THE CROWN ESTATE Round 3 Offshore Wind Farm Connection ...

THE CROWN ESTATE 

Round 3 Offshore Wind Farm Connection Study 

Prepared for 

Version 1.0 

Danielle Lane 

The Crown Estate 

16 New Burlington Place 

London 

W1S 2HX

Executive Summary 

This investigation presents an indicative set of optimum offshore and onshore electricity 

transmission network reinforcements required for the connection of up to 25GW of offshore wind 

generation as part of the Round 3 leasing process. It has been carried out by Senergy Econnect 

and National Grid for the Crown Estate to aid in the development of the potential Round 3 

development zones published earlier in the year. The final location of these zones is subject to the 

outcome of the Strategic Environmental Assessment currently being undertaken by the 

Department for Energy and Climate Change (DECC; formerly BERR) and further work with project 

developers. 

As the aim of this study was to identify the extent and costs of the works necessary to provide 

optimised transmission connections for all of the Round 3 offshore wind farms, an analysis was 

undertaken by Senergy Econnect as an annex to this report to ascertain at a high level the optimal 

ratio between the installed generating capacity offshore and the transmission capacity of the 

offshore transmission assets. This optimal utilisation ratio was determined to be 112%. In practice 

the offshore transmission asset designs provided in this report have a range of utilisation ratios 

from 81% to 112% because of the zonal capacities identified by The Crown Estate and the 

modular nature of the transmission assets themselves (with each additional cable providing a fixed 

increase in transmission capacity). National Grid are in the process of leading a review of the 

security standards for offshore generation connections to include projects of the size and distance 

form shore associated with Round 3, at the request of Ofgem. This review will culminate in a set of 

security recommendations including offshore transmission circuit capacity, which will be consulted 

upon and incorporated as revised text in the GB SQSS. 

In order to provide as accurate a cost model as possible a number of high voltage power 

equipment manufacturers and installers were consulted for the current costs of the equipment that 

would be required to realize the offshore connection designs described in this report. 

The offshore connection designs have been based around indicative zonal capacities provided by 

The Crown Estate. The location and installed capacities of the wind farms located within the zones 

as identified in this report have been determined by Senergy Econnect based on the principle of 

minimising the offshore transmission assets required for connection and identifying the associated 

costs. As such these designs may not provide the optimal solutions for the actual Round 3 wind 

farms, as the location, installed capacity, and offshore transmission technology and utilisation 

factor for the actual wind farms will be determined by the zonal developer and offshore 

transmission owner in collaboration with the selected technology provider. These solutions are 

designed to comply with the offshore GB SQSS proposals, except where expressly stated. 

The following Table summarises the optimal cost of connections resulting from this analysis. 

1845 Crown Estate Round 3 OWF connection study v1.0 (FINAL).doc Page 3 of 94

ZONE OWF 

Total 

Installed 

Capacity 

Connection 

technologies 

Moray Firth C 500MW AC 

Connection Point 

(s) 

New substation on 

coast 

TOTAL 

COST 

TOTAL 

COST 

Per MW 

£193m* £386k 

Firth of Forth G 500MW AC Torness £150m* £300k 

Dogger Bank 

Hornsea 

Norfolk 

(without 

Sizewell C) 

H1 1237.5MW DC Creyke Beck 


J 1240MW DC Creyke Beck 

H2 1237.5MW DC Keadby 


H5 1237.5MW DC Killingholme 

I1 1240MW DC Killingholme 


M 1237.5MW DC New substation on 

Lincolnshire coast 

N 1240MW DC New substation on 

Lincolnshire coast 

T 1240MW AC Sizewell 

Z2 1240MW DC Sizewell 

U 1237.5MW DC Norwich 

Z1 1237.5MW DC Norwich 

£5,910m £477k 

£1,728m £349k 

Hastings AA 500MW AC Bolney £184m £368k 

West Isle of 

Wight 

Bristol 

Channel 

Irish Sea 

DA 500MW AC Chickerell £175m £350k 

EA 1500MW AC New substation on 

Torridge Estuary 

IA 1237.5MW DC Deeside 

LA 1240MW DC Deeside 

JA 1237.5MW AC Wylfa 

NA 1240MW DC Stanah 

£430m £287k 

£1,632m £329k 

TOTALS 25,795MW £10,402m £403k 

Table 1: Optimal Connection Costs broken down by Zone 

*Total reinforcement costs dependent on GB transmission owner study currently in progress 

The total cost for connecting the round 3 wind farm projects, assuming no inclusion of Sizewell C, 

and the optimal design solutions identified in this report is £10,402 million. . Note that this Figure is 

based on 2008 price levels for the equipment required and does not allow for the additional 

equipment such as Static Var Compensation that may need to be installed at the onshore 

connection point of the HVAC connection solutions in order for the Offshore Transmission Owners 

to meet the reactive capability requirement of the System Operator/Transmission Owner code (e.g. 

an SVC sufficient to provide dynamic reactive capability for a 300MW wind farm would cost in the 

order of £12m). 


Sensitivities were also investigated in some areas where new nuclear developments could occur in 

the same region and within the same timescales as the Round 3 development. If transmission 

reinforcement was not undertaken in an optimised manner on a strategic basis then offshore 

transmission asset costs could increase as a result of having to find alternative more distant 

connection points. An example of this is the Norfolk zone where the inclusion of Sizewell C 

increases the offshore transmission asset cost by £245m. 

As a function of these designs, the total installed generating capacity connected for round 3 is 

25,295MW (with a connection capacity of 22,980MW) with a £/MW cost ranging from £287k to 

£477k. 

In undertaking this work it became clear that, from a purely economic perspective, minimising the 

length of the offshore transmission network as much as possible is desirable. Typically the cost of 

the offshore network comprised roughly 90% of the total reinforcement cost. However, the need for 

significant onshore reinforcement, and the consenting risk that accompanies this reinforcement, 

was also identified. This was particularly the case for connection of the Dogger Bank, Hornsea and 

Norfolk development zones as well as areas with the potential for connection of new nuclear 

generation. Nevertheless, National Grid is confident that the network can be developed in an 

economic and efficient manner to facilitate renewable targets. In order to achieve this aim, work will 

need to occur in a timely manner, which implies that some of it may have to occur before specific 

individual projects materialise. The possible need for investment on an anticipatory ‘no regret’ 

basis and the pressure to meet renewables targets places further emphasis on the importance of a 

coordinated approach to the design of an optimum offshore and onshore specific solution. 

Where onshore reinforcement options have been identified through this study, no environmental 

impact assessment of these reinforcements has been undertaken at this stage. Prior to 

undertaking any onshore reinforcement’s environmental impact assessments will be undertaken in 

accordance with best practice against a range of possible solutions. 

Some of the identified reinforcements will require planning consent and for this reason the 

Planning Bill, which received Royal Assent on 26 November, is seen as an essential process to 

enable significant energy infrastructure projects to be constructed, while enabling local 

communities and stakeholders to fully engage in the process . Identification of specific onshore 

reinforcements and the timing of these reinforcements are subject to the frameworks that currently 

govern the development of the transmission system such as the transmission access regime and 

the Great Britain Security and Quality of Supply Standards (GB SQSS). The onshore transmission 

owners are currently in the process of a fundamental review of these frameworks to ensure that 

they are fit for purpose for a GB electricity system that incorporates large volumes of variable 

generation from renewable sources. 

The power transfer capabilities of the HVAC and HVDC technologies available coupled with the 

potential installed capacity of the Round 3 OWF have to a large part dictated the offshore 

transmission designs presented in this report and determined that in the primary solution each 

OWF is connected directly to an onshore connection point, with no interconnection between the 

OWF in a particular zone. 

Applying an HVAC and HVDC solution to the same OWF has indicated that the choice of 

technologies used for the offshore transmission designs will be dictated by the transmission 

distance and that the cable route length at which HVDC Voltage Source Converter solutions 

become more economic than an equivalent HVAC solution is between 60km and 80km. 

Aggregated solutions, where multiple OWF are interconnected have been considered and costed, 

although these solutions do not compare favourably with the individual offshore transmission 

designs for the same OWFs in terms of cost per MW installed, except where solutions have been 

considered that utilise dual bipole HVDC overhead lines as opposed to underground cable to 

traverse the long distance overland routes from the coast to Norwich and Drax substations. 


The challenges posed in delivering the Round 3 offshore connections, regardless of design 

pursued, will be significant. Investment will be required by existing suppliers in expanding 

manufacturing facilities for HV cables, and in particular subsea cables. The HVDC VSC market is 

still at an embryonic stage, with the converter/bipole ratings used in this report yet to be deployed 

in the field. Hence there will be a technology risk as well as cost premium to be borne by the ‘first 

comer’ offshore transmission owner to specify this technology. Again it is likely that manufacturing 

facilities would need to be expanded to accommodate demand should Round 3 be developed in 

the timescales desired, with prices dropping as competition increases and with economies of scale. 

The HVDC converter manufacturers are confident that they can increase manufacturing capability 

to meet demand should they have sufficient assurance that projects will place orders. However 

Senergy Econnect have anecdotal evidence that one manufacturer is revising downwards their 

short to medium term forecasts for supplying the offshore market in the UK because of the delays 

in progressing offshore projects through the GB planning, consenting, and regulatory process, and 

the ability of the process to deliver the offshore wind farm capacity in the timescales desired. 

It should be noted that the offshore programmes of other countries and an increase in HVDC 

projects around the world will coincide with the Round 3 build programme, and hence Round 3 

developers or their Offshore Transmission Owners may potentially need to commit to production 

slots up to three or more years in advance to avoid the HVDC converters becoming a constraint. 

In order for the HVDC suppliers to have the confidence to increase their manufacturing capability, 

they will require an order book to be in place, which in turn means that the Offshore Transmission 

Owner regime needs to ensure that the procurement of equipment is triggered as early as possible 

in the process so that these lead times can be managed and reduced. 

Suppliers of the installation vessels necessary to install the cables and offshore platforms are 

bullish in their ability to quickly ramp up capacity to meet the demands of Round 3, although they 

acknowledge that to make the investment required in the timescales necessary they will need the 

security of retainer agreements or firm orders in place. 

The design and costing process has considered a “total solution” capable of handling the entire 25 

GW of Round 3 offshore wind. This assumes that the collective requirements for all the wind farms 

in a zone are required and that the overall onshore transmission system changes will all occur in a 

coordinated manner at any one location. Should piecemeal developments be undertaken, wind 

farm-by-wind farm, and/or wind generation capacity change incrementally over a period of years, 

the staggered timing of the works would result in multiple site/circuit extensions and this will 

increase the overall onshore costs and environmental impact. In order to avoid this extensive 

stakeholder engagement, coordination and collaboration is required. 

The report recommends that next steps should include a more detailed investigation of the 

environmental and planning constraints associated with the Round 3 zone connections and of the 

supply chain challenges likely to confront Round 3 projects. Further investigation into possible ‘no 

regret’ onshore reinforcements that have the potential to reduce the total connection cost would 

also be beneficial 


Table of Contents 

Executive Summary .......................................................................................................................... 3 

1 Introduction.......................................................................................................................... 10 

2 Overall Design Methodology ............................................................................................... 12 

3 Offshore Design Methodology ............................................................................................. 14 

3.1 Establishing wind farm capacity & location.......................................................................... 14 

3.2 Establishing number and location of offshore platforms...................................................... 17 

3.3 Connection link technologies, capabilities and limitations ................................................... 18 

3.3.1 AC cables ................................................................................................................ 18 

3.3.2 HVDC....................................................................................................................... 20 

3.3.2.1 Current Source Converter HVDC technology .......................................................... 21 

3.3.2.2 Voltage Source Converter HVDC technology.......................................................... 21 

3.3.3 Gas Insulated Transmission Lines........................................................................... 24 

3.3.4 Superconductors...................................................................................................... 25 

3.4 Establishing offshore redundancy, security & quality of supply criteria ............................... 26 

3.5 Tailoring Installed Capacity to Connection Capacity ........................................................... 28 

3.6 Assessing landfall points, onshore cable routes & land availability..................................... 29 

3.7 Assessing offshore cable routes.......................................................................................... 29 

4 Offshore Cost Methodology................................................................................................. 31 

5 Onshore Design................................................................................................................... 37 

5.1 Assessing requirements for additional capacity on the onshore transmission system........ 37 

5.2 Scenario – Background assumptions on generation and demand ...................................... 38 

5.3 Onshore Transmission Requirements: Methodologies for Costing and Option Analysis .... 39 

5.4 Cost Basis ........................................................................................................................... 39 

5.5 Option Analysis.................................................................................................................... 41 

Zones with only one or two wind farms and relatively small overall capacities (1500 MW or less). 41 

Zones with several wind farms and larger capacities (approx. 3000 – 11000 MW) ........................ 41 

5.6 Scottish System Area .......................................................................................................... 41 

6 Overall Design Options and Potential Zonal Solutions........................................................ 41 

6.1 Moray Firth .......................................................................................................................... 42 

6.1.1 Offshore connection................................................................................................. 43 

6.1.2 Offshore connection alternatives ............................................................................. 43 

6.1.3 Onshore reinforcement ............................................................................................ 43 

6.2 Firth of Forth ........................................................................................................................ 44 





6.3 Dogger Bank & Hornsea...................................................................................................... 46 




6.4 Norfolk ................................................................................................................................. 59 




6.4.3.1 Zonal Infrastructure Works (without Sizewell C)...................................................... 64 

6.4.3.2 Zonal Infrastructure Works (with Sizewell C)........................................................... 66 

6.5 Hastings............................................................................................................................... 67 




6.6 West Isle of Wight................................................................................................................ 70 




6.7 Bristol Channel .................................................................................................................... 73 




6.8 Irish Sea .............................................................................................................................. 77 




7 Delivery Issues .................................................................................................................... 82 

7.1 Offshore Installation & Manufacturing resource .................................................................. 82 

7.1.1 HVAC and HVDC subsea cables............................................................................. 82 

7.1.2 HVDC converter equipment..................................................................................... 83 

7.1.3 Balance of plant equipment (e.g. transformers, switchgear, etc)............................. 83 

7.1.4 Assessment of the availability and cost of cable installation vessels ...................... 83 

7.2 Onshore transmission network delivery programme ........................................................... 84 

8 Conclusions ......................................................................................................................... 85 

8.1 Methodology and Assumptions ........................................................................................... 85 

8.2 Cost of Connecting Round 3 Offshore Wind Farms ............................................................ 85 


8.3 Individual Versus Aggregated Connections......................................................................... 87 

8.4 Deliverability of Round 3 Connections................................................................................. 87 

8.5 Benefits of a co-ordinated approach.................................................................................... 88 

9 Recommendations............................................................................................................... 90 

10 References .......................................................................................................................... 91 

11 List of Appendices ............................................................................................................... 92 


1 Introduction 

Following the initial East Coast Transmission Network, Technical Feasibility Study [1] and 

subsequent meetings with key stakeholders such as the Scottish Government, National Grid, 

Ofgem, and the Department for Energy and Climate Change (DECC; formerly BERR), The Crown 

Estate now wish to understand the potential extent and cost of the works necessary to provide 

optimised transmission connections for the indicative Round 3 offshore wind farm project 

development zones 1 . This includes an assessment of the necessary onshore reinforcements to 

facilitate these connections, such that a coordinated, optimal design between onshore and offshore 

is achieved. 

A crucial starting point for this report was to establish the size and location of the offshore Round 3 

projects that could arise within the areas identified. Once this was established the challenge was to 

design a network topology with sufficient capacity to accumulate and transmit the power levels 

required. Selecting an appropriate capacity for each connection link is also important in 

establishing the financial case for such an offshore transmission scheme as the utilisation of these 

offshore assets (as part of demonstrating an economic and efficient test) will likely be a significant 

parameter in the competitive tender process to be overseen by Ofgem in awarding the Offshore 

Transmission Owner licences. 

As well as understanding the size and location of the planned generation projects, the type of 

generation proposed is fundamental to designing a technically and economically efficient offshore 

transmission system. This study is based on current, prototype or proposed offshore wind turbine 

models that could achieve market realisation in the assumed timescales of the Round 3 projects. 

The maximum amount of power that could be lost in the event of a fault on the offshore network is 

of interest to the onshore system operator as they will need to put operational measures in place 

for this possibility. The possible extent of this power loss with regard to the Round 3 project 

timescales is discussed in Section 3.4. 

Of significant impact to the final network topology is the location of the connection points to the 

onshore networks within the geographical area of consideration and the reinforcements required to 

the onshore system in order to facilitate these connections. The final choice of connection point 

was determined iteratively by assessing the ability of the onshore networks to accept either a 

power infeed or outflow at certain nodes, the land available to extend either existing substations or 

create new substations, and the practicality and cost of either extending the 400kV overhead line 

network or providing an onshore cable route. 

This analysis was undertaken against generation background assumptions other than that of the 

currently contracted generation projects (i.e. those having a Bilateral Connection Agreement with 

the GB System Operator) that would normally be considered as part of a connection application 

process. The overall optimum solutions presented could therefore change depending on which 

generation projects actually come forward in future. Sensitivity studies have been undertaken on 

key variables, such as nuclear replanting, in order to mitigate as far as possible the effect of this 

future uncertainty. 

1 Subject to the outcome of the DECC Strategic Environmental Assessment 


Once an asset optimised offshore and onshore design was achieved against the background 

assumptions made, each design was costed, based on updated pricing information received from 

Siemens, ABB, Areva, and Prysmian and the experience of National Grid in building onshore 

assets. 

There is currently a shortage of critical raw materials required for infrastructure development, such 

as copper, aluminium, and steel, as well as potentially significant restrictions in the capacity 

available to manufacture the elements of technology required to implement an offshore network 

scheme. It should be noted that an offshore scheme spanning the geographical areas outlined for 

Round 3 would also be beyond anything currently in operation. For this reason, a certain amount of 

design and development work will need to be undertaken, (for example refinement of the 

technology to support multi-terminal HVDC operation), before such a scheme could be 

manufactured, constructed, and operated. The tools necessary to install subsea cables and 

platforms, such as lifting barges and cable laying vessels, are also presently in short supply; 

therefore, this study ascertains how these restrictions will impact the lead time necessary to 

commission any proposed scheme. 


2 Overall Design Methodology 

A key feature of this work is an investigation into a coordinated offshore and onshore design for the 

connection of offshore wind generation, in an attempt to provide a more effective solution than 

simply connecting to the nearest point onshore. At a high level, the process is illustrated in Figure 

1. 

Network Design 

Engineering Design 

Standards and 

Assumptions 

Network and Turbine 

Technology 

Offshore Design 

Iterative 

Design 

Process 

Offshore and Onshore 

Costs 

Onshore Design 

Land, Planning, 

Consents and 

Network Installation 

Figure 1: Iterative Offshore and Onshore Design Methodology 

Overall 

Optimum 

Network 

Conclusions 

Projects arising out of the Round 1 and Round 2 offshore leasing process were predominantly 

small in size and close to the shoreline (almost exclusively within the 12 nautical mile limit of 

territorial waters) relative to the proposed Round 3 areas. For the majority of these Round 1 and 

Round 2 projects, cost benefit analysis clearly demonstrated that individual, AC, radial connections 

to the electricity system onshore were the most economic. In contrast, offshore areas earmarked 

for Round 3, such as the Dogger Bank, could be developed to levels of up to tens of gigawatts and 

are located more than 100km from the onshore system leaving greater scope for consolidation and 

optimisation in taking the energy to shore. 

The impact of where a project is connected to the onshore transmission system on connection 

timescales and overall cost has often been underestimated in the past, occasionally leading to 

unexpected revisions in assumptions on capital costs, additional consenting risk and the potential 

for sub-optimal overall design. This highlights the impact of the effect on the onshore transmission 

system as a result of a particular offshore design and the importance of the iterative nature by 

which the design process must take place in order to find the optimum combination between 

offshore and onshore assets. This is especially pertinent for projects of the size and geographically 

diverse locations characteristic of those expected to arise out of the Round 3 process. 

In considering the amount of transmission capacity required to facilitate the connection of the 

indicative Round 3 development zones it is important to note that this was assessed relative to the 

calculated potential capacity of these zones as well as the levels of electricity demand and the 

amount and spatial distribution of conventional generation (such as coal, gas and nuclear) 

assumed to share network capacity with onshore and offshore wind generation. 

1845 Crown Estate Round 3 OWF connection study v1.0 (FINAL).doc Page 12 of 94 

and 

Recommendations

The offshore network topology and technology is largely determined by the location of and 

distance to the optimum connection points onshore. The final choice of connection point has been 

determined by finding an economic balance between offshore and onshore reinforcement required, 

including the cost of both local (substation and circuits) and wider (Main Interconnected 

Transmission System (MITS)) reinforcement. 


3 Offshore Design Methodology 

The starting point for this report was to establish the nominal capacity and location of the forecast 

offshore Round 3 generation projects within the indicated, potential offshore zones for 

development. Once this was established a connection network topology was constructed with 

sufficient capacity to accumulate and transmit the power levels required. Selecting an optimum 

capacity for the links in this connection network is also important in establishing the financial case 

for such an offshore transmission scheme. Any offshore assets to be constructed under a 

regulated regime will be assessed by Ofgem as part of a competitive tender process for awarding 

Offshore Transmission Owner licences. Therefore demonstrating that these assets are designed to 

achieve optimum utilisation will be a key consideration. The following sections describe the 

methodology used to design and then cost the various Round 3 connection network topologies 

contained within this report. 

3.1 Establishing wind farm capacity & location 

Following the public announcement of the third round of offshore wind farm site leasing in 2007, 

The Crown Estate have published a map showing indicative Round 3 zones for development 2 (see 

Figure 2) however in order to arrive at a connection solution it was necessary to establish an 

indicative MW capacity that will be connected within each of the zones and also the locations of 

possible wind farm developments within each zone. To that end The Crown Estate allocated 25GW 

across the nine zones approximately in relation to the area of the zone. The allocation was carried 

out for the purposes of this study and is one of a number of possible scenarios for capacity 

allocation. It does not necessarily reflect The Crown Estate’s view on the likely outcome of the 

Round 3 tender. Additionally The Crown Estate provided a series of GIS shape files indicating 

areas within each zone that could potentially become sites for offshore wind farms, hereafter 

referred to as ‘Polygons’, as well as indicative connection capacities for each of the Round 3 

development zones, (see Table 2 below). 

Further it should be noted that this study does not take account of all environmental constraints. 

Therefore the location of the development zones and polygons will be dependent not only on the 

Round 3 tender but also on the outcome of the Strategic Environmental Assessment being 

undertaken by DECC and any environmental Impact Assessment of individual sites. 

2 Subject to the outcome of the DECC Strategic Environmental Assessment 


Figure 2: Round 3 Zones for Development 

©Crown Copyright 


Round 3 Development Zone 

Indicative Connection Capacity 

(MW) 

Moray Firth 500 

Firth of Forth 500 

Dogger Bank 9000 

Hornsea 3000 

Norfolk 5000 

Hastings 500 

West Isle of Wight 500 

Bristol Channel 1500 

Irish Sea 5000 

TOTAL 25,500 

Table 2: Round 3 Zonal Indicative Connection Capacities 

In order to assess each polygon’s potential for installed capacity, and hence each polygon’s 

contribution towards the zonal indicative connection capacity, it was necessary to establish a wind 

turbine array within each polygon’s boundaries. For the purposes of this report, these arrays were 

based on current, prototype, or proposed multi-MW wind turbine models that could achieve market 

realisation in the timescales of the Round 3 projects. 

Each polygon was allocated one of two wind turbine model types to maximise the power density 

achieved to meet the zonal indicative connection capacity required. The arrays were constructed 

based on standard wind farm turbine spacing principles of seven rotor diameters apart in the 

prevailing wind direction and four rotor diameters apart in the direction perpendicular to the 

prevailing wind [2]. The wind turbines used in this study and the corresponding array spacings are 

shown in Table 3. Note that the wind turbine types used here do not represent an exhaustive list of 

potential machines that could be used for the Round 3 offshore projects but as indicative wind 

turbine capacities for the purposes of this report. 

Turbine type Capacity Rotor Diameter 

REpower 

5M 

Clipper Wind 

Britannia 

Prevailing wind 

array spacing 

Perpendicular 

array spacing 

5MW 126m 882m 504m 

7.5MW 150m 1050m 600m 

Table 3: Wind turbines utilised and corresponding array spacings 

Each wind farm’s array was orientated as far as possible to the prevailing wind direction in the UK, 

i.e. from the South West, and the potential power capacity established. Some of the polygons 

could accommodate far more wind turbines than required to meet the zonal indicative connection 

capacity, and hence the arrays in this case were limited by the connection capacity available 

and/or the contribution required to the zonal indicative connection capacity (see Figure 3). Some 

polygons were excluded from the connection designs in zones where the potential connection 

capacity of the polygons exceeded the zonal indicative connection capacity provided by The Crown 

Estate. The zonal and wind farm capacities arrived at are shown in Table7. 


Figure 3: Hastings Zone showing potential and utilised array area 

(KEY: Green Dot – Wind Turbine Blue Dot –offshore substation) 

3.2 Establishing number and location of offshore platforms 

The traditional voltage for interconnecting offshore wind turbines in the UK is 33kV however due to 

the power capacities accumulated in each Round 3 wind farm and the distance from shore it is not 

possible for the power to be transmitted to the connection points on shore at this voltage. Hence 

offshore substations will need to be established within each Round 3 wind farm to accumulate the 

power from the array and step up the voltage to a level appropriate for transmission over distance. 

The amount of power that can be accumulated at one offshore substation, and hence the number 

of offshore substations required for each wind farm will be dictated by the power carrying capacity 

of the onward transmission medium, the power carrying capacity of the array cabling, the number 

of wind turbines, and the distance from the platform to the furthest wind turbine in the array, (as 

using excessive lengths of 33kV cable to connect an array can lead to onerous power losses). 

For the purposes of this report it was deemed pragmatic to consider the use of 245kV three-core 

cross-linked poly-ethylene (XLPE) insulated subsea cable as the immediate transmission medium 

from each of the offshore platforms, irrespective of whether it would be AC or DC technology that 

would ultimately provide the transmission medium from the entire offshore wind farm or Round 3 

zone to the onshore connection point. 

To ascertain the power carrying capacity of the 245kV cable, ratings were derived from information 

provided by the cable manufacturers [3] and then derated as appropriate for cables situated within 

J tubes [4], which would be required to bring the subsea cables from the seabed onto the offshore 

platform itself. The resultant cable ratings used in this report are shown in Table 4. 


Cable 

Voltage 

Cable Type/Size Current rating Power rating 

Rating after 

12% J tube 

de-rating 

factor 

245kV Copper 1000mm 2 c.s.a 825A 350MVA 308MVA 

Table 4: Intra array cable ratings 

These cable ratings were then applied to each wind farm’s indicative installed capacity to establish 

how many platforms would be required for each wind farm and hence how many ‘arrays’ radiating 

out from those platforms each wind farm would contain. For the purposes of this report in order to 

minimize offshore transmission cable lengths (and hence losses and cost) the number of platforms 

was kept to a minimum and each platform was placed on the side of the wind farm orientated to 

the likely connection point, (although this would result in larger offshore platforms with a 

requirement for sixteen switch panels at 33kV and array cable lengths of up to 13km with minimal 

losses at full load). In practice the location and number of the offshore platforms will be dependent 

on the capital and operational costs for both the offshore transmission network and the wind farm 

cable array, with design parameters optimised for a particular wind farm. 

3.3 Connection link technologies, capabilities and limitations 

Section 3.1 described how the raw wind farm capacities were arrived at, however due to the large 

Round 3 wind farm capacities considered and the distance of some of the wind farms from 

potential connection points on the onshore network, the cost of the offshore transmission assets 

and therefore their capability will play a significant part in the economic viability of each project. 

For this reason a number of connection technologies and their capabilities and limitations were 

assessed for this report and each is described briefly below. 

3.3.1 AC cables 

The advantage of using AC cables as a connection medium is obvious when the requirement is to 

link an offshore farm or farms which are generating at AC with an onshore network that is 

supplying AC, however the capabilities and limitations of AC cables are also well known, especially 

when it comes to crossing long distances. A characteristic of AC cable circuits is the charging 

current induced in the cable due to the capacitance between each phase conductor and earth. 

The charging current can be mitigated by connecting reactive compensation at regular intervals 

along the cable, however as most of the Round 3 wind farms require long sections of subsea 

cable, providing this interstitial reactive compensation would present an added technological and 

financial challenge. However it may be possible to connect shunt reactive compensation to the 

cable at or close to the transition point from subsea to underground cable. Hence an assessment 

of the reduction in effective power carrying capability of the AC cable described in Section 3.2 due 

to charging current and resistive (I 2 R) losses and the effect of adding reactive compensation at 

three points along the cable route length was carried out using the PSS/Sincal power system 

analysis software. An explanation of the analysis methodology is given in Appendix 2 while the 

results of this analysis are shown in Table 5. 


Length 

(km) 

no 

rpc 

Reactive Power Compensation Optimised 

P received (MW) Q received (MVAr) 

Reactive compensation 

applied (MVAr) 

50/50 

split 

33/33/3 

3 split 

no rpc 

50/50 

split 

33/33/33 

split 


no 

rpc 

50/50 

split 

33/33/33 

split 

no rpc 

S total (MVA) I average (kA) 

50/50 

split 

33/33/ 

33 

split 

no 

rpc 

50/50 

split 

33/33/33 

split 

0 330 330 330 -108 -108 -108 0 0 0 347 347 347 NA NA NA 

20 329 329 329 75 0.589 -1.429 0 37 26 338 329 329 0.709 0.717 0.713 

40 329 329 329 160 -0.558 1.387 0 79 52 365* 329 329 0.721 0.730 0.718 

60 328 328 328 247 0.784 0.446 0 120 80 411 328 328 0.747 0.745 0.726 

80 327 327 327 339 0.682 -0.149 0 162 108 471 327 327 0.785 0.765 0.736 

100 325 326 326 435 -0.808 -0.300 0 205 136 543 326 326 0.836 0.789 0.748 

120 323 325 326 537 0.876 0.128 0 247 164 627 325 326 0.900 0.814 0.763 

140 321 324 325 646 -0.830 1.315 0 291 192 721 324 325 0.978 0.843 0.780 

160 317 322 324 765 -1.249 -0.344 0 335 221 828 322 324 1.072 0.874 0.799 

180 311 321 323 896 0.071 -1.217 0 379 250 949 321 323 1.184 0.907 0.820 

200 303 319 322 1042 0.800 -0.993 0 424 279 1085 319 322 1.317 0.941 0.842 

Table 5: Power Transmission Capability of 1000mm 2 subsea cable against route length 

*Figures in red indicates where either the MVA or Current rating of the cable is exceeded 

Cable Data 

operating voltage 

offshore: 

275 kV 

X 0.18 ohms/km 

R 0.023 ohms/km 

C 

onshore: 

0.18 uF/km 

X 0.185 ohms/km 

R 0.023 ohms/km 

C 0.185 uF/km 

Thermal capacity 825 A 

Values from Electrical Cables handbook & 

from ABB XLPE Submarine cable system 

handbook

A further challenge posed by long AC cable circuits is the additional demands imposed on the 

circuit breakers providing protection and control functions due to the large capacitances created 

within the cable, and the attendant cable charging current drawn. Careful selection of circuit 

breakers and control equipment is necessary to ensure that integrity of operation can be ensured, 

particularly when the long offshore cables are being energised without the wind turbine 

transformers in circuit. 

For these reasons AC subsea cables have only been considered as a possible connection 

technology in this report where the total cable route length is less than 100km. 

3.3.2 HVDC 

In DC transmission, a charging current only occurs during the instant of switching on or off, (i.e. to 

charge and discharge the cable capacitance), and therefore has no effect on the continuous 

current rating (and hence power transfer capability) of the cable. In a HVDC system, electric power 

is taken from one point in a three-phase AC network, converted to DC in a converter station, 

transmitted to the receiving point by an overhead line or underground /subsea cable, and then 

converted back to AC in another converter station and injected into the receiving AC network 

(Figure 4). 

Figure 4 Overview of VSC HVDC bipolar transmission for offshore wind farms 

©ABB 

Traditionally HVDC transmission systems are used for transmission of bulk power over long 

distances because the technology becomes economically attractive compared with conventional 

AC lines as the relatively high fixed costs of the HVDC converter stations are outweighed by the 

reduced losses and reduced cable requirements. 

There are two technologies used in HVDC transmission: Current Source Converters (CSC) and 

Voltage Source Converters (VSC). 

CSCs are dependent on an external voltage source to drive the converter and feed its inherent 

reactive power demand. VSCs, on the other hand, function as independent voltage sources that 

can supply or absorb active and/or reactive power, therefore requiring no independent power 

source and making them ideal for offshore deployment. 

However, the power losses arising from the increased switching frequency of the devices used 

within the VSC technology and the power ratings of the technology currently available mean that, 


at very high power transfer levels, CSC technology with some form of commutation support could 

become an option for offshore deployment. 

3.3.2.1 Current Source Converter HVDC technology 

CSC HVDC technology is older than VSC technology and is installed at many locations around the 

world. CSC technology requires a strong AC network to interface the HVDC link so is suited to 

connecting to strong points on existing AC networks. 

CSC systems are currently able to transfer the largest amounts of power for a given number of 

overhead lines or cables because the thyristor technology utilised is able to handle very high 

voltages and currents. ±500kV installations of CSC HVDC are in operation utilising overhead lines 

and ±800kV installations are planned which can transfer up to 6000MW. Utilising cables, the 

highest voltage available is ±500kV, due to the insulation technology of the cable. 

Although CSC HVDC systems are able to control very large amounts of real power flow they are 

unable to dynamically control the reactive power injected to or absorbed from the AC network, in 

contrast to a VSC HVDC converter station. 

Thus a CSC HVDC system requires reactive compensation to be connected to the AC side of the 

converter to compensate for the reactive power drawn by the converter and to provide the required 

reactive power to the grid. 

CSC HVDC converter stations require a strong AC network to interface with, because the thyristor 

technology utilised is “line commutated” (it can be switched on by a control signal but only ceases 

to conduct when the AC network changes polarity, which occurs 50 times a second in the UK). If 

connected to a weak network, commutation of the thyristors may not occur correctly and cause 

instability in the system. To use CSC HVDC technology to connect the Round 3 offshore wind 

farms may require additional compensation in the form of synchronous compensators to provide a 

strong voltage source to commutate the DC current. 

3.3.2.2 Voltage Source Converter HVDC technology 

VSC HVDC is the latest development in the field of HVDC technology, the main difference with 

CSC technology is that VSC converter stations are able to form their own AC voltage waveform 

and act as a true voltage source. This gives total flexibility regarding the location of the converters 

in the AC system since the requirements for the short circuit capacity of the connected AC network 

is low, enabling VSC HVDC systems to be connected to very weak AC systems. Therefore VSC 

HVDC can connect remote electrical islands such as offshore generation without the need for 

additional equipment. 

VSC HVDC technology has the capability to control both real and reactive power rapidly and 

independently of each other. The converter station can operate over a whole region of differing real 

and reactive power, unlike the CSC HVDC converter which can only provide discrete amounts of 

reactive power. This helps to keep the voltage and frequency of the associated AC system stable. 

The key technology that enables VSC HVDC converter stations to produce a voltage waveform is 

the high power Insulated Gate Bipolar Transistor (IGBT) which unlike the thyristors used in the 

CSC systems are self commutated, i.e. they can be switched on and off rapidly (up to 2000 times 

per second) to modulate a voltage waveform. 

At present the power handling capability of the largest available VSC HVDC converter module is 

1000MW at ±300kV, however capabilities of 1110MW may well be possible in the immediate future 

for single converter XLPE insulated bipole pairs operating at ±300kV, and 2000MW to 2200 MW 

for dual converter Mass Impregnated bipole pairs operating at ±500kV. 


Mass Impregnated cables have been the traditional medium for transmission in DC systems until 

now. As the name suggests the conductors are insulated with special paper impregnated with a 

high viscosity compound. They can be used for voltages up to 500kV. 

More recently, as the interest in Voltage Source Converter technology has grown, DC cables have 

also been developed that rely on extruded poly-ethylene as the insulation medium for the 

conductors. These cables are easier to manufacture and correspondingly cheaper than their MI 

equivalent, however currently can only operate at voltages up to 300kV which limits possible power 

flow. 

Figure 5(a) Mass Impregnated 500kV DC cable Figure 5(b) XLPE 150kV DC cable 

©Prysmian Cables ©Prysmian Cables 

Figure 6: HVDC VSC configuration 

©ABB 


Figure 7: HVDC Dual Converter pair redundant bipole with metallic return path configuration 

©ABB 

The ability of the VSC HVDC converter station to rapidly control the active and reactive power 

provides many benefits to the associated AC grid in the form of added stability, flexibility and 

dynamic response, but a significant advantage of VSC HVDC over CSC HVDC is the possibility of 

flexible multi-terminal operation. Multi-terminal operation allows the HVDC system to interface with 

the AC system at any number of points by connecting more converter stations to the DC system. 

Although possible with CSC, control of the power flows in a multi terminal network is more onerous 

than with VSC due to the ability to minutely control the firing of the power electronic devices within 

the VSC converter. 


3.3.3 Gas Insulated Transmission Lines 

Traditional HVAC subsea cables and HVDC subsea bipole technologies are well understood and 

widely applied, albeit maybe not at the power capacities required for Round 3. However, due to the 

large connection capacity required and the distance offshore, other transmission technologies may 

become viable alternatives. 

One such technology is Gas Insulated transmission Lines or GIL. Gas insulated lines, as the name 

suggests encompass a high voltage AC conductor within a sealed aluminium pipeline which is 

filled with a SulphurHexafluoride (SF6)/Nitrogen mix as an insulating medium (see Figure 8). 

Figure 8: Cross section through a GIL showing conductor tube, enclosure and insulators 

© Siemens Power Transmission & Distribution 

The advantage of this technology is that it allows very high power transfers of up to 3000MW per 

three phase system [5], without the disadvantage of the charging current required by traditional AC 

cables, and can be installed underground, above ground or in tunnels (See Figure 9). Hence this 

technology is ideal for the bulk transfer of power over large distances where overhead lines are 

impractical, and has obvious advantages for connecting groups of large offshore wind farms. 

Figure 9: GIL directly buried and in tunnel arrangement 

© Siemens Power Transmission & Distribution 


To date the longest length of GIL installed is the 4.5km at the Tehri Hydro Project in India [6], 

however the European Commission of Trans European Networks for Electricity is sponsoring a 

project looking at the use of GIL in the North Sea, focussing primarily on the installation techniques 

required, which are similar to those applied by the oil and gas industry to install the thousands of 

kilometres of subsea pipelines used in that field. The use of GIL to provide power corridors to 

group the output from a number of offshore wind farms is attracting particular interest in Germany 

because it reduces the impact on the environmentally sensitive areas of that country’s North Sea 

coast which has a parallel with the environmentally sensitive areas such as the Wash and the 

Humber estuary in the UK. 

The disadvantages of GIL for the purposes of Round 3, is that it is as yet an untried technology in 

the subsea environment, and over these distances, that the costs may be excessive compared to 

the more traditional technologies (see Section 6), and that the power capacity of the individual lines 

may be limited by the largest loss of power infeed that can be accommodated by the system 

operator, which is stipulated in the GB Security and Quality of Supply Standards (GB SQSS) (see 

Section 3.4). 

Some environmental concerns also exist over the increased use of the inorganic compound SF6, 

often used in the electricity industry for its dielectric properties, which has been shown to be a 

greenhouse gas with approximately 22,000 times the potency of carbon dioxide (CO2) if released 

into the atmosphere. This would also have to be taken into account when assessing the suitability 

of this technology for the connection of offshore wind generation, as existing onshore transmission 

owners have policies of minimising the use of this gas. 

However the GIL technology is based on seamless welding with practically zero losses (

Figure 10: Cross section of HTS ‘cold’ dielectric cable with copper core to carry fault currents 

© American Superconductor 

As with the GIL systems the advantage of using HTS is to minimise the offshore transmission 

system required for a given power transfer, however again as with GIL, the longest HTS system in 

operation at present (with the Long Island Power Authority in the US) is only half a mile long, the 

technology has never been used in an offshore environment, and due to the requirement for 

coolant pumping stations, the costs may be excessive offshore compared to the more traditional 

technologies. However HTS technology could be considered for some of the onshore connection 

routes as a viable alternative to multiple AC or even DC cables. 

3.4 Establishing offshore redundancy, security & quality of supply criteria 

One of the key criteria that any connection design must consider is the trade off between the initial 

capital investment, and the opportunity cost of lost energy due to losses within the system, 

unavailability due to scheduled maintenance, and unavailability due to faults (which can be of 

particular concern in the marine environment due to the difficulty in finding the faulted section and 

repairing it within a benign weather/tide window). This may result in some form of redundancy, 

either partial or full, being built into the design, which will add to the capital cost, but potentially 

reduce the operating costs. 

Redundancy will also be of interest to the respective onshore system operators, as they will need 

to cater for the loss of power infeed caused by sections of the offshore network tripping out under 

fault conditions. 

A great deal of work has gone into assessing the level of redundancy required for offshore 

transmission assets. In developing these deterministic standards to facilitate a regulatory regime 

for offshore transmission, the Centre for Sustainable Electricity and Distributed Generation (SEDG) 

were employed, on behalf of BERR (now DECC) to undertake cost benefit analysis that would 

underpin these standards. A report entitled “Cost benefit methodology for optimal design of 

offshore transmission systems” [8] has been published outlining the input assumptions, models 

used and results obtained from this work. The results arising out of this work informed the 

recommendations for an offshore security standard published by National Grid and used to 

develop draft text for new, offshore sections of the standard, which is currently under consultation. 

It is from the recommendations of this report that the designs within this study have been derived, 

although with some important deviations as explained in Table 5 below. 


OFFSHORE PLATFORM 

SEDG 

Results 

Platform export Capacity About 95% of installed 

capacity 

GB Offshore SQSS 

Recommendation [9] 

100% of installed 

capacity 

Criteria used for this 

report 

90%+ of installed 

capacity 

Transformer redundancy 50% 50% 50% 

HV / LV terminals 

connected 

Platform export capacity 

following outage of one 

AC circuit 

- Yes Yes 

- Minimum 50% Minimum 50% 

DC offshore platform No redundancy No redundancy No redundancy 

Maximum Power infeed 

loss following outage of 

single DC converter 

OFFSHORE CABLE NETWORK 

Network capacity 95% of installed capacity 

for geographically small 

wind farms 

90% of installed capacity 

for geographically large 

wind farms 

Maximum Power infeed 

loss for loss of single 

offshore transmission 

cable 

ONSHORE SUBSTATION 

1000MW 1000MW 1110MW* 

100% 90%+ 

1320MW 1320MW 1800MW** 

Transformer redundancy 50% 50% 50% 

Table 6: Redundancy Criteria used for this report 

* The 1110MW DC converter power infeed loss is set by the maximum MVA rating of the HVDC voltage 

source converter stations as indicated by the manufacturers. 

**An 1800MW infrequent infeed loss limit (as opposed to the current 1320MW) is representative of the level 

of response and reserve that may be required to be held by the GB system operator in order to 

accommodate the next generation of nuclear power stations. This requirement for an increased level of 

response and reserve is currently under review. Although National Grid sees no technical barrier to its 

implementation, the economic implications are being thoroughly investigated and consulted upon before a 

final decision is made. 

It is also important to note that in the joint Ofgem/BERR Regulatory Policy Update dated 13 th June, 

2008 [16], the need to “Analyse and define the basis for an offshore security standard that can 

cater for generation projects of the size and location of Round 3 projects” was highlighted due to 

the limited scope of previous work. This further analysis, which forms part of the wider 

Fundamental Review of the GBSQSS currently underway [15], will seek to update previous work to 

ensure that it is fit for purpose and applicable to all projects that could reasonably be foreseen to 

arise in the future. This work, being undertaken by the three onshore transmission owners and 

supported by the SEDG Centre, has the potential to impact the design of the offshore transmission 

system (i.e. assets operated at 132kV and above) used in this analysis. 


3.5 Tailoring Installed Capacity to Connection Capacity 

The methodology described in Section 3.1 was used to establish the power capacity of each of the 

wind farms, adjusted to meet the zonal indicative connection capacities. However due to the 

capacities accumulated in each Round 3 wind farm and the distance from shore, the cost of the 

offshore transmission assets themselves will form a significant element within the overall capital 

cost of the wind farm, such that there will be a significant incentive to fully utilize the capacity of the 

offshore transmission assets as far as possible. Due to the variable nature of the wind resource, 

unavailability of individual wind turbines due to maintenance, and power losses in the array 

cabling, a connection design that was capable of transmitting the output from the entire installed 

capacity of the wind farm would only be fully utilized for a small percentage of the wind farms 

lifetime, hence an attempt was made at a high level within the auspices of this study to ascertain 

what the optimal installed generation capacity would be for a given connection capacity. 

The results of this analysis are given in Appendix 1, however in summary for an offshore wind farm 

in the North Sea with an average wind speed on the Dogger Bank of 8.8m/s [10] and an availability 

of 90% (Note. The Round 1 offshore wind farm at North Hoyle had an average availability of 87.4% 

in its third full year of operation (2006-07) [11]), the optimised installed capacity derived was 112% 

of connection capacity. This compares well with the results of the similar analysis carried out by 

SEDG which arrived at an indicative range of 105% to 111% depending on the geographical area, 

(and hence wind diversification), of the wind farm in question [8]. 

This Figure of 112% installed capacity coupled with the technology ratings stated in Sections 3.2 

and 3.3, the zonal indicative connection capacities from The Crown Estate, and the raw wind farm 

capacities derived in Section 3.1 were used to establish the wind farm capacities listed in Table7 

on which the subsequent offshore and onshore designs were based. 


Round 3 Wind farm 

(defined by letter) 

Indicative (Installed) Zonal 

Connection Capacity 

Polygon Installed capacity 

(MW) 

Moray Firth 500 (500) 

Number of Wind Turbines 

C 500 100 x 5MW 

Firth of Forth 500 (500) 

G 500 100 x 5MW 

Dogger Bank 9000 (9907.5) 

H1 1237.5 165 x 7.5MW 

H2 1237.5 165 x 7.5MW 

H3 1237.5 165 x 7.5MW 

H4 1237.5 165 x 7.5MW 

H5 1237.5 165 x 7.5MW 

I1 1240 248 x 5MW 

I2 1240 248 x 5MW 

J 1240 248 x 5MW 

Hornsea 3000 (2477.5) 

M 1237.5 165 x 7.5MW 

N 1240 248 x 5MW 



Round 3 Wind farm 

(defined by letter) 

Indicative (Installed) Zonal 

Connection Capacity 

Polygon Installed capacity 

(MW) 

Norfolk 5000 (4955) 

Number of Wind Turbines 

T 1240 248 x 5MW 

U 1237.5 165 x 7.5MW 

Z1 1237.5 165 x 7.5MW 

Z2 1240 248 x 5MW 

Hastings 500 (500) 

AA 500 100 x 5MW 

West Isle of Wight 500 (500) 

DA 500 100 x 5MW 

Bristol Channel 1500 (1500) 

EA (ac) 1500 200 x 5MW 

EA (dc) 1237.5 165 x 7.5MW 

Irish Sea 5,000 (4,955) 

IA 1237.5 165 x 7.5MW 

JA 1237.5 165 x 7.5MW 

LA 1240 248 x 5MW 

NA 1240 248 x 5MW 

TOTAL 25,500 (25,795) 

Table 7 Round 3 Polygon Installed Capacities 

3.6 Assessing landfall points, onshore cable routes & land availability 

As part of finalising the onshore network points of connection, desktop assessments using 

Ordnance Survey maps and satellite photography were made to ensure that there was sufficient 

land area around the onshore connection points to potentially accommodate the new substations 

or substation extensions and equipment, such as HVDC converter stations, necessary to facilitate 

the offshore network. This method was also used to identify potential landfall locations for the 

transition from the offshore subsea cable to the onshore underground cable, and then establish a 

possible onshore cable route from these landfall points to the onshore network connection points. 

Due to the differential in price between subsea and underground high voltage AC cables (in the 

order of 10%-20%), the onshore cable route length was minimized as far as possible, however 

where required, the cable routes were chosen to follow existing roads or disused railway beds in 

order to limit the elevation changes over the cable route, and also, as far as possible, avoid any 

obstacles such as river crossings that may require directional drilling. 

3.7 Assessing offshore cable routes 

Offshore, the most direct cable routes were established from the offshore substation locations to 

the proposed landfall points. These direct routes were then amended to avoid as far as possible 

any subsea obstacles, such as mineral extraction areas or other wind farms, or excessive changes 

in the depth of the seabed. Where the crossing of subsea obstacles such as gas and oil pipelines 


was unavoidable, the cost of these crossings (using concrete mattresses and rock dumping etc) 

has been included in the overall costings. In order to minimize the cable route lengths onshore, 

wherever possible the subsea cable has been extended up through river estuaries before coming 

ashore. Due to the additional installation and cable protection requirements that may be required 

as a result, particularly in areas where there is heavy river traffic and existing pipeline and cable 

crossings such as the Humber, the potential cost saving in using subsea cables may be eliminated 

although again this will need to be assessed on a detailed case by case basis, which is outside the 

scope of this report. 


4 Offshore Cost Methodology 

In order to provide as accurate a cost model as possible a number of high voltage power 

equipment manufacturers and installers were consulted for the current costs of the equipment that 

would be required to realize the offshore connection designs described in this report. 

To that end information was very helpfully supplied by Siemens, ABB, Areva, Prysmian Cables, 

American Superconductor, ETA ltd, Senergy, and National Grid to facilitate this report. 

Due to the impact on cost of the actual installation conditions specific to the site, and the 

fluctuations in price of raw materials, and limitations of manufacturing resource, the costs of 

equipment quoted by the manufacturers can only ever be generic at this high level stage, and 

hence the cost estimates provided within this report are only indicative. 

The equipment costs provided by the manufacturers were combined with equipment cost 

information in the public domain such as that from the SEDG report [8] and an average price taken 

for each equipment element required for the offshore connection designs. It was these average 

equipment prices that were then used to cost the connection designs proposed. 

The offshore connection designs were costed from the HV transformers on the offshore wind farm 

platforms to the busbar clamps at the onshore substation. These points are also referred to as the 

Grid Entry Point and Onshore Interface Point, respectively, and together would form the extent of 

the offshore transmission system under the proposed offshore regulatory regime. Note that in 

some of the connection solutions proposed in this report, the offshore transmission system extends 

to more distant connection points onshore than those closest to the wind farm. This is because the 

designs proposed balance the need for offshore and onshore reinforcement in order to achieve the 

optimal solution. The connection design cost inclusions and exclusions are listed in Table8 below. 


Offshore Connection Design 

Cost Inclusions 

• 400kV double busbar AIS or GIS 

transformer /feeder bays 

• HVDC converter station onshore 

• Onshore reactive compensation 

• Wind farm substation compound land 

cost 

• Onshore 3 x single core AC cable 

supply & installation 

• Onshore DC bipole supply & 

installation 

• Transition pit civil works & cable 

winching 

• Offshore three core subsea AC cable 

supply & installation (Transmission to 

shore & inter-platform) 

• Offshore DC bipole supply & installation 

• Offshore platform provision and 

installation 

• Offshore DC converter 

• Offshore platform GIS transformer bays 

• Offshore reactive compensation 

• Earthing transformers 

• Subsea Oil/Gas pipeline crossings 

• 5% contingency 

Cost Exclusions 

• 33kV offshore switchboards 

• Wind farm 33kV array cabling 

• Offshore reactive compensation for array 

cabling 

• Wind Turbines and installation 

Table 8 Offshore connection design cost inclusions 

Each connection design was based on a generic 245/33kV offshore platform design, HVDC 

converter arrangement, and onshore 400kV transformer feeder bay arrangement which are detailed 

in Senergy Econnect drawing numbers 1845 009, 010, and 011 below. Drawing 009 represents the 

HVAC design used for the 500MW wind farms, drawing 011 the HVAC design for the 1200MW wind 

farms and drawing 010 the HVDC design for the 1200MW wind farms. Note that the equipment 

ratings shown in these drawings will change depending on the specific connection design. 

The cost of land required for converter stations and wind farm substation compounds will vary 

substantially depending on the location. However, for the purposes of this report an average land 

cost of £75k per hectare for brown field sites and £150k per hectare for green field sites was used in 

line with National Grid estimates. 

The cable costs include material, transportation from the factory, laying and burial with trenching of 

the subsea cable with water jetting down to a maximum of 1m and normal excavation for the land 

cable down to a maximum of 1m. 


The amount of reactive compensation included at both the offshore platform and onshore connection 

point have been derived from the results in Table4. The reactive compensation applied is solely to 

compensate for the capacitive charging current of the transmission cable and to maintain a unity 

power factor at the receiving end, and does not allow for any compensation of the wind farm array 

cabling. Note that the revised drafting of the System Operator/Transmission Owner Code (STC) to 

facilitate the proposed offshore regulatory regime includes an obligation on the owner of the offshore 

transmission assets to provide a reactive capability of 0.95 lead to 0.95 lag at the interface point with 

the onshore transmission network. The additional static and dynamic reactive compensation 

equipment required to meet this obligation has not been costed as part of this report as each wind 

farm could require a bespoke solution, however this could have a significant cost and land 

requirement implication for those zones connecting using AC technology. 

Initially each wind farm connection design was costed according to the appropriate technology used, 

however where a connection design could feasibly use either AC or DC technologies, both 

connection designs have been costed for comparison. In the same way where there is more than 

one technology that could be used to connect multiple wind farms within a zone to an onshore 

connection point, both options have been costed where possible to provide a comparison. 

As regards the switchbay technology used for the cost estimates onshore, Gas Insulated Switchgear 

(GIS) was used where the connecting substation was 5km or less from the coast, and Air Insulated 

Switchgear (AIS) used for all other cases. Offshore all the switchgear used was GIS. 

A summary of the costs for each wind farm connection design is provided in Sections 6&7 of this 

report with the detailed cost breakdowns forming the bulk of the appendices to this report. 





5 Onshore Design 

The onshore electricity transmission system, as it exists today, has been built up over a period of 

time around the prevailing generation and demand background. It takes the electricity produced by 

generators across Great Britain and transmits it over large distances to points where the lower 

voltage, distribution networks take it further to the actual demand consumers. The transmission 

system is designed to ensure that electricity demand can be supplied at times of peak load and to 

facilitate competition in the electricity market in an economic and efficient manner. 

5.1 Assessing requirements for additional capacity on the onshore 

transmission system 

In assessing the need for additional capacity on the transmission system, transmission owners 

(including National Grid Electricity Transmission in England and Wales) are required by their 

transmission licences to design the system to accommodate peak demand levels according to the 

minimum, deterministic criteria outlined in the GB System Security and Quality of Supply Standards 

(GB SQSS) [12] complemented with a limited amount of additional cost benefit analysis for year 

round conditions. The total nominal output capacity of generating plant connected to the system at 

any given time exceeds the forecast peak demand, since a margin is required to cover for inevitable 

plant breakdowns and forecasting errors: in planning timescales there is always some uncertainty 

over the distribution of demand and the generators that will actually run to supply it. The GB SQSS 

sets out criteria for designing the system infrastructure (The Main Interconnected Transmission 

System, or “MITS”) in order to address these uncertainties. 

Currently, the generation fleet in Great Britain is largely comprised of conventional coal, gas and 

nuclear units with a peak-demand availability of > 80%, thus limiting the possible range of input 

assumptions to the analysis. Unless restricted by breakdowns, conventional generators normally run 

at, or close to, their maximum output since this is their most efficient mode of operation. Renewable 

generation generally exploits variable energy sources such as wind or solar energy. Wind turbines 

will seldom operate at full output individually, and even more rarely collectively. An economic and 

efficient onshore transmission system that incorporates substantial renewable generation will have to 

be designed to handle the variability of wind power together with its interactions with conventional 

plant availability and demand uncertainties. 

Over a year, the average output of offshore wind generators can be expected to be of the order of 30 

– 40% of their rated output, but wide variations will occur during the year. The network must be 

designed so that power can be exported from areas with wind generation when wind output is high, 

whilst allowing sufficient power to be imported to areas with wind generators when their output is low. 

To a large degree, the output from wind generation will share transmission capacity with 

conventional generation. This is particularly the case where the location and distribution of wind 

generation is similar to that of conventional plant in a given area and where the spread in marginal 

cost between wind and conventional generation is relatively large (i.e. areas where coal and gas 

generation are located with wind). The sharing of existing capacity will not occur to the same degree 

in areas of the system where this spread in marginal cost is much less (i.e. areas where nuclear 

generation is located with wind). 

The criteria in the current GB SQSS for design of the MITS are suitable for a system comprised of 

conventional generation with only a small amount of renewables and so need to be developed 

further to encompass large volumes of renewable generation. This has been the subject of much 

recent work in the UK which continues under the auspices of the Fundamental Review of the GB 

SQSS which is currently being directed by the GB-SQSS Review Group [13]. Modified standards 

arising from that Review will not come into force before 2010, so the analysis for this report has been 

done using the same interim methodology used for the 2008 Seven Year Statement, and outlined in 

Chapter 7 of that document [14]. 


In addition to criteria for design of the MITS, the GB SQSS also specifies requirements for the local 

connections to power stations. These must be designed to carry 100% of the output of a power 

station minus any local demand. These criteria have been applied in this project to determine the 

local transmission capacity needed at each point of connection to the GB Transmission System. 

5.2 Scenario – Background assumptions on generation and demand 

It is clear from Section 5.1, above, that the generation and demand pattern assumed in assessing 

additional capacity requirements for the onshore transmission system can have a large impact on the 

outcome of the assessment. In addition, the further one moves towards the future, the more 

uncertain the likely generation and demand pattern becomes. Therefore it is general practice to 

choose a scenario that represents one possible future outcome for analysis, as well as to investigate 

sensitivities around this scenario to identify the effects of different possible future outcomes. 

The proportion of generation by fuel type within the scenario utilised for this study is illustrated in 

Figure 11, below. 

Figure 11: Proportion of Generation by Fuel Type in Base Scenario 

From Figure 11, it is clear that the scenario used for this study is characterised by a large proportion 

of generation from renewable sources (approx. 40%) and that the bulk of this is provided by offshore 

wind. Also of note is that the proportion of electricity generated from coal is assumed to reduce 

significantly with new ‘Clean Coal’ technologies replacing all existing coal generators on the system 

to form only a small portion of the total. Gas fired generation will likely play a large role in a world 

with large volumes of renewables due to its flexibility and efficiency. Many of the existing nuclear 

stations have come off of the system and the scenario has assumed that only two new units will be 

constructed within the timescales considered. Some of the main sensitivities discussed in this report 

will be around the possibility of further nuclear connections, where this could affect the solution for 

the connection of Round 3 offshore wind. 

In this scenario, all onshore, transmission connected wind was assumed to connect in Scotland. 

Currently there is insufficient transmission system capacity to facilitate this level of generation in 

Scotland. The Electricity Networks Strategy Group (ENSG) has instigated a collaborative study 

between the three onshore transmission owners that will seek to ascertain the reinforcements 

required to facilitate the 2020 targets. Two potential reinforcement options being investigated are 

incremental upgrades to the onshore transmission system and offshore HVDC links which will bypass 

large, congested portions of the onshore network. This scenario has assumed that two HVDC 

links will be established; one on the West coast from Hunterston to Deeside and one on the East 

coast from Peterhead to Hawthorne Pit. The collaborative study is still ongoing, so this work has not 

yet concluded. However, in order to facilitate this investigation for potential Round 3 wind projects, 


this was deemed a reasonable assumption. The scenarios used for this study and that of the 

collaborative study are broadly consistent, given the range of sensitivities considered. 

Projected peak demand levels also play an important role in the scenario assumptions. In the base 

scenario demand is expected to decrease by approximately 8% to 56.3GW, reflecting the potential 

impact of energy saving measures and increasing contribution of small, embedded generation 

projects. 

5.3 Onshore Transmission Requirements: Methodologies for Costing and 

Option Analysis 

As outlined above, the final choice of onshore connection points for the indicative Round 3 offshore 

development zones was determined by finding an economic balance between the offshore and 

onshore reinforcement required, including the cost of both local (substation and circuits) and wider 

(Main Interconnected Transmission System (MITS)) onshore reinforcements against the scenario. 

The onshore transmission system refers to the entire network beyond the onshore interface point 

forming the boundary between the onshore and offshore transmission systems. 

5.4 Cost Basis 

Costs for various components of the overall design have been based on: 

• Offshore and onshore AC & DC cables – Data provided by manufacturers through Senergy- 

Econnect, as outlined in Section 5. For onshore AC cables these have included comparisons 

with National Grid’s cost estimating system 

• Onshore substation work – Budgeted from either site specific estimates for revisions to 

existing installations, using National Grid’s cost estimating database, or using ‘generic’ 

estimates around a range of basic transmission network elements – e.g. for new substations 

a series of standard arrangements have been assumed and cost estimates created for these. 

As such, costs may vary when local requirements at individual locations are taken into 

account 

• At each of the National Grid substations an evaluation of land requirements and availability 

was undertaken to determine if additional land and planning consents would be necessary. 

Where appropriate, estimates for undertaking this work have been included 

• New overhead lines – Where these are proposed, a generic cost estimate has been used, 

based on ‘standard’ circumstances- i.e. foundations, access, and routing (i.e. assuming 

reasonable sections of overhead line are in straight lines and do not require significant 

quantities of angle towers for changes of direction) 


Onshore Transmission System Design Cost Inclusions 

• Busbar extensions for new connection bays 

• Busbar protection, for new connection bays 

• Substation extensions, including fencing, surfacing, drainage 

and internal access roads 

• Land purchase 

• Surveys and environmental impact assessments 

• An allowance for site screening 

• Obtaining planning permission, or overhead line consent for the 

National Grid works 

• Substation reconfiguration costs 

• Additional circuit bays for infrastructure modifications 

• Overhead line diversions into new substations 

• Where combined with a DNO connection all costs associated 

with providing this, including SGT’s and LV connections. 

• All civil works for National Grid assets 

• Protection and Control changes, including remote ends of 

modified circuits 

• Overhead line construction or re-stringing 

• For new sites/routes an allowance for siting and routeing studies 

and consultation 

• Works award process costs 

Table 9 Basis of Onshore Transmission Costs 

NB: All costs are based on 2008 price levels 

Cost 

Exclusions 

• System access 

constraints 

• Circuit outage – system 

uplift costs 

• Consent /planning 

permission mitigation 

• Third Party Costs 

Where new overhead line (OHL) routes are proposed route lengths have been estimated assuming 

that routes will avoid environmentally and visually important areas. In estimating the cost of these 

circuits no allowance has been made for the potential need to install sections as underground cable, 

apart from some line entries to substations or water crossings where it is apparent that this will be 

required. The overall cost of any new OHL routes could increase if sections of underground cable 

are required. 

The major new 400kV infrastructure overhead line routes considered have all been estimated on a 

‘stand-alone’ cost. The possibility remains, that for certain sections mitigation measures may be 

identified where adopting, and rebuilding an existing 132kV route owned by a Distribution Network 

Operator (DNO), may be appropriate. No allowance has been made for this, or for the creation of any 

additional DNO supply points that may arise as a consequence. 


GW of Round 3 offshore wind. This assumes that the collective requirements for all the wind farms in 

a zone are required and that the overall onshore transmission system changes will all occur in a 

coordinated manner at any one location. Should piecemeal developments be undertaken, wind farmby-wind 

farm, and/or wind generation capacity change incrementally over a period of years, the 

staggered timing of the works would result in multiple site/circuit extensions and this will increase the 

overall onshore costs and environmental impact. In order to avoid this extensive stakeholder 

engagement, coordination and collaboration is required. 


5.5 Option Analysis 

In order to identify and cost the onshore connections and transmission reinforcements, three 

approaches to system design were considered: 

• Extending the offshore cables inland to existing onshore transmission sites; 

• Extending the GB Transmission System to new connection substations at the coast; 

• Hybrids of the above approaches 

An examination of the Round 3 zones show that they fall into two broad categories: 

Zones with only one or two wind farms and relatively small overall capacities (1500 MW or 

less) 

For these zones, typified by Hastings or West Isle of Wight, major reinforcements to the onshore 

transmission system were not required against the scenario, apart from extensions to existing 

substations or the establishment of new substations at the onshore interface point. The design 

process optimised the costs of cabling from a landing point to an existing substation, to a new 

substation on an existing transmission route, or to a new substation close to the coast, with the main 

interconnected transmission system extended to it. The savings in cable costs due to connecting to a 

new, rather than an existing substation outweighed the cost of the new substation in some instances. 

Zones with several wind farms and larger capacities (approx. 3000 – 11000 MW) 

For these zones – Irish Sea, Dogger Bank, Hornsea, and Norfolk – the approach was similar to that 

used for the smaller zones but the essential difference was that the larger power injection 

concentrated in one area of the system meant that transmission network reinforcement would be 

necessary. The design optimisation therefore included costs for reinforcing the main interconnected 

transmission system as well as the cost of simply connecting the offshore wind to one or more grid 

substations. 

The overall system changes required for these larger zones are such that a wind farm-by wind farm 

breakdown is misleading as the costs are driven by the totality of the installed wind generation, and 

cannot be itemised to individual wind farms. Put another way, each individual wind farm might 

require little or no reinforcement, but in combination they do. Solutions are therefore presented for 

complete zones. 

5.6 Scottish System Area 

The same approach was taken with regard to the zones located closest to the Scottish Transmission 

Owner sites. Working from published network data, high level evaluations were made of possible 

connection options. 

The costs estimates used have been based on an average of similar works proposed for the National 

Grid substation and overhead line works, and would require verification from the relevant 

Transmission Owner. The connection options identified for these areas are therefore more prone to 

revisions than those proposed for England and Wales. 

6 Overall Design Options and Potential Zonal Solutions 

The various options considered, high-level design considerations and potential zonal transmission 

network solutions are summarised below. These are presented against the input assumptions of the 

scenario, taking into account relevant sensitivities and a background of general reinforcements which 

are assumed to have already been completed within the timescales analysed. 


6.1 Moray Firth 

1 

2 

Option 

0.5GW AC 

to new 

substation 

0.5GW AC 

to Keith 

OWF Offshore 

Transmission Substation 

Extension 

Onshore Transmission 

Network 

Reinforcement 


Total 

C £178m £15*m £193m 

subject to 

collaborative 

TO study 

outcome 

C £256m £3*m 

£259m 

Table 10 : Connection cost for Moray Firth Zone 

Comments 

- indicative 

onshore costs 

- based on 

England & 

Wales average 

- indicative 

onshore costs 

- based on 

England & 

Wales average 

* It is important to note that Scottish Transmission owners have not been consulted in putting together the onshore 

transmission costs and that these were compiled on the basis of average costs in England and Wales. This portion of the 

costs could change significantly as a result. 

Figure 12: Moray Firth zone connection overview

6.1.1 Offshore connection 

Due to the nominal capacity of the offshore wind farm (OWF) located in the Moray Firth and the 

distance to the potential connection points a HVDC connection solution was discounted for economic 

reasons. Instead an HVAC solution has been proposed consisting of two offshore 33/245kV 

substations interconnected with a single three core 245kV cable, and each with a single three core 

245kV shorelink cable to transmit the power accumulated from the wind farm to a transition pit 

located at the landing point onshore. From this transition pit six single core 245kV cables have been 

routed to the potential connection point at Keith 275kV substation. The onshore cable route follows 

the road network as much as possible however there are a number of obstacles that would need to 

be crossed along the proposed route. The estimated cost for directional drilling under these 

obstacles has been included as part of the overall offshore connection cost estimate. Due to the total 

HVAC cable length of this connection, a significant amount of reactive compensation is required to 

maintain adequate power transfer levels. This reactive compensation has been located both on the 

offshore substations and in an onshore substation compound adjacent to Keith substation along with 

the associated switchgear and step up transformers which form part of the offshore transmission 

assets. Both the offshore and onshore substations have been designed to comply with the offshore 

SQSS proposals (see Section 3.4) and are represented in diagrammatic form in Senergy Econnect 

drawing 1845 009 (p34). It has been assumed that a two switchbay extension to Keith 275kV 

substation would be required to connect the Moray Firth OWF however this would need to be 

confirmed with the onshore transmission asset owner. 

6.1.2 Offshore connection alternatives 

The alternative connection solution for the Moray Firth OWF follows the same offshore connection 

route and design but connects to a new 275kV substation a couple of kilometres from the landing 

point. As the assets from this point onward would form part of the onshore transmission network, this 

option is discussed in more detail in Section 6.1.3. 

6.1.3 Onshore reinforcement 

Currently, the onshore transmission system is unable to transmit the electricity generated by the 

large volumes of renewable generation expected to arise in Scotland down into England where the 

majority of demand for electricity is located. The original ‘Renewable Energy Transmission Study’ 

(RETS) and ‘RETS revisited’ undertaken in 2003 and 2005 respectively, did not envisage the 6 to 

11GW of renewable generation now considered likely. Therefore a further collaborative study is 

underway between the three onshore transmission owners; National Grid Electricity Transmission 

(NGET), Scottish Power Transmission Ltd. (SPT) and Scottish Hydro Electric Transmission Ltd. 

(SHETL) under the Electricity Networks Strategy Group (ENSG), to develop the transmission system 

in order to facilitate the levels of generation assumed to be required to meet 2020 renewable targets. 

The study underpinning this document has not sought to pre-empt the outcome of the 

aforementioned collaboration and has made the assumption that the necessary reinforcements from 

Scotland into England are already in place. The impact of the need for these reinforcements on the 

connection of further rounds of wind leasing is predominately limited to those wishing to connect 

offshore in Scotland, such as the Moray Firth, north of this critically congested part of the network. 

The alternative connection option relies on potentially adopting an existing 132kV overhead line that 

runs from Keith towards the coast, upgrading this line to 275kV and establishing a new 275kV 

substation at the coast. The cost of this new substation has been included in Table9, but the cost of 

the line upgrade and associated distribution network works has not for the reasons identified above. 


6.2 Firth of Forth 

1 

2 

Option 

0.5GW 

AC to 

Torness 

0.5GW 

DC tied 

into VSC 

1.1 GW 

East 

Coast 

link 

OWF 

Offshore 

Transmission 


Substation 

Extension 

Network 

Reinforcement 


Total 

G £135m £15m £150m 

G £165m n/a 

subject to 

collaborative TO 

study outcome 

Table 11: Connection cost for Firth of Forth Zone 

£165m 

Comments 

- indicative 

onshore costs 

- based on 

England & 

Wales average 

- HVDC 

interconnection 

assumed 

- Control system 

technical issues 

* It is important to note that Scottish Transmission owners have not been consulted in putting together the 

onshore transmission costs and that these were compiled on the basis of average costs in England and Wales. 

This portion of the costs could change significantly as a result. 

Figure 13: Firth of Forth zone connection overview


Again due to the nominal capacity of the offshore wind farm (OWF) located in the Firth of Forth and 

the distance to the potential connection points a HVAC solution has been proposed consisting of two 

offshore 33/245kV substations interconnected with a single three core 245kV cable, and each with a 

single three core 245kV shorelink cable to transmit the power accumulated from the wind farm to a 

landing point onshore. As the proposed connection point at Torness 400kV substation is on the 

coast, the design assumes that the subsea cable will be brought into the substation cable sealing 

ends, with no transition to single core underground cable. 

Again the necessary reactive compensation has been located both on the offshore substations and 

in an onshore substation compound adjacent to Torness substation along with the associated 

switchgear and step up transformers which form part of the offshore transmission assets ( see 

drawing 1845 009 (p34). It has been assumed that a two switchbay extension to Torness 400kV 

substation would be required to connect the Firth of Forth OWF however this would need to be 

confirmed with the onshore transmission asset owner. 


The alternative connection solution for the Firth of Forth OWF makes use of a proposal to introduce 

an offshore HVDC transmission link between Peterhead and Hawthorn Pit to reinforce the onshore 

transmission network and accommodate expected power flows from the generation capacity installed 

onshore and offshore in Northern Scotland. The route of this offshore transmission link is likely to 

pass very close to the Firth of Forth OWF and hence a 500MW HVDC converter could be connected 

to the HVDC transmission link at this point to allow transmission of generation output from the OWF. 

This solution relies on the HVDC bipole forming the section from the OWF to Hawthorn Pit being 

sufficiently rated to allow transfer of the expected power flow from Peterhead and the output 

expected from the OWF coincidentally. The connection design for the OWF relies on two 33/245kV 

offshore substations interconnected with a single three core 245kV cable, and each with a single 

three core 245kV cable to transmit the power accumulated from the wind farm to an offshore platform 

housing the HVDC VSC 500MW converter. 

As the East Coast Interconnector assets would effectively form part of the onshore transmission 

network, this option is discussed in more detail in Section 6.2.3. 


As highlighted in Section 6.1.3, the study underpinning this document has not sought to pre-empt the 

outcome of the transmission owner collaborative study currently underway and has made the 

assumption that the necessary reinforcements from Scotland into England are already in place. The 

impact of the need for these reinforcements on the connection of further rounds of wind leasing is 

predominately limited to those wishing to connect offshore in Scotland, such as the Firth of Forth, 

north of this critically congested part of the network. 

The main options being considered under this work are incremental upgrades to the onshore 

transmission system and offshore HVDC links on the west coast from Hunterston to Deeside and on 

the east coast from Peterhead to Hawthorne Pit. This study has considered a scenario where the two 

offshore HVDC links are in place. Therefore, sufficient capacity is assumed to exist from Scotland 

into England in order to facilitate this investigation. 


6.3 Dogger Bank & Hornsea 

Due to the potential connection capacity and distance from shore of the Dogger Bank Zone, there is 

much greater potential for optimisation in bringing the wind power onto the onshore transmission 

system. Also because the offshore wind farms in the Hornsea zone are likely to connect in the same 

area of the network as the Dogger Bank offshore wind farms this initial investigation into a 

coordinated approach has assessed transmission network reinforcement requirements for both 

zones based on the following approaches: 

• Offshore transmission connections extended inland to existing National Grid substations at 

Creyke Beck, Thornton, Drax, Keadby and South Humber Bank 

• Hybrid arrangements combining connections to existing transmission sites at Creyke Beck, 

Keadby and Grimsby West and new substations to be established near Killingholme and on 

the Lincolnshire coast 

Note that in some of the connection solutions proposed in this section, the offshore transmission 

system extends to more southerly connection points onshore than those adjacent to the Dogger 

Bank zone on the North East coast. This is because the designs proposed balance the need for 

offshore and onshore reinforcement in order to achieve the optimal solution. The design issues 

associated with each of these options are outlined in Sections 6.3.1.and 6.3.2 and their costs are 

summarised in the table 12 below. 


Figure 14: Dogger Bank zone option 1 connection overview 






1 

2 

Option 

DOGGER BANK 

2.2GW each: 

Drax 

Thornton 

Creyke Beck 

Keadby 

OWF 

Offshore Transmission 


Substation 



Cost 

H1 Thornton £530m 

J Thornton £580m 

H2 Drax £576m 

H3 Drax £595m 

H4 Creyke £540m 


I1 Keadby £664m 

I2 Keadby £682m 

HORNSEA 

2.2GW at South 

M South Humber £413m 

Humber Bank N South Humber £437m 

DOGGER BANK 

2.2 GW at Creyke 

Beck 

4.4 GW New 

substation Near 

Killingholme 

2.2GW at Keadby 


J Creyke £561m 

H2 Keadby £607m 


H4 Killingholme £568m 


I1 Killingholme £612m 


HORNSEA 

2.2GW at Grimsby 

M Grimsby £413m 

West N Grimsby £438m 

Substation 

Extension 

Cost 

£16m 

£19m 

£14m 

£10m 

£22m 

£14m 

£10m 

£62m 

£16m 

Network 

Reinforcement 

Cost 

Total 

Cost 

£290m £5,948m 

£319m £5,968m 

Comments 

Major Onshore work 

includes: 

- New 400kV OHL 

Willington to 

Chesterfield 

- New 400kV OHL 

Drax- Keadby (sensitive 

to review of GB SQSS) 

Maximum offshore costs 

due to extent of onshore 

cabling to existing sites 

Onshore work includes: 

- 400kV OHL; Grimsby 

West to Walpole (or 

Bicker Fen) 

- 400kV OHL; Creyke 

Beck to Drax (sensitive 

to review of GB SQSS) 

- 400kV OHL; Walpole 

(or Bicker Fen) to new 

substation north of 

Eaton Socon

3 

Option 

DOGGER BANK 

3.3 GW at Creyke 

Beck 

3.3 GW at new 

substation Near 

Killingholme 

2.2GW at Keadby 

OWF 

HORNSEA 

M 

2.2GW at new 

substation along 

Lincolnshire coast N 

Offshore Transmission Onshore Transmission 


Substation 


Cost 



J Creyke £561m 






Lincolnshire 

coastal 

substation 

£404m 

Substation 

Extension 

Cost 

£17m 

£10m 

£52m 

Network 

Reinforcement 

Cost 

£23m 

Lincolnshire 

coastal £428m 

substation 

Table 12: Connection cost for Dogger Bank and Hornsea Zones 

Total 

Cost 

£319m £5,918m 

Comments 

- 400kV OHL; Grimsby 

West to Walpole (or 

Bicker Fen) 

- 400kV OHL; Creyke 

Beck to Drax 

- 400kV OHL; Walpole 

(or Bicker Fen) to new 

substation north of 

Eaton Socon


The capacity of the Dogger Bank and Hornsea OWF and their distance from the proposed 

connection points dictate that a conventional HVAC solution will be impractical and uneconomic and 

hence an HVDC solution has been applied in each case. For the reasons mentioned in Section 

3.3.2, VSC HVDC technology is ideally suited to applications offshore and it is this technology that 

has been used for these connections. Indeed the capacity of the OWF themselves has been tailored 

to the maximum power transfer rating (1110MVA) of a single VSC bipole/converter pair indicated by 

the manufacturers for this study. As each OWF would fully utilise the available power transfer 

capability of its dedicated VSC bipole/converter pair there is no advantage in this primary solution of 

interconnecting the OWF offshore, hence each OWF in these two zones is radially connected using 

an HVDC bipole arrangement to its onshore connection point as indicated in Table12 with the 

offshore (subsea) and onshore (underground) cable costs and obstacle crossings both onshore and 

subsea costed separately. Note that the offshore cable routes themselves are designed to avoid 

areas allocated for mineral extraction, other wind farms, or concentrations of oil and gas pipelines, 

however some pipeline and cable crossings are inevitable, and for some routes numerous, and as 

such the cost of these crossings has been included in the cost estimates within the appropriate 

connection designs. 

There are alternative technologies available which may allow and indeed favour interconnecting the 

OWF in these two zones and some of these options are discussed in more detail in Section 6.3.2 

Offshore the OWF connection design is based on two 33/245kV offshore substations each consisting 

of three 200MVA 33/245kV transformers with associated GIS switchgear. Each offshore AC 

substation is interconnected to an HVAC busbar on the offshore platform housing the HVDC VSC 

1110MW converter via a pair of three core 245kV cables. Although this design requires an extended 

33kV cable array to connect the wind turbines to the offshore substations, it has the advantage of 

reducing the number of platforms, transformers and switchgear, and 245kV AC cable length required 

offshore, and hence represents significant savings in capital cost. As stated previously an analysis of 

the full lifetime capital and operational costs will be required to optimise the overall electrical design 

for each specific wind farm; however such an analysis is outside the remit of this report. 

The power from the offshore converter is then routed through two HVDC cables (forming a bipole) to 

an onshore 1110MVA converter located in a compound adjacent to the National Grid connection 

substation where it is converted back from DC to AC for input into the onshore transmission network. 

Both the offshore and onshore substations have been designed to comply with the offshore SQSS 

proposals (see Section 3.4) and are represented in diagrammatic form in Senergy Econnect 

drawings 1845 010 and 011 (p35 &36). It has been assumed that a two switchbay extension will be 

required at those connection points that are existing substations to connect the Dogger Bank and 

Hornsea OWF in line with the requirement of the offshore SQSS for 50% redundancy in the onshore 

transformers. Again where a new double busbar 400kV substation is deemed necessary, two 

switchbays per wind farm have been allocated and costed as part of the offshore transmission 

assets. 

The three connection scenarios identified in Table12 and represented in Figures 14, 15 and 16 have 

been determined to illustrate the requirement for onshore transmission network reinforcement 

necessary for connection of the Dogger Bank and Hornsea zones (see Section 6.3.3). At each 

connection point sufficient land area has been identified (and costed based on a nominal £/per 

hectare rate) to locate the onshore HVDC converter stations for each OWF adjacent to the existing 

or proposed National Grid substation. 



The three offshore connection alternative options described below (and summarised in Table12) are 

designed to illustrate alternative technologies that could potentially be used in place of the HVDC 

VSC technology used in the primary solutions for the Dogger Bank. The onshore implications of 

using these connection alternatives have not been considered. 

Option 4 foresees the use of Current Source Converter technology to provide the transmission 

medium from the OWF to the onshore connection point. CSC technology combined with Mass 

Impregnated HVDC cables (see Section 3.3) allow for much greater power transfer capabilities than 

VSC. For example option 4 is based on a dual converter HVDC design operating at +/-500kV utilising 

four MI HVDC cables with a common LV return cable. This would give a power transfer capability of 

3000MW. However in order to minimise the inter wind farm AC cabling necessary to accumulate this 

amount of power at the converter platforms, option 1 foresees the installed wind farm capacity in 

polygon I of the Dogger Bank zone being expanded from 2480MW to 3360MW with the 

corresponding increase in offshore substations. The disadvantages of using CSC offshore such as 

the increased physical converter size, and the requirement to provide a strong voltage source in 

order for the converters to operate has been allowed for in the cost estimates. Note that as such 

technology has not been used offshore to date, the cost estimates below can only be indicative at 

this stage. 

Option 5 utilises the GIL technology introduced in Section 3.3.3 to provide a ‘power corridor’ out to 

polygon I in the Dogger Bank, in this option with an installed capacity expanded to 3105MW. The 

creation of these power corridors utilising GIL technology is one option being considered in Germany 

for the connection of their own offshore wind farms in the North Sea. However as yet this technology 

has yet to be installed in an offshore/subsea environment and hence the costs provided by the 

manufacturer for onshore installation have been extrapolated by Senergy Econnect based on 

pipeline and cable laying costs in order to provide the indicative cost estimates in the Table below. 

The other issue to note with this option is that it does not comply with the proposed offshore SQSS 

as the maximum power infeed loss (2771MW at 400kV) would exceed the 1800MW* limit (*see 

Section 3.4). 

Option 6 still utilises HVDC VSC technology offshore but recognises that the cable route between the 

land fall point on the coast and the connection substation at Drax for the H2 and H3 OWF identified 

in Option 1 is extensive. Hence the use of a single HVDC overhead line to transport the bipole 

conductors for both OWF on a more direct route from the land fall point to Drax substation may be 

considered an economic alternative. The costs for HVDC overhead line used in the cost estimates 

below have been derived from a manufacturer’s article in the IEEE Power & Energy magazine [19]. 

Note that this option would not meet the current onshore GB SQSS criteria for the maximum power 

infeed loss (1320MW) for the loss of a double circuit overhead line. 


4 

5 

6 

Option 

DOGGER BANK 

I1 & I2 combined and 

enlarged to 3360MW 

installed and jointly 

connected via HVDC CSC 

to Killingholme 

DOGGER BANK 

I1 & I2 combined and 

enlarged to 3104MW 


connected via GIL to 

Killingholme 

DOGGER BANK 

H2 & H3 

Jointly connected onshore 

via HVDC overhead line to 

Drax 

OWF 

I1 

I2 

I1 

I2 

H2 

H3 


Substation 



Cost 

£M 

Cost 

per MW 

£k 

Killingholme £2,202m £655k 

Killingholme £3,185m £1,026k 

Drax 

£1,076 £434k 

Table 13: Alternative combination connection costs for Dogger Bank zone 

Cost per MW 

comparison 

£ 

I1 & I2 to 

Killingholme 

£501k 

I1 & I2 to 

Killingholme 

£501k 

H2 & H3 to 

Drax 

£473k

Figure 17: Dogger Bank Polygon I CSC connection overview 

Figure 18: Dogger Bank Polygon I GIL connection overview 



In all cases, including those where the offshore HVDC links are brought into existing National Grid 

substations, reinforcement with new 400 kV lines would be needed to ensure enough local 

transmission capacity to carry the full capacity of the wind farms entering the onshore transmission 

system at the onshore interface. This is currently a requirement under Section 2 of the GB SQSS. 

Additionally, a new 400 kV overhead line route would be required to carry the increased power 

transfer southwards from the Yorkshire/Lincolnshire area. This requirement would be driven by the 

criteria of Section 4 of the GB SQSS for design of the Main Interconnected Transmission System 

(MITS). 

The choice of route for this new North to Midlands line depends on the connection points of the 

offshore HVDC links. With “inland” connections (Drax, Thornton, Creyke Beck, Keadby and Grimsby 

West/South Humber Bank – Option 1, above), the most effective option would be a new 400 kV line 

from Chesterfield to Willington, with uprating of the existing 275 kV Brinsworth-Chesterfield circuits to 

400 kV. With connections around the Humber Estuary (Creyke Beck, Keadby, Grimsby West and 

near Killingholme, or new substations close to the coast – Option 2 and 3, above), a route from 

Grimsby through Lincolnshire to Walpole (or Bicker Fen) would be preferred. To be fully effective, 

this line would have to be extended westwards from the Walpole (or Bicker Fen) substation to a new 

substation to be established on the existing Cottam – Eaton Socon circuits somewhere near 

Peterborough. This final section of required overhead line, extending westwards from Walpole (or 

Bicker Fen) would link two critical north to south circuits on the east coast and have the added 

benefit of providing additional onshore transmission capacity for connections into the East Anglia 

region as well as the potential for connecting any future offshore developments further south in the 

Wash. 

The locations of the potential major reinforcements required against the input assumptions used are 

illustrated in Figure 19, below. 


Figure 19: Dogger Bank & Hornsea Local Onshore Transmission Network and Location of Potential Onshore 

Transmission Reinforcement 

Arrangements that involved extending the transmission system eastwards to the coast 

(predominately north of the Humber) to connect all the assumed offshore wind generation in these 

zones involve more construction of new 400 kV overhead line routes and substations than the 

aforementioned options. 

As explained in Section 5, onshore transmission requirements are sensitive to the onshore 

generation background as well as to the energy coming ashore from offshore wind. Requirements 

may also vary as consequences of the current reviews of the GB-SQSS and transmission access 

arrangements. The optimum arrangement found in this investigation with 3.3 GW connected at both 

Creyke Beck and a new substation near Killingholme, and 2.2 GW connected at both Keadby and 

Grimsby West – may well cease to be the optimum choice if the background assumptions change. 

While the costs estimated in this work may be taken as indicative of the likely range of eventual 

costs, the connection arrangements eventually used will depend on the conventional generation 

projects that may be developed in the Yorkshire/Humber area in parallel with the offshore wind 

programme. 

As outlined above, a variety of solutions were considered, for the overall connection of 11GW from 

the Dogger Bank and Hornsea zones. These options ranged from onshore cabling to a variety of 

existing National Grid substations, to providing all new connection points on the Lincolnshire, or 

Yorkshire coasts. Overall the most economic solution is presently to undertake a mixture of cabled 

connections to existing sites and extending the National Grid MITS. 


The primary solution comprises three 1100MVA connections to be cabled to Creyke Beck and two 

1100 MVA connections cabled to Keadby substation. A new 400kV substation is proposed to be 

established at the existing Grimsby West substation along with a new 400kV overhead line, or at a 

new substation on a new Grimsby West – Walpole 400kV overhead line along the Lincolnshire coast 

to accommodate a further two 1100 MW connections,. An additional new 400kV substation to 

accommodate three 1100MW connections is proposed south of the existing Killingholme substation, 

to provide connections into three existing 400kV overhead line routes. 

As mentioned, in addition a new 400kV overhead line is required from Grimsby West to Walpole (or 

Bicker Fen) substation, continuing on to a new 400kV substation to be established on the Cottam – 

Eaton Socon double circuit and another new 400kV overhead line is required from Creyke Beck to 

Drax. The additional cost of this onshore infrastructure is £319m. 

All options require the construction of new 400kV overhead lines and substations to provide a 

compliant system, with all of the capacity connected. The substation extension and network 

reinforcement costs provided above assume that a coordinated approach is taken to the design of 

the offshore network. No environmental impact assessments of the reinforcement options have been 

undertaken at this stage. 


6.4 Norfolk 

For the Norfolk zone transmission system reinforcement requirements were assessed for offshore 

transmission connections extending inland to existing National Grid substations such as Norwich, 

Sizewell and Rayleigh 

Sizewell is a connection point for an existing, advanced gas-cooled reactor (AGR) nuclear generator. 

DECC has yet to complete the Strategic Environmental Assessment for nuclear siting, but the 

connection of new nuclear units at Sizewell is an option that could be constructed within similar 

timescales to that of Round 3 offshore developments. One scenario utilised for this study did not 

include nuclear replanting at Sizewell within the assumed timescales. However, British Energy 

currently has Bilateral Connection Agreements in place for the connection of two European 

Pressurised Water Reactor (EPR) nuclear generators at Sizewell with 1650MW in 2016 and a further 

1650MW in 2021. In light of this further assessments were undertaken to consider the infrastructure 

to provide sufficient onshore transmission capacity if these additional nuclear units at Sizewell 

proceed. The studies also assumed that the existing Sizewell B plant would still be generating as it is 

feasible that there will be some parallel running of both Sizewell B and Sizewell C stations for a 

period of time before decommissioning of Sizewell B takes place. 

Figure 20: Norfolk zone option 1 connection overview 


Figure 21: Norfolk zone option 2 connection overview 

The design issues associated with each of these options are outlined in Sections 6.4.1, 6.4.2, and 

6.4.3 and their costs are summarised in the Table 14 below. 


1 

2 

Option Offshore Transmission £M Substation 

Extension £M 

2.2GW AC 

at Norwich 

2.2GW AC 

at Sizewell 

1.1GW 

Norwich 

1.1GW 

Sizewell 

2.2GW 

Rayleigh 

OWF 

T 

(AC) 


Substation 

Sizewell £223m 

Z2 Sizewell £436m 

U 

(DC) 

Norwich £410m 

Z1 Norwich £451m 

T 

(AC) 

U 

(DC) 

Z1 

Z2 


Network 

Reinforcement 

£M 

Cost 

£M 

Without new nuclear unit at Sizewell 


£30m 

£7m 

Sizewell £223m £23m 

Norwich £410m £4m 

Rayleigh £573m 

Rayleigh £559m 

With new nuclear unit at Sizewell 

£11m 

Total 

£M 

£171m £1,728m 

£187m £1,990 

Table 14: Connection costs for Norfolk Zone 

Comments 

Major onshore work includes: 

- Reconductor of two Sizewell- 

Bramford 400kV double 

circuits, 

- New Bramford 400kV 

substation 

- New 400kV Bramford to 

Twinstead double circuit OHL 

to create a Pelham-Bramford 

double circuit route and 

Bramford-Braintree-Rayleigh 

overhead line with 

reconductoring of Bramford- 

Braintree-Rayleigh OHL 

routes. 

The overall optimum design 

proposed for this background 

(i.e. with new nuclear at Sizewell) 

has sought to minimise onshore 

reinforcement requirements to 

reduce timescales. However, if 

onshore reinforcement where to 

begin in advance of financial 

commitment from users, it may 

be possible for a more economic 

solution to be delivered within the 

necessary timescales.


Due to the proximity of the OWF T and U in the Norfolk zone to their respective connection points at 

Sizewell and Norwich Main, cost estimates for both an HVAC and HVDC solution were derived. 

However due to the their distance offshore, AC solutions for OWF Z1 and Z2 were not deemed 

pragmatic and hence only HVDC connection solutions have been assessed for these two wind 

farms. As explained in Section 6.4.3, the connection points for OWF Z1 and Z2 and hence their 

respective bipole cable route lengths, (which form the bulk of the cost differential between the 

offshore costs in option 1 and option 2), have been determined by the presence or not of a new 

nuclear unit at Sizewell C. 

Offshore the OWF connection designs are based on two 33/245kV offshore substations each 

consisting of three 200MVA 33/245kV transformers with associated GIS switchgear. For the HVDC 

solutions each offshore AC substation is then interconnected to an HVAC busbar on the offshore 

platform housing the HVDC VSC 1110MW converter via a pair of three core 245kV cables. 

The power from the offshore converter is then routed through two HVDC cables (forming a bipole) to 

an onshore 1110MVA converter located in a compound adjacent to the National Grid connection 

substation where it is converted back from DC to AC for input into the onshore transmission network. 

Where a new double busbar substation extension to the existing National Grid substation is deemed 

necessary, two 400kV switchbays have been allocated and costed as part of the offshore 

transmission assets. 

The HVAC connection solution utilised for OWF T and U is different. In this design two 245kV three 

core cables are taken direct from each offshore substation to the landfall point (i.e. four three core 

cables in total). Where required there is a transition at this point from three core subsea cable to 

three single core underground cables per circuit (i.e. twelve cables in total) which are then routed to 

a 245kV busbar in a compound adjacent to the National Grid substation, the voltage is then stepped 

up to 400kV via two 600MVA transformers for input into the National Grid via two GIS or AIS 400kV 

double busbar switchbays as appropriate. The cost of crossing both the offshore and onshore 

obstacles along these cable routes, the cost of the transition, and the cable joints have all been 

allowed for in the cost estimates provided. This design meets the offshore SQSS requirement for 

50% redundancy in export capacity from an offshore platform following loss of an AC cable but does 

not require the offshore substations to be interconnected. This 1200MW HVAC design is represented 

diagrammatically in Senergy Econnect drawing No 1845-011 (p36) 


As explained in the previous section, alternative connection solutions for wind farms T and U were 

costed using HVAC and HVDC technology for comparison purposes. Options 3 and 4 (see Table14) 

demonstrate the breakpoint of where HVAC becomes uneconomic and HVDC economic and vice 

versa. Because OWF T is relatively close to Sizewell, the extra cost of the two HVDC converters 

outweighs the saving in cable cost in using an HVDC solution (two cables for DC as opposed to four 

for the equivalent AC solution), however for OWF U the cost of the additional AC cables particularly 

onshore (with twelve AC cables required as opposed to two for the DC option) more than covers the 

cost of the two converter stations (and their attendant platforms/compounds and switchgear). 

It is the length of this onshore cable route for OWF U and Z1 from the landfall on the Norfolk coast to 

the connection substation at Norwich that is addressed in option 5. This option looks at the impact on 

the overall cost of these two wind farms were the onshore section to be constructed using a HVDC 

double bipole overhead line rather than underground HVDC cable. The costs for HVDC overhead 

line used in the cost estimates below have been derived from a manufacturer’s article in the IEEE 

Power & Energy magazine [19]. Note that this option would not meet the current onshore GB SQSS 


criteria for the maximum power infeed loss (1320MW) for the loss of a double circuit overhead line, 

or for the loss of two generator connection circuits, depending on how this line would be classified. 

Option 6 considers the use of CSC HVDC technology to assess whether combining the Z1 and Z2 

OWF, but reducing the combined installed capacity to 1680MW, and transmitting the power through 

a single CSC converter pair/bipole may be an economic alternative for connection to Rayleigh than 

using the two VSC converter pairs/bipoles in option 2. 

3 

4 

5 

6 

Option 

OWF T connected to 

Sizewell using HVDC VSC 

OWF U connected to 

Norwich using 245kV HVAC 

OWF U and Z1 jointly 

connected onshore via 

HVDC overhead line to 

Norwich 

OWF Z1 & Z2 combined 

and reduced to 1680MW 



to Rayleigh 

OWF 



Substation 



Cost 

£M 

Cost 

per MW 

£k 

T (DC) Sizewell £356m £287k 

U (AC) Norwich £590m £477k 

U 

Z1 

Z1 

Z2 

Norwich £811m £328k 

Rayleigh 

£1,057m £629k 

Table 15: Alternative connection costs for Norfolk Zone 

Cost per MW 

comparison 

£ 

T(AC) to 

Sizewell 

£180k 

U(DC) to 

Norwich 

£331k 

U & Z1 to 

Norwich 

£348k 

Z1 & Z2 to 

Rayleigh 

£457k 

Due to the proximity of parts of the offshore Norfolk zone to Sizewell (as little as 20km at points), a 

portion of the Norfolk zone generation can be brought ashore via AC cables. The distance from the 

offshore zone to Norwich and Rayleigh indicate that HVDC subsea cable could provide a more 

economic solution for connection to these substations. The choice of technology impacts the local 

substation works only in evaluating the onshore transmission reinforcements. 

To enable the full export of the power generated by the OWF onto the onshore transmission system 

plus the generation background assumed in the scenario, transmission reinforcement is required to 

transfer power further south towards the Essex area. 

Whether the Norfolk zone OWF are connected wholly into East Anglia or split between coonection 

points in East Anglia and further south (such as Rayleigh), there is a common set of onshore 

reinforcements arising out of the GB SQSS requirements. The additional incremental capacity 

available due to the construction of a new section of OHL and substation reconfiguration at 

Bramford, allows the full 4.4GW investigated to be connected within the East Anglia region thus 

minimising offshore cable lengths. However, if the connection of new nuclear generation at Sizewell 

is taken into account, further MITS reinforcement is required. The impact of this on the connection of 

OWF is dependent on the relative timing of these developments.

Extending the onshore transmission out to the coast to minimise the amount of onshore cabling from 

the East Coast wind farms was not considered in detail. This solution would necessitate a new 

400kV double circuit line from a new coastal substation to Norwich. As this option still injects the 

output of the OWF into East Anglia it does not alleviate the congested Sizewell to Pelham circuit 

corridor. In this way the onshore transmission reinforcements outlined above would still be required 

and therefore this option was not considered further at this time. However option 5 in Section 6.4.2 

does consider the use of HVDC overhead line from Norwich to the coast. As this route would 

traverse the Norfolk Broads the use of either HVAC or HVDC overhead line would depend on 

planning and project timescales. 

6.4.3.1 Zonal Infrastructure Works (without Sizewell C) 

The connection of HVDC converters at Norwich and Rayleigh substations would necessitate 

additional switchgear and substation extensions. The remaining 1.1GW HVDC connection in this 

zone cannot be accommodated in the existing Sizewell substation compound. As a result, the 

connection proposal is for a new substation (constructed in or around the Sizewell area) and 

connected to the existing Sizewell to Bramford overhead line route that would be a suitable collection 

point for the OWF. The extent of these substation works would be driven by land availability and the 

requirements of the GB SQSS. 

With the levels of OWF assumed in this zone, the increased cable costs associated with extending 

further inland to Bramford substation would outweigh the cost of establishing a new substation at 

Sizewell, given the cost assumptions used. 

The reinforcements required within the East Anglia geographical zone, have been identified at a total 

cost of £171m and include a new substation at Bramford (to accommodate the increase in power 

flows under system contingencies), a new circuit route from Bramford to Pelham and a new circuit 

route from Bramford to Rayleigh via Braintree. The new circuit routes are created by the installation 

of a new section of overhead line from Bramford substation to the circuit tee-point near Twinstead 

The locations of these potential major reinforcements required against the input assumptions used 

are illustrated in green on Figure 22, below. 


Figure 22: Norfolk Zone Local Onshore Transmission Network and Location of Potential Onshore 



6.4.3.2 Zonal Infrastructure Works (with Sizewell C) 

The connection of Sizewell C nuclear generation requires the construction of a new 400kV 

substation and overhead line reinforcements out of the East Anglia area. This includes those 

reinforcements highlighted in Section 6.4.3.1 plus the reconductoring of the existing Rayleigh- 

Coryton-Tilbury overhead line route. 

Similar to the scenario without the new Sizewell C nuclear plant, the connection of a HVDC converter 

at Norwich (1.1GW) substation would necessitate additional switchgear and a substation extension. 

The connection of the new Sizewell C plant initiates the construction of a new substation as well as 

the substantial transmission system reinforcements highlighted above. Here it is assumed that this 

new substation can be extended to enable connection of a single 1.1GW HVDC converter. 

The approach towards establishing the overall onshore/offshore optimum network solution for this 

generation background was initially to try and minimise onshore reinforcement as much as possible 

by cabling offshore in order to reduce the timescales for connection of OWF (given the relative lead 

times of onshore vs. offshore transmission build). In taking this approach, the connection of 2.2GW 

into Rayleigh, along with the associated local substation work required, was introduced. This solution 

is considered optimum for this generation background if it is assumed that the current, approach to 

onshore transmission investment continues and that financial commitment is required from 

generators in order to invest in the necessary transmission capacity. This solution provides a trade 

off between cost and time to delivery if the aforementioned assumption is made. 

However, if onshore reinforcement were to begin in advance of financial commitment from users, it 

may be possible for a more economic solution to be delivered within the necessary timescales. 

There is potential for the total capacity of OWF in the Norfolk zone to connect into the East Anglia 

area in addition to Sizewell C nuclear generation, therefore reducing overall offshore cable lengths 

and hence costs, if a new OHL route were to be established from Walpole to a new substation on the 

Cottam – Eaton Socon line (highlighted in orange on Figure 22) as well as the reinforcements 

highlighted above. 

One final alternative option investigated, in order to further reduce onshore reinforcement 

requirements, was the connection 2.2GW of Norfolk OWF further south into Barking via the river 

Thames. The intention with this option was to bring the generation into the onshore transmission 

system as close to the demand as possible. Due to the complexity of delivering such a scheme, the 

lack of land availability at Barking for siting HVDC converter stations and a significant increase in the 

overall cost of this option relative to those proposed, this option was discounted. 


6.5 Hastings 

1 

Option 

0.5GW 

AC at 

Bolney 

OWF 


Transmission 

£M 


Substation 

Extension 

£M 

Network 

Reinforcement 

£M 


Total 

£M 

AA £182m 1.4 0 £184m 


Table 16: Connection cost for Hastings Zone 

Figure 23: Hastings zone connection overview 

Comments 

This does not 

include the cost 

of reactive 

compensation 

equipment 

required to meet 

reactive 

requirements set 

out in the SO-TO 

code. 

Due to the nominal capacity (500MW) of the offshore wind farm (OWF) located in the Hastings zone 

and the distance to the potential connection point at Bolney a HVDC connection solution was 

discounted for economic reasons. Instead an HVAC solution has been proposed consisting of two

offshore 33/245kV substations interconnected with a single three core 245kV cable, and each with a 

single three core 245kV shorelink cable to transmit the power accumulated from the wind farm to a 

transition pit located at the landing point onshore. From this transition pit six single core 245kV 

cables have been routed to the potential connection point at Bolney 400kV substation. The onshore 

cable route follows the road network as much as possible however there are a number of obstacles 

that would need to be crossed along the proposed route. The estimated cost for directional drilling 

under these obstacles has been included as part of the overall offshore connection cost estimate. 

Due to the total HVAC cable length of this connection, reactive compensation is required to maintain 

adequate power transfer levels. This reactive compensation has been located both on the offshore 

substations and in an onshore substation compound adjacent to Bolney substation along with the 

associated switchgear and step up transformers which form part of the offshore transmission assets. 

Both the offshore and onshore substations have been designed to comply with the offshore SQSS 

proposals (see Section 3.4) and are represented in diagrammatic form in Senergy Econnect drawing 

1845 009 (p34). It has been assumed that a two AIS switchbay extension to Bolney 400kV 

substation would be required to connect the Hastings OWF. 


Alternative connection points were considered at the existing National Grid 400kV substation at 

Ninfield, and at a new substation to be created between Shoreham on Sea and Bolney. The former 

option was discounted due to the extended cable route length (and hence cost), while the latter was 

discounted because of the cost of the onshore transmission network extension necessary to create 

and then connect this new substation (see Section 6.5.3) compared to the cost of taking a cable all 

the way to Bolney. 


For connections of the Hastings polygon, extension of the existing onshore 400kV substation at 

Bolney is recommended. No further infrastructure costs are incurred against the input assumptions of 

the scenario. 

Alternative options have considered similar connections to Ninfield, but these were dismissed due to 

a significant increase to the offshore transmission costs and minimal change to onshore 

requirements. 

An alternative option of providing a 400kV OHL from Bolney towards the coast and establishing a 

new 400/132kV substation close to the South Downs was considered to reduce the onshore section 

of the offshore transmission system (due to the substantial cost of onshore AC cable). This solution 

proposed the adoption of a section of existing 132kV OHL and reconstructing it as 400kV. The 

increased cost of the new substation and upgrade work was greater than the savings in onshore 

transmission cabling cost, and this option was not taken further. 

This part of the onshore system is characterised by one 400kV double circuit from Kemsley 

substation passing Canterbury North, Sellindge, Dungeness, Ninfield and Bolney before branching 

out into further routes at Lovedean. The significance of this solitary double circuit, is that the amount 

of generation connecting into this single route is limited by the need to cater for the loss of a double 

circuit overhead line route in planning transmission capacity (outlined in the GB SQSS). For the fault 

outage of a section of this double circuit route between Kemsley and the new Cleve Hill substation 

west of Canterbury North, all the generation connected southwest on this route will accumulate until 

it reaches Lovedean before it has further outlets onto the rest of the system. The scenario used for 

this study assumes one new 1.6GW nuclear unit at Dungeness. This 1.6GW, coupled with 0.5GW 

from the proposed Hasting OWF and a potential further 1.9GW import from the Anglo-French HVDC 

link would mean that if a second nuclear unit were to connect at Dungeness, a new 400kV OHL 

route would be required out of this region. This region of the system is illustrated in Figure 24, below. 


Figure 24: Hastings Zone Local Onshore Transmission Network 

If all currently contracted generators connected to this area of the system were to be considered in 

conjunction with the possibility of imports on the Anglo-French link, there would be no spare capacity 

on this part of the onshore transmission system. The timescales for connecting a project in this 

region would be impacted by those associated with any onshore transmission reinforcement 

requirements. 


6.6 West Isle of Wight 

1 

Option 

0.5GW AC 

to 

substation 

at 

Chickerell 

OWF 


Transmission 

£M 



Substation 

Extension 

£M 

Network 

Reinforcemen 

t £M 


Total 

£M 

DA £160m £15m 0 £175m 

Table 17: Connection cost for West Isle of Wight Zone 

Figure 25: West Isle of Wight zone connection overview 

Comments 

This does not 

include the cost 

of reactive 

compensation 

equipment 

required to meet 

reactive 

requirements set 

out in the SO-TO 

code. 

Due to the nominal capacity (500MW) of the offshore wind farm (OWF) located in the West Isle of 

Wight zone and the distance to the potential connection point at Chickerell a HVDC connection 

solution was discounted for economic reasons. Instead an HVAC solution has been proposed 

consisting of two offshore 33/245kV substations interconnected with a single three core 245kV cable, 

and each with a single three core 245kV shorelink cable to transmit the power accumulated from the 

wind farm to a transition pit located at the landing point onshore. From this transition pit six single

core 245kV cables have been routed to the potential connection point at Chickerell 400kV 

substation. The onshore cable route follows the road network as much as possible however there 

are a number of obstacles that would need to be crossed along the proposed route. The estimated 

cost for directional drilling under these obstacles has been included as part of the overall offshore 

connection cost estimate. Due to the total HVAC cable length of this connection, reactive 

compensation is required to maintain adequate power transfer levels. This reactive compensation 

has been located both on the offshore substations and in an onshore substation compound adjacent 

to Chickerell substation along with the associated switchgear and step up transformers which form 

part of the offshore transmission assets. Both the offshore and onshore substations have been 

designed to comply with the offshore SQSS proposals (see Section 3.4) and are represented in 

diagrammatic form in Senergy Econnect drawing 1845 009 (p34). It has been assumed that a two 

GIS switchbay extension to Chickerell 400kV substation would be required to connect the West Isle 

of Wight OWF. 


Alternative connection points were considered at the existing National Grid 400kV substation at 

Mannington, and at a new substation to be created between Chickerell and Mannington on the 

existing 400kV overhead line route, however both these options were discounted due to the 

extended cable route length (and hence cost), and the difficult terrain and environmental 

designations along the coastline between Weymouth and Bournemouth. 


For connections of the West Isle of Wight wind farm, extension of the existing onshore 400kV 

substation at Chickerell is recommended. No further infrastructure costs are incurred against the 

input assumptions of the scenario. 

An alternative option considered connection to Mannington, but this was dismissed due to a 

significant increase in the length of both onshore and offshore cabling required along with the 

associated increase in costs and minimal change to onshore transmission network requirements. 

The onshore transmission network in this area consists of a 400 kV double circuit transmission line 

that runs west from Nursling substation near Southampton, via substations at Mannington (inland 

from Bournemouth), Chickerell (Weymouth) and Axminster to Exeter. East of Nursling the line 

connects with generation sites at Fawley and Marchwood before branching out into the wider system 

at Lovedean substation near Portsmouth. The line route is closest to the coast between Chickerell 

and Axminster but otherwise lies several kilometres inland. (Fig 26) 

West of Exeter, the line continues to Indian Queens in Cornwall and then approximately follows the 

North Cornwall and North Devon coast back to Taunton. There it connects with another overhead 

line running directly from Exeter and a single double-circuit line then passes through Somerset to 

Hinkley Point and onwards to connect to the wider system at Melksham. (Fig. 26 refers) 

The transmission system must be designed and operated as required by the GB SQSS so that the 

loss of a section of double circuit line causes no overloading or other unacceptable system 

performance. Following such an outage on the line to the east of any wind farm connection, the 

power from the wind farm would have to flow west to Exeter and then via Hinkley Point to Melksham. 

It would therefore combine with the power from generators at Langage, from any wind farms in the 

Bristol Channel and from nuclear generation at Hinkley Point. This combined power flow could be 

sufficient to trigger a need for significant reinforcements in this area of the network. The extent and 

timing of these reinforcements is subject to the number of nuclear units assumed to be connected at 

Hinkley Point, the amount of offshore wind generation expected to be connected into the south west 

peninsula and the extent to which wind generation is assumed to share capacity with conventional 

generation in this area. 


At the time of writing, 3.3GW of nuclear generation (i.e. 2 x1.65GW units) is contracted to connect at 

Hinkley Point in 2016. However 1.512GW of offshore wind generation, not involved in either the 

Round 1 or Round 2 leasing process, is also already contracted to connect at Alverdiscott in 2014. In 

combination, this level of generation in this area of the South West would trigger the need for a new 

40km overhead line route as well as significant uprating of existing routes 

This region of the system is illustrated in Figure 26, below. 

Figure 26: West Isle of Wight Zone Local Onshore Transmission Network 


6.7 Bristol Channel 

1 

2 

3 

Option 

1.5GW AC 

to new 

substation 

on Torridge 

estuary 

1.5GW AC 

to existing 

Alverdiscott 

substation 

1.1 GW DC 

to existing 

Alverdiscott 

substation 

Figure 27: Bristol Channel zone AC connection overview (options 1&2) 

OWF 


Transmission 

£M 


Substation 

Extension 

£M 

Network 

Reinforcemen 

t £M 


Total 

£M 

EA £345m £37m £48m £430 

EA £404m £34m 0 £438 

EA £413m 33 0 £446 

Table 18: Connection cost for Bristol Channel Zone 

Comments 

- new substation 

- new DNO 

supply 

- Alverdiscott 

double busbar 


double busbar 

- no MITS 

without new 

nuclear at Hinkley 


double busbar 

- no MITS 

without new 

nuclear at Hinkley


Figure 28: Bristol Channel zone DC connection overview (option 3) 

The connection of the Bristol Channel zone OWF presents a number of options. The nominal 

capacity of this zone (1.5GW) exceeds the nominal capacity of a single HVDC VSC converter 

pair/bipole (1100MVA) while for an HVAC connection five 245kV three core subsea cables are 

required to transmit this power output ashore. The accumulation of 1.5GW from the wind farm array 

itself also requires an additional 33/245kV offshore substation to be installed with the wind farm 

effectively split into three sections. In addition there are two possible connection points onshore, the 

existing National Grid 400kV substation at Alverdiscott, and a potential new 400kV substation to be 

established on the bank of the Torridge estuary. 

Option 1 in Table18 considers an HVAC connection for the full 1.5GW to this new substation. 

Offshore the OWF connection designs are based on three 33/245kV offshore substations each 

consisting of three 160MVA 33/245kV transformers with associated GIS switchgear. From the 

Northern offshore substation, one 245kV three core cable is routed directly to the landing point on 

the Torridge estuary, while the other 245kV three core cable is connected to the 245kV busbar at the 

Western offshore substation. The Western and Eastern offshore substations both have a further two 

245kV three core cables connecting them directly to the landing point on the Torridge estuary, 

providing a total of five shorelink HVAC cables and one platform HVAC interconnection cable 

(between the Northern and Western substations). These cables are then routed to a 245kV busbar in 

a compound adjacent to the new National Grid substation, the voltage is then stepped up to 400kV 

via two 750MVA transformers for input into the National Grid via two GIS 400kV double busbar 

switchbays. As this new substation could potentially be on or very close to the bank of the estuary no 

transition to single core underground cables has been deemed necessary. 


Option 2 considers the same HVAC design offshore but this time with the existing substation at 

Alverdiscott as the connection point, which extends the offshore cable route length and also requires 

transition to fifteen separate 245kV single core underground cables for the 5km of onshore route 

between the landfall point and Alverdiscott substation. 

Option 3 considers the HVDC VSC option and follows the same design as used for the Dogger Bank, 

Hornsea, and Norfolk zones. As a result the installed capacity of the wind farm has been dropped 

from 1.5GW to just over 1.2GW (which also means only two 33/245kV offshore substations are 

required) to allow one 1110MVA HVDC VSC converter pair/bipole to be utilised. 


Option 4 shown in table 19 provides the alternative HVDC solution which utilises the extra power 

transfer capacity of a CSC converter pair/bipole link to transmit the full 1.5GW from the Bristol 

Channel zone. Offshore this solution required the three 33/245kV offshore substations of option 1 but 

here the exporting 245kV cables are connected to a 245kV busbar on the offshore CSC HVDC 

converter platform with the power being transmitted through a pair of HVDC Mass Impregnated 

cables with integrated return conductor (which has the advantage of allowing for 50% operation for 

the loss of one cable) to an identical CSC converter onshore in a compound adjacent to Alverdiscott 

substation where the power is converted back into AC for input into the National Grid through two 

400kV AIS double busbar switchbays. The onshore impact of this alternative solution has not been 

investigated in detail. 

4 

Option 

1.5 GW to existing 

Alverdiscott substation 

utilising CSC HVDC 

OWF 



Substation 



Cost 

£M 

Cost 

per MW 

£k 

EA Alverdiscott £590m £393k 

Table 19: Alternative connection costs for Bristol Channel Zone 

Cost per MW 

comparison 

£ 

1.5GW (AC) to 

Alverdiscott 

£292k 

For either of the AC or DC offshore connection options a new 400kV substation is to be added at the 

existing Alverdiscott 400/132kV substation site. Currently the 400kV equipment is simply Teeconnected 

to the overhead line route, but a full double busbar 400kV substation will be required for 

the connection of 1.5GW. 

With the AC connection, an option is to seek to construct a new 400kV overhead line from 

Alverdiscott towards the coast. This would effectively replace an existing 132kV line over this portion 

of the route and create a new connection point for the wind farm with a new 400/132kV substation. 

This additional network extension is estimated at £48m. 

The generation scenario described in Section 5.2 assumes the closure of Hinkley Point B (1.26 GW) 

and the commissioning of one 1.6 GW European Pressurised Water Reactor (EPR) at Hinkley Point 

in the timescales considered. As explained in Section 6.6.3, all generation developments in the 

South West interact and, in combination, may drive a need for reinforcement. If a further 1.6 GW unit 

were to materialise at Hinkley Point, major reinforcement would be required. This could potentially 

include the need for a 40 km overhead line route as well as significant uprating of existing routes.

At the time of writing, 3.3GW of nuclear generation (i.e. 2 x1.65GW units) is contracted to connect at 

Hinkley Point in 2016. However 1.512GW of offshore wind generation, not involved in either the 

Round 1 or Round 2 leasing process, is also already contracted to connect at Alverdiscott in 2014 


Figure 29: Bristol Channel Zone DC Local Onshore Transmission Network 


6.8 Irish Sea 

1 

2 

Option 

1.1GW 

at Wylfa 

2.2GW 

at 

Deeside 

1.1GW 

at 

Stanah 

1.1GW 

at Wylfa 

2.2GW 

at Pentir 

1.1GW 

at 

Stanah 

OWF 

Offshore Transmission £M 


Substation 

IA Deeside 

Cost 

£M 

£416m 

(DC) 

LA Deeside £420m 


Substation Extension £M 

Network Reinforcement £M 


£86m 

JA Wylfa £266m (AC) £7m 

NA Stanah £407m £30m 

IA 

LA 

JA 

NA 

Pentir £379m (AC) 

Pentir 

Wylfa 

Stanah 


£401m 

(DC) 

£266m 

(AC) 

£6m 

£7m 

£407m £30m 

Table 20: Connection cost for Irish Sea Zone 

Total 

£M 

£0m £1,632 

£186m £1,682 

Comments 

Possible land 

restrictions at 

Deeside if CSC- 

HVDC link is 

used for 

Hunterston to 

Deeside Link. 

The 

establishment of 

a second circuit 

on the existing 

route from Pentir 

to Trawsfynydd 

would be 

required to 

deliver this 

option. 

Again due to the proximity of the OWF IA and JA in the Irish Sea zone to their potential respective 

connection points at Pentir and Wylfa, cost estimates for both an HVAC and HVDC solution were 

derived. However due to their distance offshore, AC solutions for OWF LA and NA were not deemed 

pragmatic and hence only HVDC connection solutions have been assessed for these two wind 

farms.

Figure 30: Irish Sea zone connection overview 


The HVDC and HVAC connection designs for these wind farms are the same as those discussed in 

the previous sections (and shown diagrammatically in Senergy Econnect drawings 1845-010 (p35) 

and 1845-011 (p36)) and hence are not re-iterated here. The options for connecting wind farm IA to 

either the existing National Grid 400kV substation at Pentir or via a longer route to the existing 

National Grid 400kV substation at Deeside has been shown due to the impact of each connection on 

the wider onshore transmission reinforcements required. The respective reinforcements are 

discussed in more detail in Section 6.8.3. 


With the relatively short cable distances between OWF IA and the substation at Pentir, and OWF JA 

and the substation at Wylfa, it is the HVDC solutions for these wind farms that are more expensive 

than the HVAC alternatives, again due to the cost of providing the HVDC converters, and associated 

extra platform and switchgear. However for the connection of OWF LA (option 5) the longer cable 

route length makes the HVDC solution more cost effective. 

Option 6 looks at the use of HVDC CSC technology to transmit the power generated in polygon IA, 

expanded to an installed capacity of 1680MW to the connection substation at Deeside. The design 

would follow the same principles as that discussed for the Bristol Channel zone option 4 in Section 

6.7.2. 

3 

4 

5 

6 

Option 

OWF IA connected to Pentir 

using HVDC VSC 

OWF JA connected to 

Wylfa using HVDC VSC 

OWF LA connected to 

Pentir using HVAC 

OWF IA enlarged to 

1680MW installed and 


to Deeside 

OWF 


Substation 



Cost 

£M 

Cost 

per MW 

£k 

IA (DC) Pentir £395m £319k 

JA (DC) Wylfa £354m £286k 

LA (AC) Pentir £454m £366k 

IA 

Deeside 

£723m £430k 

Table 21: Alternative connection costs for Irish Sea Zone 

Cost per MW 

comparison 

£ 

IA (AC) to 

Pentir 

£306k 

JA (AC) Wylfa 

£215k 

LA (DC) Pentir 

£323k 

IA (DC) 

Deeside 

£336k


For the Irish Sea zone, connections to the onshore transmission system were considered in the 

North Mersey area to the existing substations of Heysham and Stanah for a total of 1.1GW. Due to 

severe land restrictions at Heysham and similar offshore cable lengths for both, Stanah was 

considered to be the best interface point with the onshore transmission system. The standard 

substation extensions associated switchgear will be required at Stanah in order to provide the 

interface with the offshore network. 

Due to the location of the wind farms and zone polygons, it was most economic to connect the 

remaining 3.3GW into the North Wales area. Connection into the existing substations at Wylfa, Pentir 

and Deeside were considered. 

The optimum solution for the Irish Sea OWF connecting into North Wales is also influenced by the 

possibility of undertaking onshore transmission reinforcement in advance of financial commitment 

from users being in place to do so. 

The limiting section of the network in this region is the single circuit between Pentir and Trawsfynydd 

substations. The scenario analysed assumes that the existing nuclear generator at Wylfa is closed 

and that no new nuclear is connected in the timescales considered. Should nuclear replanting occur 

at Wylfa, there is a definite need to reinforce this section of the network with a second circuit along 

the existing route. 

From an offshore transmission system perspective, the most economic solution is the connection of 

the entire 3.3GW of Irish Sea OWF into Wylfa and Pentir. An alternative solution, in order to avoid 

significant onshore reinforcement is to still connect 1.1GW into Wylfa, but to take the remaining 

2.2GW into Deeside. There is a risk with this solution that sufficient land may not be available at 

Deeside, as these connections would interact with the potential development of an HVDC link from 

Hunterston into Deeside, which could be either a CSC or VSC HVDC link depending on the 

requirements identified. 

Therefore, if onshore reinforcement of the Pentir – Trawsfynydd route (highlighted in green on Figure 

26.1) was undertaken strategically, in advance of connections coming forward, this would help in 

connecting both offshore wind and/or any nuclear generation in this region. This solution has the 

potential to reduce the cost of the offshore network. 



Figure 31: Irish Sea Zone Local Onshore Transmission Network and Location of Potential Onshore 



7 Delivery Issues 

7.1 Offshore Installation & Manufacturing resource 

From the connection designs presented in the earlier sections of this report it is apparent that 

significant quantities of HVAC and HVDC equipment will be required to complete the connection of 

the Round 3 offshore wind farms. Senergy Econnect is aware of anecdotal evidence of problems 

being faced by developers currently in sourcing major items of plant including wind turbines, 

transformers, switchgear and cables, and hence development of the Round 3 projects may well be 

constrained by the ability of developers to procure (and manufacturers to provide) the physical 

assets required to create their wind farms. The installed capacity and timetable proposed for Round 

3 may also make the availability of offshore installation vessels a potential bottleneck in the 

construction phase. 

This section of the report investigates these issues in more detail. Specifically, it reviews the latest 

industry major publication assessing supply chain issues and documents the outcomes of 

communications with major suppliers in order to arrive at a more thorough assessment of supply 

chain issues facing the development of offshore wind projects. 

The suite of documentation supporting the Government UK Renewable Energy Strategy 

Consultation document [20], and the BERR Publication, “Quantification of Constraints on the Growth 

of UK Renewable Generating Capacity”, Sinclair Knight Merz, June 2008 (The BERR Report) [18] 

has been used in this assessment. 

7.1.1 HVAC and HVDC subsea cables 

The supply chain associated with high voltage alternating current (HVAC) and high voltage direct 

current (HVDC) subsea cables is a significant constraint to growth. HVAC and HVDC cables are 

required to connect offshore wind farms to the onshore electricity infrastructure. 

From the analysis undertaken in this report, Senergy Econnect estimate that about 1200km of HVAC 

three core and single core cable and 5,200km of HVDC underground / subsea cable will be required 

for Round 3 projects. The UK does not have a high voltage subsea cable manufacturing capability 

and there are only three suppliers of HVAC and HVDC subsea cables in Europe (i.e. ABB, Nexans 

and Prysmian) with lead times of between two and three years depending on the type of cable 

required. 

The technology associated with the manufacture of high voltage cable is vested with the existing 

cable suppliers and it is unlikely that a new entrant could get the product to market within several 

years, if at all, because of the research needed to overcome the technological barriers. Accordingly if 

high voltage subsea cables are to be manufactured in the UK it will be necessary to encourage one 

or more of the existing European suppliers to set up a manufacturing facility in the UK at a suitable 

port location to facilitate loading onto specialist cable laying vessels. Setting up such a facility is 

estimated to cost about £35 million and would take about three years [18] to reach production. 

Senergy Econnect are aware that the lead times in HV cables has increased to 18 -24 months over 

the past year due to the large demand from other sectors such as utility infrastructure, and oil and 

gas. 

However a number of existing suppliers do see the future potential capacity requirements of the 

offshore wind as well as other sectors and have firm plans to increase their capacity through 

investment in facilities, although the delay from investment to first supply from new production lines is 

of the order of two years. 


7.1.2 HVDC converter equipment 

Although not presently a supply chain constraint, the demand for HVDC converter equipment that will 

be needed to connect offshore wind farms located more than 60km from the onshore connection 

point is likely to increase significantly as the more distant offshore wind farm sites are developed in 

the North Sea. It will be at least five years before these distant sites are constructed, therefore as 

these projects become committed the HVDC converter suppliers are confident that there is sufficient 

time to increase manufacturing capacity to meet demand if they have sufficient assurance that these 

projects will go ahead. However Senergy Econnect have anecdotal evidence that one manufacturer 

is revising downwards their short to medium term forecasts for supplying the offshore market in the 

UK because of the delays in progressing offshore projects through the GB planning, consenting, and 

regulatory process . 

With each HVDC VSC converter taking approximately nine months to manufacture, a number of 

converters would have to be manufactured concurrently in order to meet the timetable for Round 3 

assuming all the zones are developed simultaneously. It should be noted that the offshore 

programmes of other countries and an increase in HVDC projects around the world will coincide with 

the Round 3 build programme, and hence Round 3 developers or their Offshore Transmission 

Owners may potentially need to commit to production slots up to three or more years in advance to 

avoid the converters becoming a constraint. In order for the HVDC suppliers to have the confidence 

to increase their manufacturing capability, they will require an order book to be in place, which in turn 

means that the Offshore Transmission Owner regime needs to ensure that procurement of 

equipment is triggered as early as possible in the process so that these lead times can be managed 

and reduced. 

7.1.3 Balance of plant equipment (e.g. transformers, switchgear, etc) 

Although there are significantly more suppliers of balance of plant equipment than HV cable 

suppliers, the worldwide demand for this type of equipment is forcing up prices and prolonging 

delivery times. The lead time for transformers, a key long-lead element of the offshore substations, 

has increased to around 36 months over the past year. Currently the lead time for switchgear can 

take up to 12 months for switchgear rated at 132kV and above and up to six months for switchgear 

rated at 33kV and below. 

In reality the lead time from placement of order on an offshore project to energisation of the on and 

offshore substations is in the order of three years, once the preparatory design work, installation and 

commissioning is taken into account. 

7.1.4 Assessment of the availability and cost of cable installation vessels 

The view from suppliers is that they can meet the near-term capacity requirements and although it 

will take significant investment, they can increase capacity fairly quickly to meet future requirements, 

and there is a willingness to do so within the right frameworks. With a global pool of more than 

twenty suitable vessels, cable installation is not expected by those involved to present a bottleneck. 

Installation vessel availability is a significant issue but generally higher cost solutions are likely to 

remain available, though this may price some projects out of the market. The following Table 

illustrates the cost, capability and availability of the vessels owned and operated by one cable laying 

company: - 


Item Capability 

Number of Vessels Seven under ownership at various locations 

worldwide 

Number of vessels allocated specifically for offshore 

wind industry 

Three to Four vessels 

Typical lead time Two to three months 

Cost 

132kV cable laying @£80k /day 

5km per day ploughing typical 

33kV cable laying @£60k per day 

Vessel Operating limits 1.25 – 1.5m height of swell 

12m/s wind speed 

7+sec swell period 

Table 22: Cable Installation Vessel parameters 

(Courtesy of Global Marine Systems) 

7.2 Onshore transmission network delivery programme 

To construct the onshore transmission system proposed in this study under the present regulatory 

regime National Grid would require to receive applications for connections for each of the zones that 

sought connection capacity for the total capacity of that zone. 

It has been assumed that the new Planning Act would apply to the overhead line works required. 

Under this regime, for moderate overhead line works the minimum timescale that is envisaged to 

undertake the required studies, environmental impact assessments and obtain consent is 

approximately four years from approval to commence work. Following this period it is necessary to 

add the time required to enter into commitment to obtain the required materials, undertake the 

installation activities then obtain system access to commence the connection process. This leads to 

an overall time period from approval to connection of around seven years. Where new transmission 

transformers are required, allowance has to be made for delivery periods for these, which are 

presently around 36 months. 

Where new 400kV overhead lines are required, particularly reasonably long routes, then the time 

periods to undertake the required assessments, consultation and consenting process may take 

considerably longer 

Obtaining access to the system to undertake the required connections (i.e. taking outages of 

equipment) will have to compete with other demands such as maintenance and outages to 

undertake works for other users, and commitments. With the level of uncertainty around which year 

connections will be undertaken arising from the issues above, it is not possible to accurately identify 

if system access constraints would seriously impact on the delivery programme. As National Grid 

presently has commitments to provide connections for users that are not present in the study 

background the existing system access plans do not provide a reliable basis to work against. It is 

however, reasonable to assume for the east coast connections particularly, that available system 

access will be a major constraint on the ability to deliver the required work. Any location that has 

programmes of delivery that approach those for new Nuclear or other generation connections will 

also face system access competition. If reinforcement was able to take place before financial 

commitment from users is in place, it may be possible to optimise the system outages required and 

spread these out over a longer time period. 


8 Conclusions 

8.1 Methodology and Assumptions 

The aim of this study was to identify the extent and costs of the works necessary to provide 

optimised transmission connections for all of the Round 3 offshore polygons. The methodology and 

assumptions used to assess the required works are set out in Sections 2 and 3. 

Key among these assumptions is the view that the offshore transmission assets should be designed 

to achieve a high utilisation, both to optimise the capital investment and also demonstrate an 

economic and efficient solution to the regulator. Such a consideration will be likely to form part of 

Ofgem’s decision making criteria in the granting of an offshore transmission licence. 

Factors such as the variability of the wind resource and the operational availability of offshore wind 

turbines dictate that the Round 3 wind farms will rarely be generating to the full extent of their 

installed capacity, which would adversely impact the utilisation of a connection solution that was 

rated to transmit total installed capacity. In light of these considerations a high level analysis was 

therefore undertaken to ascertain the optimal ratio between the installed generating capacity offshore 

and the transmission capacity of the offshore transmission assets. This optimal utilisation ratio (given 

by the formula below) was determined to be 112% (see Appendix 1): - 

Utilisation ratio = Offshore transmission asset capacity 

Installed generating capacity 

In practice the offshore transmission asset designs provided in this report have a range of utilisation 

ratios from 81% to 112% because of the zonal capacities identified by The Crown Estate and the 

modular nature of the transmission assets themselves (with each additional cable providing a fixed 

increase in transmission capacity). National Grid are in the process of leading a review of the 

security standards for offshore generation connections to include projects of the size and distance 

form shore associated with Round 3, at the request of Ofgem. This review will culminate in a set of 

security recommendations including offshore transmission circuit capacity, which will be consulted 

upon and incorporated as revised text in the GB SQSS. 

8.2 Cost of Connecting Round 3 Offshore Wind Farms 

A summary of the optimal connection costs broken down by zone is set out in Table22 below. 


ZONE OWF 

Total 

Installed 

Capacity 

(MW) 


technologies 

Moray Firth C 500MW AC 


Point (s) 

New substation 

on coast 

TOTAL 

COST (£m) 

TOTAL 

COST 

Per MW 


(£k) 

£193m* £386k 

Firth of Forth G 500MW AC Torness £150m* £300k 

Dogger Bank 

Hornsea 

Norfolk 

(without 

Sizewell C) 



J 1240MW DC Creyke Beck 



H5 1237.5MW DC Killingholme 



M 1237.5MW DC New substation 

on Lincolnshire 

coast 

N 1240MW DC New substation 

on Lincolnshire 

coast 

T 1240MW AC Sizewell 

Z2 1240MW DC Sizewell 

U 1237.5MW DC Norwich 

Z1 1237.5MW DC Norwich 

£5,910m £477k 

£1,728m £349k 

Hastings AA 500MW AC Bolney £184m £368k 

West Isle of 

Wight 

Bristol 

Channel 

Irish Sea 

DA 500MW AC Chickerell £175m £350k 

EA 1500MW AC New substation 

on Torridge 

Estuary 

IA 1237.5MW DC Deeside 

LA 1240MW DC Deeside 

JA 1237.5MW AC Wylfa 

NA 1240MW DC Stanah 

£430m £287k 

£1,632m £329k 

TOTALS 25,795MW £10,402m £403k 

Table 23: Optimal Connection Costs broken down by Zone 

*Total reinforcement costs dependent on GB transmission owner study currently in progress 

The total cost for connecting the Round 3 wind farm projects, assuming no inclusion of Sizewell C, 

and the optimal design solutions identified in this report is £10,402 million. Note that this Figure is 

based on 2008 price levels for the equipment required and does not allow for the additional

equipment such as Static Var Compensation that may need to be installed at the onshore connection 

point of the HVAC connection solutions in order for the Offshore Transmission Owners to meet the 

reactive capability requirement of the System Operator/Transmission Owner code (e.g. an SVC 

sufficient to provide dynamic reactive capability for a 300MW wind farm would cost in the order of 

£12m) . Sensitivities were also investigated in some areas where new nuclear developments could 

occur in the same region and within the same timescales as the Round 3 development. If 

transmission reinforcement was not undertaken in an optimised manner on a strategic basis then 

offshore transmission asset costs could increase as a result of having to find alternative more distant 

connection points. An example of this is the Norfolk zone where the inclusion of Sizewell C increases 

the offshore transmission asset cost by £245m. As a function of these designs, the total installed 

generating capacity connected for Round 3 is 25,295MW (with a connection capacity of 22,980MW) 

with a £/MW cost ranging from £287k to £477k. 

8.3 Individual Versus Aggregated Connections 

The power transfer capabilities of the HVAC and HVDC technologies available coupled with the 

potential installed capacity of the Round 3 OWF have to a large part dictated the offshore 

transmission designs presented in this report and have determined that in the primary solution each 

OWF is connected directly to an onshore connection point, with no interconnection between the 

OWF in a particular zone. 

The economies of using either HVAC or HVDC for these offshore transmission solutions have been 

further explored within the report. Applying an HVAC and HVDC solution to the same OWF has 

indicated that the choice of technologies used for the offshore transmission designs will be dictated 

by the transmission distance and that the cable route length at which HVDC Voltage Source 

Converter solutions become economic relative to an equivalent HVAC solution is between 60km and 

80km. 

Aggregated solutions, where multiple OWF are connected using ‘power corridor’ technologies such 

as Gas Insulated Lines and HVDC Current Source Converters have been considered and costed, 

although these solutions do not compare favourably with the individual offshore transmission designs 

for the same OWFs in terms of cost per MW installed, except where solutions have been considered 

that utilise dual bipole HVDC overhead lines as opposed to underground cable to traverse the long 

distance overland routes from the coast to Norwich and Drax substations. Such designs also do not 

necessarily permit the connection of higher levels of generating capacity relative to the approach of 

allocating a dedicated connection per wind farm. 

This is not to say that consideration of aggregated connections should not pursued further as there 

are likely to be benefits associated with this approach that are not considered in this report, for 

example there will be environmental and planning benefits of consenting a single connection cable 

route compared to multiple cable routes. However, it would indicate that, in terms of the physical 

plant required to connect the Round 3 wind farms alone, there would appear to be little to be gained 

by aggregating these OWFs through single connections. The option of connecting the Round 3 wind 

farms to continental Europe has not been considered within this report, however such connections 

would face the same power transfer capacity constraints highlighted in Section 6.2.2. 

8.4 Deliverability of Round 3 Connections 

Offshore infrastructure projects on the scale considered within this report would set a global 

precedent, with unparalleled volumes of offshore HVAC and HVDC plant required to facilitate the 

connections. The challenges posed in delivering the Round 3 offshore connections, regardless of the 

design pursued, will therefore be significant. Investment will be required by existing suppliers in 

expanding manufacturing facilities for HV cables, and in particular subsea cables. The HVDC VSC 

market is still at an embryonic stage, with the converter/bipole ratings used in this report yet to be 

deployed in the field. Hence there will be a technology risk as well as cost premium to be borne by 

the ‘first comer’ offshore transmission owner to specify this technology. 


Again it is likely that manufacturing facilities would need to be expanded to accommodate demand 

for these technologies should Round 3 be developed in the timescales desired. Assuming the supply 

chain can be sufficiently stimulated; prices should drop as competition increases and with economies 

of scale. The HVDC converter manufacturers are confident that they can increase manufacturing 

capability to meet demand should they have sufficient assurance that projects will place orders. 

However Senergy Econnect have anecdotal evidence that one manufacturer is revising downwards 

their short to medium term forecasts for supplying the offshore market in the UK because of the 

delays in progressing offshore projects through the GB planning, consenting, and regulatory process, 

and the ability of the process to deliver the offshore wind farm capacity in the timescales desired. 

It should be noted that the offshore programmes of other countries and an increase in HVDC 

projects around the world will coincide with the Round 3 build programme, and hence Round 3 

developers or their Offshore Transmission Owners may potentially need to commit to production 

slots up to three or more years in advance to avoid the HVDC converters becoming a constraint. 

In order for the HVDC suppliers to have the confidence to increase their manufacturing capability, 

they will require an order book to be in place, which in turn means that the Offshore Transmission 

Owner regime needs to ensure that the procurement of equipment is triggered as early as possible in 

the process so that these lead times can be managed and reduced. 

Suppliers of the installation vessels necessary to install the cables and offshore platforms are 

currently confident in their ability to quickly ramp up capacity to meet the demands of Round 3, 

although they acknowledge that to make the investment required in the timescales necessary they 

will need the security of retainer agreements or firm orders in place. 

An offshore infrastructure program on this scale may present significant commercial opportunity for 

UK plc in the medium to long term, however it would also present significant development cost in the 

short term. Such development costs are likely to be exacerbated by the shortage of engineering skills 

within the UK as identified in the BERR report [18]. 

Establishing the large new compounds onshore to accommodate assets such as the multiple HVDC 

converter stations, extending National Grid’s existing substations and creating the new substations 

and overhead line routes necessary to integrate Round 3 into the existing onshore transmission 

network will all require an efficient transition through the planning process if the desired timescales 

are to be achieved. The passing into law of the recent planning bill which is the first step in the 

creation of an Infrastructure Planning Commission to determine nationally significant projects should 

therefore be welcomed. 

8.5 Benefits of a co-ordinated approach 


GW of Round 3 offshore wind. This assumes that the collective requirements for all the wind farms in 

a zone are required and that the overall onshore transmission system changes will all occur in a 

coordinated manner at any one location. Should piecemeal developments be undertaken, wind farmby-wind 

farm, and/or wind generation capacity change incrementally over a period of years, the 

staggered timing of the works would result in multiple site/circuit extensions and this will increase the 

overall onshore costs and environmental impact. In order to avoid this extensive stakeholder 

engagement, coordination and collaboration is required. 

By considering the connection requirements of zones as a whole, and by balancing the requirements 

and crucially the costs of the offshore and onshore transmission assets, this report has sought to 

indicate the optimal solutions for the connection of the Round 3 OWF projects, from an impartial 

perspective. While individual OWF or even individual zones may be able to achieve a more 

economically favourable connection in isolation, such an approach may lead to additional cost and/or 

additional delays in the connection of Round 3 as a whole. 

To mitigate this, the ongoing development of the offshore transmission regulatory regime should 

carefully consider how the connection application process will work in practice to provide the co- 


ordination necessary to deliver the optimum solution. Detailed investigations should also be 

undertaken into ‘no-regret’ onshore transmission reinforcements that can be taken forward 

immediately to deliver the network capacity required. 


9 Recommendations 

This report has identified the optimum outline connection designs in light of target generating 

capacities and high level environmental constraints. This report has also identified some of the likely 

challenges to be overcome in delivering the Round 3 connection designs. In order to further explore 

the feasibility, costs and environmental issues surrounding Round 3 it is recommended that further 

more detailed investigations be carried out into; 

• The environmental and planning constraints that may affect connection solutions for each 

zone 

• The extent of constraints on supply chain that may impact delivery of the Round 3 

connections 

• Raising the power transfer capacity of the HVAC and HVDC technologies to improve 

economies of scale 

• Putting in place a process to effectively manage the Round 3 grid connection applications 

and coordinate the on and offshore transmission works 

• ‘No regret’ onshore reinforcement options that can be progressed immediately to provide the 

necessary transmission capacity in a timely manner 


10 References 

1. East Coast Transmission Network, Technical Feasibility Study, Project 1845 v1.0 dated 

March 2007. 

2. www.windpower.org Danish Wind Industry Association 2003 

3. "Rating cables in J-Tubes" by M. Coates of Engineering Materials Division, Era 

Technology Ltd 

4. Table 41 Attachment to XLPE Cable systems – User’s Guide ABB 

5. Gas Insulated Lines –reliable power transmission towards new worldwide challenges in 

hydro and wind power generation H.Koch, D.Kunze, S.Pohler, L.Hofmann, C.Rathke, 

A.Mueller, CIGRE study committee B3, 2008 session 

6. GIL – Gas Insulated Transmission Line reference list - Siemens Power Transmission & 

Distribution (28/05/08). 

7. Superconductor Power Cables – American Superconductor 2008 

8. Cost benefit methodology for optimal design of offshore transmission systems, P. Djapic, 

G Strabac, SEDG July 2008 

9. Report on the recommendations arising from additional cost benefit analysis 

10. http://eosweb.larc.nasa.gov NASA atmospheric science and data center, surface 

meteorology and solar energy tables for Latitude 55 0 Longitude 2 0 

11. North Hoyle Offshore Wind farm annual report, URN no. 08/P47 BERR 

12. GB Security and Quality of Supply Standard 

13. Terms of Reference for GB Security and Quality of Supply Standard Review Group: via 

National Grid Electricity website: http://www.nationalgrid.com/NR/rdonlyres/67B20E95-61EF- 

4532-8557-659F7CD6D12A/15792/120207GBSQSSReviewGroupToR_FINAL_.pdf 

14. GB Seven Year Statement 2008, Chapter 7: GB Transmission System Performance – 

Modelling of the Planned Transfer Condition 

15. http://www.nationalgrid.com/uk/Electricity/Codes/gbsqsscode/reviews/ 

Review GSR001 

GB SQSS 

16. http://www.ofgem.gov.uk/Networks/Trans/Offshore/ConsultationDecisionsResponses/Pag 

es/ConsultationDecisionsResponses.aspx 

Joint Ofgem/BERR Regulatory Policy Update 

Offshore Electricity Transmission – A 

17. Djapic, P & Strbac, G (2008) Cost Benefit Methodology for Optimal Design of Offshore 

Transmission Systems, BERR Centre for Sustainable Electricity & Distributed Generation, 

July 2008. 

18. http://renewableconsultation.berr.gov.uk/related_documents, “Quantification of 

Constraints on the Growth of UK Renewable Generating Capacity”, Sinclair Knight Merz., 

June 2008. 

19. The ABC’s of HVDC Transmission Technology IEEE Power & Energy magazine March 

/April 2007 Vol 5 No2 

20. UK Renewable Energy Strategy Consultation document BERR June 2008 

(http://renewableconsultation.berr.gov.uk/consultation/consultation_summary) 


11 List of Appendices 

Appendix 1 Offshore wind farm installed capacity / connection capacity study 

Appendix 2 HVAC cable reactive compensation methodology 

Appendix 3 Moray Firth C KEITH detailed costing 

Appendix 4 Moray Firth C NEW SUBSTATION detailed costing 

Appendix 5 Firth of Forth G TORNESS detailed costing 

Appendix 6 Firth of Forth G EAST COAST IC detailed costing 

Appendix 7 Dogger Bank H1 THORNTON detailed costing 

Appendix 8 Dogger Bank H1 CREYKE BECK detailed costing 

Appendix 9 Dogger Bank H2 DRAX detailed costing 

Appendix 10 Dogger Bank H2 KEADBY detailed costing 

Appendix 11 Dogger Bank H3 DRAX detailed costing 




Appendix 15 Dogger Bank H4 KILLINGHOLME detailed costing 



Appendix 18 Dogger Bank H5 KILLINGHOLME detailed costing 

Appendix 19 Dogger Bank I1 KEADBY detailed costing 

Appendix 20 Dogger Bank I1 KILLINGHOLME detailed costing 

Appendix 21 Dogger Bank I2 KEADBY detailed costing 

Appendix 22 Dogger Bank I2 KILLINGHOLME detailed costing 

Appendix 23 Dogger Bank J THORNTON detailed costing 

Appendix 24 Dogger Bank J CREYKE BECK detailed costing 

Appendix 25 Dogger Bank I+ CSC KILLINGHOLME detailed costing 

Appendix 26 Dogger Bank I+ GIL KILLINGHOLME detailed costing 

Appendix 27 Dogger Bank H2 & H3 DC OHL DRAX detailed costing 

Appendix 28 Hornsea M SOUTH HUMBER BANK detailed costing 

Appendix 29 Hornsea M GRIMSBY detailed costing 

Appendix 30 Hornsea M LINCOLNSHIRE COASTAL SUBSTATION detailed costing 

Appendix 31 Hornsea N SOUTH HUMBER BANK detailed costing 

Appendix 32 Hornsea N GRIMSBY detailed costing 

Appendix 33 Hornsea N LINCOLNSHIRE COASTAL SUBSTATION detailed costing 


Appendix 34 Norfolk T AC SIZEWELL detailed costing 

Appendix 35 Norfolk T DC SIZEWELL detailed costing 

Appendix 36 Norfolk U AC NORWICH detailed costing 

Appendix 37 Norfolk U DC NORWICH detailed costing 

Appendix 38 Norfolk Z1 NORWICH detailed costing 

Appendix 39 Norfolk Z1 RAYLEIGH detailed costing 

Appendix 40 Norfolk Z2 SIZEWELL detailed costing 

Appendix 41 Norfolk Z2 RAYLEIGH detailed costing 

Appendix 42 Norfolk U & Z1 DC OHL NORWICH detailed costing 

Appendix 43 Norfolk Z+ CSC RAYLEIGH detailed costing 

Appendix 44 Hastings AA BOLNEY detailed costing 

Appendix 45 West Isle of Wight DA CHICKERELL detailed costing 

Appendix 46 Bristol Channel EA AC NEW ESTUARY SUBSTATION detailed costing 

Appendix 47 Bristol Channel EA AC ALVERDISCOTT detailed costing 

Appendix 48 Bristol Channel EA DC ALVERDISCOTT detailed costing 

Appendix 49 Bristol Channel EA CSC DC ALVERDISCOTT detailed costing 

Appendix 50 Irish Sea IA DC DEESIDE detailed costing 

Appendix 51 Irish Sea IA DC PENTIR detailed costing 

Appendix 52 Irish Sea IA AC PENTIR detailed costing 

Appendix 53 Irish Sea JA DC WYLFA detailed costing 

Appendix 54 Irish Sea JA AC WYLFA detailed costing 

Appendix 55 Irish Sea LA DC DEESIDE detailed costing 

Appendix 56 Irish Sea LA DC PENTIR detailed costing 

Appendix 57 Irish Sea LA AC PENTIR detailed costing 

Appendix 58 Irish Sea NA STANAH detailed costing 

Appendix 59 Irish Sea IA+ CSC DC DEESIDE detailed costing 


Appendix 1: Offshore Wind Farm installed capacity/connection capacity 

study 

1 Introduction 

To date the connection of both on and offshore wind farms is calculated on enabling export of full 

capacity despite the fact that the majority of the time the wind farm is not generating at full power. 

The development of wind farms with a maximum output that exceeds the available grid capacity is 

not common practice as it requires the wind farm to be constrained, as such, revenue during 

periods of peak generation, however brief, is lost. 

As the cost of connection for offshore wind farms is significantly higher than those experienced 

onshore, and the uncertainty surrounding weather and tidal conditions to perform maintenance 

functions may result in lower availability for offshore turbines, it may make sense to install a higher 

installed generating capability than the connection capacity will allow. Such an approach could 

result in better overall economics for the development despite being constrained at generation 

peaks. 

While wind farm developments are often considered in terms of costs per MW installed this is a 

view that takes no account of the capacity factor (ratio of energy generated to maximum possible 

energy output). Therefore, it could be argued that, from a financial perspective, a more appropriate 

measure of costs would be cost per MWh generated over the lifetime of the wind farm. 

From the perspectives of grid connection and economics, the question is - for a given scenario 

which size is optimum? 

To answer this question the economic drivers and associated sensitivities for an Offshore Wind 

Farm need to be understood. This report provides an overview of a model developed to address 

this question and provides conclusions to this analysis which have been used to determine 

installed capacities for the Round 3 offshore wind farms identified within the main report. 

2 Objectives 

The objective of the Wind Farm Sizing model is to ascertain, at a high level, the optimum size of an 

Offshore Wind Farm for a given connection capacity to assess the lowest ratio of cost per MWh 

generated over the lifetime of a wind farm project, as shown in Figure A1.1 

1845 Appendix 01 OWF installed-connection capacity study v1-0.doc Page 1 of 13

Figure A1.1. Trend of Capex/lifetime energy generation (£/MWh) as installed capacity increases as a 

percentage of connection capacity 

3 The Model and Method 

3.1 Assumptions 

For an offshore location, measured wind speeds throughout a year are characterised by moderate 

to fresh winds (5-10m/s), while winds that are strong gale force and above (>20 m/s), where 

energy levels are maximised, are relatively uncommon. The wind variation for a standard site is 

typically described using the Weibull distribution, such as that shown in Figure A1.2. 

Figure A1.2. Weibull distribution [1] 


The black line in figure A1.2 is the average wind speed and separates the curve into two equal 

areas. 

Based on this curve it can be assumed that every site can be defined by a shape factor (which, as 

the name suggests, defines the shape of the curve) and an average speed (which defines the 

curve’s axis) that can be applied to mathematically model the wind profile at a site. 

A shape factor of 2 is known as a Rayleigh distribution. In this study a shape factor of 2, which is 

the most common in Europe, is applied alongside the average wind speed from real or implied data 

for the North Sea. [2] 

3.2 Constraints 

The amount by which the installed generation capacity may be greater than a specified grid 

connection capacity will depend upon the availability of the wind turbine generator (WTG) and the 

balance between the cost of installing a WTG relative to the cost of connection. 

3.2.1 Availability of the WTG 

A WTG is considered unavailable when it is not capable of operating in productive conditions. This 

may be as a consequence of a number of different aspects, for example, maintenance, fault 

conditions, etc. 

It is well documented that the availability of onshore WTGs is in the order of 97 – 98% [1]; 

however, in the offshore environment, due to the challenges of vessel availability and weather and 

tidal windows, in particular, it is realistic to expect availability to be lower, for example, the 

availability of North Hoyle Round 1 offshore wind farm is reported at 84.7% [3]. 

Understanding the wind speed distribution is crucial in determining the energy utilisation of the 

connection assets and the energy lost by constraint. For a low wind speed site, more WTGs can be 

installed above a nominal connection capacity without an equivalent increase in constraint costs. 

Such ‘over-development’ could represent an economic advantage for the wind farm. 

3.2.2 Cost of installed WTG vs. cost of connection. 

It is estimated that the typical cost per MW installed (including grid connection) for offshore wind 

farms is presently in the range £1.8m - £2.3m [4]. As the grid connection increasingly represents a 

significant proportion of these costs, especially as these offshore wind farms are located further 

from their points of connection, then minimising these costs has more influence on the project 

financial model. 

Conversely, should the cost of the WTG increase relative to the connection costs then it may be 

anticipated that there would be little or no advantage to increasing the installed capacity beyond 

the available connection capacity. 

3.3 Model Set-up and Analysis Methodology 

3.3.1 WTG Technology 

Different WTG technologies have different power curves. The turbines used in this analysis are as 

follows; Siemens 3.6MW, Repower 5MW and Multibrid 5MW. The power curves for these WTG 

have been used to calculate the number of turbines required for the best case scenario and hence 

determine the ideal wind farm size. 


The engine of the model is based upon the power curve of the selected WTG. As the wind farm is 

‘enlarged’ beyond the connection capacity the amount of constraint on the wind farm increases. 

This is simulated in the model by reducing the maximum power that each WTG can generate. As 

more WTGs are installed the level of constraint is increased and the subsequent total wind farm 

power that can be generated is reduced due to the electrical constraint of the connection capacity. 

This is shown in Figure A1.3. 

3.3.2 Connection Costs 

Figure A1.3. Power curve constraint 

This input variable is at the discretion of the model user, typical costs of connection applied here 

are approximated at £0.7m per MW [4] 1 . 

3.3.3 WTG Costs 

This input variable is at the discretion of the model user and constitutes all costs other than 

connection costs, the majority of which is the cost of the WTG. Typical costs applied are 

approximated at £1.5m per MW [4] 

3.3.4 Average Wind Speed 

This input variable is at the discretion of the model user. For offshore wind farms in the UK this has 

been approximated at 9m/s, as shown in Figure A1.4 [5]. 

1 The actual connection costs identified within the report range between £287k and £477k per MW based on 

a 112% utilisation factor or £287k and £532k per MW based on a 100% utilisation factor which would 

weaken the financial case for over installing capacity offshore, however it could also be surmised that for 

Round 3 the WTG installed costs per MW may also reduce below £1.5m per MW which would in turn 

strengthen the financial case for over-installing. Sensitivity to these variables has been assessed within this 

analysis. 


3.3.5 WTG Availability 

Figure A1.4. Annual mean wind speed in UK [5] 

This input variable is at the discretion of the model user. Turbine availability is approximated at 

90% based upon data from existing offshore wind farms [3]. 

3.4 Sensitivity Analysis 

The aim of the sensitivity analysis is to gain an understanding of the limitations to the scale of 

overdevelopment of the wind farms in relation to changes in the different constraint variables 

identified in section 3.3. 

The sensitivity analyses pertain to; ratio of connection costs to WTG costs, average wind speed, 

and WTG availability. 

3.4.1 Ratio of connection costs to installed WTG costs 

This ratio is calculated on a per MW basis. The cost of installed MW includes costs associated with 

the WTG machine, transportation and installation. The cost of connection includes the offshore 

transmission assets and the substations both on and off shore. The ratio of installed WTG costs to 

connection costs is stepped in the sensitivity analysis from 0.5 to 2.5. 


As the mean wind speed varies year on year, an analysis of the sensitivity to mean wind speed is 

an important element. It should be noted that the energy production of the WTG is directly 


proportional to the average wind speed; as average wind speed increases the energy production of 

an operational WTG increases; which will increase revenue and, therefore, reduce the cost per 

MWh generated. 

Typically, at an average wind speed of 6m/s, depending upon the WTG selected, the WTG is 

generating at 10-25% of its maximum MWh output, while at wind speeds above16m/s the WTG is 

generating at 100% of the maximum available MWh output. The energy produced by a wind farm 

over the course of a year as a proportion of the total energy that the wind farm could possibly have 

generated had the wind speed been constantly above 16m/s for example is given by the term 

‘capacity factor’ (CF). Capacity factors tend to be higher for offshore wind farms than those 

onshore due to higher average wind speeds and less turbulence in the air flow; however it should 

be noted that CFs of 50% or more are exceptional. 

It should also be noted that a WTG must cut out at wind speeds in excess of, typically, 25m/s, 

depending upon turbine type. 

In the sensitivity analysis the average wind speed is stepped from 6m/s to 16m/s. 


WTG availability is described in detail in Section 3.2.2. In the sensitivity analysis the availability is 

stepped between 84% and 100%. 

4 Results 

The results below are based on the typical wind farm parameters used as a basis for the Round 3 

offshore wind farm connection study main report (v1.0) 

4.1 Example wind farm base parameters 

The base model set-up for this example is as follows: 

WTG 

Technology 

Wind Farm 

Size (MW) 


Cost per MW 

(£k) 

Installed WTG 

Cost per MW 

(£k) 

Average Wind 

Speed (m/s) 

1845 Appendix 01 OWF installed-connection capacity study v1-0.doc Page 6 of 13 

WTG 

Availability (%) 

Repower 5MW 1110 700 1,500 9.0 90 

4.2 Example wind farm base results 

Table A1.1. Base model set-up 

For these input values, the optimal installed given is 112% of the connection capacity, as shown in 

Table A1.2. This is based on the total WTG installed cost increasing for the extra WTG’s but the 

total connection cost remaining at the 1110MW x £700k value. The revenue generated is 

increased due to the additional wind turbines operating at low wind speeds. (Note: at high wind 

speeds the additional WTGs will result in each WTG being slightly more constrained; this is 

allowed for in the model).

Size (%) 100% 112% 

Total CAPEX (£m) 2442 2642 

Lifetime Revenue (£m) 6,874 7,680 

CAPEX/Lifetime Energy Generation (£/MWh) 29.84 28.89 

WTG (units) 222 249 

Capacity Factor (%) 44.18% 44.08% 

Table A1.2. Size results comparison 

As shown Table A1.2, using 249 WTG at a total cost of £2,642m instead of 222 WTG with a total 

cost £2,442m, generates revenue of £7,680m against £6,874m. It is evident that the capacity factor 

is only slightly reduced by the loss in energy for the electrical constraint (assuming 90% WTG 

availability in each case). However, installing generation capacity up to 112 % of the connection 

capacity results in a better CAPEX/Lifetime Energy Generation Figure of £28.89 per MWh against 

£29.84 per MWh produced were 100% connection capacity installed. 

This CAPEX/Lifetime Energy Generation Figure can be used to assess how project variables affect 

an investment in order to determine the economically optimised model, and hence should not be 

used in isolation. 

It can be seen in Figure A1.5, the red line representing the CAPEX/Lifetime Energy Generation 

Figure has a minimum value at 112 % of the connection capacity. 

Figure A1.5. Trend of CAPEX/Lifetime Energy Generation Figure as installed capacity increases as a 

percentage of connection capacity 


4.3 Sensitivity Analysis 

For this analysis each of the parameters in Table A1.1 was varied in turn. 

4.3.1 Ratio of Connection Costs to Installed WTG Costs (Cost Ratio) 

Table A1.3 shows the analysis results for a range of cost ratios with the wind speed and WTG 

availability remaining at the base set-up given in Table A1.1. 

It is evident that as the installed cost of the WTG reduces against a fixed connection cost, the 

CAPEX/Lifetime Energy Generation Figure also reduces assuming a significant overbuild is 

desirable. For a cost of £0.35m per MW installed WTG and £0.7m per MW connection cost, 333 

WTG (150% of connection capacity) can be installed instead of the 222 provided in Table A1.2 for 

100% connection capacity. 

However, as is evident from both Table and Figure A1.6, as the cost ratio increases there is an 

asymptotic trend for the optimum size of the wind farm toward 111%. 

WTG cost/connection cost ratio 0.5 1 1.5 2 2.5 

Size (%) 150% 122% 113% 112% 111% 

Total CAPEX (£m) 1360 1725 2094 2517 2933 

Lifetime Revenue (£m) 8933 8080 7725 7680 7630 

CAPEX/ Lifetime Energy Generation (£/MWh) 12.18 17.08 21.68 26.22 30.75 

WTG (units) 333 271 251 249 246 

Capacity Factor (%) 38% 43% 44% 44% 44. 

Table A1.3. WTG installed cost sensitivity sample results. 

In Figure A1.6, each line represents the CAPEX/Lifetime Energy Generation Figure for different 

cost ratios between the installed WTG cost per MW and a fixed connection cost per MW of £0.7m. 

Figure A1.6. CAPEX /Lifetime energy figure & installed capacity sensitivity to WTG installed costs 



Table A1.4 shows the sensitivity analysis results for a range of average wind speeds with the WTG 

installed cost and WTG availability parameters remaining at the base set-up given in Table A1.1. 

As provided in Table A1.4, the possible percentage of installed power against connection capacity 

ranges asymptotically from 147% at low average wind speeds (6m/s) to 111% at high wind speeds 

(16m/s). Given that the typical mean wind speed for the North Sea is 9m/s, these results suggest 

that the optimum size wind farm installed capacity is 112% of the available connection capacity. In 

the scenario presented here, the recommendation would be that the number of turbines used for 

the development should be 249 rather than 222 (100% of connection capacity). As the average 

wind speed increases there is little change in the optimum size. If the mean wind speed is less 

than 9m/s then the optimum size increases in order to maximise the utilisation of the available 

connection capacity. 

Wind speed 

(m/s) 

6 7 8 9 10 11 12 13 14 15 16 

Size (%) 147 126 114 112 111 111 111 111 111 111 111 

Total CAPEX 

(£m) 

Lifetime 

Revenue 

(£m) 

CAPEX / 

Lifetime 

Energy 

Generation 

(£/MWh) 

3225 2875 2675 2642 2625 2625 2625 2625 2625 2625 2625 

4325 5395 6444 7680 8795 9801 10651 11347 11900 12302 12574 

59.65 42.63 33.21 27.52 23.88 21.43 19.72 18.51 17.65 17.07 16.70 

WTG (units) 326 280 253 249 246 246 246 246 246 246 246 

Capacity 

Factor (%) 

19% 28% 36% 44% 50% 57% 62% 66% 69% 71% 73% 

Table A1.4. Average wind speed sensitivity 

It should be noted that the average wind speed is a characteristic of the site chosen for the wind 

farm development; however, this model can be used to ascertain the level of enhanced installation 

above the connection capacity required to maximise the economic benefit given the site 

constraints. 


Figure A1.7. Sensitivity of CAPEX/Lifetime Energy Generation Figure & installed capacity to average wind 

speed 


Table A1.5 shows the analysis results for a range of WTG availabilities with the WTG installed cost 

and Average wind speed remaining at the base set-up given in Table A1.1. 

Availability (%) 84% 86% 88% 90% 92% 94% 96% 98% 100% 

Size (%) 119 117 114 112 109 107 105 103 101 

Total CAPEX (£m) 2758 2725 2675 2642 2592 2559 2525 2492 2459 

Lifetime Revenue 

(£m) 8180 8028 7829 7680 7487 7343 7200 7060 6922 

CAPEX/Lifetime 

Energy Generation 

(£/MWh) 26.98 27.16 27.33 27.52 27.70 27.88 28.06 28.24 28.42 

WTG (units) 264 260 253 249 242 238 233 229 224 

Capacity Factor (%) 44% 44% 44% 44% 44% 44% 44% 44% 44% 

Table A1.5. CAPEX/Annual Energy figure & installed capacity sensitivity to average wind speed 

The results in Table A1.5 show that as WTG availability decreases, the percentage of installed 

power for a given connection capacity needs to increase to maintain similar CAPEX/Lifetime 

Energy Generation Figures. However, for a 90% WTG availability, an installed capacity of 112% 

provides the optimum CAPEX/Lifetime energy figure, as shown in Figure A1.8. 


Figure A1.8. CAPEX/Lifetime Energy Generation Figure against installed capacity for 

various WTG availabilities 


5 Recommendations 

This high level analysis presented here suggests that the optimum installed capacity for a fixed 

connection capacity in terms of a CAPEX/Lifetime Energy Generation Figure appears to be around 

112%. 

It is therefore recommended that the installed capacity for the Round 3 wind farms used in this 

report be set at 112% of the total power transfer capacity of the technology elements used in the 

connection design. 


6 References 

[1] Danish wind industry association, www.windpower.com. 

[2] NOABL and NCIC wind speed data 

[3] North Hoyle Offshore Wind farm annual report, URN no. 08/P47, BERR 

[4] CERA: Offshore Wind Power Capital Costs Will Continue To Rise, Creating New 

Challenges for European Renewable Energy Targets, CERA (Cambridge Energy 

Research Associates), Press Release 28 May 2008, 

www.cera.com/aspx/cda/public1/news/pressReleases/pressReleaseDetails.aspx?CID=9512 

[5] Atlas of UK Marine Renewable Energy Resources: Technical Report, 

www.berr.gov.uk/files/file27763.pdf, Dec 2004. 


Appendix 2 : HVAC cable reactive compensation analysis methodology 

A power systems model of a nominal 275kV offshore-onshore alternating current (AC) grid interconnection 

from a proposed 330MW (derived from the manufacturer’s maximum power rating) point 

of supply (POS) to the onshore point off common coupling (PCC) was developed in PSS/SINCAL 

V5.4. This model was used to assess at a high level the maximum feasible length of three-core 

subsea AC cable that could be deployed before the combined issues of active power losses and 

reactive power charging capacitance reduced the collector cables useful power carrying capacity to 

zero. Figure A2.1 illustrates the power system model. 

100.00 % 

0.00 ° 

112.41 % 

2.43 ° 

115.10 % 

5.16 ° 

I61 

-316.82 MW 

-765.35 MVAr 

316.82 MW 

1 

765.35 MVAr 

-327.71 MW 

-455.05 MVAr 

2327.71 MW 

328.69 MVAr 

-330.00 MW 

108.00 MVAr 

LO57 

330.00 MW 

-108.00 MVAr 

Figure A2.1: PSS/SINCAL power systems model 

The following assumptions have been made regarding the model: 

• The collector cables from the offshore POS to the landfall transition pit and from the landfall 

transition pit to the PCC are equal in length 

• Import of reactive power is defined as inductive and export of reactive power is defined as 

capacitive where 0.95 power factor equates to the import or export of 108MVAr of reactive 

power 

• The offshore wind farm is capable of importing 108MVAr of reactive power at the POS during 

maximum active power export to partially offset the cable charging current 

• The PCC is controlled to a nominal voltage (275kV) 

• The maximum permissible variation of voltage from nominal is ±10% of nominal voltage 

1845 Appendix 02 HVAC cable reactive compensation methodology v1.0.doc Page 1 of 2

• The grid at the proposed PCC is strong, i.e. the fault level from the grid is 10 times the fault in 

feed from the proposed 330MW infeed, in order to minimise voltage variations 

The reactive power compensation (RPC) to compensate for cable charging capacitance was 

assessed under the following conditions: 

• No additional RPC 

• RPC of equal quantity installed at the PCC and POS (50/50 split) 

• RPC of equal quantity installed at the PCC, landfall transition pit and POS (33/33/33 split) 

Initial approximate sizing of the RPC requirement was determined from Equation 1 where Qreq is 

reactive power, C is the cable capacitance (µF) per km, l is the cable length in km’s, V is the 

operating voltage of 275kV and ω is the angular frequency of the supply in radians. It is important to 

note that this does not consider the presence of voltage drop due to resistive losses and also series 

inductance of the cable. Further optimisation of the RPC was performed manually to produce near 

zero reactive power transfer to the PCC. 

Equation 1: Sizing of RPC 

Q req 

= ωClV 

2 

The cables average current flow (kA) and apparent power capacity (MVA) were applied as 

constraints to determine the cables useable capacity. These are defined as follows: 

• Average current flow – The current carrying capacity of the conductors’ cross-sectional area 

is the limiting factor. If this is exceeded the heat produced over a prolonged period of time 

would cause damage to the conductor insulation possibly causing a total dielectric failure. 

Figures are shown as an average of the current flows observed at different points in the 

cable. Indication has been given in Table 4 of the main report to cases where peak current 

flow exceeds the cables current capacity 

• Apparent power capacity - This considers the conductors current carrying capacity with 

respect to transmission voltage. If the transmission voltage exceeds the design withstand 

voltage of the cables dielectric for a significant period of time it will cause the dielectric 

breakdown causing possible short circuits in the dielectric or intermittent breakdown of the 

dielectric due to charging current producing transient interference 

The results of this analysis are presented in Table 4 of The Round 3 Offshore Wind farm Connection 

Study main report (v1.0). 

1845 Appendix 02 HVAC cable reactive compensation methodology v1.0.doc Page 2 of 2

THE CROWN ESTATE Round 3 Offshore Wind Farm Connection ...

You also want an ePaper? Increase the reach of your titles

Delete template?

Save as template?