Offshore Transmission Network Feasibility Study · worked together to produce this Offshore Transmission Network Feasibility Study ... maintenance costs and congestion management

Offshore Transmission Network Feasibility Study

Date: 26 September 2011 Version: 1.0

Cover Photograph: © DONG Energy


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Offshore Transmission Network Feasibility Study Section 1 Executive Summary Page 2 Section 2 Background Page 5 Section 3 Methodology and Assumptions Page 7 Section 4 Stakeholder Engagement Page 17 Section 5 Consenting and Planning Page 18 Section 6 Overview – radial and radial plus Page 24 Section 7 Overview – coordinated Page 29 Section 8 Assessment of Potential Benefits and Challenges Page 32 Section 9 Conclusions Page 41 Appendices Appendix A Further information on scenarios Page 42 Appendix B Generic cable route optimisation Page 48 Appendix C Marine Resource System modelling and datasets Page 53 Appendix D Technology and cost assumptions Page 57 Appendix E Consenting and planning Page 58 Appendix F Assessment of design strategies Page 66 Appendix G East Coast of England Page 82 Appendix H East Anglia Page 98 Appendix I Southern Page 114 Appendix J Irish Sea Page 123 Appendix K Scotland Page 138 Appendix L Assumptions Page 152 Appendix M Glossary of acronyms Page 154


Section 1: Executive Summary 2

Section 1.0 Executive Summary Offshore Electricity Generation 1.1 Offshore electricity generation will play an important part in meeting the renewable energy

and carbon emission targets for 2020 and afterwards toward 2050. The Crown Estate‟s leasing rounds provide the potential to deliver around 46 GW of offshore wind generation in UK waters, and the award of Round 3 Zone Development Agreements in December 2009 marked the start of the biggest single programme in the world. Around 17 GW of Round 3 capacity has now entered into connection agreements with National Grid, demonstrating tangible progress toward the UK‟s binding commitments on renewable energy.

Transmission Infrastructure Requirements 1.2 The potential growth rate, location and size of new offshore generation expected over the

remainder of this decade and beyond means that the need to consider the necessary transmission infrastructure requirements to deliver this generation to market is more pressing than ever. In meeting the objectives of sustainability, affordability and energy security, ensuring the deliverability of offshore wind will be critical in facilitating the connection of generation in the required timescale.

1.3 To date, the offshore transmission infrastructure has typically been delivered on a point-to-

point or radial basis, reflecting the characteristics of the generation projects as well as timing and technology constraints. However, questions arise as to whether this approach is fit for purpose over the longer term given limited resources and wider issues such as planning and consenting constraints, particularly onshore.

1.4 To this end, The Crown Estate and National Grid Electricity Transmission (NGET) have

worked together to produce this Offshore Transmission Network Feasibility Study (the study) to identify and assess the feasibility, benefits and challenges of adopting a more coordinated approach to the development of offshore transmission infrastructure.

1.5 The coordinated design presented in this study is based on the installation of high voltage

multi-user assets that interconnect the offshore platforms and generation projects to form an offshore network that is fully integrated with onshore Transmission requirements. This conceptual design highlights how the volume of assets installed offshore could be reduced whilst the need for onshore reinforcement is minimised.

Offshore Transmission Network Feasibility Study 1.6 Focused on Round 3 and Scottish Territorial Waters (STW) projects, together with possible

interconnection, the study has undertaken a detailed assessment of constraints (onshore and offshore) and network design. It has been additionally recognised that other programmes, notably some Round 2 projects, large marine energy schemes and future interconnectors, could be incorporated into a coordinated network design strategy.

1.7 Three scenarios form the basis of the design work: Accelerated Growth, Gone Green and

Slow Progression as per the Offshore Development Information Statement (ODIS). Together, these provide a broad range of scenarios for the deployment of offshore generation. A further sensitivity has been utilised which offers a different build profile of offshore wind generation.

1.8 A number of design strategies are considered against these scenarios and the report offers

a comparison between a purely radial design, radial plus (use of larger assets but without inter-zonal interconnection) and a fully coordinated solution. Each design strategy has been built incrementally, with designs illustrated at 2015, 2020, 2025 and 2030.



1.9 Through the combined expertise of NGET and The Crown Estate, this has resulted in a detailed report on potential development paths for the electricity transmission system offshore (and associated onshore) in Great Britain to 2030.

1.10 The study represents a view of the future network requirements and direction for potential

development using information available at the time of analysis (frozen June 2011). The actual network design will be developed in accordance with user requirements. The designs shown in this report should not be considered as implying actual connection dates or connection routes for new infrastructure and they do not reflect the Transmission Owner‟s investment decisions regarding the development of their transmission area nor any other parties‟ investment decisions. The designs present an illustrative coordinated transmission design approach and have been developed to allow a comparison between the potential design options. The actual contracted position and development of the offshore and onshore transmission system can and may differ from that illustrated in the study.

Headline findings 1.11 The study has identified a number of benefits that are likely to result from the development

of a coordinated offshore transmission network. These benefits can be categorised as follows:

Environmental and consenting benefits;

Improved management of valuable resources including land take, corridor routes, and manufacturing capability;

Reduced cost for UK consumer (capital cost reductions and also a reduction in operational costs such as maintenance costs and congestion management costs in relation to system operation); and

A flexible offshore transmission network that is better able to respond to future challenges.

1.12 Total potential cost savings associated with the coordinated strategy of £6.9 billion by

2030 have been identified1, when compared with the development of the offshore

transmission network on a radial basis (£3.6 billion against radial plus by 2030). This includes:

£5.6 billion capital cost savings (£2.4 billion against radial plus);

£1.2 billion congestion management cost savings (against both radial and radial plus);

£0.1 billion maintenance cost savings (£0.05 against radial plus). 1.13 The capital cost savings identified are largely delivered through a reduction in the volume of

assets required to connect offshore generation under a coordinated design as opposed to a radial design. The table below summarises aggregate asset requirements and savings under the Accelerated Growth scenario to 2030. More detail in respect of the benefits arising under this and the other scenarios is included within the main body of the report.

1 Congestion management and maintenance cost savings beyond 2030 are not reflected in this study.



1.14 The study has demonstrated that interconnection between zones (full coordination) is vital

to realise the overall savings in relation to both asset and cost - and drives the additional benefits beyond those identified under radial plus. In contrast, the radial plus approach continues to require significant onshore reinforcements and an increased number of landing points to support the offshore developments – bringing with it environmental and consenting challenges, as well as greater ongoing operating costs (maintenance and congestion management).

1.15 The study recognises a number of challenges associated with moving towards a

coordinated transmission design offshore:

Uncertainty over the rate of deployment of offshore wind;

Technology advancement rate; and

The ability to consent those new routes required to connect the offshore generation. 1.16 A clear regulatory framework, delivered in a timely manner, will be required to navigate

these challenges. Whilst the study does not explicitly consider the regulatory framework changes required to deliver a coordinated offshore transmission design, it does recognise that timescales for delivery and the need for holistic consideration will be key factors. Given the level of uncertainty within the wider energy industry with respect the rate of offshore wind deployment, a small risk of investment stranding is evident in the analysis. This risk however largely occurs at the pre-construction stage of the process, with the stranding risk associated with physical transmission investment occurring as a result of timing issues regarding lead times for new transmission infrastructure. The design and consenting activities will need to progress a coordinated solution, even though there may be varying degrees of certainty as to whether a generator(s) may proceed with a project.

2 The onshore reinforcements (onshore AC lines) referenced in this study relate only to MITS reinforcements (locally or

deeper system reinforcements).

Asset volume and capital cost (Accelerated Growth) – radial vs coordinated

( 2010 prices) Radial Coordinated Savings Radial plus

Coordinated Savings

HVDC cables 6641 km 5216 km 1425 km 21% 5145 km 5216 km -71 km -1%

Offshore AC cables 1559 km 2353 km -794 km -51% 1948 km 2353 km -405 km -21%

Onshore AC lines (new)2

447 km 126 km 321 km 72% 447 km 126 km 321 km 72%

Offshore platforms 112 110 2 2% 103 110 -7 -7%

Cable landing sites 65 43 22 34% 58 43 15 26%

Cost £34.8 bn £29.2 bn £5.6 bn 16% £31.6 bn £29.2 bn £2.4 bn 8%


Section 2: Background 5

Section 2.0 Background Offshore Wind, National Grid and The Crown Estate 2.1 The Crown Estate has extensive marine assets, including ownership of approximately 55%

of the UK‟s foreshore and the majority of the seabed within the 12 nautical mile UK territorial limit. It also has the right to exploit natural energy resources, excluding fossil fuels, on the continental shelf within the Renewable Energy Zone. The Crown Estate has a responsibility to ensure an efficient and sustainable use of seabed in relation to marine activities, including corridors for cables and pipelines within 12 nautical miles and those cables associated with renewable energy infrastructure in the Renewable Energy Zone. The Crown Estate is obligated to enhance the capital value and the revenue return of the assets it has responsibility for. This includes the seabed and therefore it is the view of The Crown Estate that consideration needs to be given to the most efficient (within environmental, technical, commercial and other constraints) use of the seabed, coastal and other assets within its responsibility.

2.2 Offshore wind farm developers lease an area of seabed from The Crown Estate within

which their infrastructure is to be constructed. There have been five commercial allocation rounds to date: Round 1, Round 2, Round 3, extensions to Rounds 1 and 2 projects, and projects in Scottish Territorial Waters (STW).

2.3 The first allocation, in 2001, acted as a demonstration round to allow potential developers

to gain an understanding of the technological, environmental and economic issues associated with developing and operating offshore wind farms.

2.4 Further allocation rounds were conducted in 2003 (Round 2), 2008 (Scottish Territorial

Waters), 2009 (Round 3), and 2010 (Round 1 and 2 extensions). The combined generation capacity for all of these rounds amounts to over 46 GW by 2025.

2.5 National Grid Electricity Transmission (NGET) owns and operates the high voltage

electricity transmission system in England and Wales and, as National Electricity Transmission System Operator (NETSO), operates the Scottish high voltage transmission system. Following activation of the offshore transmission regime in June 2009, NGET‟s system operator role was extended to cover offshore waters. NGET‟s system operator role brings responsibility for the day-to-day management of the flow of electricity onto and over the National Electricity Transmission System – including developing and maintaining an efficient, coordinated and economical system of electricity transmission. NGET also has an obligation to provide information on offshore developments through the publication of a non-binding Offshore Development Information Statement (ODIS).

2.6 The Crown Estate and NGET have contributed their relative experience and expertise to

the findings of this study. The Crown Estate has used its award-winning Geographic Information System (GIS) based Marine Resource System (MaRS) to identify the offshore constraints relevant to the portion of illustrative cable routes under each of network design strategies identified for each scenario, taking into account constraints and exclusions for each region. It has also reviewed the current consenting framework in relation to offshore developments. NGET has identified electrical requirements and preliminary illustrative routing for onshore and offshore including landing points, interface points and offshore platform positioning, and has modelled the cost and technology assumptions to these illustrative designs in order to assess potential benefits and challenges. Further detail on the underlying assumptions is provided in section 3 and relevant appendices.

Project objective and scope

2.7 The potential growth rate, location and size of new generation raises a number of

challenges in terms of grid connections, which has resulted in the requirement to consider a coordinated design of the offshore and onshore transmission system. In order to


Section 2: Background 6

investigate the feasibility of such an approach The Crown Estate and NGET worked together on this offshore transmission network feasibility study, to:

Identify how the coordinated development of the offshore (and associated onshore) network could be developed across a range of scenarios;

Compare the coordinated approach against a radial and a radial plus approach where appropriate3

;

Assess the benefits and challenges of a coordinated network, in particular, the impact on overall volume of assets, cost, flexibility, consenting, network security and resilience.

2.8 The study sought to present illustrative designs which:

Optimise deliverability of offshore generation;

Minimise overall cost to consumers;

Optimise network resilience and security;

Identify incremental development to minimise the risk of asset stranding;

Facilitate flexible network development; and

Mitigate the consent risk. 2.9 The study focused on the potential network development associated with the offshore wind

programmes of Round 3 and STW projects, together with possible additional European interconnection. However, it has been additionally recognised that other programmes, notably some Round 2 projects, large marine energy schemes and future interconnectors, could be incorporated into a coordinated network design strategy4

. 2.10 The designs shown in this study should not be considered as implying actual connection

dates or connection routes for new infrastructure and they do not reflect the Transmission Owners (TOs) investment decisions regarding the development of their transmission area or imply any other parties‟ investment decisions. The designs present an illustrative coordinated transmission design approach using information available at the time of analysis (frozen June 2011) and have been developed to allow a comparison between the potential design options. The constraints presented in this study are those identified by high level (desktop based) analysis using the available information known at the time of analysis. The actual constraints, which would be applicable to the individual connection route, can and may be different following completion of further detailed site analysis. The actual contracted position and development of the offshore and onshore transmission system can, and may, differ from that illustrated in the study. The study represents a view of the future network requirements and direction for potential development, the actual network design will be developed in accordance with user requirements.

2.11 The study does not consider the legal and regulatory mechanisms which would be required

for the delivery of the designs or the specific impact on individual transmission connections. It is, however, recognised that Ofgem and DECC are currently reviewing the existing framework through the Offshore Transmission Coordination Group.

3 A description of these design strategies is provided in section 3.14 of this report.

4 For this study, the STW projects of Beatrice, Inch Cape and Neart na Gaoithe were not included in the coordinated design

and therefore are not included in the asset volume and cable route assessment. Some benefits of coordination of these projects is likely, but has not been captured in this study.


Section 4: Stakeholder Engagement 7

Section 3.0 Methodology and Assumptions Overview 3.1 The study undertook an assessment of the constraints and network design by region to

allow a detailed assessment to be made. The following regions (as illustrated in Figure 3.1) were identified and developed:

Irish Sea;

East Coast of England;

Southern;

East Anglia;

Scotland. 3.2 For each region, three full generation and demand scenarios and an additional sensitivity

analysis have been considered. A snapshot of the network design has been taken for each design strategy for 2015, 2020, 2025 and 2030. A holistic review of the entire network across the regions was undertaken to ensure that the interactions between regions (and associated onshore reinforcements or avoidance thereof) could be fully reflected. This approach allowed a view to be presented on investment required and incremental development of the system.



Figure 3.1: Regions Assessed Within Study



Future Generation and Demand Scenarios 3.3 In order to appropriately assess the need for future transmission system development, it is

necessary to make assumptions regarding the future generation and demand background that the electricity transmission system will need to accommodate. Three generation and demand background scenarios, plus an additional sensitivity, have been used5

:

Slow Progression;

Gone Green;

Accelerated Growth; and

Tuned Transmission Entry Capacity sensitivity (Tuned TEC). 3.4 In each of the scenarios, demand is included at its assumed peak level. The assessment

of the electricity system adequacy tends to focus on transmission system peak demand as this is often the most onerous demand condition the network needs to be able to accommodate and will drive many of the required reinforcements.

3.5 All scenarios cover the period from 2011 to 2030 and consider the anticipated range of

potential offshore developments from nearly 23 GW of offshore transmission wind generation installed capacity (Slow Progression) rising to approximately 49 GW (Accelerated Growth).

Slow Progression

3.6 In this scenario, the emphasis is on a slow progression towards the EU 2020 targets for

renewable energy, carbon emissions reduction and energy efficiency improvements. The EU 2020 renewable targets are not met until around 2026. Gone Green

3.7 The Gone Green6 scenario represents a potential generation and demand background that

meets the environmental targets in 2020 and maintains progress towards the UK‟s 2050 carbon emissions reduction target.

3.8 The scenario takes a holistic approach to the meeting of the targets, assuming a

contribution from the heat and transport sectors towards the renewable energy target.

Accelerated Growth 3.9 The Accelerated Growth scenario uses the Gone Green onshore generation background as

a base with the assumption that offshore generation builds up far more quickly due to a rapidly established supply chain, higher carbon prices and strong government stimulus.

3.10 The key comparison to the onshore background against the two scenarios above is that the

nuclear advanced gas-cooled reactor (AGR) plant is consistent with the Slow Progression scenario and that existing gas plant remains open for longer to maintain the plant margin and act as a back-up for the significant amount of wind generation that may be built.

Sensitivity – Tuned Transmission Entry Capacity (Tuned TEC) 3.11 The Tuned TEC sensitivity was developed with a view to reflecting The Crown Estate

offshore leasing capacity. It was derived primarily using publicly available information.

5 These scenarios are based on the 2011 ODIS Future Scenarios: http://www.nationalgrid.com/NR/rdonlyres/4C5B2769-

76D8-46D0-8B1E-429B477FDE88/47455/Industy_BriefingNote1.pdf. More information is provided in Appendix A. 6 Please note that there is close correlation between the Gone Green 2011 scenario and the Renewables Roadmap which

was published with the 2011 Electricity Market Reform White Paper.

http://www.nationalgrid.com/NR/rdonlyres/4C5B2769-76D8-46D0-8B1E-429B477FDE88/47455/Industy_BriefingNote1.pdf

http://www.nationalgrid.com/NR/rdonlyres/4C5B2769-76D8-46D0-8B1E-429B477FDE88/47455/Industy_BriefingNote1.pdf



3.12 For projects that currently do not have a Connection Agreement with NGET for their maximum generation capacity, the Tuned TEC sensitivity depicts an alternative planning view regarding the connection dates for the development zones/projects, based on the aggregated proposed development rates for projects considered by this study.

3.13 Figure 3.2 illustrates a comparison of the three scenarios and the Tuned TEC sensitivity –

comprising Round 3 and STW projects.

Figure 3.2: Future Scenarios Comparison: Round 3 & STW Offshore Wind Developments

Offshore and Associated Onshore Connection Designs 3.14 The study includes a number of conceptual desktop design strategies that demonstrate

how different design and technology assumptions can influence the offshore transmission development for each scenario (and sensitivity). The different design strategies presented are:

Radial: point-to-point connections from the offshore generation to suitable onshore Main Interconnected Transmission System (MITS) collector substations using currently available technology;

Radial plus: similar to radial in the use of point-to-point connections for connecting the offshore generation to the onshore MITS, but utilising anticipated future transmission technology capability (e.g. 2 GW capacity converter stations and high capacity offshore cables) in line with technology projections for the next five years.

Coordinated: an interconnected offshore design using AC cable and HVDC interconnection between MITS, offshore platforms and offshore wind development areas, using the same advanced technology as the radial plus strategy.

3.15 These design strategies are consistent with those identified in the 2010 Offshore

Development Information Statement7 (ODIS) and are illustrated in Figure 3.3.

7 http://www.nationalgrid.com/NR/rdonlyres/14BFDA91-01E7-49A2-82CB-A7151155D12F/43325/2010ODIS_Chapters_Final.pdf

0

5

10

15

20

25

30

35

40

45

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Insta

lled

Cap

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)

Slow Progression: R3 & STW Offshore Wind Gone Green: R3 & STW Offshore Wind

Accelerated Grow th: R3 & STW Offshore Wind Tuned TEC Register: R3 & STW Offshore



Figure 3.3: Design strategies

Network design – an overview 3.16 In undertaking the network design, the study sought to demonstrate a network that can:

Meet user requirements at the most economic and efficient cost (considering onshore and offshore costs) - taking account of all user requirements (including onshore generation, offshore generation, interconnectors);

Be developed incrementally and flexibly (to minimise stranding risk) - incorporating an appropriate level of extendibility (with snapshots taken at 2015, 2020, 2025 and 2030);

Optimise network resilience and security - facilitating flexible development and use of the transmission system;

Be considered against a credible range of scenarios – Slow Progression, Gone Green, Accelerated Growth - and Tuned TEC sensitivity;

Be compared across radial, radial plus (where appropriate) and coordinated design strategies.

3.17 This was achieved by:

Desktop analysis of known offshore, foreshore and onshore constraints;

Assessment of the consenting implications of alternative network design strategies;

Utilisation of appropriate technology assumptions,

Discussion with developers to gain their input (through an initial workshop and individual developer meetings);

Focusing on Round 3 and STW projects, together with possible additional European interconnection.

3.18 The following National Electricity Transmission System Security and Quality of Supply

Standards (NETS SQSS) assumptions were used for the offshore element of the study:

Radial elements:

Up to 1800 MW can be connected by a single circuit;

Radial connections rated at 100% generation capacity;



Loss of single connection circuit may cause loss of all generation on connection.

Interconnected elements:

Links can be greater than 1800 MW provided alternate power paths are available to redistribute power following loss;

Local connections based on 100% generation capacity, other elements are based on scaled generation as onshore;

Up to 1800 MW can be lost for a cable loss;

Wider infrastructure requirements based on scaled generation, as onshore. 3.19 By extending the interconnected transmission system to include parallel offshore circuits

through a coordinated design, the offshore transmission assets become an integral part of the wider transmission system. The transmission focus changes from simply transporting power away from the generation to that of meeting both the generators requirements and those of the wider transmission system to ultimately satisfying demand. This is in contrast to point-to-point radial connections transporting power from offshore generation to the onshore MITS (with connections to the MITS based on 100% generation capacity), which then must take the role of onward transport to the demand centres. In the coordinated strategy, the offshore system assists in the wider system power transfer and is required to respond dynamically to changing power flow conditions on the system (including demand and generation changes and fault outages). With the coordinated strategy, the local offshore generator connection must still satisfy the local generation capacity (i.e. local connections are based on 100% generation capacity), but the transmission capacity beyond that may be shared with wider system power flows (i.e. the scaling approach (as detailed in 3.18) does not require the same connection capacity). This is the same as experienced by onshore generation connections joining the onshore MITS.

3.20 A generic exercise in cable and platform position optimisation (as shown in Appendix B)

has also been used in developing the designs. 3.21 It is important to note that all of the design strategies illustrated in this report will involve

development of both offshore and onshore infrastructure. Whilst some offshore strategies may facilitate the requirement for fewer additional onshore reinforcements, the onshore system will still be required to meet the electricity requirements of Great Britain‟s homes and businesses. Interfaces between the onshore and offshore elements of the transmission system will need to be robust to facilitate power flows.

Technology 3.22 The study takes a relatively cautious approach to the technology development, with only

those technological advancements available in the next three to five years included within the design. These are consistent with those outlined in Appendix 4 of ODIS 2010

8.

3.23 A sample of the technology assumptions are as follows:

Only technology that is already available or is reasonably expected to be available within the next 3-5 years with appropriate supplier engagement has been considered.

DC Technology assumptions:

Offshore HVDC links will be Voltage Sourced Converter (VSC);

HVDC converters up to 2 GW capacity will be available by 20179;

Multi-terminal VSC links with off-line DC switching will be available by 2017.

AC technology assumptions:

Platforms will have a maximum of 600 MW of generation connected;

AC transmission to shore and between platforms will be at 220 kV using 3 core bundled, 300 MVA cables;

8http://www.nationalgrid.com/NR/rdonlyres/CC4994A2-83C5-4990-9E0C-F8CE04DCA588/43378/Appendices2010_Final.pdf

9 This assumes focused development commences early 2012.

http://www.nationalgrid.com/NR/rdonlyres/CC4994A2-83C5-4990-9E0C-F8CE04DCA588/43378/Appendices2010_Final.pdf



Greater design efficiencies may be obtained by increasing voltage and utilising 3 single core cables (300 MVA plus);

Maximum distance considered for AC will be ~ 60km cable length.

Technology not considered in the study10

:

HVDC on-load circuit breakers have not been considered;

AC cables with ratings greater than 300MVA;

HVDC cables exceeding 2 GW. 3.24 The designs presented in the report utilise DC cabling to an AC platform and therefore do

not require the use of a HVDC circuit breaker. Amendment to these assumptions, facilitated by research and design to support the coordinated solution, would result in further reductions in both required asset volumes and the overall cost, e.g. increased ratings of AC cables or more compact, cheaper offshore platforms.

Cost Assumptions 3.25 All designs have been costed using the specific cost ranges and unit cost assumptions

included within ODIS 2010 (a summary of which is provided in Appendix D). In some instances, these costs have been grouped to provide an installed cost, for example to give the total cost of an offshore platform rather than its component parts. Where pricing information has been available as part of NGET‟s day-to-day operations, this information has been used to validate the cost assumptions. For offshore assets and „next generation‟ technologies, the cost assumptions have been validated through discussions with suppliers. Given the lack of information available regarding the cost of offshore platforms, only conservative cost efficiencies have been taken into account as the size of offshore platforms is increased

Staging 3.26 The designs present a staged development, with each stage assigned against a particular

year for the scenario under consideration (2015, 2020, 2025 and 2030). The analysis assumes that pre-construction engineering takes place in a timely manner11, to allow the commencement of major construction work within the same lead-time as the development of generation projects. By ensuring the design stages are consistent for each scenario, it is possible to make the design robust against changes in the generation background. For example, this means that design stages can be brought forward should the generation background move from a predominantly Gone Green generation background to an Accelerated Growth generation background (or vice versa).

Cost Model 3.27 To enable analysis of the economics associated with asset volume for each of the

illustrative offshore network designs, NGET has developed a scheme and capital cost model. The cost model applies average costs for each equipment type (as detailed in Appendix D). When calculating the cost of cabling offshore, the analysed cable statistics from The Crown Estate‟s Marine Resource System (MaRS) has been used to account for difficult conditions like deep water, hard seabed material, obstacle avoidance and existing infrastructure crossings. The offshore platforms have been assumed to typically be in a water depth of 35-40m and to include sufficient electrical equipment to accept multiple transmission connections.

3.28 The unit costs represent an installed cost and, therefore, include an estimate for such

things as consenting, land purchase, materials, installation and construction.

10

Development in these areas would significantly increase the benefits of a coordinated network. 11

By undertaking pre-construction engineering the lead time for the delivery of the major transmission projects can be aligned with the offshore development and significantly reduce stranding risk while ensuring transmission capacity can be made available in accordance with generator requirements.



3.29 To determine the cost of each of the design components, the cost model calculates the

sum of the average cost for each equipment type and multiplies it by quantity. The total design cost of building everything was then determined by the cumulative cost of all of the elements required for the selected scenario.

3.30 Each of the scenarios and the sensitivity specify the year of commissioning for each

element allowing the determination of a cost profile. The cost model utilises a four year cost profile for each scheme to spread the scheme cost over time. Cumulative costs for a selected scenario are determined by summing the costs from all of the applicable individual schemes.

3.31 The resulting cost analysis (both component assessment and capital cost over time) is

provided in section 8 for Accelerated Growth. The cost analysis for the other scenarios and sensitivity is provided in Appendix F and for the individual regions in Appendices G – K.

Offshore constraints 3.32 MaRS is a Geographic Information System (GIS) based decision support tool that can be

used to identify areas with potential development opportunity within UK waters. The tool utilises a range of datasets to allow the user to determine areas of exclusion or potential restriction. Exclusions must be avoided when planning cable routes and include any activity or obstacle that will inhibit cable routing such as current The Crown Estate assets, oil and gas infrastructure and other structures. Restrictions of varying degree are prioritised (weighted) in order to capture other sensitivities, interests and marine users considered to be relevant or to represent a potential constraint for cable infrastructure. The full range of datasets considered in the MaRS model is outlined in Appendix C.

3.33 In some instances it is not appropriate to incorporate a dataset directly into the MaRS

model. This may be due to the format/completeness of the data or due to a lack of supporting detail about how to prioritise the information shown. Such information has been incorporated into the study analysis as a series of review layers, which have been analysed separately in the GIS for each of the routes identified. The review layers include bathing beaches, military interests and shipping densities (a full list of these is available in Appendix C).

3.34 Following the initial iteration of the network design for each region, the MaRS modelling

outputs were used to underpin a detailed assessment of illustrative routes (where relevant outlined within the regional reports in Appendices G - K). Input from individual developers also contributed to a fuller appreciation of potential constraints offshore. This allowed a thorough desktop assessment of the constraints/exclusions against the chosen route to shore – reflected in the network design shown in sections 6 and 7.

3.35 Figure 3.4 provides an overview of the entire GB coastline to demonstrate the constraints

and exclusions identified through the MaRS modelling. It should be noted that this analysis is based on a desktop study and actual constraints may be found to differ from those illustrated.

3.36 As per the key outlined in Figure 3.4 the green shading on the map illustrates the varying

levels of constraint offshore, with the six shades from pale through to dark illustrating a low level of constraint through to highly constrained – as determined by the desktop analysis undertaken. Areas of exclusion are shown in black. There are also a number of areas where no data was available which have been highlighted accordingly.

3.37 It should be emphasised that the constraints analysis undertaken is acceptable for the

purposes of this feasibility study. It is not sufficiently detailed, however, to provide any certainty on the suitability of those routes illustrated (technical, environmental or consenting). Furthermore, the data used for constraints are necessarily at a national/regional scale and are therefore coarser in their resolution that would be required



as part of a specific project. The constraints presented in this study are those identified through high-level desktop analysis. Actual constraint analysis may differ upon completion of further detailed work.

Consideration of planning and consenting issues 3.38 As part of the study, the consenting of related aspects of transmission have been

considered. This consideration included an analysis of those consents required and an assessment of the consenting benefits and challenges associated with different design strategies. The outcome of this is detailed in sections 5 and 8.



Figure 3.4: Offshore Constraints and Exclusions



Section 4.0 Stakeholder Engagement 4.1 As part of the process, developers (Round 3 and STW in particular) were invited to input

into the study in order to maximise the data available and ensure relevant information was reflected.

4.2 A challenge and review of the findings has sought to allow the results to be reflective of the

latest public information and include credible (illustrative) offshore routing designs for each zone.

4.3 The stakeholder engagement process with developers was initiated by a launch event

workshop in February 2011, followed by individual sessions (which discussed the study in the context of anticipated projects) and a closing seminar in July 2011 to discuss the outcome of the study.

4.4 During the stakeholder engagement process, key principles of the study were discussed,

including:

The need to take a holistic view of the development of the onshore and offshore network to ensure the most appropriate solution across the system is presented;

To clearly articulate assumptions used to allow review by interested parties;

The study does not consider how the illustrative designs presented would be delivered;

Future routes and locations are illustrative, based on desktop analysis and not representative of actual positioning. Detailed positioning and identification of the infrastructure required will be subject to detailed survey and consultation, taking into account the latest developments on the network;

Although the focus was on Round 3 and STW, other projects such as the remaining Round 2 projects and large marine energy projects, could be included in future coordinated solutions if the analysis found this approach to be of benefit for that site;

Assumptions on platform positions were acceptable on the basis that it was made clear that they were illustrative only and therefore subject to change and finalisation.

4.5 All Round 3 developers were given the opportunity to discuss the study with regards to their

own zone. These one-to-one sessions, with representatives from NGET and The Crown Estate, facilitated more detailed discussion on how the individual zones could be developed utilising the different transmission design strategies and different electricity (generation and demand) backgrounds. The sessions enabled NGET and The Crown Estate to explain and illustrate their respective methodology on the transmission design and offshore routing and how this influenced the study findings. The sessions also enabled the developers to provide specific feedback on the regional designs, which may influence the methodology utilised by NGET and The Crown Estate in the study analysis.

4.6 In July, a seminar was held to present the findings arising from the joint study. In addition to the developers who attended the February session, other interested parties were also invited such as those attending Ofgem/DECC‟s Offshore Transmission Coordination Group as well as devolved government departments12. The seminar saw the presentation of illustrative designs for all regions, an early view of the benefits arising thereof and some of the consenting practicalities likely to be faced, allowing for a full question and answer session. Questions raised at the seminar have been addressed in this report.

12

Attendees included developers, OFTOs, supply chain representatives, trade bodies, government departments and Ofgem.


Section 5: Consenting and Planning 18

Section 5.0 Consenting and Planning 5.1 Construction and operation of offshore windfarms, transmission links to the onshore MITS

and system reinforcement works require the acquisition of consents and rights under a variety of legislation. Significant information requirements and the involvement of multiple parties can all add to the complexity of the process. Consents legislation and environmental regulations prescribe the information that must be submitted with consent applications. Certain legislation requires mandatory pre-application consultation through the project development process. This requires considerable levels of design to be undertaken early in the process to support the consultation activities, with consultation responses influencing the development of the project. In addition, environmental regulations may require the assessment of cumulative and in-combination effects with other projects, which may be at different stages of project development, adding complexity and uncertainty to the consents process.

5.2 With a typical consents process including effective pre-application consultation, project

design development, environmental impact assessment (where appropriate), examination of the application, consultation comments and decision-making, obtaining consents is dependent on many factors. These must be carefully balanced by the determining authority in weighing up the merits of the application, which is likely to include consideration of relevant policy, environmental and socio-economic effects, technical issues and, where relevant, cost. It is therefore essential that the consenting process, and the issues which are considered in that process, are included as part of the review of potential offshore grid strategies.

5.3 This section describes the consenting requirements for the different design strategies. The

benefits and challenges involved with consenting the different strategies are also summarised in this section and detailed in section 8 of this report.

Consenting/planning aspects of the offshore transmission network 5.4 Whilst the acquisition of any onshore and offshore consent broadly follows similar

processes, there are subtle differences between the different legislation and determining bodies, for example, devolution of planning responsibility or type of infrastructure to be consented. The specific consents required for offshore and onshore elements are dependent on four main factors:

The location of the infrastructure (terrestrial or marine; marine within territorial waters or in the Renewable Energy Zone);

The planning system(s)13 which applies to the geographical location of the infrastructure (English/Welsh/Scottish);

The nature of the infrastructure (e.g. Nationally Significant Infrastructure Project (NSIP)); and

The nature of the organisation seeking consent (for example, NGET has certain Permitted Development rights, as would OFTOs once they are licensed).

5.5 Figure 5.1 sets out the typical infrastructure requirements along with the existing

responsibilities for development and ownership of the assets. Appendix E provides detail of the applicable consenting legislation, and also includes information about the individual pieces of legislation, along with a brief summary of other relevant regulations, in particular the requirements of the Environmental Impact Assessment.

13

Described in Appendix E.



Figure 5.1: Typical infrastructure requirements

MITS reinforcements

(locally or deeper system

reinforcements)

Substation connecting to MITS

DC converter station (if required)

and substation

Jointing pit and onshore cable

Offshore substations and

cable connection to landfall point

Offshore Generating Station

Development and Consent

Transmission Owner Transmission Owner

Offshore wind developer

or OFTO1


or OFTO


or OFTO


Construction

Transmission Owner Transmission Owner


or New project company

or OFTO



or OFTO



or OFTO



Ownership & Operation

Transmission Owner Transmission Owner OFTO OFTO OFTO



1 Offshore Transmission Owner



Consenting requirements for the radial strategy 5.6 A significantly greater volume of onshore and offshore infrastructure will typically be

required under this approach14, relating both to the offshore generating station and to its

associated transmission connection requirements. Furthermore, consents applications will be submitted to determining authorities by multiple parties in similar timescales and locations, affecting similar communities. Given this, a number of challenges are evident for the radial strategy:

The volume of consents sought means that consultation respondents are likely to challenge the need for, location of and design of the transmission infrastructure and request demonstration of the overall strategy for the delivery of the generating station, the offshore works and the onshore works;

To demonstrate that the most appropriate solution is being pursued different organisations working to different timescales and programmes must coordinate with each other in terms of engineering design and consenting/construction programmes (currently facilitated by the relationship between the generator and NGET as part of the connection agreement);

Multiple applications for consents could be required over a prolonged time frame – resulting in interlinked consent applications being run by different organisations on different programmes. This could result in a delay to the consenting programmes and add to confusion for the public and statutory bodies, with whom the consultation is taking place.

5.7 Figure 5.2 shows three examples of the different routes that could be followed to obtain the

necessary consents for the main infrastructure requirements for a radial connection within English waters. This report explores these considerations in the light of the English planning system, but the principles also apply to planning systems under the devolved administrations.

5.8 A number of important assumptions have been made in drawing up the consent options

shown in this Figure and the subsequent coordinated option, notably:

The transmission link is related to an offshore wind farm of ≥100MW and could therefore be considered associated development to an NSIP;

The onshore transmission links (connecting to the MITS) would be buried cables rather than overhead lines (if overhead lines greater than 132kV were required these would form an NSIP project in their own;

Transmission licence holders will have permitted development rights for certain aspects of the onshore elements of an offshore transmission link, so the timing of when OFTOs are involved plays an important role in the development of a project.

5.9 The transmission link referred to above, relates only to the link connecting the offshore

wind farm to the onshore MITS, additional onshore reinforcements is likely also to require consents.

14

Information on the infrastructure requirement of the design strategies is presented in section 8 of this report.



Figure 5.2: Radial consent examples

5.10 In the case of a radial plus strategy, some additional consenting considerations apply in

bringing forward the separate generating stations for connection and/or consenting the transmission link itself. However, the options for consenting in terms of the legislative regimes applied are consistent with the radial strategy and are influenced largely with issues of ownership and any association with an NSIP generating station – as such no separate figure for radial plus has been prepared.

Consenting requirements for the coordinated strategy 5.11 Under a coordinated strategy, a number of differences are apparent which will impact on

the consents process. Onshore, the key difference is that fewer cables come ashore, requiring fewer land fall points, fewer converter stations and substations. There is also less likely to be a requirement for deeper system reinforcement works.

5.12 Offshore, the key difference is the requirement for fewer transmission connections to shore,

more interconnection between offshore wind developments and an overall reduction in infrastructure requirement.

5.13 The legislative framework for radial or radial plus could equally be applied to consent the

coordinated strategy. This is illustrated (for English projects) in Figure 5.3. For radial plus and coordinated designs, the main variations in consent strategy arise in relation to the ownership of the various assets and their association or otherwise with an NSIP, the timing of projects coming forward for development, the need case and the provision of any anticipatory infrastructure. It is uncertain under current arrangements whether a need case which contains elements of anticipatory infrastructure would be sufficiently robust to meet the challenge of key stakeholders, consultees and the determining authorities.



Figure 5.3: Coordinated consent examples

Benefits and challenges associated with consenting a coordinated strategy 5.14 The key consenting benefits from the development of a coordinated strategy are derived

from the requirement for fewer cables coming ashore and the requirement for fewer, more strategic onshore reinforcements and offshore infrastructure.

5.15 Whilst the consenting of radial connections may be better understood by developers,

consenting bodies, and stakeholders, the consenting of offshore generation is yet to be taken through the development consent order process under the Planning Act. Furthermore, consents for radial links are only likely to be granted if the consenting body believes development to be sustainable. The consenting burden and associated risk is likely to increase as the volume of radial connections increases, particularly in relation the extensive onshore reinforcements required. In contrast, the coordinated strategy would demonstrate that consideration has been given to the overall solution, which would minimise the cumulative effect of projects seeking to connect.

5.16 It is important to note that as part of the coordinated strategy, some wind farm connections

would be connected on a radial basis where this offers the most economic and efficient solution. However, through being considered as part of the wider coordinated strategy, the consenting of these radial elements will see the same consenting benefits.

5.17 The benefits and challenges of consenting a coordinated strategy are detailed in Section 8

and Appendix E of this report. Consenting summary 5.18 Obtaining consent for offshore and onshore transmission is an essential step in the

connection of offshore wind generation capacity to the transmission network. The existing legislation under which consents for transmission are obtained is appropriate for both the



radial and coordinated strategies. However, the consenting burden for Round 3 and STW is likely to become unmanageable. The sequential consenting of radial connections allows no scope for minimising the cumulative effects of transmission links, which could result in delay or consents not being obtained. On balance, the coordinated strategy is likely to give rise to fewer planning and environmental issues, thus resulting in consents being more easily acquired. However, to support the consents for a coordinated solution it would be helpful if policy or guidance existed to endorse the development of anticipatory infrastructure. It is essential that the consenting process forms a fundamental element of the development of the coordinated strategy. In particular:

Investigating the most appropriate way to incorporate the transmission infrastructure requirements within the marine planning process;

Establishing whether the move to a coordinated approach suggests the need for enabling anticipatory consenting; and

Considering whether transitional arrangements are necessary in respect of projects already in the consenting process.


Section 7: Overview – coordinated 24

Section 6.0 Overview: radial and radial plus 6.1 This section provides an overview of the illustrative network designs envisaged for the

radial and radial plus design strategies under Accelerated Growth. 6.2 Figures 6.2 to 6.3 illustrate the designs in subsequent five year periods of development,

with Figures 6.4 and 6.5 providing an overview of the radial and radial plus designs in 2030. The key associated with Figures 6.2 to 6.5 is illustrated in Figure 6.1 below:

FIGURE 6.1: Key for Figures 6.2 – 6.5



Figure 6.2: Overview, Time Series, Radial, Accelerated Growth



Figure 6.3: Overview, Time Series, Radial Plus, Accelerated Growth



Figure 6.4: Overview, Radial, Overview, Accelerated Growth, 2030



Figure 6.5: Overview, Radial Plus, Accelerated Growth, 2030



Section 7.0 Overview: coordinated 7.1 This section provides an overview of the illustrative network designs prepared for the

coordinated design strategy under Accelerated Growth. 7.2 Figure 7.2 illustrates the design in subsequent five year periods of development, with

Figure 7.2 providing an overview of the coordinated design in 2030. The key associated with Figures 7.2 to 7.3 is illustrated in Figure 7.1 below:

7.3 Similar figures are provided in Appendix F for the Gone Green and Slow Progression

scenarios, and Tuned TEC sensitivity. 7.4 It is recognised that offshore generation could, depending on the volume of generation

connecting, lead to the requirement for significant onshore reinforcements to accommodate the increased transfers required. For the radial strategy, the network capacity requirements have been provided by the use of point-to-point circuits to accommodate generation capacity supported by additional onshore reinforcements. By developing a coordinated strategy, which links together the offshore developments and integrates fully with onshore, it is possible to accommodate all generation requirements whilst significantly reducing the onshore transmission reinforcement requirements. An alternative network solution that could be considered is to coordinate within development areas, but without coordinating between areas. However, this approach would fail to realise many of the potential benefits of coordination as detailed in section 8. This is particularly apparent in the East Coast and East Anglia regions considered in this study.

Figure 7.1: Key for Figures 7.2 – 7.3



Figure 7.2: Overview, Time Series, Coordinated, Accelerated Growth



Figure 7.3: Overview, Coordinated, Accelerated Growth, 2030


Section 8: Assessment of Potential Benefits and Challenges 32

Section 8.0 Assessment of Potential Benefits and Challenges Comparison of design strategies 8.1 For the purpose of comparison, this section focuses on the Accelerated Growth scenario in

order to assess the benefits and challenges associated with the various design strategies.15

The benefits and challenges hold true for the other scenarios and sensitivity (to varying degrees depending of the rate of offshore wind deployment), the data relating to the other scenarios and sensitivity are provided in Appendix F16

. 8.2 The benefits and challenges identified in this section are for the overall network design.

The specific regional findings are detailed within the regional Appendices (Appendices G - K.)

Potential benefits associated with the coordinated strategy 8.3 In meeting the objectives of sustainability, affordability and energy security, ensuring the

deliverability of offshore wind will be critical. The benefits of pursuing a coordinated transmission network design, highlighted as part of this study, help to facilitate deliverability of offshore wind. They can be categorised under the following headings:

Environmental and consenting benefits,

Improved management and utilisation of valuable resources;

Reducing costs for the UK consumer; and

Future proofing the transmission network. Environmental and consenting benefits

8.4 A key aspect to the deliverability of offshore wind will be the ability to consent the

necessary transmission infrastructure to allow for connection of the wind farm. Whilst the process of consenting under both the radial and coordinated strategy will present its challenges, the study demonstrates that there are tangible consenting benefits that arise from a coordinated approach. With a reduction in consenting complexity due to fewer onshore reinforcements and offshore assets being required, this allows for:

The improved management of valuable environmental resources - minimising potential for route sterilisation by reducing the number of cables and landing points required and facilitating the ability to take a holistic view of requirements. This will allow assets to be sized and located accordingly, with consents obtained once whilst recognising future developments as projects are deployed and/or re-optimisation of the network takes place;

The coordination of works and associated consents to allow demonstration that an appropriate solution was being sought beyond that required for an individual project. Option evaluation and demonstration of alternatives is challenged rigorously by interested parties, in particular for onshore developments;

Reduced consenting burden on stakeholders with whom the relevant applicant organisation is undertaking consultation.

8.5 This is in contrast to the radial (and radial plus) strategy where the requirement for multiple

radial connections would result in a number of highly interlinked applications being run by different organisations on different programmes. This would:

Increase the consenting burden and requirement to demonstrate the correct solution is being sought;

Result in cumulative and increased risk for later projects; and

15

Unless otherwise stated, the benefits and challenges associated with radial/radial plus are the same. 16

Appendix F also includes a comparison between the output from this study and the study prepared by NGET in 2010 – to allow tracking of the findings between studies.



Make robust assessment of alternatives difficult (for both those seeking consents and those considering consents applications).

8.6 Further detail on the benefits of consenting a coordinated strategy is included within

Appendix E. 8.7 There is further environmental benefit from the coordinated strategy through a reduced

footprint delivered through a reduction in land area required for substations and HVDC converters. For the East Coast region for example, there is approximately 25% reduction in land area required.

Improved management and utilisation of valuable resources

8.8 The coordinated strategy reduces the overall volume of assets installed with respect to

offshore and associated onshore transmission.

Onshore17: the coordinated strategy requires significantly reduced onshore

reinforcements. This not only brings with it cost savings, but facilitates deliverability of the required network in terms of reduced construction challenge and reduced planning/consenting requirements. The overall reduction in asset volume also reduces the overall environmental impact of the design.

Offshore/foreshore: the reduced offshore cabling, platforms and landing points required under the coordinated approach will also minimise environmental impact and reduce the likelihood of route sterilisation.

8.9 Figure 8.1 shows the asset volume (and associated capital cost) required for the

coordinated strategy compared to the radial and radial plus strategies under the Accelerated Growth scenario (as determined by the methodology outlined in section 3). The cost information presented is taken from NGET‟s scheme and capital cost model (as described in section 3), and has been populated with cost data based on information in the 2010 ODIS.

Figure 8.1: Asset volume and capital cost (Accelerated Growth) – radial Vs coordinated

Radial Coordinated Savings Radial plus

Coordinated Savings

HVDC cables 6641 km 5216 km 1425 km 21% 5145 km 5216 km -71 km -1%

Offshore AC cables 1559 km 2353 km -794 km -51% 1948 km 2353 km -405 km -21%

Onshore AC lines (new)

447 km 126 km 321 km 72% 447 km 126 km 321 km 72%



Capital cost (2010 prices)

£34.8 bn £29.2 bn £5.6 bn 16% £31.6 bn £29.2 bn £2.4 bn 8%

Capital cost based on 2010 prices.

17

The onshore reinforcements (onshore AC lines) referenced in this study relate only to MITS reinforcements (locally or deeper system reinforcements).



8.10 Taken together, this overall reduction should help alleviate constraints on the supply chain‟s ability to meet demand for both the onshore and offshore infrastructure requirements, thus increasing confidence from a deliverability perspective18.

Reducing costs for the UK consumer

8.11 The total potential overall savings associated with the coordinated strategy are identified as

being £6.9 billion by 2030 (2010 prices)19 when compared to a radial transmission design (and £3.6 billion against radial plus by 2030). This consists of:

£5.6 billion „real‟ capital cost savings (£2.4 billion against radial plus);

£1.2 billion congestion management cost savings (against both radial and radial plus);

£0.1 billion maintenance cost savings (£0.05 billion against radial plus). 8.12 It is important to note that the technology assumptions considered in the study could be

viewed as conservative. Amendment to these assumptions facilitated by further technological development to support the coordinated solution would result in further reduction in both the asset volume required and the overall cost of the coordinated solution – for instance through increasing the rating for AC cables or the development of more compact, cheaper offshore platforms20. Similarly, amendment to the other assumptions, such as undergrounding, will have a significant impact on the capital cost21

. The assumptions used within this study are detailed in Appendix L.

8.13 Further detail of these cost savings is provided below.

Real capital cost savings 8.14 By implementing a coordinated strategy, the study has demonstrated that there are capital

cost savings due to the deployment of larger, standardised, multi-user offshore transmission assets and optimisation of onshore and offshore transmission reinforcements. All capital cost savings are in 2010 prices.

8.15 Figure 8.2 provides a comparison of the capital cost of the coordinated strategy against

both the radial and radial plus strategies to 2030. It is clear that the coordinated strategy provides a significant capital cost reduction in comparison to the other two design strategies.

Figure 8.2: Capital cost comparison (Accelerated Growth)

Coordinated Capital Cost

Coordinated Capital Savings

Radial £34.8bn £29.2bn £5.6 bn 16%

Radial Plus £31.6 bn £29.2bn £2.4 bn 8%

8.16 A breakdown of the capital expenditure differential between each of the key component

classifications of the radial and coordinated strategy under Accelerated Growth is illustrated in Figure 8.3.

18

It is widely recognised within the industry that supply chains will come under significant pressure as they ramp up production capability to meet demand for increased HVDC cable and offshore wind assets. Moreover, the volume of onshore reinforcements required across GB irrespective of energy source as we transition to meeting the 2020 targets means that onshore the supply chain is also under considerable pressure. 19 Congestion management and maintenance cost savings beyond 2030 are not reflected in this study. 20

For instance if the delivery of HVDC cables with greater capacity then 1.2GW could be advanced, from 2017 (as has been used in the study) to 2015, this would result in more then £0.5 billion of additional savings. Similarly, any further delay in the development of technology would see the potential savings eroded. 21

For instance amending the existing undergrounding assumption of 10% down to 5% under the radial strategy would reduce the total capital cost by £0.4 billion, similarly increasing the assumption to 15% would add an extra £0.4 billion.



Figure 8.3: Capital expenditure assessment – by components (Accelerated Growth)

8.17 Figure 8.3 identifies that whilst the coordinated design incurs additional capital cost in

offshore AC cables (largely driven by the additional interconnection between zones and a change to the assumed MVA rating), there are significant capital cost savings associated with HVDC cables, converters and onshore reinforcements. The interconnection between zones is vital to realise the overall savings in both asset and cost reduction (and drives the additional benefits beyond those identified under radial plus).

8.18 Figure 8.4 illustrates the capital expenditure profile across the years to 2030 under

Accelerated Growth for all three of the design strategies. It demonstrates that the profile associated with the coordinated strategy mirrors those associated with radial and radial plus, which is a result of the design facilitating incremental delivery.

Figure 8.4: Capital expenditure assessment (Accelerated Growth)



Operational cost savings – congestion management

8.19 As part of the day-to-day operation of the wider transmission network, additional generating

plant is held in reserve to cover possible generation loss as result of operational faults across the wider network. The risk of loss of generation is exacerbated where connection is facilitated via a single connection, as no alternative route to market for the power is possible. In such instances, generation held in reserve will be instructed to generate to cover the loss in electrical output, thus affecting operational costs passed back to the market (called congestion management).

8.20 A coordinated offshore transmission network has the potential to reduce the risk of loss of

output because of wider network issues, with a significant positive effect on system operation costs. Figure 8.5 provides an estimate of the annual energy curtailment cost associated with the Round 3 and STW projects in the Accelerated Growth scenario for four individual years from 2015 to 2030 for each design strategy.

8.21 For the three design strategies, a high-level analysis of constrained generation was

assessed against an assumed average offshore wind generation load factor of 40% (a widely used level of load factor assumption). It was also considered against an average transmission asset availability of 98% (the minimum OFTO availability target set by Ofgem). The energy curtailment, and its associated constraint cost estimate, reflects the £ value of the renewable energy that may be incurred due to transmission unavailability. A constraint index of £75/MWh has been assumed based on recent energy and ROC values.

8.22 The analysis detailed in Figure 8.5 illustrates that there would be significantly higher

congestion management costs associated with the radial and radial plus approaches through energy curtailment. This is attributable to the onshore reinforcements necessary to facilitate the radial strategies wider within the network. Therefore, through the coordinated strategy, as time progresses and the volume of offshore wind connected rises, increasingly efficient operation of the network will be facilitated. Extrapolating this out from 2015 to 2030 could result therefore, in cumulative congestion management savings in the region of £1.2 billion under Accelerated Growth for the coordinated strategy. For the purposes of this study, the assessment has only extended to 2030, however the requirement for congestion management and the associated constraint cost will continue beyond 2030 – a quantification for which is not provided here.

Capital Costs

0

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8.23 A change to the assumed transmission asset volume availability would significantly impact

on the constraint cost. For instance, amendment from 98% to 95% would see by 2030 the constraint cost savings increasing from £1.2 billion to approximately £3 billion.

Figure 8.5: Congestion Management (Accelerated Growth)

Operational cost - maintenance

8.24 It follows that the asset reduction will result in a reduction in maintenance costs associated

with the coordinated solution. This is illustrated in Figure 8.6. 8.25 The total maintenance cost has been calculated by considering three major categories of

infrastructure, which are offshore cables, offshore platforms and the remaining assets (onshore and other). The maintenance cost (calculated on present money value) is assumed as a percentage of the installed capital cost as follows:

Offshore Cables 0.5%

Offshore Platform 2.0%

Onshore and Other 1.0% 8.26 The figure demonstrates maintenance cost savings in the region of £0.1 billion by 2030

against the radial strategy.

Annual Curtailment (40% wind load factor & 98%

availability factor)

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Figure 8.6: Maintenance Cost

Losses

8.27 It follows that with a reduction in assets and pushing the technology to run at higher voltages there should be a reduction in losses (although it is difficult to quantify the full impact of transmission losses). The interconnected nature of the coordinated approach with HVDC also provides the opportunity to actively manage transmission losses by controlling power distribution and shutting down redundant elements under lightly loaded conditions.

Future proofing the transmission network

8.28 The profile of investment identified in Figure 8.4 demonstrates that the three design strategies can equally be developed incrementally. This will allow opportunity for re-optimisation as developments occur and thereby minimise the risk of stranding. Re-optimisation is critical, as it is important to note that the commitment to spend will follow a less smooth profile due to the timing associated with taking the investment decisions22

.

8.29 The added resilience (through the additional redundancy provided) in the coordinated strategy facilitates greater security of supply of the network. It also helps to facilitate greater European interconnection by allowing the potential for future connection to an international platform. This is in line with the North Seas Countries‟ Grid Initiative being implemented by the member states surrounding the North Sea. This allows for greater flexibility in the effective management of the wider transmission network, minimising the need for generation curtailment and future proofing the transmission network.

Potential challenges associated with the coordinated strategy

8.30 The study has identified a number of potential benefits that could be delivered through the adoption of a coordinated strategy. There are also a number of challenges associated with the delivery of the coordinated strategy, which require careful management. The challenges can be categorised under the following headings:

Delivery of an appropriate framework for coordination;


22

Sections 8.38-8.40 provide details of how such flexibility can be achieved.

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Consenting.

Framework for coordination 8.31 Realisation of the coordinated design depends on an appropriate legal and regulatory

framework to enable delivery. Whilst this study does not consider the detail of what this should be, amendment to the current provisions is likely to be required.

8.32 The coordinated design illustrated includes all potential offshore wind seeking to connect, in

line with the scenarios identified. As discussion over the delivery of an appropriate framework to facilitate coordination progresses, there is a risk that timing will result in it no longer being possible to capture all projects as part of the coordinated strategy, with some of the value associated with this strategy becoming eroded. Timely resolution is therefore paramount.

Uncertainty over the rate of deployment of offshore wind

8.33 This study considers a range of scenarios to illustrate the impact of the future deployment of offshore wind. Whilst this provides a useful illustration of potential developments, the actual deployment of wind out to 2030 cannot be predicted. The designs presented are illustrative based on desktop analysis, as further analysis is undertaken the actual constraints, which are applicable to the individual connection route, can and may be different.

8.34 A radial strategy connecting individual wind farms will ensure only those transmission

assets required for the wind farms under development will be taken forward. The coordinated strategy requires a much more holistic view to be taken on the transmission requirements, which may include elements of anticipatory investment.

8.35 It is critical that the design and deployment of future GB offshore transmission assets are

able to evolve against an uncertain and changing future onshore/offshore generation backdrop. Given the level of uncertainty within the wider energy industry with respect the rate of offshore wind deployment, a small risk of investment stranding is evident in the analysis. This risk however largely occurs at the pre-construction stage of the process. The detailed design, Invitation to Tender and consenting process will need to consider a coordinated design even though certainty as to whether the generator will proceed is not yet evident.

8.36 In practice, the stranding risk associated with physical transmission investment is more

limited. This largely occurs as a result of timing issues in relation to the lead-times required for new transmission infrastructure, in particular HVDC cable, being slightly longer (approximately one year) than that required for the generation assets. In such instances, standardisation will be important as this will allow the asset to be utilised within another project should the original development change course within the intervening lead-time period.

8.37 A key tool in mitigating the stranding risk in the process will be the ability to re-optimise the

proposed transmission design as necessary to ensure incremental build is possible using the optimal design. The ability to design holistically and flexibly across both the onshore and offshore transmission systems is critical to delivering the right offshore transmission network at any point in time.

8.38 As part of the study, a variation to the Irish Sea offshore transmission design has been

prepared as an example as to how flexibility in design might be pursued. This design (included as Figure F22 in Appendix F) is intended to illustrate how a design might change should the generation mix deviate from the scenarios expected. Should the offshore wind generation within the Irish Sea not develop in line with either timing or volume assumptions, then the onshore requirements relating to the commissioning of new nuclear generation in the North Wales region would require a different solution. It is this kind of flexibility in



design at the pre-construction stage that, whilst it may incur some additional cost, allows for the minimisation of stranding risk at the point of actual investment. This flexibility in approach will allow for the right procurement strategies and ensure that investment occurs in a timely manner thus minimising the risk arising from uncertainty.

Technology advancement rate

8.39 The technology assumptions associated with both the coordinated and the radial plus

design strategies require technological progress if the designs are to be realised – indeed further development will be required to ensure the necessary timescale can be met. It is essential that the supply chain be provided with appropriate signals to ensure this development occurs. The analysis has already demonstrated that some of the potential benefits of a coordinated strategy (under Accelerated Growth) in the early years cannot be realised23.

8.40 Discussion with equipment manufacturers has led to conservative assumptions being taken

with respect to offshore VSC HVDC circuits larger than 1.2GW, i.e. not deliverable before 2017. For the Accelerated Growth scenario and Tuned TEC, this means the initial stages for some projects will be restricted to using currently available technology. Commitment to focused research and development will allow for faster technology development, with the potential for more than £500 million capital benefit. Similarly, delays to technological development will reduce potential capital savings by similar magnitudes.

Consenting

8.41 The achievement of the necessary consents is vital to facilitate project realisation, which

therefore brings consenting challenges to the delivery of any infrastructure both onshore and offshore. It is important to be mindful that such challenges exist under both the coordinated and radial strategies. In particular, for the coordinated strategy, it would be helpful if policy or guidance existed to endorse the development of anticipatory infrastructure. Moreover, marine spatial planning must take account of the coordinated strategy (a matter that requires timely attention due to the ongoing development of marine plans). It is also important that the impact on ongoing consents programmes is taken into account.

8.42 A further consideration of the challenges of consenting a coordinated strategy is included

within Appendix E.

23

HVDC convertor suppliers have indicated that 12 months development work is required before they are likely to be in a position to offer greater than a 1.2GW HVDC link, making the earliest deployment 2016/17.


Section 9: Conclusions 41

Section 9.0 Conclusions 9.1 Offshore power generation will play an important part in meeting the renewable energy and

carbon emission targets for 2020 and afterwards towards 2050. The potential growth rate, location and size of new offshore generation means that it is important to reflect on how best to connect offshore wind to the wider transmission system while balancing the three key policy objectives of decarbonisation, security of supply and affordability.

9.2 The coordinated design presented in this study is one that is based on the installation of

high voltage multi-user assets that interconnect the offshore platforms and generation projects to form an offshore network. This conceptual design highlights how the volume of assets installed offshore could be reduced whilst the need for onshore reinforcement is minimised.

9.3 As a result of the study, a number of benefits have been identified arising from the

development of a coordinated offshore transmission network and can be categorised as follows:

Environmental and consenting benefits;

Improved management and utilisation of valuable resources including land take, corridor routes and manufacturing capability;

Reduced costs for UK consumer (capital cost reductions as well as a reduction in operational costs such as maintenance costs and congestion management costs in relation to system operation); and

A flexible offshore transmission network that is better able to respond to future challenges.

9.4 The study also recognised a number of challenges associated with moving towards a

coordinated transmission design offshore including:



The ability to consent those new routes required to connect the offshore generation. 9.5 A clear regulatory framework, delivered in a timely manner, will be required to navigate

these challenges. The existence of these challenges should not detract from the potential benefits associated with a coordinated design strategy, and in order for the benefits to be realised, the timescales for delivery will be key. The ability to re-optimise the proposed transmission design as necessary to ensure incremental build using the optimal design has been demonstrated in this study and this will be crucial to ensure that the most appropriate network is delivered.

9.6 To ensure that the benefits identified in this report can be achieved it is recognised that:

Pre-construction work should commence early 2012 for the initial key elements of the coordinated network;

Further detailed steady state and transient system studies must be undertaken to allow protection and control requirements for HVDC equipment to be fully specified;

Functional specification must be produced to enable focused development to take place;

Focused development with all key suppliers must be undertaken to ensure equipment is available in the required timescale.

9.7 To conclude, the study has demonstrated that the coordinated strategy will facilitate

balancing of the three key policy objectives of decarbonisation, security of supply and affordability by:

Maximising deliverability of offshore wind - providing a means through which the significant volumes of offshore wind can connect which minimises risk of route sterilisation, maximises supply chain deliverability and facilitates the consents process;

Strengthening security of supply through delivery of a more resilient network;

Delivering at a lower overall cost to consumers.

Offshore Transmission Network Feasibility Study – Appendices

Appendix A: Further information on scenarios 42

Appendices

Appendix A: Further information on scenarios

Future Scenario: Slow Progression A.1 In this scenario, the emphasis is on a slow progression towards the EU 2020 targets for

renewable energy, carbon emissions reductions and energy efficiency improvements and the UK‟s unilateral carbon emissions reduction targets. EU 2020 renewable targets are not met until around 2026.

A.2 This scenario has been developed against a background of lower carbon prices. This

results in a slower build-up of lower carbon generation and a greater reliance on gas-fired plant. The scenario also assumes a slower rate of development for coal generation plant with carbon capture and storage (CCS) functionality, compared to the other scenarios.

Future Scenario: Slow Progression – Offshore Transmission Generation (Wind)

A.3 In the Slow Progression scenario, there is 11.5 GW of offshore transmission wind generation capacity included in 2020 (with a further 11.5 GW connecting by 2030).

A.4 The build-up of offshore transmission wind developments in this scenario includes:

6.0 GW of Round 1 and Round 2 (inclusive of Round 1 and 2 extensions) offshore transmission wind capacities by 2020;

0.5 GW of STW offshore transmission wind capacity by 2020

An additional 5 GW of Round 3 offshore transmission wind capacity by 2020; and

A further 11.5 GW of Round 2, 3 and STW developments by the end of the study period

A.5 The build-up of Round 3 and STW offshore wind developments in this scenario is shown in

Figure A1:

Figure A1: Slow Progression - Offshore Transmission Generation Wind Vs Round 3 & STW Offshore Wind Developments

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Future Scenario: Slow Progression – Generation and Demand (Transmission) Backgrounds A.6 The generation mix for this scenario is detailed in Figure A2. Generation is shown at full

capacity with the total rising to account for the intermittent nature of wind generation and thus the need for back-up plant.

Figure A2: 2011 Slow Progression: Generation (Transmission) Backgrounds

A.7 A summary of Slow Progression‟s key points:

AGR (Advanced Gas-cooled Reactor) nuclear plants receive five-year life extensions to that publicly announced;

First new nuclear plant connects in 2021/22;

A significant amount of existing coal plant closes by 2023 due to a combination of the Industrial Emissions Directive (IED) and the age of the plant;

Carbon Capture and Storage (CCS) is retro-fitted at one coal plant as part of the government funded scheme with no further CCS coal plant included in the scenario over the study period;

Existing gas-fired plant remains open for longer than in the Gone Green scenario;

A total of 26 GW of new gas plant is included in the scenario by 2030, with 7 GW already under construction / commissioning;

6 GW of new gas plant with CCS is included in the scenario;

The build-up of wind generation is lower in this scenario with 20 GW of wind capacity in 2020 (11 GW offshore) and 32 GW (23 GW offshore) in 2030;

Marine generation is assumed to develop very slowly with some larger scale generation not connecting until around 2027.

Future Scenario: Gone Green

A.8 The Gone Green scenario represents a potential generation and demand background that

meets the environmental targets in 2020 and maintains progress towards the UK‟s 2050 carbon emissions reductions target. The scenario takes a holistic approach to the meeting of the targets, assuming a contribution of the heat and transport sectors towards the renewable energy target.

A.9 This scenario includes a more rapid build-up of wind generation, with the supply chain and

thus growth in offshore wind, maintained post 2020. Nuclear AGR plant is assumed to receive ten years life extension, maintaining the level of nuclear capacity until the advent of new nuclear plant and assisting in lowering the level of carbon emissions from the generation sector. CCS plant is envisaged at both coal and gas plants into the future, with

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Nuclear Coal Gas Offshore Transmission Wind Onshore Transmission Wind Other Renew ables Other



thermal plant developed after 2023 required to have CCS technology. The increased lifespan of the AGR plant results in existing Combined Cycle Gas Turbine (CCGT) plant closing earlier than in the Slow Progression and Accelerated Growth scenarios.

A.10 This scenario is set against a background of potentially higher energy prices with the price

of carbon and the level of government subsidies stimulating low carbon generation and increasing the levels of energy efficiency.

Future Scenario: Gone Green – Offshore Transmission Generation (Wind) A.11 In the Gone Green scenario, there is 16.5 GW of offshore transmission wind generation

capacity included in 2020 (with a further 20.3 GW connecting by 2030). A.12 The build-up of offshore transmission wind developments in this scenario includes:


1.3 GW of STW offshore transmission wind capacity by 2020;

An additional 8.2 GW of Round 3 offshore transmission wind capacity by 2020; and

A further 20.3 GW of Round 3 and STW developments by the end of the study period. A.13 The build-up of Round 3 offshore and STW transmission wind developments in this

scenario is shown in Figure A3:

Figure A3: Gone Green - Offshore Transmission Generation Wind Vs Round 3 & STW Offshore Wind Developments

Future Scenario: Gone Green – Generation and Demand (Transmission) Backgrounds A.14 The level of demand in this background is consistent with the wider Gone Green scenario

and represents a level of electricity demand where the 2020 targets are met. There is a greater level of energy efficiency (than that included in the Slow Progression scenario) and potentially higher power prices. The impact of new demand sectors is also considered, namely heat pumps and electric vehicles.

A.15 The impact of the electrification of heat and transport has been assessed in more detail,

with demand increasing towards the end of the period post-2025. This includes an assessment of the impact of smart metering and time of use tariffs, which are assumed to flatten the load profile to some degree.

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A.16 The overall generation mix for this scenario is detailed in Figure A4. Generation is shown at full capacity with the total rising to account for the intermittent nature of wind generation and thus the need for back-up plant.

Figure A4: Gone Green: Generation (Transmission) Backgrounds

A.17 A summary of Gone Green‟s key points:

AGR nuclear plant receives additional five-year life extension to that assumed in the Slow Progression scenario;


Significant amount of coal plant closes due to IED and age;

4 GW of coal with CCS connects post-2023 in addition to the development of CCS at original demonstration site;

Existing gas-fired plant assumed to close at around 25 years of age;

A total of 19 GW of new gas-fired generation connects over the period with 7 GW already under construction / commissioning;

7 GW of new gas plant with CCS is included in the scenario from 2023;

The build-up of wind generation reaches nearly 26 GW of wind capacity in 2020 (16.5 GW offshore) and 47 GW (nearly 37 GW offshore) in 2030;

Marine generation develops more quickly than in the Slow Progression scenario reaching 4 GW in 2030.

Future Scenario: Accelerated Growth A.18 The Accelerated Growth scenario uses the Gone Green onshore generation background as

a base with the assumption that offshore generation builds up far more quickly due to a rapidly established supply chain, higher carbon prices and strong government stimulus.

A.19 The key differences in the onshore background are that the AGR plant assumptions are

consistent with the Slow Progression scenario (AGR nuclear plant receive five-year life extensions) and that existing gas plant remains open for longer to maintain the plant margin and act as a back-up for the significant amount of wind generation.

Future Scenario: Accelerated Growth – Offshore Transmission Generation (Wind)

A.20 In the Accelerated Growth scenario, there is 32.9 GW of offshore transmission wind generation capacity included in 2020 (with a further 16.0 GW connecting by 2030).

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A.21 The build-up of offshore transmission wind developments in this scenario includes:


2.8 GW of STW offshore transmission wind capacity by 2020;

An additional 21.3 GW of Round 3 offshore transmission wind by 2020; and

A further 16.0 GW of Round 2, Round 1 and 2 Extensions, Round 3 and STW developments by the end of the study period.

A.22 The build-up of Round 3 and STW offshore transmission wind developments in this

scenario is shown in Figure A5:

Figure A5: Accelerated Growth - Offshore Transmission Generation Wind Vs Round 3 & STW Offshore Wind Developments

Future Scenario: Accelerated Growth – Generation and Demand (Transmission) Backgrounds A.23 The electricity demand in this scenario is the same as that used in the Gone Green

scenario.

A.24 The overall generation mix for this scenario is detailed in Figure A6:

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Accelerated Grow th: Offshore Transmission Wind Accelerated Grow th: R3 & STW Offshore Wind



Figure A6: 2011 Accelerated Growth: Generation (Transmission) Backgrounds

A.25 A summary of Accelerated Growth‟s key points:

AGR nuclear plant receives five-year life extensions to that publicly announced;


Significant amount of coal plant closes due to IED and age;

4 GW of coal with CCS connects post-2023 in addition to the development of CCS at original demonstration site;

Existing gas-fired plant remains open for longer as a back-up for the significant amount of wind capacity;

A total of 17 GW of new gas-fired generation connects over the period with 7 GW already under construction / commissioning;

5 GW of new gas plant with CCS is included in the scenario from 2023;

The build-up of wind generation reaches 42 GW of wind capacity in 2020 (32 GW offshore) and 59 GW (49 GW offshore) in 2030;

Marine generation develops at a slightly quicker rate than in the Gone Green scenario albeit reaching the same level by 2030.

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Appendix B: Generic cable route optimisation 48

Appendix B: Generic cable route optimisation B.1 This Appendix investigates possible configurations of electrical connection to offshore

collector platforms with the objective of generic optimisation to minimise the overall length of cable required. Many factors influence the selection of offshore platform and cable, but for this generic assessment a uniform grid layout has been considered with a nominal AC platform spacing of 15km. Despite the generic nature of this assessment, the same optimisation principles should still apply when considering practical examples on a real world geographic layout. The basic layouts here may be seen in the different regional designs for radial, radial plus and coordinated designs.

B.2 A set of standard building blocks/modules have been assumed when assessing the design

options. These are:

500MW AC wind farm collection/substation platform with AC switching;

600MVA capable AC interconnecting cables (which may consist of 6 separate single core cables or a pair of multi-core cables);

1 GW HVDC offshore converter platform with AC switching;

2 GW HVDC offshore converter platform with AC switching;

1 GW offshore HVDC bipole cable;

2 GW offshore HVDC bipole cable.

B.3 The base assumption for the following electrical designs is to ensure sufficient transmission capacity to allow the generation capacity (with minimum transmission losses) to reach shore under intact conditions.

B.4 The design layouts shown in Figure B1 expand from a small group of AC collector

platforms in a string to expanding to include additional HVDC interconnection to the joining of more platforms into different grid configurations.



Figure B1: Generic route optimisation design layouts

2GW HVDC connection. 15km grid spacing Option A

AC Platforms 4 (500MW) DC Platforms 1 (2GW) AC Cable 60 km HVDC Cable - km Option B

AC Platforms 4 (500MW) DC Platforms 2 (1GW) AC Cable 45 km HVDC Cable +16 km (an increase of 16km from configuration A) Addition of a 2GW interconnector shared with the windfarm connection Option A

AC Platforms 4 (500MW) DC Platforms 2 (2GW) AC Cable 61 km (assuming HVDC platforms within 1km of each other) HVDC Cable - km Option B



AC Platforms 4 (500MW) DC Platforms 4 (1GW) AC Cable 47 km HVDC Cable +32 km (an increase of 32km from configuration A) Expanding to a 2 x 4 grid Option A


AC Platforms 8 (500MW) DC Platforms 4 (1GW) AC Cable 90 km HVDC Cable +30 km (an increase of 30km from configuration A) Option C



AC Platforms 8 (500MW) DC Platforms 2 (2GW) AC Cable 115 km HVDC Cable - km 4GW of wind connection and a 2GW interconnector Option A


AC Platforms 8 (500MW) DC Platforms 6 (1GW) AC Cable 120 km HVDC Cable +45 km (an increase of 45km from configuration A)



Option C

AC Platforms 8 (500MW) DC Platforms 3 (2GW) AC Cable 127 km HVDC Cable - km Option D AC Platforms 8 (500MW) DC Platforms 3 (2GW) AC Cable 206 km HVDC Cable - km


Appendix C: Marine Resource System modelling and datasets 53

Appendix C: Marine Resource System (MaRS) Modelling and Datasets An Introduction to MaRS C.1 MaRS is a GIS based, decision support tool designed to enhance marine resource analysis

and ultimately identify areas with potential for development in UK waters. MaRS helps to identify and resolve possible planning conflicts in a transparent, evidence-based manner. As well as assessing the suitability of sites for specific projects by identifying areas of opportunity and constraint, MaRS can undertake analyses that are more complex – for example, it can identify how different activities would interact in a particular area and provide statistics showing the value of the area to a competing industry.

C.2 The MaRS desktop tool provides the main model processing function in which datasets are

selected to add to models. Datasets are prioritised individually according to UK government and/or industry-approved policy and the information within the datasets can be reviewed and easily fine-tuned to make the focus more precise.

Models for Offshore Transmission Network Feasibility Study C.3 The models were run in two parts – an exclusion model and a restriction model – and the

results are combined to produce the final output. The exclusion model contains the „hard constraint‟ data, which must be avoided when planning cable routes. The exclusions include any activity or obstacle that will inhibit cable routing such as current The Crown Estate assets, oil and gas infrastructure and other structures.

C.4 The restriction model includes information regarding other sensitivities, interests and

marine users considered to be relevant, or to represent a potential constraint. These are considered „soft constraints‟ and include The Crown Estate assets, environmental areas (Statutory and non-Statutory), technical parameters and other users and obstacles. Buffers are applied to specify a distance from current activities that should be considered when planning new activities.

C.5 The model datasets are prioritised within the model by applying weights and scores (see

Figure C2). A single weight is applied to each data dataset on a scale of 100 to 1000, with 100 having the least influence, and 1000 having the most influence on the output. The weights are used to prioritise the level of importance for each input dataset. Scores are applied within each dataset to prioritise the attributes within the datasets. For example, shipping may have an overall weight of 500 (medium importance) but this weight is prioritised to locations with higher shipping densities using scores. All continuous datasets are divided into 10 intervals and the scores divided in diminishing importance for each value range e.g. shipping density. For continuous datasets, the sum of the weights is always equal to the score (e.g. see slope, sediments, bathymetry and fishing value data in table below). For discreet datasets, the score is a tenth of the weight as this would be the mean score if 10 intervals were applied to the dataset.

C.6 The weights and scores are multiplied to give a final value (importance) to that parameter.

MaRS analyses locations where datasets overlay each other and combines the final values of each into a summed outputs. This highlights locations with more overlapping datasets with high weightings as less suitable for a potential cable route. For example, the output cells where Special Areas of Conservation (SACs) overlap with Marine Conservation Zones (MCZs) will have a total value of 200,000 whereas cells where obstructions overlap with closed disposal sites will have a total value of 109,000, identifying the latter location as offering less constraint for siting a cable route. The restriction model includes both technical and non-technical parameters.

Weights and Scores Used for Modelling C.7 Figure C2 is a list of the weights and scores used to model the selected hard and soft

constraints.



Figure C1: EXCLUSIONS – deemed incompatible with cables Name Buffer (m)

MCZ Reference sites 0

Aggregate Dredging - 250

Aquaculture Leases – Current 250

Current Wind Farm Structures in UK Waters 250

Current Surface Airdata Structures in UK Waters 250

Met Office Buoys 250

Navigational Shipping Aids 250

Oil and Gas Safety Zones and infrastructure 0

Protected Wrecks variable

Unprotected Wrecks 100

Anchorage Areas 0

Figure C2: RESTRICTIONS – additional constraints, higher W*S = more constraint Dataset Name Buffer

(m) Weight Score W*S

The Crown Estate Assets

Active Cable inside UK Waters 250 1000 100 100000

Inactive Cable inside UK Waters 250 700 70 49000

Active Pipelines in UK Waters 250 1000 100 100000

Inactive Pipelines in UK Waters 250 700 70 49000

Dredging Option - Aggregates 2000 1000 100 100000

Tidal Leases - Live n/a 1000 100 100000

Wave Leases - Live n/a 1000 100 100000

UK Offshore Wind Activity n/a 1000 100 100000

Aquaculture Leases - Pending 250 1000 100 100000

Regulated Fishery Orders n/a 500 50 25000

Dataset Name Buffer (m)

Weight Score W*S

Environmental24 #

MCZs n/a 700 70 49000

Areas of outstanding Natural Beauty AONB n/a 600 60 36000

National Scenic Areas (NSA) n/a 600 60 36000

Special Areas of Conservation (SAC) n/a 1000 100 100000

Special Protection Areas (SPA) n/a 1000 100 100000

Sites of Special Scientific Interest (SSSI) n/a 700 70 49000

Ramsar Sites n/a 1000 100 100000

Heritage Coast n/a 700 70 49000

Local Nature Reserves (LNR) n/a 600 60 36000

Local Authority Nature Reserve (LANR) n/a 600 60 36000

National Nature Reserve (NNR) n/a 700 70 49000

National Parks n/a 600 60 36000

24

If designations overlap, the designation with the highest statutory weighting will be given priority.



World Heritage Sites n/a 1000 100 100000

Scheduled Ancient Monuments n/a 700 70 49000


Weight Score W*S

Technical

Slope (%)

< 2.7 n/a 100 3 300

2.7 - 5.5 n/a 100 3 300

5.5- 8.2 n/a 100 3 300

8.2 - 11.0 n/a 100 5 500

11.09 - 13.7 n/a 100 5 500

13.7 - 16.5 n/a 100 9 900

16.5 - 19.2 n/a 100 12 1200

19.2 - 22.0 n/a 100 16 1600

22.0 - 24.7 n/a 100 20 2000

24.7 - 28.5 n/a 100 24 2400

Sea-bed Sediment of UK Waters

Mud n/a 700 19 13300

Muddy sand [marine sediment] n/a 700 32 22400

Sandy mud [marine sediment] n/a 700 32 22400

Slightly gravelly mud [marine sediment] n/a 700 32 22400

Slightly gravelly sandy mud [marine sediment] n/a 700 32 22400

Sand [marine sediment] n/a 700 43 30100

Slightly gravelly muddy sand [marine sediment] n/a 700 43 30100

Slightly gravelly sand [marine sediment] n/a 700 43 30100

Gravelly mud [marine sediment] n/a 700 43 30100

Muddy gravel [marine sediment] n/a 700 53 37100

Clay and sand n/a 700 53 37100

Gravel, muddy, sandy [marine sediment] n/a 700 53 37100

Gravel, sand and silt n/a 700 53 37100

Gravelly muddy sand [marine sediment] n/a 700 53 37100

Gravelly sand [marine sediment] n/a 700 53 37100

Sandy gravel [marine sediment] n/a 700 63 44100

Bathymetry (m)

0 to -25 n/a 400 7 2800

-25 to -50 n/a 400 15 6000

-50 to -75 n/a 400 22 8800

-75 to -100 n/a 400 29 11600

-100 to -125 n/a 400 36 14400

-125 to -150 n/a 400 44 17600

-150 to -175 n/a 400 51 20400

-175 to -200 n/a 400 58 23200

-200 to -225 n/a 400 65 26000

-225 to -250 n/a 400 73 29200


Weight Score W*S



Other uses and obstacles

Round 26 Conditional Award Blocks n/a 500 50 25000

Obstructions to Navigation 100 1000 100 100000

Inactive UK Offshore Wells 100 1000 100 100000

Munitions Dumps n/a 1000 100 100000

Disused Disposal Sites n/a 300 30 9000

Closed Disposal Sites n/a 300 30 9000

Open, Not in Use Disposal Sites n/a 700 70 49000

Open Disposal Sites n/a 900 90 81000

Fish Value for Trawls - VMS (average £/yr)

< £916 n/a 800 15 12000

£916 - £1,833 n/a 800 29 23200

£1,833 - £2,749 n/a 800 44 35200

£2,749 - £4,583 n/a 800 58 46400

£4,583 - £6,416 n/a 800 73 58400

£6,416 - £10,082 n/a 800 87 69600

£10,082 - £14,665 n/a 800 102 81600

£14,665 - £21,082 n/a 800 116 92800

£21,082 - £32,998 n/a 800 131 104800

£32,998 - £23,4655 n/a 800 145 116000

C.8 In some instances, it is not appropriate to incorporate a dataset directly into the MaRS model.

This may be due to the format/completeness of the data or due to a lack of supporting detail about how to prioritise the information shown. Such information has been incorporated into the study analysis as a series of review layers, which have been analysed separately in the GIS for each of the routes identified. These include:

Bathing beaches;

Proposed Cable and Pipeline Infrastructure;

Tidal Development Knowledge Dataset;

Wave Development Knowledge Dataset;

Gas Storage Lease;

Coastal foreshore leased areas;

Ordnance Survey coastline classification (includes location of cliffs, beaches, etc);

England Maritime cliff and slope;

Round 25 oil and gas licence blocks – these will be checked to see which ones have infrastructure within them and may be added to model with same weight as Round 26 blocks or kept as a Review flag dataset;

UK Ministry of Defence (MoD) Areas (any areas with firing, rifle, bombing, demolition, explosive, mines in description);

MoD Areas (all other activities except those associated with the air only);

Shipping Density;

International Maritime Organization (IMO) routes.


Appendix D: Technology cost assumptions 57

Appendix D: Technology cost assumptions D.1 The technology cost assumptions used within this study were taken from those published in

ODIS 2010 Appendix 4.3. The derivation of the cost assumptions for more readily available items (such as those already purchased by NGET) were based upon existing and/or historical pricing information. Cost assumptions for offshore specific assets such as offshore platforms, and „next generation‟ technologies have been validated through dialogue with key suppliers. The unit costs represent an „installed‟ cost and therefore include elements such as consenting, land purchase, materials, installation and construction.

D.2 Figure D1 details the unit cost assumptions used within the study. These are based on the

costs presented in the 2010 ODIS – where a range of projected costs are identified the mid-point of this range has been used for the purposes of this study. The platform elements have been grouped together into complete units to represent a complete platform cost. For instance, the AC platform units are made up of sub elements of base platform, topside, transformers, switchgear, reactive compensation and installation. The onshore DC converters include the addition of land purchase, construction and consenting, which has not been included in the offshore converters as this is assumed within the platform.

Figure D1: Cost assumptions (2010 prices)

Offshore HVDC Voltage Source Platform Installed Cost Estimates

1000 MW +/-300KV Offshore Platform £175m



AC platforms

300MW 220 KV (1500 tonnes) £65m

500MW 220KV (2000 tonnes) £85m

HVDC Onshore Converters

HVDC voltage sourced converter 1000MW (300kV Bipole) £110m


HVDC current source converter 1500MW (500kV Bipole) £130m


HVDC current source converter 3000MW (650kV Bipole) £205m

300MVA 3 core AC

500MVA 3x single cores AC

1000MW HVDC Bipole (XLPE)

2000MW HVDC Bipole (MI PPL)

2000MW HVDC Bipole (XLPE)

3000MW HVDC Bipole (MI PPL)

£/km €/km (£k/MW - km)

1.2 1,4 (4)

1.5 1,7 (3)

1.1 1,3 (1.2)

1.35 1,52 (0.7)

1.25 1,41 (0.66)

1.5 1,7 (0.5)

Kg Cu/m 21kg 34kg 28kg 43kg 45kg 45kg

Kg Pb/m 27kg 26kg 25kg 29kg 32kg 34kg

Kg Fe/m 18kg N/A 15kg 17kg 18kg 19kg

Installation Passes

1 3 1 1 1 2

Overall Weight /m

95kg 3 x 32kg 2 x 41kg 2 x 53kg 2 x 59kg 2 x 60kg


Appendix E: Consenting and planning 58

Appendix E: Consenting and planning

E.1 This Appendix presents an overview of the existing consenting related legislation and further assessment of the potential benefits and challenges of the coordinated design strategy. Figure E1 shows the geographical extent of key development consents as applied to the main elements of an onshore and offshore transmission network.

Figure E1: Development consents

Onshore

Development Country Consenting Regime Decision Maker

England Town and Country Planning Act 1990 (a) Local Authority

Wales Town and Country Planning Act 1990 (a) Local Authority

Scotland Planning &c (Scotland) Act 2006 (a) (e) Local Authority

N Ireland Planning (Northern Ireland) Order 1991 (b) NIPS

England Planning Act 2008 IPC/SoS

Wales Planning Act 2008 IPC/SoS

Scotland Electricity Act 1989 Scottish Gvt

N Ireland Electricity (Northern Ireland) Order 1992 NIPS

England Marine and Coastal Access Act 2009 MMO

Wales Marine and Coastal Access Act 2009 WAG MCU

Marine and Coastal Access Act 2009 MMO

Scotland Marine (Scotland) Act 2010 Marine Scotland

Marine and Coastal Access Act 2009 Marine Scotland

N Ireland FEPA 1985/Northern Ireland Marine Bill DoE


England Town and Country Planning Act 1990 (c) Local Authority

Electricity Act 1989 (d) MMO


Wales Town and Country Planning Act 1990 (c) Local Authority

Electricity Act 1989 (d) MMO

Marine and Coastal Access Act 2009 WAG MCU


Scotland Planning &c (Scotland) Act 2006 (c) Local Authority

Electricity Act 1989 (d) Marine Scotland

Marine (Scotland) Act 2010 Marine Scotland


N Ireland Planning (Northern Ireland) Order 1991 NIPS

FEPA/Northern Ireland Marine Bill DoE


England Planning Act 2008 IPC/SoS

Wales Planning Act 2008 IPC/SoS

Marine and Coastal Access Act 2009 WG MCU

Scotland Planning &c (Scotland) Act 2006 (c) (e) Local Authority

Electricity Act 1989 (d) Marine Scotland

Marine (Scotland) Act 2010 Marine Scotland


N Ireland Electricity (Northern Ireland) Order 1992 NIPS

FEPA 1985/Northern Ireland Marine Bill DoE


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ion

MHWS MLW 12 nm REZ

(a) Electricity Act S37 consent also required for overhead lines (b) Electricity (Northern Ireland) Order 1992 S40 consent also required for overhead lines (c) Applies only if onshore works are not deemed within S36 Consent (d) Geographical extent if cable and onshore works are deemed within S36 Consent is shown in hashed section (e) Consent under the Planning &c. (Scotland) Act 2006 extends down to MLWS rather than MLW

Planning Regime in England and Wales

Figure E2: Planning Act 2008

Legislation and Consent

Planning Act 2008 Development Consent Order (DCO)



Geographical Extent England and Wales

Onshore and offshore within all English and Welsh waters

Purpose The DCO is the key development consent for Nationally Significant Infrastructure Projects (NSIP). NSIP are defined within the Planning Act 2008. The DCO can contain a number of other deemed consents. These include consents under the Marine and Coastal Access Act 2009, the Town and Country Planning Act 1990 and the Compulsory Purchase Act 2004, including (in some cases) compulsory acquisition of land rights. Additional elements of an NSIP can be included within the DCO as „associated development‟ – this might include, for example, an onshore substation associated with an offshore wind farm NSIP. (Note that in Wales, town and country planning is devolved to the Welsh Assembly Government, and any onshore or intertidal works which would otherwise require Planning Permission under the Town and Country Planning Act 1990 cannot be included as associated development within a DCO).

Decision maker Infrastructure Planning Commission (IPC),and relevant Secretary of State

Application to offshore transmission infrastructure

All offshore wind farms > 100MW are NSIP. The IPC requires that the DCO application also includes transmission infrastructure (offshore platforms, export cables and onshore cabling/substations). Where offshore windfarms are NSIP developments, the DCO replaces the requirement for consent under s36 of the Electricity Act 1989 (consent to construct and operate a generating station).

Overhead transmission lines of 132kV and above are NSIP. Where overhead lines are NSIP developments, the DCO replaces the requirement for consent under s37 of the Electricity Act 1989 (consent to construct overhead lines).

Other notes The Localism Bill will amend the Planning Act by abolishing the IPC and creating a „Major Infrastructure Planning Unit‟ within the existing Planning Inspectorate (PINS). It is unlikely that the process for obtaining a Development Consent Order will change significantly because of this transition.

Figure E3: Marine and Coastal Access Act 2009


Marine and Coastal Access Act 2009 Marine Licence

Geographical Extent Below Mean High Water Springs (MHWS) throughout English and Welsh waters, and in Northern Irish waters outside the 12nm Territorial Waters limit.

In Scotland, marine licensing is undertaken by marine Scotland under the Marine (Scotland) Act 2010.

Purpose A Marine Licence is required for the deposit of any substance or object either in the sea or on or under the seabed, and to construct, alter or improve any works in or over the sea, or on or under the seabed, below MHWS. An assessment of the environmental effects of any such project must be made as part of the application process The Marine Licence replaces the requirement for a licence under the Food and Environment Protection Act 1985 and consent under S34 of the Coast Protection Act 1949, and can be deemed within a DCO application (except within Welsh territorial waters, where the Welsh Assembly Government Marine Consents Unit will continue to issue FEPA licences for projects).

Decision maker Marine Management Organisation (MMO) (English waters 0 – 200nM; Welsh waters 12 – 200nM) Welsh Assembly Government (in Welsh Territorial Waters only 0-12nM) Marine Scotland (Scottish waters 12 – 200nM)


All offshore windfarms, their cables and offshore platforms will require a Marine Licence. For NSIP windfarms, this will be deemed within the DCO. For non-NSIP windfarms, a separate licence will be issued.

Any cables, platforms, connectors etc. below MHWS will require a Marine Licence. Electricity cables do not require a marine licence if they are located



between 12 and 200nM.

Other notes The Marine and Coastal Access Act 2009 and Marine Scotland Act 2010 also contain requirements for the designation of Marine Conservation Zones, and for statutory Marine Planning. Both these elements could influence the location and nature of offshore generation and transmission infrastructure, and may therefore influence the location of onshore transmission infrastructure.

Figure E4: Town and Country Planning Act 1990


Town and Country Planning Act 1990 Planning Permission

Geographical Extent England and Wales

Above Mean Low Water (MLW)

Purpose Planning Permission is required for construction onshore (including cable laying) unless by a statutory undertaker where it benefits from permitted development. In England, the development consent order (DCO) for a NSIP project can include deemed planning permission for works agreed to be „associated development‟. In Wales, DCOs cannot include „associated development‟ as the planning function has been devolved to the Welsh administration, and planning permission must be sought separately from the local planning authorities. For offshore windfarms requiring consent under S36 of the Electricity Act 1989 (i.e. windfarms in Scottish waters, or windfarms in English and Welsh waters which are less than 100MW), Planning Permission for onshore works may be deemed within the S36 consent.

Decision maker Local Authority


Where onshore infrastructure for an offshore wind farm is not included as associated development within a DCO, or deemed within a S36 consent, Planning Permission will be required.

Onshore elements requiring Planning Permission include onshore cable connection, underground cabling, onshore converter stations or substations, temporary or permanent compounds associated with offshore windfarms or transmission infrastructure (unless by a statutory undertaker).

Alterations and upgrades to onshore transmission infrastructure will require Planning Permission where these are not NSIP, unless covered by permitted development rights.

Figure E5: Electricity Act 1989 (as amended)


Electricity Act 1989 (as amended) S36 Consent/S37 Consent

Geographical Extent England, Wales and Scotland, subject to thresholds

Onshore and offshore within all English, Welsh and Scottish waters, subject to thresholds

Purpose S36 consent gives permission for the construction and operation of a generating station. S37 consent gives permission for the construction of overhead lines. Where a generating station or overhead line is NSIP, the requirement for consent under the Electricity Act is replaced by a DCO under the Planning Act 2008 for England and Wales. S36 consent for an offshore wind farm of less than 100MW in English Waters can include deemed Planning Permission for onshore works in England. This is not however a requirement and separate applications can also be made.

Decision maker MMO (for offshore S36 Consents in English and Welsh waters) Scottish Government (for offshore S36 Consents in Scottish waters) Secretary of State for Department of Energy and Climate Change (DECC) (for onshore S37 Consents in England and Wales)



Scottish Government (for onshore S37 Consents in Scotland)


Offshore windfarms <100MW are not NSIP, and will therefore require a S36 consent.

All overhead lines of 132kV and above will be NSIP projects in England and Wales and will require DCO consent under the Planning Act.

Overhead lines in Scotland, or lines in England and Wales of 132kV and below, will require S37 consent from the Scottish Government.

Planning Regime in Scotland E.2 The Electricity Act 1989 and the Marine and Coastal Access Act 2009 also apply in

Scotland; these have been described above and details are not repeated here.

Figure E6: Marine (Scotland) Act 2010


Marine (Scotland) Act 2010 Marine Licence

Geographical Extent Scotland

Below Mean High Water Springs (MHWS) out to 12nm

Purpose A Marine Licence is required for all construction and/or deposits on the seabed below MHWS. An assessment of the environmental effects of any such project must be made as part of the application process. The Marine Licence replaces the requirement for a FEPA licence and a CPA consent.

Decision maker Marine Scotland


All offshore windfarms, their cables and offshore platforms will require a Marine Licence from Marine Scotland within 12nm.

Any cables, platforms, connectors etc. below MHWS and within Scottish Territorial Waters will require a Marine Licence.

Notes For applications in the Scottish REZ (12 to 200nm) licences are issued by Marine Scotland under the provisions of the Marine & Coastal Access Act.

Figure E7: Town and Country Planning (Scotland) Act 2006


Town and Country Planning (Scotland) Act 2006 Planning Permission

Geographical Extent Scotland

Above Mean Low Water (MLW)

Purpose Planning Permission is required for construction onshore (including cable laying). For offshore windfarms, Planning Permission for onshore works may be deemed within the consent granted under S36 of the Electricity Act 1989.

Decision maker Local Authority


Where onshore infrastructure for an offshore wind farm is not deemed within S36 consent, Planning Permission will be required.

Onshore elements requiring Planning Permission include onshore cable connection, underground cabling, onshore converter stations or substations, temporary or permanent compounds associated with offshore windfarms or transmission infrastructure, and upgrades to onshore transmission infrastructure.

Other Key Legislation relevant to the UK Planning Process

Figure E8: Environmental Impact Assessment (EIA) Directive

Legislation Environmental Impact Assessment (EIA) Directive EIA Directive (Council Directive of 27 June 1985 on the assessment of the effects of certain public and private projects on the environment (The EIA Directive 85/337/EEC) (amended in 1997, in 2003 and in 2009); transposed into a variety of UK legislation controlling onshore and offshore development activities.



Geographical Extent UK wide for qualifying development (Annex 1 or 2) (onshore & offshore)

Purpose To ensure environmental effects of development are recognised in the planning process.

Decision maker Applies to all relevant regulatory regimes in the UK, subject to screening opinions for Annex 2 developments (within which most of not all of the offshore grid infrastructure development is likely to fall).


It is likely that all of the components of an coordinated offshore grid network would currently be classified as EIA development.

Figure E9: Habitats Regulation Assessment (HRA)/Appropriate Assessment (AA)

Legislation Habitats Regulation Assessment (HRA)/Appropriate Assessment (AA) Habitats Directive (Council Directive 92/43/EEC on the conservation of natural habitats and of wild fauna and flora (the Habitats Directive) and Council Directive 2009/147/EC on the conservation of wild birds (the Birds Directive); transposed into UK legislation though various sets of „Habitats Regulations‟. Regulations exist for both terrestrial and marine areas.

Geographical Extent UK wide where qualifying sites or species may be affected by development activities.

Purpose To protect sites or species of European nature conservation importance.

Decision maker Various – responsibility as the Competent Authority usually falls to the lead regulator responsible for issuing the relevant consent.


Where onshore or offshore infrastructure necessary for development of an offshore grid network may have a likely significant effect on the conservation objectives a designated site or species. May involve completion by the regulator of an Appropriate Assessment as part of the determination of the consent application.

Figure E10: Strategic Environmental Assessment (SEA) Directive

Legislation Strategic Environmental Assessment (SEA) Directive SEA Directive (The Directive on the Assessment of Certain Plans and Programmes on the Environment (Directive 2001/42/EC)); implemented into UK legislation through „Environmental Assessment of Plans and Programmes‟ Regulations.

Geographical Extent Whole UK

Purpose To ensure environmental consequences of certain plans and programmes are identified and assessed during their preparation and before their adoption. SEA is required when a 'plan' or 'programme' is being proposed. The SEA directive defines a plan or programme as a document produced by a public body and required by legislation, a regulation or an administrative order.

Decision maker Various – normally the „owner‟ of the relevant plan or project.


Unclear. Energy plans/programmes may be subject to SEA, and as such it is possible that the development of a strategic offshore transmission network could qualify as a plan or project for the purposes of SEA. Depending on the nature of the way in which the network is developed, this possible requirement would need to be investigated.

Other Notes A plan or project for the purposes of SEA may also need to be subject to an assessment under the Habitats Regulations where the plan (alone or in combination with other plans or projects) is considered to have a likely significant effect on the conservation objectives of a European site.

Further assessment of the challenges and benefits of a coordinated strategy E.3 The challenges and benefits of consenting a coordinated strategy are detailed in Section 8

of this report. This Appendix provides further detail on these benefits and challenges, making comparisons where relevant to consenting under a radial approach.



Challenges of consenting the coordinated strategy E.4 Elements within the consenting approach may need to evolve to accommodate the

coordinated strategy:

It would be helpful if policy or guidance existed to endorse the use of anticipatory infrastructure;

Marine spatial planning must take account of the coordinated strategy (requiring timely attention due to the ongoing development of marine plans).

E.4.1 One of the main consenting benefits of the radial strategy is the fact that the process for

achieving consent offshore has been defined through Rounds 1 and 2. The design of the associated offshore transmission links, the programme for consenting and the assessment of their environmental impacts are better understood by developers, statutory consultees and stakeholders. The „one project one transmission link‟ view of an offshore windfarm project is a straightforward concept for stakeholders.

E.4.2 Under this approach, a single organisation can be responsible for the consenting of both

the generating station and the offshore transmission link for a single project. This allows the developer to manage the consenting for their offshore development programme and ensures consistent and clear stakeholder engagement for the offshore element of the project. However, it is important to note that this only applies to the offshore element and under the radial strategy significant volumes of onshore reinforcements are required.

E.4.3 In contrast, whilst the existing legislation is equally suitable for radial and coordinated

strategies, the consenting process may need to evolve to accommodate the coordinated strategy.

E.4.4 The development of a coordinated network will likely require a degree of anticipatory

investment – not directly linked with a specific windfarm currently under development. This will therefore require consents to be attained on an anticipatory basis. The demonstration of a needs case associated with such anticipatory consenting will differ from that of infrastructure, which can be solely linked to projects already under development – and is not currently accommodated by the existing National Policy Statements. To ensure that, where appropriate, consents for anticipatory investment can be realised, the consenting process must ensure the ability to reflect appropriately an anticipatory needs case. It would be helpful if policy or guidance existed to endorse the use of anticipatory infrastructure.

E.4.5 The MMO is currently undertaking marine spatial planning in English waters by developing

regional marine plans, and Marine Scotland and the Welsh Government will shortly commence this process in Scottish and Welsh Waters. These marine plans, together with the overarching UK Marine Policy Statement, will set the framework for the delivery of marine licences and consents within UK waters and will form the basis against which marine consent applications are considered. The nature of a coordinated network means that the individual components are likely to have greater strategic significance than radial elements; therefore it is vital that the coordinated strategy is accommodated within the development of these marine plans.

E.5 Increased developer dependence on third party assets will result in greater

dependence on the delivery party achieving consents E.5.1 Currently, with radial connections, a developer is dependent on their own consenting

activity, potentially the consenting activity of an OFTO and the consenting activity for onshore reinforcements. Under a coordinated solution where a developer is required to connect through a coordinated asset, offshore the developer becomes dependent not only on their own consenting (for the generating station), but also on the successful consenting by another body (or bodies) for the coordinated assets both offshore and onshore.

E.5.2 Greater dependence on these third party consenting and development activities may

reduce developer control over their individual project.



E.6 The impact on ongoing consenting programmes must be taken into account E.6.1 Any framework changes to facilitate coordination will require a transition from the current

arrangements and the impact on ongoing consents programmes must be considered as part of this. NGET already has licence obligations to consider coordination and, as such, offers for connection (both onshore and offshore) already take into account the need to coordinate. However, it is important that the perception of an “alternative coordinated” approach does not impact on the ongoing consents programmes of developers. It is important to note that this remains, until the framework for coordination is able to clearly demonstrate that all alternatives have been fully considered.

Benefits of consenting the coordinated strategy

E.7 The consenting complexity will be reduced due to fewer onshore reinforcements, as

well as offshore assets, being required E.7.1 The development of a coordinated system for connecting offshore wind brings with it some

very tangible benefits in terms of the coordination of consenting activity and the consenting burden on stakeholders. Compared to the radial (or indeed radial plus) strategy, fewer offshore-to-onshore transmission links require consent under a coordinated strategy. In addition to this, the reduction in the onshore reinforcements required would result in fewer consent applications overall.

E.7.2 Given that onshore consenting risks for transmission infrastructure are high, arguably a

coordinated network alleviates a large part of the overall consenting risk for the connection of offshore wind projects.

E.7.3 In contrast, one of the key disadvantages of consenting the radial strategy is the

requirement for sequential consenting of offshore transmission links and onshore reinforcements (which are only triggered when grid connection applications are made). The potential volume of offshore wind seeking to connect increases the consenting risk for the radial strategy owing to the number of connections and associated onshore reinforcements, which will be required. Sequential consenting of multiple transmission links and onshore reinforcements does not allow a forward-looking plan for the connection of capacity and there is a significant risk that the cumulative effects on communities and the environment will result in delays to the determination of applications or refusal of applications.

E.7.4 The scale of capacity in Round 3 requiring connection means that in a situation where all

capacity is connected radially, not only will there need to be multiple applications for offshore transmission links, but also multiple applications for onshore reinforcements by onshore TOs. Additional layers of consenting risk are added by the interdependency of the various consent applications. In situations where generating stations and/or onshore reinforcements are considered NSIP, there is a risk of delays to the determination of consent where there is doubt over the success of linked consents, since in the process of determining an NSIP application the IPC will need to take into account the probability of other works achieving consent.

E.7.5 The radial plus strategy starts to address some of the risks of multiple consenting by

connecting several projects at a point offshore and bringing a reduced number of transmission links onshore, however, the requirement for associated onshore reinforcement remains and this strategy still has an increased requirement for cabling and landing points

E.8 Reduced consenting burden on stakeholders E.8.1 A coordinated strategy would reduce the planning and consenting burden on individual

developers, transmission owners, consenting bodies and stakeholders through reducing the number of optioneering studies and consent applications. An additional benefit would



be derived from the ability of stakeholders and consenting bodies to see how individual consent applications fit within a wider overall strategy for transmission.

E.9 Better management of valuable environmental resources (minimises potential for

route sterilisation) E.9.1 Properly planned and sited, a coordinated transmission network requiring significantly

fewer pieces of larger capacity infrastructure would result in a reduced overall environmental impact both individually and cumulatively, reducing the effect on local communities onshore and interactions with other industries offshore.

E.9.2 A key benefit, therefore, for the consenting of a coordinated approach stems from the ability

to plan more strategically and develop a coordinated strategy for the required capacity, including onshore reinforcements. This should allow an early and thorough consideration of alternatives, environmental impacts and potential cumulative impacts, which in turn should reduce both the consenting risk for individual elements of the coordinated network and the overall environmental impact of the required grid development

E.9.3 This more strategic approach mitigates one of the key risks under a radial design strategy,

which is that whilst early projects may benefit from a more straightforward and consentable approach, limitations on resources (e.g. suitable offshore routes or landfall points) may lead to later projects being more constrained.


Appendix F: Assessment of design strategies 66

Appendix F: Assessment of design strategies

F.1 Sections 6, 7 and 8 of the report provide an overview of the study findings, focusing on

Accelerated Growth. This Appendix F has been prepared to support these sections by facilitating review of the alternative scenarios of Gone Green and Slow Progression and the Tuned TEC sensitivity. This Appendix also presents a comparison with the findings of the study conducted by NGET in 2010

F.2 Figures F2 to F4 provide an overview of how the coordinated offshore network could be

developed in subsequent five year periods for Slow Progression, Gone Green and Tuned TEC sensitivity. The key associated with Figures F2 to F4 is illustrated in Figure F1:

FIGURE F1: Key for Figures F2 – F4



Figure F2: Overview, Time Series, Coordinated, Slow Progression



Figure F3: Overview, Time Series, Coordinated, Gone Green



Figure F4: Overview, Time Series, Coordinated, Tuned TEC



Slow Progression F.3 Figure F5 shows the asset volume and associated cost for the coordinated strategy

compared to the radial and radial plus strategies under the Slow Progression scenario.

Figure F5: Asset volume and cost (Slow Progression) – radial and radial plus Vs coordinated

Radial Coordinated Savings Radial plus Coordinated Savings

HVDC cables 2161 km 1809 km 352 km 16% 2019 km 1809 km 210 km 10%

Offshore AC cables

933 km 977 km -44 km -5% 1116 km 977 km 139 km 12%


25 126 km 126 km 0 0 126 km 126 km 0 0

Offshore platforms 48 48 0 0 53 48 5 9%


Capital cost £14.3 bn £13.4 bn £0.9 bn 6% £16.2 bn £13.4 bn £2.8 bn 17%


F.4 The capital expenditure differential between each of the key component classifications of

the radial and coordinated design under Slow Progression is illustrated in Figure F6.

Figure F6: Capital expenditure assessment – by components (Slow Progression)

25




F.5 Figure F7 below illustrates the capital expenditure profile across the years to 2030 under Slow Progression.

Figure F7: Capital expenditure assessment (Slow Progression)

F.6 Figure F8 provides an estimate of the annual congestion management cost associated with

the Round 3 and STW projects in the Slow Progression scenario for four individual years from 2015 to 2030 for each design strategy (the derivation of this information is explained in section 8.19 – 8.23). Extrapolating this from 2015 to 2030 could result in cumulative congestion management cost savings in the region of £0.4 billion under Slow Progression for the coordinated strategy.

Capital Costs

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Figure F8: Congestion Management (Slow Progression)

F.7 Figure F9 shows the maintenance cost associated with each of the design strategies under

Slow Progression.

Figure F9: Maintenance cost (Slow Progression)

Gone Green

Annual Curtailment (40% wind load factor & 98% availability

factor)

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F.8 Figure F10 shows the asset volume and associated cost for the coordinated strategy

compared to the radial and radial plus strategy under the Gone Green scenario.

Figure F10: Asset volume and cost (Gone Green) – radial and radial plus Vs coordinated


Coordinated Savings

HVDC cables 4381 km 3111 km 1270 km 29% 3457 km 3111 km 346 km 10%

Offshore AC cables

1341 km 1739 km -398 km -30% 1609 km 1739 km -130 km -8%


262 km 126 km 136 km 52% 262 km 126 km 136 km 52%

Offshore platforms 82 77 5 6% 80 77 3 4%





the radial and coordinated design under Gone Green is illustrated in Figure F11.

Figure F11: Capital expenditure assessment – by components (Gone Green)

F.10 Figure F12 illustrates the capital expenditure across the years to 2030 under Gone Green.

26




Figure F12: Capital expenditure assessment (Gone Green)

F.11 Figure F13 provides an estimate of the annual congestion management cost associated

with the Round 3 and STW projects in the Gone Green scenario for four individual years from 2015 to 2030 for each design strategy (the derivation of this information is explained in section 8.19 – 8.23). Extrapolating this from 2015 to 2030 could result in cumulative congestion management cost savings in the region of £0.8 billion under Gone Green for the coordinated strategy.

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Figure F13: Congestion management (Gone Green)

F.12 Figure F14 shows the maintenance cost associated with each of the design strategies

under Gone Green.

Figure F14: Maintenance cost (Gone Green)


factor)

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GG 2015 GG 2020 GG 2025 GG 2030

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Gone Green

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Tuned TEC F.13 Figure F15 shows the asset volume and associated cost for the radial strategy compared to

the coordinated strategy under the Tuned TEC scenario.

Figure F15: Asset volume and cost (Tuned TEC) – radial Vs coordinated


Coordinated Savings

HVDC cables 6641 km 5216 km 1425 km 21% 5145 km 5216 km -71 -1%

Offshore AC cables

1559 km 2335 km -776 km -50% 1948 km 2335 km -387 -20%


27 447 km 126 km 321 km 72% 447 km 126 km 321 km 72%






the radial and coordinated design under Tuned TEC is illustrated in Figure F16 below.

Figure F16: Capital expenditure assessment – by components (Tuned TEC)

27




F.15 Figure F17 below illustrates the capital expenditure across the years to 2030 under Tuned TEC.

Figure F17: Capital expenditure assessment (Tuned TEC)

F.16 Figure F18 provides an estimate of the annual congestion management cost associated

with the Round 3 and STW projects in Tuned TEC for four individual years from 2015 to 2030 for each design strategy (the derivation of this information is explained in section 8.19 – 8.23). Extrapolating this from 2015 to 2030 could result in cumulative congestion management cost savings in the region of £1.4 billion under Tuned TEC for the coordinated strategy.

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Figure F18: Congestion management (Tuned TEC)

F.17 Figure F19 shows the maintenance cost associated with each of the design strategies

under Tuned TEC.

Figure F19: Maintenance cost (Tuned TEC)

Comparison NGET 2010 Study findings


factor)

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F.18 In 2010, NGET produced a study comparing the benefits of a coordinated design strategy against a radial strategy. To facilitate tracking between the output from the 2010 study and this study a comparison of the findings is illustrated in Figures F20 and F21 below.

Figure F20: 2010 findings Vs 2011 findings (Accelerated Growth)

2010 2011

Offshore wind connected

51552 MW 50200 MW

Radial Coordinated Radial Coordinated

HVDC cables 6562 km 5566 km 6641 km 5216 km

Offshore AC cables 1229 km 1077 km 1559 km 2353 km


593 km 162 km 447 km 126 km

Offshore platforms 182 104 112 110

Cable landing sites 87 45 65 43

Capital cost £33.7 bn £25.7 bn £34.8 bn £29.2 bn Capital cost based on 2010 prices.

Figure F21: 2010 findings Vs 2011 findings (Gone Green)

2010 2011

Offshore wind connected

26354 MW 36828 MW

Radial Coordinated Radial Coordinated

HVDC cables 2605 km 2472 km 4381 km 3111 km

Offshore AC cables 1206 km 603 km 1341 km 1739 km


593 km 137 km 262 km 126 km

Offshore platforms 73 45 82 77

Cable landing sites 61 32 51 35

Capital cost £15.9 bn £11.5 bn £25.0 bn £20.8 bn Capital cost based on 2010 prices.

Changes to assumptions F.19 A number of different assumptions were used in the current study, which results in the

differences outlined above as detailed below:

An updated generation and demand background (2011) which introduces significant change in the volume of offshore wind connected with the Gone Green scenario (~ 26 GW to ~ 37 GW) and impacts the volume of assets and overall cost of delivery under all design strategies. The changes have been driven by a change to underlying demand within the scenario and recognition that offshore generation will be required to meet this demand following a re-assessment of marine technologies coupled with greater certainty relating to recent offshore leasing capacities;

Incorporation of Round 3 and STW projects29. It does recognise, those other projects,

most notably Round 2 projects, might be usefully incorporated into a coordinated network. The 2010 study covered all offshore wind developments that might usefully be incorporated into a coordinated network;

28

The onshore reinforcements (onshore AC lines) referenced in this study relate only to MITS reinforcements (locally or deeper system reinforcements). 29

For this study, the STW projects of Beatrice, Inch Cape and Neart na Gaoithe were not included in the coordinated design

and therefore are not included in the asset volume and cable route assessment. Some benefits of coordination of these projects is likely, but has not been captured in this study.



Changes to technical assumptions including:

Amendment to the maximum AC cable capacity from 600 MVA to 300 MVA. This results in the requirement for more AC cabling (and increased associated cost);

An increase in the SQSS infeed loss limit to 1800MW allowing for larger radial cables and lower cost in the radial solution; and

Changes to platform positioning and offshore routing identified as a result of stakeholder engagement and collaboration between NGET and The Crown Estate.

Variation in Irish Sea offshore transmission design F.20 Figure F22 illustrates a variation in the Irish Sea offshore transmission design. The figure

illustrates a variation in the Irish Sea offshore transmission design prepared as an example as to how flexibility in design might be pursued (as detailed in section 8.38). This design is intended to illustrate how a design might change should the generation mix deviate from the scenarios expected. Should the offshore wind generation within the Irish Sea not develop in line with either timing or volume assumptions, then the onshore requirements relating to the commissioning of new nuclear generation in the North Wales region would require a different solution as shown here. It is this kind of flexibility in design at the pre-construction stage that, whilst it may incur some additional cost, allows for the minimisation of stranding risk at the point of actual investment.



Figure F22: Variation in Irish Sea Design


Appendix G: Offshore and Associated Onshore Network Design – East Coast of England 82

Appendix G: Offshore and Associated Onshore Network Design – East Coast of England

Study Overview

G.1 This Appendix provides a detailed analysis of the East Coast of England region considered in the study.

G.2 The study sought to present illustrative designs which:






Facilitate the consents process.

G.3 The study focused on the potential network development associated with the offshore wind programmes of Round 3 and Scottish Territorial Water projects, together with possible additional European interconnection. It was additionally recognised, however, that other programmes, notably some Round 2 projects (and large marine energy schemes), might also usefully be incorporated into a coordinated network.

G.4 Taking account of all User requirements (offshore generation, onshore generation, interconnectors), the study used a wide range of data relating to the potential development of the National Electricity Transmission System (NETS) in offshore waters, including applicable technology, a desktop assessment of constraints, illustrative offshore transmission design and onshore transmission coordination. It was supported by technical and economic analysis, which sets out options for reinforcing both the offshore and onshore transmission networks. It did not identify, however, project specific engineering designs. The coordinated designs identified in this study can be compared against a purely radial design (with individual point-to-point connections) and a radial plus approach (inter zonal interconnection) – the different design strategies are described further in section 3.

G.5 The designs shown in this study should not be considered as implying actual connection dates or connection routes for new infrastructure and they do not reflect the Transmission Owners (TOs) investment decisions regarding the development of their transmission area or imply any other parties‟ investment decisions. The designs present an illustrative coordinated transmission design approach using information available at the time of analysis (frozen June 2011) and have been developed to allow a comparison between the potential design options. The constraints presented in this study are those identified by high level (desktop based) analysis using the available information known at the time of analysis. The actual constraints, which would be applicable to the individual connection route, can and may be different following completion of further detailed site analysis. The actual contracted position and development of the offshore and onshore transmission system can, and may, differ from that illustrated in the study. The study represents a view of the future network requirements and direction for potential development, the actual network design will be developed in accordance with user requirements.

G.6 Whilst there are many areas under discussion with respect to delivery of a coordinated offshore transmission network, the objective of the study was to illustrate what such a design could look like. Consideration of how such a network might be delivered is outside of the project scope. The study does not consider the regulatory mechanism, which will be applicable for delivery of the designs or the specific impact on individual transmission connections.

Scenario Overview - Generation Background

G.7 Figure G1 presents the three scenarios and sensitivity which are considered for the Round 3 projects from the East Coast of England. The scenarios facilitate a range of installed capacity trajectories to be considered over the study period, as described in section 3.



Figure G1: East Coast of England (Round 3) Zone – Installed Generation Capacity Comparison (By Future Scenarios)

G.8 In additional to the possible growth in generation, it is conceivable that additional

interconnection with other North Seas European countries may develop. The position of the East Coast developments could bring connection options to other European projects with sharing of transmission assets and reducing cabling requirements. For this report, a connection from Dogger Bank to Norway (1000 MW to 2000 MW) has been considered.

Constraints analysis G.9 To develop this design, the known offshore conditions have been considered. An overview

of the identified offshore constraint areas are shown in the Figure G2. On the East Coast of England, the main exclusions include marine aggregate leases and unsuitable seabed sediments. Areas of high constraint include further marine aggregate leases and environmental designations.

East Coast Round 3 Generation Capacity

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Figure G2: East Coast of England, Constraints Overview



Illustrative Offshore Transmission Design G.10 In order to develop the transmission designs, an understanding of the location and size of

offshore developments is required. The position of the offshore AC collector/substation platforms has been estimated as illustrated in Figure G2. Each AC collector platform is set to allow 500 MW of turbines to be connected. The AC collector platforms are also assumed to contain any necessary high voltage switchgear and step-up transformers.

G.11 Staging of the transmission infrastructure delivery has been accomplished by planning to

the maximum potential capacity of the zone and working backwards to identify the key delivery stages and build progression. Design adjustments have been made to ensure logical development stages and to minimise possible asset stranding. The design stages are checked against each of the scenarios to ensure suitable optimisation.

G.12 Findings from a generic exercise in cable and platform position optimisation as shown in

Appendix B have been used in developing the designs shown here. G.13 With an increased percentage of generation coming from intermittent sources such as

wind, it is beneficial to increase the transmission capability between countries to take advantage of power source diversity therefore increasing supply security. If intermittent source capacity grows as in the later years of the generation scenarios presented here, it can be reasonably expected that additional interconnection capacity could be constructed between Great Britain and the other North Sea countries.

G.14 Traditionally any continental interconnectors are directly connected to the respective

onshore transmission networks. With an interconnected offshore network, it becomes feasible to interconnect countries through the offshore generation sites taking advantage of potentially redundant offshore transmission capacity and saving on cable requirements.

G.15 For example, a new interconnection to Norway could connect to Dogger Bank, sharing the

capacity of the multiple offshore transmission circuits back to the onshore transmission system. For the scenarios where this is relevant this is included within the network designs illustrated.

Illustrative Offshore Cable Route Statistics G.16 Illustrative offshore cable route statistics give the length of routes, seabed sediments along

the routes, potential cable crossing and other constraints on the routes. The information was used in assessing the routing suitability cable laying/installation methods and costs. A sample of the statistics is included in G.27.

Onshore Connection and Main Interconnected Transmission System Considerations G.17 Given the long length of coastline accessible by the eastern projects, there are many

potential connection substations that already exist. As illustrated in Figure G3.



Figure G3: East Coast of England (Round 3) Zone – Onshore Transmission System

G.18 As with any physical change to the transmission network, a number of factors must be

considered such as the available space, planning permissions and electrical stresses. While a number of existing substations are reviewed, there is always the possibility of constructing a new connection substation if deemed the most suitable option.

G.19 The transmission network with close proximity to the Eastern coastline is situated

predominantly around traditionally industrial areas of Humber, Tyneside, and Teesside. Major transmission circuit heading south also run in close proximity to the Wash. Other major transmission routes are much further inland, typically 40-60km.

G.20 The areas of Humber, Tyneside and Teesside pose a number of challenges to further

connections, including:

Significant existing generation capacity exists here using most of the current transmission capacity;

The existing transmission network contains a lot of legacy 275kV assets which may need to be upgraded to 400kV to carry increased power flows;

As these are traditionally industrial areas, many of the transmission assets are built around the industrial and residential areas making access and expansion more challenging;

Being built around major river estuaries much of the transmission has to cross these, which adds additional cost and difficulties, as crossing towers or tunnels are required.

G.21 Given the scale of potential offshore growth from the East Coast of England (as illustrated

in Figure G1), the requirement for onshore transmission upgrade will be unavoidable. Together with development of suitable connection interface points, the significant offshore capacity will also bring changes to the power transmission flows throughout the transmission system.



G.22 A number of potential onshore reinforcements have been identified in order for the East

Coast of England to meet the required high power transfer levels. Figure G4 lists the potential reinforcements for the East Coast of England area. The reinforcements highlighted in grey may be avoided through the coordinated strategy. While these potential reinforcements have been identified, they may change as developments occur, such as consenting progress, changes in background or more efficient alternatives being found.

Figure G4: East Coast of England (Round 3) Zone – Potential Onshore Transmission System Reinforcements

Name Description

01 Walpole – Norwich circuit uprate

Reconductor the conductors on the Walpole to Norwich 400KV double circuit route to increase the thermal rating.

02 New Killingholme South substation

Establish a new 400KV double busbar substation near the crossing of the Keadby - Killingholme – Grimsby circuits.

03 New Killingholme South line

Establish a new 400KV double circuit from the new Killingholme South substation to West Burton

04 High Marnham – West Burton circuit) uprate

Reconductor the circuits from High Marnham to West Burton to achieve 3100MVA rating

05 Staythorpe – Ratcliffe circuit uprate

Reconductor the circuits from Staythorpe to Ratcliffe to achieve 3100MVA rating

07 High Marnham – Ratcliffe circuit uprate

Reconductor the circuits from High Marnham to Ratcliffe to achieve 3100MVA rating

08 Sundon – Wymondley circuit uprate

Reconductor the conductors on the Sundon to Wymondley 400KV double circuit route to increase the thermal rating.

09 Creyke Beck – Thornton circuit uprate

Reconductor the conductors on the Creyke Beck to Thornton 400KV double circuit route to increase the thermal rating

10 Fenwick T reconfigure

Reconfigure and uprate the circuits between Drax, Keadby and Thorpe Marsh to increase though flow capability

11 Chesterfield to High Marnham 400KV upgrade

Upgrade High Marnham, Chesterfield and associated circuits to 400KV operation

12 Rye House 400KV MSC

Install a 400KV 225MVAR shunt MSC at Rye House





15 Pelham 400KV MSC Install a 400KV 225MVAR shunt MSC at Pelham



18 New Creyke Beck – Drax circuit

Create a new 400KV double circuit between Creyke Beck and Drax

19 New substation Establish a new 400KV double busbar substation near Walpole

with connection to the existing substation

20 New substation Establish a new 400KV double busbar substation near

Lackenby

21 New Lackenby – Creyke Beck circuit

Create a new 400KV double circuit between Lackenby and Creyke Beck

22 North East ring 400KV upgrade

Upgrade the circuits and associated substations from Blyth to Lackenby to 400KV operation.



Network design results G.23 Figures G6 to G12 illustrate how the coordinated offshore network could be developed in

subsequent five year periods for each of the future scenarios and Tuned TEC. An overview of the radial (and radial plus) design under the Accelerated Growth scenario for comparison is also provided. Please note that the designs illustrated represent only one potential option for development, the actual development of the onshore and offshore transmission system can and may differ from that illustrated. The key associated with Figures G6 to G12 is illustrated in Figure G5 below:

FIGURE G5: Key for Figures G6 – G12



Figure G6: East Coast, Time Series, Slow Progression, Coordinated



Figure G7: East Coast, Time Series, Coordinated, Gone Green



Figure G8: East Coast, Time Series, Coordinated, Accelerated Growth



Figure G9: East Coast, Time Series, Radial, Accelerated Growth



Figure G10: East Coast, Time Series, Radial Plus, Accelerated Growth



Figure G11 provides an overview of the coordinated, radial and radial plus design strategies in 2030 against Accelerated Growth.

Figure G11: East Coast of England (Round 3) Zone – Indicative Network Design Overview 2030 Accelerated Growth (radial, radial plus and coordinated)



Figure G12: East Coast, Time Series, Coordinated, Tuned TEC



G.25 Figure G13 shows the asset volume (and associated capital cost) required for the coordinated strategy compared to the radial and radial plus strategies under Accelerated Growth in the East Coast of England.

Capital Expenditure Assessment G.26 By taking the staged transmission designs presented and applying unit costs (as detailed in

Appendix D) to the assets, the capital expenditure for both onshore and offshore assets may be provided, as illustrated by Figure G14. The capital expenditure assessment has been completed against the Accelerated Growth scenario. It is important to note that the capital expenditure assessment illustrates the cost within this single region. Section 8 provides the comparison of the design strategies on a national basis and the individual regional assessments should not be considered in isolation.

30


Figure G13: Asset volume and capital cost East Coast Accelerated Growth

East Coast Radial Coordinated Savings Radial plus Coordinated Savings

HVDC cables 4185 km 3174 km 1011 km 2875 km 3174 km -299 km

Offshore AC cables 484 km 750 km -266 km 661 km 750 km -89 km

Onshore AC lines (new)30 216 km 50 km 166 km 216 km 50 km 166 km

Offshore platforms 51 51 0 45 51 -6

Cable landing sites 17 9 8 11 9 2

Capital cost £ 17.5 bn £ 14.7 bn £ 2.8 bn £ 15.1 bn £ 14.7 bn £ 0.4 bn Capital cost based on 2010 prices.

Figure G14: East Coast of England (Round 3) Zone – Illustrative Network Design (Capital Expenditure Assessment (Onshore & Offshore – Accelerated Growth Scenario)



G.27 Figure G15 illustrates the capital expenditure differential between each of the key

component classifications between the radial and coordinated design. It can be seen that the coordinated design incurs additional cost in offshore AC cables to provide the interconnection between the platforms, but there is significant saving in HVDC assets and onshore reinforcements.

Figure G15: East Coast of England (Round 3) Zone – Illustrative Network Design (Capital Expenditure Assessment (Component Assessment – Accelerated Growth Scenario)

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Indicative Cable Route Statistics G.28 The following Figure G16 provides a sample of the cable route statistics outlined in G.16

Figure G16: Sample indicative cable route statistics - coordinated

Dogger Bank - A1

Data Values Percentage (%)

Offshore Cable Length 165.9 km n/a

Seabed Surface Sediment Hard (rock) Soft (other)

0 100%

Seabed Elevation (metres)

Shallow (0 - 60m) Deep (>60m)

96% 4%

Tidal Currents Mean Peak Spring Current (metres per second)

Slow (0 – 1.5 m/s) Fast (> 1.5 m/s)

100% 0%

Potential Cable and Pipeline Crossings

1 active cables 0 inactive cables 0 proposed cables

Environmental Designations

Dogger Bank pSAC

Military Practice Areas Southern MDA Flamborough Head D323 Southern MDA


Appendix H: Offshore and Associated Onshore Network Design – East Anglia 99

Appendix H: Offshore and Associated Onshore Network Design – East Anglia

Study Overview H.1 This Appendix provides a detailed analysis of the East Anglia region considered in the

study. H.2 The study sought to present illustrative designs which:






Facilitate the consents process. H.3 The study focused on the potential network development associated with the offshore wind

programmes of Round 3 and Scottish Territorial Water projects, together with possible additional European interconnection. It was additionally recognised, however, that other programmes, notably some Round 2 projects (and large marine energy schemes), might also usefully be incorporated into a coordinated network.

H.4 Taking account of all User requirements (offshore generation, onshore generation,

interconnectors), the study used a wide range of data relating to the potential development of the National Electricity Transmission System (NETS) in offshore waters, including applicable technology, a desktop assessment of constraints, illustrative offshore transmission design and onshore transmission coordination. It was supported by technical and economic analysis, which sets out options for reinforcing both the offshore and onshore transmission networks. It did not identify, however, project specific engineering designs. The coordinated designs identified in this study can be compared against a purely radial design (with individual point-to-point connections) and a radial plus approach (inter zonal connection) – the different design strategies are described further in section 3.

H.5 The designs shown in this study should not be considered as implying actual connection dates or connection routes for new infrastructure and they do not reflect the Transmission Owners (TOs) investment decisions regarding the development of their transmission area or imply any other parties‟ investment decisions. The designs present an illustrative coordinated transmission design approach using information available at the time of analysis (frozen June 2011) and have been developed to allow a comparison between the potential design options. The constraints presented in this study are those identified by high level (desktop based) analysis using the available information known at the time of analysis. The actual constraints, which would be applicable to the individual connection route, can and may be different following completion of further detailed site analysis. The actual contracted position and development of the offshore and onshore transmission system can, and may, differ from that illustrated in the study. The study represents a view of the future network requirements and direction for potential development, the actual network design will be developed in accordance with user requirements.

H.6 Whilst there are many areas under discussion with respect to delivery of a coordinated

offshore transmission network, the objective of the study was to illustrate what such a design could look like. Consideration of how such a network might be delivered is outside of the project scope. The study does not consider the regulatory mechanism, which will be applicable for delivery of the designs or the specific impact on individual transmission connections.



Scenario Overview - Generation Background H.7 Figure H1 presents the three scenarios and the sensitivity, which are considered for the

Round 3 projects from the East Anglia. The scenarios facilitate a range of installed capacity trajectories to be considered over the study period, as described in section 3.

Figure H1: East Anglia (Round 3) Zone – Installed Generation Capacity Comparison (By Future Scenarios)

Constraints analysis H.8 To develop this design the known offshore conditions have been considered. An overview

of the identified offshore constraint areas are shown in the Figure H2. H.9 The main exclusions in the region are from marine aggregate leases and unsuitable

seabed sediments, with further constraints from environmental designation, Marine Conservation Zones and existing wind farm sites.

East Anglia

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Figure H2: East Anglia Offshore Constraints



Illustrative Offshore Transmission Design H.10 To develop the transmission designs an understanding of the location and size of offshore

developments is required. Using available knowledge the position of the offshore AC collector platforms/substation has been estimated as per Figure H2. Each AC collector platform is set to allow 600 MW of turbines to be connected and include the relevant high voltage switchgear and step-up transformers.

H.11 Staging of the transmission infrastructure delivery has been accomplished by planning to the maximum potential capacity of the zone and working backwards to identify the key delivery stages and build progression. Design adjustments have been made to ensure logical development stages and to minimise possible asset stranding. The design stages are checked against each of the scenarios to ensure suitable optimisation.

H.12 Findings from a generic exercise in cable and platform position optimisation as shown in

Appendix B has been used in developing the designs shown here. H.13 When considering the designs consideration has been given to possible interconnections

with the rest of Europe beyond those, which are currently built, or under construction.

Illustrative Offshore Cable Route Statistics H.14 Illustrative offshore cable route statistics give the length of routes, seabed sediments along

the routes, potential cable crossing and other constraints on the routes. The information was used in assessing the routing suitability cable laying/installation methods and costs. A sample of the statistics is included in H.26.

Onshore Main Interconnected Transmission System Considerations H.15 There are only a few substations in East Anglia that are feasibly close to the sea without

extensive new onshore transmission being required, as illustrated in Figure H3.

Figure H3: East Anglia (Round 3) Zone – Onshore Transmission System



H.16 As with any physical change to the transmission network a number of factors must be considered such as the available space, planning permissions and electrical stresses. While a number of existing substations are reviewed there is always the possibility of new connection substation being constructed if deemed the most suitable option.

H.17 Around East Anglia the transmission system consists of a 400kV double circuit ring joining

from Walpole at the Wash to Norwich, Bramford and back towards London at Pelham and Rayleigh. A twin double circuit spur connects the nuclear generation on the coast at Sizewell, which is the closest substation to the sea around East Anglia. While appearing attractive for a connection to new offshore wind, a new nuclear generator is currently planned for construction at Sizewell, which would fully utilise all of the circuit capacity connecting that substation.

H.18 To accommodate the proposed large capacities of generation in East Anglia the circuit and

substation capabilities need to be as high as is possible. To achieve this some uprating of the conductors and substations will be required. As power flow is predominantly toward London, an additional circuit route to the south of the region feeding into London is required. The transmission works are also partially required to help support the proposed new nuclear generation at Sizewell.

H.19 Following analysis, a number of possible onshore reinforcements have been identified for

the coordinated solution, detailed in Figure H4. While reinforcements have been identified, these may change due to new information coming available on consenting, changes in background or more efficient alternatives being found.

Figure H4: East Anglia (Round 3) Zone – Possible Onshore Transmission System Reinforcements

Ref. Name Description

01 Bramford Extend and reconfigure Bramford 400KV substation with

provision of up to four new connection bays

02 Norwich Extend and reconfigure Norwich 400KV substation with

provision for up to three new connection bays

03 New East Anglia substation

Create a new 400KV substation with a new double circuit Tee connected into the existing Norwich – Bramford circuit

04 Bramford - Twinstead

Establish a new 400KV circuit route between Bramford and Twinstead Tee

Reconfigure and reconductor the circuits between Bramford, Pelham and Braintree for higher ratings

Network design results H.20 Figures H6 to H12 illustrate how the coordinated offshore network could be developed in

subsequent five year periods for each of the future scenarios and Tuned TEC. An overview of the radial (and radial plus) design under the Accelerated Growth scenario for comparison is also provided. The key associated with Figures H6 to H12 is illustrated in Figure H5:



FIGURE H5: Key for Figures H6 to H12



Figure H6: East Anglia, Time Series, Slow Progression, Coordinated



Figure H7: East Anglia, Time Series, Coordinated, Gone Green



Figure H8: East Anglia, Time Series, Coordinated, Accelerated Growth



Figure H9: East Anglia, Time Series, Radial, Accelerated Growth



Figure H10: East Anglia, Time Series, Radial Plus, Accelerated Growth



Figure H11 provides an overview of the coordinated and radial design strategies in 2030 against Accelerated Growth.

Figure H11: East Anglia (Round 3) Zone – Indicative Network Design Overview 2030 Accelerated Growth (radial, radial plus and coordinated)



Figure H12: East Anglia, Time Series, Coordinated, Tuned TEC



H.22 Figure H13 shows the asset volume (and associated capital cost) required for the coordinated strategy compared to the radial and radial plus strategies under Accelerated Growth in East Anglia. It is important to note that the capital cost and asset requirements illustrated are for within this single region. Section 8 provides the comparison of the design strategies on a national basis and the individual regional assessments should not be considered in isolation.

Capital Expenditure Assessment H.23 By taking the staged transmission designs presented and applying unit costs (as detailed in

Appendix D) to the assets, the capital expenditure for both onshore and offshore assets may be provided, as illustrated by Figure H14. The capital expenditure assessment has been completed against the Accelerated Growth scenario.

31


Figure H13: Asset volume and capital cost East Coast Accelerated Growth

East Anglia Radial Coordinated Savings Radial plus Coordinated Savings

HVDC cables 527 km 396 km 131 km 341 km 396 km -55 km

Offshore AC cables 211 km 471 km -260 km 423 km 471 km -48 km

Onshore AC lines (new)31 76 km 76 km 0 76 km 76 km 0

Offshore platforms 17 16 1 15 16 -1

Cable landing sites 7 7 0 6 7 -1

Capital cost £ 4.7 bn £ 4.5 bn £ 0.2 bn £ 4.1 bn £ 4.5 bn £ -0.4 bn Capital cost based on 2010 prices.



H.24 Figure H15 shows the capital differential between each of the key component

classifications between the radial and coordinated design. It can be seen that the coordinated design incurs additional cost in offshore AC cables to provide the interconnection between the platforms, but there is a saving in HVDC assets and onshore reinforcements. The potential coordinated capital savings for East Anglia, in particular against radial plus, are not as large as for some of the other areas due to the additional cost of interconnecting the network and 1GW interconnection with the East Coast of England.

H.25 The coordinated East Anglia design interacts directly with the East Coast of England

design, through linking between the regions. Therefore, whilst the overall saving specifically within the region may be minimal (and indeed against the radial plus design the East Anglia coordinated design taken in isolation is more expensive), as part of a fully coordinated network this region contributes significantly to the benefits detailed in section 8 of this report.

Figure H14: East Anglia (Round 3) Zone – Illustrative Network Design (Capital Expenditure Assessment (Onshore & Offshore – Accelerated Growth Scenario))

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Indicative Cable Route Statistics H.26 The following Figure H16 provides a sample of the cable route statistics outlined in H.14

Figure H16: Sample of indicative cable route statistics - coordinated

Bramford - DC1




0 100%



100% 0%


Slow (0 – 1.5 m/s) Fast (> 1.5 m/s)

68% 32%




Orfordness-Havergate NNR Deben Estuary RAMSAR, SPA & SSSI Alde-Ore Estuary RAMSAR, SPA & SSSI Orfordness-Shingle Street SAC Alde-Ore & Butley Estuaries SAC Suffolk Coast & Heaths AONB Suffolk Heritage Coast

Figure H15: East Anglia (Round 3) Zone – Illustrative Network Design (Capital Expenditure Assessment (Component Assessment – Accelerated Growth Scenario)


Appendix I: Offshore and Associated Onshore Network Design – Southern 115

Appendix I: Offshore and Associated Onshore Network Design – Southern

Study Overview I.1 This Appendix provides a detailed analysis of the Southern region considered in the study. I.2 The study sought to present illustrative designs which:





Facilitate flexible network development;

Facilitate the consents process. I.3 The study focused on the potential network development associated with the offshore wind


I.4 Taking account of all User requirements (offshore generation, onshore generation,


I.5 The designs shown in this study should not be considered as implying actual connection dates or connection routes for new infrastructure and they do not reflect the Transmission Owners (TOs) investment decisions regarding the development of their transmission area or imply any other parties‟ investment decisions. The designs present an illustrative coordinated transmission design approach using information available at the time of analysis (frozen June 2011) and have been developed to allow a comparison between the potential design options. The constraints presented in this study are those identified by high level (desktop based) analysis using the available information known at the time of analysis. The actual constraints, which would be applicable to the individual connection route, can and may be different following completion of further detailed site analysis. The actual contracted position and development of the offshore and onshore transmission system can, and may, differ from that illustrated in the study. The study represents a view of the future network requirements and direction for potential development, the actual network design will be developed in accordance with user requirements.

I.6 Whilst there are many areas under discussion with respect to delivery of a coordinated


Scenario Overview - Generation Background I.7 Figure I1 presents the three scenarios and the sensitivity, which are considered for the

Round 3 projects from the southern region. The scenarios facilitate a range of installed capacity trajectories to be considered over the study period, as described in section 3.



Figure I1: Southern (Round 3) Zone – Installed Generation Capacity Comparison (By Future Scenarios)

Constraints analysis I.8 To develop this design the known offshore conditions have been considered. An overview

of the identified offshore constraint areas are shown in the Figure I2. I.9 Off the South Coast of England the main exclusions are marine aggregate leases and

unsuitable sediments, as well as constraints due to environmental designations.

South Coast Installed Capacity Scenarios

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Figure I2: Southern Offshore Constraints



Potential Offshore Transmission Design I.10 To develop the transmission designs an understanding of the location and size of offshore

developments is required. The positions of the offshore AC collector platforms/substation have been estimated as illustrated per Figure I2. Each AC collector platform has been set to allow 400MW of turbines to be connected and include the relevant high voltage switchgear and step-up transformers.

I.11 Staging of the transmission infrastructure delivery has been accomplished by planning to

the maximum potential capacity of the zone and working back to identify the key delivery stages and build progression. Design adjustments have been made to ensure logical development stages and to minimise possible asset stranding. The design stages are checked against each of the scenarios and sensitivity to ensure suitable optimisation.

I.12 Findings from a generic exercise in cable and platform position optimisation as shown in

Appendix B has been used in developing the designs shown here. I.13 When considering the designs, consideration has been given to possible interconnections

with the rest of Europe beyond those that are currently built or under construction. Illustrative Offshore Cable Route Statistics I.14 Illustrative offshore cable route statistics give the length of routes, seabed sediments along

the routes, potential cable crossing and other constraints on the routes. The information was used in assessing the routing suitability, cable laying/installation methods and costs. A sample of the statistics is included in I.22.

Onshore Connection and Main Interconnected Transmission System Considerations

I.15 The 400kV transmission system loosely follows around the south coast around to the

Bristol Channel with a number of substations along the way connecting high volumes of demand and a range of generators (as illustrated in Figure I3). As the transmission system is somewhat sparse, care must be taken not to cause overloads with new connections when outages may occur on the system.

Figure I3: Southern (Round 3) Zone – Onshore Transmission System

Network design results I.16 The three Round 3 projects of Bristol Channel, West Isle of Wight and Rampion are of

suitable size that may be accommodated at existing substation sites with some limited transmission works. With the spacing, proximity to shore, individual project sizes and no need to connect to more than one onshore substation there is no clear advantage to coordinating the projects. Therefore, the optimum design option for the three projects



appears to be a direct radial approach. The projects are also close enough to shore to not require the use of HVDC transmission so enhanced DC technology would offer no benefit. As a result, only the design associated with the radial strategy has been prepared.

I.17 Following analysis, a number of possible onshore reinforcements have been identified,

detailed in Figure I4. While reinforcements have been identified, these may change due to new information coming available on consenting, changes in background or more efficient alternatives being found.

Figure I4: Southern (Round 3) Zone – Illustrative Onshore Transmission System Reinforcements


01 Alverdiscot New double busbar 400KV substation connected to the existing

Alverdiscot circuits.

02 Mannington Extend Mannington 400KV substation with new connection bays.

03 Southern circuits upgrade

Upgrade the circuits around Mannington, Fawley, Botley Wood and Nursling to improve their capacity.

04 Bolney Extend Bolney 400KV substation to provide new connection bays.

I.18 Figure I6 illustrates how the offshore network could be developed in subsequent five year

periods for Accelerated Growth. The key associated with Figures I6 is illustrated in Figure I5.

I.19 Figure I7 illustrates the overview of the Southern network design in 2030 under the

Accelerated Growth scenario.

FIGURE I5: Key for Figure I6



Figure I6: Southern, Time Series, Accelerated Growth



Figure I7: Southern, Overview, 2030, Accelerated Growth



I.20 Figure I8 shows the asset volume (and associated capital cost) required for Southern region under Accelerated Growth.

Capital Expenditure Assessment I.21 By taking the staged transmission designs presented and applying unit costs (as detailed in

Appendix D) to the assets, the capital expenditure for both onshore and offshore assets may be provided, as illustrated by Figure I9. The capital expenditure assessment has been completed against the Accelerated Growth scenario.

Indicative Cable Route Statistics I.22 The following Figure I10 provides a sample of the cable route statistics outlined in I.14

32


Figure I8: Asset volume and capital cost Southern Accelerated Growth

Southern Radial

HVDC cables 0

Offshore AC cables 253 km

Onshore AC lines (new)32 0

Offshore platforms 7

Cable landing sites 8

Capital cost £ 0.9 bn Capital cost based on 2010 prices.

Figure I9: Southern (Round 3) Zone – Illustrative Network Design (Capital Expenditure Assessment (Onshore & Offshore – Accelerated Growth Scenario))



Figure I10: Sample indicative cable route statistics

Indicative AC2




0% 100%



100% 0%


Slow (0 – 1.5 m/s) Fast (> 1.5 m/s)

100% 0%


3 active cables 3 inactive cables 1 proposed cable

n/a


Hartland (Devon) Heritage Coast Mermaid‟s Pool to Rowden Gut SSSI

n/a

Military Practice Areas No MoD practice areas Low priority military low flying area

n/a


Appendix J: Offshore and Associated Onshore Network Design – Irish Sea 124

Appendix J: Offshore and Associated Onshore Network Design – Irish Sea

Study Overview J.1 This Appendix provides a detailed analysis of the Irish Sea region considered in the study. J.2 The study sought to present illustrative designs which:






Facilitate the consents process. J.3 The study focused on the potential network development associated with the offshore wind


J.4 Taking account of all User requirements (offshore generation, onshore generation,


J.5 The designs shown in this study should not be considered as implying actual connection dates or connection routes for new infrastructure and they do not reflect the Transmission Owners (TOs) investment decisions regarding the development of their transmission area or imply any other parties‟ investment decisions. The designs present an illustrative coordinated transmission design approach using information available at the time of analysis (frozen June 2011) and have been developed to allow a comparison between the potential design options. The constraints presented in this study are those identified by high level (desktop based) analysis using the available information known at the time of analysis. The actual constraints, which would be applicable to the individual connection route, can and may be different following completion of further detailed site analysis. The actual contracted position and development of the offshore and onshore transmission system can, and may, differ from that illustrated in the study. The study represents a view of the future network requirements and direction for potential development, the actual network design will be developed in accordance with user requirements.

J.6 Whilst there are many areas under discussion with respect to delivery of a coordinated


Scenario Overview - Generation Background J.7 Figure J1 presents the three scenarios and the sensitivity, which are considered for the

Round 3 projects from the Irish Sea. The scenarios facilitate a range of installed capacity trajectories to be considered over the study period, as described in section 3.



Figure J1: Irish Sea (Round 3) Zone – Installed Generation Capacity Comparison (By Future Scenarios)

J.8 In additional to the possible growth in generation it is conceivable that additional

interconnection with Ireland may develop. The position of the Irish Sea development is close to possible new offshore generation from Ireland so a possible interconnection with the Irish projects or the Irish mainland has been considered in the size 500MW – 1000MW.

Constraints analysis J.9 To develop this design the known offshore conditions have been considered. An overview

of the identified offshore constraint areas are shown in the Figure J2. J.10 In the Irish Sea, the main exclusions are marine aggregate leases between the East

boundary of the Irish Sea site and the coast and unsuitable sediments south of the Irish Sea site.

J.11 As for constraints, there are wind farm sites, environmental designations and Marine

Conservation Zones that result in a high levels constraint between the Irish Sea site and the coast.

Irish Sea Round 3 Zone

0

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/16

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/31

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SP

GG

AG

TTEC



Figure J2: Irish Sea Offshore Constraints



Illustrative Offshore Transmission Design J.12 To develop the transmission designs, an understanding of the location and size of offshore

developments is required. The position of the offshore AC collector/substation platforms has been estimated as illustrated by Figure J2. Each AC collector platform is set to allow 500 MW of turbines to be connected and inclusive of the relevant high voltage switchgear and step-up transformers.

J.13 Staging of the transmission infrastructure delivery has been accomplished by planning to the

maximum potential capacity of the zone and working backwards to identify the key delivery stages and build progression. Design adjustments have been made to ensure logical development stages and to minimise possible asset stranding. The design stages are checked against each of the scenarios to ensure suitable optimisation.

J.14 Findings from a generic exercise in cable and platform position optimisation as shown in

Appendix B has been used in developing the designs shown here. J.15 When considering the transmission system designs, consideration has been given to possible

interconnections with Ireland and the Isle of Man beyond those that are currently built or under construction.

Illustrative Offshore Cable Route Statistics J.16 Illustrative offshore cable route statistics give the length of routes, seabed sediments along

the routes, potential cable crossing and other constraints on the routes. The information was used in assessing the routing suitability cable laying/installation methods and costs. A sample of the statistics is included in J.28.


J.17 There are several existing high voltage substations close to the Irish Sea which may

provide connection opportunities, as illustrated in Figure J3.

Figure J3: Irish Sea (Round 3) Zone – Onshore Transmission System



J.18 As with any physical change to the transmission network a number of factors must be considered such as the available space, planning permissions and electrical stresses. While a number of existing substations are reviewed there is always the possibility of constructing a new connection substation if deemed the most suitable option.

J.19 The transmission system around the North West consists of demand around Merseyside

and Manchester fed by 275kV network and some larger generators spread around the area. HVDC links from Scotland and Ireland are planned to connect into Deeside substation. North Wales has sparse transmission, a small amount of demand and significant generation. The current nuclear generator at Wylfa is expected to be renewed with a new nuclear power station sometime after 2016.

J.20 With the potential growth in generation capacity from Irish Sea wind, other wind projects

and the Wylfa nuclear generation, the transmission capacity from Anglesey back to the wider system will be insufficient. The existing circuits will need supporting with additional capacity to ensure a secure connection.

J.21 Following analysis, a number of potential onshore reinforcements have been identified,

detailed in Figure J4. The reinforcements highlighted in grey may be avoided through the coordinated strategy. While these potential reinforcements have been identified, they may change as developments occur, such as consenting progress, changes in background or more efficient alternatives being found.

Figure J4: Irish Sea (Round 3) Zone – Potential Onshore Transmission System Reinforcements

Ref Name Description

01 Establish second Pentir – Trawsfynydd 400 kV circuit

Rationalise existing SP Manweb owned 132 kV circuit, strung between Trawsfynydd and tower 4ZC70, for operation at 400 kV by reconductoring the circuit using 2x700 mm2 conductor

Establishing a GSP at Bryncir to secure the demand at Four Crosses following SP Manweb route rationalised to 400 kV

Reconfiguration and extension of Pentir 400 kV substation

Installation of approximately 6km of 400 kV cable to cross the Glaslyn Estuary

02 New 400 kV, Pentir – Wylfa circuit

40km, 3x700 mm2 double circuit

Extension of Pentir 400 kV substation

Modifications to Wylfa substation

03 Deeside – Trawsfynydd series compensation 120 Mvar series compensation

04 Deeside – Pentir series compensation 120 Mvar series compensation

05 Reconductor Trawsfynydd – Treuddyn 2 x 85 km of GZTACSR conductor

07 WYLF-PEMB 2 GW HVDC LINK 120 km HVDC link from Wylfa to Pembroke

Substation extension at Wylfa and Pembroke

08 New 400 kV, Pentir – Wylfa single circuit 40km, 3x700 mm2 single circuit

09 New 400 KV Pentir – Deeside double circuit

New 79 km 400KV double circuit between Pentir and Deeside substation with GZTACSR conductor

10 Hot wire Treuddyn T - Legacy Operate Treuddyn T – Legacy circuit at 900C

11 New 400 KV Deeside – Willington East double circuit

New 400 KV double circuit between Deeside and Willington East substation.

12 New 400 KV Deeside – Cellarhead double circuit

New 400 KV double circuit between Deeside and Cellarhead substation.

Reconductor Cellarhead – Drakelow double circuit

Reconductor Ironbridge – Feckenham 400 KV single circuit

13 New 400 KV Deeside – Walham double circuit

New 400 KV double circuit between Deeside and Walham substation.

14 Penwortham – Frodsham upgrade to 400KV

Upgrade Washway Farm, Kirkby, Rainhill and Fiddlers Ferry substations to 400KV operation

Uprate OHL for 400KV operation



Network design results J.22 Figures J6 to J11 illustrate how the coordinated offshore network could be developed in

subsequent five year periods for each of the future scenarios and Tuned TEC. Finally, an overview of the radial design under the Accelerated Growth scenario is provided for comparison. The key associated with Figures J6 to J11 is illustrated in Figure J5:

Radial Plus Design J.23 The availability of larger offshore HVDC converters for consideration under a radial plus

design does not change the radial design of the Irish Sea region as the majority of the capacity is connecting using direct AC cabling. The only offshore HVDC converter used in the radial design does not need to be larger than 1 GW. Therefore, for radial plus no additional maps have been prepared for comparison in the Irish Sea region.

Figure J5: Key for Figures J6 – J11



Figure J6: Irish Sea, Time Series, Slow Progression, Coordinated



Figure J7: Irish Sea, Time Series, Gone Green, Coordinated



Figure J8: Irish Sea, Time Series, Accelerated Growth, Coordinated



Figure J9: Irish Sea, Time Series, Radial, Accelerated Growth



Comparison of Radial and Coordinated Figure J10 provides an overview of the coordinated and radial design strategies in 2030 against Accelerated Growth.

Figure J10: Irish Sea (Round 3) Zone – Indicative Network Design Overview 2030 Accelerated Growth (radial and coordinated)



Figure J11: Irish Sea, Time Series, Coordinated, Tuned TEC



J.25 Figure J12 shows the asset volume (and associated capital cost) required for the coordinated strategy compared to the radial strategy under Accelerated Growth in Irish Sea.

Capital Expenditure Assessment J.26 By taking the staged transmission designs presented and applying unit costs (as detailed in

Appendix D) to the assets the capital expenditure for both onshore and offshore assets may be provided, as illustrated by Figure J13. The capital expenditure assessment has been completed against the Accelerated Growth scenario. It is important to note that the capital cost expenditure assessment illustrates the cost within this single region, to understand the impact of a coordinated versus radial/radial plus solution it is necessary to take a holistic view, including cross-regional impact across the network. Section 8 provides the comparison of the design strategies on a national basis and the individual regional assessments should not be considered in isolation.

33


Figure J12: Asset volume and capital cost Irish Sea Accelerated Growth

Irish Sea Radial Coordinated Savings

HVDC cables 489 km 527 km -38 km

Offshore AC cables 503 km 365 km 138 km

Onshore AC lines (new)33 80 km 0 80 km

Offshore platforms 9 10 -1

Cable landing sites 10 4 6

Capital cost £ 3.3 bn £ 2.7 bn £ 0.6 bn Capital cost based on 2010 prices.

Figure J13: Irish Sea (Round 3) Zone – Illustrative Network Design (Capital Expenditure Assessment (Onshore & Offshore – Accelerated Growth Scenario))



J.27 Figure J14 illustrates the capital expenditure differential between each of the key component classifications between the radial and coordinated design. Whilst the coordinated design incurs additional cost in offshore HVDC assets there is significant saving in AC cabling and onshore reinforcements.

Indicative Cable Route Statistics J.28 The following Figure J15 provides a sample of the cable route statistics outlined in J.16

Figure J15: Sample of indicative cable route statistics - coordinated

Pembroke



Seabed Surface Sediment Hard (rock) Soft (other) No Data

<1% >99%



53% 47%

Seabed surface features Bathymetry becomes much deeper in the seabed 120km from starting point of the cable at zone 9.

n/a


Slow (0 – 1.5 m/s) Fast (> 1.5 m/s)

71% 29%



n/a

Environmental Irish Sea pMCZ4 n/a

Figure J14: Irish Sea (Round 3) Zone – Illustrative Network Design (Capital Expenditure Assessment (Component Assessment – Accelerated Growth Scenario)



Designations Castlemartin Coast SPA Pembrokeshire Marine SAC

Military Practice Areas Castlemartin Firing Range Aberporth Firing Range

n/a


Appendix K: Offshore and Associated Onshore Network Design – Scotland 139

Appendix K: Offshore and Associated Onshore Network Design – Scotland Study Overview K.1 This Appendix provides a detailed analysis of Scotland considered in the study. K.2 The study sought to present illustrative designs which:






Facilitate the consents process. K.3 The study focused on the potential network development associated with the offshore wind

programmes of Round 3 and Scottish Territorial Water projects, together with possible additional European interconnection. It was additionally recognised, however, that other programmes, notably some Round 2 projects (and large marine energy schemes), might also usefully be incorporated into a coordinated network. For this study, the Scottish Territorial Water (STW) projects of Beatrice, Inch Cape and Neart na Gaoithe were not included in the coordinated design (and as such have been illustrated as radial connections only).

K.4 Taking account of all User requirements (offshore generation, onshore generation,

interconnectors), the study used a wide range of data relating to the potential development of the National Electricity Transmission System (NETS) in offshore waters, including applicable technology, a desktop assessment of constraints, illustrative offshore transmission design and onshore transmission coordination. It was supported by technical and economic analysis, which sets out options for reinforcing both the offshore and onshore transmission networks. It did not identify, however, project specific engineering designs. The coordinated designs identified in this study contain both integrated and radial elements as appropriate to optimise the outcome. This can be compared against a purely radial design (with individual point-to-point connections) and a radial plus approach (inter zonal connection) – the different design strategies are described further in section 3.

K.5 The designs shown in this study should not be considered as implying actual connection dates or connection routes for new infrastructure and they do not reflect the Transmission Owners (TOs) investment decisions regarding the development of their transmission area or imply any other parties‟ investment decisions. The designs present an illustrative coordinated transmission design approach using information available at the time of analysis (frozen June 2011) and have been developed to allow a comparison between the potential design options. The constraints presented in this study are those identified by high level (desktop based) analysis using the available information known at the time of analysis. The actual constraints, which would be applicable to the individual connection route, can and may be different following completion of further detailed site analysis. The actual contracted position and development of the offshore and onshore transmission system can, and may, differ from that illustrated in the study. The study represents a view of the future network requirements and direction for potential development, the actual network design will be developed in accordance with user requirements.

K.6 Whilst there are many areas under discussion with respect to delivery of a coordinated

offshore transmission network, the objective of the study was to illustrate what such a design could look like. Consideration of how such a network might be delivered is outside of the project scope. The study does not consider the regulatory mechanism which will be applicable for delivery of the designs or the specific impact on individual transmission connections.



Scenario Overview - Generation Background K.7 Figure K1 presents the three scenarios and the sensitivity which are considered for the

Round 3 and STW projects from Scotland. The scenarios facilitate a range of installed capacity trajectories to be considered over the study period, as described in section 3.

Figure K1: Scotland – Installed Generation Capacity Comparison (By Future Scenarios)

Constraints analysis K.8 To develop this design the known offshore conditions have been considered. An overview

of the identified offshore constraint areas are shown in the Figure K2. K.9 There are high constraints due to navigations, environmental designations and Special

Areas of Conservation (SACs).

Scottish Capacity Scenarios

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Figure K2: Scotland, Offshore Constraints



Illustrative Offshore Transmission Design K.10 To develop the transmission designs an understanding of the location and size of offshore

developments is required. Using available knowledge the positions of the offshore AC collector platforms/substation has been estimated as illustrated in Figure K2. Each AC collector platform has been set to allow 400 MW of turbines to be connected and include the relevant high voltage switchgear and step-up transformers.

K.11 Staging of the transmission infrastructure delivery has been accomplished by planning to

the maximum potential capacity of the zone and working back to identify the key delivery stages and build progression. Design adjustments have been made to ensure logical development stages and to minimise possible asset stranding. The design stages are checked against each of the scenarios to ensure suitable optimisation.

K.12 Findings from a generic exercise in cable and platform position optimisation as shown in

Appendix B has been used in developing the designs shown here. K.13 When considering the designs, consideration has been given to possible interconnections

with the rest of Europe beyond those that are currently built or under construction. For this study, the Scottish Territorial Water (STW) projects of Beatrice, Inch Cape and Neart na Gaoithe were not included in the coordinated design (and as such have been illustrated as radial connections only).

Illustrative Offshore Cable Route Statistics K.14 Illustrative offshore cable route statistics give the length of routes, seabed sediments along

the routes, potential cable crossing and other constraints on the routes. The information was used in assessing the routing suitability cable laying/installation methods and costs. A sample of the statistics is included in K.25.


K.15 Some of the existing substations may offer opportunity for connection around the Moray

Firth and Firth of Forth development zones, as illustrated in Figure K3.



Figure K3: Scotland Zone – Onshore Transmission System

K.16 The Scottish onshore transmission system is owned and developed by two separate

Transmission Owners, Scottish Hydro Electricity Transmission and Scottish Power Transmission covering north and south Scotland respectively. Over the last few years there has been significant growth in onshore renewable generation connecting to the Scottish transmission system with more still to connect. This growth has driven major development of the transmission system with upgrades to existing transmission assets, new connection substations and new transmission routes.

K.17 Several GW of new offshore generation is proposed all around the Scottish coastline from

the west coast to Shetland to Firth of Forth. The existing transmission network is limited in the new connections that can be accepted and future connections, particularly large offshore connections will require new infrastructure.

K.18 The extensive growth of new renewable generation in Scotland has led to major

development of new and upgraded transmission. The Scottish Transmission Owners are



responsible for the planning and construction of the transmission infrastructure in Scotland. Figure K4 lists possible reinforcements for Scotland.

Figure K4: Scotland – Possible Onshore Transmission System Reinforcements


01 Beauly – Denny rebuild

Upgrade the 132KV circuits from Beauly to Denny to 400KV operation with associated substations at Beauly and Denny

02 Knocknagael substation

Establish a new 275/132KV substation at Knocknagael

03 Beauly – Kintore re-conductor

Replace the conductors on the Beauly to Kintore circuits with higher rated ones

04 Beauly – Dounreay 2

nd circuit

Put up a second 275KV circuit between Beauly and Dounreay on the existing towers

Rebuild the Dounreay 275KV substation

05 East Coast of Scotland upgrade

Upgrade the circuits and connections from Blackhillock to Kincardine to 400KV operation

07 Strathaven transformer

Installation of a new 400/275KV transformer at Strathaven

08 Strathaven – Smeaton upgrade

Upgrade the circuits between Strathaven and Smeaton from 275KV to 400KV operation including Wishaw substation

09 Denny – Wishaw upgrade

Upgrade the circuits from Denny to Wishat from 275KV to 400KV operation

Network design results K.19 Figures K6 to K11 illustrate how the coordinated offshore network could be developed in

subsequent five year periods for each of the future scenarios and Tuned TEC. It also provides an overview of the radial (and radial plus) design under the Accelerated Growth scenario for comparison. The key associated with Figures K6 to K11 is illustrated in Figure K5:

Radial Plus Design K.20 The availability of larger offshore HVDC converters for consideration under a radial plus

design does not change the radial design of the Scotland region as the majority of the capacity is connecting using direct AC cabling. The only offshore HVDC converter used in the radial design does not need to be larger than 1 GW. Therefore, for radial plus no additional maps have been prepared for comparison in Scotland.

FIGURE K5: Key for Figures K6 to K11



Figure K6: Scotland, Time Series, Slow Progression, Coordinated



Figure K7: Scotland, Time Series, Gone Green, Coordinated



Figure K8: Scotland, Time Series, Accelerated Growth, Coordinated



Figure K9: Scotland, Time Series, Accelerated Growth, Radial



Comparison of Radial and Coordinated K.21 Figure K10 provides an overview of the coordinated and radial design strategies in 2030 against Accelerated Growth.

Figure K10: Scotland Zone – Indicative Network Design Overview 2030 Accelerated Growth (radial and coordinated)



Figure K11: Scotland, Time Series, Coordinated, Tuned TEC



K.22 Figure K12 shows the asset volume (and associated capital cost) required for the coordinated strategy compared to the radial and radial plus strategies under Accelerated Growth in Scotland34

.

Capital Expenditure Assessment K.23 By taking the staged transmission designs presented and applying unit costs (as detailed in

Appendix D) to the assets, the capital expenditure for both onshore and offshore assets may be provided, as illustrated by Figure K13. The full extent of wider onshore costs have not been included in this region as the requirements are joined with many of the other Scottish generation projects – however, even without this there are clear cost benefits associated with the coordinated solution. The capital expenditure assessment has been completed against the Accelerated Growth scenario. It is important to note that the capital cost saving illustrates the cost within this single region. Section 8 provides the comparison of the design strategies on a national basis and the individual regional assessments should not be considered in isolation.

34

For this study, the Scottish Territorial Water (STW) projects of Beatrice, Inch Cape and Neart na Gaoithe were not included in the coordinated design and therefore are not included in the asset volume and cable route assessment. Some benefits of coordination of these projects is likely, but has not been captured in this study. 35


Figure K12: Asset volume and capital cost Scotland Accelerated Growth

Scotland Radial Coordinated Savings

HVDC cables 1440 km 1119 km 321 km

Offshore AC cables 108 km 514 km -406 km

Onshore AC lines (new)35 75 km 0 75 km

Offshore platforms 28 26 2

Cable landing sites 23 15 8

Capital cost £ 8.3 bn £ 6.3 bn £ 2 bn Capital cost based on 2010 prices.

Figure K13: Scotland – Illustrative Network Design (Capital Expenditure Assessment (Onshore & Offshore – Accelerated Growth Scenario))



K.24 Figure K14 illustrates the capital expenditure differential between each of the key

component classifications between the radial and coordinated design. It can be seen that the coordinated design incurs additional cost in offshore AC cables to provide the interconnection between the platforms, but there is significant saving in HVDC assets.

Indicative Cable Route Statistics K.25 The following Figure K15 provides a sample of the cable route statistics outlined in K.14

Figure K15: Sample of indicative cable route statistics - coordinated

1a to Teal



Seabed Surface Sediment Hard (rock) Soft (other) No Data

0% 100%



>99% <1%


Slow (0 – 1.5 m/s) Fast (> 1.5 m/s)

100% 0%


None

n/a


No Environmental Designations n/a

Military Practice Areas Low priority military low flying area n/a

Figure K14: Scotland – Illustrative Network Design (Capital Expenditure Assessment (Component Assessment – Accelerated Growth Scenario)


Appendix L: Assumptions

153

Appendix L: Assumptions L.1 This Appendix captures the assumptions used within the study. NETS SQSS L.2 The following NETS SQSS assumptions (as detailed in section 3.18 of the report) were

used for the offshore element of the study:

Radial elements:

Up to 1800 MW can be connected by a single circuit;

Radial connections rated at 100% generation capacity;

Loss of single connection circuit may cause loss of all generation on connection.

Interconnected elements:

Links can be greater than 1800 MW provided alternate power paths are available to redistribute power following loss;

Local connections based on 100% generation capacity, other elements are based on scaled generation as onshore;

Up to 1800 MW can be lost for a cable loss;

Wider infrastructure requirements based on scaled generation, as onshore. Generic cable and platform position optimisation L.3 Findings from a generic exercise in cable and platform position optimisation (as shown in

Appendix B) have been used in developing the designs. Technology L.4 In considering technology assumptions, the availability, development and cost of

technology have been considered. The technology assumptions from Appendix 4 of ODIS 2010

36 were used in this study.

L.5 A sample of the technology assumptions (as detailed in section 3.22) are as follows:

Only technology that is already available or is reasonably expected to be available within the next 3-5 years with appropriate supplier engagement has been considered.

DC Technology assumptions:

Offshore HVDC links will be Voltage Sourced Converter (VSC);

HVDC converters up to 2 GW capacity will be available by 2017;

Multi-terminal VSC links with off-line DC switching will be available by 2017.

AC technology assumptions:

Platforms will have a maximum of 600 MW of generation connected;

AC transmission to shore and between platforms will be at 220 kV using 3 core bundled, 300 MVA cables;

Greater design efficiencies may be obtained by increasing voltage and utilising 3 single core cables (300 MVA plus);

Maximum distance considered for AC will be ~ 60km cable length.

Technology not considered in the study:

HVDC on-load circuit breakers have not been considered. L.6 The rate of technology advancement used for the radial plus strategy is delayed beyond

that used in the coordinated strategy to reflect the likely delay in necessary research and development associated with this strategy.

36




Appendix L: Assumptions

154

L.7 HVDC cables with capacity greater than 1.2GW are available in 2017 L.8 AC collector platforms are assumed to contain any necessary high voltage switchgear and

transformers. In the study, a range of platform sizes from 300 MW to 600 MW has been used to best suit the different overall development sizes and turbines.

L.9 The offshore platforms have been assumed to be in typical water depth of 35-40m and to

include sufficient electrical equipment to accept multiple transmission connections. Cost assumptions L.10 The specific cost ranges used in this study are detailed in Appendix D of this report, as well

as the costing information from ODIS 2010 (Appendix 4.3). L.11 The unit costs represent an installed cost, including an estimate for such things as

consenting, land purchase, materials, installation and construction. L.12 Onshore a 10% undergrounding rate has been assumed. The onshore reinforcements

(onshore AC lines) referenced in this study relate only to MITS reinforcements (locally or deeper system reinforcements).

L.13 In the calculation on operating cost, the following assumptions were used (as detailed in

section 8):

Assumed average offshore generation load factor of 40%;

98% transmission asset availability (in line with the OFTO availability target set by

Ofgem);

Energy curtailment cost of £75/MWh (reflecting the amount in £ for each MW curtailed

when the network is not available).

L.14 The total maintenance cost was calculated by considering three major categories of assets,

which are offshore cables, offshore platforms and the remaining assets (onshore and other). The maintenance cost (calculated on present money value) is assumed as a percentage of the installed capital cost as follows:

Offshore Cables 0.5%

Offshore Platform 2.0%

Onshore and Other 1.0% Cable landing L.15 A cable landing site is counted as a single or pair of 3-phase AC cable entries to shore

(single triple bundled cable or three separate single cores) or a HVDC bipole cable pair. A pair of triple bundled 300MVA cables connecting a single 500MW offshore platform is therefore counted as a single cable landing. Please note: onshore transmission reinforcement using offshore DC links has been included in the DC landing point count, this does not include the first east and west HVDC bootstraps.

Scope of study L.16 The study focused on the potential network development associated with the offshore wind

programmes of Round 3 and STW projects, together with possible additional European interconnection. It has been additionally recognised that other programmes, notably some Round 2 projects and larger marine energy schemes, might also usefully be incorporated into a coordinated network. For this study, the Scottish Territorial Water (STW) projects of Beatrice, Inch Cape and Neart na Gaoithe were not included in the coordinated design and therefore are not included in the asset volume and cable route assessment. Some benefits of coordination of these projects is likely, but has not been captured in this study.


Appendix M: Glossary of acronyms

155

Appendix M:Glossary of Acronyms

AGR Advanced Gas-cooled Reactor CCS Carbon Capture and Storage CPA Coast Protection Act 1949 DCO Development Consent Order EIA Environmental Impact Assessment FEPA Food and Environment Protection Act 1985 GIS Geographic Information System IED Industrial Emissions Directive IPC Infrastructure Planning Commission MaRS Marine Resource System MCZ Marine Conservation Zone MITS Main Interconnected Transmission System NETSO National Electricity Transmission System Operator NETS SQSS National Electricity Transmission System Security and Quality of Supply Standards NGET National Grid Electricity Transmission NSIP Nationally Significant Infrastructure Project ODIS Offshore Development Information Statement OFTO Offshore Transmission Owner OHL Overhead line REZ Renewable Energy Zone SAC Special Areas of Conservation STW Scottish Territorial Waters TCPA Town and Country Planning Act TEC Transmission Entry Capacity TO Transmission Owner VSC Voltage Sourced Converter

Offshore Transmission Network Feasibility Study · worked together to produce this Offshore Transmission Network Feasibility Study ... maintenance costs and congestion management

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