost. This is excluded from CAPEX on the basis
that it is not a generic cost, rather it is site specific and very variable. However, a
notional figure has been provided based on a normalised estimate of the costs of
connection to the grid as provided by ECONNECT.

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Table 6: Explanation of Cost and Schedule Assumptions in ode Offshore Wind Farm Cost Model

Activity Cost Cost Basis Schedule Schedule Basis

Project Management - -
Calculated - Based on project duration
~3% Calculated - Will run for full life
Project Management and estimates at ~3% of CAPEX for -
CAPEX of project
typical offshore wind farm.

Calculated – Based on
Calculated – Sum of component parts difference between start date of
Consenting Phase - -
below first item and end date of last
item
Obtain Lease Fixed - Value obtained from
Agreement in Principle £3,400,000 60 days Fixed - Estimated duration
confidential ode data.
with Crown Estate
Pre-planning Doc. to
£2,000 Fixed - Nominal cost 5 days Fixed - Estimated duration
MOD and CAA
Scoping Document - Fixed - Team of 5 @ £50/hr for 80 Fixed - Duration from
£150,000 80 days
Forms part of ES days confidential ode source
Assess and Negotiate Fixed – Team of 4 @ £50/hr for 70 Fixed - Duration from
£100,000 70 days
Grid Connection days confidential ode source
Calculated – This assumes
Calculated – This assumes that as the that as the size of the Project
size of the Project increases there is increases there is an additional
an additional effort required for the ES, time required for the ES,
Environmental
- proportional to the square root of the - proportional to the square root
Statement
increase in the size of the field. The of the increase in the size of
baseline has been assumed as £350K the field. The baseline has
for 30 turbines. been assumed as 250 days for
30 turbines.
Calculated – This assumes
Calculated – This assumes that as the that as the size of the Project
size of the Project increases there is increases there is an additional
an additional effort required for this time required for this activity,
Contact Statutory
- activity proportional to the square root - proportional to the square root
Consultees
of the increase in the size of the field. of the increase in the size of
The baseline has been assumed as the field. The baseline has
£90K for 30 turbines. been assumed as 250 days for
30 turbines.
Calculated – This assumes
Calculated – This assumes that as the that as the size of the Project
size of the Project increases there is increases there is an additional
an additional effort required for this time required for this activity,
Contact Non-statutory
- activity proportional to the square root - proportional to the square root
Consultees
of the increase in the size of the field. of the increase in the size of
The baseline has been assumed as the field. The baseline has
£45K for 30 turbines. been assumed as 250 days for
30 turbines.
Preliminary
Fixed - From Titan Environmental
Geotechnical/physical £100,000 15 days Fixed - Estimated duration
Surveys Ltd webpage
Surveys
Preliminary Bathymetric Fixed - From Titan Environmental
£30,000 30 days Fixed - Estimated duration
Survey Surveys Ltd webpage
Calculated - Based on number of met
masts with fixed cost of £1.8M per
Procure & Install Met installed mast. Fixed - Duration from
- 120 days
Mast From internet - SLP won £3.2M confidential ode source
contract for EPIC of 2 met masts at
Shell Flat and Docking Shoal & Race

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Bank
FEED/Development of Fixed - Cost of FEED is taken from Fixed - Duration from
£750,000 250 days
ITT confidential ode source. confidential ode source
Fixed - Cost is taken from confidential Fixed - Duration from
Compilation Phase £20,000 30 days
ode source. confidential ode source
Fixed - Cost is taken from confidential Fixed - Duration from
Consent Review £25,000 250 days
ode source. confidential ode source
Fixed - Milestone, therefore
Consent Awarded £0 Fixed – Zero cost 0 days
zero duration

Calculated – Based on
Calculated – Sum of component parts difference between start date of
Post Consent Phase - -
below first item and end date of last
item
Calculated – Based on number
of turbines and length of export
Calculated – This assumes that the
cables to shore. Duration
Detailed Geotechnical baseline cost i.e. £1.2M for 30 turbines
assumes two days per
Surveys – CPT, - at 25km offshore, will be increased by -
borehole/CPT at each WTG
Boreholes the square root of the relative increase
location and 2 km per day for
of those parameters.
survey/boreholes/CPT along
cable route.
Calculated – Assumed to take
Detailed Swath
£0 Fixed – Zero cost as included Above - one third of the time of the
Bathymetry Surveys
geotechnical survey

Calculated – Based on
Calculated – Sum of component parts difference between start date of
Engineering Phase -
below first item and end date of last
item
Fixed – Assumed to be
rd
Appoint 3 Party/Clients required on part time basis for
£50,000 Fixed – Nominal cost estimated 700 days
Engineer/ Verification two years which will cover
component manufacture phase.

Calculated – Based on
Calculated – Sum of component parts difference between start date of
Procurement Phase - -
below first item and end date of last
item
Calculated – Based on trend line Fixed - Assumed duration,
PO for WTG (WTGS +
- based on current market costs of 600 days based on current lead times for
Blades + Tower)
turbine sizes turbines
Calculated – Formula based on Fixed - Assumed duration,
PO for Foundations &
- number of turbines (thus foundations), 180 days based on current lead times for
Transition Piece
steel costs and foundation weight foundations
Fixed - Cost is taken from confidential Fixed - Assumed duration,
PO for SCADA £1,000,000 270 days based on current lead-time for
ode source.
SCADA systems.
Calculated – Based on £195/m
Fixed - Assumed duration,
PO for Cables (onshore material cost (information garnered 300 days
- based on current lead-time for
and offshore) from developers) and total onshore
cables.
and offshore cable lengths.
Calculated – Based on number of
PO for Onshore substations required multiplied by a Fixed - Durations based on
- 300 days
Substation fixed cost of £3M per substation (this is information from developers.
based on information from developers).
Calculated – Based on number of
substations required multiplied by a
PO for Offshore Fixed - Durations based on
- fixed cost of £7.5M per substation (this 550 days
Substation information from developers.
is based on information from
developers).

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Calculated – Based on
Calculated – Sum of component parts difference between start date of
Transport & Lay Down - -
below first item and end date of last
item
Transport Foundations/
£0 Fixed – Cost assumed to be included
Appurtenances to Lay 30 days Fixed - Estimated duration
in PO’s.
Down Area
Transport Cables to Lay Fixed – Cost assumed to be included
£0 30 days Fixed - Estimated duration
Down Area in PO’s.
Transport WTG to Lay Fixed – Cost assumed to be included
£0 30 days Fixed - Estimated duration
Down Area in PO’s.

Calculated – Based on
Calculated – Sum of main headings difference between start date of
Installation Phase - -
below. first item and end date of last
item

Foundations
Calculated – Based on
Calculated – Sum of component parts difference between start date of
- -
below first item and end date of last
item
Fixed - Cost is taken from confidential Fixed - Duration from
Mob Vessel £120,000 2 days
ode source. confidential ode source
Calculated – Number of foundations x Calculated – Number of
installation vessel day rate (£75K/day – foundations x number of days
taken from Ref #19) x number of days transport per foundation (0.5
Foundation transport - transport per foundation (0.5 - days/foundation – based on
days/foundation – based on assumed assumed boat speed and
boat speed and estimated distance estimated distance from shore)
from shore) + 25% weather downtime. + 25% weather downtime
Calculated – Number of
Calculated – Number of foundations x
foundations x number of days
installation vessel day rate (£75K/day –
to install foundation (1.5
taken from Ref #19) x number of days
Install Foundations (Q2 days/foundation – based on
- to install foundation (1.5 -
earliest) information from installation
days/foundation – based on
contractors) + 25% weather
information from installation
downtime
contractors) + 25% weather downtime.

Calculated – Number of
Calculated – Number of foundations x
foundations x number of days
secondary installation vessel day rate
to install foundation (1.5
(£45K/day – taken from Ref #19) x
days/foundation – based on
Install Scour Protection number of days to install scour
- protection (1.5 days/foundation – - information from ode
(Q2 earliest)
based on information from ode Installation Vessel Report
which states 1.5 months to
Installation Vessel Report) + 25%
install scour protection for 30
weather downtime.
turbine OWF) + 25% weather
downtime

Calculated – Number of
Calculated – Number of foundations x
foundations x number of days
installation vessel day rate (£75K/day –
to install foundation (1.5
taken from Ref #19) x number of days
Install Transition Piece, days/foundation – based on
- to install foundation (1.5 -
J-Tubes & ancillaries information from installation
days/foundation – based on
contractors) + 25% weather
information from installation
downtime
contractors) + 25% weather downtime.
Calculated – Based on
Calculated – Sum of component parts
Offshore Cables - - difference between start date of
below
first item and end date of last

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item
Calculated – Related to
Calculated – Distance of inter-array number of wind turbines.
Plough Inter-array cable x cable laying costs/2 (£195/m – Doubling the number of
- -
Cables based on information from developer) turbines will not double duration
+ 10% weather downtime. as calculation is to power 0.5.

Calculated – Distance of
Calculated – Distance of export cable export cable to shore x cable
Plough and Install to shore x cable laying costs (£195/m – laying rate (fixed at 1.5 days
- -
Export Cables based on information from developer) per km) + 10% weather
+ 10% weather downtime. downtime

Calculated – Number of
Calculated – Number of turbines x turbines x number of days to
number of days to terminate cables at terminate cables at each
Terminate Cables at
- each location (fixed at 3 days – based - location (fixed at 3 days –
Foundations
on information from developer) x based on information from
secondary installation vessel day rate. developer).

Shore End Pull In and Fixed – Zero cost as included in

£0 15 days Fixed – Estimated duration
Burial laying.
Fixed - Cost is taken from confidential Fixed - Duration from
Demob Vessel £120,000 2 days
ode source. confidential ode source
Calculated – Based on
Onshore
Calculated – Sum of component parts difference between start date of
Cables/Onshore - -
below first item and end date of last
Substation
item
Construct Onshore Fixed – Zero cost as assumed Fixed - Duration from
£0 180 days
Substation included in PO. confidential ode source
Calculated – Length of onshore cables
Calculated: Based on a pro-
x onshore cable laying costs (£125/m –
Lay Onshore Cables - - rata duration of 150 days for
based on information from developer)
10km onshore cable
+ 25% disruption downtime.
Calculated - £185K per MW of Fixed - Duration from
Tie-in to Network - capacity. Adapted from information 100 days
confidential ode source
from ECONNECT website.
Calculated – Based on
Calculated – Sum of component parts difference between start date of
Offshore Substation - -
below first item and end date of last
item
Fixed - Cost is taken from confidential Fixed - Duration from
Mob/Demob Vessel £240,000 2 days
ode source. confidential ode source
Calculated – Number of
Calculated – Number of days to install
substations x number of days
substation(s) x main installation vessel
Install Substation - - to install substation (fixed at 20
day rate (£75K/day – taken from Ref
days – information from
#19) + 25% weather downtime
developer)
Fixed - Duration from
Connect Cables £0 Fixed – Included in installation costs
confidential ode source
Calculated – Based on
Calculated – Sum of component parts difference between start date of
WTG - -
below first item and end date of last
item
Fixed - Cost is taken from confidential Fixed - Duration from
Mob Vessel £120,000 2 days
ode source. confidential ode source
Calculated – Number of WTGS x main
installation vessel day rate (£75K/day –
taken from Ref #19) x number of days
WTG Transport - transport per WTGS (0.5 days/WTGS - Calculated – Number of WTGS
– based on assumed boat speed and x number of days transport per
estimated distance from shore) + 25% WTGS (0.5 days/foundation –
weather downtime based on assumed boat speed

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and estimated distance from

shore) + 25% weather
downtime

Calculated – Number of WTGS x main

installation vessel day rate (£75K/day – Calculated – Number of WTGS
taken from Ref #19) x number of days x number of days to install each
Install WTG - -
to install each WTG (1.5 days/WTGS – WTG (1.5 days/WTGS – based
taken from Ref #14 and Ref #19) + on information from Ref # 14,
25% weather downtime Ref #19, and experience from
Round 1) + 25% weather
downtime.
Fixed - Cost is taken from confidential Fixed - Duration from
Demob Vessel £120,000 2 days
ode source. confidential ode source

Calculated – Based on
Testing & Calculated – Sum of component parts difference between start date of
- -
Commissioning below first item and end date of last
item
Commission Fixed - Duration from
Fixed – Zero cost as assumed to form
Onshore/Offshore £0 30 days
part of substation PO. confidential ode source
Substation
Test Transmission Fixed – Zero cost as assumed to form Fixed - Duration from
£0 60 days
Cables part of cable PO. confidential ode source
Calculated – This assumes that as the
size of the Project increases there is
an additional effort required for this Fixed - Duration from
Commission WTG - activity proportional to the square root 70 days
confidential ode source
of the increase in the size of the field.
The baseline has been assumed as
£2M for 30 turbines.
First Production from Fixed - Milestone, therefore
£0 Fixed – Zero cost 0 days
OWF zero duration

Fixed - Milestone, therefore

Other Costs £2,000,000 Fixed – Estimated contingency cost 0 days
zero duration

Calculated – Based on
Calculated – Sum of component parts difference between start date of
O&M - -
below, based on 23% over lifetime. first item and end date of last
item
O&M Activities Yr 0-5 This has been assumed as £1.3M per
Fixed – Initial 5 year period
(warranty) year for the first 5 years. – study data
Assuming a mean of £1.2M pa for
Calculated – Based on life of
O&M Activities Yr mid OPEX over the life of the field, this is
field and excludes initial and
range the remaining sum after the first and
last 5 year periods.
last 5 years.
This has been assumed as £1.5M per
O&M Activities Yr last 5 Fixed – Initial 5 year period
year for the last 5 years

Decommissioning Calculated – Sum of below - Calculated – Copy from below

Calculated - Cost of decommissioning Calculated: This is assumed
per turbine (fixed at £275,000 – based as being directly proportional to
Decommissioning - on information from developers) x the number of turbines,
number of turbines + 25% weather prorated on 150 days for 30
downtime. turbines.

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8.5 Sheet – Trends

8.5.1 General

The choice and application of trends allow the user to identify the key drivers in cost. Of
course, it must be stressed that these “future” trends are very subjective. They may be
correct within a margin or may be completely the reverse of what could be guessed from
historical data. A Trend “B” represents ode’s best guess based on study work, whilst
trends “A” & “C” will represent what realistically “could” happen. It is important to note
that these represent GLOBAL trends. The trends are shown on the following sheets.

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Learning Curve Trend Lines

1.0
0.9
0.8
0.7
Variation

0.6
0.5
0.4
0.3
0.2
0.1
0.0
2005 2007 2009 2011 2013 2015 2017 2019
Year
Trend A Trend B Trend C

Supply & Dem and Trend Lines

1.4

1.3
Variation

1.2

1.1

0.9
2005 2007 2009 2011 2013 2015 2017 2019
Year
Trend A Trend B Trend C

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R&D Trend Lines

110%
100%
90%
80%
70%
Variation

60%
50%
40%
30%
20%
10%
0%
2005 2007 2009 2011 2013 2015 2017 2019
Year

Trend A Trend B Trend C

Steel Trend Lines

2.5

2
Variation

1.5

0.5

0
2004 2006 2008 2010 2012 2014 2016 2018 2020 2022
Year
Trend A Trend B Trend C

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Copper Trend Lines

4
Variation

0
2004 2006 2008 2010 2012 2014 2016 2018 2020 2022
Year

Trend A Trend B Trend C

Turbine Supply & Dem and Trend Lines

1.5
1.4
1.3
1.2
Variation

1.1
1
0.9
0.8
0.7
0.6
2005 2007 2009 2011 2013 2015 2017 2019
Year

Trend A Trend B Trend C

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8.6 Assumed Turbine cost

There was difficulty in determining definitive current turbine costs due to supplier and
developer confidentiality, however we were able to ascertain some values and these are
indicated below. In some cases, the costs of the turbines were found to be variable
between developers. Where varying costs for the same machine were obtained, an
average cost has been used. It should be noted that the costs in Table 5 relate only to
procurement costs for the turbines.

What is clear is the global tendency for a reduction in turbine cost. An increase in the
volume of production of an item generally results in a decrease in the unit cost. Even so,
the price of wind turbines has fallen faster than would be expected purely on the basis of
increasing volume production.

In 1991, it was predicted, based on an analysis of the labour and material costs to
produce wind turbines, that there would be an 8 per cent reduction in the cost per kW of
wind turbines for every doubling of capacity. In fact, the figure that was actually achieved
was a 15 per cent reduction for each doubling of capacity, nearly twice the estimate.

Part of this faster-than-expected fall has been the consequence of a move towards
larger machines. In 1992, the cheapest machine per kW was rated at 300kW. In 2005,
the cheapest machine per kW has a rating of 1,500kW (Ref #20). Currently, machines
larger than 1,500kW tend to be more expensive. This increase in machine size results in
fewer machines being needed for a site of a given output, which has consequent
savings in foundation costs, transport, electrical connections and operating costs.

For the purposes of the cost model, these values were trended for larger sizes of turbine
and to normalise current model prices. The accuracy of this data is felt to be +/-15%.
The trended costs are also seen on Table 7.

Assumed Turbine Cost

WTGS Capacity Cost Trended cost
2.0MW £1,500,000 £1,426,030
2.5MW £1,750,000 £1,836,945
3.0MW £2,000,000 £2,247,860
3.6MW £2,963,000 £2,740,958
4.0MW £3,250,000 £3,069,690
5.0MW £3,750,000 £3,891,520
Table 7: Assumed Turbine Cost

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Trended Turbine cost

£4,500,000
y = 2E+06Ln(x) - 255016
£4,000,000

£3,500,000

£3,000,000

£2,500,000

£2,000,000

£1,500,000

£1,000,000

£500,000

£0
2.0MW 3.0MW 4.0MW 5.0MW 6.0MW 7.0MW

Chart 2: Trended Turbine Cost

8.6.1 Steel

Steel is chosen as a trend because it represents a significant proportion of the make up

of an offshore wind farm. The nacelle is estimated to comprise of 90% steel. The
foundation is rolled steel plate. The transition piece is primarily composed of steel. The
cables contain a proportion of steel. Therefore, steel is a major constituent and any
fluctuations in raw material costs will impact on overall project costs.

Steel costs have been extrapolated from CRU data (Ref #21). CRUspi (CRU's Steel
Price Index) is formulated weekly from a weighted basket of steel industry prices in
steel's main markets. Products included are HR coil, CR coil, HDG sheet, rebar and
beams; regions included are North America, Europe and Asia.

This data has been plotted and then three trends have been established.

Ø Trend A is the lower boundary of cost. It assumes that steel costs will in fact
decrease over time. There are views that in the long term, steel cannot maintain
its current increase. The Trend A has been aligned with the Iron and Steel
Statistics Bureau at http://www.uksteel.org.uk/fact6.htm

Ø Trend B is the expected trend, extrapolating on historical from the CRU steel
price index.

Ø Trend C is based on the possibility that steel costs will in fact increase at a
greater rate than they have done.

As detailed above, these trends may differ significantly from actual future trends, but can
be used to give an indication of the effect on total project cost of a rise, fall or plateau in
steel prices.

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8.6.2 Copper

Cables incorporate a significant proportion of Copper. As cable lengths increase with

distance offshore, the trend in Copper costs becomes more important as any
fluctuations in material costs will impact on the overall development costs. Copper is
also used quite extensively in the nacelle.

Copper cost trends have been established from Kitco Base Metals (Ref #22). The five-
year historic costs ($/lb) have been graphed and extrapolated to show three trends of
expected costs of copper over time.

Ø Trend A represents the lower cost level. As for steel, it assumes that copper
prices will decrease over time.

Ø Trend B represents the anticipated trend of copper costs over time.

Ø Trend C represents the perceived upper limit of copper costs.

8.6.3 Learning Curves

As an industry develops, it ‘learns’ how to carry out operations more efficiently which
leads to a reduction in time and hence costs. Therefore, incorporation of a learning
curve trend was seen as critical.

The learning curve trends are based on information from the report; Learning Curves
and Changing Product Attributes: the Case of Wind Turbines, Louis Coulomb and
Karsten Neuhoff, Feb 2006 (Ref #23). This indicates that for every doubling of installed
global capacity, costs of wind turbines per installed capacity have fallen by 10.9%
(12.7% corrected).

Ø Trend A assumes a 25% decrease in the learning on Trend B

Ø Trend B assumes a 10% reduction in costs for every doubling of installed

European capacity. Dates of proposed installations have been taken from ode
report, Installation Vessel Capability Study.

Ø Trend C assumes a 25% increase in the learning on Trend B.

8.6.4 Supply & Demand

Supply & Demand trends have been based on the trend for installation vessels as
derived from the ode report, Installation Vessel Capability Study (Ref #14). It is clear
that another main driver for supply and demand is the availability of turbines. However,
it is considered that this is already considered separately under turbine cost.
Additionally, the supply and demand issues with respect to Steel and copper are already
separately covered.

The figures are based on the total number of perceived foundation and WTGS
installation operations for all planned European projects. This has then been factored
and a percent change year on year has been established.

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It is assumed that basing supply & demand on the installation requirements is sufficient
as it gives a quantitative basis for the trend line.

Ø Trend A assumes a 25% decrease in the supply/demand on Trend B

Ø Trend B is proportional to the number of installation operations.

Ø Trend C assumes a 25% increase in the supply/demand on Trend B

8.6.5 Research and development

It has been seen from other new industries that the challenge to push forward the
technological boundaries by the commissioning of research and development has been
a key parameter in the ability to reduce costs over time. The offshore wind industry has
its new challenges in this respect and this impact on future costs is therefore required to
be accounted for.

There will be numerous areas of focus in the industry, but those likely to have the
greatest financial impacts will be in the areas of: -

Ø Turbine development, gearbox design, blade design, and associated control

systems.

Ø Foundation design.

Ø Installation concepts, strategy, equipment and capabilities.

Ø Materials.

The trend has been built up on the following basis that: -

Ø Investment into R&D will be proportional to the value of projected annual overall
industry expenditure.

Ø The likelihood of investment will be proportional to the maturity of the industry.

Ø The success rate for investment will be 33% and the return rate on investment
will be 20 times.

Ø The benefit to the industry will not be captured until 3 years after investment.

The trends A & C assume a +/-25% variation on the resulting value.

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9.0 AREAS FOR FUTURE COST REDUCTIONS

The cost model clearly identifies that the only real areas for future cost reduction within
industry influence will be due to Research and Development and Learning gains. Other
potential gains as a consequence of commodities price reductions or supply and
demand reductions cannot be planned for or quantified and realistically any gains are
unlikely to occur.

9.1 Research and development

9.1.1 General

We are moving into larger projects, greater investment and greater risk. 70% of the
overall electricity cost is due to the initial investment, i.e. CAPEX, in an environment
where the unknowns of OPEX and revenue are unclear and where there is significant
risk on the CAPEX. The importance of continued and focused R&D is imperative to
allow continued growth of the industry.

Our prime objectives should be to: -

Ø Increase value and reduce uncertainties. Current prediction models reflect that
reduction in the uncertainty of Project by 15-20% will yield 5-10% reduction in
cost: Areas include better definition of wind speed to be expected.
Ø Optimisation of turbines, enhancing turbine technology, direct drives etc.,
Ø New materials. Better materials;
Ø New foundation concepts
Ø Finding ways to integrate the power into the network, ways to increase reliability
Ø Enable large-scale tools for transmission and control of the power supply to the
grid, (development of HVDC and storage, ability to correct grid deficiencies, e.g.
voltage drops and flicker. And grid stability)
Ø Minimize environmental impacts - determine suitable places where there is
acceptance of impacts on the environment. This is difficult as currently there is a
pronounced concern by some groups about the locations of OWF.

We need to focus on those big areas of cost first to reap the benefits.

Through our survey of completed UK projects and comparison of this data with
published data we find great deviation in the perceived costs of the various Project
phases. This is likely to be due to the way in which the costs are broken down, contract
strategy and differences in physical factors such as distance to shore, ground conditions
and problems during installation.

Below is an estimate of cost breakdown. In reality this is not definitive, but indicative.
Each Project will be different depending on the primary factors of distance to shore,
water depth, soil type, turbine size, and rotor diameter.

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Offshore Wind - ~£1.6M/MW Installed

Project Testing and

management commissioning
5% Other costs 2%
PO Cable 2%
WTGS Installation
10%
2%
Consenting
7% Cable installation
9%

Foundation
installation
6%

PO Substation
4%
PO Scada
1%
PO WTGS
33%

PO Foundations
19%

Figure 11: OWF Cost Breakdown

As the distance to shore increases, the offshore cable cost will increase and as we
move to deeper water the foundation and installation costs will increase. Net effect will
be a reduction in the percentage cost of the turbine although it will still be significant.

9.1.2 Turbines

It is clear that this remains one of the major challenges of the industry. The call for
bigger, lighter and more reliable turbines and at a competitive price increases.

Current preferred turbine size has been seen as the 3/3.6MW machine and lower, and
has been dominated by the international onshore market, in particular the US, but there
is a need to develop larger turbines for the future. Optimal turbine size will increase as
the industry matures, since in an offshore environment to have fewer but larger
foundations (or of a different configuration) to install with an accompanying larger turbine
will be cheaper than installing a larger number of foundations with smaller turbines. This
is due to the fact that hydrodynamic effects offshore play a significant part in the
foundation loads and this will be exacerbated as we move into deeper waters. This has
been recognised by manufacturers but they are reluctant in many cases to invest due to
an uncertain market. One manufacturer has recognised this to date and has taken an
initiative to develop. One other had proposed a 4MW machine but this development
plan has been withdrawn. Whilst there is merit in ensuring reliability of current models

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there is also the foresight required to enable the feasibility of bigger farms in years to
come.

Clearly though we are making progress. The weight of turbines has not increased
proportionally to the increase in volume, but at a rate of 1.5 [5.4]. In fact it is not unheard
of for higher-powered turbines to be brought onto the market with the same weight as
older, lower capacity models.

Turbines need to be made more reliable to allow machines to be placed in excess of

20km offshore with confidence by the developer of the likely operating and maintenance
costs. Transportation times and costs will be significantly higher than current
installations with the distance offshore. Also offshore sea conditions, wave height etc,
will be greater offshore, which will reduce the weather window. This weather window is a
period of time of calm weather in which it is deemed safe to work offshore. Thus, the
need for more reliable turbines is imperative to ensure that the offshore time is
minimised.

There also needs to be R&D into the production line for turbine manufacture; with the
forthcoming Round 2, there will be a magnitude difference in the number of turbines
required. This will demand that manufacturers enhance their production line. It is
estimated that with increased production and increased orders the cost of turbines may
reduce by 15%.

Blades are another area worthy of R&D. We have seen significant development of the
blades as the manufacturers endeavour to increase tip speed and length coupled with a
challenge to keep the weight down. Material selection is obviously a key; the most
common design has used carbon fibre overlaid on a profiled skeleton. Now there needs
to be R&D to enhance these designs, using cheaper more readily available materials
and with a durability to withstand the future demand placed on them.

9.1.3 Transition piece

The transition pieces are currently either bolted or grouted. Both of these have their
problems. R&D should endeavour to find an innovative method of connection or a
method of deleting this requirement. It is worthy of note to recall the swaged pile in the
O&G sector.

The emphasis should be on simplified installation. Grouted suffers from environmental

problems but allows greater tolerances on pile verticality. Maybe more emphasis should
be placed on ensuring the pile is within the tolerance for a bolted transition?

9.1.4 Access

From industry feedback to date, access to the tower and to the turbine was regarded as
one of the main areas requiring more R&D, as currently the time involved to access both
tower and Nacelle is significant and heavily dependent on sea state. Consequently,
there are significant OPEX costs savings feasible in this area.

The other issue is the access to the generator system i.e. through the tower, which is
physically very demanding. This limits the number of turbines that can be serviced in a

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certain period of time; on one of the operating OWF’s only three turbines can be
serviced in a day.

9.1.5 Foundation

Clearly it seems a common challenge to deal with problem soils around the continental
shelf. Oil and Gas hasn’t had so much of a problem with this due to there being
nominally 3 or 4 legs and piles.

R&D should also focus into alternate means of foundation design, to allow shorter
installation times. Historical data reflects up to a 25% downtime in operation during the
piling phase. An example of innovation is the development of the suction pile seen in
the industry over recent years though originally idealised in the 50’s. We have a need to
understand the shallow pile soil interaction. On Oil and Gas there was much research
done on the soil/pile interaction. But offshore monopiles operate in a different way to oil
and gas piles with predominately OTM and so this Oil and Gas research has limited
applicability. This will not necessarily reduce the cost of piles but will give the developer
greater confidence that foundations are optimised and reliable for the life of the tower.

As we move into deeper water, with larger turbines, greater wind loads, longer blades
and taller structures above water level, so we will reach the limit of the capability of the
monopile. There has to be a practical limit for this based on the ability to roll, the ability
to pile, the ability to transport and the cost of this compared to an alternative structure.
This is likely to be in the range 25-30m. Above this will be the need for other type of
foundation.

So what are the alternatives?

Ø Tripod: Good track record in the oil and Gas sector. For depths above 30m.
Better knowledge of foundation action. It is a known technology.

Ø Suction Pile - Monopile with a difference. Decommissioning easy. Being looked

at for the offshore wind market

Ø Others: Guyed Floating, Self-installing, Telescopic

It is considered that with R&D, there may be up to 20% saving in CAPEX of the
foundation for deeper wind farms on a proportional basis.

Scour protection needs to be address to provide a cheap, reliable and efficient method
of protection. One farm has had to replace the first method of scour protection with an
alternative.

9.1.6 J Tube entry configuration.

The Oil and Gas industry has a number of prescribed configurations for the J tube at
mud line, but in general the problem in many wind farms is different due to high mud line
scour. Generally to date, mud line mattress protection has not been adopted. The
industry needs to develop some accepted system for cable pull and connection to the
tower and should be complementary to the scour protection utilised.

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9.1.7 Installation vessels

There needs to be development of installation vessels that will be capable of installing

the hundreds of turbines in future years. These new turbines will likely have extended
blades, be mounted significantly higher than those of today, and of greater weight.
Dynamic stability needs to be addressed to allow installation in more rigorous sea states
so as to minimize weather downtime.

The option of single lift should be examined. This allows the turbine (complete with all
three blades rather than in standard Bunny Ears formation) and tower to be installed
directly onto the foundation. Although this will require new or certainly modified
installation vessels it could save significantly on offshore time.

9.1.8 Cabling from offshore to onshore

As distances become further HVDC becomes a more favourable alternative with better
future prospects of cost reduction. As the distance to shore increases and the size of the
field increases, with increased production HVDC is required to be developed to reduce
losses. Consistent with this is the need to carry out R&D on the methods to translate
and bring this power into the grid. This is an area that will become under much more
scrutiny as Round 2 and beyond develop with much larger power generation that is
further offshore. It needs to be addressed soon before these future projects are upon us
and are unnecessarily delayed.

Energy Storage. With the potential for significant increases in energy generation, and
the inability of the grid to accept the fluctuations in this power, there is a growing need
for R&D in battery storage systems.

9.1.9 Materials

There is the need to carry out research into new materials for use on OWF and to do
study to get more out of the materials being currently used. As turbines get larger,
weights increase which leads to the need for larger foundations and therefore additional
installation complexity and cost. Use of lightweight and yet less costly materials would
be seen as a major benefit to the industry. These materials need to be fatigue
resistant, easy to produce and light. There is also an opportunity for the development of
recyclable materials, which will reap further reduction in carbon emissions.

If we are to meet our renewable obligation in 2010 of 10% UK energy from renewable
sources we need to keep up the impetus.

Challenges for offshore development include higher initial investment costs for large
machines and marine cables for the connection to land; more difficult access to the
turbines resulting in higher maintenance costs; and more severe environmental
conditions at sea.

If the industry either focuses or receives focus on R&D initiatives then future developers
and investors will gain confidence in the industry which will allow a self perpetuated
reduction in the risks that currently surround offshore wind energy. This should allow
more projects to get past the project sanction phase and towards inception.

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Despite the difficulties of offshore development, it holds great promise for expanding
wind generation capacity and this will be enhanced if appropriate R&D is engaged.

There is a need to learn from the oil and gas industry. This is particularly pertinent to
installation and safety aspects. There is also a need to integrate onshore and offshore
R&D for mutual gain.

There can be no doubt that R&D has been an essential activity in achieving the cost and
performance improvements in wind generation to date. This may not seem evident
given the increased costs perceived, but this is mainly due to the increasing cost of
commodities, components in the supply chain, and turbine cost. Much of this is outside
the control of the developer. Long-term projections are that when stability of the market
occurs we will have a valid, mature and invaluable electrical infrastructure offshore the
UK coast.

9.2 Learning gains

This is the other likely method of future cost reduction but its effectiveness is highly
dependent on ensuring a good level of inter-project and inter-company communication
to allow the learning to benefit the industry rather then just individual projects or
developers. The concept of learning has been studied at great depth over the years,
with some recent research carried out into the offshore wind industry. This prediction
method has been shown to prove correct many times and is based on the concept that
for every doubling of production there will be a consequential learning and consequential
reduced cost.

Consider the progress made for example in the length of blades where in 1990 the
longest blade was circa 27m and now just 16 years later we have blades over 60m long;
an increase in area of sweep of 500%. Take into account that this must be supported at
a higher elevation, attracting a greater wind speed; we increase our overall production
many fold.

A recent learning curve study projected that for every doubling of production there would
be a reduction in turbine cost of 12.7% (Ref #23).

Clearly the learning potential, as well as the appetite to progress is far reaching and this
is absolutely essential to maintain industry momentum and promote cost reduction,
increased reliability and project viability with decreased risk.

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10.0 REFERENCES

1. http://www.wind-
energie.de/fileadmin/dokumente/statistiken/statisiken_englisch/ewea_2005statistics.
pdf#search=%22wind%20power%20installed%20in%20europe%20by%20end%20of
%202005%22
2. http://www.wwindea.org/home/index.php?option=com_content&task=view&id=13&It
emid=40
3. http://www.ewea.org/fileadmin/ewea_documents/documents/publications/WETF/WE
TF.pdf
4. http://www.bwea.com/ukwed/operational.asp
5. http://www.bwea.com/media/news/060327.html
6. Offshore Wind At Crossroads – BVG Associates & Douglas Westwood Ltd, April
2006
7. http://www.ewea.org/fileadmin/ewea_documents/documents/publications/briefings/n
o_fuel_lo_res_72dpi.pdf#search=%22ewea%20briefing%202006%20europe's%20e
nergy%20crisis%22
8. http://www.bwea.com/pdf/briefings/offshore05_small.pdf#search=%227%2C169%20
maximum%20capacity%20(MW)%22
9. http://www.windpower.org/en/tour/wres/enrspeed.htm
10. http://www.owen.eru.rl.ac.uk/documents/bwea20_44a.pdf#search=%22wind%20turb
ine%20technology%20Offshore%2C%20J%20R%20C%20Armstrong%22
11. http://www3.dti.gov.uk/renewables/publications/pdfs/windfs3.pdf#search=%22onshor
e%20wind%20bank%20fees%201%25%22
12. http://www.publications.parliament.uk/pa/cm200304/cmselect/cmtran/555/555we15.h
tm
13. http://www.earthscan.co.uk/news/article/mps/uan/485/v/3/sp/
14. ode Installation Vessel Capability Study, February 2006
15. http://www.dti.gov.uk/files/file29979.pdf#search=%22decommissioning%20offshore
%20renewable%20energy%20installations%22
16. Assessment of UK Offshore Wind Costs and Potential UK Content - BVG
Associates, 2006
17. http://www.offshore-
sea.org.uk/site/scripts/documents_info.php?documentID=6&pageNumber=2
18. http://www.dtistats.net/energystats/dukes06_c7.pdf
19. http://www.dti.gov.uk/files/file22067.pdf
20. http://www.ipg.antfx.com/index.php?option=com_content&task=view&id=178&Itemid
=41
21. http://www.cruspi.com/
22. http://www.kitcometals.com/
23. http://www.electricitypolicy.org.uk/pubs/wp/eprg0601.pdf#search=%22karsten%20ne
uhoff%20learning%20curves%22

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APPENDICIES

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APPENDIX 1 ROUND 1 FEEDBACK

1. STATUS OF ROUND 1 PROJECTS

1.1. Background

This section aims to give feedback of learning points of the Round 1 wind farm
developments to date. Round 1 sites are located in three main areas as shown in Figure
1 below.

Figure 1: Location Map - Round 1 Offshore Wind Farms – Source BWEA

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The first phase of the UK’s offshore wind industry was launched in December 2000.
Offshore wind farm developments require a lease from the Crown Estate, whose Marine
Estates include over 55% of the foreshore around the UK and beds of tidal rivers, and
the seabed out to the 12 nautical mile territorial limit around the UK. The lease term for
Round 1 projects is for 22 years and includes timing requirements for the construction of
the wind farm, and also covers rent and issues of wind farm operation, maintenance and
decommissioning.

In April 2001, following the pre-qualification process, 18 companies were awarded

agreements for leases by the Crown Estate (CE) in the first round of offshore wind farm
sites on the UK seabed. This represented a significant achievement for the DTI in
encouraging the development of offshore wind farms. Under the agreements, the
companies were given a three-year period in which to obtain the necessary consents for
a lease to be granted by the CE.

Developments had to comply with a number of conditions:

• Sites had to be within the 12-nautical-mile territorial limit around the UK.
• Sites had to be at least 10 kilometres apart.
• Sites had to have a minimum generating capacity of 20 megawatts.
• Sites were restricted to a maximum of 30 turbines.

In identifying sites, applicants also had to take account of all the relevant environmental
factors, including proximity to shipping lanes, dredging areas, fisheries, conservation
areas, cables and pipelines. Applicants were also required to provide a statement and
project plan with reference to their first choice, showing the main stages of development.
A financial deposit was required when applications were lodged (pre-qualification).

Intended as a pilot phase, Round 1 sites were limited to a maximum of 30 turbines.

Round 1 proposals proved to be successful and developers consequently expressed an
interest for larger offshore projects in the second phase of development, Round 2. [3]

1.2. Current Status

Of the 14 sites allocated in 2001 (following combination of five of the original 18 sites
into two and withdrawal of EnergieKontor from its Southport project) there are three in
operation, one under going commissioning, one in construction and seven approved for
development. The remaining are either in the consenting and approval process or are
out to tender.

As such there is a limited experience base of the process of design and implementation,
but a fairly significant experience base of the problems associated with the preliminary
proceedings to approval.

Overall, developers have had a challenge to provide a commercially viable solution in an

environment where there are constraints on supply, where there is market demand
greater than availability and where costs are increasing significantly.

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2. ROUND 1 PROJECTS: STATISTICAL DATA

WTGS Capacity (MW)

Total Capacity (MW)

Rotor Diameter (m)

Number of WTGS

Hub Height (m)

Tip Height (m)

Site Developer/Turbines WTGS Model

Blyth Harbour - Pilot E.ON UK Renewables/Vestas 4 2 1.9 V66 67 100 66

North Hoyle npower Renewables/Vestas 60 30 2.0 V80 67 107 80
Scroby Sands E.ON UK Renewables/Vestas 60 30 2.0 V80 61.5 101.5 80
Kentish Flats Elsam/Vestas 90 30 3.0 V90 70 115 90
Barrow-in-Furness Centrica/DONG/Vestas 90 30 3.0 V90 70 115 90
Gunfleet Sands GE Energy 108 30 3.6 GE 3.6 80 135 110
Lynn Centrica 90 30 3.0
Inner Dowsing Centrica 90 30 3.0
Cromer Norfolk Offshore Wind/EDF 108 30 3.6
Scarweather Sands E.ON UK Renewables/Energi
E2 99 30 3.3 83 135 104
Rhyl Flats npower Renewables 90 30
Burbo Bank Seascape Energy/Siemens 90 25 3.6 Siemens 3.6
Solway Firth/Robin Rigg E.ON UK Renewables/Vestas 90 30 3.0 V90 70 130 90
Shell Flat ScottishPower/Tomen/
Shell/Elsam 270 90 3.0
Teesside/ Redcar Northern Offshore Wind/EDF 90 30 3.0
Tunes Plateau * RES/B9 Energy 150-250 50-85 3.0
Ormonde * Eclipse Energy 108 30 3.6
* These two projects were outside of the original Round 1 process, but conform to its
requirements.

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Site Sea/Ocean Status Comment

Blyth Offshore Irish Sea 2000 Operating (Pilot installation)

North Hoyle Irish Sea 2003 Operating (Dec 2003)
Scroby Sands North Sea 2004 Operating (Dec 2004)
Kentish Flats Thames Estuary / 2005 Operating (Sep 2005)
North Sea
Barrow-in-Furness Irish Sea 2006 Construction complete. Commissioning in
progress. 18 turbines generating. Expected
completion Q2/06
Gunfleet Sands North Sea 2007 Approved. Engineering design work and
procurement activities are currently being
finalised with a view to commence construction
in 2007
Lynn North Sea Approved Out to Tender. Due to be producing by Q4
2008.
Inner Dowsing North Sea Approved Out to Tender. Due to be producing by Q4
2008.
Cromer North Sea Approved October 2003
Scarweather Sands Southern Irish Sea Approved October 2004. Grant yet to be applied for.
Delayed because of costs
Rhyl Flats Irish Sea Approved npower Renewables purchased the Rhyl Flats
project from COWL in December 2002 are now
out to Tender for 2007 installation of
foundations.
Solway Firth Irish Sea Approved June 2003
Shell Flat Irish Sea Submitted. Jan 2003.
Teesside/ Redcar North Sea Submitted
Tunes Plateau * North Irish Submitted
Sea/Atlantic
Burbo Bank Irish Sea 2007 Consented. Initial scour protection installation
in progress. Foundations to be installed
summer 2006. Turbines to be installed summer
2007.
Ormonde * Irish Sea Delayed due to Grid Upgrading negotiations
* These two projects were outside of the original Round 1 process, but conform to its
requirements.

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2.1. Grants & Financing

Developers have experienced significant technical challenges, which have highlighted

the importance of field location. Geotechnical, environmental, distance to shore,
distance to grid connection, distance to port and water depths are major influences on
the viability of a development.

The capital grants provided for the Round 1 development allowed developer risk to be
absorbed to move projects from not have being considered economically viable, to
become viable. As such these grants were essential. It was clearly stated in one case,
that without capital grant, the development would not have been pursued.

Developers are apprehensive to develop Round 2 projects where economy of scale is

not seen to prevail and where some development costs could be as much as £1 Billion.
Upfront investment could be as much as for a Round 1 development on its own, without
confidence of adequate return. Breakeven on Round 1 projects is expected to be after
10-12 yrs, half the overall life of the development, and, potentially for Round 2, without
financial support and with increased CAPEX this would be significantly worse. This
apprehension and financial insecurity is cascading down to the supply chain, and leaves
the industry uncertain.

Due to the poor economics of offshore wind farms in the UK, many of the original Round
1 sites have been sold from small developers that have struggled to obtain finance, to
those larger developers that can finance off the balance sheet.

With the time taken to develop the Round 1 developments there is also the threat that
capital grant allocations will expire and there are concerns that extensions will not be
granted.

For projects not yet completed, given current market trends (rising commodity prices,
rising manufacturing costs, long lead times etc), these grants, or alternative financial
initiatives, are seen as even more critical to many developers

Developers feel that distribution of the grant during the lengthy consenting phase, rather
than releasing the funds only when construction begins is worthy of consideration.

2.2. Environmental Statement

The Environmental Statement (ES) has been seen as a major pre-approval investment
demanding significant survey, research, planning and study. Some developers have
taken up to 3 years to develop the input necessary for the ES. The industry has
indicated some concern with the time taken for the approval of the ES due to the
number of parties required to provide comment.

It should be ensured that approval is not unduly delayed and that negative impact on a
UK energy development is not influenced by personal opinion. A centralised facilitation
or co-ordinating body may assist this process with the ability to have interaction to
amend minor points where possible would be useful.

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Developers have learnt that public enquiry should be avoided as it leads to delays in the
development of the OWF and to significant additional costs.

2.3. Consents process

The UK’s offshore wind farm Industry is fairly young, and therefore the whole process is
going through a learning curve. This is especially applicable for the consents process,
which in itself, is developing as more is learned about the impact of an OWF on the
marine environment, navigational issues, grid connection and other aspects. This also
leads to an increase in the complexity and therefore, the OWF developers are expending
more time and money in order to obtain consent.

There are three main consenting authorities applicable to the OWF and those are the
Department of Trade and Industry (DTI) the Department for Environment, Food and
Rural Affairs (DEFRA) and the local council’s planning authority.

The Offshore Renewables Consents Unit (ORCU) is the DTI’s focal point for offshore
wind farm projects. Upon a successful application the DTI will grant consent to develop
the OWF within the established territorial limits. There are currently two main consent
routes applicable to the Round 1 development for OWF within the 12 nautical miles limit
and those are:

• Section 36 of the Electricity Act – this is required by the Secretary State if the
capacity of the offshore generating station exceeds 1 megawatt. This route also
includes the Coastal Protection Act (CPA) 1949 and the Food and Environment
Protection Act (FEPA), 1985. Approximately six Round 1 OWF developers opted
for this route, and

• The Transport and Works Act 1992 (TWA) – the Secretary of State can also grant
consent through this route and approximately five Round 1 OWF developers
opted for this route.

Applications through the TWA take approximately 12 months to obtain consent and
applications through the Electricity act take approximately 7-9 months. Despite taking
longer many developers opt to apply through the TWA route since the order obtained can
extinguish the public rights of navigation.

There have been inconsistent approaches to navigational marking during the

construction period. A more streamlined system should be developed in consultation with
Trinity House.

The DEFRA and Department for Transport’s (DfT’s) Port Division have formed an
alliance called the Marine Consents and Environment Unit (MCEU) in order to coordinate
requests of consents for the full range of marine works. There are also plans to form an
alliance between the MCEU, ORCU and the local council’s planning authority but this will
not change the number and type of consents required for development of an OWF.
However, this alliance should make the consent application process simpler to a certain
extent.

The view of all parties consulted so far is consistent on the need for the consents
process to be made simpler. The Round 1 consents process was found to be lengthy
ranging from several months to, in the extreme case, a few years. Developers were

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unaware of the requirements but are now generally understood requiring sufficient lead-
time for completion. There is experience and concern that the requirements are not
sufficiently ring fenced and open to an escalation of expectation from statutory
consultees. Whilst some of these additional requirements are seen as reasonable, e.g.,
decommissioning strategy, others are more subjective and minor. As a consequence,
after having been through a very lengthy consents process developers are reluctant to
go through even minor deviation in consent approval for fear that there will be an
incidental comment which may throw the consent approval into disarray.

There seems to be consensus amongst developers that a central government

coordinating role for the consents process would be beneficial.

The other issue, which is generating some concern amongst the developers, is the
requirement to pay the Network Reconnection fee, for connection to the grid before
consent can be granted.

Overall a significant learning point from the Round 1 process has been the clear
requirement that the location of the proposed OWF be absolutely appropriate in terms of
all environmental, political and local factors. Where location had shortcomings in any
parameter consent application is recognised as being troublesome.

Round 1 has also seen developers forming consulting/cost-sharing bodies in the three
main areas, as shown in Figure 1. This has resulted in sharing of costs for activities such
as environmental surveys.

2.4. Geotechnical/Environmental

One of the Round 1 developments had major problems in the driving of piles due to
unexpected ground conditions. It had been predicted that 5 locations would require
drilling, however, this increased to 11, which took significantly more time than was
planned. Of course, with the Round 2 developments occurring over a much larger area,
the challenge to understand the limiting ground conditions will be greater. Problems
have also been experienced with cable laying as a result of ground conditions and this is
even more of a challenge where the affected ground covers a much larger area. It
should be recognised that burial depths may differ and stringent compliance to pre-
determined depths from the consenting process may not always be practical.

As such, it is anticipated that developers, having learnt from the initial Round 1 process,
will propose varied cable burial depths depending on ground conditions and the risk
factors such as shipping routes, anchor patterns etc.

Clear study of marine growth to be expected is also of mention where developers

underestimated the quantity and speed of accumulation. This has caused design and
safety issues in the estimation of environmental loading and resulting structural
configuration for the tower and foundation.

As the area of offshore developments increase there is an increasing need to erect met
masts at multiple locations throughout the proposed wind farm site to enable thorough
wind speed profiles to be developed and the costs of these included in the overall
economics.

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Developers have learned that detailed geophysical and geotechnical surveys need to be
carried out in the wind farm and along the cable route. It is worth spending a reasonable
amount of money carrying out these surveys at the outset rather than experiencing
problems in installation of the OWF and consequential delays.

2.5. Need for FEED

Given the latitude in foundation design, transition piece design, installation design,
access, etc and the extended time for both consent, grid application, turbine
procurement and the booking for vessel availability, a FEED has proven to provide the
developer with additional data to refine on risk. In Round 1 FEED was not generally
performed.

It is a reflection of a lack of industry transparency that there seems to have been little
learning on the benefits of a FEED process. FEED studies can help with safety,
accessibility, availability and reliability aspects of a project and therefore should not be
overlooked. Due to the lengthy approval process, FEED studies could be initiated and
completed without the need for impact on the schedule.

It is probable that FEED will be carried out for the Round 2 and Round 3 projects due to
their larger size and increased complexity.

2.6. Planning offshore vessel spread

Recent study has been carried out already by ode for the DTI, and this identified a long-
term shortage of installation vessels. Increased water depth will add further restrictions
and currently there is limitation on size of turbine that can be installed without
modularisation and some installation vessels are unable to carry out piling activities.

Short-term supply does not pose a problem with only one wind farm per year likely to be
installed up to 2008.

However, in 2009 the OWF industry is predicted to go through a very busy period due to
demands from the UK market and also the European market, particularly the Danish and
German OWF industries. This demand is predicted to increase further and peak in the
year 2012. Despite current vessel usage being limited, the future demand is anticipated
to rise so significantly that the introduction of more vessels will be essential.

During this period of forecast high activity the availability of installation vessels will be
scarce and the project developers are being forced to commit themselves at an earlier
stage in order to secure vessel contracts and ensure installation goes ahead when
planned. This forward commitment can only be done if a reliable financial forecast is
available.

However, vessel owners are reluctant to build new vessels for the long term without a
clear indication that there will be market. During recent years, overall vessel company
losses have only been saved due to the European market. One vessel supplier identified
that in 2006 their vessel was on standby for approximately 25% of the time and engaged
on offshore wind farm work for approximately only half the year. Another owner noted
the plan to convert one vessel for 2007 to have greater capacity and to operate at water

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depths up to 35-45m and capable of installing up to 5-6MW machines, but due to market
uncertainty will now put this back to 2008/2009.

Another issue causing concern to the industry is the shortage of adequate port facilities
on the East coast, where a significant proportion of both Round 1 and Round 2 OWF are
located. Port acceptability is dependant on the ability to handle the very large
components. For example, at Thanet, the nearest port is DeBrugge whereas in the
Wash area it would be Hull, Great Yarmouth or Lowestoft, all of which have fairly limited
capability and may be inappropriate for Project development. Yard facilities required to
support significant developments are limited e.g. 30 WTG site requires 10+ acres

Several of the Round 1 projects have seen (or will see) two season installation. This will
involve foundations and scour protection being installed during the summer of one year,
with the turbines being installed the following summer. This gives a short period of work
for the installation vessels, which could lead to bottlenecking and shortages during the
installation seasons, and could leave them without work for the rest of the year.

2.7. Planning

Round 1 has highlighted the need for clear planning to account for the risks in delivery of
equipment, extended time for installation, securing of vessels and time for consents and
upgrade and connection to grid.

For instance, the lead-time and availability of turbines is a critical factor. Assuming
availability, lead time for supply of turbines is now upwards of two years demanding up
front investment by developers, prior to consent.

2.8. Contract strategy

The majority of the Round 1 contracts were EPIC contracts, under the control of the
turbine provider.

Broadly speaking, EPIC contractors were subjected to significant additional costs and
claims/liquidated damages, some of this was due to poor management, planning etc and
they are now reluctant to engage in future EPIC contracts in the offshore industry.

As a result of this, more recent projects are using a multi-contract approach. Multi-
contracts place a more potential risk on the owner, but if managed properly this risk can
be controlled. The main area of risk for the owner, relates to interfaces and ensuring that
all parties are working in a co-ordinated approach. It is considerably easier to allocate
risks between the main contractors as a multi-contract strategy.

2.9. Project Management

Round 1 developers underestimated the level of project management required to service

the EPIC contracts and have learnt that adequate project management needs to be
provided for Round 2 projects. This is further underlined by the move to adopt a multi
contract approach where a greater degree of control of QA, safety and specification will
be required. It is seen as essential that these management teams have the required
experience.

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2.10. Specification

There are no statutory requirements for offshore wind farms and hence the choice of
code is project specific and subjective. Some Round 1 developers and contractors took
inadequate care over specification for design, fabrication, material procurement and
supply and had consequential quality, consistency and supply problems.

There are various specifications to work to in the offshore wind industry. The two main
bodies are Germanischer Lloyd WindEnergie (GL) and Det Norske Veritas (DNV). Some
contractors will also turn to American Petroleum Institute (API) specifications.

Future contracts will see developers stating the highest standard of specifications in the
tenders as in some instances, lower specification requirements have led to quality
problems, which caused additional, cost and time expenditure.

2.11. Connection to Grid

Agreement for connection to the grid has proved in many cases to be extremely time
consuming, up to two years, where licensing has taken an unforeseen amount of time
and the required maintenance/upgrade work required to allow input of production has
been a major cost. The problems of connecting to the grid are even more significant for
Round 2 developments, with significant higher production input. However, with the
recent change in legislation, grid maintenance work will not fall on the developer but on
the network provider.

Current requirement is that a generating licence is required where production is greater

than 100MW. This means that all Round 2 wind farms will require generation licences.

It is perceived that consent and licensing for connection to the grid is time consuming
and costly. There is consensus that something should be done to make the process
less troublesome. Reference has been made to the procedures for Danish projects to
connect to the Danish grid where connection procedures are smooth.

Feedback received from developers underlines the importance of location for connection
to the grid in order to minimise the distance for cabling but also to ensure grid stability.
In remote areas, the nearest grid connection point may be too weak to receive all the
power from the wind farm, which could result in the need to reduce the input. Therefore,
extending the cable to a stronger grid connection site is preferable, though at
significantly increased cost.

2.12. Procurement of Turbines

Supply Issues

The US market is subject to a boom at the moment. This boom is the result of the 2005
US Energy Policy Act, which, like the Renewable Obligation in the UK, encourages
suppliers to offer more electricity from renewable sources. This Act has extended the
production tax credit (PTC) until 2007, offering tax breaks to suppliers that provide
energy from renewable sources, and encouraging the development of further wind
projects. The US market is growing and will stabilise in the long term, but the question of
whether the policy will be renewed at the end of 2007 could mean a period of frantic

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manufacturing followed by uncertainty about whether to invest in new plants and

production, producing a potentially harmful boom-and-bust cycle. In the meantime, the
increase in US schemes is sapping supply elsewhere.

Further, there is a demand for smaller machines in China, India and Europe.

As a consequence, turbine manufacturers are reluctant to make commitment for larger

UK turbines with a consequential impact that developers cannot readily commit to
develop OWF’s until 2008/2009. This is leading to long lead times and is contributing to
the delay in installation of offshore wind farms.

Due to historical experience coupled with a secure non-UK market turbine suppliers,
acting in a sellers market, are in favour of more secure markets and contracts. It is
known that turbine providers are declining to bid in cases.

At current rates, a turbine ordered from a major supplier during 2006 is unlikely to be
delivered before the end of 2008.

As such, turbine supply is seen as a major hurdle in achieving a successful project

completion. The investment required to procure and install the turbine is significant
(~40% installed) and as such is a major pre-investment risk.

Material supply is also a problem due to the drain on commodities by SE Asia, putting
pressure on the supply chain limitation.
Reliability

The reliability of turbines has caused significant and expensive operating cost exposure
for those WTG installed. Only recently has the reliability increased on current machine
models.

In one Round 1 development, operational for only a short period, operating costs were
greater than expectation with 5 generators failures, 1 gearbox replacement and nearly
all main bearings requiring replacement and redesign. Costs of gearboxes are now
reaching values in excess of £200K. Much of this was due to the inadequate
marinisation of onshore machines for the offshore environment with major problems
occurring in areas of corrosion, ingress of salty air for ventilation over transformers
made worse by inadequate access and inadequate quality assurance during fabrication.
Deficient specification also allowed components taken from sub-suppliers to be
unreliable.

This causes the developers to be reluctant to commit to larger currently untested machines, such as
the Repower 5MW machine to be installed on the Beatrice field. It is likely that Round 2 developers
will err on the side of the 3MW or 3.6MW machine where higher reliability is more likely, having
been trialled on the Round 1 projects. Cost

Turbines themselves have increased in cost by up to 60% over the last 4 years and on
one project increased by 30% during the project development phase. Concern over
liability has also meant that turbine manufacturer’s are becoming more aggressive on
warranty agreements.

Installation

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As more research and development is carried out into large machines, reference must
be made to the installation constraints. There are several drawbacks of the 5MW
machine, which the industry is currently unprepared for. This includes the fact that
transportation is an issue and that it is more complex and difficult to install at ~350Te
(rotor weight) compared with ~290Te (rotor weight) for the 3.6MW machine. There are
also logistical constraints related to port facilities due to the increase in blade lengths
from 52m for a 3.6MW machine, to 63m for a 5MW machine.

2.13. E&I

A learning point from Round 1 was that the electrical systems had inadequate
redundancy built in. Round 2 developments will endeavour to have more remote resets.
SCADA systems, essential to give feedback of actual production, require more
development. Some producers are now looking at a master SCADA system to collect
data from multi-field in order that there be better feedback to have better control over the
sale of power. SCADA systems are required for those projects >100MW to allow
reporting of the power input to the Grid 4 hrs before it happens.

2.14. Design for Access to Towers

Access to towers via ladders is a major safety concern. For existing systems, it is
recommended to install two access ladders, one upstream and one downstream of the
dominant tidal current direction to ensure that boats can access the turbines.

Access platform levels needs to be addressed to ensure that the effects of run-up are
minimised.

Some suppliers are developing propriety systems to enable easier, safer access, which
will save on time and cost.

The round 1 experience identified this design shortcoming and will be addressed in
future projects. This will save on platform maintenance.

2.15. Corrosion protection

Round 1 foundations generally utilised sacrificial anodes subsea and coating systems in
and above the splash zone. In the Oil and Gas sector the standards and procedures for
application of the coating systems are rigorous however Round 1 saw some
shortcomings, in some cases, on quality assurance in application resulting in blistering
of coating and requiring significant Contractor remedial works. It is again a learning
point that quality control was lacking in Round 1.

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2.16. Cable laying

Cables must be buried for several reasons. Firstly, to protect against damage from
dropped anchors or objects. Secondly, burial prevents against the snagging of any
fishing equipment. Thirdly, some species of marine life are sensitive to electromagnetic
forces and as such, this burial reduces the EMF emissions.

The depth for cable burial for Round 1 developments was generally 3 metres, although
not a statutory requirement. This covers both the inter-turbine cables and the export
cables. The proposed burial depth is contained within the FEPA licence from DEFRA.

Round 2 may see the proposal to bury cables consistent with the risk at location and the
ground condition. Loss of time due to failure of cable or inability to bury has been seen
to move the activity of cable laying from being non-critical to critical.

Also, the seabed is a dynamic environment and some sites have experienced significant
sediment movement, which has led to the need to provide additional protection to the
cables. This is generally in the form of concrete mattressing or rock dumping. This
results in additional costs to the project and these costs are often contentious as to who
is responsible.

Lessons learned from the cable burial process indicate that detailed geotechnical
surveys should be conducted to provide as much information about the sea bed
characteristics as possible to avoid the need for future remedial work.

Related to cable laying is the procurement of the cables themselves. One developer
found that cable prices had increased by over 40% in less than 2 years. This was due to
increases in copper prices and also due to a lack of competition in the submarine cable
industry.

There is concern in the industry that there is currently a lack of definition of the
requirements for onshore cable laying and a concern that when this comes in there may
be retrospective implementation requirements.

2.17. Installation phase

The installation phase of an OWF is seen as one of the most complex phases during the
project and it represents a significant logistical challenge. Installation is weather
dependent and as such is limited to those times of the year when sea and wind
conditions are ideal for offshore activities (usually from April to September in the UK).
Maximum installation conditions for turbines are wind speeds of about 11m/s and a sea
state with significant wave height of 0.9m.

Round 1 has shown the need to ensure that installation is carried out during the weather
window as overruns can have significant knock on effects. Recent projects have begun
a two-season installation programme. This involves installation of piles and scour
protection during one summer and then cables and turbines the following summer.
Currently this is due to delays in turbine delivery, however, as wind farms get larger this
may well be the approach that is adopted.

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Reduction in cost of installation by careful planning of installation period (to avoid costly
standby periods), selection of installation vessel and equipment to ensure timely pile
installation and a clear understanding between installation contractor and developer of
the contract risks are required. Installation costs represent notionally ~20% of overall
project cost and are therefore considered significant.

As the industry moves into deeper water, so the challenges of installation will increase,
with a need for vessels able to install equipment further offshore, at greater water depths
and potentially capable of installing larger turbines and blades, rather than having to
deal with piecemeal installation of Nacelle etc with hook up at location.

2.18. Onshore Testing & Commissioning phase

Success of the offshore activities relies on sufficient onshore testing of all components.
Some projects have had components taken offshore without being fully tested onshore.
This has resulted in failures and the need for maintenance and replacement, which in
the offshore industry is costly and time consuming. Therefore, manufacturers must learn
from this. All components must be fully tested prior to offshore instalment. Economics of
the offshore wind industry are already fairly tight and needless expenditure needs to be
avoided by all parties.

Connection is required for the Energisation process during the commissioning phase
and where location or connection has been hampered then diesel generator deployment
has been required to facilitate power up. Whilst this was not seen as a major cost it
none the less was out of plan requiring access, handling and space. This is an
additional consideration for developers as a consequence of the inability to firm up
schedule for connection to grid.

2.19. HSE

There has been a surprising shortfall in attention to safety in the UK offshore wind farm
sector. There are significant learning points from the offshore oil and gas industry, which
have not been adopted. It is required that the Round 2 projects will take more care to lay
down clear requirements for HSE.

2.20. R&D recommendations

Whilst turbine manufacturers hold at the 3/3.6MW machine and lower, dominated by the
international market place there is a need to develop larger turbines for the future. Only
one manufacturer has recognised this to date and has taken an initiative to develop.
One other had proposed a 4MW machine but this development plan has been
withdrawn. The government needs to provide financial support and focus to R&D
activities that will allow continued technical development of the industry to provide bigger
and more reliable machines to allow placement in excess of 20km offshore where
transportation and access is of a magnitude greater than close to shore.

From the research conducted so far, access to turbines was regarded as one of the
main sectors requiring more R&D input, as currently this represents a very large slice of
OPEX costs.

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The other issue is the access to the generator system i.e. through the tower, which is
physically very demanding. This limits the number of turbines that can be serviced in a
certain period of time; on one of the operating OWF’s only three turbines can be
serviced in a day.

Another learning point has been the need to hold the rotor whilst maintenance work or
access is occurring. This is an issue that could be associated with R&D for turbine
manufacturers.

There is need for inclusion of more redundant systems on the WTGS in order to
increase its availability and reduce maintenance activities. The developers consulted
also expressed the need for a new automatic braking system, being imposed by the
Marine Coast Authority, to park the blades in “bunny ears” position whenever there is a
problem on the WTGS. Additionally the OWF industry would benefit from WTGS built
specially for offshore applications and improvements on the reliability of these WTGS.

There is the need to carry out research into new materials for use on OWF. As turbines
get larger, weights increase which leads to the need for larger foundations and therefore
additional installation complexity and cost. Use of lightweight and yet less costly
materials is seen as a major benefit to the industry.

R&D should also focus into alternate means of foundation design, consequentially
leading to shorter installation times. Historical data reflects up to a 25% downtime in
operation during the piling phase.

The effects of lightning strikes can be significant resulting in costly damage to the
nacelle and blades. Further work should be carried out into lightning protection systems
to help minimise the resultant damage.

The industry would benefit from a standard design for foundations and transition pieces
with an emphasis on simplified installation. Currently all designs are project specific.

2.21. Operating and maintenance

The main concern with the regards to maintenance work is the high costs involved with
access to the turbines for maintenance and inspections. Furthermore the maintenance
can only be conducted during the right weather conditions, which means that the wind
turbines can be unproductive for a number of days.

O&M will become more of an issue as we approach the Round 2 and beyond wind
farms, which will be significantly, further offshore. The industry should embark on study
to identify as many steps as possible that can lead to a reduction in requirement for
access.

2.22. Future of the industry

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Developers feel that, given the current market conditions, development trends will
remain stable, until circa 2009 when there will be an anticipated marked increase in
demand. This increase will only happen assuming that projects remain an attractive
investment with guaranteed returns. Current difficulties regarding turbine supply, cable
prices, steel prices, consent delays and the installation costs make projects marginal at
best and is reflected by the sale of projects from one developer to another.

Overall, costs per MWh have increased by over 25% between Scroby Sands and
Barrow, of which not all can be solely associated to the increased cable lengths and
offshore substation on Barrow. Component and commodity costs will have to stabilise in
order for the offshore wind industry to develop in line with project availability.

Problems experienced by contractors and manufacturers on Round 1 are leading to

wariness in the industry and reluctance to partake. This wariness is amplified by the
current boom in the more stable, onshore market in the US.

ROC price forecast is highly susceptible to change and this causes additional concern,
reflected in developer’s economic models. As an example, there is concern in the
industry that if energy targets for renewable energy are reduced then Renewable
Obligations will be more easily fulfilled and therefore, the projects will become
uneconomic.

With current government focus on adoption of a planned, future nuclear industry, there
is concern that if renewable credit is assigned to this nuclear energy that the
consequential impact on ROC prices will affect the wind industry.

The planning and consents process would benefit from being simplified as some
developers have found the process extremely time consuming, bureaucratic and
ultimately frustrating. Developers would prefer to deal with a single point of contact in
the government as is in some European states, rather than having to deal with a huge
array of statutory consultees.

The industry notes the essential work being carried out by the BWEA to setup a conduit
for industry communication, but the industry still requires more transparency between
developers and contractors for mutual gain. Greater transparency between will allow
more confidence in reducing perceived risk, which would in turn reflect in cost forecasts.

Involvement of the supply chain as soon as possible to commence negotiations on

equipment, cost, specification and lead-time is seen as a major target.

There has been invaluable benefit provided by the capital grants in round 1 to facilitate
the impetus to develop and to provide rapid growth. However, there is a long way to go
and the industry is still immature in an environment where costs are spiralling upwards.
The industry therefore requires further support by the government to allow the UK sector
to further develop and consolidate this new industry.

2.23. Future DTI/Government Support to the Industry

Government financial support for Round 2 projects is essential. Suggestions are:-

• Fix the ROC price on a contract for difference approach to allow developers to
know the return they will get, and to reduce the risk at outset.

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• Extend the ROC system to 2020.

• Government to provide financial support to supply chain to allow adequate

supply and growth, rather than just to the developers.

• Move surplus Round 1 capital grants to fund the deeper water, further offshore
Round 2 projects and provide grants as was done for Round 1

• Provide financial support to extend and develop the national grid to allow easier
and more reliable connection.

The industry is not satisfied with the current lack of clarity on the requirements for
projects from the governing bodies:

• Decommissioning requirements are still unclear. There are still currently no

requirements laid down for guidance. The DTI are said to be moving into a
consultation phase, but this is seen as being a lengthy process.

• Safety Zones/Exclusion zones are still an issue and are not yet finalised,
although it is hoped that the Energy Act will resolve these issues.

• Transmission licenses are unclear. OFGEN are criticised for moving particularly
slowly to refine and consolidate these and it is predicted that firm rules will not be
in place until 2008 at the earliest. As a consequence developers have to move
forward without this guidance and are exposed with the threat of retrospective
implementation.

The impact on marine users of offshore wind farms should be reviewed with the
insurance industry to allay fears with fishing, merchant shipping and recreational users.

The government should study the effects on fish, marine mammals and environment
after implementation of the farm. It has been noted that in many instances there has
been an increase in marine life.

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APPENDIX 2 – STRUCTURAL WEIGHT STUDY

1.0 INTRODUCTION

1.1 Background
ode has been commissioned by the Department of Trade & Industry (DTI) to study the
estimate in future costs of offshore wind turbine generation, and the potential for cost
reductions in the future. This structural study has been carried out in order to ascertain the
changes in structural weight with variations in water depth, soil profile and turbine size.

1.2 Objectives
A major factor that will considerably influence the cost of an offshore wind project is that of
the foundation. Therefore this structural report sets out the following objectives:
• To provide the cost model with weight estimates of different wind turbine (WTG)
foundations for given water depths
• Preparation of a series of curves from the information gathered from the structural
analysis for incorporation into the cost model
• Comparison of the weights of two well-supported structural solutions for carrying
WTGs.

2.0 METHODOLOGY

2.1 General
Because of the need to achieve a broad spectrum of quantitative output data, three common
WTGs have been used in the analysis – 2.0MW, 3.6MW and 5.0MW corresponding to small,
medium and large WTG capacities with appropriate lateral loads and weights. Each WTG
has been designed to stand in 5, 15, 25, 35 and 45 metres of water depth (WD) and
supported by pre-defined weak and strong soil profiles.

Two groups of structural solutions have been investigated: monopile solutions and tripod
solutions. The former comprises a substructure of a single large diameter driven pile
terminating with a grouted transition price that supports a tower on which the nacelle is
placed. The latter has a similar arrangement of tower and transition piece but instead of a
single large pile is supported by three piles tied together by an arrangement of plan and
diagonal braces.
The weights of the solutions for the different water depths are investigated and an
assessment of the effect of soil profile and WTG type is also made.

2.2 Computer Model

The modelling of the structure is performed using SACS software (version 5.2) from
Engineering Dynamics Inc. The model includes the following items:

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• The tower.
• The transition piece including overlap piece
• The structure below the transition piece (monopile or tripod)
• A pile-soil interaction model beneath the mud line

The structural analysis was performed to API RP-2A [7] for general structural items and
Germanischer Lloyds Rules and Guidelines for Wind Energy [5].

The material assumed for all structures is steel grade S355 with the following properties.
2
Young’s Modulus 205 kN/mm
3
Density 7850 kg/m
Yield Stress 355MPa if less than 40mm thickness
345 MPa if exceeding 40mm thickness
Poisson’s coefficient 0.3

Figure 2-1 shows the generic layouts of the two structural types used in the analysis.

Figure 2-1: General view of monopile and tripod model (Not to scale)

Tripod Monopile

2.3 Loads
The structure is subject to four primary sources of load:

1. Turbine hub loads from the weight of the nacelle and the wind load on the rotors

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2. Wind loads on the tower

3. Wave loads on the submerged structure
4. Current loads on the submerged structure

The turbine hub loads are obtained from manufacturers data for nacelle weight and
maximum wind-force (see Table 3-2). This load is applied as a point load at the top of the
tower for static analysis and as a point mass for eigenvalue analysis. The wind loads on the
tower are based on a 20-year return period extreme wind speeds obtained from data
recorded at Lynn & Inner Dowsing (L&ID) project [3], a wind farm off the coast of Kent. The
software is used to automatically calculate the loads arising from wave and current hitting
the submerged structure with due allowance for marine growth.

2.4 Structural Design

The way the structural masses have been modeled in this study is illustrated in Figure 2-2
below.

Figure 2-2: Structural Masses of Analysed Model Structures

1
1

STRUCTURAL MASSES

1. HUB
2 2. MAST/TOWER
3. TRANSITION
PIECE
2
4. PILE
5. TRIPOD

Sketch ‘Not to Scale’

4 4 4

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2.4.1 Monopile
The elements above the mud line (tower, transition piece and pile continuation) are designed
to just have sufficient strength and stiffness accept the nacelle and environmental load
without failing. There are additional geometric conditions that are maintained including space
for grouting and minimum diameters to support the nacelle. The pile continuation above the
mud line is assumed to maintain the same properties as the pile below the mud line.

2.4.2 Tripod
There are a number of possible tripod systems that have been proposed. The tripod solution
used for the analysis is composed of three piles that are tied to each other and the bottom of
the mast by 6 plan braces. A further 3 braces connect the three piles with a point further up
the tower and just below the bottom of the transition piece. Note that the bottom of the tower
in this solution terminates just above the mud line and is not part of the foundation support.
To reduce the wave load attracted by the tripod joint, this point is kept outside a zone 4m
below the mean water level. The braces all subtend an angle of 120-degrees when viewed in
plan.

The tripod solution is shown in Figure 2-3.

Figure 2-3: Tripod System

As for the monopile solution the elements comprising the tripod are also designed to just
have sufficient strength and stiffness to support the applied loading.

2.5 Piles
The piles for both monopile and tripod are designed in the following way:

• An initial structural analysis gives an estimated required diameter of pile for

normal thickness tubes.
• The required level of soil adhesion then defines the required penetration of the
pile.
• The thickness of the pile is then determined from the minimum required to resist
the pile forces given the pile diameter and penetration and mud line forces.

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3.0 DESIGN PARAMETERS

For this parametric study the design parameters have been selected based on those used in
previous offshore wind farm projects in the UK.

3.1 WTG Characteristics

The wind turbine generators (WTG) that have been used in this study are industry standard
WTGs. Their selection has been done on the basis of covering small, medium and large
WTGs commonly used in the current market. The higher the WTG capacity, the heavier it
becomes and the greater wind load is attracted on the hub due to its greater swept area.
WTG key parameters used in this study are listed below in Table 3-1.

Table 3-1: WTG data

WTG Rotor Rotor Speed Swept Area Hub Load (kN) / Weight (Te) Manufacturer
Dia (m) (rpm) (m^2) Wind on Blades
2.0MW 80 9 – 19 5027 51.55 104 Vestas
3.6MW 111 8.5 – 15.3 9677 92.21 142.5 GE
5.0MW 125 6.9 – 12.1 12272 125.85 220 ~

3.2 Structural Data

The minimum air-draft (i.e. clearance between bottom of blades to LAT) has been taken as
30m based on practice used for London Array project [4]. This policy fixes the distance
between the hub and the waterline and mud line for a given WTG. The same lengths are
used for the transition piece at all water depths. Therefore the only geometric variable is the
length of the pile extension above mud line or, for the case of the tripod, it’s height.

The overlap between pile and transition piece is taken as 6m, about 2 pile diameters based
on Thanet Sand’s transition piece design.

The structural parametric ranges that were used are shown in Table 3-2.

Table 3-2: Structural Parametric Ranges

Monopile Transition Piece (TP) Tower
WTG
Dia (m) WT (mm) Dia (m) WT (mm) Height (m) Height (m)
16 for 5m WD
2.0MW 3.0 – 4.5 35 – 60 3.23 – 4.73 30 – 40 60
25 for other WD
16 for 5m WD
3.6MW 3.0 – 3.5 45 – 75 3.73 – 4.23 40 65
25 for other WD
16 for 5m WD
5.0MW 4.0 – 4.5 55 – 80 4.23 – 4.73 40 – 50 75
25 for other WD
Notes:
Diameters are at 0.5m intervals. Wall thicknesses (WT) are at 5mm intervals. TP outer diameter includes grouting annulus.

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3.3 Environmental Data

Marine Growth
Marine growth has been assumed as 200mm from LAT to mud line with a density of
250kg/m3.

Scour
Scour has not been directly taken into account in this study. However for the monopile
solution its structural effect is limited to an increase in effective water depth. The effects of
scour on the tripod solution are subtler and require further study.

Wave and Current

Generally a wave height of 10.6m has been taken based on data from Scroby Sands project
[2]. A wave height of 4.1m was used for the 5m water depth cases due to the limitations on
the height of a breaking wave.
A block current of 0.8m/s is used, taken as the maximum current value that is the average
current value used around UK offshore region.

The environmental data that were used in this study are shown in Table 3-3.

Table 3-3: Environmental Parameters

Water Depth Tidal Current Wave Period Wave Height Wind Speed Marine Growth
50 years return
(-mCD) (m/s) (sec) (m) (m/s) (mm)
5 0.8 7.6 4.1 35 200
15 – 45 0.8 9.6 10.6 35 200

3.4 Soil Parameters

To obtain an estimate of the effect of differing soil parameters, generic “weak” and “strong”
soil profiles are used in comparative analyses. To obtain realistic values for the soil
parameters, the geotechnical data used in this study were based on survey information
taken for Thanet Sands project and modified to develop sufficiently different “weak” and
“strong” soil conditions.

Table 3-4 presents the soil parameters used in this study.

"W eak" Profile "Strong " Profile

Coeff. Lat. Subg rade Friction Coeff. Lat. E arth Subg rade Friction
Stratum Stratum
Type E arth Press Density Ang le Type Press Density Ang le
Depth (m ) Depth (m )
M Pa deg . M Pa deg .
Sand 2-4 0.6 0.61 20 Silty Sand 0-1.6 0.8 0.92 20
G ravel 4-14 0.6 0.69 20 Silty Sand 1.6-10 0.8 0.92 20
G ravel 14-24 0.6 0.69 20
Chalk 10-50 0.8 0.97 15
Clay 24-44 0.6 0.69 -

Table 3-4: Soil Parameters

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4.0 RESULTS SUMMARY

4.1 Weights
Table 4-1 shows the foundation weights required to support the three different WTGs at
different water depths and soil conditions.

Table 4-1: Summary Results for Structural Weights

SUMMARY - MONOPILE

Water Depth (m)

Soil Type WTG Weights (Te)
5 15 25 35 45

Pile Total 66.5 129.6 191.6 267.6 370.6

2.0 MW Steel Total Weight 104.4 209.3 271.3 370.8 486.2
Total Foundation Weight 110.1 215.5 277.5 377.5 493.7
Pile Total 107.3 189.8 285.5 378.2 515.1
Strong 3.6 MW Steel Total Weight 165.5 293.1 388.8 481.5 618.4
Total Foundation Weight 171.3 299.8 395.4 488.2 625.1
Pile Total 160.4 271.2 362.3 481.5 636.2
5.0 MW Steel Total Weight 226.5 400.0 492.2 625.7 780.4
Total Foundation Weight 233.2 405.8 499.2 632.2 786.9
Pile Total 74.2 149.4 212.6 284.9 381.5
2.0 MW Steel Total Weight 112.0 229.1 292.3 375.3 472.0
Total Foundation Weight 117.7 235.4 298.5 402.0 498.6
Pile Total 119.0 213.9 291.3 390.8 529.6
Weak 3.6 MW Steel Total Weight 177.2 317.2 394.6 494.1 632.9
Total Foundation Weight 183.1 323.8 401.3 500.8 639.6
Pile Total 181.8 291.5 417.4 531.7 573.2
5.0 MW Steel Total Weight 256.1 420.3 546.1 675.8 732.8
Total Foundation Weight 262.3 426.1 551.9 682.3 765.1

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SUMMARY - MONOPILE - DYNAMIC

Pile Total 74.2 149.4 212.6 284.9 381.5

2.0 MW Steel Total Weight 112.0 229.1 292.3 375.3 472.0
Total Foundation Weight 117.7 235.4 298.5 402.0 498.6
Pile Total 102.3 199.6 296.1 557.7 746.9
Weak 3.6 MW Steel Total Weight 160.5 302.8 411.7 673.3 874.9
Total Foundation Weight 166.4 309.5 419.2 680.8 883.2
Pile Total 181.8 312.0 390.8 529.7 884.3
5.0 MW Steel Total Weight 256.1 440.7 534.9 689.3 1043.9
Total Foundation Weight 262.3 446.5 541.4 696.5 1051.1

SUMMARY - TRIPOD

Pile Total ~ 111.9 78.2 53.6 62.8

Tripod Weight ~ 152.0 210.0 282.3 390.8
Weak 3.6 MW
Steel Total Weight ~ 367.6 391.9 439.6 557.3
Total Foundation Weight ~ 400.1 424.5 472.2 589.9

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4.2 Loads
Table 4-2 illustrates the key loading output for each one of the analyses that have been
carried out.

Table 4-2: Overturning Moments (OTM) & Base Shears (BS)

Water Depth (m)
5 15 25 35 45
OTM (kNm) 44104 68595 80760 94011 107461
2.0MW BS-MDL (kN) 828 1718 1729 1939 1734
BS-HUB (kN) 506 506 506 506 506
OTM (kNm) 83448 118787 136741 155738 175794
Weak 3.6MW BS-MDL (kN) 1352 2401 2412 2411 2426
BS-HUB (kN) 905 905 905 905 905
OTM (kNm) 125631 166618 188084 216800 248738
5.0MW BS-MDL (kN) 1775 2752 2763 3044 3243
BS-HUB (kN) 1235 1235 1235 1235 1235
OTM (kNm) 44104 68595 80760 99473 122914
2.0MW BS-MDL (kN) 828 1718 1729 1949 2207
BS-HUB (kN) 506 506 506 506 506
OTM (kNm) 83448 118787 136741 155738 175794
Strong 3.6MW BS-MDL (kN) 1352 2401 2412 2411 2426
BS-HUB (kN) 905 905 905 905 905
OTM (kNm) 125631 166618 192791 216800 242231
5.0MW BS-MDL (kN) 1775 2752 2999 3044 3022
BS-HUB (kN) 1235 1235 1235 1235 1235
OTM (kNm) ~ 118204 131618 153392 176568
Tripod 3.6MW BS-MDL (kN) ~ 3905 2793 2851 2827
BS-HUB (kN) ~ 905 905 905 905
Notes
BS – HUB: Base Shear at hub, or wind load at rotors
BS – MDL: Base Shear at mud line. Is the sum of wind load at rotors + wind load at tower + wave & current load at
substructure.

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4.3 Input & Output Data Tables

The following tables present, for each individual analysis case, input structural and geometric
data, and output data such as loads and deflections.

Table 4-3: Structural Weights for a 2.0MW WTG monopile – Strong Soil

2.0 MW WTG - Strong Soil

Water Depth (m) 5 15 25 35 45

Superstructure
WTG Weight (Te) 104.0 104.0 104.0 104.0 104.0
Mast/Tower Weight (Te) 72.8 72.8 72.8 72.8 72.8
Structure UC 0.98 0.98 0.98 0.98 0.98
Pile
Pile Dia (m) 3.0 3.5 3.5 4.0 4.5
Pile WT (m) 0.035 0.040 0.045 0.045 0.045
Cross Sectional Area (m^2) 0.326 0.435 0.488 0.559 0.629
Pile-Soil UC 0.92 0.98 0.99 0.94 0.92
Transition Piece
TP Dia (m) 3.23 3.73 3.73 4.23 4.73
TP WT (m) 0.030 0.035 0.035 0.040 0.040
TP Cross Sectional Area (m^2) 0.301 0.4061 0.4061 0.5263 0.5891
TP Length (incl. Overlap) (m) 16 25 25 25 25
TP-Pile Overlap (m) 6 6 6 6 6
Grouting/Overlap
Grout WT (m) 0.085 0.08 0.08 0.075 0.075
Grouted Cross Sectional Area (m^2) 0.406 0.4446 0.4446 0.4754 0.5343
Heights
Hub to Tr.P (m) 60 60 60 60 60
Top of Pile to Mud line (m) 9 17 27 37 47
Hub to Mud line (m) 79 96 106 116 126
Loads
Hub Load (kN) 505.7 505.7 505.7 505.7 505.7
Mast Wind Load (kN) 68 79 79 82 84
Deflections
Hub (mm) 2690 3130 3510 3560 3509
Pile Head (mm) 92 95 74 85 73
Pile Tip (mm) 25 24 7 22 15
Penetration
Strong Soil 17 21 23 24 28
Weights
Pile above Mud line (Te) 23.0 58.0 103.5 162.3 232.2
Pile below Mud line (Te) 43.5 71.6 88.1 105.3 138.3
Total Pile Weight (Te) 66.5 129.6 191.6 267.6 370.6
Weight of Transition Piece (Te) 37.9 79.7 79.7 103.3 115.6
Total Steel Weight (Te) 104.4 209.3 271.3 370.8 486.2
Weight of Grout/Overlap (Te) 5.7 6.2 6.2 6.7 7.5
TOTAL FOUNDATION WEIGHT (Te) 110.1 215.5 277.5 377.5 493.7

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Table 4-4: Structural Weights for a 3.6MW WTG monopile – Strong Soil

3.6 MW WTG - Strong Soil

Water Depth (m) 5 15 25 35 45

Superstructure
WTG Weight (Te) 142.5 142.5 142.5 142.5 142.5
Mast/Tower Weight (Te) 121.3 121.3 121.3 121.3 121.3
Structure UC 0.98 0.98 0.98 0.98 0.98
Pile
Pile Dia (m) 3.5 4.0 4.0 4.0 4.0
Pile WT (m) 0.045 0.050 0.060 0.065 0.075
Cross Sectional Area (m^2) 0.488 0.620 0.742 0.803 0.924
Pile-Soil UC 0.98 0.98 0.92 0.96 0.98
Transition Piece
TP Dia (m) 3.73 4.23 4.23 4.23 4.23
TP WT (m) 0.040 0.040 0.040 0.040 0.040
TP Cross Sectional Area (m^2) 0.4635 0.5263 0.5263 0.5263 0.5263
TP Length (incl. Overlap) (m) 16 25 25 25 25
TP-Pile Overlap (m) 6 6 6 6 6
Grouting/Overlap
Grout WT (m) 0.075 0.075 0.075 0.075 0.075
Grouted Cross Sectional Area (m^2) 0.4165 0.4754 0.4754 0.4754 0.4754
Heights
Hub to Tr.P (m) 65 65 65 65 65
Top of Pile to Mud line (m) 9 17 27 37 47
Hub to Mud line (m) 84 101 111 121 131
Loads
Hub Load (kN) 905 905 905 905 905
Mast Wind Load (kN) 104 146 146 146 146
Deflections
Hub (mm) 3150 3617 4696 5550 5964
Pile Head (mm) 181 155 225 251 224
Pile Tip (mm) 57 51 84 99 83
Penetration
Strong Soil 19 22 22 23 24
Weights
Pile above Mud line (Te) 34.5 82.7 157.3 233.2 341.0
Pile below Mud line (Te) 72.8 107.1 128.2 145.0 174.1
Total Pile Weight (Te) 107.3 189.8 285.5 378.2 515.1
Weight of Transition Piece (Te) 58.204 103.27 103.27 103.27 103.27
Total Steel Weight (Te) 165.5 293.1 388.8 481.5 618.4
Weight of Grout/Overlap (Te) 5.8 6.7 6.7 6.7 6.7
TOTAL FOUNDATION WEIGHT (Te) 171.3 299.8 395.4 488.2 625.1

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Table 4-5: Structural Weights for a 5.0MW WTG monopile – Strong Soil

5.0 MW WTG - Strong Soil

Water Depth (m) 5 15 25 35 45

Superstructure
WTG Weight (Te) 220 220 220 220 220
Mast/Tower Weight (Te) 201.1 201.1 201.1 201.1 201.1
Structure UC 0.98 0.98 0.98 0.98 0.98
Pile
Pile Dia (m) 4.0 4.0 4.5 4.5 4.5
Pile WT (m) 0.055 0.070 0.065 0.070 0.080
Cross Sectional Area (m^2) 0.681 0.864 0.905 0.974 1.110
Pile-Soil UC 0.92 0.95 0.95 0.98 0.94
Transition Piece
TP Dia (m) 4.23 4.23 4.73 4.73 4.73
TP WT (m) 0.040 0.050 0.045 0.050 0.050
TP Cross Sectional Area (m^2) 0.5263 0.6563 0.662 0.7348 0.7348
TP Length (incl. Overlap) (m) 16 25 25 25 25
TP-Pile Overlap (m) 6 6 6 6 6
Grouting/Overlap
Grout WT (m) 0.075 0.065 0.07 0.065 0.065
Grouted Cross Sectional Area (m^2) 0.4754 0.4115 0.4984 0.4625 0.4625
Heights
Hub to Tr.P (m) 75 75 75 75 75
Top of Pile to Mud line (m) 9 17 27 37 47
Hub to Mud line (m) 94 111 121 131 141
Loads
Hub Load (kN) 1235 1235 1235 1235 1235
Mast Wind Load (kN) 150 167 171 171 171
Deflections
Hub (mm) 3839 5708 5279 5411 6374
Pile Head (mm) 195 310 236 186 234
Pile Tip (mm) 68 112 94 70 93
Penetration
Strong Soil 21 23 24 26 26
Weights
Pile above Mud line (Te) 48.1 115.3 191.8 282.8 409.6
Pile below Mud line (Te) 112.3 155.9 170.5 198.7 226.6
Total Pile Weight (Te) 160.4 271.2 362.3 481.5 636.2
Weight of Transition Piece (Te) 66.1 128.8 129.9 144.2 144.2
Total Steel Weight (Te) 226.5 400.0 492.2 625.7 780.4
Weight of Grout/Overlap (Te) 6.7 5.8 7.0 6.5 6.5
TOTAL FOUNDATION WEIGHT (Te) 233.2 405.8 499.2 632.2 786.9

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Table 4-6: Structural Weights for a 2.0MW WTG monopile – Weak Soil

2.0 MW WTG - Weak Soil

Water Depth (m) 5 15 25 35 45

Superstructure
WTG Weight (Te) 220 220 220 220 220
Mast/Tower Weight (Te) 72.8 72.8 72.8 72.8 72.8
Structure UC 0.97 0.97 0.97 0.97 0.97
Pile
Pile Dia (m) 3.0 3.5 3.5 3.5 3.5
Pile WT (m) 0.035 0.045 0.050 0.055 0.060
Cross Sectional Area (m^2) 0.326 0.488 0.542 0.595 0.648
Pile-Soil UC 0.92 0.94 0.96 0.92 0.90
Transition Piece
TP Dia (m) 3.23 3.73 3.73 4.23 4.23
TP WT (m) 0.030 0.035 0.035 0.035 0.035
TP Cross Sectional Area (m^2) 0.3014 0.4061 0.4061 0.461 0.461
TP Length (incl. Overlap) (m) 16 25 25 25 25
TP-Pile Overlap (m) 6 6 6 6 6
Grouting/Overlap
Grout WT (m) 0.085 0.08 0.08 0.08 0.08
Grouted Cross Sectional Area (m^2) 0.406 0.4446 0.4446 1.8988 1.8988
Heights
Hub to Tr.P (m) 60 60 60 60 60
Top of Pile to Mud line (m) 9 17 27 37 47
Hub to Mud line (m) 79 96 106 116 126
Loads
Hub Load (kN) 505.7 505.7 505.7 505.7 505.7
Mast Wind Load (kN) 68 79 79 82 84
Deflections
Hub (mm) 2386 3354 3941 4594 5580
Pile Head (mm) 93 89 71 82 71
Pile Tip (mm) 26 23 7 22 15
Penetration
Strong Soil 20 22 23 24 28
Weights
Pile above Mud line (Te) 23.0 65.1 114.8 172.8 239.1
Pile below Mud line (Te) 51.2 84.3 97.8 112.1 142.4
Total Pile Weight (Te) 74.2 149.4 212.6 284.9 381.5
Weight of Transition Piece (Te) 37.9 79.7 79.7 90.5 90.5
Total Steel Weight (Te) 112.0 229.1 292.3 375.3 472.0
Weight of Grout/Overlap (Te) 5.7 6.2 6.2 26.7 26.7
TOTAL FOUNDATION WEIGHT (Te) 117.7 235.4 298.5 402.0 498.6

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Table 4-7: Structural Weights for a 3.6MW WTG monopile – Weak Soil

3.6 MW WTG - Weak Soil

Water Depth (m) 5 15 25 35 45

Superstructure
WTG Weight (Te) 142.5 142.5 142.5 142.5 142.5
Mast/Tower Weight (Te) 121.3 121.3 121.3 121.3 121.3
Structure UC 0.98 0.98 0.98 0.98 0.98
Pile
Pile Dia (m) 3.5 4.0 4.0 4.0 4.0
Pile WT (m) 0.050 0.055 0.060 0.065 0.075
Cross Sectional Area (m^2) 0.542 0.681 0.742 0.803 0.924
Pile-Soil UC 0.90 0.92 0.94 0.98 0.93
Transition Piece
TP Dia (m) 3.73 4.23 4.23 4.23 4.23
TP WT (m) 0.040 0.040 0.040 0.040 0.040
TP Cross Sectional Area (m^2) 0.4635 0.5263 0.5263 0.5263 0.5263
TP Length (incl. Overlap) (m) 16 25 25 25 25
TP-Pile Overlap (m) 6 6 6 6 6
Grouting/Overlap
Grout WT (m) 0.075 0.075 0.075 0.075 0.075
Grouted Cross Sectional Area (m^2) 0.4165 0.4754 0.4754 0.4754 0.4754
Heights
Hub to Tr.P (m) 65 65 65 65 65
Top of Pile to Mud line (m) 9 17 27 37 47
Hub to Mud line (m) 84 101 111 121 131
Loads
Hub Load (kN) 905 905 905 905 905
Mast Wind Load (kN) 129 146 146 146 146
Deflections
Hub (mm) 2311 3291 3497 5281 6193
Pile Head (mm) 72 124 86 240 289
Pile Tip (mm) 8 24 13 70 93
Penetration
Soft Soil 19 23 23 25 26
Weights
Pile above Mud line (Te) 38.3 90.9 157.3 233.2 341.0
Pile below Mud line (Te) 80.8 123.0 134.0 157.6 188.6
Total Pile Weight (Te) 119.0 213.9 291.3 390.8 529.6
Weight of Transition Piece (Te) 58.204 103.27 103.27 103.27 103.27
Total Steel Weight (Te) 177.2 317.2 394.6 494.1 632.9
Weight of Grout/Overlap (Te) 5.8 6.7 6.7 6.7 6.7
TOTAL FOUNDATION WEIGHT (Te) 183.1 323.8 401.3 500.8 639.6

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Table 4-8: Structural Weights for a 5.0MW WTG monopile – Weak Soil

5.0 MW WTG - Weak Soil

Water Depth (m) 5 15 25 35 45

Superstructure
WTG Weight (Te) 104.0 104.0 104.0 104.0 104.0
Mast/Tower Weight (Te) 201.1 201.1 201.1 201.1 201.1
Structure UC 0.98 0.98 0.98 0.98 0.98
Pile
Pile Dia (m) 4.0 4.0 4.0 4.5 4.5
Pile WT (m) 0.055 0.070 0.080 0.075 0.070
Cross Sectional Area (m^2) 0.681 0.864 0.985 1.042 0.974
Pile-Soil UC 0.95 0.98 0.94 0.94 0.94
Transition Piece
TP Dia (m) 4.23 4.23 4.23 4.73 5.23
TP WT (m) 0.045 0.050 0.050 0.050 0.050
TP Cross Sectional Area (m^2) 0.5913 0.6563 0.6563 0.7348 0.8133
TP Length (incl. Overlap) (m) 16 25 25 25 25
TP-Pile Overlap (m) 6 6 6 6 6
Grouting/Overlap
Grout WT (m) 0.07 0.065 0.065 0.065 0.315
Grouted Cross Sectional Area (m^2) 0.4434 0.4115 0.4115 0.4625 2.3034
Heights
Hub to Tr.P (m) 75 75 75 75 75
Top of Pile to Mud line (m) 9 17 27 37 47
Hub to Mud line (m) 94 111 121 131 141
Loads
Hub Load (kN) 1235 1235 1235 1235 1235
Mast Wind Load (kN) 150 167 167 171 171
Deflections
Hub (mm) 2938 5213 6021 5688 6215
Pile Head (mm) 84 273 315 245 274
Pile Tip (mm) 12 85 106 89 107
Penetration
Strong Soil 25 26 27 28 28
Weights
Pile above Mud line (Te) 48.1 115.3 208.7 302.6 359.2
Pile below Mud line (Te) 133.7 176.3 208.7 229.0 214.0
Total Pile Weight (Te) 181.8 291.5 417.4 531.7 573.2
Weight of Transition Piece (Te) 74.3 128.8 128.8 144.2 159.6
Total Steel Weight (Te) 256.1 420.3 546.1 675.8 732.8
Weight of Grout/Overlap (Te) 6.2 5.8 5.8 6.5 32.3
TOTAL FOUNDATION WEIGHT (Te) 262.3 426.1 551.9 682.3 765.1

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Table 4-9: Structural Weights for a 2.0MW WTG monopile – Weak Soil

2.0 MW WTG - Weak Soil - Dynamic

Water Depth (m) 5 15 25 35 45

Superstructure
WTG Weight (Te) 220 220 220 220 220
Mast/Tower Weight (Te) 72.8 72.8 72.8 72.8 72.8
Structure UC 0.97 0.97 0.97 0.97 0.97
Pile
Pile Dia (m) 3.0 3.5 3.5 3.5 3.5
Pile WT (m) 0.035 0.045 0.050 0.055 0.060
Cross Sectional Area (m^2) 0.326 0.488 0.542 0.595 0.648
Pile-Soil UC 0.92 0.94 0.96 0.92 0.90
Transition Piece
TP Dia (m) 3.23 3.73 3.73 4.23 4.23
TP WT (m) 0.030 0.035 0.035 0.035 0.035
TP Cross Sectional Area (m^2) 0.30144 0.4061 0.4061 0.461 0.461
TP Length (incl. Overlap) (m) 16 25 25 25 25
TP-Pile Overlap (m) 6 6 6 6 6
Grouting/Overlap
Grout WT (m) 0.085 0.08 0.08 0.08 0.08
Grouted Cross Sectional Area (m^2) 0.40602 0.4446 0.4446 1.8988 1.8988
Heights
Hub to Tr.P (m) 60 60 60 60 60
Top of Pile to Mud line (m) 9 17 27 37 47
Hub to Mud line (m) 79 96 106 116 126
Loads
Hub Load (kN) 505.7 505.7 505.7 505.7 505.7
Mast Wind Load (kN) 68 79 79 82 84
Deflections
Hub (mm) 2386 3354 3941 4594 5580
Pile Head (mm) 93 89 71 82 71
Pile Tip (mm) 26 23 7 22 15
Penetration
Strong Soil 20 22 23 24 28
Dynamic Response
Manufacturer's Natural Period (sec) 3.1 3.1 3.1 3.1 3.1
Manufacturer's Natural Frequency (Hz) 0.32 0.32 0.32 0.32 0.32
Natural Period (sec)
Natural Frequency (Hz)
Weights
Pile above Mud line (Te) 23.0 65.1 114.8 172.8 239.1
Pile below Mud line (Te) 51.2 84.3 97.8 112.1 142.4
Total Pile Weight (Te) 74.2 149.4 212.6 284.9 381.5
Weight of Transition Piece (Te) 37.9 79.7 79.7 90.5 90.5
Total Steel Weight (Te) 112 229 292 375 472
Weight of Grout/Overlap (Te) 5.7 6.2 6.2 26.7 26.7
TOTAL FOUNDATION WEIGHT (Te) 117.7 235.4 298.5 402.0 498.6

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Table 4-10: Structural Weights for a 3.6MW WTG monopile – Weak Soil Dynamic

3.6 MW WTG - Weak Soil - Dynamic

Water Depth (m) 5 15 25 35 45

Superstructure
WTG Weight (Te) 142.5 142.5 142.5 142.5 142.5
Mast/Tower Weight (Te) 121.3 121.3 121.3 121.3 121.3
Structure UC 0.97 0.97 0.97 0.97 0.97
Pile
Pile Dia (m) 3.5 4.0 4.5 4.5 5.0
Pile WT (m) 0.040 0.050 0.050 0.080 0.080
Cross Sectional Area (m^2) 0.435 0.620 0.699 1.110 1.236
Pile-Soil UC 0.90 0.92 0.94 0.98 0.93
Transition Piece
TP Dia (m) 3.73 4.23 4.73 4.73 5.23
TP WT (m) 0.040 0.040 0.040 0.040 0.040
TP Cross Sectional Area (m^2) 0.463 0.526 0.589 0.589 0.651
TP Length (incl. Overlap) (m) 16 25 25 25 25
TP-Pile Overlap (m) 6 6 6 6 6
Grouting/Overlap
Grout WT (m) 0.075 0.075 0.075 0.075 0.075
Grouted Cross Sectional Area (m^2) 0.416 0.475 0.534 0.534 0.593
Heights
Hub to Tr.P (m) 65 65 65 65 65
Top of Pile to Mud line (m) 9 17 27 37 47
Hub to Mud line (m) 84 101 111 121 131
Loads
Hub Load (kN) 905 905 905 905 905
Mast Wind Load (kN) 129 146 146 146 146
Deflections
Hub (mm) 2386 3354 3941 4594 5580
Pile Head (mm) 72 124 86 240 289
Pile Tip (mm) 8 24 13 70 93
Penetration
Soft Soil 21 24 27 27 30
Dynamic Response
Manufacturer's Natural Period (sec) 3.9 3.9 3.9 3.9 3.9
Manufacturer's Natural Frequency (Hz) 0.26 0.26 0.26 0.26 0.26
Natural Period (sec) 3.5 3.9 3.9 3.9 3.9
Natural Frequency (Hz) 0.29 0.26 0.26 0.26 0.26
Weights
Pile above Mud line (Te) 30.7 82.7 148.1 322.4 455.9
Pile below Mud line (Te) 71.6 116.8 148.1 235.3 291.0
Total Pile Weight (Te) 102.3 199.6 296.1 557.7 746.9
Weight of Transition Piece (Te) 58.2 103.3 115.6 115.6 127.9
Total Steel Weight (Te) 161 303 412 673 875
Weight of Grout/Overlap (Te) 5.8 6.7 7.5 7.5 8.3
TOTAL FOUNDATION WEIGHT (Te) 166.4 309.5 419.2 680.8 883.2

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Table 4-11: Dynamic Structural Weights for a 5.0MW WTG monopile

5.0 MW WTG - Weak Soil - Dynamic

Water Depth (m) 5 15 25 35 45

Superstructure
WTG Weight (Te) 104.0 104.0 104.0 104.0 104.0
Mast/Tower Weight (Te) 201.1 201.1 201.1 201.1 201.1
Structure UC 0.98 0.98 0.98 0.98 0.98
Pile
Pile Dia (m) 4.0 4.0 4.5 5.0 5.0
Pile WT (m) 0.055 0.075 0.065 0.065 0.095
Cross Sectional Area (m^2) 0.681 0.924 0.905 1.007 1.463
Pile-Soil UC 0.95 0.98 0.94 0.94 0.94
Transition Piece
TP Dia (m) 4.23 4.23 4.73 5.23 5.23
TP WT (m) 0.045 0.050 0.050 0.050 0.050
TP Cross Sectional Area (m^2) 0.59134 0.6563 0.7348 0.8133 0.8133
TP Length (incl. Overlap) (m) 16 25 25 25 25
TP-Pile Overlap (m) 6 6 6 6 6
Grouting/Overlap
Grout WT (m) 0.07 0.065 0.065 0.065 0.065
Grouted Cross Sectional Area (m^2) 0.44345 0.4115 0.4625 0.5136 0.5136
Heights
Hub to Tr.P (m) 75 75 75 75 75
Top of Pile to Mud line (m) 9 17 27 37 47
Hub to Mud line (m) 94 111 121 131 141
Loads
Hub Load (kN) 1235 1235 1235 1235 1235
Mast Wind Load (kN) 150 167 167 171 171
Deflections
Hub (mm) 2938 5213 6021 5688 6215
Pile Head (mm) 84 273 315 245 274
Pile Tip (mm) 12 85 106 89 107
Penetration
Strong Soil 25 26 28 30 30
Dynamic Response
Manufacturer's Natural Period (sec) 4.9 4.9 4.9 4.9 4.9
Manufacturer's Natural Frequency (Hz) 0.20 0.20 0.20 0.20 0.20
Natural Period (sec) 4.4 4.9 4.9 4.9 4.9
Natural Frequency (Hz) 0.23 0.20 0.20 0.20 0.20
Weights
Pile above Mud line (Te) 48.1 123.3 191.8 292.5 539.8
Pile below Mud line (Te) 133.7 188.6 198.9 237.2 344.5
Total Pile Weight (Te) 181.8 312.0 390.8 529.7 884.3
Weight of Transition Piece (Te) 74.3 128.8 144.2 159.6 159.6
Total Steel Weight (Te) 256 441 535 689 1044
Weight of Grout/Overlap (Te) 6.2 5.8 6.5 7.2 7.2
TOTAL FOUNDATION WEIGHT (Te) 262.3 446.5 541.4 696.5 1051.1

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Table 4-12: Structural Weights for Tripods

3.6 MW WTG - Weak Soil - Tripod

Water Depth (m) 5 15 25 35 45

Superstructure
WTG Weight (Te) ~ 142.5 142.5 142.5 142.5
Mast/Tower Weight (Te) ~ 121.3 121.3 121.3 121.3
Structure UC ~ 0.98 0.98 0.98 0.98
Pile
Pile Dia (m) ~ 1.27 1.27 1.27 1.27
Pile WT (m) ~ 0.035 0.025 0.020 0.020
Cross Sectional Area (m^2) ~ 0.136 0.098 0.079 0.079
Pile-Soil UC ~ 0.63 0.66 0.68 0.99
Transition Piece
TP Dia (m) ~ 3.115 3.115 3.115 3.115
TP WT (m) ~ 0.055 0.055 0.055 0.055
TP Cross Sectional Area (m^2) ~ 0.5285 0.5285 0.5285 0.5285
TP Length (incl. Overlap) (m) ~ 25 25 25 25
TP-Pile Overlap (m) ~ 6 6 6 6
Grouting/Overlap
Grout WT (m) ~ 0.8675 0.8675 0.8675 0.8675
Grouted Cross Sectional Area (m^2) ~ 2.3205 2.3205 2.3205 2.3205
Heights
Hub to Tr.P (m) ~ 65 65 65 65
Top of Pile to Mud line (m) ~ 17 27 37 47
Hub to Mud line (m) ~ 101 111 121 131
Loads
Hub Load (kN) ~ 905 905 905 905
Mast Wind Load (kN) ~ 146 146 146 146
Deflections
Hub (mm) ~ 2885 3020 3201 3342
Pile Head (mm) ~ 34 27 26 24
Pile Tip (mm) ~ 0 0 0 0
Penetration
Soft Soil ~ 35 34 29 34
Weights
Tripod Weight (Te) ~ 152.0 210.0 282.3 390.8
Pile below Mud line (Te) ~ 111.9 78.2 53.6 62.8
Total Structural Weight (Te) ~ 263.9 288.2 335.9 453.6
Weight of Transition Piece (Te) ~ 103.7 103.7 103.7 103.7
Total Steel Weight (Te) ~ 367.6 391.9 439.6 557.3
Weight of Grout/Overlap (Te) ~ 32.6 32.6 32.6 32.6
TOTAL FOUNDATION WEIGHT (Te) ~ 400.1 424.5 472.2 589.9

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5.0 DISCUSSION OF RESULTS

There are numerous factors influencing the choice of structure type (foundation) for a given
turbine type and water depth. Part of this study’s objective is to quantify the important
influences (including environmental, geotechnical and structural trends and limitations) on
the choice of foundation type.
5.1 Monopiles
Structurally a monopile is essentially a cantilever with a combination of tip point load and
distributed load along its length supported by non-linear springs where it is buried. As the
water depth increases the length of the cantilever also increases so that predefined air-draft
space can be maintained. The different types of turbine impose different hub heights, hub
loads and natural frequency demands on the structure due to the size and operating periods
of the rotors.

The study showed that for each type of turbine the weight and size of monopile increases
with water depth. However for each turbine there was a point where the weight started to
increase more rapidly than before. This point was generally found to be the point where
considerations of natural frequency started to govern rather than stress in the pile. Stress in
a cantilever with a tip load is linearly related to increases in length. However the natural
frequency of such a structure, ignoring self weight is given by the following expression:

1.732 EIg
2π Wl 3
The natural frequency of a monopile is therefore approximately related to length by a
function of order 1.5 and therefore monopile weight will increase more rapidly where it is
governed by natural frequency rather than stress.

There are also practical limitations to the size of monopiles that can be installed at time of
writing. These are assumed to be 4.5m diameter and 80mm thickness though in future there
will be developments in equipment. Notwithstanding improvements in technology, if these
limits are adhered to the largest water depth a 3.6MW turbine can be installed in is 35m. For
the 5.0MW the limit is 25m.

Even for depths of water within the above limits, the monopile may not be lightest or
cheapest option but is at least a feasible solution assuming the size limits of 4.5m diameter
and 80mm are adhered to.

5.2 Tripods
There are a number of variations on the theme of the tripod solution including “star” shapes,
braced monopiles but the version chosen for this analysis has three identical piles supporting
the bottom of the tower. Structurally the tripod offers the advantage over the monopile of
having a large footprint in which to resist the overturning moment, resolving the overturning
moment into a system of vertical forces that also resist the base shear. There are also
bracing members that reduce the unsupported lengths of the tower and substructure.

The tripod is less efficient at water depths below 10m for the following reasons:

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• Practical angles of the braces limit the possible spacing between piles and reduce
the advantage of the tripod in converting overturning moment into relatively small
vertical forces.
• The practical angles of the braces with the need to maximise pile spacing produces
tripod members close to the water line that attract large wave and current load.

As the water depth increases the use of practical bracing angles (30 to 60 degrees)
increases the footprint and spans of the bracing members. Since the critical buckling load of
a strut increases with the square of its length, the sizes of the bracing members increase to
compensate leading to increases in the weight of this solution. However for water depths
from 15m to 35m similar footprint tripods could be used to support the same turbine while
maintaining the bracing angle limits which would support a family design strategy. Beyond
35m however larger footprint tripods with larger members are required to remain within the
limits on the bracing angles. Further work is required to quantify the effect of water depths
beyond 45m on the weights of the tripod solution.

The analysis shows the tripod to have a slower rate of increase in weight than the monopile
for a given turbine. The precise point at which the monopile weight exceeds that of the
tripod depends on turbine type, environmental load and geotechnical factors but is in the
range from 15m to 25m. It is observed that for the weak soil and with a single environmental
load the crossover point is at 25m for the 3.6MW turbine. Further work to identify the range
of crossover points between monopile and tripod for various environmental loads and soil
conditions.

5.3 Variability in Soil

Soil variability was only considered for the monopile solution. The results of the analyses
indicated that the “weak” soil required deeper penetrations and larger diameters for some of
the water depths but in general the differences between weights of the structures did not
exceed 10%. This is probably because the soil type does not affect the forces above the
mud line and the piles are mainly designed by the bending moment which is resolved by a
system of lateral soil forces that is broadly similar in both the weak and strong soils:

The strong soil is able to support higher lateral forces closer to the mud line but the weak soil
is ultimately able to mobilise adequate resistance without a great increase in pile penetration
or weight. The systems of lateral forces for the piles in strong and weak soils are shown in
Figure 5-1.

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Figure 5-1: Comparison of the lateral forces in the strong and weak soil profiles

STRONG SOIL

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WEAK SOIL

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5.4 Natural Frequencies

In accordance with the recommendations of Germanischer Lloyd [5], the natural period of the
structures was assessed and lowest period limited to 95% of the lowest period of the rotor.
This provision has a significant impact only on the larger monopiles carrying the larger
WTGs because of their inherent flexibility and the effects of more massive nacelle at the top
of the mast. The weights of nacelle, mast, transition piece and pile structures are all
modelled as masses in this analysis. A single pile analysis is performed to calculate the
equivalent linearised spring stiffness appropriate to each the soil and pile. The masses, the
spring supports and the modelled structure are combined to calculate the natural frequencies
of the structure.

Natural frequency considerations governed the design of the 3.6MW monopiles in waters
exceeding 25m and 5MW monopiles exceeding 15m. Since structural stiffness and thus
natural frequency is mainly influenced by diameter, the natural frequency criterion makes the
45m-water depth achievable only with 5m diameter monopiles. There are no reports of such
large piles being successfully installed and so there is an effective technological limit on the
water depths that monopiles can be currently installed. This limit is currently 35m for the
3.6MW turbine and 25m for the 5.0MW turbine. Beyond this currently technology requires a
tripod or similar solution.

6.0 CONCLUSIONS

This parametric study allows the following conclusions to be drawn:

• The weights of monopile and tripod solutions increase with water depth though at
different rates. Within the range of water depths considered, the tripod’s weight
increase is always slower than that of the monopile.
• The monopile is lighter for water depths below 15m but is heavier beyond 25m for all
the cases analysed.
• The transition water depth where the tripod becomes lighter varies but for the 3.6MW
turbine in weak soil it is approximately 25m.
• There are practical limitations on the size of monopile that may be fabricated and
installed. Assuming this to be 4.5m diameter and 80mm thickness this puts a 35m
water depth limitation on the 3.6MW turbine and a 25m limit on the 5.0MW turbine.

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7.0 STUDY LIMITATIONS

The research included consideration of the effects of three turbine types, two soil types, two
structural solutions and five water depths. While this is comprehensive there are a number of
limitations that need to be noted.
7.1 General
The study considered extreme values for nacelle and environment load. While this is
conservative, additional load cases based on characteristic values with appropriate load
factors would need to be considered for a comprehensive assessment of both static and
dynamic effects.
7.2 Pile Size
Monopiles may be used at any water depths depending on the limits imposed by the largest
possible size of driven pile that may be fabricated or installed. Currently it is reported that
4.5m-diameter and 80mm thickness is the limit for driven monopiles due to hammer
limitations. Changing this limit will affect the range of water depths that the monopile solution
may be used. No consideration has been given to limitations on the sizes of tripod or its
component members from fabrication or transportation considerations.
7.3 Environmental Loads
Environmental conditions vary widely around sites offshore the UK and yet only a single
wind, wave and current condition was considered. The environmental load is the largest
contributor to the base shear of the structure and a significant contributor to overturning
moment and so can influence the choice of structure. In addition the largest level of the
water is the key determinant of the hub height for a given wind turbine and therefore
influences the overturning moment.

7.4 Foundation Criteria

The criteria for the behaviour of the foundations are simplified, namely soil or pile failure. In
practice there would be other criteria considered such as the limits used on Thanet of
200mm on pile head displacement, 10mm pile tip displacement and 0.5-degree limit on pile
head rotation.

Also certain soils are more prone to scour, liquefaction and boulders and in practice more
sophisticated criteria would be used to assess the acceptability of foundations. However
since scour is simply an increase in effective water depth, there is already some scope for its
consideration in this analysis.
7.5 Pile-Transition Piece Annulus
Current data show that there are certain limitations for the annulus at pile-transition piece
overlap. The average annulus (grouted) that can be used to ensure safe connection is
between 60mm up to 80mm. Although there it has no impact to purposes of this analysis,
this study considers grouted annulus in that range using high strength grout without grout
beads [6]. Annulus was important for the calculations of member volumes indicating relevant
weights.

7.6 Fatigue Strength

No Fatigue runs were carried out. This is a major consideration for both Tripods and
Monopiles for local design and would have secondary impact of the overall weight.

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7.7 Other Foundation Type Options

There are other solutions available including gravity base structures, braced monopiles or
suction piles that are currently being proposed to support wind turbine towers. These have
not been considered in the analysis but may offer utilised solutions to the limitations of the
considered structures identified by this study.

8.0 COST MODEL ALGORITHM

8.1 Methodology
As the main objective was to provide the final cost model with relevant structural weights of
each WTG for given water depths, it was essential to create a cost model algorithm using the
output data from the analysis.

The objective is to generate an algorithm system that would be able to provide weight
estimates for each WTG at given water depths and soils. That was achieved by using a
WTG as a baseline for given soil conditions and then factorise the rest WTG upwards and
downwards respectively depending on the current weight estimate proportions taken from
analysis.
8.2 Algorithmic Approach
For the best possible optimisation of the analysed structural weights for each WTG, the
3.6MW WTG was used as baseline, which is of a medium capacity in comparison to the
other two WTG. However, as one of the main conclusions of this report was that tripod
weights are lighter for great water depths of 35m to 45m, those weights have now replaced
the existing monopile weights for these water depths of the WTG. Hence, a new curve has
been developed for the 3.6MW WTG which combines effective weights of monopiles and
tripods for given water depths at weak soil conditions – see Figure 8-1. A linear trendline
has then been developed to form the baseline of the algorithmic system.

Figure 8-1: Algorithmic representation of 3.6MW WTG in Weak Soil - Dynamics

3.6MW WTG - Weak Soil - Dynamic

y = 10.098x + 139
700.0
Total Foundation Weight (Te)

600.0

500.0

400.0

300.0
TRIPOD
200.0
Trendline
100.0

0.0
0 10 20 30 40 50

Water Depth (m)

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8.3 Algorithmic Adjustments/Corrections

An adjustment is made for the difference in weights for WTG greater or smaller than 3.6MW.
This algorithmic adjustment for a given water depth involved the following corrections:

1. Differences in weight from the analysis between 3.6MW and 2.0MW as well as
3.6MW and 5.0MW have been calculated.
2. Two separate curves have been developed of weight differences against water
depths and relevant linear trendlines have been produced for each case – Figures
8-2.
3. Essentially, corrections have been made to the soil conditions where a 5% of the
trended weight, coming from trendline equation in Figure 8-1, is subtracted for
strong soils while strong soils are expected to require smaller foundations. There
are no corrections for weak soils since the algorithm is based on a weak soil profile.
4. Trendlines in Figure 8-2 belong to adequate trendline equations. Depending on
WTG capacity (smaller or greater than 3.6MW), the sum of trended weight coming
from this equation with the soil correction weight estimate are added to the baseline
3.6MW trended weight. The final weight value is the logarithmic weight estimate of
the model.

Figure 8-2: Algorithmic Factors for WTG Size Increase or Decrease

Correction for WTG less than 3.6MW
y = 0.8125x + 60.691
140
120
100
80
60
40 Trendline

20
0
0 5 10 15 20 25 30 35 40 45 50
Water Depth (m)

Correction for WTG greater than 3.6MW

y = 8.1778x + 3.6792
500

400

300

200
Trendline
100

0
0 5 10 15 20 25 30 35 40 45 50
Water Depth (m)

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8.4 Weight Differences/Percentage Error

Weight differences in percentages between analysed weights and logarithmic weights are
shown in Table 8-1. For analysed weights reference can be made at Table 4-1.

Table 8-1: Algorithmic Foundation Weight Estimates & % Differences with Analysis
Weights
Water Depth (m)
WTG 5 15 25 35 45
2.0MW 118 207 295 383 471
Algorithmic
Estimate 3.6MW 180 276 372 468 564
Strong 5.0MW 222 396 570 743 917
Soil 2.0MW 7% 4% 6% 1% 5%
% Difference
with Analysis 3.6MW 5% 8% 6% 4% 10%
Weights
5.0MW 5% 2% 12% 15% 14%
2.0MW 125 218 310 403 496
Algorithmic
Estimate 3.6MW 189 290 391 492 593

Monopile Weak Soil 5.0MW 234 417 600 782 965

% Difference 2.0MW 6% 7% 4% 0% 1%
with Analysis 3.6MW 3% 10% 3% 2% 7%
Weights
5.0MW 11% 2% 8% 13% 21%
2.0MW 125 218 310 403 496
Algorithmic
Estimate 3.6MW 166.4 309.5 419.2 **680.8 **883.2
Weak Soil 5.0MW 234 417 600 782 965
- Dynamic 2.0MW 6% 7% 4% 0% 1%
% Difference
with Analysis 3.6MW 12% 6% 7% 28% 33%
Weights
5.0MW 11% 7% 10% 11% 8%
Algorithmic
3.6MW ~ ~ ~ 492 593
Estimate
Tripod Weak Soil % Difference
with Analysis 3.6MW ~ ~ ~ 4% 1%
Weights
** substituded Tripod values

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9.0 REFERENCES

[1] Foundations Options Review For Thanet Offshore Wind Farm, BOMEL Ltd,
C1179/06/001R Rev C March 2006

[2] Scroby Sands Wind Farm, Monopile Foundation Design, LIC Engineering A/S, R0144-
30 Rev A February 2003

[3] Lynn & Inner Dowsing Wind Farm, Metocean Study, HR Wallingford, Report EX 5018
Rel 3.0 August 2005

[4] London Array Wind Farm Project, Project Design Statement, London Array, May 2005,
10th Version

[5] Guidelines for the Certification of Offshore Wind Turbines, Germanischer Lloyd Wind
Energy, Edition: June 2005

[6] Efficient Connection Between Offshore Foundation and Wind Turbine Towers, Densit
A/S, Denmark, www.densit.com

[7] API RP-2A, Recommended Practice for Planning, Designing and Constructing Fixed
Offshore Platforms – Working Stress Design, 21th Edition, December 2005

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APPENDIX 3 – SENSITIVITY OF LOAD FACTORS AND MODEL TRENDS

1.0 TRENDS

The Cost Model estimations are based in several cost trends projected from year 2006,
these trends allow estimation of CAPEX and OPEX for project developed in the years
2006-2020.

The trends are: Supply & Demand, Leaning Curves, R&D, Steel Cost, Copper Cost and
Turbine Supply & Demand. Each of these trends has been represented in three trend
lines A, B and C in order to cover a wider range of future cost behaviour. The B trendline
is the “ode best guess” and trendlines A and C are the perceived lower and upper
boundaries respectively.

This study looks at the significance of the effect each of these trends will have on the
CAPEX of an OWF Project in the future. The study analysis will focus mainly on the
behaviour of the B trendlines, the A and C trendlines will be discussed briefly.

No inflation was considered on the CAPEX cost projection so that the effect of the
trends could be more evident, hence the results shown are the “real cost” CAPEX.

The following characteristics were chosen for the OWF project, to be analysed in this
study:

Number of Turbines 30
Distance of export cable to shore (km) 10.0
Distance to Port/Holding bay (km) 10.0
Length of interarray cables (km) 15.0
Length of onshore cable (km 4.0
Life of Field in Years 25
Capacity of Turbine (MW) 3.6
Total nr of Onshore Substation 1
Total nr of Offshore Substation 0
Water Depth (m) 15.0
Number of Met Masts 1
Cost of Steel (July 06 =650 [£/Tonne]) 650
Soil Type (1:Poor 2:Good) 1

Scour Depth (m) 2.0

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1.1 Base Case

The figure below shows the base case CAPEX variation for the chosen OWF project,
which is the result obtained when choosing the ode best guest trendlines i.e. B
trendlines for all the trends. The B trend is represented on the “line” graphs in pink. The
influence of a trend on the project CAPEX is obtained by calculating the difference
between the CAPEX values with the trend (R&D, Steel, Copper…) and trendline (A, B or
C) and the CAPEX values excluding the trend. The CAPEX values, which exclude the
trend, are represented on the “line” graph in Turquoise.

Project CAPEX Base Case

£170.00
Millions

£160.00

£150.00

£140.00

£130.00
CAPEX

£120.00

£110.00

£100.00

£90.00

£80.00

£70.00
2004 2006 2008 2010 2012 2014 2016 2018 2020 2022
Year

Note:
CAPEX calculation for a particular year takes projected costs of activities over the
Project development period, typically 6 years. Since these future events are affected by
trends, the resultant CAPEX for the development year is seen to differ from a case
where a trend is excluded by typically 2-10% (see the highlighted difference in R&D
graph)

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1.2 Research & Development

Provided there is continuous investment on R&D work relevant to OWF industry the
CAPEX real costs are predicted to reduce by almost 26% by year 2020 (trendline B).
The reduction of costs is steady during the initial years, reducing the CAPEX costs by
about 3-5%. The effect of R&D is more evident from years 2010 to 2020 where there is
a steady reduction of costs rising from 7% to just over 26%. Trendlines A & C forecast a
reduction on CAPEX of 21% and 29%, respectively, by year 2020.

R&D Impact on CAPEX

0%
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

-5%

-10%
CAPEX Variation per Year %

-15% R&D A
R&D B

-20% R&D C

-25%

-30%

-35%
Year

R&D Trendlines

£190.00
Millions

£170.00

£150.00
CAPEX

£130.00

£110.00 Difference in CAPEX

due to excluded trend
(see note above)
£90.00

£70.00
2004 2006 2008 2010 2012 2014 2016 2018 2020 2022
Year

R&D A R&D B R&D C NO R&D TREND

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1.3 Supply & Demand influence

Looking at trendline B on the graph below, the Supply and Demand (S&D) trend is
predicted to inflate the CAPEX by about 12% from year 2006, this continues to rise and
peaks at 17% in years 2008 and 2010 when the industry is predicted to be highly active.
This level of activity is predicted to reduce in the following years, which reflects in a
progressively lower effect of S&D on the CAPEX costs, reaching just under 2% by year
2020. Trendlines A and C offset trendline B values by about 1% in the initial years and
peak in years 2008 and 2010 at approximately 16% and 18% respectively. This offset
reduces to about 0.1% by year 2020.

S&D Impact on CAPEX

20%

18%

16%
CAPEX Variation per Year %

14%

12%
S&D A
10% S&D B
S&D C
8%

6%

4%

2%

0%
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Year

S&D Trendlines

£170.00
Millions

£160.00

£150.00

£140.00

£130.00
CAPEX

£120.00

£110.00

£100.00

£90.00

£80.00

£70.00
2004 2006 2008 2010 2012 2014 2016 2018 2020 2022
Year
S&D A S&D B S&D C NO S&D TREND

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1.4 Learning Curves

The Learning trend is directly proportional to the industry development. Hence provided
the Industry continues to develop and the level of investment from the private and the
government sectors is maintained, the Learning trend is estimated to reduce CAPEX
significantly over the next 13 years reaching the highest value of approximately 30% in
2020, for trendline B. The trendlines A and C predict a reduction on costs by year 2020
of approximately 24% and 36%, respectively.

Learning Curve Impact on CAPEX

0%
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
-5%

-10%
CAPEX Variation per Year %

-15%
LC A
-20% LC B
LC C
-25%

-30%

-35%

-40%
Year

Learning Curve Trendlines

£210.00
Millions

£190.00

£170.00

£150.00
CAPEX

£130.00

£110.00

£90.00

£70.00
2004 2006 2008 2010 2012 2014 2016 2018 2020 2022
Year
LC A LC B LC C NO LC TREND

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1.5 Steel Cost

There is currently a high demand for Steel and this is predicted to rise in the following
years. Looking at trendline B the cost of Steel is predicted to increase the CAPEX cost
steadily by an approximate rate of 3-4% per year on the initial years of the CAPEX
period and at a rate of 1-2% thereafter. On year 2020 the Steel cost is predicted to
inflate the project CAPEX by 46%. Trendline A does not vary more than 4% throughout
the entire period, starting at 8% in 2006 peaking in the year 2010 at approximately 13%
and finishing close to 10% in year 2020. Trendline C shows a fairly linear increase on
the CAPEX starting at 11% in year 2006 and rising to 81% by year 2020. The curves
indicate the volatility of the commodities market.

Steel Impact on CAPEX

90%

80%

70%
CAPEX Variation per Year %

60%

50% STEEL A
STEEL B
40% STEEL C

30%

20%

10%

0%
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Year

Steel Trendlines

£190.00
Millions

£170.00

£150.00
CAPEX

£130.00

£110.00

£90.00

£70.00
2004 2006 2008 2010 2012 2014 2016 2018 2020 2022
Year
STEEL A STEEL B STEEL C NO STEEL TREND

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1.6 Copper Cost

Similarly to Steel, the cost of Copper is also predicted to increase the CAPEX costs
steadily by an approximate rate of 2-3% per year and reach 18% in year 2020(trendline
B). Trendlines A and C inflate the CAPEX throughout the entire period but at different
rate, trendline A starts 3% in year 2006 and increases steadily to approximately 12% in
year 2020. Trendline C affect the CAPEX by 4% in year 2006 and the effect rise at a
linear rate to peak at 26% in year 2020.

Copper Impact on CAPEX

30%

25%
CAPEX Variation per Year %

20%

COPPER A
15% COPPER B
COPPER C

10%

5%

0%
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Year

Copper Trendlines

£170.00
Millions

£160.00

£150.00

£140.00

£130.00
CAPEX

£120.00

£110.00

£100.00

£90.00

£80.00

£70.00
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Year
COPPER A COPPER B COPPER C NO COPPER TREND

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1.7 Turbine Supply & Demand

The turbine S&D influence on the project CAPEX in the years 2006-2020 takes a form of
an oscillation where, for trendline B, the highest peak takes place in the year 2008
reaching approximately 6%. In year 2011 the effect of the turbine cost is almost non-
existent and subsequently reduces the CAPEX costs peaking in the year 2018 where
the influence is of approximately -14%. Trendlines A and C follow a similar trend
whereby the highest peak is at 3% and 9% in year 2008 and the lowest peak at –14%
and –13% in year 2018, respectively.

Turbine S&D Impact on CAPEX

10%

5%
CAPEX Variation per Year %

0%
TURBINE S&D A
06

07

08

09

10

11

12

13

14

15

16

17

18

19

20
TURBINE S&D B
20

20

20

20

20

20

20

20

20

20

20

20

20

20

20
TURBINE S&D C
-5%

-10%

-15%
Year

Turbine S&D Trendlines

£190.00
Millions

£170.00

£150.00
CAPEX

£130.00

£110.00

£90.00

£70.00
2004 2006 2008 2010 2012 2014 2016 2018 2020 2022
Year
TURBINE S&D A TURBINE S&D B TURBINE S&D C NO TURBINE S&D TREND

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1.8 Conclusion

As shown in the graph below, the R&D and Learning trends reduce the CAPEX costs
significantly without which the CAPEX would almost double by year 2020. (Trend B).

The parametric study indicates just less than a 30% reduction in CAPEX cost for both
R&D and Learning, offset by a 46% increase due to Steel cost and a 18% due to the
cost of copper. Turbine cost in the long term tends to reduce the CAPEX by some 15%.
Clearly without the benefits of R&D and industry learning the development costs will
make the industry uneconomic.

The Learning trend is proportional to the level of activity in the industry; the positive
benefits of this can only be amplified by ensuring that the industry remain active. R&D
benefit and Financial support to the industry are primary motivators to ensure continued
development.

TREND A B C
COPPER 12.4% 19.1% 26.1%
STEEL 11.0% 46.8% 80.9%
R&D -29.5% -26.3% -20.6%
LC -35.4% -30.0% -23.9%
S&D 1.8% 1.9% 2.0%
TURBINE S&D -12.4% -12.0% -11.6%
TOTAL -52.0% -0.5% 52.9%

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2.0 LOAD FACTORS

Sensitivity of different Load Factors was investigated. A wind farm consisting of 30

3.6MW turbines, with a field life of 20 years was assumed. Availability (i.e. the amount of
time the turbines are assumed to be able to produce power) was set at 95%. This is a
standard figure used for offshore wind turbines.

The total output in MWh from the wind farm was generated and compared to identify the
significance of the load factor.

Case 1 Case 2

Number of Turbines 30 Number of Turbines 30

Size of Turbine 3.6 Size of Turbine 3.6
Life of Field 20 Life of Field 20
Load Factor 25.00% Load Factor 30.00%
Availability 95.00% Availability 95.00%
Hours in Year 8760 Hours in Year 8760

OWF Total Output (MWh) 4,493,880 OWF Total Output (MWh) 5,392,656

Case 1 Case 4

Number of Turbines 30 Number of Turbines 30

Size of Turbine 3.6 Size of Turbine 3.6
Life of Field 20 Life of Field 20
Load Factor 35.00% Load Factor 40.00%
Availability 95.00% Availability 95.00%
Hours in Year 8760 Hours in Year 8760

OWF Total Output (MWh) 6,291,432 OWF Total Output (MWh) 7,190,208

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OWF Total Output with Different Load Factors (Availability Constant @ 95%)

8,000,000

7,000,000

6,000,000

5,000,000

4,000,000 OWF Total Output

3,000,000

2,000,000

1,000,000

0
25.00% 30.00% 35.00% 40.00%

Change in Wind Farm Output with Load Factor

70%

60%
% Increase in Wind Farm Output

50%

40%
Increase in Output
30%

20%

10%

0%
25% to 30% 25% to 35% 25% to 40%
Change in Load Factor

The above analysis shows that a 15% change in load factor from 25% to
40% results in a 60% increase in total output. Thus, ensuring that the
wind farm is located at a site with a good wind profile is imperative to
overall output and hence revenue.

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