A European Supergrid

House of Commons Energy and Climate Change Committee

Seventh Report of Session 2010–12

Volume II Additional written evidence

Ordered by the House of Commons to be published 7 September 2011

Published on 22 September 2011 by authority of the House of Commons London: The Stationery Office Limited

The Energy and Climate Change Committee

The Energy and Climate Change Committee is appointed by the House of Commons to examine the expenditure, administration, and policy of the Department of Energy and Climate Change and associated public bodies.

Current membership Mr Tim Yeo MP (Conservative, South Suffolk) (Chair) Dan Byles MP (Conservative, North Warwickshire) Barry Gardiner MP (Labour, Brent North) Ian Lavery MP (Labour, Wansbeck) Dr Phillip Lee MP (Conservative, Bracknell) Albert Owen MP (Labour, Ynys Môn) Christopher Pincher MP (Conservative, Tamworth) John Robertson MP (Labour, Glasgow North West) Laura Sandys MP (Conservative, South Thanet) Sir Robert Smith MP (Liberal Democrat, West Aberdeenshire and Kincardine) Dr Alan Whitehead MP (Labour, Southampton Test)

The following members were also members of the committee during the parliament:

Gemma Doyle MP (Labour/Co-operative, West Dunbartonshire) Tom Greatrex MP (Labour, Rutherglen and Hamilton West)

Powers The committee is one of the departmental select committees, the powers of which are set out in House of Commons Standing Orders, principally in SO No 152. These are available on the internet via www.parliament.uk.

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The Reports of the Committee, the formal minutes relating to that report, oral evidence taken and some or all written evidence are available in a printed volume.

Additional written evidence may be published on the internet only.

Committee staff The current staff of the Committee are Nerys Welfoot (Clerk), Richard Benwell (Second Clerk), Dr Michael H. O’Brien (Committee Specialist), Jenny Bird (Committee Specialist), Francene Graham (Senior Committee Assistant), Jonathan Olivier Wright (Committee Assistant) and Nick Davies (Media Officer).

Contacts All correspondence should be addressed to the Clerk of the Energy and Climate Change Committee, House of Commons, 7 Millbank, London SW1P 3JA. The telephone number for general enquiries is 020 7219 2569; the Committee’s email address is [email protected]

List of additional written evidence

(published in Volume II on the Committee’s website www.parliament.uk/ecc)

Page 1 Climate Policy Initiative Ev w1 2 Alstom Grid UK Ev w4 3 The Crown Estate Ev w7 4 E.ON UK Ev w9 5 Association of Electricity Producers Ev w11 6 EDF Energy Ev w14 7 Greenpeace UK Ev w19 8 RWE npower Renewables UK Ev w21 9 Alderney Renewable Energy Ev w22 10 Scottish and Southern Energy Ev w24, Ev w26 11 Campaign to Protect Rural England Ev w28 12 DONG Energy Ev w30 13 Centrica Ev w32 14 Institute of Marine Engineering, Science and Technology, Offshore Renewables Special Interest Group Ev w36 15 Mainstream Renewable Power Ev w39, Ev w44 16 Scottish Renewables Ev w44 17 E3G Ev w47 18 WWF-UK Ev w52 19 Scottish Government Ev w60

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Written evidence

Memorandum submitted by Climate Policy Initiative Climate Policy Initiative (CPI) welcomes the opportunity to respond to the Energy and Climate Change Select Committee’s Inquiry into A European Supergrid dated 14 February 2011.1 An integrated, robust yet ﬂexible European power network is needed to ensure that the EU’s medium- to long-term energy and carbon aspirations are met. In particular, this submission will provide written evidence in response to the following questions: — How would a Supergrid contribute to the goals of the EU Third Energy Liberalisation Package? — Would new institutions be needed to operate and regulate a Supergrid?

General Remarks In light of the goals of European climate policy, the power system will require significant investments in electricity transmission, distribution, generation and innovative new approaches to manage the demand side. The North Seas offshore grid (contributing much to the so-called EU Supergrid) and the Memorandum of Understanding between 10 North Seas Countries,2 offer the opportunity to cooperatively tackle areas which, if addressed, could provide long-term and far reaching benefits to the onshore and offshore European power market: — the current approach to congestion management between and within countries limits cross- border flows. — regional/zonal pricing does not adequately reflect system state and risks undermining investment; — an integrated approach to offshore DC (Direct Current) interfaces can limit exposure to possible operational shortcomings, and; — system-wide information-sharing can maximize the potential resources available and efficiently incorporate variable energy sources. Since offshore DC links will be connected to various locations of the onshore AC power system,3 they are of particular importance to the EU transmission system. Any flows scheduled on these DC lines have an impact on the flow pattern in the remaining system, and can thus create benefits for countries (reducing existing line loading) or contribute to additional constraints (loop flows). The responsible TSO can determine the DC flow volumes, and consequently can have a significant impact on the performance of the overall system. Without a jointly agreed methodology (including a system operation objective function), operation of the offshore grid has the potential to create conflicts that undermine the effective use of the transmission system. Furthermore, for the effective integration of intermittent generation (especially offshore wind), the offshore grid offers the opportunity to share flexibility across regions. This is only effective however, if intraday markets are fully integrated across regions with energy markets—building on the positive experience of coupling energy and transmission markets at the day-ahead stage. The reminder of this submission reports on market design options to address these requirements.

Options for Europe: EU Power Market Design to Support Offshore Grid Planning and Operations In the EU, almost 200 gigawatts (GWs) of new and additional renewable energy sources are expected to be constructed by 2020. However, the existing EU power market design and the pursed “target model” utilizing regional/zonal pricing risks impeding the required rate of development to meet these 2020 aspirations. Through various qualitative and quantitative studies detailed below, we explore whether the current European power market designs foster the transition to low-carbon energy. Using an international comparison, we ﬁnd that the approaches currently pursued across EU countries do not provide an effective framework for the widespread adoption of many GWs of on- and off-shore intermittent power: — The current structure does not make effective use of network transmission capacity, thus increasing costs and risking delays for renewable energy connections—see Section A. — It does not use improvements in wind forecasts during the day to optimise European system dispatch, to save costs and emissions—see Section B. — In addition, it does not create transparent signals about system constraints to inform transmission network investment decisions. 1 http://www.parliament.uk/business/committees/committees-a-z/commons-select/energy-and-climate-change-committee/news/ new-inquiry-a-european-supergrid/ 2 http://ec.europa.eu/energy/renewables/grid/doc/north_sea_countries_offshore_grid_initiative_mou.pdf 3 See the European Commission’s Baltic and North Seas Coordinator Annual Review for 2010 in which CPI contributed. http://ec.europa.eu/energy/infrastructure/tent_e/doc/off_shore_wind/2010_annual_report_en.pdf. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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We conclude that implementing an integrated nodal pricing approach addresses the needs by providing appropriate price signals for the economic design, evaluations and planning of offshore grids, and encourages the effective use of transmission capacity whilst improving interfaces between onshore and offshore networks4—see discussion in Section C. For reference, listed below are recent studies we carried out with regards to the current power market design in the EU: — K Neuhoff (CPI Berlin/DIW Berlin), B Hobbs & D Newbery (Electricity Policy Research Group, University of Cambridge): Congestion Management in European Power Networks, 2010. — F Borggrefe (University of Cologne) & K Neuhoff: Balancing and Intraday Market Design: Options for Wind Integration, 2010. — K Neuhoff: A Smart Power Market at the Centre of a Smart Grid, 2010. — K Neuhoff, R Boyd & T Grau (CPI Berlin), J Barquin & F Echavarren (Universidad Pontiﬁcia Comillas), J Bialek & C Dent (Durham University), C von Hirschhausen (TU Berlin), B Hobbs, F Kunz & H Weigt (TU Dresden), C Nabe & G Papaefthymiou (Ecofys Germany) and C Weber (Duisberg-Essen University): Renewable Electric Energy Integration: Quantifying the Value of Design of Markets for International Transmission Capacity, 2011. — K Neuhoff & R Boyd: Frequently asked questions on the international experience with nodal pricing implementation, working document 2011.

A. Congestion Management in European Power Networks Congestion represents the situation when technical constraints (eg, line current, thermal stability, voltage stability, etc.) or economic restrictions (e.g. priority feed-in, contract enforcement, etc) are binding and thus restrict the power transmission between regions; congestion management aims at obtaining a cost optimal power dispatch while accounting for those constraints. The EU electricity regulator, ERGEG,5 proposed a short-run market design based on market coupling and expanding market coupling to address congestion. However, the topology of the European power network does not follow national boundaries and signiﬁcant congestion occurs both between and within countries. Several market designs have been explored in the past to achieve some integration of congestion management and balancing markets. In contrast to the EU, some areas of the US have adopted an approach based on locational marginal pricing (or nodal pricing—a description of which can be found in Section C). Table 1 illustrates how the efﬁciency of the system can be enhanced by integrating congestion management and balancing markets on a European scale. As the table outlines, only nodal pricing has the potential to achieve full integration. Table 1 ASPECTS OF CONGESTION MANAGEMENT AND BALANCING MARKETS THAT BENEFIT FROM EUROPEAN INTEGRATION, AND MARKET DESIGN OPTIONS TO ACHIEVE THIS INTEGRATION (ii) Joint (i) Integration allocation of (iv) Integration with domestic international (iii) Integration with intraday/ (v) Transparency congestion transmission with day ahead balancing of congestion management rights energy market market management Bilateral No No No No No transmission rights auction

Joint multi- No Yes No No No country auction of NTC rights

Multi-region day- No (only at Possible Yes No No ahead market zonal level) coupling (zonal pricing)

Nodal pricing Yes Yes Yes Possible Yes

4 Available on www.climatepolicyinitiative.org, or can be requested by email from the authors. 5 European Regulators’ Group for Electricity and Gas (ERGEG), www.energy-regulators,eu cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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B. Balancing and Intraday Market Design

Historically, balancing markets have been the only markets to provide reserve and response operations needed to respond to unplanned power plant outages or load prediction errors. Transmission System Operators (TSOs) contract in day-ahead and longer-term markets with generators to provide ﬂexibility that can be called upon on short notice to balance the system.

Balancing services were provided nationally, or in the case of Germany, within the region of the TSO. Mutual support between operating regions was restricted to emergency situations, such as unexpected power plant failures, and not remunerated (only energy that was provided had to be returned).

In recent years, renewable energy and newly installed wind power have prompted additional demand for reserve and response operations. This demand arose predominantly due to the uncertainty of day-ahead forecasts for renewable feed-ins. This trend will continue as EU member states increase the deployment of wind power and other intermittent renewable energy sources to deliver the 20% renewable target formulated in the European Renewables Directive of 2009.

To meet this additional demand for reserve and response operations, intraday and balancing markets need to be adjusted to allow the TSOs to appropriately respond to increased uncertainty.

After comparing different EU power market designs, we determined that a nodal pricing approach provides appropriate price signals for the economic design and evaluation of (onshore and offshore) power grids, encourages the effective use of transmission capacity and improved interfaces between onshore and offshore networks, even between regions.

Table 2

SUMMARY FOR HOW DIFFERENT MARKET DESIGN OPTIONS ALLOW FOR INTRADAY OPTIMISATION OF THE POWER SYSTEM IN THE PRESENCE OF WIND POWER, AND HOW THEY PERFORM AGAINST CRITERIA USED FOR THEIR EVALUATION

Balancing Flexible use Internaonal Integraon Eﬀecve Dispatch requirements / of individual integraon of demand monitoring adjusted provision convenonal of intraday / side of market during day adjusted during power balancing response power day staons markets services possible

UK system N/A

German

system N/A

Nordpool

Spanish N/A system

Nodal pricing system

C. Recommendations

System-wide Information Sharing for Efﬁcient Operation of DC Offshore Links

In the European power network, national and regional system operators share information about the state of the system on a limited and infrequent basis. Since the operation of a DC system will significantly influence flow-patterns and network congestion profiles, an operational agreement is needed in conjunction with the design of an offshore grid.

Locational Marginal (Nodal) Pricing

An important goal of market design should be to expand national markets to real-time, recognizing all network-wide constraints. At the same time, effective congestion management schemes have to be fully integrated with the intraday balancing market design. Nodal pricing offers a clearly deﬁned process that can achieve this objective. Below is a description of nodal pricing and how it can be applied in the EU. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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Nodal pricing is based on the engineering solution to congestion management (Optimal Power Flow optimization).6 It has been widely used since the late 1960s by vertically integrated utilities which were able to directly control the generators they owned. Schweppe et al (1988)7 provided the economic interpretation of nodal shadow prices. This allowed for market-based power system operation. Being built around the physical reality of the network, nodal pricing thus allows for a more efﬁcient use of the network, reduces the opportunity to game the re-dispatch, and provides more regulatory stability because the physical principles that guide the design will not change. In an assessment by the European regulator’s group for electricity (ERGEG),8 a nodal pricing approach was considered the “ultimate goal and (technically and economically) optimal solution”, but only adjustments to the current power market design were subsequently proposed for consultation. Several regions worldwide (US, Australia, New Zealand) already have, or are considering, nodal pricing as a common congestion management and market setting solution.9 Their experience show that designs that do not appropriately address transmission constraints, or do not offer a consistent approach for integrating day- ahead and real-time energy trading, can be subject to market failures including gaming and blackouts. This introduces signiﬁcant onshore and offshore regulatory uncertainty that potentially undermines investment and innovation, since future changes to regulations can be expected, but neither their timing nor exact nature is clear to market participants. The early adoption of a robust power market design that is compatible with large-scale renewable energy deployment is thus necessary with regards to the suitability of nodal pricing In the EU. This requires a committed effort with a long-term perspective. March 2011

Memorandum submitted by Alstom Alstom Grid is one of the top three global players in electrical transmission and, as an acknowledged leader in key technologies, markets and geographies, it is helping today to develop the intelligent and green grids of tomorrow. Electrical power is generated as an alternating current (AC). It is also transmitted and distributed as AC and, apart from certain traction and industrial drives and processes, it is consumed as AC. However, in many circumstances it is technically and advantageous to introduce direct current (DC) links into the electrical supply system. Indeed, in particular situations it may be the only feasible method of power transmission. The European Supergrid is a case in point. When AC systems cannot be synchronized or when the distance by cable is too long for stable and/or economic AC transmission, DC transmission is used. At one “converter station” the AC is converted into DC, which is then transmitted to a second converter station, converted back to AC, and fed into another electrical network. High Voltage Direct Current (HVDC) is all about making existing power grids efficient. In a world consumed by cost-cutting, yet obliged to improve environmental impact, HVDC is the answer to one of the biggest challenges faced by energy managers: move more power, more efficiently, with the lowest losses possible. Alstom Grid is a major supplier of turnkey HVDC solutions for efficient power transmission worldwide. From its global HVDC Competency Centre in Stafford, UK, and with over a half-century of experience, we have designed and delivered schemes in all parts of the world, including the High Voltage Direct Current (HVDC) converter substations for the world’s largest submarine interconnection, the 2,000MW link between UK and France. The Alstom Grid global HVDC Competency Centre is the only one based in the UK and here we have assembled large teams of researchers, engineers and technologists to develop the next generation of HVDC technology in readiness for offshore grid substation opportunities that will arise as part of the Round 3 Offshore wind and any resulting European SuperGrid. Alstom Grid designed and delivered the key substation elements for the first UK offshore windfarm, Barrow, which was commissioned in 2006. Progressively, and with experience, Alstom Grid has expanded its offering to the offshore market and is now completing the contract for Sheringham Shoal, which encompasses the entire electrical substation, with the topside. Alstom Grid recently secured an order for an innovative self-floating, self-installing offshore high 6 Wood, A, J, Wollenberg, B F: “Power generation operation and control”, Wiley, 1996. 7 Schweppe, F C, Caramanis, M C, Tabors, R D, and Bohn, R E: “Spot pricing of electricity”, Kluwer Academic Publishers, Boston, MA, 1988. 8 European Regulators’ Group for Electricity and Gas—Initial Impact Assessment for the Framework Guidelines on Capacity Allocation and Congestion Management, Ref: E10-ENM-01–01-CM_FM_IIA, page 30. Dated 8 September 2010. 9 Consequently, it is now the dominant form of network management in all the restructured markets in the US, including PJM, Midwest ISO, New England ISO, New York ISO, ERCOT (Texas), and the Californian ISO. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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voltage substation to connect a 400MW offshore windfarm located in the German Exclusive Economic Zone of the North Sea to the offshore HVDC grid. Recently, Alsom Grid commissioned a 25MW HVDC Demonstrator at its facilities in Stafford, which is a major milestone in its development of what is known as Voltage Source Converter (VSC) technology. This £15 million investment demonstrates the key enabling technology that is required to deliver onshore the electricity generated from the Round 3 offshore wind programme. In addition, this technology is critical to the creation of a robust European Supergrid.

[Q] What are the technical challenges for the development of a European Supergrid? [A] The technology challenges faced today, when considering the construction of a “SuperGrid” can be broadly classiﬁed into three groups; lack of standardization, technology gaps, supply chain.

Standardization At present each HVDC project constructed is specified in a way that maximizes the investor’s return on investment. Hence, each HVDC interconnection is bespoke. For a SuperGrid to become a reality there needs to be some level of standardization in the specification of HVDC equipment to ensure that equipment from different suppliers can operate together, allowing for competitive bidding at each stage of the development of a HVDC SuperGrid. Data considered essential to be standardized and accepted by all parties involved in the development of the SuperGrid includes: — Topology: — Symmetric Monopole. — Monopole. — Bipole. — DC Voltage (nominal, steady-state and transient range). — Fault Current Contribution. — Multi-terminal DC Protection — Multi-terminal DC control.* * Barker C D, Whitehouse R S, “Autonomous Converter Control in a Multi-Terminal HVDC System”, IET, ACDC 2010. Clearly, standardization of these elements will result, in some instances, in a need for over capital investment at some nodes within the SuperGrid. Other elements associated with the HVDC SuperGrid should not be “standardized” as this could stifle innovation and eventually, increase costs and reduce efficiency of equipment. Nevertheless, it is possible for these equipments to be “functionally” specified, that is, to treat the equipment as a “black box” with a defined input and output and a defined response under defined conditions. Equipment that should be considered as needing to be “functionally standardizing” includes: — AC/DC Converters. — HVDC Cables. — DC Breakers. — DC-DC Converters. — Dump Resistor.

Technology Gaps Today, the vast majority of HVDC transmission is only between two points, connecting one AC node to another AC node. Consequentially, a fault on the DC side can be cleared by the total interruption of the DC transmission. However, for a HVDC SuperGrid it will be necessary to be able to isolate part of a DC network without interrupting the rest of the DC grid (for example, a fault in the North of Norway should not result in the converter stations in Southern Spain to block). For this to happen a “DC circuit breaker” capable of operating at the DC transmission voltage and interrupting the maximum envisaged fault current is required. Various development activities are presently being undertaken, but as of now there is no product available on the market. A HVDC SuperGrid will be a “low inertia” system. This means that a fault within the DC network will very rapidly (milli-seconds) give rise to a very large fault current. It will most probably be necessary to develop very fast detection techniques that are able to reliably discriminate between a fault and a sudden change in steady-state load as well as the location of the fault in order to operate the correct DC circuit breaker at the correct time. Whilst such protection methods exist today for point-to-point HVDC converter schemes it can be envisaged that with a complex, meshed, HVDC grid there will be challenges in terms of detection and discrimination. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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It is unlikely that a single uniﬁed HVDC SuperGrid will be constructed. It is noted that some utilities within Europe have already taken the ﬁrst steps in procuring small DC grids and hence there is a likelihood that the HVDC SuperGrid will most likely develop from small “islanded” DC Grids within Europe. In order to connect these islanded DC grids together DC-to-DC Converters will be required. These devices can be considered to provide the same function as step-up or step-down transformers within the existing AC systems. Again, development is presently being undertaken in order to bring this technology to the market but, at present, there is no market demand for the product.

Supply Chain

Even with the level of standardization proposed above, allowing manufacturers to reduce the engineering process required in order to deliver products, the development of a HVDC SuperGrid will be limited by the supply of the component parts. It is assumed that, within Europe, it will not be possible to gain planning permission for overhead lines and hence underground, along with submarine cables will make up almost the entire DC SuperGrid. Today, the manufacturing capacity of such cable is limited, necessitating cable manufacturers to subcontract parts of orders to other cable manufactures in order to meet individual project deliveries.

Other components that are used to manufacture the HVDC converter stations are also specialized components that can, presently, be on long lead times.

[Q] What risks and uncertainties would a supergrid entail?

[A] The biggest risk in the early development of a HVDC SuperGrid is the risk of “stranded assets”. That is, building parts of the SuperGrid infrastructure where, later, as the SuperGrid develops, this equipment can not be fully utilized.

Standardization will be important within a HVDC SuperGrid but, as mentioned in response to the previous question, incorrect or over proscriptive standardization could stiﬂe innovation and, consequently lead to higher costs and poorer performance. Equally, without the correct selection of “standards” for the HVDC SuperGrid, such as the DC circuit topology and the operating DC voltage from the outset, changes in direction could happen throughout the development of the HVDC SuperGrid, again leading to stranded assets.

From an operational perspective, rules must be developed which allow the system operators (NETSOs) to control both the DC power flows as well as the AC power flows in a coordinated manner. Without careful control there is a risk of, for example, “real power wheeling” where real power is transferred from the DC system to the AC system at one node and then transmitted across the AC system only to be transferred from the AC system to the DC system at another node. It may, in fact, be of some benefit, once a HVDC SuperGrid has been established, to break the existing common European AC grid up in order to create “AC islands”, which can then be connected together via the HVDC SuperGrid. Operationally this may be a better final goal than to always consider operating two large overlaid power transmission systems (both AC and DC).Thus during the transition time, whilst the HVDC SuperGrid is being developed special care will be needed.

[Q] Will a supergrid help to balance intermittency of electricity supply?

[A] As with any natural system, a sufficient mix of basic building blocks helps to overcome any problems with one particular element. In the same way that this is true for the human gene pool, it is also true for the electricity supply, as long as sufficient investment is made not only in the HVDC SuperGrid but also in the mix of renewable and semi-renewable energy sources. Where the DC SuperGrid helps is that it will potentially give pan-European access to diverse energy sources. Considering this in conjunction with the power load diversity (daily / yearly) across Europe, then conceivably when the wind is blowing in the North Sea, Britain could be supplying power to Italy but when the British load can no longer be met by our own resources (because the wind speed has reduced) then Britain could make up it’s energy deficit from solar generation in Spain or North Africa or, alternatively hydro-power in Norway.

Alstom in the UK

Alstom’s presence in the UK can be traced back to 1889 with the formation of the General Electric Company Ltd, the merger of GEC and Compagnie d’Electricitie (CGE in 1989—to become GEC Alstom—and the eventual formation as Alstom in 1998.

Today, Alstom, with a turnover of almost £1 billion, operates out of more than 30 key locations across the country and employs over 6,500 people within its Transport, Power and Grid Sectors, helping to develop the UK’s power, transmission and transport infrastructure to meet the challenges ahead. March 2011 cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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Memorandum submitted by The Crown Estate

1. Executive Summary

The Crown Estate welcomes the opportunity to provide written evidence for the ECCC’s inquiry into the potential for building a European Supergrid. As outlined in the Terms of Reference for written evidence, we have addressed the questions posed and provided further information of relevance from our position as The Crown Estate. This is outlined in more detail below but the summary points are: — The Crown Estate is providing comment from its distinctive position as steward of the marine estate which includes over half of the UK’s foreshore and vast majority of the seabed out to territorial 12 nautical mile limit and with vested rights for the development of renewable energy to the UK Continental Shelf. — Renewable energy, in particular offshore wind, could make a signiﬁcant contribution to the UK’s energy supply mix to mitigate the impact of the retirement of fossil fuel and nuclear generating capacity, while at the same time supporting the UK Government in achieving its carbon reduction and renewable energy targets. The offshore renewable energy programme also has the potential to create jobs around the UK in manufacturing, services and construction. — The development of a pan European offshore grid will require a European vision, including the contribution of the European Commission, the European Network of Transmissions System Operators, and other stakeholders. It will require strong cooperation among the countries across the North Sea. — An offshore transmission network linking the hydro resources of Scandinavia with the marine and wind resources of Northern Europe will undoubtedly mitigate the impact of the variability of power output from renewable energy sources and will increase the ability of each national power system to accommodate the variability of wind power supplies. — Technically a HVDC based offshore supergrid would not entail major risks. However, uncertainties in relation to procurement rules, regulatory frameworks and trading arrangements may result in risks to the success of a supergrid. — An offshore grid would allow the full potential of the UK offshore energy resources to be utilised, energy export to other countries and for the ease of system operations with other countries. This would also translate into lower energy price.

2. The Crown Estate Remit and Responsibilities

The Crown Estate manages an estate worth £6.6 billion, which contains extensive marine assets, including over half of the UK’s foreshore and the vast majority of the seabed out to the 12 nautical mile territorial limit. Under The Crown Estate Act 1961, The Crown Estate’s permission, in the form of a lease or licence, is required for the placement of structures or cables on the seabed; this includes offshore wind farms and their ancillary cables and other marine facilities. In addition to this, by virtue of the Energy Act 2004 (and Energy Act 2008) it has the rights vested in it for the development of renewable energy within the Renewable Energy Zone and to the UK Continental Shelf for development of natural gas and carbon dioxide storage.

In carrying out this duty, under the core values of commercialism, integrity and stewardship, The Crown Estate is concerned to deliver the maximum renewable energy potential of the marine estate, in line with government policy and consistent with the requirement to oversee the estate in accordance with the principles of good management.

In its role as steward for the marine estate The Crown Estate is working with the grain of government to develop this new energy mix through several programmes of work including offshore wind, wave and tidal, carbon capture and storage and natural gas storage.

It has instigated major Rounds of offshore wind leasing, the most recent being Round 3 with a target delivery of up to 32GW of electricity generating capacity as well as a Round in Scottish Territorial Waters with potential generating capacity in the region of 5GW. The Crown Estate recently announced offshore wind and tidal leasing rounds in waters off Northern Ireland. The Crown Estate has entered into agreements for wave and tidal projects in the Pentland Firth and Orkney Waters: the world’s largest Wave and Tidal programme, with potential capacity of 1.6GW and opened a subsequent tender for projects of up to 30MW installed capacity in connection with the Scottish Government’s Saltire Prize.

The Crown Estate’s unique perspective on the UK offshore energy sector, the programmes outlined above and the work being undertaken to identify and address strategic grid and technical issues that may impact on these being delivered, has informed our responses to the questions outlined in the inquiry. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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3. Responses to the Questions asOutlined in the Terms of Reference: 3.1 What are the technical challenges for the development of a European Supergrid? — The utilisation of HVDC (High Voltage Direct Current) technology for the offshore grid has been widely accepted because it offers the control needed to allow the network both to transmit offshore wind power and to provide the cross-country electricity trade. Moreover, HVDC offers the possibility of terminating inside onshore AC grids, and thus avoiding onshore reinforcements close to the coast and avoiding operational interference among interconnected AC systems. — However, to improve asset utilisation rate thus reducing cost, there may be a need to route the interconnections along wind farms and avoid single purpose shore to shore interconnections. This wind farm teeing in connection does require further technological development such as circuit breakers for DC circuits. There will be a need to proactively promote signiﬁcant technical advancement of multi-terminal HVDC conﬁguration which at this point would utilise control strategies for fault clearing. — There may be risks of the lack of electrical coordination (including voltage standardisation), corridor coordination and lack of coordination between wind farms and interconnectors.

3.2 What risks and uncertainties would a supergrid entail? — Technically a HVDC based offshore supergrid would not entail major risks. However, uncertainties in relation to procurement rules, regulatory frameworks and trading arrangements may result in risks to the success of a supergrid.

3.3 How much would it cost to create a supergrid and who would pay for it? — Capex of a supergrid will depend on the total length of all transmission cables and the total number of substations/converter stations. — It should be noted that the offshore wind farms will have capacity factors (average output divided by rated output) of approximately 40–45% but offshore wind farm grid connections have to be rated at near the maximum rating of the offshore wind farm. This leaves up to 60% of the offshore grid connection unused with a simple spur grid connection to the offshore wind farm. By integrating the offshore wind farm grid connections with interconnectors, when the offshore wind farms are not generating at rated output, the available capacity on the grid connections can be used to trade electricity and ancillary services. Thus these cables can be used in all wind conditions and they are expected to be used up to twice as heavily as conventional wind farm connections. This much more efﬁcient utilisation of the cables is expected to give positive economic beneﬁts. — As the offshore supergrid will most likely be regulated asset, the consumer will ultimately pay for it.

3.4 Will a supergrid help to balance intermittency of electricity supply? — An offshore transmission network linking the hydro resources of Scandinavia with the marine and wind resources of Northern Europe will undoubtedly mitigate the impact of the variability of power output from renewable energy sources and will increase the ability of each national power system to accommodate the variability of wind power supplies. This would occur in two ways: — The wind conditions in the various systems being connected will exhibit a degree of diversity. In such situations the interconnections will allow systems experiencing high winds with surplus generation, to provide some of this surplus to other systems that are experiencing low wind conditions. — The envisaged interconnection to Norway will allow the UK and other member states to take advantage of the potential for using the hydro-electric resources of Norway for de facto energy storage. At times of high wind power would ﬂow to Norway, replacing hydro power so that water would be retained in the reservoirs; at times of low wind this water would be used and the resulting power re-exported from Norway.

3.5 Will a supergrid reduce energy prices for consumers and businesses? — In order to make use of the full potential of the UK offshore energy resources an offshore grid will be required for energy export to other countries and for the ease of system operations with other countries. This would translate into lower energy prices than the scenarios without an offshore supergrid.

3.6 What are the implications for UK energy policy of greater interconnection with other power markets? — Renewable energy, in particular offshore wind, could make a signiﬁcant contribution to the UK’s energy supply mix to mitigate the impact of the retirement of fossil fuel and nuclear generating capacity, while at the same time supporting the UK in achieving its carbon reduction and renewable energy targets. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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— It will help the UK to meet its renewable energy targets and achieve greater security of energy supply for Europe.

3.7 Which states are potential partners with the UK in a supergrid project? — All countries around the North Sea are important potential partners in a supergrid project, in particular, Germany, France, the Netherlands, Denmark, Norway and Ireland.

3.8 How would a supergrid contribute to the goals of the EU Third Energy Liberalisation Package? — A coordinated offshore grid will serve to augment energy security for the participating countries while making it easier to optimise offshore wind electricity production and facilitate market competition. It will also assist the EU as a whole to meet its renewable energy target for 2020.

3.9 Would new institutions be needed to operate and regulate a supergrid? — The construction of a pan European offshore grid will require a European vision, including the contribution of the European Commission, the European Network of Transmissions System Operators, and other stakeholders. It will require strong cooperation among the countries across the North Sea. — There can be a number of options to operate and regulate a supergrid. The principal operational tasks concerning the offshore grid include operating and maintaining the grid in a secure and equitable way, whilst granting fair access to the connected parties; and scheduling the HVDC lines for the predicted amounts of wind power and the nominated amounts of power for trade. March 2011

Memorandum submitted by E.ON UK GeneralComments — Greater interconnection has the potential to bring benefits in terms of increased system security, access to a wider range of sources of generation and more efficient use of available generating capacity. — A European supergrid could help to balance intermittent generation during periods of excess production in one system, although it may not help during periods of low production as the weather systems that cause low winds can affect much of northern Europe. However, generation from sources other than wind, e.g. hydro, could also be transported via the supergrid and be used to balance the missing wind production. — It is likely that increased interconnection will lead to a convergence of prices across Europe, with prices to some customers falling, but other customers’ prices will rise. — Roles will need to be clearly defined (TSO/DSO/SG-TSO) to avoid potential overlap or confusion, as each will want to optimise its own assets and systems. — Similarly, consideration will need to be given to the legal and regulatory arrangements that will apply to supergrids and to generators connected to them, and the impact that the arrangements are likely to have on incentives to invest. — We believe that a European supergrid should be regulated by existing national regulators, in conjunction with the European regulatory body, ACER, for cross border issues. There is no need to create additional institutions.

Responses toSpecificQuestions What are the technical challenges for the development of a European supergrid? 1. A grid covering the North Sea would require HVDC cables for high capacity power transmission over long distances, and HVDC convertor stations for connection to existing onshore grids. These technologies are mature and are in operation in existing HVDC interconnectors, but only as point-to-point schemes. To form a supergrid, HVDC systems with multiple points of connection (referred to as multi-terminal schemes) will be required, for two reasons: firstly to facilitate the connection of offshore generation combined with interconnectors; and secondly to create a meshed grid, which is desirable to provide high power transfer capability combined with operational flexibility and the necessary levels of redundancy and security. 2. An offshore supergrid using multi-terminal HVDC systems poses some technical challenges and will require further technology developments, including: HVDC circuit breakers; protection systems for interconnected cable circuits; and fast-acting control systems to manage power flows in the event of a failure of a network component. A standardised HVDC voltage level must be agreed that will facilitate interconnection between different HVDC systems, staged development, and future expansions. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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3. All equipment and installations must be designed for the offshore environment, with due consideration given to the more challenging operation and maintenance needs that this entails. 4. We believe that a “big bang” approach to the development of a European supergrid is probably not achievable. Instead, consideration should be given to a more gradual approach, perhaps with clusters of offshore generating plant connected in phases, but in a way that will allow the supergrid to be expanded and extended later as demand for it arrives and the economic case is demonstrated for each extension.

What risks and uncertainties would a supergrid entail? 5. A coordinated approach to grid investment is appropriate, but it is important that investments are made to support new generation build and in response to the needs of developers. Generation should not be made to ﬁt in with proposed transmission investments and any investment must be driven by demand from customers as either generators or consumers.

How much would it cost to create a supergrid and who would pay for it? 6. It is difficult to assess the likely cost of a European supergrid based on the information currently available and given uncertainty about its scale and purpose, but it will be high. Interconnectors to the UK have in the past been constructed on a merchant basis, with income for the interconnector owner driven by differences in prices in the markets either end. However, this is unlikely to be sustainable, as increased interconnection should cause prices in the connected markets to equalise over time, removing the incentive to construct. This may limit interconnection to a level which does not realise the full benefits of a more integrated European wide network. 7. We think that a regulated asset base model could work, with a regulated entity similar to a transmission system operator (TSO) responsible for the development and operation of the supergrid in a defined area, and recovering its reasonable costs from users, whether connected generators or companies trading across the grid, through regulated tariffs. Any investment should be subject to a full economic assessment. The impact on customers of the costs and benefits of the construction of a European supergrid also needs to be fully considered.

Will a supergrid help to balance intermittency of electricity supply? 8. Greater interconnection has the potential to help to balance intermittency, and to make more efficient use of the available generation capacity in the EU. If the wind is blowing in Britain but not in mainland Europe, then the supergrid could support the export of renewable energy from an area of surplus to an area in which it could be used. However the anticyclone weather systems that cause cold windless periods in the winter are often very large and may well extend to large areas of mainland North West Europe. Therefore the ability of a supergrid linking Member States with large volumes of wind generation such as Germany or Denmark to alleviate this issue may be limited. 9. This means that, whilst increased interconnection will clearly make a contribution to system security, it is unlikely to remove fully the need to retain sufficient flexible conventional generating capacity in a Member State to meet demand during a period of cold weather with little or no wind. However, the amount of flexible generation that will be needed in any Member State is likely to be lower in an interconnected system and there are clear security of supply benefits from having access to a greater variety of sources of generation. 10. Increased interconnection between countries will provide greater diversity in terms of access to a mix of energy sources (e.g. fossil, nuclear, hydro, wind) that are spread over a larger area. This could enable a supergrid to contribute to various balancing services, ranging from real time balancing, which will help to mitigate intermittency, through to longer term security.

Will a supergrid reduce energy prices for consumers and businesses? 11. A supergrid could reduce prices to customers but only if there is a supply of cheaper generation from elsewhere in Europe that can be brought to the UK. However, end customers are likely to have to bear a substantial proportion of the costs of constructing the supergrid, so this will inﬂuence the extent to which they would see prices fall. 12. The effect of the supergrid should be to cause prices across the EU to even out, which will inevitably mean that some customers who currently enjoy low prices may well see them rise. These customers may be reluctant to fund the development of new infrastructure that will mean they have to pay more for their energy in future.

What are the implications for UK energy policy of greater interconnection with other power markets? 13. There are a lot of regulatory and legal issues that will need to be resolved. Existing interconnectors can already be subject to different regulatory regimes in the two Member States they connect, and this can be confusing and difﬁcult for interconnector owners to manage. The regulatory framework for a European supergrid would need to be carefully considered, to avoid conﬂicting or overlapping regulation imposed by the various national regulators or by ACER, the European energy regulator. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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14. Clarity is important to the owners/operators of the supergrid, and it is equally important to generators who may want to connect to the supergrid. They will need to understand the regime in which their plant will be operating, and will need to know who to approach for a connection, and be able to make a reasonable estimate of the likely costs of connection, in the same way as they can for connections on land. Similarly, businesses wanting to trade across an interconnector will need to understand the regulatory arrangements of the connected systems, and the charges that they will be expected to bear. 15. Similarly, companies will need to understand whether their offshore assets fall under the legislative framework of one or other Member State, as this will impact on the legal requirements that the plant has to meet, as well as the tax burden on it. There could also be issues for generators in terms of the benefits they gain under initiatives in one or other MS. For example, renewable generation sold outside Britain does not qualify for British ROCs, and if the incentives are less favourable in the other MS, this could undermine the economics of a project. 16. The interaction with other regulatory reforms within UK, such as DECC’s ongoing Electricity Market Reform, needs to be carefully considered. For instance, mechanisms meant to promote the build of lower carbon generation in the UK may instead have the effect of encouraging greater imports from elsewhere. 17. The roles of DSO, TSO and supergrid operator will need to be defined carefully, so that the responsibilities and obligations of each are clear, and the businesses are able to optimise their positions. The involvement of different legal and regulatory regimes will make this more difficult.

Which states are potential partners with the UK in a supergrid project? 18. We would expect potential partners in a North Sea supergrid to be countries with an economic interest in electricity transmission across the North Sea, so that would include Belgium, France, Germany, the Netherlands and the Nordic countries. The North Seas Offshore Grid initiative should increase cooperation between the involved Member States, and ensure that planning, regulatory and technical challenges are properly addressed and the right framework is created to encourage investment.

How would a supergrid contribute to the goals of the EU Third Energy Liberalisation Package? 19. A supergrid would increase interconnection, and so would contribute to the goal of a single European electricity market, but it is possible that most of the beneﬁt could be delivered by an increase in the amount of point to point interconnection to the UK. As noted earlier, any proposal for extending the amount of interconnection should be subject to an appropriate cost beneﬁt analysis.

Would new institutions be needed to operate and regulate a supergrid? 20. There is no need to create another regulatory body, and it could be counterproductive. The national energy regulators, whose powers were reinforced by the third package, should regulate the national aspects of a supergrid and ACER, the European energy regulator created by the third package, should deal with cross border issues. Creating additional regulatory institutions unnecessarily will increase the risk of confusion and of overlapping or duplicated obligations. 21. It is likely that there will be a limited number of businesses with the necessary skills and activities to take on the role of supergrid operator and, as the activities that they will be undertaking will be natural monopolies, we would expect their activities to be regulated. This could be done by allocating responsibility for clearly deﬁned parts of the supergrid to the TSOs in the connected Member States, or there could be a number of new supergrid operators appointed by a competitive process, each covering a distinct area. March 2011

Memorandum submitted by the Association of Electricity Producers About the Association 1. The Association of Electricity Producers (AEP) represents the many different companies, both large and small, that make the electricity upon which the UK depends. Between them, AEP members account for more than 95% of the country’s electricity generation capacity and embrace all generating technologies used commercially in the UK—coal, oil, gas, nuclear power and a range of renewable energy technologies. A list of our members can be found online at www.aepuk.com. 2. At the time of receipt of this inquiry members are currently developing extremely detailed consultation responses including Electricity Market Reform and the Ofgem Significant Code Review of Gas Security of Supply. For that reason it is rather difficult to understand the urgency and timing of this inquiry, together with the one launched on Security of Supply. Nevertheless, we trust our responses below go some way towards fulfilling the full terms of reference. Please note that we are limiting our response to the North Sea’s grid rather than comment on wider European Grid expansion (for example to harvest north African solar energy) nor on a possible radial UK-Iceland link. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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Question 1—What are the technical challenges for the development of a European Supergrid? 3. It is important to clearly understand the full scope of an inquiry into the European Supergrid. In the introduction the inquiry references the 3 December 2010 Memorandum of Understanding which includes a schedule for the development of an offshore transmission grid with a network of North Sea and Irish Sea subsea cables. As an Association we believe that we should concentrate on getting it right for these cable networks as ultimately this is what we will have to rely upon in circumstances when ﬂows across the wider European Supergrid become constrained. The wider EU network will remain outside of our direct control. A European Supergrid goes beyond that of simply an offshore transmission grid with a network of North Sea sub-sea cables and must also consider EU-wide infrastructure and generation connectees. 4. A primary concern is to address the issue of whether to allow this combination of networks to evolve or mandate a prescribed design. We favour a process of evolution not revolution in this respect. At the present time the subsea cable technology required for such a network has only been utilised at a relatively small scale, albeit at 500–1,000MW, and from point to point, such as to connect an offshore windfarm to the transmission network or to interconnect two transmission systems. Larger intermeshed offshore network designs remain untried and untested. Therefore, the supergrid idea, although potentially promising in theory, should be considered with some caution. For instance, due consideration needs to be given to how the offshore environment will affect the design operation and maintenance of the assets. 5. Clearly, the role of a network is to facilitate the delivery of electricity from generators to customers and whilst we are supportive of a strategic element to network planning we believe that the network should ultimately respond to the needs of generators and customers rather than the other way around. Therefore, we would be concerned if the development of a supergrid was to prevent or delay much needed renewable projects or lead to inappropriate decisions on where to site generation projects, due to a lack of due consideration of generator developers’ needs.

Question 2—What risks and uncertainties would a supergrid entail? 6. The main risks we perceive are the potential cost of a supergrid along with the structure of the overall regulatory framework and ensuring that this facilitates delivery of the most efﬁcient overall outcome for the UK. A major investment of this kind will put pressure on the supply chain for the necessary equipment and this is likely to drive up costs. Therefore, initial cost estimates may prove overly optimistic. If the project is to proceed it must only do so if a thorough cost beneﬁt analysis proves that it is the best option. There is also the potential of an overreliance on other countries to export to the UK at times of system stress.

Question 3—How much would it cost to create a supergrid and who would pay for it? 7. This depends on a number of factors such as the level of resilience that it provides, whether spare capacity is created initially to meet potential future user demand, or whether the design is allowed to evolve or follows a mandated design path. However, the cost of this investment will be significant and depends on how extensive the North Sea’s grid becomes. It could range from a £billion for a single additional interconnector to tens of £billions for several GW of additional capacity between GB and its neighbours. We believe strongly that additional capacity should be built only with a sound economic justification which must include an assessment of the impact on consumers. It is not likely that future interconnection will be undertaken on a merchant investment basis. The current financial climate makes that a less likely outcome and both Ofgem and the European Commission have indicated that they now favour regulated interconnection projects . Individual national regulators working together with TSO’s, generation, consumers and distribution network operators, should facilitate debate on what is best for each country. 8. We have had recent difficult experience of development of the ENTSO-e Pilot Network Code for Grid Connections which means that we would be wary of a development process that is driven by the European monopoly transmission businesses. This was due to the opacity of the process, limitations on input from network users during the development phase, the over-reliance on the TSOs via ENTSO-e to develop workable solutions and unknown cost of this exercise. If such a process were to be repeated then we would be concerned that the deliverables would be tailored more to the requirements of the TSOs than network users. We believe that the optimum design, in terms of efficiency and cost reflectivity, will only be delivered if TSOs, SOs, generators, Distribution Network Operators and demand takers work together. 9. It may be sensible at times to build in surplus capacity into the network when there is a good indication that further generation investment is likely to follow. However, we would reiterate that the choice of locations for new investment must take into account the needs of generators as well as those of TSOs.

Question 4—Will a supergrid help to balance intermittency of electricity supply? 10. Government policy should not be built around an over reliance on interconnection to provide system security to the UK. However we acknowledge that connection to the continent may offer additional opportunities with regard to security of supply as peaks occur at different times. But this cannot be a full substitute for appropriate market signals for back up plant and robust back up arrangements. For example, when the wind does not blow for short periods then we believe that National Grid should be in a position via cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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its STOR contracts as well as the use of interconnections to adequately balance supply and demand. If, however when a wide area of the EU is affected by a period of calm weather, such as during a large anticyclone, then the UK would need to ensure an adequate level of generation is available to meet its local demand. The market arrangements should assure the availability of low load factor controllable generation and interruptible demand. 11. It is possible, and has indeed been seen within the gas arrangements, that despite higher prices within the UK, flows into the UK do not always occur. For example it could be that contractually generation and supply limitations in certain areas require local customer needs to be provided for first, allowing only residual excess levels to become available for export. At the same time once market coupling is in place then electricity should automatically flow from low price to higher price areas. In summary, a robust Grid can assist security of supply by providing access to a wider portfolio of generation plant than can be achieved solely within the national network.

Question 5—Will a supergrid reduce energy prices for consumers and businesses? 12. Government should carry out an appropriate impact assessment to ensure that there are no unintended consequences should wide scale interconnection plans be factored into the baseline for our UK energy policy. It would be unacceptable should the UK invest significant sums to attract generation flows to the UK and then see no benefit. 13. In addition there should be some exploratory work into the impacts of how generation will be despatched in the North Sea on a network which has interconnections with multiple countries. It is possible to envisage in the future operators of an offshore multi connected plant “flipping” flows between different countries as they choose to nominate wherever the price is most attractive. Consideration needs to be given to whether the overall design should enable such behaviour since it may make investment in offshore wind more, or less, likely. 14. In particular, the nomination arrangements would need to be specified in terms of where wind generators would be a ‘balancing responsible party’ (in the case of the UK this means signing onto the Balancing and Settlement Code). The producer would then have to nominate or sell into a particular market. It is important to understand how the trading arrangements will combine to ensure the best result for UK. We acknowledge that the effect on UK consumers will be complex to analyse as sometimes we will be exporting and sometimes importing.

Question 6—What are the implications for UK energy policy of greater interconnection with other power markets? 15. As we mention above, we are concerned about the possibility that transmission development could be driving generation decisions rather than the other way around. It would be unacceptable if too much capital was spent on transmission and not enough on viable generation. Another major consideration is how the eventual design would ﬁt into the longer term with the aims of the Electricity Market Reforms. The effect of increased interconnection will be to make market convergence more of a reality and it is therefore important that the market/trading arrangements in each country are compatible with those of its interconnected neighbour.

Question 7—Which states are potential partners with the UK in a supergrid project? 16. An appropriate cost beneﬁt analysis should provide the answer to this question.

Question 8—How would a supergrid contribute to the goals of the EU Third Energy Liberalisation Package? 17. It should assist but should not be relied upon as a major contributing factor. The trajectory for achieving the target model for an integrated European market is to both ensure that local markets are ﬁt for purpose and to achieve wider integration through market coupling and other integration measures. Interconnection will help facilitate that aim. However, interconnection should not become an overriding aim in itself.

Question 9—Would new institutions be needed to operate and regulate a supergrid? 18. It is possible that a central body would be required to facilitate a coordinated design and operation of a European supergrid, although this largely depends on how it develops. As we mention above, we are concerned that a large centrally planned venture may be driven in such manner so as to lose sight of the needs of network users and ultimately customers.

Additional Observations 19. There is an additional potential upside from the creation of a Supergrid in that liquidity should, during some periods increase. March 2011 cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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Memorandum submitted by EDF Energy Summary of our MainPoints 1. In principle, EDF Energy believes that optimal interconnection between European Member States is likely to be a contributing factor towards the development of a Single European Energy Market. 2. It is important to recognise that affordability, carbon reduction and security of supply form the basis of UK Government energy policy. Furthermore, we note that the Memorandum of Understanding (MoU) signatories of the North Seas Offshore Grid Initiative share a common goal of moving to a low-carbon economy while maintaining security of supply in the most cost effective manner. We believe that the attainment of these three goals is crucial to the evaluation and assessment of a European Supergrid. 3. We believe that any significant infrastructure investment in the North Sea, which may later form part of a European Supergrid, should have the primary objective of facilitating the connection of offshore generation projects. 4. It is imperative that a common understanding of the purpose and definition of a Supergrid is reached by all European actors prior to assessing the costs, benefits and risks of any European Supergrid. The UK can then begin to assess the contribution it should make. 5. In our opinion, a European Supergrid would be a fully integrated European-wide grid incorporating both onshore and offshore grids. Depending on the precise definition of a Supergrid, there are several technical models: (i) A radial approach to offshore connections and optimal interconnection between European Member States; or (ii) Some local co-ordination which integrates offshore connections within Member States and optimal interconnection; or (iii) Some international co-ordination bilaterally between Member States on an integrated network of interconnectors and offshore wind; or (iv) A fully integrated solution across multiple Member States for both interconnection and offshore wind. 6. These four Supergrid options range from light-touch to fully prescriptive and broadly reflect those presented by ENTSO-e at their conference, “Towards Electricity Infrastructure for a Carbon Neutral Europe”, on 11 February 2011. The level of costs and potential benefits of any European Supergrid will clearly differ between this range of options if any are mandated. 7. The development and integration of transmission systems has historically been organic, based on the needs of the users of the transmission system. These needs might be for the benefit of demand users, for security of supply and to facilitate new generation projects or interconnections. This approach has generally ensured that investment in new assets is efficient and has a demonstrable net benefit identified through a robust Cost Benefit Analysis (CBA). We believe that any approach for the European Supergrid must ensure that this efficient and economic assessment of investment in transmission assets is maintained. 8. It is important that a suitable legislative, regulatory and commercial framework exists to ensure the right level of transmission investment. It is beneficial to ensure that the mechanism exists to enable co-operation between Member States’ regulators, Transmission System Operators (TSOs) and system users to understand the risks and develop an indicative direction for the Supergrid. 9. However, we would not support a prescribed or top-down approach from a new institution that defines a required level of transmission investment. We believe that the assumptions needed to develop any such requirements are critical to the accuracy of a CBA and are extremely difficult to predict. We feel that there is a significant risk that assumptions on future scenarios and the needs of offshore generators might be misinterpreted. 10. It is important that markets are left as much as possible to adopt optimal infrastructure that brings energy to where it is needed. Any interference in commercial arrangements needs careful consideration so as not to undermine current and future investment in merchant assets. 11. We believe that managing intermittency should not be stated as a principle objective of the Supergrid. We consider that Member State intermittent generation will require significant Member State investment in back-up flexible generation to balance generation and demand. Furthermore, connecting a Supergrid would require additional interconnection between member states as a back-up for any technical or catastrophic failures of that Supergrid. These issues should be covered in an appropriate CBA. 12. Funding of a Supergrid could be both a political and commercial consideration. We would wish to see robust arguments that provide tangible benefits should Member States, including the UK, be asked to contribute to its funding. In particular, we consider that it remains inappropriate to impose offshore and interconnector costs onto onshore generators unless it can be proven unequivocally that they will use and benefit from the Supergrid. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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13. Whilst we agree that more interconnection in the EU may facilitate the objectives of the EU Third Package, combining the Super Grid initiative with the aims of the Third Package is not warranted at this stage. This may only serve to detract from achieving the goals of the Third Package, something which we believe is of more importance. 14. The challenge for a prescribed approach is further compounded by the technical aspects that may prove difﬁcult; we discuss these in more detail in our second attachment. 15. In conclusion, we note that the approach of the Electricity Network Strategy Group (ENSG) in 2008–09 and the subsequent work by Ofgem under the Transmission Investment Incentives framework represent good models of how a co-ordinated approach might help to mitigate risk while still delivering value for money for all system users.

EDF Energy Response toQuestions 16. We wish to note a number of related areas of work within the electricity industry which we feel will assist in informing this inquiry, this includes: (i) A presentation from National Grid which has promoted the benefits of an integrated offshore grid for GB which is deemed more cost efficient than radial offshore connections.10 (ii) National Grid’s Offshore Development Information Statement.11 (iii) Ofgem/DECC Offshore Transmission Advisory Co-ordination Group.12 (iv) A publication from ENTSO-e of their views indicating the benefits of a co-ordinated plan for the construction of an offshore grid between GB, Norway, Denmark, Germany, Netherlands, and Belgium.13 (v) The ENTSO-e Ten Year Network Development Plan.14 (vi) ENTSO-E Scenario Outlook and Adequacy Forecast (SO&AF) 2011–25.15 17. Our response below has been informed by a Pöyry Energy Consulting multi-client study (partially funded by EDF R&D) titled “Northern European Wind and Solar Intermittency Study (NEWSIS)” which we discuss with the permission of Pöyry.

What are the technical challenges for the development of a European Supergrid? 18. There are a number of technical challenges which must be considered as part of this work not least of which is that these are, in part, untested technologies. We provide below some more detailed remarks regarding these challenges. 19. We would suggest that re-routing of interconnector cables to an offshore generator is unlikely to result in the optimum route for the interconnector and has the potential to result in additional cable and embedding costs, as well as increased losses and risk of interconnector unavailability. 20. Cable integrity is a paramount objective of an interconnector, and breaking this integrity offshore requires assessment as to the risk of unavailability and primary purpose. Connecting a wind farm into an interconnector is likely to reduce the integrity of the cables and increase any risk of external damage. 21. There will need to be a connection point of some description on the offshore generator marshalling platform, the size of which will have to increase to cater for the increased number of HVDC isolators and switchgear; particularly so if it is to house a back to back convertor/inverter station. 22. If HVDC circuit breakers are employed then there would be concern about using this technology at the voltages used for the interconnector and in the offshore environment. Our understanding is that suppliers might offer the latest technology, but that it is relatively untried in the field at this time. 23. Integrating an offshore generator into an interconnector may result in difficulties in determining the optimum design, in terms of voltage, number of cables, reliability; as what might be optimum for one, might not be optimum for the other. These are important assumptions in respect of any cost benefit analysis, which we discuss further in paragraph 30 below. 24. The reactive requirement of the offshore generator will need separate consideration from that of the interconnector. 10 As presented at the September 2010 Customer Seminar: http://www.nationalgrid.com/NR/rdonlyres/B6F334D0–15E8–4087–9230–7AA467EC9CB6/43419/CustomerSeminarsv3.pdf 11 http://www.nationalgrid.com/uk/Electricity/ODIS/ 12 http://www.ofgem.gov.uk/Networks/offtrans/pdc/pwg/OTCP/Documents1/OCTG%20slides%201%20Mar.pdf 13 Presented at the ENTSO-e conference: Towards Electricity Infrastructure, 11/02/2011, Brussels 14 https://www.entsoe.eu/media/news/newssingleview/article/second-workshop-on-the-roadmap-towards-entso-es-tyndp-2012-and- the-202020-scenario/?tx_ttnews%5BbackPid%5D=43&cHash=e90105c27c3d14bca4d33d059cdccb85 15 https://www.entsoe.eu/system-development/soaf-2011–2025/ cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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25. Operational planning, programming and control, as well as designing any access arrangements to the interconnector and the grid systems at either end, will be more difficult. We highlight that the two stage approach to development of offshore generation within UK waters has the potential for jurisdiction issues where more than two Transmission entities will be operating at one onshore substation. 26. Unless there is redundancy built into the cable and the interconnector convertor stations, then the offshore generator will need to compete for commercial access with other potential users. There are further complexities in considering the potential for commercial access arrangements to a number of different electricity markets and the necessary systems and processes to which an offshore generator may need to be party. 27. The technical requirements for the onshore networks to cope with large capacities of offshore generation are also an important consideration. We would wish to be confident that the onshore networks are provided with the appropriate level of ancillary and balancing services which are required for their secure operation. 28. In summary, we consider that these challenges are areas that might be clarified by experience and ongoing development. We therefore believe that an incremental approach to a European Supergrid and the North Seas offshore development in particular, is likely to result in the best mechanisms to address these at a lower risk to affordability and security of supply.

What risks and uncertainties would a Supergrid entail? 29. A prescribed or top-down approach from a new institution, which sets a required level of transmission investment, may increase risk and uncertainty and has the potential to result in inefficient investments with higher costs to consumers. 30. Any transmission asset investment should, in our view, be preceded by a thorough CBA and impact assessment, which incorporates a robust set of assumptions. These might include the design and technical capabilities; an appropriate standard for security of supplies; an expectation of the needs of generators; and the commercial arrangements specifying sharing arrangements and rights of access for capacity. We consider that it is these important points which warrant discussion with a wider group of stakeholders than is currently anticipated by the intentions of the MoU (see comments under paragraph 65). 31. Commercial arrangements for the allocation of capacity are inherently linked to the needs of users (e.g. interconnectors, offshore generators), which we believe will drive the required level of investment. This is why it is important to consider different scenarios for the required level of offshore generation capacity in determining an efficient level of transmission asset investment. 32. The risk that the needs of offshore generators and interconnection capacity are overstated has a potential consequence of stranding of assets and over-investment. 33. The CBA should be based on the primary purpose of the transmission investment and any perceived secondary benefits must be appropriately described. A prime example of reported secondary benefits is the ability of a Supergrid to balance intermittency. We address this issue separately below. 34. The lack of legislative and regulatory framework required to deliver any fully integrated and co-ordinated approach to a Supergrid creates uncertainty. However, we would hope that existing mechanisms might be adapted as necessary to ensure that an incremental and cost efficient approach can deliver a co-ordinated investment plan. 35. The potential challenges of transmission system ownership licensing requirements and assets operation which straddle Member States must be considered. Associated planning and consent issues will need attention. Finally, we note that the technical challenges described above will also have associated risks.

How much would it cost to create a Supergrid and who would pay for it? 36. We consider that the costs of a North Seas offshore Supergrid are likely to be very significant and it is therefore imperative that any such developments are economically justified. 37. High costs are likely to be seen in system upgrades deemed necessary to increase the existing levels of interconnection between Member States. Furthermore, any assessment of costs should include investment required by the onshore network, to ensure it is resilient to offshore generation imports. 38. We note a recent presentation from ENTSO-e on planning16 the grid for 2020 stated that at present the “business case for expansion investment [is] often not stable and attractive enough”. Furthermore, “Innovative financing aids by EU [would be] needed”. It is important that this level of funding does not interfere and undermine current and future merchant plant investment in interconnectors and other assets. Much investment is needed in energy infrastructure and plant across Europe in the next 10 years. Regulatory and cost certainty is paramount to attracting investment. It is also important to consider the potential implications for GB of what might be an innovative approach as it could prove costly and provide little benefit. 16 Presented at the ENTSO-e conference: Towards Electricity Infrastructure, 11/02/2011, Brussels. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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39. Funding of a Supergrid could be both a political and commercial consideration. We would wish to see robust arguments which provide tangible beneﬁts should Member States, including the UK, be asked to contribute to its funding.

40. We believe that the costs of offshore transmission investment must be equitably allocated to offshore system users. Transmission tends to be driven by generation capacity. Offshore transmission will in turn be driven by the capacity requirements of offshore generation. Interconnecting offshore generation and Member States provides additional charging complexity as to which of these should pay for the capacity. However, it remains inappropriate to impose offshore and interconnector costs onto onshore generators unless it can be proven unequivocally that they will use and beneﬁt from the Supergrid.

41. However, we are aware that charging regimes across Member States differ in many aspects and the existing EU tariff guidelines in the context of this level of offshore development may need further consideration.

Will a Supergrid help to balance intermittency of electricity supply?

42. We believe that the role of the Supergrid is to facilitate efﬁcient trade across the EU and progress towards delivering EU renewable energy targets by aiding the connection of offshore wind generation.

43. We do not believe managing intermittency should be the primary objective of the Supergrid. However, as part of an appropriate analysis of the efﬁcient level of interconnection capacity and investment there may be consequential beneﬁts, such as the ability to better manage the consequences of intermittency.

44. We consider that Member State intermittent generation will still require signiﬁcant investment in Member State back-up ﬂexible generation to meet the needs of balancing generation and demand.

45. Independent Member States will each have their own focus on security of supply and greater levels of interconnection are merely a facilitator in addition to local back-up capacity as part of a diverse generation mix.

46. While interconnection has the potential to reduce the level of capital expenditure required on back-up generation, we would be concerned that this beneﬁt might be overstated. It should be possible for interconnection and transmission asset investment to be the subject of a CBA of the potential beneﬁts of reducing required back-up plant.

47. Pöyry’s NEWSIS report findings include some consideration of the economic benefits of greater interconnection. As part of this work, its findings included the observation that periods of calm weather can cover the entire North West Europe region at once. This implies that with a large penetration of wind generation, interconnectors cannot solve the problems of intermittency alone as there would not be sufficient flexible generation, such as hydro, to cover the intermittent generation fluctuations of an integrated European electricity system.

48. Pöyry also found that interconnection can make sense in more localised areas, e.g. between a region with intermittent generation to a region without intermittent generation. Therefore, for the UK, the question should be whether there is a beneﬁt of increased interconnection to allow the export of our own intermittent generation. However, if this is deemed to be of value we note that the level of interconnection will create a cap on this opportunity, i.e. the capacity of planned interconnection with other Member States is currently expected to be well below the current targets for new intermittent generation capacity in the UK.

49. Therefore, we consider that investment in a Supergrid might have potential for economic benefit for the UK in a situation where there is significant investment in intermittent generation. However, the levels of investment in generation, transmission and interconnection and the allocation of costs across Europe might define whether or not these benefits are realised for the UK as whole. The CBA we propose might be used to evaluate the affordability of these benefits.

Will a Supergrid reduce energy prices for consumers and businesses?

50. We consider that there are likely to be high costs to install the required assets but if investment is made to an efﬁcient level there is a potential for beneﬁts to be realised.

51. However, Pöyry’s NEWSIS report states that in all of the scenarios studied, wholesale and retail prices rise signiﬁcantly across all Member States. We consider that in the longer term the Supergrid might provide price equilibrium between Member States, and this is borne out by Pöyry’s ﬁndings.

52. The cost of direct financial support for renewables by individual Member State governments has a significant influence on prices. Variations in support levels will be an important factor to address.

53. Therefore, we conclude it is imperative that the allocation of costs between Member States and system users, and the UK consumer in particular, is made transparent and is justiﬁed by tangible beneﬁts. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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What are the implications for UK energy policy of greater interconnection with other power markets?

54. It is essential to consider the implications of greater interconnection with other European Member States to the UK Electricity Market Reform policy (i.e. contracts for low carbon electricity, capacity payments, carbon price support and an Emissions Performance Standard).

55. We believe that the UK is taking an innovative stance on ensuring that our energy policy will deliver the UK goals of affordability, carbon reduction and security of supply; however, these measures might result in policy differences between the UK and neighbouring Member States. There is the potential that UK policy measures might be undermined if the appropriate balance of neighbouring, and wider Member State, energy policies do not feed into Member State wholesale prices.

56. Indeed, EDF R&D analysis of interconnection levels across Western Europe demonstrates the importance of the relationship between energy policies (e.g. the choice of generation technologies) and interconnection issues. For Europe to reach full market intration these two issues are best addressed in parallel.

Which states are potential partners with the UK in a Supergrid project?

57. We note the existing signatories to the MoU for the North Seas Offshore Grid Initiative (UK, Germany, France, Belgium, Netherlands, Luxembourg, Denmark, Sweden, Ireland, and Norway). These member states are geographically positioned to beneﬁt from a North Seas Supergrid.

58. However, we also consider that there are beneﬁts and issues for the wider European transmission system and that it may at some future point become appropriate to widen the scope of the debate and the Supergrid to other Member States.

How would a Supergrid contribute to the goals of the EU Third Energy Liberalisation Package?

59. The purpose of the EU Third Energy Package is to remove barriers to the free flow of energy, promotion of competition and efficient prices, based on optimal infrastructure and arrangements to facilitate cross-border flows and market integration. The European Supergrid initiative, involving less than half of the Member States, is a separate project not originally envisaged as part of the Third Energy Package. It is large enough to warrant its own directive. We believe combining the two initiatives at this stage is not warranted and may compromise the success of the Third Package, which we believe is the priority.

60. However, different scales of interconnection and offshore development may all make a similar contribution. The appropriate level of investment will only be established through a robust CBA which should be undertaken to ensure that all UK and EU energy policy goals are realised.

Would new institutions be needed to operate and regulate a Supergrid?

61. We believe that ACER should play a role in overseeing the regulation of a Supergrid. However there are a number of framework considerations (described earlier) which will have different implications for the appropriate regulatory bodies e.g. planning and licensing authorities.

62. We would also wish to highlight that ACER’s existing responsibilities and powers are established in European Law and any anticipated changes will need to be re-speciﬁed.

63. We believe that the technical considerations are likely to inﬂuence any decision on how and what party will need to be able to operate an offshore Supergrid. Aspects such as the information systems, despatch instructions and control of both offshore generators and interconnector ﬂows will in the longer term be relevant issues to consider.

64. It is possible that a central body would be required to facilitate a co-ordinated design and operation of a European Supergrid, although this largely depends on how it develops. As we mention above, we are concerned that a prescribed and top-down approach may not take sufﬁcient account of the needs of network users and ultimately GB consumers. It is vital that any co-ordinated body takes full account of the interests of all Supergrid stakeholders.

65. Finally, we note the responsibility under the MoU for the signatories to deliver by June 2011 a baseline overview of policy considerations and constraints for the development of possible future technical grid conﬁgurations and would welcome an understanding of how the views of stakeholders other than ENTSO-e and ACER will be able to contribute to this ongoing work. March 2011 cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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Memorandum submitted by Greenpeace Summary Greenpeace believes that the development of a European supergrid presents a huge opportunity to drive a transition to 100% renewable energy by 2050. The major difference in producing clean energy is that it requires lots of smaller generators, some with variable power output. Some can be located inside the grid, close to where power is used. Small generators include wind turbines, solar panels, micro turbines, fuel cells and co-generation (combined heat and power). The challenge ahead is to integrate new decentralised and renewable power generation sources while phasing out most large-scale, outdated power plants. This will need a new power system architecture. The overall concept balances ﬂuctuations in energy demand and supply to share out power effectively among users. New measures, such as managing the demand from big users or forecasting the weather and using energy storage to cover times with less wind or sun, enable this. Advanced communication and control technologies further help deliver electricity effectively. The key elements of the new power system architecture are micro grids, smart grids and a number of interconnectors or an effective super grid. The three types of systems support each other and interconnect with each other.

1. What are the technical challenges for the development of a European Supergrid? Large-scale integration of renewable electricity in the European grid (68% by 2030 and 99.5% by 2050) is technically feasible with a high level of security of supply, even under the most extreme climatic conditions with low wind and low solar radiation.17 This further confirms the feasibility of a 100% renewable electricity vision. It also strengthens the findings of Greenpeace’s Energy [R]evolution2, which demonstrates that meeting the demand in 2050 with 97% renewable electricity would cost 34% less than under the IEA’s Reference scenario and that by 2030, 68% renewable electricity would generate 1.2 million jobs, 780,000 more than under the Reference scenario. It is vital that there is a clear priority of access for renewables in a European Supergrid. Currently there are no clear priority rules at the European level, including on the interconnections between countries. For example, wind turbines in Germany currently do not have a priority over nuclear power plants in France in providing energy to the European grid.18 As a first priority, national and European regulators should create appropriate framework conditions to enable network upgrades and developments. In addition, to overcome bottlenecks to international transmission, the European Commission should propose financing mechanisms for international transmission projects where the individual business case does not sufficiently reflect the wider economic benefit. Demonstration projects for innovative approaches to onshore grid upgrades and the construction of offshore grids should be supported on the European and national level. These ground-breaking projects are necessary to help develop cross-border networks and test the technical and regulatory conditions. The European Union should focus on the development of smart grid technology and demand management measures through research and development support, streamlining and standardising technology, and the support of demonstration projects.

2. How much would it cost to create a supergrid and who would pay for it? Greenpeace has developed two models of Supergrid: a “Low Grid” model focused on the centre of Europe; Germany, Netherlands, Belgium and France and a “High Grid” model incorporating North Africa. (Please see the attached report, “Battle of the Grids” for more details). “Low Grid”—central europe. This pathway would seek to produce as much renewable energy close to areas with high electricity demand as possible. It is particularly focused on the centre of Europe; Germany, Netherlands, Belgium and France. Solar PV capacity in these areas is increased, even if those solar panels could supply more electricity if installed in the south of Europe. This approach would increase the generation cost per kWh, but lowers the grid investment, which is limited to€74 billion between 2030 and 2050. Security of supply relies less on the electricity grid and long distance transmission. Instead the gas pipelines are used more intensively to transfer biogas from one region to the other, thereby optimising the use of bioenergy as a balancing source. “High Grid”—north africa. This approach would install a maximum of renewable energy sources in areas with the highest output, especially solar power in the South of Europe and interconnections between Europe with North Africa. This pathway would minimise the cost to produce electricity while increasing the amount of electricity to be transferred over long distances through the grid. The result is a higher interconnection cost (an investment of€581 billion between 2030 and 2050), and strong security of supply 24/7 because the super grid capacity exceeds demand. It also balances solar production in the south and wind production in the north of Europe. 17 See Greenpeace ‘Battle of the Grids’ Report, 2011, (http://www.greenpeace.org/international/en/publications/reports/Battle-of- the-grids/), pg. 5. 18 Ibid. pg. 21. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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It should be stressed that between these “Low Grid” and “High Grid” scenarios after 2030, there is a large area of feasibility to combine different levels of grid development and renewable capacities. Over the next decade, European policy needs to be better formulated to provide a clearer vision for the energy mix after 2030 period.

3. Will a supergrid help to balance intermittency of electricity supply?

Power from some renewable plants, such as wind and solar, varies during the day and week. Some see this as an insurmountable problem, because up until now we have relied on coal or nuclear to provide a ﬁxed amount of power at all times. There is a struggle to determine which type of infrastructure or management we choose and which energy mix to favour as we move away from a polluting, carbon intensive energy system.

Some important facts include: — electricity demand ﬂuctuates in a predictable way; — smart management can work with big electricity users, so their peak demand moves to a different part of the day, evening out the load on the overall system; and — electricity from renewable sources can be stored and “dispatched” to where it is needed in a number of ways, using advanced grid technologies.

Wind-rich countries in Europe are already experiencing conﬂict between renewable and conventional power. In Spain, where a lot of wind and solar is now connected to the grid, gas power is stepping in to bridge the gap between demand and supply. This is because gas plants can be switched off or run at reduced power, for example when there is low electricity demand or high wind production. As we move to a mostly renewable electricity sector, gas plants will be needed as backup for times of high demand and low renewable production. Effectively, a kWh from a wind turbine displaces a kWh from a gas plant, avoiding carbon dioxide emissions. Renewable electricity sources such as thermal solar plants (CSP), geothermal, hydro, biomass and biogas can gradually phase out the need for natural gas. (See Case Studies for more). The gas plants and pipelines would then progressively be converted for transporting biogas.

Lines will be needed especially from areas with overproduction, e.g. south of Europe in the summer, to areas with a high demand like Germany. This allows a more efﬁcient use of the installed solar power. In winter months, the opposite could happen, when a large oversupply of wind power is transported from the north of Europe south to population centres. It is common for both wind speeds and solar radiation to vary across Europe concurrently, so interconnecting the variable renewables in effect “smoothes out” the variations at any one location. Adding more grid infrastructure increases security of supply and makes better use of renewable energy sources. It also means backup capacity in Europe can be used more economically because biomass, hydro or gas plants in one region can be transferred to another region.

4. What are the implications for UK energy policy of greater interconnection with other power markets?

A European-wide legal framework is required to build and operate a crossborder transmission system. It should include a regulatory approach for international transmission and continue to harmonise network codes. Europe also requires accelerated standardisation of transmission technology to move towards a truly international power system. Cross-border markets for the day-ahead and intra-day trading of power should be introduced to allow for a truly integrated market capable of exploiting efﬁciencies. At the same time, European energy regulators should allow for the international exchange and accounting of reserve capacity.

5. Would new institutions be needed to operate and regulate a supergrid?

The planning and development of Europe’s power system should be done with an overall view to integrating increasing shares of renewable energy sources. The European Transmission System Operators’ (ENTSO-E) Ten year Network Development Plans should reﬂect the renewable energy forecasts in line with the Renewable Energy Directive.

At the same time, an independent European body should be created to oversee and coordinate European grid planning and developments. Its tasks should include also the development and analysis of long-term scenarios and network development options. March 2011 cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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Memorandum submitted by RWE Npower Renewables UK RWE welcomes the opportunity to respond to the ECC Select Committee inquiry on the Supergrid. We are responding on behalf of RWE companies operating in the UK: — RWE npower owns and operates one of the largest and most diverse portfolios of power generating plant in the UK with over 9,000 megawatts (MW) of large gas, coal and oil-ﬁred power stations and cogeneration plant. Our retail arm, npower, is one of the UK’s leading suppliers of electricity and gas with around six million customers. — RWE npower renewables, the UK subsidiary of RWE Innogy, is one of the UK’s leading renewable energy developers with an operational portfolio in the UK of 535MW and a potential UK development portfolio of over 8,500MW, including wind farms, hydro plant and biomass generation to produce sustainable electricity. — RWE Supply & Trading is one of the leading companies in European energy trading and is responsible for all of RWE’s activities on the international procurement and wholesale markets for energy.

1. What are the technical challenges for the development of a European Supergrid? 1.1 If offshore wind farms are integrated into the interconnection assets there are certain additional electrical challenges, however, none are insurmountable and we expect that the electricity industry would work with suppliers to achieve solutions using “technology of the day”.

2. What risks and uncertainties would a supergrid entail? 2.1 A North Seas supergrid lacks definition but is usually viewed as being something that integrates large volumes of offshore wind. Decarbonisation of the UK and European economies with large volumes of offshore wind by 2020 is understood to be the priority. These offshore wind projects are actively being developed now with a view to meeting 2020 targets. Knowing the points where the large offshore wind farms connect is clearly an early activity as part of the consenting process. The key risks in realising a European Supergrid that integrates large amounts of offshore wind are principally timing, regulatory, commercial and financial. The regulatory risk features heavily given that a strategic network will require harmonisation of disparate electricity markets and potentially international treaties (for example with Norway). The commercial and financial risks relate to the allocation of liabilities for construction and operation and also capex investment constraints, particularly as it is unclear as to who would pay for such infrastructure.

3. How much would it cost to create a supergrid and who would pay for it? 3.1 The cost of the supergrid is signiﬁcant. Estimates in public domain range from the “whole package of infrastructure measures” cost of€209 billion (Greenpeace, 2009), to€45 billion for a nine-country European Supergrid (DLR, 2010) with€34 billion quoted for the initial North Sea supergrid for the initial phases (Friends of Supergrid, 2010) (a 2009 EWEA study also indicated€20 billion over 20 years). It is RWEs view that whilst these costs are high, the beneﬁts of providing energy stability, price control, capital cost savings from integrated infrastructure and realising long term renewable energy targets whilst ensuring security of supply outweigh these costs.

4. Will a supergrid help to balance intermittency of electricity supply? 4.1 With a large increase in the penetration of wind generation on the UK grid system, intermittency causes two effects: one is in relation to market prices and predicted increase in price volatility; the other is in terms of grid stability, affecting the way the grid system operates (system balancing and system reliability). RWEs view is that a supergrid will help the UK to balance electricity supply from intermittent generation sources (notably from variable renewable sources). The use of interconnection between countries including integration with large offshore wind farms will mitigate intermittency risk for wind farm generators by enabling balancing power from other countries to be imported to balance the supply during times of low wind and high demand, and export surplus power to Europe in times of high wind. By increasing the geographical network across Europe also provides a natural hedge and risk mitigation measure by ensuring that wind generation is spread across wind zones and weather systems (i.e. improves negative correlation between wind farm assets). 4.2 This vision was supported by Energy Minister Chris Huhne at UK-Baltic-Nordic Summit held in London, 20 January 2011, where he stated that: “Today we’re stepping up our efforts with our European partners to develop a North Sea electricity supergrid that will help secure our energy supplies in a low carbon way”.

5. Will a supergrid reduce energy prices for consumers and businesses? 5.1 Yes, based on the premise the supergrid will facilitate “market coupling” whereby the Transmission System Operator will automatically sell electricity in the direction of higher market price if a difference in prices exists between two countries. Further, it is envisaged that an integrated supergrid solution will provide cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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capital cost savings scale of efﬁciencies in investment and ultimately lower losses (or even forced shut down). Thus the energy price is reduced to the end user.

6. What are the implications for UK energy policy of greater interconnection with other power markets? 6.1 Currently the UK operates essentially as a grid island to the rest of Europe. Better integration will mean more efﬁcient use of generation resources and improved security and diversity of supply. Essentially UK Energy policy principles as summarised in the draft National Policy Statement for energy (EN-1) would be further encouraged by the existence of a supergrid and advocate low carbon goals for 2050 (2020 Renewable targets are unlikely to be signiﬁcantly promoted by a supergrid as the time horizon for realising a completed supergrid go beyond this target date).

7. Which states are potential partners with the UK in a supergrid project? 7.1 RWE considers that Supergrid should be focussed on Europe starting with countries bordering the North Sea to facilitate the realisation of offshore wind farm deployment in the next 10 years. Beyond this date incorporating other countries to facilitate extension to other renewable technologies, particularly in southern Europe, is expected.

8. How would a supergrid contribute to the goals of the EU Third Energy Liberalisation Package? 8.1 The objectives of security of supply, connecting increased renewables volume and internal market liberalisation will be fostered through realisation of a supergrid. RWE is making signiﬁcant investment in renewable and low carbon electricity generation assets and would welcome efforts to secure long term rights to sale of power via interconnectors.

9. Would new institutions be needed to operate and regulate a supergrid? 9.1 Yes, new independent institutions will be required to operate and regulate a supergrid. A regulatory framework will be needed and codes will need to be aligned between participating countries. RWE envisages jurisdiction problems where both rules issues and alignment issues will be raised and a coherent regulatory regime is need to ensure the entire proposed network gets built. March 2011

Memorandum submitted by Alderney Renewable Energy (ARE) Executive Summary — As a crown dependency sitting outside both Great Britain and the EU, Alderney has hitherto been omitted from broader European plans to create a European supergrid. Nonetheless, ARE believes that its recent experiences in developing an interconnected network between Britain, Alderney and France could serve to inform the Committee’s inquiry into a European Supergrid. — Crown dependencies such as the individual Channel Islands and the Isle of Man are potential partners in a supergrid project. — A European supergrid would serve as a catalyst for broader cooperation across Europe to avoid other Crown dependency projects suffering the same difﬁculties as Alderney in the development of its renewable resources. — A supergrid would allow the UK to mitigate the effects of intermittency just as the proposed France-Alderney-Britain link would enable power from France and Alderney’s tidal power. This would enable French power and Alderney’s tidal power to be pumped into the UK grid in a region (the South Coast) where there is an excess of demand over generation. — Strategic interconnection between existing and potential renewable energy resources will likely encourage and facilitate the faster development and optimum exploitation of hitherto untapped natural energy resources. — A supranational body with an ability to draw EU and non-EU territories together would greatly simplify the regulatory process and lighten the burden on business in negotiating with a number of regulatory authorities.

1. ARE Company Profile 1.1 ARE was founded in 2004 to harvest Alderney’s energy-producing marine resources effectively, economically and safely in a manner that benefits Alderney and is sensitive to the local environment. 1.2 In November 2008 ARE was granted an exclusive 65-year licence to generate electricity from the tidal flows around Alderney. The licence, granted by The States of Alderney and Alderney Commission for Renewable Energy, provides ARE with access to 50% of the island’s territorial waters (3 nautical miles from the coast). The tidal resource in this area is estimated to be capable of generating sufficient electricity to power cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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at least 1 million homes. ARE will partner with leading utility and infrastructure companies to build, own and operate tidal farms in the region. 1.3 In November 2010, ARE forged an agreement with Transmission Capital Ltd to develop an interconnection project between Britain, Alderney and France.

2. Alderney and a European Supergrid 2.1 As a crown dependency sitting outside both Great Britain and the EU, Alderney has hitherto been omitted from broader European plans to create a European supergrid. Nonetheless, ARE believes that its recent experiences in developing an interconnection network between Britain, Alderney and France could serve to inform the Committee’s inquiry. 2.2 Aside from other European countries, crown dependencies such as the individual Channel Islands and the Isle of Man are potential partners in a supergrid project. Given that the Crown dependencies sit outside of existing regulatory frameworks, inclusion in a supergrid would remove the regulatory barriers that currently exist through the need for special arrangements to be made on a per-project basis. 2.3 The territorial waters around Alderney contain one of the world’s largest tidal energy resources, estimated by independent consultants as capable of generating up to 3,000MW of electricity—sufﬁcient to power at least 1 million homes. As Alderney’s peak electricity demand is 1.5MW, the vast majority of this electricity would be exported. Alderney’s tidal resource could therefore potentially be a major contributor in assisting the UK and France to achieve their stated 2020 renewable energy targets of 15% and 23% respectively. 2.4 ARE has faced two particular obstacles in developing this resource: (1) ARE is not eligible to receive the same ﬁnancial incentives as companies based in either Great Britain or the EU to incentivise development of its tidal resource; and (2) Alderney does not fall within EU rules for EU interconnectors and is not a party to the North Seas Countries Offshore Grid Initiative. ARE is therefore faced with developing its tidal resource without the assistance offered to members of the European Union. ARE has had extensive discussions and correspondence at ministerial level with UK and French government departments and is encouraged by the response that it has received.

3. Interconnection Plans 3.1 There are currently no power cables to or from Alderney, although ARE holds the right to export power to both the UK and France and has developed advanced plans for cable connections to both countries. ARE acquired 285MW capacity into the French Grid in November 2008 and in 2010 acquired 2,000MW capacity into the UK grid. Over the summer of 2010 Transmission Capital, an independent transmission company undertook studies which revealed a need for additional transmission capacity between Britain and France. The existing link—conceived over 30 years ago—has insufficient capacity and as a result the price of shipping power across the link has risen to a level which justifies the construction of new capacity. A new link would also benefit security of supply in Britain. 3.2 Having justified a new link, Transmission Capital concluded that a France-Alderney-Britain link would be over £300million/GW cheaper than a direct France-Britain link, with a separate link to carry power from Alderney to Britain. Even if Alderney’s renewable power can flow through France the France-Alderney-Britain project would still be £35million/GW cheaper than a France-Britain power link and separate Alderney-France cables. 3.3 Under these plans, it is envisaged that interconnectors will run from Flamanville in France to Alderney and from Alderney to Fawley on the UK South Coast. This would enable French power and Alderney’s tidal power to be pumped into the UK grid in a region (the South Coast) where there is an excess of demand over generation. This would have the effect of mitigating intermittency on the UK side and assist with meeting peak demand in France.

4. Beneﬁts of Interconnection for New Projects 4.1 Strategic interconnection between existing and potential renewable energy resources will likely encourage and facilitate the faster development and optimum exploitation of those resources. Routing interconnection between Britain and France via Alderney will allow the tidal resources of the island to be developed much more rapidly than would otherwise be the case. Having a grid connection already in place on the island means that generation can be connected economically, even if it is initially built in small blocks, without the delays and costs that would be associated with building a dedicated new transmission infrastructure as part of a tidal project. Using an approach based on the DECC document “Carbon Valuation in UK Policy Appraisal,” we estimate that the resulting acceleration of the tidal power build-out on Alderney would be worth up to £500million/GW.

5. Joined-up Regulation 5.1 In November 2010, Transmission Capital and Alderney Renewable Energy agreed to jointly develop the France-Alderney-Britain project. A proposed regulatory arrangement has been developed and discussions are cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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currently underway with regulatory authorities in Britain and France. Part of this would involve intergovernmental agreements involving the UK, France and Alderney. 5.2 The timescales of the France-Alderney-Britain project are such that it needs to be developed using custom-designed regulatory arrangements and special agreements between the governments and regulators concerned, and work on these is already well advanced. For future similar projects, however, a supranational body with an ability to draw EU and non-EU territories together would greatly simplify the regulatory process and lighten the burden on business in negotiating with a number of regulatory authorities. March 2011

Memorandum submitted by SSE 1.1 SSE welcomes the opportunity to respond to the Energy and Climate Change Committee’s inquiry into a European supergrid. This is a particularly complex topic which will come to prominence in the coming decade and beyond. Due to the complexities and lack of clarity on the scope and scale of any supergrid, the questions posed in the inquiry are very difficult to answer in any detail, due to the number of different possibilities which could be interpreted. 1.2 SSE is supportive of the Memorandum of Understanding which the UK signed with nine other European states back in December 2010, with the prospect of developing a North and Irish Sea sub-sea grid. SSE is particularly interested in the Memorandum and similar developments as it owns and operates the electricity transmission network in the North of Scotland and has a partnership with three Norwegian utilities (E-CO Energi, Agder Energi (AE) and Lyse) and Swedish utility Vattenfall looking into the possibility of a High Voltage Direct Current (HVDC) link between Norway and Scotland.19 1.3 From SSE’s response to the Committee’s specific questions, the key inter-related messages are: 1.3.1 Scale—The required frameworks, institutions and policy support vary with the degree of interconnection, so the scale of a desired potential network would need to be developed. 1.3.2 Finances—The cost of any network, who would pay for the initial development and how the cost would be recouped, would be fundamental to attracting developers and investors to any project. This needs thorough analysis to ensure any benefits outweigh the costs, which will inevitably be borne by consumers. 1.3.3 Regulation—The legislative and regulatory framework in which a potential network would operate both domestically and internationally would need to be defined. The framework would be fundamental to the feasibility of any future projects. 1.3.4 European issues—There would need to be harmonisation of European electricity markets to facilitate significant interconnection. The UK’s current EMR proposals move the UK market further away from harmonisation and the EU’s Third Energy Liberalisation package creates issues for developing bilateral merchant interconnectors. The Treasury’s Carbon Price Support also creates a significant price differential between the UK and the EU and distorts the GB electricity market too significantly, too early. 1.3.5 Strategic Planning—The degree of central planning that a potential network development entails needs to be decided. A planned grid would prove to be more economic and able to exploit economies of scale, but would increase the risk of stranded assets and underutilised capacity. This leads to an inevitable trade-off in which a compromise would need to be determined. 1.3.6 Leadership—The European Commission would be the obvious institution to initiate any European grid development, but there has been a distinct lack of leadership. The UK could lead Europe in a desired direction, by developing a regulatory and legislative framework for the Commission to take forward. 1.4 In conclusion, whilst SSE views interconnection as a valuable tool to enhance security of supply, it cannot be solely relied upon to meet the challenges of intermittent renewable generation in its current form of bilateral interconnectors. In regard to any development of a potential North Sea grid or even a European supergrid, the UK should take the opportunity of a lack of leadership from the European Commission and initiate the development of an appropriate framework to meet the needs of the GB electricity market.

SSE Responses to Speciﬁc Committee Questions (1) What are the technical challenges for the development of a European Supergrid? (2) What risks and uncertainties would a supergrid entail? 2.1 The technical challenges for the development of a supergrid can be overcome, but it must be noted that intermeshed offshore network designs are untried and untested. The real challenges lie with the regulatory and 19 “SSE enters into partnership to investigate electricity interconnector to Norway”, 1 February 2011, http://www.sse.com/PressReleases2011/ElectricityInterconnectorPartnership/ cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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legislative framework, and the other risks associated with large capital projects in the energy sector, including capital, planning and construction risk. 2.2 Solutions to alleviate these risks and others would not be possible until an appropriate regulatory and legislative framework was developed. Yet any attempt for a framework could not be implemented unilaterally or even bilaterally by the UK for the GB electricity market, as any framework would need to be pan-European, where little uniformity exists between markets.

(3) How much would it cost to create a supergrid and who would pay for it? 3.1 SSE is in no doubt that the costs of developing a substantial pan-European grid would be extremely large and uncertain. A thorough cost benefit analysis would need to be undertaken to determine the viability of different network designs. But there would be significant difficulties in accurately anticipating how a network would operate without a defined legislative and regulatory framework in place. Any finalised network design and its operational framework would need to ensure that the consumer gets the best deal. 3.2 This still leaves numerous unanswered queries such as; who pays? Who builds the project? Who is responsible for losses and balancing? Who pays the operational costs? All of which are not possible to provide answers in any significant detail without knowing the scale and scope of any network and the framework in which it would operate.

(4) Will a supergrid help to balance intermittency of electricity supply? 4.1 If a supergrid was developed and operated as a grid rather than a series of interconnectors, then the benefits of grid balancing can offset the challenges of intermittency. If the development is a series of bilateral merchant interconnectors, then they have the ability to balance the grid to a degree, but the benefits may be overstated. There is still a definite benefit to security of supply, but this will be due to irregular shocks to the system, rather than the relative regularity of intermittency issues and interconnection will not be able to replace the need for firm capacity in the UK.

(5) Will a supergrid reduce energy prices for consumers and businesses? 5.1 Maybe, but an assessment of any potential reduction of prices would be answered in the detail of the potential legislative and regulatory framework. Any grid developments that would lead to greater interconnection would likely reduce energy prices by a marginal amount, but this would need to be subject to a detailed cost-beneﬁt analysis of each project to ensure they meet the needs of the GB market and its consumers.

(6) What are the implications for UK energy policy of greater interconnection with other power markets? 6.1 Greater interconnection could have implications for UK energy policy, as the Government’s EMR proposals do not interlink well with other electricity markets. The EMR proposals actually hinder the development of European interconnections as they will put the UK further away from the required uniformity with European markets. With more interconnections there would be a greater pressure to harmonise markets. 6.2 The Treasury’s Carbon Price Support (CPS) mechanism in the EMR proposals will incentivise an increase in interconnections, but not of the desired capacity. The interconnections encouraged by the CPS will lead to CCGTs being built outside of the inﬂuence the GB electricity market, by-passing the CPS payments whilst not meeting the Government’s objective of incentivising low carbon generation in the UK at an additional cost to the consumer.

(7) Which states are potential partners with the UK in a supergrid project? 7.1 The ambition of any development would initially define the potential partners. If it is a significant development, the project would have to be undertaken by the European Commission. But more realistically the most logical partners would be the states neighbouring the North and Irish Sea grids mentioned in the Memorandum of December 2010 and expansion of existing capacity with Continental Europe. 7.2 To avoid the difficulties of matching peak demands and issues with intermittency, more appropriate partners would be with the Scandinavian states, in particular Norway as their hydro and pumped storage capacity has the greater ability to assist the challenges of intermittency of wind generation in the UK. 7.3 An appropriate question to answer would be the types of investors the UK and the EU would be looking to attract, as this would feed into the development of any framework, and how a project would be financed and costs recouped.

(8) How would a supergrid contribute to the goals of the EU Third Energy Liberalisation Package? 8.1 The EU Third Energy Liberalisation Package seeks to create a fully integrated European energy market. It is clear that this market cannot exist without effective grid interconnection and a supergrid would be a key part of this vision. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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8.2 However, the unbundling requirements of the Third Package introduce signiﬁcant barriers to the development of grid interconnection across Europe by potentially limiting the number and type of market players who can become involved in the development of EU grid interconnection. Given the scale of what is required to deliver a supergrid, it would not appear prudent to limit the pool of available investors and more should be done to ensure that the regulatory and legislative framework encourages investment in these projects.

(9) Would new institutions be needed to operate and regulate a supergrid? 9.1 The size and requirements for a body to operate and regulate a potential supergrid is dependent on the scale of any network. The challenges of operating and regulating a new network on a signiﬁcant scale could require a new institution. Yet if the scenario occurs of interconnection developed through bilateral interconnectors then the current mechanisms could be appropriate. March 2011

Supplementary memorandum submitted by SSE Brieﬁng on Interconnectors An interconnector is a connection between electricity transmission grids in separate countries, which allows bidirectional transfer for the import and export of electricity. The preferred technology for interconnectors over 100km long is High Voltage Direct Current (HVDC), which reduces transmission losses, as opposed to High Voltage Alternative Current (HVAC) commonly used in onshore and shorter offshore transmission grids. The technology is well understood after decades of development and is extremely reliable and controllable.

GB Interconnection GB has electricity interconnectors with Northern Ireland, France and the Netherlands with a connection to the Republic of Ireland under construction, due for completion this year.

ELECTRICITY INTERCONNECTOR IN USE ELECTRICITY INTERCONNECTOR UNDER CONSTRUCTION GAS PIPELINE LIQUID NATURAL GAS IMPORT TERMINAL

SCOTLAND-NORTHERN MOYLE INTERCONNECTOR IRELAND PIPIELINE

DATE ESTABLISHED: 2001 DATE ESTABLISHED:1996 LENGTH OF LINK: 63KM LENGTH OF LINK: 135KM CAPACITY: 500MW CAPACITY:8MCM

SCOTLAND - REPUBLIC OF IRELAND PIPELINE

DATE ESTABLISHED: 1993 LENGTH OF LINK: Approx 200km BACTON-BALGZAND LINE CAPACITY: 26mcm DATE ESTABLISHED: 2006 LENGTH OF LINK: 260KM EAST - WEST INTERCONNECTOR CAPACITY: 46MCM

DATE ESTABLISHED: Estimated 2012 LENGTH OF LINK: 261KM CAPACITY: 500MW BRIT NED INTERCONNECTOR

DATE ESTABLISHED: 2011 LENGTH OF LINK: 260KM CAPACITY: 1,000MW

BACTON-ZEEBRUGGE INTERCONNECTOR

DATE ESTABLISHED: 1998 ENGLAND - FRANCE LENGTH OF LINK: 230KM INTERCONNECTOR CAPACITY: 58-74MCM

DATE ESTABLISHED: 1986 LENGTH OF LINK: 70KM CAPACITY: 2,000MW HVDC cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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The Beneﬁts ofInterconnection

Interconnection allows the import or export of electricity according to price differentials between markets. This means that during times of peak demand and/or restricted supply GB can import electricity from markets with excess supply reducing costs for the consumer and the need for additional investment in generation capacity. Conversely, when there are shortages of supply elsewhere, then GB can export electricity when demand is low.

Interconnection assists the UK in meeting the challenges of security of supply, reducing carbon emissions and providing affordable energy for the consumer. Without interconnection it will be more difficult for all member states to meet their 2020 renewable targets. However, for electricity to be transferred it must be available for export at the other end of the interconnector. There may be problems with similar peak demand and weather conditions at both ends of the interconnector negating the potential benefits. This is particularly true when a large anticyclone is positioned across Northern and Western Europe for days or even weeks during the winter. Therefore interconnection will not replace the need for firm capacity to be built in GB, although it will reduce the amount of energy they have will have to generate saving cost and carbon emissions.

Despite these issues of matching intermittent renewable generation across Europe, generation resources in GB and Norway complement each other favourably. In GB there is a large amount of intermittent renewable generation coming onto the system, notably wind, whereas Norway has significant hydro capacity. This is a complementary supply of low carbon electricity especially when combined with pumped storage capacity which provides vital cost-effective energy storage. This offers a powerful symbiotic relationship and can assist the challenges of intermittency in GB caused by significant levels of wind capacity, and provide an export market for renewable electricity at times of low demand. Interconnection with Continental Europe, particularly Norway will ensure a more stable price of electricity for consumers even in unfavourable weather conditions, seasonal variations and time of day system fluctuations.

SSE’s NorwayInterconnectorProject

Last year, SSE signed a partnership agreement with three Norwegian utilities Adger Energi, E-Co Energi and Lyse; and Sweden’s Vattenfall to build an interconnector with a potential capacity of 1200–2000MW, between GB and Norway by 2020. The most direct route would mean that the interconnector would connect with GB in North East Scotland (see below).

Whilst, an assessment of all feasible grid connection points is underway, Scotland is an ideal location for an interconnector because it has a huge renewable energy resource for export. The offshore resources alone are estimated by the Scottish Government at 206 GW allowing development of excess renewable capacity providing an export market for the Scottish economy. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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Barriers to interconnection: The regulatory and policy frameworks for interconnection need to be clarified and made compatible in a series of practical steps. Unless these are successfully tackled, third party financing, essential for deployment of interconnectors, will not be made available. Market design compatibility is also important and there is concern from the European Commission that the Government’s current EMR proposals move the GB market further away from Europe and create issues of state aid. In particular the following issues, which will hinder interconnector development, need to be addressed: — UK policy uncertainty—The uncertainty of Government’s EMR proposals make it difficult for developers to develop interconnector projects. Until this comes to a firm conclusion interconnector investment decisions, like others in the industry are likely to be delayed. — Differing regulatory frameworks—Interconnector regulation between GB and continental Europe needs to be addressed to avoid unexpected situations like the revenue cap that was imposed in the final stages of the Britned interconnector project. If the amount of interconnectors suggested is to be delivered before 2020, then this issue needs to be resolved by 2012 at the latest. — UK regulatory licenses—Current licensing regime (separate licensing needed for interconnectors from regulated business) in GB does not enable utilities with the appropriate experience/financial/technical capability to cost effectively promote interconnection. — Strategic grid development—There is little incentive for utilities to consider developing strategic connections rather than point to point interconnectors. It carries technical and commercial risk which needs extra support to become attractive. A compromise might be for some pre-investment in “hubs” which would facilitate later connection of other offshore grids. — European transmission model—To meet the European Commission’s 2020 target for renewable energy DG Energy has identified an infrastructural gap of€70 billion in terms of delivering transmission infrastructure. The current model in Europe of TSOs delivering interconnection is unable to meet this objective. The Commission must consider different mechanisms to deliver interconnection, including encouraging projects promoted by utilities. — Transmission development funding—The current system of designating projects to be of “European Significance” must be revamped to allow non-TSO led projects to be included and early stage development funding must be channeled to help projects in the first months of their development and fund technical studies. Current TEN-E funding scheme has project maturity as one of its key criteria, once projects are “mature” they shouldn’t need extra funding support. July 2011

Memorandum submitted by the Campaign to Protect Rural England (CPRE) Introduction 1. We welcome the opportunity to submit evidence to the Energy and Climate Change Committee on proposals for a European supergrid. As a leading environmental charity, the Campaign to Protect Rural England (CPRE) has worked to promote and protect the beauty, tranquillity and diversity of rural England by encouraging the sustainable use of land and other natural resources since our formation in 1926. We support the Government’s 2020 and 2050 renewables and carbon targets, have a long-standing interest in the reduction of environmental harms which can arise from electricity production and transmission, and strongly support an increase in offshore electricity transmission where this reduces the need to construct new onshore transmission lines and supports the wider decarbonisation of the power sector.

GeneralComments 2. The value of a supergrid lies in two areas: first, insofar as it can link regions across Europe that have different peak demand periods and different supplies of renewable power, it can contribute positively to the task of balancing the electricity grid on a second-by-second basis. Second, an effective supergrid would enable the UK, along with partners across Europe, to benefit from trading electricity from geographically dispersed renewable resources, including offshore wind in the North Sea; hydro power resources in Scandinavia, the Alps, and Pyrenees; and solar power in southern Europe and North Africa. This could help to address both longer term balancing issues—such as a period of low wind during a cold winter—and allow for bulk imports and exports of power, which could substantially aid the task of achieving an 80% cut in greenhouse gas emissions by 2050. Indeed, the Department for Energy and Climate Change’s 2050 pathways analysis suggests that many effective pathways to 2050 would benefit from substantial interconnection, and that this could dramatically reduce the need to build unabated gas plants to deal with peak demand.20 Several other studies assessing the ability of Europe as a whole to reduce emissions dramatically point to the need for significant 20 See, for example, http://blog.decc.gov.uk/?page_id=264 and in particular, a consensus on the need for significantly greater interconnection with Europe in the ensuring 2050 pathways debate: http://blog.decc.gov.uk/?p=301 cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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interconnection, as part of a wider package of market reforms and a very large increase in demand management measures.21

How much would it cost to create a supergrid and who would pay for it?

3. CPRE has not analysed the costs of creating a supergrid, though we are aware of a number of external analyses of costs, and have had extensive involvement in debates over the cost of onshore transmission. This experience leads us to suggest that any analysis or modelling of the cost of creating a supergrid must take into account a wide range of factors, including: (a) the comparative cost of providing balancing via flexible, probably gas-fired generators over the lifetime of these plants versus providing balancing via interconnection. This should include an assessment of potential costs of gas and its associated delivery infrastructure between now and 2050, bearing in mind the uncertainty over the availability and environmental cost of shale gas; (b) the cost of carbon generated by UK-based peaking plant which would be needed to help balance variable renewables compared to a realistic assessment of the availability and cost of low-carbon balancing plant overseas; and (c) the costs of different configurations for the grid, particularly in relation to the environmental and social costs of opting for onshore transmission reinforcements as compared to the benefits of pursuing undersea and underground connections. Early evidence from National Grid suggests that connecting Round 3 offshore wind farms in an integrated manner compatible with the development of a North Sea section of a future supergrid would cost approximately 25% less than the “point- to-point” approach incentivised by the current regulatory regime. This cost saving would occur due to greater use of assets and a reduction in the total amount of infrastructure required—around half the number of substations and one quarter the distance of overhead lines would be required.22 National Grid’s analysis does not attempt to quantify the value of landscapes, rural character, or reduced impacts on the wider environment in its assessment of savings. It also does not quantify potential savings from the lower likelihood of public opposition through the planning process. These are important factors in the overall cost, both financial and environmental, of different grid options.

Will a supergrid help to balance intermittency of electricity supply?

4. As noted above, the issue of intermittency needs to be understood in relation to two different timescales. First, the need to balance the grid over the very short term, and second, the need to balance the grid over longer periods when wind or solar power production is low due to large-scale weather phenomena, which may occur a small number of times each year. There is some evidence that interconnection can aid in smoothing peak demand where regions that are interconnected have different peaks, which may help with short term balancing. However, the supergrid is more likely to be valuable in coping with longer term intermittency issues, particularly if very wide-spread renewable resources, including Southern European and North African solar power, are connected to the supergrid. Such geographical diversity, along with the technological diversity offered by linking offshore wind with concentrating solar power, could help to address intermittency of supply.23

Conclusion 5. A significant increase in interconnection should play a part in helping the UK to balance variable power from renewables and cut carbon emissions. Interconnection, if done well, can reduce the need to build flexible power plants and reduce the impact of energy infrastructure on the countryside. Expected energy scenarios for 2020 require a significant degree of offshore electricity transmission infrastructure, along with some interconnection. There is therefore an opportunity to design this necessary infrastructure to be compatible with a wider North Sea grid or supergrid at low additional cost. However, interconnection needs to be pursued within a wider context of market reform and should go hand-in-hand with measures to reduce peak demand through load shifting and demand response. March 2011

21 See, for example analysis of the benefits of intra-regional electricity interconnection in Roadmap 2050, available from http://www.roadmap2050.eu/attachments/files/Volume1_fullreport_PressPack.pdf or Pöyry’s analysis of interconnection in Northern Europe, available from http://www.poyry.com/linked/services/pdf/142.pdf. It should be noted that Pöyry’s analysis only covers northern European interconnection, and does not assume wider market reform or wider interconnection with southern Europe or North Africa. 22 These figures are based on internal National Grid analysis, public summaries of which are available from http://www.bwea.com/ pdf/Cables2010/Louise_Wilks.pdf and http://www.businessgreen.com/bg/news/1870000/exclusive-shared-grid-promises-slash- offshore-wind-costs 23 There is some evidence that molten salt heat storage can help concentrating solar power plants to achieve high capacity factors— around 70%. See http://www.nrel.gov/csp/troughnet/thermal_energy_storage.html and http://www.nrel.gov/csp/troughnet/pdfs/ 2007/martin_solar_tres.pdf for examples. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

Ev w30 Energy and Climate Change Committee: Evidence

Memorandum submitted by DONG Energy Executive Summary 1. DONG Energy Company Proﬁle 1.1 DONG Energy is a leading energy company operating in Northern Europe and headquartered in Denmark. It is heavily expanding its UK business in renewable energy and Exploration and Production. It has a strong presence across the energy value chains. These include Exploration and Production, Generation (thermal and renewable), Energy Markets and Sales and Distribution. DONG Energy does not however supply energy to retail customers in the UK.

1.2 By 2020, DONG Energy aims to have reduced its CO2 emissions per kWh of generation by 50%, and by 85% by 2040. In order to achieve these targets, growth has been focussed on the two main areas of Exploration and Production and Renewable Power Generation. The United Kingdom has a major part to play in both areas.

Exploration and Production (E&P) 1.3 DONG Energy is one of the largest acreage holders in the West of Shetland Region and a partner in the recently sanctioned Laggan-Tormore gas development. The company’s ﬁrst operated well in the UK (the Glenlivet gas discovery) was drilled in the West of Shetland in 2009. It has interests in a further six discoveries. Aside from the UK, DONG Energy is the operator of nine licences in Denmark, six in Norway and two in Greenland.

Renewable Power Generation 1.4 DONG Energy is one of the most active offshore wind operators and investors in the United Kingdom. The company currently operates four offshore wind farms (Gunﬂeet Sands 1&2, Barrow and Burbo Bank). It has a stake in a further four sites currently under construction (London Array, Walney1&2 and Lincs). It also possesses a strong pipeline of potential future renewable projects.

Thermal Generation 1.5 In thermal generation, DONG Power UK has recently completed a new CCGT gas ﬁred power station of 824MW output at Severn in South Wales.

2. What are the technical challenges for the development of a European Supergrid? 2.1 DONG Energy does not have the technical expertise on the technology necessary for a European Supergrid and cannot therefore make much comment on the challenges that need to be met. However, we note that HVDC cable technology, which is likely to be necessary for a supergrid, is already available. Indeed, it has been used for interconnections between EU member states and in other areas across the world. Current examples of interconnectors currently under construction or recently operational include: (1) The East-West Interconnector between the UK and Ireland being constructed by EirGrid; and the (2) BritNed interconnector between the UK and the Netherlands, which has recently been constructed by TenneT and National Grid. 2.2 However, extensive use of HVDC technology on the scale envisaged for an offshore supergrid has not previously been attempted. In particular, inclusion of offshore wind farms within the proposed network adds additional complexity to the concept. Even without including connections to offshore wind farms, a supergrid will require interconnection points between cables. Whilst this does not prevent development of a European supergrid, it does increase risk for all parties.

3. What risks and uncertainties would a supergrid entail? 3.1 Establishing a supergrid, (from design to implementation) is a very complex exercise, particularly if the ambition is to achieve a “perfect” solution that is optimal in terms of technical capability and economic efficiency. It will require careful planning and exactly the right path to be plotted through a very long and complex decision tree. One of the biggest risks to a supergrid becoming reality is that the level of complexity could lead to a lack of action. In short, planning for perfection comes at a cost. DONG Energy believes that it is critically important that a way is found for a stepwise development of point-to-point interconnectors, which in turn could develop into a grid. Whilst the concept of a supergrid is a good one, it must not become a barrier to the development of interconnectors. 3.2 There are number of risks and uncertainties that would need to be overcome to allow successful implementation of a supergrid, including: 3.2.1 Regulatory and political risk: The success of a supergrid will require engagement and support from all member states. Given that there will be differential costs and benefits to each member state, this may be difficult to achieve. In particular, there are two main risks that must be considered: firstly, the regulatory and legislative framework in each member state must allow for coordinated development of an offshore network. In the UK at least, this may be difficult to cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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achieve under the existing OFTO arrangements. Secondly, in order to realise the full beneﬁts of a supergrid, offshore wind farms must form an integrated part of the network. This is only likely to be achieved if subsidies are realisable for offshore wind farms independent of the country of origin. That is, if a wind farm produces power in the UK but delivers power in The Netherlands, it must be able to receive green beneﬁt. Without this assurance, it is unlikely that any offshore wind farms would wish to be connected to a supergrid. 3.2.2 Planning and consenting risk: The concept and delivery of a supergrid is complex and will require detailed planning and consents in numerous jurisdictions. In addition to the consents required for the cables, there is a need to coordinate with the consents and timing of construction for the integrated offshore wind farms. Each of the wind farms and their transmission links to shore are complex projects in their own right. Inability to coordinate all aspects of these projects with the development of a supergrid would severely threaten successful delivery. 3.2.3 Technical risks: As noted above, the HVDC technology necessary to implement a supergrid is available and has been used in other projects. However, these examples have been point-to-point interconnectors and not an interconnected network. They have also not included offshore wind farms as an integral part of the network. Construction of a supergrid would require common technical standards to be agreed and implemented to ensure that all component parts work together, even if provided by different technology providers.

4. How much would it cost to create a supergrid and who would pay for it? 4.1 The cost of a supergrid will be highly dependent on the scope and extent of the network and the operational benefits that may be derived. As a general rule, it can be assumed that the capex cost for the transmission assets of a 1GW offshore wind farm are approximately€500 million. The government’s current projection for the UK’s offshore wind delivery is at least 20GW of offshore wind by 2020.24 It can therefore be assumed that the offshore transmission assets for the UK alone will be in the order of€10 billion by 2020. This total could be significantly higher on a Europe-wide basis. Indeed, ENTSO-E has suggested capex estimates of approximately€70 billion depending on the potential designs. 4.2 These estimates are based on independent, “radial” connections for offshore wind farms. If a coordinated approach is taken, significant savings can be made. For example, National Grid25 has indicated that, based on the Gone Green scenarios, an integrated network for the UK’s offshore wind delivery could provide a 25% discount for the UK consumer on the capital cost compared to connecting each offshore wind farm with a dedicated radial connection. 4.3 In addition, ENTSO-E26 has published a report that concluded that the current approach of radial shore- to-shore connections will reach its limits by 2030. The report recommended a coordinated and integrated offshore grid aiming at fewer landing points, accommodating larger and more distant-from-shore wind parks, and efficiently enabling trade between the North Seas countries. Most importantly, the report indicated that such investment could be delivered at a lower cost than an uncoordinated approach. This is because its delivery would involve the installation of fewer assets, resulting in capital cost saving of approximately 10% (or€7 billion). 4.4 The cost of the offshore transmission system would be paid for by the generators and customers who use the network, if the costs are socialised. For an integrated network, it is likely that the costs would need to be recovered through an EU-agreed tariff structure. Importantly, the main gain from interconnector capacity stems from its role as facilitators for trade between markets. Merchant interconnectors could be expected to be financed through rents achieved from power flowing between markets. However, the complexity of the grid and the effect one connection can have on the other means that a potential expansion of a supergrid may deter merchant interconnectors unless a mechanism for compensation of stranded assets is in place.

5. Will a supergrid help to balance intermittency of electricity supply? 5.1 As the proportion of low carbon generation increases on the network, there will be a corresponding requirement to improve flexibility within the system. This will be driven in part by the intermittency of wind generation, but also by the relative inflexibility of nuclear generation and new technologies such as CCS. As such, a high value will be placed not only on flexible thermal plant and demand side response but also on interconnectors.

6. Will a supergrid reduce energy prices for consumers and businesses? 6.1 Given the uncertainty of future oil and gas prices, their link to the UK electricity price and the signiﬁcant changes currently under review in the government’s Electricity Market Reform process, it is difﬁcult to predict the impact of a supergrid on electricity prices. However, increased interconnection can be expected to lead to 24 Renewable Energy Strategy, DECC, July 2009. 25 National Grid response to Offshore Electricity Transmission: Further consultation on the Enduring Regulatory Regime, September 2010. 26 Offshore Grid Development in the North Seas: ENTSO-E views, ENTSO-E, February 2011. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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greater market coupling and harmonisation of electricity prices between linked countries. In the case of the UK, this is likely to lead to lower prices for the electricity consumer. 6.2 In addition, as the expected volume of renewable wind generation increases on the network, there will be a greater requirement for system balancing services. Greater interconnection will also reduce the need for thermal plant as alternative electricity generation can be sourced from other markets.

7. What are the implications for UK energy policy of greater interconnection with other power markets? 7.1 Greater interconnection, and ultimately a supergrid, will facilitate achievement of the UK’s energy policy objectives, including a transition to a low carbon economy and increased security of supply. Interconnection will also lead to harmonisation of electricity prices between energy markets and potentially require a greater degree of regulatory consistency. Greater interconnection with neighbouring markets will also add liquidity to the UK electricity market.

8. Which states are potential partners with the UK in a supergrid project? 8.1 In the ﬁrst instance, the 10 countries that have signed the North Sea Memorandum of Understanding are likely to be potential partners in a supergrid project. These countries are: Belgium, Denmark, France, Germany, Ireland, Luxembourg, the Netherlands, Norway, Sweden and the UK. Following the Nordic-Baltic Summit, where Baltic Energy Ministers working on the Baltic Energy Market Interconnection Plan (BEMIP) and UK energy ministers engaged on the North Seas Offshore Grid initiative agreed to work together, this list could also be extended to include Finland, Iceland, Estonia, Latvia and Lithuania.

9. How would a supergrid contribute to the goals of the EU Third Energy Liberalisation Package? 9.1 Interconnection capacity is the physical pre-requisite for integrated electricity markets. Competition is imported and exported through physical interconnections and the exchange of price signals improves transparency and liquidity. Interconnectors will, however, only contribute to the goals of the liberalisation package if they are used effectively, through explicit and preferably implicit auctions and effective trade of balancing and ancillary services.

10. Would new institutions be needed to operate and regulate a supergrid? 10.1 Regulators play a key role in determining an acceptable investment framework. To the extent that national regulators are unable to provide the necessary investment incentives to TSOs due to the regional allocation of costs and beneﬁts, ACER or other regional regulatory coordination initiatives may be necessary. In due course, a meshed off-shore network may also require new TSO collaboration initiatives for effective operation. April 2011

Memorandum submitted by Centrica Executive Summary 1. Centrica is a leading participant in the GB energy markets. The group is active through British Gas in the retail sector, whilst other group companies engage in energy wholesale trading markets, electricity generation including the development of renewable wind energy, gas production, gas storage and LNG import. We are also active in wholesale energy markets in neighbouring north west European countries as well as in gas and power activities in certain North American markets. 2. The European Supergrid concept has a number of deﬁnitions. Given the terms of reference for this response we have narrowed the scope of our response to an assessment of North (and Irish) Seas supergrid(s) concept. 3. Given the GB OFTO regime is still in its infancy and interconnection with EU MS remains limited, this response, by necessity, is a high level positioning which may change as further information becomes available. Despite this, we trust our response addresses the relevant areas for further development.

Question 1: What are the technical challenges for the development of a European Supergrid? 4. The main consideration is how the supergrid concept will be developed. The Supergrid design and construction could be introduced two ways: a top down mandated and “prescribed design” with strong central control; or an incremental and “evolutionary build” which takes advantage of coordination opportunities between interconnection, offshore wind farm connections and offshore bootstrap transmission lines. 5. Depending on the route, a key question for the technology solution(s) is how much coordination is desirable or needed. Each of the two options above introduces its own challenges. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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6. Centrica is minded to favour the “evolutionary build” model as this allows for better consideration of the needs of the various parties involved, is less likely to lead to stranded assets, and reduces the risk of project delays for planned projects. 7. Manufacturers and those involved in building transmission lines will in principle have more detailed views on the design and construction technical challenges; although we note that there are often vested interests depending on the product offerings of the various manufacturers. At this stage in the discussion it is not possible for Centrica to state a preference for one solution over another e.g. DC versus an AC nodal solution with DC connections. 8. In addition, we note that a large scale roll out of the technologies needed for a supergrid has not yet been attempted anywhere else on this scale. Interoperabilty and standards will need to be considered at a time when innovative solutions may be key to overcoming both technical and commercial issues. 9. Finally, the supply chain and skilled resource constraints should not be underestimated and will contribute to the technical challenges. These challenges are already features of the expansion of the GB offshore grid and may be exacerbated by the introduction of a supergrid in the same timescales.

Question 2: What risks and uncertainties would a supergrid entail? 10. At this stage in the development of the concept the risks and uncertainties are many and varied. We have outlined below the key risk areas: 11. The total costs of a supergrid may outweigh the benefits. We are yet to see a cost benefit analysis that confirms the need for a supergrid and/or the relative merits of a purpose designed (prescriptive) solution or one that evolves from existing offshore wind and interconnection projects. 12. The potential costs of a supergrid together with stranding risk; i.e. oversizing assets that are subsequently not required leaving generators and/or consumers, depending on the construction model, exposed to the financial consequences. The mitigation of such risks will require significant development of both commercial and regulatory frameworks to ensure the solution does not create unnecessary and additional risks for investors. 13. Where the solution requires the integration of interconnection and offshore wind generation there is a potential risk of delay to current/planned offshore wind projects and interconnection projects. A delay to these projects will affect investors’ financing and could also lead to an increase regulatory risks and investor appetite for later projects. 14. The technology may not support the EU Supergrid aspirations, given this offshore level of subsea transmission and interconnected wind farms has never been achieved at this scale before. 15. The necessary regulatory and commercial frameworks that need to be negotiated across the EU Member States should not be underestimated and could be a significant delaying factor. 16. The impact on the supply chain and skilled resources could adversely impact existing transmission and offshore wind projects. E.g. projects competing for scarce cabling, marine resources, skilled labour could drive up costs.

Question 3: How much would it cost to create a supergrid and who would pay for it? 17. We do not have any reliable cost estimates, not least because this depends on the definition of the supergrid. However, it is clear that a supergrid, whether of a “prescribed design” or “evolutionary design” model will be a very expensive initiative. Figures ranging from £30 billion to over £100 billion are quoted for a range of solutions. 18. In any calculation of costs there are a wide range of factors to consider ranging from the size/reach of the supergrid; the resilience requirements of the network design; how much anticipatory spare capacity is built in the early stages; the level of interconnection with other countries and consequential onshore transmission upgrades; design life of the assets; technology used; supply chain constraints etc. In addition, given the substantial investment figures, the financing costs will also be significant and these will be sensitive to the investor’s perceived risks in any such projects. 19. Another related issue is how will the costs (ultimately be borne by electricity consumers) be allocated across Member States, especially when considering that a European supergrid will deliver benefits shared between consumers of different countries. The methodology for cost sharing must be transparent and fair. 20. The inter-transmission system operator compensation mechanism, now established in EU law, is one way of sharing the costs. It is important to note however that the compensation scheme was designed for a system of relative simple flows between two countries across conventional interconnectors and would need significant modifications to deal with flows through a supergrid with multiple countries connected to it. 21. This pan-European compensation scheme essentially says that countries that are net importers ultimately pay those that are net exporters via a centrally administered fund. The GB market has thus far been a net cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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importer, and hence both consumers and generators that pay transmission tariffs already contribute to the inter- TSO compensation fund. There is a plethora of commercial (charging) and regulatory arrangements to be addressed as part of this harmonisation process. 22. Given the recent launch of the GB OFTO regime it is unclear how an interconnector, that also connects an offshore windfarm, will be treated. Solutions to these issues will need to be addressed. 23. The Generator Build option within the OFTO regime provides developers with the option of building their own transmission assets, thus providing certainty of connection to the generating assets. Arrangements within a supergrid project must continue to provide generators with similar levels of certainty that the appropriate assets would be connected in timescales that meet developer needs, an also that the assets would be available to fully export power at all times. 24. Careful consideration of the commercial and regulatory arrangements will be needed to manage the fluctuating demand for capacity from both the windfarm generators and the interconnectors within the supergrid model. Generation demand will vary according to the level of wind generation at any moment in time. Meanwhile interconnector demand will vary according to system demands and price differences in the connected countries. The supergrid operational arrangements should not be designed in such a way that a grid system operator can chose to limit windfarm access at times of high flows on the interconnector part of the supergrid. The value of exports from connected windfarms to the supergrid owner would have to be higher than the value of power transfer over the interconnector, otherwise renewable generation’s access would be curtailed in favour of cross border interconnector flows. 25. Similarly the technical ability to connect interconnectors and wind generation together has not yet been proven at sufficiently high voltage. Furthermore, connecting existing windfarms and interconnectors will not be possible without prohibitively high costs for a redesign and recabling of assets. This is due to the technology used—HVDC Light or similar would have to be the technology for a supergrid and existing lines do not utilise this at the moment.

Question 4: Will a supergrid help to balance intermittency of electricity supply? 26. A supergrid may potentially help to balance intermittency. It could be argued however that increased level of interconnection can also do this without the need to incorporate into a supergrid. 27. The cause of intermittency is strongly linked to weather patterns. Where weather patterns are local, then importing/exporting with other areas and market can clearly help balance supplies. Where weather patterns have a larger impact, for example an extended, large anti-cyclone, then the ability of interconnection and supergrids to manage the intermittency problems are reduced. More analysis of weather fronts and the relative wind diversity (or not) they deliver is required. 28. Interconnectors already assist in balancing electricity supplies within Member States, including intermittent supplies. Different time zones, lifestyles and uses of electricity contribute to diversifying and elongating peak demand periods, which help with balancing. However, interconnection can also add more uncertainty for the grid system operator, in particular it can expose them to swings or changes in direction of electricity ﬂows on the interconnectors. For example, during an extended, wide anti-cyclone (low wind scenario across several member states) it is clear that robust back up generation requirements will need to remain a major feature of the GB system to provide security of supply to the local market. 29. Increased renewable penetration, including intermittent generation, is expected to be a feature in a number of national markets, and hence reliance of cross-border connections should be carefully managed/ considered. Signiﬁcantly more modelling and analysis of the various impacts are required.

Question 5: Will a supergrid reduce energy prices for consumers and businesses? 30. This is not possible to answer with the level of unknown factors discussed above. It is clear that a full GB impact assessment would be necessary at an early stage to ascertain the customer impacts and ensure no unintended consequences arise. That said, the increased infrastructure needs are unlikely to lead to reduced consumer prices at least in the near term, regardless of whether the investment is made by a regulated company or via a merchant project. It is however, possible they will deliver costs that, although higher than the current baseline, are lower than they would have been without a supergrid. As previously indicated we believe that a “prescriptive design” supergrid initiative could lead to higher costs and hence prices than an “evolutionary” approach as the former carries an increased risk of stranded assets and/or under utilised assets. 31. There are potential beneﬁts in the longer term from increased interconnection with other markets through the market coupling trading model. Market coupling, in principle, should lead to price convergence across markets, with lower cost energy being transported to areas of high prices. By its very nature this would mean any area with lower prices traditionally would see higher prices as the result of a cross-border connection and vice versa. However, these connections could be through interconnections rather than a supergrid. 32. Further analysis would be needed to assess the balance between the increase in consumer prices due to transmission investment and a downward pressure from market coupling. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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Question 6: What are the implications for UK energy policy of greater interconnection with other power markets? 33. At this stage, it is difﬁcult to assess and measure what the implication for UK energy policy will be from greater interconnection. Currently, GB has three interconnectors, connecting France, Ireland and more recently the Netherlands providing a GB total of around 2.5GW of interconnection (c.f a peak demand for GB of c60GW). There are a number of credible interconnector projects at various stages of development to deliver links to Belgium, Norway, France and the Irish Single Electricity Market which could see interconnection at c10GW by 2020. 34. A major concern is the interaction with the Electricity Markets Review and policy options. It is not clear whether adequate consideration has been given to interconnection and market price convergence through a form of market coupling. 35. The implications for UK energy policy from the development of a supergrid depend strongly on whether this is built via a “prescriptive design” or “evolutionary” approach. The former risks seeing transmission based decisions over-riding generator concerns for location or technologies. The latter should lead to less unexpected impacts as the growth in offshore wind generation and some increased generation is already taken into account by market parties. 36. The implications for UK energy policy are to some extent already contained within the EU internal energy market initiative. The third energy package has laid down the legislative basis, and pan-European network codes will be developed over the coming three years to further enhance cross-border arrangements and improve market integration across the EU. 37. With the introduction of a supergrid, the issue of transmission charging will need to be considered. Interconnectors are no longer subject to transmission charging. Meanwhile as stated above, GB generators do face transmission charges (unlike the majority of European generators). How ﬂows across a supergrid are to be treated for transmission and balancing charges must therefore be assessed. 38. Finally, how offshore generators, connected to more than one Member State, should interact with the onshore transmission system operators needs consideration, in particular whether a generator should be given a choice to which market it sends it generated power. Furthermore should this be a static, permanent decision, or should a generator be allowed to change its behaviour according to daily market conditions and different national market prices?

Question 7: Which states are potential partners with the UK in a supergrid project? 39. In the early stages, we would expect a supergrid to connect the GB market with its immediate geographic neighbours. The ﬁrst zones being selected/determined according to the needs of market participants and a thorough cost-beneﬁt analysis. As time progresses the supergrid could potentially be expanded. 40. Regardless of who the potential partners in a supergrid are, the issue of cost allocation for this expensive investment must be fully addressed.

Question 8: How would a supergrid contribute to the goals of the EU Third Energy Liberalisation Package? 41. A supergrid can help contribute to the goals of the EU energy policy by increasing cross-border connections, assisting in the development and connection of renewable energy, the goals of sustainability and security of supply. A supergrid can thus help contribute to the goals of the third energy package, but should not be seen as an essential element or relied upon as major contributor to further liberalisation in electricity markets.

Question 9: Would new institutions be needed to operate and regulate a supergrid? 42. As noted above, some form of coordination may be desirable even for an incremental build model. The North Seas Initiative may be a good platform at which to discuss this issue in more detail. 43. However we do not believe that new institutions would be needed to operate or regulate a supergrid. In our opinion it would be more efﬁcient to require the relevant grid operators and national regulators to cooperate along the lines they do currently. The third package has already laid the foundation for increased coordination between the transmission system operators and between national regulatory authorities, and also created pan- European coordination institutions with ENTSO-E and ACER.

Conclusion 44. In summary, Centrica believes that the most appropriate model for a supergrid is that of the “evolutionary build” model rather than a “prescribed design” model, as this we feel would allow for better consideration of the needs of the range of different parties involved, is less likely to lead to stranded assets and hence better cost mitigation. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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45. The technical and engineering challenges of a supergrid project should not be underestimated. As the first such large scale project, there are limited lessons to be learned from elsewhere. The development of a supergrid project would be a long term investment and commitment. 46. Of importance to companies already investing in offshore wind projects or interconnectors is that a supergrid initiative does not cause delay to investments already commenced, nor cause unnecessary concern in the investor community to slow down future projects in these areas. 47. The regulatory, commercial and market arrangement challenges will also be great. Among the plethora of issues that would need to be addressed is the required harmonisation of rules and cost allocation of the investment between the different countries involved. 48. Meanwhile there are a number of areas which require further assessment in order to better understand the potential impact, both costs and benefits, of a supergrid. Alongside the technical, commercial and regulatory challenges must also be considered the areas of security of supply; the generation mix, renewable energy and low carbon objectives; and market competitiveness. Until a detailed assessment is done, it is at this stage difficult to even estimate the costs and benefits to the GB electricity market, the wider economy and consumers. April 2011

Memorandum submitted by the IMarEST Offshore Renewables Special Interest Group 1. The Institute of Marine Engineering Science and Technology (IMarEST) Established in London in 1889, is the leading international membership body and learned society for marine professionals, with over 15,000 members worldwide. The IMarEST has a strong international presence with an extensive marine network of 50 international branches, afﬁliations with major marine societies around the world, representation on the key marine technical committees and non-governmental status at the International Maritime Organization (IMO).

2. IMarEST and Climate Change The Institute of Marine Engineering, Science and Technology recognises that climate change is the most important threat facing humanity. The global community, represented through the United Nations Framework Convention on Climate Change (UNFCCC) and informed by the Intergovernmental Panel on Climate Change (IPCC), now unequivocally recognises that emissions of greenhouse gases and land use changes are resulting in significant warming of the atmosphere and the oceans. As a consequence, there is widespread acceptance of the need to mitigate global warming through control of emissions of greenhouse gases and to plan adaptation to the impacts of a changing climate. As an international professional body representing the marine sector the IMarEST supports strategies and technologies for adaptation to the consequences of climate change. In addition the IMarEST is committed to: — Encouraging recognition that human activities are contributing to global climate change, and that regional changes are likely to be significant. — Fostering a responsible and knowledgeable attitude to climate change matters. — Contributing to the climate change debate through representation at bodies such as the International Maritime Organization (IMO), the Intergovernmental Panel on Climate Change (IPCC), and the Intergovernmental Oceanographic Commission (IOC) of UNESCO. — Providing objective and independent expert advice to governments and intergovernmental bodies on marine aspects of climate change and climate change impacts. — Supporting marine engineering and technological solutions with significant potential to achieve long-term reductions in anthropogenic greenhouse gas emissions. — Showing leadership in support of the development and deployment of clean marine energy technologies and energy efficiency. IMarEST Offshore Renewables SIG supports the creation of a SuperGrid as a key European initiative to help address the progression of Climate Change.

3. Introduction 3.1 In 2009 the European Union (EU) and the G8 Heads of Government committed their countries to an 80% reduction in Greenhouse Gas emissions by 2050. International consensus to reach this target requires the EU to achieve a “nearly zero-carbon power supply”. 3.2 This will require an open market in electricity, alongside an upgraded and extended trans-national transmission network. Investment in such a transmission network will enable the balancing of renewable energy generation (also enabling greater grid penetration) required to decarbonise generation and maintain security of supply across the EU. This cannot be achieved by individual European countries in isolation. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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4. The European SuperGrid 4.1 The envisaged European SuperGrid will result in multi sub-sea transmission cables across the waters of European States, associated offshore transmission hubs and large scale renewable energy generation developments (mostly offshore wind farms).

5. Existing Policy and Regulatory Frameworks 5.1 The existence of the renewable energy target of the new Directive for 2020 will not, by itself, promote significant interconnection between Member States. 5.2 The interconnections required for the establishment of a SuperGrid need specific European wide cooperation, planning and the establishment of necessary European wide systems and structures. 5.3 A lack of interconnection combined with the establishment of significant renewable generation capacity will lead to a dramatic reduction in the efficacy of the renewable energy plant, which will severely hinder a zero carbon goal. 5.4 To enable the creation of a SuperGrid, to achieve the 2050 decarbonisation targets, current regulatory and policy measures are insufficient. IMarEST Offshore Renewables SIG therefore fully supports the recognition that new European regulatory and policy frameworks need to be established to set up the required European wide rules and procedures for the development of the SuperGrid and the required supply chain. 5.5 IMarEST Offshore Renewables SIG also supports the Memorandum of Understanding signed on 3 December by the 10 countries supporting the North Seas Countries Offshore Grid Development Initiative (NSCOGI).

6. SuperGrid Evolution 6.1 Current environment: — The UK wants to connect a further 25GW of offshore wind to its already congested networks by 2020. — Germany plans to build 25GW of offshore wind generation by 2025–30 and the existing grids in Northern Germany are already largely congested with on-shore wind generation. — Norway wants to trade up to 25GW of hydro generation in markets where prices are higher and has signiﬁcant untapped hydro generation resources. — Belgium’s Renewable Energy plans include at least 2GW of offshore wind generation. — The Netherlands’s Renewable Energy plans include at least 2GW of offshore wind generation by 2020. 6.2 The ﬁrst evolutionary step to creating the SuperGrid should seek to take advantage of the current ‘state of play’ while providing a solid structure to enable future development.

7. Technology 7.1 A key concept put forward for the SuperGrid is the SuperNode. A SuperNode interconnects a number of DC links together with wind parks via a small islanded AC network (Node). 7.2 This concept is largely based on technology existing today. As of today there is much experience with DC links interconnecting two AC systems. Most of the existing DC links are equipped with Line Commutated Converters (LCC) based on thyristor technology. However, there is quite a number of HVDC links operating or under construction, which are based on Voltage Sourced Converter technology (VSC). The development needed to build SuperNodes is mainly in the field of control and protection for the islanded AC network, which includes frequency control as well as fault detection and fault clearing strategies. 7.3 The preferred DC transmission technology for building SuperNodes is VSC. This is because a VSC transmission system can generate and maintain the AC voltage at the node with respect to amplitude and frequency, a feature also referred to as black start capability. As long as there are VSC systems providing sufficient short circuit power available at the AC node, LCC based HVDC transmission can also be connected. The concept of VSC transmission controlling islanded AC networks will be demonstrated by the first HVDC connected wind parks in the North Sea which are currently under construction. 7.4 There are also some disadvantages associated with the concept of SuperNode including the number of AC/DC and DC/AC conversions necessary. The power converters needed are costly; require relatively expensive space on offshore platforms and cause extra power losses. Eliminating some of the power converters requires HVDC links to be interconnected on the DC side forming HVDC multi-terminal systems or grids. There are only very few HVDC systems having three LCC terminals today which are operated under specific conditions. In general, larger multi-terminal systems have to be considered a new field of technology with the first projects being already under discussion. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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7.5 The most important step needed to develop HVDC grids further is the aspect of interoperability of different individual projects and technologies of different manufacturers. Interoperability requires standardization of the basic principles of design and operation of HVDC grids. 7.6 In order to standardize HVDC grids, some fundamental planning criteria need to be deﬁned. Key questions: — What applications should be covered? (e.g.: radial or meshed topologies, transmission distances, character and requirements of the AC systems to be connected). — What operating conditions should be covered? (e.g.: system contingencies, future expandability, communication for control and protection). — What are typical performance requirements? (e.g.: reliability, power losses, time to detect and clear faults). 7.7 Important questions to be answered with respect to HVDC grid standardization include: — Standardization of DC voltage levels. — Concepts for interconnecting local and inter area DC grids. — DC grid topologies. — Control and protection principles. — Fault behaviour. — Typical block sizes for converter stations. 7.8 A number of key network components need to be developed. Investors should be provided with clear guidelines on how to specify the equipment for a multi vendor HVDC grid. Such guidelines are normally summarized in functional speciﬁcations and are needed for components such as: — AC/DC Converters. — Cables. — DC Overhead Lines. — DC Chopper. — Charging Resistors. — DC/DC Converters. — DC Circuit Breakers. — Communication for network control and protection.

8. Policy and Regulatory Framework Requirements for the SuperGrid 8.1 In order to help the process of developing a stable regulatory framework for the European SuperGrid, IMarEST Offshore Renewables SIG proposes the implementation of the following general principles that should evolve: 8.2 A Single Planner: A single Grid Code for the SuperGrid: Standardisation and interoperability are major steps required to achieve the SuperGrid. Such a new Grid Code should be proposed by a single entity responsible for grid planning with the agreement of the EC and after consultation with all the interested stakeholders. The new Grid Code will immediately need to start focusing on offshore wind investments. 8.3 A Single European Regulator: The EC should create a single EU regulator. In order to function effectively, the SuperGrid will need to be a Europe wide integrated network and not a collection of individual interconnections between European states. It therefore needs to be designed taking into account the entire EU and so its regulatory framework also needs to be European wide.

9. Qualitative Beneﬁts The beneﬁts of the SuperGrid are seen as: — Reducing wastage. Without a grid, electricity supply systems waste energy and this is particularly true with renewable forms of energy. If for example, the wind is blowing strongly in Scotland, producing more electricity than the local people can use, that surplus energy is simply wasted unless it can be moved to places where it is needed. If there were affordable systems for bulk storage of electricity, that would make a difference, but it would not remove the need to move electricity from areas of surplus to areas of need. — Accessing sources of renewable energy. Without a transmission grid, it would not be possible to take advantage of the large amounts of energy that may be obtained from large scale but remote sources of renewable electricity such as wave farms, offshore wind farms, tidal lagoons, tidal stream generators and large scale solar power. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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— Opening up new sources of energy. A related point is that a large-scale transmission grid can open up entirely new sources of energy that might not otherwise be considered. For example, there is potential to import geothermal energy into the UK from Iceland via a submarine HVDC transmission line. — Smoothing out variations in supply and demand. Another advantage of transmission grids is that, if they cover a large area like Europe, they reduce the variability of energy sources such as wind. The wind may stop blowing in any one spot but it is very rare for it to stop blowing everywhere across an area the size of a continent. Without a large-scale grid, it may be necessary to maintain conventional power stations on spinning reserve to supply electricity at short notice if the wind drops, and this spinning reserve is wasteful. In a similar way, large- scale grids can help to smooth out variations in demand. — Reducing the need for plant margin. A transmission grid helps to reduce the amount of plant margin that is required—the difference between actual generating capacity in any area and the theoretical minimum generating capacity. This is because a large-scale grid smooths out much of the variability in electricity supply and demand and because spare generating capacity that is needed to meet contingencies can be shared across a relatively wide area, thus reducing the amount that is allocated to any one area. — Security of supply. A related point is that large-scale transmission grids help to ensure the security of electricity supplies in any one area. This is because any local shortage of electricity or local peak in demand can almost always be met from one or more other areas where there is spare capacity.

10. Social and Economical Benefits The development of the SuperGrid will provide social and economical welfare to Europe. 10.1 Energy prices will be more stable and increase by less than would be the case without the SuperGrid, since the latter will help exploiting local, low cost, low carbon and inextinguishable energy resources. 10.2 The SuperGrid will also introduce additional demand of the marine workforce needed to implement such a grid over the next decades. It will create a global opportunity for companies to develop sustainable offshore energy technology. This type of integrated AC/DC grid will be a template for what will be needed later in the rest of the world, particularly US and China. 10.3 In order to ensure the Supply Chain can call upon such a marine workforce, a policy needs to be developed to attract new and in particular young engineers to join the industry. Education at university and all technical, including maritime, levels need to be mobilised to ensure a timely inflow of skilled staff and workers. IMarEST will support the necessary training and education schemes. Research and development programs have also to be implemented in a timely manner. Experience and skills will be the backbone of this industry. IMarEST Offshore Renewables SIG supports the creation of a SuperGrid as a key European initiative to help address the progression of Climate Change whilst recognising the added benefits such a SuperGrid will bring. April 2011

Memorandum submitted by Mainstream Renewable Power 1. Foreword 1.1 Mainstream Renewable Power is a leading energy company developing renewable energy projects across several continents, including Europe, Africa, North and South America. The Company expects to be a major provider of renewable capacity for the UK and has a development pipeline in excess of 5000MW in the EU. In the UK, we are developing two large offshore wind projects. In Scottish territorial waters, we are developing the 450MW Neart Na Gaoithe power plant. Through the SMart Wind consortium, we are developing the 4000MW Hornsea Round 3 Zone with our partners, Siemens Project Ventures. In the German North Sea, we are developing the 1000MW Horizont site. 1.2 Supergrid is the future electricity system that will enable the UK and Europe to connect their electricity networks and help create a single market in electricity. This High Voltage DC interconnected and “meshed” network will make possible the generation and sale of renewable electricity across countries, enhancing the 20th century AC networks that supplied power to individual states. It will come to be the transmission backbone of Europe’s decarbonised power sector. 1.3 In 2010, 20 of Europe’s leading companies joined forces to create the Friends of the Supergrid (FOSG) to make the case for the earliest possible deployment of Supergrid, with a ﬁrst Phase linking the UK, Norway, Germany and Belgium to be undertaken before 2020, in part to enable the development of the very large amounts of offshore wind in the North Sea planned for commissioning before that date. Mainstream Renewable Power is a founding member of FOSG. Our submission should be read in conjunction with theirs. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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1.4 The UK government has helped to create the North Seas Countries’ Offshore Grids Initiative (NSCOGI) together with nine other European countries. The Group’s Memorandum of Understanding, published in December 2010, commits the members to develop the regulatory, ﬁnancial and technical frameworks that will allow the development of an offshore interconnected grid in the North Sea; in essence, the ﬁrst Phase of Supergrid.

2. Executive Summary 2.1 The development of the Supergrid is the next stage in helping to meet the UK’s strategic energy requirements. Supergrid will, first, deliver the benefits of the UK’s new sources of electricity generation to consumers within an appropriate envelope of security and efficiency, and second, facilitate the creation of an open market in electricity in the EU. 2.2 Supergrid will: — Provide additional capacity for the UK grid as the country expands its demand for electricity. — Help deliver increased energy security to the UK. — Lower the cost of electricity. — Enable deployment at scale of technology already on the market. — Deeply embed long-term supply chain jobs and investment in the UK. — Create opportunities to trade electricity with neighbouring states. 2.3 Existing interconnection schemes will not provide the benefits to the UK grid and to consumers that a meshed interconnected network will. Without developing an interconnected network with its neighbours, the UK will face significant challenges to provide secure, decarbonised and competitively priced electricity to consumers without considerable onshore works associated with storage, grid enhancement and balancing and reserve requirements. 2.4 Crucially, without the development of Supergrid’s first phase, the UK will not be able to connect sufficient sources of offshore generation to the national grid in time to meet the country’s binding 2020 Renewable Energy targets.

3. Supergrid:The Opportunity From 2011 to 2020 3.1 The UK is renewing its electricity generation fleet at an unprecedented rate, driven in part by policy goals to decarbonise the production of electricity and encourage renewable and other low carbon generation; and also because the fleet is ageing and drawing to the end of its operational life. A large share of new electricity production will come from plant with variable output, principally wind energy. 3.2 Since 2005 successive UK governments have encouraged the development of offshore wind, again to take advantage of the UK’s significant marine energy resources, and to leverage the country’s offshore skills gained in oil and gas production. 3.3 Offshore wind development has been licensed in a series of Rounds. In 2009 The Crown Estate, who have administered the licensing process, awarded 32GW of offshore wind development in a number of Zones around the UK, comprising the third Round of the ongoing process. In total, some 50GW of offshore wind sites have been awarded by The Crown Estate, with 1.4GW in operation, rising to over 2GW by mid 2011, making the UK the global leader in harnessing this form of energy production. 3.4 In 2010 FOSG proposed a first Phase of Supergrid linking the UK, Norway, Germany and the Low Countries.27 Without the development of this first Phase by 2020 it is very difficult to envisage how the UK will be able to connect sufficient sources of offshore generation to the national grid in time to meet the country’s binding 2020 Renewable Energy targets. In addition, the current regulatory framework for offshore grid connection does not incentivise interconnection, and will instead deliver a series of point to point connections unsuited for future interconnection. 3.5 The cable technology is either currently available, or will be available in time to deliver an interconnected network by 2020. The supply chain, which has already developed significant capacity in the last year in response to the UK government’s clear policy support for the development of offshore wind energy, is positioned to deliver the additional capacity required for the construction and operation of the first Phase of Supergrid. Much of this activity will take place in the UK. 3.6 The UK government has already indicated its support for North Sea interconnection through its membership of the North Seas Countries’ Grid Initiative (NSCOGI). The FOSG first Phase proposal presents the NSCOGI countries with the potential to create the first stage of a large and secure network taking electricity generation from the North Sea to load centres across Europe. In addition, it will enable the UK to trade electricity across the NSCOGI markets. 27 http://www.friendsofthesupergrid.eu/position_papers_proposals.aspx cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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From 2020 to 2050

3.7 In 2010, the UK Department of Energy and Climate Change, the Scottish and Welsh governments, the Energy Technology Institute, The Crown Estate and a range of companies including Mainstream, commissioned the Offshore Valuation Report.28 The Report’s objective was to determine the potential economic beneﬁts to the UK of developing its practical marine renewable energy resource. Undertaken by the Boston Consulting Group, the Report established that by developing 30% of this resource by 2050: — the UK could be producing the electricity equivalent of 1billion barrels of oil a year making it a net exporter of electricity; — the income generated to the UK from this production would exceed £60 billion annually; and — the UK would create 145,000 new jobs.

In this mid-range scenario the UK will have developed 170GW of marine renewables by 2050. In the high scenario, in which the UK exploits 76% of this resource to develop 400GW of marine energy and become a net energy exporter, the annual revenues to the UK exceed £160 billion. In this latter scenario—where the EU has adopted a 100% renewable energy target for 2050—the total installed capacity for offshore wind in Europe could exceed 1000GW. Supergrid will be critical to bringing this power to market.

3.8 In order to fully exploit this resource—which has the potential to exceed domestic demand many times over—the Report recommended that the UK take a leadership position in the development of an integrated and interconnected Supergrid linking the UK’s centres of marine renewable production with customers in this country and on the continent.

3.9 The Offshore Valuation Report is consistent with a number of other pieces of research published in the last year, each examining aspects of UK and EU policy which commits us to reduce GHG emissions by 80–90% by 2050. One of the most comprehensive is the European Climate Foundation’s 2050 Roadmap29 which posits a range of credible future energy mixes in Europe, from 60% to 100% renewable energy, all with a lower or similar levelized cost of energy to today, and all requiring a signiﬁcant degree of interconnection within European electricity markets.

3.10 The ECF Report recommends that “a large increase in the interconnection of electricity markets” is a priority goal for the next 5 to 10 years. For the UK, the opportunity presented by the early adoption of this grid network is multifaceted: — it will deliver “firm” power from variable generation sources, by aggregating multiple sources over an integrated Europe-wide network; — in its first Phase it will enable the UK to fully exploit the potential presented by its 2020 offshore wind targets; and — it will facilitate the further development of the UK’s marine renewables sector after 2020, and consolidate the country’s global leadership position in the offshore energy supply chain with significant export opportunities.

3.11 To enable the country to reap the full beneﬁts of these opportunities the UK government needs, as a matter of policy, to facilitate the development of the ﬁrst Phase of this network by 2020.

4. Supergrid:The Challenges

4.1 Supergrid is not just about increased interconnection between the UK and other European countries. It has to address the detailed technical, operational, market and regulatory aspects related to the integration of wind power and other renewables in Europe, together with the challenges of operating a pan-European grid that delivers secure and low cost supplies of electricity to consumers, and enables the decarbonisation of the power sector.

4.2 It is important to agree what is meant by Supergrid. Supergrid is the solution to an energy challenge and in order to define the solution, we first need to define the challenge. In broad terms, it is ensuring that Europe’s renewable electrical resource is harnessed to the maximum extent, at most efficient cost and in an integrated manner.

4.3 Having done this, we have a set of requirements which can be placed on the Europe-wide electrical system. Some of these will be met by reinforcement of existing networks, which may not otherwise have happened; some will be met by additional network expansion; and others by overlaying new circuits on top of the existing and planned European grid system. All of this will have a timeline associated with it. 28 http://www.offshorevaluation.org/ Offshore Valuation BCG on behalf of DECC and Ors (2010) 29 http://www.europeanclimate.org/ ECF2050 Roadmap Vol. 1 McKinsey & Co and Ors (2010) cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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4.4 Without this overview, long term objective and level of detail, network development will continue to occur as it does now, centred on the needs of geographic areas, and coordinated (which is very different to integrated) where necessary; with increased interconnection pursued on a case by case basis.30

4.5 This may deliver the Supergrid that we seek, capable of meeting the above objectives. However, the odds of it doing so are very low, compared with the alternative approach of an initiative led by the UK in conjunction with our North Sea neighbours, within the framework of a liberalised and competitive European electricity market.

Technical

4.6 There are cable and connection technologies available today that can deliver an interconnected network. The main challenge for the development of Supergrid is the agreement of a common set of connection standards. It is important that a framework is rapidly established to ensure that developments, either on a project speciﬁc or integrated basis, are pursued on a consistent and coherent technical base. We refer the Committee to the more detailed analysis in the response of FOSG.

Operational

4.7 Electricity systems need to be operated, and the operational standards, processes, procedures and regulations need to be established to allow a Europe-wide operation of the Supergrid. This may require a new Independent System Operator (“ISO”) to oversee the operation of the Supergrid, while existing operators actually operate it, on a devolved regional basis.

4.8 Further work still needs to be done on the development and harmonisation of grid, operating and planning Codes to ensure that a robust technical platform exists to underpin Supergrid operation.

4.9 Fundamental operational issues such as standing and spinning reserve levels, reactive power requirements, fault level coordination, in-feed loss standards will all need review in the light of increased interconnection under a Supergrid.

Regulatory

4.10 The European regulatory framework needs to evolve in order to deal effectively with the establishment of a pan European Supergrid. To create a single electricity market we need to address questions of jurisdiction, governance, stakeholder engagement, and relationships with existing bodies. The approach so far has been characterised as “evolutionary”—in attempting to adapt existing less than suitable frameworks to deal with new challenges, such as the treatment of interconnectors between member states. Going forward this approach is unsatisfactory and needs to be reformed.

4.11 Particular attention needs to be paid to the relative competitive position of the UK market if it adopts policy measures, for example on carbon pricing, which create materially divergent pricing structures in neighbouring markets.

4.12 Across Europe there are different models for trading electricity. With increased market coupling it is important that the rules for trading are not only “harmonised” but recognise and respond to the new challenges of a market with a high degree of renewable penetration. Failure to do so will result in sub optimum results and the misallocation of beneﬁt amongst participants. Of particular interest are the areas of capacity allocation, entry/exit rights, congestion management and balancing cost allocation.

5. Supergrid: Delivering Energy Security

5.1 Europe, including the UK, is set to face increasing challenges to its energy security. Indigenous fossil fuel reserves are declining rapidly. Imports are being sourced from geographically remote and in many cases less reliable trading partners. There is an increasing risk of both severe price and availability fuel shocks in the future. For some energy sources such as gas and oil there is the possibility of strategic storage to smooth out some of the consequences of short term supply interruptions. However, storage cannot provide a hedge against a sustained step increase in price.

5.2 Electricity cannot currently be stored at a scale necessary to decouple production and consumption and as such has to incorporate specific security strategies to manage shortfalls in either generation or transmission capacity. 30 As an example of the difference, the UK is through the current “OFTO” regime trying to find a way to pursue a coordinated approach to offshore transmission. Whilst this will bring benefits over and above an individual approach, it has a low probability of delivering an integrated network which is “interconnection ready” as it has no reference to the UK’s wider, longer term energy requirements. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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5.3 An increasing proportion of Europe’s energy will be provided by electricity, as climate change objectives provide a policy imperative to move away from current energy sources for heating and transport. As such, our electricity infrastructure will play a greatly enhanced role in delivering the energy we need. The new electricity generation mix will include a significant proportion of renewables, dispersed across the continent, greatly reducing our reliance on imported energy. 5.4 Supergrid is required, not only to access these geographically determined strategic resources, but to deliver these benefits within an appropriate envelope of security and efficiency required for a network transporting the majority of end user energy requirements across Europe.

6. Supergrid: Lowering the Cost of Energy 6.1 Offshore wind capex and opex costs remain high in comparison to unabated fossil fuelled generation. There are several initiatives under way that will reduce cost; larger and more efﬁcient turbines, alternative foundation designs, and innovative O&M strategies. 6.2 One area with the potential to signiﬁcantly reduce the cost of energy lies in how offshore wind connects to the grid. By coordinating the transmission requirements of offshore wind farms, factoring in the strengths and reinforcement needs of the existing onshore grid, and by interconnecting with neighbouring countries, Supergrid will lower the cost of energy. It does so in a number of different ways:

Lower Capital Costs 6.3 Current cost estimates suggest that to connect an offshore wind farm directly to the onshore grid could represent at least 20% of the total project capex. This translates into potentially £20 billion to connect the offshore wind farms currently under development in the UK; well in excess of the current value of the existing onshore grid. Instead, if neighbouring projects interconnected and maximised the use of grid infrastructure, the total costs could be reduced signiﬁcantly. National Grid has estimated the cost savings to be up to 25% for the UK.

Higher Utilisation 6.4 Using a coordinated offshore grid means that the offshore transmission infrastructure will be better utilised. Using point to point radial connections, the offshore transmission infrastructure would be limited to the capacity factor of the wind farm; about 40%. However, multi-user infrastructure will mean the utilisation of the offshore grid is not limited to the output of individual projects. 6.5 Additionally, an integrated offshore grid can also act to help alleviate onshore bottlenecks. The latest Offshore Development Information Statement (ODIS)31 from National Grid clearly shows how the grid infrastructure needed to connect east coast Round 3 Zones could also be used to facilitate transmission of electricity from Scotland to England via an offshore network. 6.6 However, the most signiﬁcant increase in utilisation of the offshore grid will come from the increased trading of power that it will facilitate in addition to the capacity of the connected wind farms.

Lower Risk 6.7 As capital intensive projects, offshore wind farms have significant upfront financing costs. These financing costs are affected by the overall risk of the project. Additional risks translate into a higher risk premium in the financing cost and therefore also a higher ultimate cost of energy. By mitigating some of these risks, Supergrid will lower the cost of energy. 6.8 Under the current UK offshore transmission regime, the majority of offshore projects are reliant on a single connection to the onshore grid and have no control over this link. Should there be a fault in the export cable the offshore project is effectively stranded with no route to market and no compensation. This is a major risk and one that could be significantly mitigated if there were more than one physical route to market as would be the case under a coordinated and integrated offshore grid.

Lower Balancing and Reserve Costs 6.9 As well as facilitating trade in energy, increased interconnection will help National Grid in its role as system operator by providing balancing and reserve services. In its consultation “Operating in 2020” National Grid points out that operating the electricity network in 2020 will be more complex due to the revised plant portfolio on the system. They conclude that increased interconnection will assist in managing this complexity. 6.10 All system operators must operate with deﬁned reserve levels in order to ensure the system is robust to a range of operational events, including generation transmission and demand problems. Further interconnection would allow reserve in one market to be deployed across multiple markets. The result is that individual market system operators will not need to “double up” on reserve, lowering the cost of energy. 31 http://www.nationalgrid.com/uk/Electricity/ODIS/CurrentStatement/p73. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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7. Questions and Answers 7.1 We adopt the answers to the Committee’s questions provided in the submission of the Friends of the Supergrid. April 2011

Supplementary memorandum submitted by Mainstream Renewable Power Thank you for the opportunity to present the vision proposed by the Friends of The Supergrid to the Energy and Climate Change (ECC) Select Committee’s Inquiry into A European Supergrid. We firmly believe that the Supergrid is necessary to achieve Europe’s common goals of sustainable, secure and affordable electricity. With regard to the benefits for the UK, Supergrid achieves these by facilitating both the delivery and value realisation of offshore wind. Without the offshore renewable resource that Supergrid will facilitate, there is a high probability that the UK will invest in a significant volume of gas (CCGT) generation in order to meet its electricity requirements. This will lock in a significant proportion of high carbon gas generation—which is not CCS compatible—for 30 to 40 years, exposing the UK to an enduring supply and price risk, and undermining the country’s statutory obligation to reduce emissions. When I presented to the committee on 10 May, I described the cost structure of offshore wind. While it does have relatively high capital costs, because its fuel, the wind, is free, these capital costs will be recovered in a relatively short time. Without the contribution from offshore wind that Supergrid will deliver, the UK would derive the equivalent amount of energy from new gas generation, the marginal choice. Gas generation has a continuing and uncertain fuel cost throughout its operational life. I noted that a comparison of costs between Phase 1 of the Supergrid and the alternative of gas generation gave a payback period for Supergrid of approximately seven years. You asked if I could provide further detail on this calculation. This is given below. Our proposal for Phase 1 of the Supergrid involves connecting 23 GW of offshore wind in the North Sea. This represents a total transmission investment of about £25 billion. Without the Supergrid, two factors would militate against the delivery of this offshore capacity. Firstly, the transmission infrastructure would be based on expensive, uncoordinated radial links, rather than an efficient network. Secondly, the ability to direct power into multiple national transmission networks and access a wide range of balancing services would be lost, imposing a significant balancing requirement on the UK network, alone. In order to replace 23 GW of offshore wind, it would be necessary to build approximately 11GW of CCGT plant. While this may represent a saving in capital cost compared with offshore wind, there is a continuing fuel cost. According to the latest power generation cost assumptions provided to DECC by Mott McDonald,32 the expected annual fuel cost for 11GW of CCGT plant is approximately £3.6 billion. Comparing this with Phase 1 Supergrid costs (£25 billion) gives a payback period of slightly less than seven years. This is, of course, focussing on one particular aspect of how the Supergrid delivers benefits for the UK. It does not take into account the security of supply benefits from greater energy self-sufficiency, or the avoidance of costs associated with reduced carbon emissions. We are grateful to the Committee for the opportunity to present the Friends of The Supergrid vision to the Inquiry. If we can provide further information or detail on any of the issues covered, please do not hesitate to contact me. July 2011

Memorandum submitted by Scottish Renewables Scottish Renewables is Scotland’s leading renewables trade body. We represent over 300 organisations involved in renewable energy in Scotland.33 Firstly, many thanks for the opportunity to respond on what is an important issue for the renewables industry in Scotland. This industry is playing a crucial role in the Scottish and UK Government’s efforts to tackle climate change and increase Scotland’s energy security, and must continue to do so in order to meet our carbon emissions reduction target of 42% by 2020. Scotland has ambitious targets to source 80% of our electricity demand and a ﬁfth of all energy consumption from renewables by 2020. As such, the creation of a European Supergrid is of importance to our members as a means of facilitating the integration of increasing levels of renewable generation onto the electricity networks. The main points we make in our response are as follows: — A European Supergrid could facilitate the UK’s security of energy supply. — A European Supergrid could further enhance the nation’s commercial interests. 32 http://www.decc.gov.uk/assets/decc/statistics/projections/71-uk-electricity-generation-costs-update-.pdf 33 Further information on our work and membership can be found at www.scottishrenewables.com cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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There were a number of issues raised in the Terms of Reference, and Scottish Renewables has speciﬁcally responded to those relating to intermittency and energy prices, in addition to a host of other beneﬁts a European Supergrid could deliver for the UK.

1. European Supergrid: An Introduction

1.1 A European Supergrid has the potential to facilitate the integration of huge amounts of renewable energy onto electricity systems across Great Britain and Europe. The vast renewable energy resource we have across the UK, and in particular Scotland, could potentially deliver signiﬁcant commercial and strategic beneﬁts to UK plc.

1.2 For the most part, generation from renewable energy has a variable output which can possess varying degrees of unpredictability. Consequently, the balancing of such resources is often cited as a barrier to the integration of these resources onto electricity networks across Europe.

1.3 Across Europe, there are signiﬁcant amounts of renewable energy available from differing resources and in increasingly remote locations. Divergent weather patterns and geographic differences afford certain areas within Europe comparative advantages in certain technologies. Thus, a supergrid could provide the opportunity to balance energy ﬂuctuations.

1.4 For instance, Scotland has the strongest offshore wind, wave and tidal resources across Europe, and has a global lead in marine energy research and testing due to vast marine resources around its shores. You will see from the diagrams below the potential for electricity generation from onshore wind and solar photovoltaic is divergent across various areas of Europe. In terms of onshore wind, Scotland, Ireland, the Baltic nations and Scandinavia have a particular lead. This is not to mention the vast hydro and pumped storage potential that exists within Norway.

1.5 These comparative advantages could mean that each area has the potential to generate electricity whilst balancing ﬂuctuations in energy production by taking advantage of the geographical spread enabled by such interconnectivity. The portfolio of energy generation across Europe would thus become more diversiﬁed, and thus aids security of energy supply.

1.6 The creation of a European Supergrid is likely to require a large amount of capital. However, it is important that these costs are tempered by the benefits that could emanate from its creation. Costs associated with the development of a European Supergrid centre, by and large, on the Capex and Opex of the system. These costs are rather clear cut, and relatively simple to quantify. However, the benefits of such interconnection revolve around both commercial benefits and security of supply. These are not so clear cut and can be difficult to quantify.

2. Beneﬁts: Security of Energy Supply

2.1 The variability of output from renewable resources can be reduced via interconnection as there exists a limited correlation between divergent energy resources across Europe, including wind, marine, hydro and solar technologies. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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2.2 During periods of electricity shortage in any one area, or indeed excess electricity supply, the shortfall can be met from an area of excess capacity. As such, a supergrid could help to ensure security of supply in any one area, and across the entire system.

3. Beneﬁts: Commercial Beneﬁts to the UK

3.1 The UK, and Scotland in particular, has a vast and unrivalled potential for offshore wind and marine generation. If these resources are utilised suitably, interconnection across European nations could represent a considerable commercial opportunity for the UK. Furthermore, during periods of low renewables output, interconnection via a supergrid could reduce the UK’s exposure to the volatile nature of fossil fuel supply and pricing, which has knock on effects on the price of electricity for consumers.

3.2 A European Supergrid could enhance competition within the electricity market. In the main, there exists an association between the degree of market concentration and variance between the price of electricity and the underlying costs of its production. Interconnection permits additional generators to enter the market from across national boundaries. This is likely to mean that players within a concentrated market will have a less decisive role in that market and as a result, the wholesale price could decrease during peak hours. Such beneﬁts will be passed on to the end consumer.

3.3 During periods of high renewables output in specific regions, such as wind output across Scotland, it is likely that generation could outstrip demand. This surplus of potential generation could go unexploited, which will be an inefficient outcome. However, this presents a commercial opportunity if this output could be moved to an area where demand outstrips electricity supply. This is also an efficient solution to the issues surrounding the variability of renewable output since it is possible that wind may cease in one area, but is highly unlikely to cease across a vast geographical area such as continental Europe.

3.4 By enabling efficient electricity markets, the economic welfare generated from that market is maximised. The benefit of increases in economic welfare will be reflected throughout the entire economy, and more so for industries underpinning national economies, such as electricity supply. Efficiency improvements in the market stem from gains in both productive and allocative efficiency: — Productive efficiency concerns the optimal generation of electricity involving maximum output for minimum cost. The efficiency gains outlined in 3.3 are likely to lead to gains in the productive efficiency of electricity generation, since a supergrid could permit a more extensive use of the cheapest method of electricity generation. If, for instance, the cost of producing electricity is high in Norway compared to Scotland, it is welfare enhancing to generate power in Scotland instead of in Norway. — Allocative efficiency is achieved if the value consumers place on a unit of electricity equals the cost expended in the production of that unit. A supergrid could potentially allow electricity prices to converge with marginal costs in both regions. The process of convergence between the two will of course enhance total economic welfare.

3.5 As discussed above, a European Supergrid has the potential to lower the cost of electricity. Other ways in which this could occur include: — National Grid estimates that coordinating the offshore grid could produce cost savings of around 25%. Such savings will be passed through to electricity consumers. — A coordinated and integrated offshore grid will mitigate risks that eventually factor into the ﬁnancing costs associated with offshore wind. As such, a supergrid could lower these costs and therefore the costs passed through to the consumer. — Operating the electricity network in 2020 will be more complex as a consequence a changing generation portfolio on the system. Increased interconnection will assist in managing this complexity.

4. Summary

4.1 The creation of a European Supergrid has the potential to increase the security of energy supply across GB, whilst simultaneously delivering economic opportunities throughout the UK. Undoubtedly, there will be costs associated with the development of a supergrid, but it is important that the substantial beneﬁts highlighted above are considered appropriately against such costs. April 2011 cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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Memorandum submitted by E3G

Summary 1. E3G welcomes this timely and important inquiry into a European Supergrid. As the recent volatility of fossil fuel prices and public concern over nuclear safety demonstrates, future energy pathways in the UK and in Europe face high levels of risk, and there remains significant uncertainty on future policy and technology mixes, market design and levels of consumption. In this context, the concept of a European Supergrid has been advanced as a tool for addressing security of supply concerns and in managing the costs and risks associated with the transition to a low carbon European power sector. A European Supergrid could, it is suggested: — enable a wider range of options for future UK and European energy pathways; — enable optimum use of Europe’s geographically-diverse energy resources, including high volume renewables; — help to manage the energy system challenges associated with increasing volumes of variable and/or must-run generation; and — enable the UK to become an electricity exporter over the longer term, taking full advantage of its natural renewable energy and carbon storage opportunities as Europe decarbonises its power sector. 2. However, behind the Supergrid issue is a wider strategic choice that will need to be made on the level and form of European energy market integration. European governments will need to decide between progressing with separate, Balkanised electricity markets linked at the margin, or moving to a more unified European-wide market with harmonisation of market rules and policies. The outcome of this decision will largely determine the extent of interconnection requirements and the nature of Supergrid design. It will also shape the ability of European governments to overcome the financing, planning and market design challenges associated with building a Supergrid. 3. E3G is an independent, not-for-profit European organisation committed to working in the public interest to accelerate the global transition to sustainable development.34

Key Choices andDecisions Strategic choices on European market integration 4. Before a decision on a European Supergrid can be taken, European governments face a high level strategic choice on the nature of future electricity market integration: should key power market objectives such as security of supply and decarbonisation be achieved on a shared or on a purely national basis? 5. There are, broadly speaking, two competing visions in answer to this question: —A “weak integration” model in which power markets remain largely separate but are linked through physical interconnections and market coupling. In this model, energy policy agendas remain relatively separate. Trade occurs at the margin to improve market efficiency, but is not a core element of meeting security of supply or decarbonisation objectives. Markets become linked but not thoroughly integrated, and in some cases market distortions may arise from differences in national policies. —A “strong integration” model in which power resources are shared and a harmonised set of market rules and policy instruments are developed across Europe. In this model, power sector objectives such as security of supply and decarbonisation are achieved by the European market as a whole rather than guaranteed by individual member states; trade forms a significant proportion of overall market volumes. Such a pan-European market is likely to be more economically efficient at a European level and may involve lower overall costs, but also involves a degree of pooling of national sovereignty. 6. While both of these models could potentially involve higher levels of electricity interconnection than at present, the outcome of this high-level choice will largely determine the requirements and utilisation of a future European grid. In the strong integration model, both renewable and conventional generation would be sited where it is most cost effective to do so rather than on the basis of national supply meeting national need; grid requirements are therefore likely to be considerably higher.

Design choices for a European Supergrid

7. Underneath this high level choice, there are also several possible grid design options for a European Supergrid: the “Supergrid” is a broad term describing several different grid concepts. A number of studies, including the European Climate Foundation’s Roadmap 2050, have focused on the volumes of inter-regional 34 A more detailed evaluation of some of the issues raised in this evidence note can be found in the E3G discussion paper “Opportunities and Challenges for a European Supergrid”, August 2010. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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transmission required to accommodate significant levels of renewable power generation in Europe, including balancing wind power in northern Europe with solar from the south.35 8. Other approaches have focused on the potential for an offshore grid in the Northern Seas to enable the connection of high levels of offshore wind generation and to link to flexible hydro resources in Scandinavia and the Alps. Initiatives and organisations promoting this approach include the North Sea Countries Offshore Grid Initiative, Friends of the Supergrid, and the European Wind Energy Association.36 9. Still further “Supergrid” concepts relate to accessing large scale solar power resources in North Africa or the Mediterranean, and exporting this electricity to consumers in Northern Europe. Examples of this approach include the Desertec Industrial Initiative, the Transgreen Initiative, and the Mediterranean Solar Plan.37 10. These different approaches to a European Supergrid are not necessarily mutually exclusive. A North Sea or Mediterranean grid, for example, could act as a modular building block for a wider Supergrid developed over the longer term. For this to be successful, however, regional grids and markets would need to be designed to be compatible from the outset, requiring early cooperation. 11. There are also a number of technological choices facing a possible European Supergrid, including between the appropriate balance between new HVDC lines and extending the existing meshed AC system. While it is important to develop evidence on the costs, risks and potential of the various options, technology choices should follow rather than lead the higher-level political decisions on the nature of market integration. 12. A final system design choice for further attention is the relationship between a European Supergrid and smart grid solutions. Both offer the prospect of providing greater flexibility to integrate intermittent generation, but they are not mutually exclusive—a combination of “super” and “smart” elements is likely to be the most cost effective solution. Institutional and market arrangements need to be developed to allow system operators to implement the best value response to specific system challenges.

Benefits andCosts ofa European Supergrid for theUK Value case and trade-offs 13. There are three main sources of value for the UK in participating in a European Supergrid: creating energy system options, optimising use of resources and providing flexibility to mange the challenges related to intermittent generation. 14. All of the potential future energy pathways face a significant degree of risk, including climate impacts and fuel price vulnerability for conventional thermal generation; cost, public acceptance and safety risks of nuclear power; delivery, intermittency and cost risk for wind, wave and solar power; cost and technology uncertainties of carbon capture and storage; and significant implementation challenges for energy efficiency. In this context, there is value in keeping options open to manage these risks until potentials and costs are better known. A European Supergrid would allow the UK to keep open a wider range of possible futures, potentially increasing security. This includes the potential for electricity imports from other areas of Europe with an overcapacity of generation if energy efficiency and low carbon generation policies fail to deliver the desired outcomes; or export of electricity if these policies perform better than expected. It also opens up the option of making high use of North Sea offshore wind resources (which would be challenging without interconnection), without foreclosing other low carbon options such as distributed generation, carbon capture and storage or nuclear. 15. A European Supergrid combined with a higher level of market integration would enable more economically optimal use of Europe’s energy resources. This would deliver European-level economic advantages from more efficient integrated electricity markets, lower transmission congestion rents, reduced need for reserve capacity and enabling expensive generation in one country to be replaced with cheaper generation in another. Such benefits will be contingent on system design and on the degree of market integration, and may be hard to definitively quantify.38 There are also likely to be winners and losers from market integration: electricity costs in high-cost areas would fall as cheaper power can be imported, but power prices in currently low-cost areas would rise towards the European average meaning some consumers would 35 European Climate Foundation. 2010. “Roadmap 2050: A practical guide to a prosperous, low carbon Europe”. www.roadmap2050.eu. 36 See for example “North Sea Countries Offshore Grid Initiative Memorandum of Understanding” (http://ec.europa.eu/energy/renewables/grid/doc/north_sea_countries_offshore_grid_initiative_mou.pdf); Friends of the Supergrid Phase 1 proposals (http://www.friendsofthesupergrid.eu); EWEA. 2009. Oceans of Opportunity: Harnessing Europe’s largest domestic energy resource (http://www.ewea.org/fileadmin/ewea_documents/documents/publications/reports/Offshore_Report_2009.pdf) 37 See for example Desertec Industrial Initiative (http://www.desertec.org/); PWC/PIK/IIASA. 2010. 100% renewable electricity: A roadmap to 2050 for Europe and North Africa. (http://www.supersmartgrid.net/wp-content/uploads/2010/03/100-renewable_electricity-roadmap.pdf); Von Hirschhausen, C. 2010. “Developing a “Super Grid”: Conceptual Issues, Selected Examples, and a Case Study for the EEA-MENA Region by 2050 (“Desertec”)”. In J Pardilla and R. Schmalensee (eds) Harnessing Renewables. Boston and Chicago. 38 The European Commission has suggested that European GDP could be boosted by 0.5–0.6% as a result of a European single energy market. Bruegel suggest this may be an overestimate. Zachmann, G. 2010. “Power to the People of Europe”. Bruegel: Brussels. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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pay more. Currently, UK wholesale power prices currently tend to be higher than its neighbours, suggesting that UK consumers may be net beneficiaries of price convergence enabled through a Supergrid.39 16. A European Supergrid should enable the UK and other European countries to take advantage of renewable resources both where it is located and when it is available. A North Sea grid could play a key role in both connecting offshore wind generation and in using wind power in an optimal fashion. As highlighted in the European Climate Foundation’s Roadmap 2050, aggregation of demand and supply patterns through a European Supergrid may result in much lower overall volatility, leading to lower costs for dealing with both daily and seasonal fluctuations of intermittent generation. 17. In the longer term, this may lead to significant export opportunities for the UK enabled through a Supergrid. While current levels of renewable generation in the UK is relatively low, overall renewables potential is among the highest in Europe, and UK wind energy resources in the North Sea have been valued at up to £126 billion.40 UK offshore carbon storage potential is also among the highest in Europe, an important resource given the public acceptance challenges facing CCS in many countries.41 As Europe seeks to decarbonise, these natural assets may become increasingly valuable. 18. The extent to which these sources of value can be accessed will largely depend on power market and grid design. Without significant levels of European market integration, a European Supergrid would deliver fewer economic benefits as less trade would occur. This would also limit opportunities for the UK to become an electricity exporter, as European countries seek to avoid over-reliance on imports, support domestic rather than European renewables installations and continue to balance their power systems on a national basis.

Capital investment requirements and operational savings 19. Given the range of potential options for delivering a European Supergrid, the precise capital cost requirements are not yet fully known. A range of estimates has been developed at European level. 20. For the 2020 time horizon, grid development is likely to be limited to that set out in the ENTSO-E Ten Year Network Development Plan, plus initial development of offshore grids to support offshore wind power. A study for the European Commission estimated that this requires€27.7 billion in expenditure for member state interconnection and€32.8 billion in investment in offshore grids. 42 According to the study,€3.2 billion of the investment in interconnection and€11.7 billion of the offshore grid investment would occur in the UK. 21. By 2030, the study for the European Commission estimated that constructing a grid suitable for a high level of renewable electricity would require€61.2 billion for member state interconnection and€99.8 billion in investment in offshore grids. This compares to€28.1 billion for member state interconnection and€50.4 billion for offshore grids in the 2030 baseline scenario. However the high-renewables scenario enabled annual power sector system cost savings of€31.5 billion compared to the baseline scenario; these savings would rise further if fossil fuel prices increase. 22. For the 2050 time horizon, the range of cost estimates becomes even wider. In the European Climate Foundation’s Roadmap 2050, European interregional transmission costs range from€44 billion in a 40% renewables scenario to€105–139 billion in an 80% renewables scenario 43. In the 100% renewables scenario involving accessing solar power from North Africa, these costs rise to€395 billion (including North African interconnectors). A different study for Greenpeace and the European Renewable Energy Council projected transmission grid costs of€209 billion to 2050 including the link to North Africa, 44 while analysis by the German Aerospace Centre suggested that€45 billion would be required for European grid reinforcements to integrate Mediterranean concentrating solar power.45 23. These figures must be understood in context. First, capital costs for transmission only represents a very small proportion of the overall cost of electricity, even with a Supergrid. In the 80% Renewables Scenario in the ECF Roadmap 2050 study, the expansion of the interregional transmission grid accounts for only 1.6% of overall expenditure in the power sector to 2050.46 24. Second, the upfront capital costs of a European Supergrid should enable significant cost savings over the longer term. As well as the overall sources of public value identified above, there are a number of specific sources of cost savings enabled through a Supergrid: 39 European Commission. 2010. Energy Observatory: Quarterly report on European electricity markets. http://ec.europa.eu/energy/observatory/electricity/doc/qreem_2010_quarter3.pdf 40 The Offshore Valuation Group. 2010. The Offshore Valuation: A valuation of the UK’s offshore renewable energy resource. http://www.offshorevaluation.org/ 41 Arup. 2010. “Feasibility study for Europe-wide CO2 infrastructures”. http://ec.europa.eu/energy/coal/studies/doc/2010_10_co2_infrastructures.pdf 42 Cambridge Econometrics, Kema and Imperial College London. 2010. Revision of the Trans-European Energy Network Policy (TEN-E): Final report. European Commission: Brussels. Note: European interconnections only; not internal transmission. 43 ECF. 2010. Roadmap 2050. www.roadmap2050.eu. 44 Greenpeace/EREC. 2010. Renewables 24/7: Infrastructure needed to save the climate. http://www.greenpeace.org/raw/content/international/press/reports/renewables-24–7.pdf 45 DLR. 2006. Trans-Mediterranean Interconnection for Concentrating Solar Power. http://www.dlr.de/tt/Portaldata/41/Resources/dokumente/institut/system/projects/TRANS-CSP_Full_Report_Final.pdf 46 E3G analysis based on ECF Roadmap 2050 data (www.roadmap2050.eu). cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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— Reserve sharing: across the EU, reserve sharing enabled by a Supergrid would reduce total reserve requirements by 35–40%, potentially eliminating the need for up to€34.3 billion in backup generation.47 — Limiting renewables curtailment: analysis suggests that if only half of the required interregional transmission capacity is built, 15–20% of renewable power generation would have to be curtailed off the system—at a cost signiﬁcantly exceeding the cost of the transmission capacity.48 — Reducing connection costs for offshore wind: The Offshore Grid study suggests that offshore grid infrastructure development would cost up to€90 billion by 2030 if radial connections are used to connect offshore wind generation, compared to€75 billion if clustering through a North Sea grid is utilised.49 25. Third, it is important to distinguish between capital investment costs and wider economic costs or public spending requirements. Macroeconomic modelling shows a small but positive impact on GDP from investing in electricity grid infrastructure, alongside a rise in employment and a rise in economic activity in general.50

ImplementationIssues andNear-termPolicyProcesses Financing and cost allocation 26. Despite these caveats, the capital required to develop a European Supergrid remains substantial and represents a significant increase on current grid investment. The majority of any new European Supergrid is likely to be financed through existing market mechanisms. Currently, most interconnectors are built on the basis of regulated investment following agreement between Transmission System Operators and regulators on both sides of a border. International transmission lines can also be built through the “merchant interconnector” model, in which operators may profit from the difference in electricity prices between countries. 27. Difficulties arise with both options. More integrated European power markets would cause prices to converge and this may make further development of merchant interconnectors unviable. The regulated tariff model may run into challenges where: — regulatory rules vary between countries or regulators are unable to agree; — benefits are more regional than national, or where a link between two countries primarily benefits a third country; — long-distance lines (eg HVDC cables) cross several national borders; or — projects use innovative technologies or face high levels of risk. 28. To overcome these difficulties, a more effective system of cost allocation rules would need to be developed in order to enable complex projects such as the new lines forming a European Supergrid. To be successful, greater European-level coordination may be required. Experience from the USA indicates that bottom-up cost sharing agreements may be insufficient without an independent body playing an arbitration and coordination role. In the EU, this could involve a stronger role for the newly-created Agency for the Cooperation of Energy Regulators, and independent modeling of welfare changes from network investment to develop a fair and transparent allocation of cost. The European Commission will propose guidance or legislation on cost allocation for cross-border infrastructure later in 2011; however, the degree of independent coordination and the suitability of such proposals for complex and large-scale projects such as a Supergrid remains to be seen. 29. While the majority of new power network investment will continue to occur under the regulated tariff system, public financing support may also be needed in cases where market failures prevent the required investment taking place. There is considerable uncertainty on the future location, type and volume of power generation; this is a key source of policy and revenue risk. However, networks tend to take considerably longer to build than generation assets, with new interconnectors taking on average seven years and many taking considerably longer.51 In some circumstances, such as the development of the North Sea Offshore Grid, new networks may deliver significant public value; however the uncertainties facing future generation and the challenging nature of the project means that it may not otherwise be developed. This suggests a role for targeted public investment to ensure these projects are brought forward. 30. The market failures that restrict the availability of market finance and services following the financial crisis may also necessitate public intervention to support network investment. Energy utilities are facing unprecedented challenges to their balance sheets as a result of the financial crisis and the availability of project- based finance is in sharp decline.52 47 ECF. 2010. Roadmap 2050. (www.roadmap2050.eu). Based on 80% RES scenario and a cost estimate of€350,000 per MW for OCGT backup generation. 48 ECF. 2010. Roadmap 2050. 49 The Offshore Grid Consortium. 2010. www.offshoregrid.eu 50 Cambridge Econometrics et al. 2010. “Revision of the Trans-European Energy Network Policy”. 51 PWC/PIK/IIASA. 2010. 100% renewable electricity: A roadmap to 2050 for Europe and North Africa. http://www.supersmartgrid.net/wp-content/uploads/2010/03/100-renewable_electricity-roadmap.pdf 52 Eurelectric. 2011. “The financial situation of the electricity industry—a view to the future challenges”. Eurelectric: Brussels. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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31. At European level, there are already several sources of public support for network investment, including the Trans-European Network for Energy (TEN-E), Structural Funds, and the European Energy Programme for Recovery (EEPR). However these instruments have in the past been poorly targeted, and are insufficient compared to the overall scale of investment required.53 Later in 2011, the European Commission is expected to propose a new financing and regulatory instrument on energy infrastructure. This may include a strengthened role for the European Investment Bank, new risk-sharing facilities (such as first-loss provisions for infrastructure project bonds), and revisions to the existing TEN-E programme.54 Such proposals are a welcome response to the challenges facing grid development; however it remains unclear whether they will prioritise low carbon over high carbon investment.

Planning and institutions 32. Developing a European Supergrid is a long-term project may require more forward visibility in grid development and more strategic planning than at present. Currently, grid investments tend to follow generation, even though power lines take significantly longer to build than gas turbines or wind farms. This can lead to long delays in grid connection, undermining investment in new low carbon generation. 33. The European Network of Transmission System Operators (ENTSO-E) is required under the Third Energy Package to develop a Ten Year Network Development Plan. This is an important starting point for providing forward visibility for grid development. However the current Plan is insufficiently aligned with European decarbonisation goals and remains a collection of predominantly national plans. To develop a European Supergrid, ENTSO-E would need to be empowered to become anticipatory rather than reactive, to address longer time horizons (e.g. 20 years rather than 10), and to work with member states, regulators and the Commission to identify and push forward transformational projects that could unlock significant volumes of low carbon investments. 34. The North Sea Countries Offshore Grid Initiative offers an important platform for strategic planning of a North Sea grid. The Initiative brings together 10 governments from north-west Europe, ENTSO-E, ACER and the European Commission. Working groups will analyse potential grid configuration and integration issues, and will report by the end of 2012. To enable maximum benefit for the UK, the Government should play a proactive role in driving this system forward and provide resources to enable the initiative to undertake detailed energy system modelling. 35. Greater attention to grid issues will also be needed within longer term energy planning. Further consideration of grid infrastructure and power market integration will be needed in the development of DECC’s 2050 pathways. The European Commission is producing an “Energy Roadmap” to 2050 later this year; it is important that this includes analysis of the infrastructure requirements of different scenarios.

Market arrangements 36. As highlighted above, over the longer term the nature and extent of a European Supergrid will depend on the strategic choices made on European power market integration. In the interim however, it is imperative that both European and UK energy policy processes are sufficiently consistent to avoid perverse outcomes. More consideration is needed of how the UK’s current Electricity Market Reform process relates to wider European power markets. The role and opportunities of interconnectors were not a significant part of the Government’s consultation on EMR, and the details of how the proposals will work in a European context still need to be developed. Further specification is needed for the long-term contracting arrangements for low carbon generation, including whether such generation may be sited outside the UK and the conditions under which power from this generation may be exported. Investigation is also needed into how the proposed capacity mechanism would interact with neighbouring markets. 37. Greater attention to national decarbonisation and security of supply aims will also be required as ACER and ENTSO-E develop Framework Guidelines and Grid Codes for market coupling under the Third Energy Package.

Conclusions andNextSteps 38. There is now a considerable body of research literature highlighting the potential value of a European Supergrid—including opening options for decarbonisation, managing energy system challenges associated with inflexible generation and delivering cost reductions for consumers through more efficient markets. Given its considerable natural renewable energy and carbon storage resources, the UK is well-placed to capitalise on the potential that a Supergrid offers. Such benefits, however, do not automatically accrue through building new wires: they are contingent on strategic choices on the level of market integration and the design of power systems. The outcomes of this choice—between Balkanised energy markets where policy design is primarily national and a more unified European markets where scope for national interventions become more limited— 53 European Commission. 2010. Report on the Implementation of the Trans-European Energy Networks in the Period 2007–2009. http://ec.europa.eu/energy/infrastructure/studies/doc/2010_0203_en.pdf 54 European Commission. 2010. Energy infrastructure priorities for 2020 and beyond—A Blueprint for an integrated European energy network. European Commission: Brussels. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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will determine both the ability of European countries to surmount the ﬁnancing, planning and market operation challenges for developing a European grid, and the ways in which a future European Supergrid could operate. April 2011

Memorandum submitted by WWF-UK

WWF-UK welcomes the opportunity to respond to the Energy and Climate Change Committee’s enquiry into the development of a European supergrid.

Executive Summary

A European supergrid could be deﬁned as a transnational electricity transmission system which is optimised at European level to make the best use of Europe’s power resources—such a system could either take the form of an “overlapping” European transmission system (essentially running in parallel to existing national transmission systems) or take the form of enhanced interconnection capacity between the existing transmission systems of different Member states.

Regardless of the model that is ultimately adopted, such a transmission system would differ substantially from current transmission systems which are currently built and operated on a national basis, with very little cross-border interconnections. A recent non-paper from the European Commission’s DG Energy55 provides a good assessment of the current state of play. In particular, the Commission highlights that there is currently very little interconnection infrastructure in place: “Interconnection capacity between Member states remains generally insufﬁcient and certain regions, such as the Baltic States, the Iberian Peninsula and the United Kingdom and Ireland remain isolated. In 2002, the European Council set the target for all Member states to have a level of electricity interconnections equivalent to at least 10% of their installed production capacity by 2005. In 2010, 9 Member states still did not meet this target”.

The Commission’s call for enhanced interconnection came together with a recommendation for harmonised market rules to reduce market segmentation and transaction costs as well a recommendation to improve the statutory independence of national energy regulators and their ability to enforce EU legislation, both recommendations being seen as key to improve the competitiveness of the EU’s electricity market during its decarbonisation transition.

(a) What could be the beneﬁts of a European supergrid?

The development of a European supergrid could be one of the key measures needed to assist with (i) the cost-efﬁcient system balancing of supply-driven forms of renewable energy (such as wind power), (ii) improved integration and competitiveness of Europe’s electricity market during the transition towards a decarbonised power sector and (iii) improved security of supply by optimising the efﬁcient conversion, delivery and use of Europe’s vast renewable energy resources.

In particular, a European supergrid could help provide: — Smaller “congestion rents”: These are currently estimated at around€1.3 billion/year in the 10 most congested interconnectors in Europe56 and occur as a result of surplus generation in one Member state being unable to be transferred to another member state. This is an important advantage, given that an increase in renewables capacity in countries such as the UK will mean that there will be instances where excess generation from supply-driven renewables (especially wind power) will regularly occur. — Improved certainty for investors in renewables: Insufﬁcient interconnection infrastructure (and plans to build such infrastructure) is likely to be detrimental to investment decisions in supply- driven renewables. This is because it would create a risk that generators would be unable to sell power that is in excess of national demand needs, thus increasing the risk of curtailment and making such investments less attractive. 55 DG Energy, The Internal Energy Market—Time to Switch into Higher Gear, Non-paper, http://ec.europa.eu/energy/gas_electricity/legislation/doc/20110224_non_paper_internal_nergy_market.pdf 56 Chrysoula Argyriou, DG ENER presentation to ENTSO-ETYNDP workshop, 19 March 2010. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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— Decreasing the cost of decarbonisation: A European supergrid could also help reduce the overall costs of decarbonising the EU’s power sector by making optimum use of Europe’s geographically diverse energy resources57 and therefore reduce the amount of back-up generation required in each Member state. The European Climate Foundation Roadmap 2050 report found for instance that increased interconnection could limit the “load factor” (or utilisation rate) of back-up plants to 5% in an 80% renewable energy scenario and 8% in 100% renewable energy scenario.58 It is worth noting that the investment required in grid infrastructure is likely to be a very small part of the overall electricity infrastructure costs required as part of decarbonising the European power sector (in the order of 0.5% to 1.6% of total costs).59

— Improved security of supply: the development of a European supergrid also has the potential to improve security of supply at both European and national level. From a national perspective, enhanced interconnection can help support a wider penetration of supply-driven renewables on the grid, by allowing for exports of excess power at times of high output and low demand and imports of power from other European markets at times of lower renewable output and high demand (such as imports of hydropower from Norway,60 geothermal power from Iceland, etc). From a European perspective, a European supergrid can help strengthen the EU’s ability to respond to external energy crisis—especially at times of high fossil fuel prices—by making optimum use of domestic energy resources and reducing European reliance on imported fossil fuels.

— Unlocking the value of the UK’s marine renewable resources: Several reports, in particular DECC’s recent Offshore Valuation Report,61 found that the value of the UK’s marine renewable resources was enormous62 and that taking a leadership role in EU supergrid negotiations was key to ensure the UK could maximise the beneﬁts from future export opportunities that such a resource offers.

(b) What are the main challenges that need to be addressed?

The development of a European supergrid will require addressing various challenges. Whilst there will obviously be some technical challenges, these do not appear unreasonably difﬁcult to overcome (see question 1), given the existing expertise in using long-distance higher voltage cables such as those used in the United States (that are well above 400kV) and in building and operating subsea cables, such as what has been done in the recent Britned interconnector,63 France-England interconnector and the Basslink interconnector.64

The main challenges facing the development of a European supergrid appear to be more of a regulatory, political and ﬁnancial nature. In particular, the main challenges that will need to be addressed include:

— The need for more harmonised & transparent market rules: To avoid market distortions and ensure that power flows from the least to highest cost areas, the development of European market rules that will improve the transparency of electricity pricing and consistency of renewable support mechanisms across the EU will be important. Such a development will require strong political will. However, as recently pointed out by the European Commission’s DG Energy in a non-paper on the internal market,65 a well functioning energy market with harmonised rules and improved physical interconnection could help ensure that European electricity prices remain competitive whilst the EU is on a transition towards a decarbonised power sector. This will be important for the competitiveness of the EU’s energy intensive industries and could be a key factor in helping harness political will around more harmonised and transparent European pricing structures.66 57 Such as wind, wave, tidal, hydro and geothermal resources in Northern Europe / Scandinavia and solar resources in Southern Europe and the wider Mediterranean region. 58 European Climate Foundation, Roadmap 2050, A Practical Guide to a Prosperous Low-Carbon Europe, Technical Analysis, Page 19: http://www.roadmap2050.eu/attachments/files/Volume1_fullreport_PressPack.pdf. 59 See ECF Roadmap 2050 Analysis, the grid expenditure represents around 0.5% of overall investment in the power sector under the 40% renewable energy scenario to 1.6% in the 80% renewable energy scenario. 60 Considered in one of Poyry’s latest report for the Committee on Climate Change: “Options for Low-Carbon Power Sector Flexibility to 2050: A report to the Committee on Climate Change”, October 2010: http://downloads.theccc.org.uk.s3.amazonaws.com/4th%20Budget/fourthbudget_supportingresearch__Poyry_ %20power%20sector%20flexibility%20to%202050.pdf 61 The Offshore Valuation Report: A valuation of the UK’s offshore renewable energy resource, July 2010: http://www.offshorevaluation.org/downloads/offshore_vaulation_full.pdf 62 By using 29% of the UK’s practical offshore resource, “the electricity equivalent to 1 billion barrels of oil could be generated annually, matching North Sea oil and gas production and making Britain a net electricity exporter” (page 6 & 7). See answer to question 2 for more detail. 63 https://www.britned.com/Pages/default.aspx 64 http://www.basslink.com.au/home/. This interconnector links Tasmania with Victoria and other Southern Australian states 65 http://ec.europa.eu/energy/gas_electricity/legislation/doc/20110224_non_paper_internal_nergy_market.pdf 66 It is worth pointing out that in the same paper, the European Commission therefore called for harmonised electricity market rules to be in place by 2014, a demand that was fully endorsed by the European Council in February this year. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

Ev w54 Energy and Climate Change Committee: Evidence

— Need for harmonised codes and institutions: To function effectively, a European supergrid will require a set of harmonised network codes (especially if an “overlapping” structure is adopted), governing in particular key generation dispatch rules, safety requirements as well connection charging issues. This is a challenge that the association of European transmission system operators (ENTSO-E) has already begun addressing through its work on a draft Connection Code, draft Operations Code and a Ten Year Network Development Plan and by the European Commission which recently issued a consultation regarding the prioritisation in which different network codes should be developed.67 — Financing & cost allocation issues: A more complex issue relates to how transnational interconnection infrastructure will be financed and in particular, how the costs would be allocated between Member states, transmission system operators (TSOs), taxpayers or consumers (see question 3). This issue has already been identified by the European Commission in its recent Communication on Energy Infrastructure priorities for 2020 and beyond, where the Commission announced its intention to “put forward, in 2011, guidelines or a legislative proposal to address cost allocation of major technologically complex or cross-border projects, through tariff and investment rules”,68 together with recommendations for a new set of innovative financing tools to help address the likely financing gap.

Question 1: What are the technical challenges for the development of a European supergrid?

The main technical challenge to the development of a European supergrid is likely to be more linked the scale of the new infrastructure that is required rather than the challenge of building interconnection infrastructure as such. The technical challenge of building and installing subsea cables is fairly well understood following recent experience in installing and connecting offshore wind infrastructure and building subsea interconnectors such as the Britned interconnector (opened on 1 April 2011), the Basslink interconnector and the France-England interconnector. With respect to onshore infrastructure, experience in the United States where higher voltage cables are used to transport electricity over longer distances could also be applied to Europe’s new interconnection infrastructure.

However, looking beyond Europe’s interconnection reinforcement needs in the run up to 2020 (see question 7 for more detail), the European Commission recognised in its Energy Infrastructure Priorities Communication that technological improvements in “electricity highways” will be needed to increase both the amount and the distance over which electricity can be transported through transmission lines across Europe. This would require “allowing notably direct current (DC) transmission and voltage levels signiﬁcantly higher than 400kV”.69 Another important challenge going forward will also be to ensure that future “electricity highways” be built step by step, ensuring in particular the compatibility of AC/DC connections and local acceptance (which might for instance be an issue for enhanced interconnection across the Pyrenees between France and Spain, where some undergrounding of interconnection infrastructure may be required).

Question 2: What risks and uncertainties would a supergrid entail?

As explained in more detail in answer to question 5, the main risks and uncertainties linked to the development of a supergrid relate to whether it will be accompanied by a harmonisation of market rules (at least between the most interconnected markets), as this will be key to avoid market distortions and ensure that electricity ﬂows from the lowest to highest price areas, thus maximising beneﬁts for consumers. The introduction of more stringent EU emission reduction targets would also be helpful in helping ensure that the supergrid is used in the context of increasingly optimising the use of the EU’s vast renewable energy resources.

A risk that has been put forward by some commentators in the past is that the development of a supergrid or enhanced interconnection with Europe could result in electricity flowing out of the GB system, thus resulting in security of supply issues. We believe that such a risk is extremely unlikely to occur in practice. The objective of a supergrid is to allow the optimum use of Europe’s energy resources and ensure in particular that electricity flows from lowest price to highest price areas. In practice, this means that it is unlikely that exports from the UK electricity market would occur unless there was sufficient capacity in excess of UK demand that could be exported. This is because at times of high demand for electricity and lower renewable energy output, it is very likely that prices would rise in the UK electricity market compared to prices in other European markets and this would de facto act as a price barrier preventing export of electricity out of the UK system at such times. 67 http://ec.europa.eu/energy/international/consultations/doc/20110410_consultation_document.pdf 68 Communication From the Commission to the European Parliament, The Council, The European Economic and Social Committee and the Committee of the Regions: “Energy Infrastructure priorities for 2020 and beyondZ-A Blueprint for an integrated European energy network”, COM (2010) 677/4, http://www.energy.eu/directives/com-2010–0677_en.pdf, page 16. 69 See footnote 14, Appendix, section 4.1, page 42. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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Another concern that has been raised is whether by increasing interconnection with other European countries, the UK could end up in a situation where it is unable to use or export power generated from its own renewable energy assets because imports from elsewhere in Europe could be cheaper. Again, we believe that this risk is fairly unlikely to occur in practice. Given that the majority of the UK’s renewable energy power over the next two decades will come from wind sources, which have no fuel costs,70 the price of electricity on the UK market at times of excess renewables output is likely to be very low and therefore very competitive with electricity prices in other electricity markets. It is worth reiterating here that the value of the UK’s marine renewables estate is enormous. The Offshore Valuation Report,71 which was issued by DECC, the Crown Estate and key energy industry players sized the UK’s full practical renewable energy offshore resource at 2,131 TWh/year—six times the current UK electricity demand72—and found in particular that by just using 29% of the UK’s practical offshore resource,73 the UK could become a net exporter of electricity by 2050, generating around 145,000 jobs and £62 billion of annual revenues for the UK. Using an even greater share of this potential could gradually move the UK towards a position of becoming a net exporter of energy.74 Developing a European supergrid is key to unlocking this electricity generation potential and the beneﬁts it could provide to the UK economy.

Question 3: How much would it cost to create a supergrid and who would pay for it? The costs of a supergrid Information regarding the capital costs of a supergrid remain generic, given the range of different models that are available. At European level, a recent study prepared for the European Commission’s DG Energy75 and based on the infrastructure proposals of the Ten Year Network Development Plan76 published by ENTSO- E suggests that the costs of electricity interconnection between Member states up to 2020 would amount to roughly€27.7 billion. This comes in addition to forecast investments in offshore transmission network infrastructure in the order of€32.8 billion by 2020. Based on a high renewable energy scenario for 2030, 77 the same study estimates that total interconnection costs between Member states could amount to€61.2 billion, whilst offshore grid costs would amount to approximately€99.8 billion. 78 Another way of estimating interconnection costs on a project by project basis could be to take a bottom up approach and look at the costs of recent interconnection or subsea connection projects, where those are available. Two recent projects which may be valuable in terms of understanding the costs of subsea interconnection for the UK are the proposed West Coast subsea “bootstrap” connection between Ayrshire and North Wales, planned for 2015 (capacity of 2,000MW, distance of 400km and approximate cost of £1,000/ MW.km) and the BritNed interconnector that was recently commissioned (capacity of a 1,000MW, distance of 260km and approximate cost of £2,000/MW.km). The capacity and distances of these two projects are representative of likely connections to mainland Europe and provide an average cost estimate of £1,500/ MW.km, which appears reasonable to use.

The financing challenge Clearly, the amount of interconnection required to create a European supergrid will require substantial upfront capital costs, which will present a financing challenge. The European Commission acknowledged in its Energy Infrastructure Priorities Communication that only about 50% of the€200 billion required for energy transmission networks investment by 2020 will be taken up by the market, thus leaving a substantial financial gap.79 To solve this financing gap, the European Commission has highlighted two key areas of work: — The first is to improve the leveraging of private financing sources through better cost allocation. Given that current tariff setting remains national, the Commission is proposing to put forward later in 2011 some guidelines or legislative proposals “to address cost allocation of major technologically complex or cross-border projects, through tariff and investment rules”. Such guidelines/legislation would aim to reflect the fact that the most efficient approach for a transmission system operator to address national customer needs may at times require investment in a network outside national boundaries. 70 This benefit is not negligible given the current volatility of fossil fuel prices. 71 The Offshore Valuation Report: A valuation of the UK’s offshore renewable energy resource, July 2010: http://www.offshorevaluation.org/downloads/offshore_vaulation_full.pdf 72 See page 6. 73 See scenario 2. 74 This occurs under scenario 3, where the UK harnesses 76% of its practical offshore resource. It is important to bear in mind that these assumptions were based on a high level of electricity demand by 2050, envisaging a 74% increase in electricity demand by 2050 compared to 2008 levels, implying that if the UK was successful at substantially reducing its demand for energy, an even smaller amount of the UK’s offshore resource would have to be used to make it an electricity or energy exporter. 75 KEMA, COWI, Imperial College, The Revision of the European Trans-network Policy (21 October 2010), Report for DG Energy, http://ec.europa.eu/energy/infrastructure/studies/doc/2010_11_ten_e_revision.pdf. 76 https://www.entsoe.eu/index.php?id=232 77 The high renewable energy scenario used in this study was based on the ECF Roadmap 2050’s 80% renewable energy scenario, with generation & interconnection capacities cast back to 2030. See page 11 of the study for more information. 78 See footnote 21, table 1 on page v for all the data. 79 See footnote 14, section 2.7, page 9. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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— The second is to optimise the leverage of public and private sources by mitigating investor risks. This would require not only strengthening the EU’s partnership with international financial institutions but also developing a range of innovative financing tools80 “that are different, flexible and tailored towards the specific financial risks and needs faced by projects at the various stages of their development”,81 by paying particular attention to projects that will contribute to the EU’s 2020 targets and which can deliver EU-wide benefits which the market alone cannot provide. The range of tools that are being proposed by the Commission beyond the traditional support forms of grants and interest rate subsidies include “equity participation and support to infrastructure funds, targeted facilities for project bonds, test option for advanced network related capacity payment mechanism, risk sharing facilities (notably for new technological risks) and public private partnerships loan guarantees.”82

Who should pay? Electricity infrastructure in Europe is generally built on the basis of “user commitments” that commit in advance to using the infrastructure. Electricity networks are therefore generally subject to a business model based on regulated tariffs that are then collected from users of the network to recover the original investment costs (the “user pays principle”). It seems reasonable to assume that in most (but not all) cases, this tariff structure could continue to apply when charging for the use of interconnection as part of a European supergrid. However, the situation is more complex when one or the main beneficiary of a particular interconnector or specific section of a supergrid is a third country—this is an issue that will need to be looked at carefully by the European Commission when developing its guidelines or legislative proposals on cost allocations. It is also important to note that the development of a strategic European supergrid will require a certain amount of “planning ahead” of specific user commitments being made (especially post 2020), which may for instance require installing cables with slightly larger capacity than what is immediately needed or designing tee points/cable routes that can accommodate further connections at a later date. This anticipatory approach to building infrastructure will need to be taken into account when designing the appropriate tariff structure.

Putting these costs in context As explained in the executive summary and below in response to questions 4 and 5, whilst the upfront capital costs for interconnection infrastructure are likely to be substantial, it must be remembered that this new infrastructure will allow substantial savings in the long-run (by optimising the use of Europe’s renewable energy resources and substantially reducing the amount of “back-up”/“peaking” generation required to support an increasingly higher share of renewables). Such investments will also amount to a small part of total infrastructure spending in the EU power sector (0.5% to 1.6% of total power sector costs according to the ECF Roadmap 2050 report’s 40% to 80% renewable energy scenarios). Regardless of how the tariff structures are developed for the use of a European supergrid, consumers will ultimately be bearing the costs of such infrastructure. However, given the common understanding that decarbonising the power sector is essential to meet emission reduction objectives, supporting the development of an electricity transmission infrastructure that will optimise the use of energy resources across Europe and reduce the amount of generation assets required to address the intermittency of some forms of renewable energy (by up to 35%–40% according to the ECF Roadmap 2050 study),83 appears to be a package worth supporting given the substantial long-term beneﬁts it could offer European consumers.

Question 4: Will a supergrid help to balance intermittency of electricity supply? A European supergrid could play a significant role in helping to balance the intermittency of supply-driven renewables, in particular by spreading this intermittency over a much wider geographical area and facilitating imports and exports of renewable energy power between Member states at times of high / low renewable energy output nationally. A European supergrid would in particular make sense from both a security of supply and decarbonisation perspective, as it would help optimise the efficient use of Europe’s vast and mixed renewable energy sources (not all of which are intermittent), whether it be wind, wave and tidal power from the North Sea, geothermal and hydropower from Scandinavia and the Alps, biomass from Eastern Europe (and some Nordic countries such as Finland) or solar power (including concentrated solar power) from Southern Europe and North Africa.84 80 This raises issues similar to the thinking behind the Green Investment Bank in the UK. 81 See footnote 14, section 5.4.2, page 17. 82 See footnote 14, section 5.4.2, page 17. 83 See answer to question 5. 84 It is worth noting that the security of supply concerns regarding electricity imports from Northern Africa (mainly linked to vulnerability to political instability in host countries) are often overplayed. For instance, in the ECF Roadmap 2050 report, “the 15% of total EU supply assumed in the 100% renewable scenario would mean no more than about 5% of total supply coming from any single country, and the power would flow across tens of individual export cables. Thus the share of total supply that would be exposed to individual points of disruption is of a magnitude that European system operators plan against today in the normal course of business.” See http://www.roadmap2050.eu/attachments/files/Volume1_fullreport_PressPack.pdf, page 75. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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The efficient and optimum use of the EU’s renewable energy sources also means that interconnection infrastructure can help balance the intermittency of electricity supply in a very cost efficient manner, by in particular reducing the amount of “back-up”/“peaking” generation capacity required to provide power at times of low national renewable energy output. The European Climate Foundation Roadmap 2050 report found for instance that increased interconnection could limit the “load factor” (or utilisation rate) of back-up plants to 5% in an 80% renewable energy scenario and 8% in 100% renewable energy scenario.85 This point was also reiterated by the European Commission in its latest Energy Infrastructure Priorities Communication: “Through a well interconnected and smart grid including large scale storage the cost of renewable deployment can be brought down, as the greatest efficiencies can be made on a pan-European scale”.86

The role of enhanced interconnection at EU level and more effectively integrated European electricity markets was also recognised as a potential source of system ﬂexibility in a recent report prepared for the Committee on Climate Change ahead of the Fourth Carbon Budget Report. In particular, this report stressed that when designing a capacity mechanism (to help secure the system at times of lower renewables output and high demand), it was important for policy makers to consider how the revenue streams under such mechanisms could be “accessed by parties outside the generation sector. Otherwise, there is the risk of distorting the incentives for provision of ﬂexibility in favour of generation”,87 which would be likely to increase costs for consumers and businesses.

WWF is aware of a recent summary report issued by Pöyry Energy Consultants, arguing that increased interconnection capacity was unlikely to substantially reduce the need for back-up plants and was unlikely to “average out” the intermittency of renewable power across Europe.88 WWF has only been able to review the short publically available summary of this report. As an initial observation from our review of this summary, we believe that there are some important limitations to the findings of this report: — Firstly, this report only considers the situation in Northern Europe and therefore fails to consider the benefits of interconnection with the vast renewable and especially solar resources of Southern Europe and Northern Africa, which could be a key part of the design of a European supergrid. — Secondly, the report is based on aggregating the National Renewable Energy Action Plans submitted by different Member states under the 2009 Renewable Energy Directive. Given that those plans were very much developed on a national self-sufficiency basis and therefore paid little attention on the potential benefits of cross-border interconnection, it is very likely that the Pöyry report under-recognised the benefits of interconnection which would have been made more obvious if the report had reviewed an integrated European market model. — Thirdly, the report does not look at the effect of aggregating demand patterns across Europe, which would have provided a clearer picture of the role of demand side response and enhanced interconnection capacity in helping address the intermittency of supply-driven renewables.

Question 5: Would a supergrid reduce energy prices for consumers and businesses?

Economic beneﬁts of a supergrid

A European supergrid has the potential to reduce energy prices for consumers and businesses, as it is the key physical pre-requisite to improving electricity resource sharing across Europe and reducing the amount of back-up generation required at Member state level to support a greater deployment of supply-driven renewables. According to the ECF Roadmap 2050’s 80% renewable energy scenario, increased interconnection at EU level could reduce total reserve requirements by 35–40%. This will be key in helping maintain competitive electricity prices and protect the competitiveness of European businesses.

Similar points were made by the European Commission in its Communication on Infrastructure Priorities: “The cost of not realising these [energy transmission network] investments or not doing them under EU-wide co-ordination would be huge, as demonstrated by offshore wind development, where national solutions could be 20% more expensive. Realising all needed investments in transmission infrastructure would create an additional 775,000 jobs during the period 2011–20 and add€19 billion to our GDP by 2020, compared to growth under a business-as-usual scenario”.89 85 European Climate Foundation, Roadmap 2050, A Practical Guide to a Prosperous Low-Carbon Europe, Technical Analysis, Page 19: http://www.roadmap2050.eu/attachments/ﬁles/Volume1_fullreport_PressPack.pdf. 86 See footnote 14, section 2.1, page 6. See also introduction section on page 4. 87 Poyry Energy Consultants, Options for Low-Carbon Power Sector Flexibility to 2050: A report to the Committee on Climate Change, October 2010: http://downloads.theccc.org.uk.s3.amazonaws.com/4th%20Budget/fourthbudget_supportingresearch__Poyry_ %20power%20sector%20ﬂexibility%20to%202050.pdf, page 8. 88 Pöyry Energy consultants, The challenges of intermittency in North West European power markets, March 2011 http://www.poyry.com/linked/services/pdf/142.pdf 89 See footnote 14, section 2.7, page 9 and the associated Impact Assessment document. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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The need for harmonised market rules

However, the ability of a supergrid to provide competitive energy prices across Europe will not be fully effective unless harmonised market rules are developed at EU level, as this will be key to avoid market distortions. Action on EU decarbonisation objectives would also be helpful to ensure that the supergrid can be developed in the context of increasingly optimising the EU’s vast renewable energy resources. Clearly, this will require substantial political will. However, the potential of a European supergrid to substantially reduce the costs of decarbonising the EU’s power sector (and help address carbon leakage concerns), the current uncertainties around future fossil fuel prices (making the future costs of remaining in the existing electricity generation mix increasingly uncertain), the growing package of EU climate/energy legislation,90 as well as new pan-European initiatives being pursued by key EU Member states (such as the North Seas Countries Offshore Grid Initiative) all point to the fact that there is an existing basis upon which political agreement towards a well functioning internal market for electricity and more stringent EU emission reduction targets can gradually be achieved. It is also worth noting here that the European Commission recently called in its latest Energy Non-Paper91 for harmonised market rules to be developed by 2014, a demand which was fully endorsed in February this year by the European Council.

Action on the EMR should not be delayed

The gradual development of EU wide rules on market harmonisation and the need for more stringent European emission reduction targets should not be used as an excuse to delay power sector decarbonisation action in the UK as part of the electricity market reform (EMR), although more consideration is required as to how the proposals under the EMR could ﬁt within a European supergrid and a more integrated European power market. The UK has at its disposal one of the most valuable renewable energy resources (and potentially CO2 storage resources) in Europe,92 which can offer the UK substantial energy security in a low-carbon world93and industrial growth beneﬁts.94 Early action from the UK in reducing its carbon intensity and building strong industrial leadership in marine renewables and CCS will put the UK in a strong position, as deeper market harmonisation rules are developed and more stringent European emission reductions kick in.95

Question 7: Which states are potential partners with the UK in a supergrid project?

Overall EU priorities for 2020

In its Energy Infrastructure Priorities Paper, the EU Commission highlighted the following four “priority corridors” to make Europe’s electricity grid “fit” for 2020: “1. Offshore grid in the Northern Seas and connection to Northern as well as Central Europe—to integrate and connect energy production capacities in the Northern Seas with consumption centres in Northern and Central Europe and hydro storage facilities in the Alpine region and in Nordic countries. 2. Interconnections in South Western Europe—to accommodate wind, hydro and solar, in particular between the Iberian Peninsula and France, and further connecting with Central Europe, to make best use of Northern African renewable energy sources and the existing infrastructure between North Africa and Europe. 3. Connections in Central Eastern and South Eastern Europe—strengthening of the regional network in North-South and East-West power flow directions, in order to assist market and renewables integration, including connections to storage capacities and integration of energy islands. 4. Completion of the BEMIP (Baltic Energy Market Interconnection Plan)—integration of the Baltic States into the European market through reinforcement of their internal networks and strengthening of interconnections with Finland, Sweden and Poland and through reinforcement of the Polish internal grid and interconnections east and westward”.96 90 This includes in particular the existing set of 3 internal market directives for electricity and gas, the 2020 climate package, the latest Commission Communication on Infrastructure Priorities and the upcoming 2050 Energy Roadmap. 91 DG Energy, The Internal Energy Market—Time to Switch into Higher Gear, Non-paper, http://ec.europa.eu/energy/gas_electricity/legislation/doc/20110224_non_paper_internal_nergy_market.pdf 92 See reference to Offshore Valuation Report in answer to question 2 (footnote 14). The report found that the net value of the UK’s marine renewable energy sales in the period from 2010 to 2050 could be worth up to £126 billion under the “High High” DECC price scenario (see page 78). 93 The 29% practical offshore resource scenario in the Offshore Valuation Report referred to in answer to question 2 would deliver 1.1 billion tonnes of CO2 emission reductions in the UK between 2010 and 2050 (see page 6 of the report). 94 Building a low-carbon economy: the UK’s innovation challenge, Committee on Climate Change, July 2010, http://hmccc.s3.amazonaws.com/CCC_Low-Carbon_web_August%202010.pdf, see in particular part 2, pages 14 to 16. The CCC makes the point in particular that both marine renewables and CCS are areas where the UK has a natural advantage to become an industrial leader, thus warranting that these technologies should be both “developed and deployed” in the UK rather than simply “deployed”, using foreign imports. 95 In this context, it is important to recall that both EU emission trading law and the cap that it introduced have no sun-set clause. Each and every year going forward, the overall ETS cap will be automatically reduced by a fixed percentage, which is currently 1.74%. While this “linear factor” still needs to be increased (e.g. to 3%), nonetheless it legal nature ensures binding emissions reductions are maintained in the electricity sector to and beyond 2020, and to and beyond 2050. 96 See footnote 14, section 4.1, page 10. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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Direct partners for the UK The first priority corridor is clearly the most relevant for the UK, although it is important not to underestimate the importance of developing the other corridors as well (especially the interconnections in South Western Europe), which will enable the UK to reap the full benefits of pan-European interconnection. The UK is one of 10 signatories of the North Seas Countries Offshore Grid Initiative’s Memorandum of Understanding,97 signed in December 2010, the purpose of which is to find common technical, regulatory and policy solutions to the development of a North Sea grid infrastructure. Of these 10 members, the UK already has existing interconnection capacity with France (currently 2GW) and The Netherlands (1GW—since 1 April 2011) and has a planned East-West interconnector with Ireland (500MW) in addition to the Moyle interconnector (460 MW) which currently links Scotland to Northern Ireland. It is reasonable to assume that interconnection capacity with these existing partners, as well as new partners in North West Europe will need to be increased in the run up to 2020 and beyond. However, in addition to improved interconnection with partners in North West Europe, the development of new interconnection infrastructure with Norway and Iceland is likely to be very beneficial for the UK from a security of supply perspective, given the availability of fairly large baseload hydropower (Norway98) and geothermal power (Iceland) resources in these two countries. With respect to Norway, it is worth pointing out that Scottish and Southern Electric (SSE) and Norwegian utilities are currently developing proposals for a DC link of up to 2 GW capacity,99 whilst initial talks have taken place between the UK and Iceland officials on the feasibility of a UK-Iceland interconnector.100

Question 9: Would new institutions be needed to operate and regulate a supergrid? Given the variety of cross-border regulatory issues that it will entail, the technical development of a European supergrid will need to be matched by a clear European regulatory framework (especially if an overlapping structure is adopted).101 This will essentially require the development of a European transmission system operator and of a European electricity regulator. It is important to note that the foundation structures for these two bodies are already in place through the Agency for Co-operation of Energy Regulators (ACER) and the European Network for Energy Transmission System Operators (ENTSO-E). Therefore, what is required is for these bodies to evolve into organisations in their own right, rather than creating completely new institutions. In terms of mandates, it will be important for both ACER and ENTSO-E to be responsible for developing a strategic interconnection plan for 2020 and beyond that would facilitate the near-decarbonisation of the EU’s power sector and the optimisation of energy resources across Member states. As set out in the Policy Recommendations of the European Climate Foundation’s Roadmap 2050 report,102 key areas of focus for ACER and ENTSO-E should include: — assimilating long-term forecasts of generation and demand side resources at both Member state and regional level; — using this baseline to develop a strategic interconnection plan; — providing feedback to Member states on interconnection opportunities to reduce the costs of decarbonising the EU’s power sector while maintaining power system reliability and long-term security of supply. This is now beginning to be addressed as part of ENTSO-E’s work on the Ten Year Network Development Plan, although a more forward looking outlook (e.g. 20 years instead of 10) will ultimately be required to ensure the strategic identiﬁcation of interconnection opportunities. From a UK perspective and pending further EU regulatory and legislative developments, it will be important for the Government to play an active role in the North Seas Grid Initiative, which is strategically the most valuable interconnection “corridor” for the UK. Greater attention to grid issues will also be needed within longer term energy planning. In particular, further consideration of improved interconnection infrastructure and European power market integration will be needed in the development of DECC’s 2050 pathways, the development of the EMR process and the European Commission’s upcoming “Energy Roadmap” to 2050. April 2011

97 http://ec.europa.eu/energy/renewables/grid/doc/north_sea_countries_offshore_grid_initiative_mou.pdf. The other nine countries are Belgium, Denmark, France, Germany, Ireland, Luxembourg, The Netherlands, Sweden and Norway. 98 Norway’s existing reservoir capacity is understood to be around 100 TWh. 99 http://www.newenergyworldnetwork.com/renewable-energy-news/by-technology/wind/sse-subsidiary-enters-jv-to-launch- norway-scotland-renewable-transmission-developer.html 100 http://www.platts.com/RSSFeedDetailedNews/RSSFeed/ElectricPower/8678578 101 Cross-border regulatory frameworks have already been developed in the past—a recent, albeit much smaller scale example, is the development of the Single Electricity Market (SEM) on the Island of Ireland which required the merging of the Northern Ireland and Republic of Ireland Grid Codes, which operated in very different technical and market contexts prior to the introduction of the SEM. 102 European Climate Foundation, Roadmap 2050, A Practical Guide to a Prosperous, Low-Carbon Europe, Policy Recommendations, http://www.roadmap2050.eu/attachments/ﬁles/Volume2_Policy.pdf, page 9. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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Memorandum submitted by the Scottish Government 1. Background 1.1 This response is submitted on behalf of the Scottish Government by Dr Patrick McWilliams, manager of the Irish-Scottish Links on Energy (ISLES) study, and Michael McElhinney, Head of Energy Markets. 1.2 Supported by the EU’s INTERREG IVA Programme, ISLES is a collaborative project between the Scottish Government, Northern Ireland Executive and Government of Ireland. It is assessing the feasibility of creating an offshore interconnected transmission network and subsea electricity grid to connect and transport electricity created from renewable energy sources in the coastal waters linking Scotland, Northern Ireland and Ireland. By delivering a credible and ground-breaking evidence-based assessment of the practical steps, challenges and opportunities to accelerate infrastructure development for 2020 and beyond, ISLES’ pioneering work is a signiﬁcant step along the road how to create possible offshore interconnected grid networks. 1.3 Moreover, by assessing how better to connect up markets, regulatory frameworks, powers and support and incentivisation mechanisms, ISLES is mapping out a pathway for an interconnected offshore grid, with substantial amounts of renewable energy, across boundaries and potentially as part of a European integrated electricity market. The project, of strategic importance and a signiﬁcant piece of research in an EU-wide context, is now a formal part of the North Seas Countries Offshore Grid Initiative.

2. Context 2.1 Scotland has some of the most signiﬁcant offshore renewable energy resources in Europe—with much as a quarter of Europe’s offshore wind and tidal energy resource and an estimated 10% of its capacity for wave power. A major UK Offshore Valuation Study, published in partnership with industry and Government in May 2010, estimated Scotland’s practical offshore renewables resource at 206 GW (almost 40% of the overall UK total). 2.2 Scotland has 7 GW of renewable energy capacity installed, under construction or consented. We are on track to hit our Scottish Government target of 31% of electricity consumed in Scotland provided by renewable energy by 2011, and we are conﬁdent of delivering 100% by 2020. 2.3 It is clear that renewable energy from Scotland will play the crucial role in helping the UK progress towards meeting its renewable energy target and delivering our low carbon renewable energy future. 2.4 The Scottish Government is, therefore, working closely with our UK and EU counterparts, with Ofgem, National Grid and Scottish Transmission System Operators to ensure energy from Scotland plays its part in meeting renewable energy, carbon reduction and climate change targets set by Governments—and helping ensure secure and sustainable energy supplies—at Scottish, UK and EU level. 2.5 The Scottish Government vision is for Scotland to play its part in developing onshore and offshore grid connections to the rest of the UK and to European partners—to put in place the key building blocks to export energy from Scotland to national electricity grids in the UK and Europe. 2.6 We want Scotland to play its part in building a Europe-wide supergrid to help meet Scottish, UK and EU renewable energy targets and address the challenges of climate change, as well as ensuring security of future energy supply through greater interconnection. 2.7 Scotland’s remarkable wind and wave energy potential is a major opportunity for Scotland. But the challenge of developing the grid connections to make this happen—and the cost of doing so—is substantial.

Offshore Grid 2.8 Developing offshore interconnected grid work requires a collaborative approach to strengthening national grids while developing interconnections between countries, regions and members states into a strategic, coordinated and connected grid network—and developing an offshore grid in the North Seas in modular form to deliver an interconnected North Seas grid. 2.9 It also needs significant and sustained effort to work with other parts of the GB networks and EU countries and regions to standardise electricity transmission and energy regulation. The Scottish Government is working closely with UK and EU partners on this. 2.10 The period 2010–18 will see significant activity to reinforce and develop onshore and offshore connections in Scotland to address some of the grid constraints within the GB system (and between Scotland and England in particular) and to connect both our onshore and offshore renewable generators. 2.11 The Electricity Networks Strategy Group (ENSG) Vision 2020 report of March 2009 highlighted the electricity transmission network reinforcement that will enable Scotland and the UK to meet the EU target of 15% of UK energy from renewable sources by 2020. 2.12 It identifies the need for two subsea cables linking Scotland to centres of energy demand in the southern part of the UK. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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— a West Coast 1.8 GW HVDC link between Hunterson and Deeside—attracting investment of around £760 million. Planning for this is already underway, with consultation on possible sea route and landing points issued in June 2010. The target for commissioning the link is 2015; and — an East Coast 1.8 GW HVDC link between Peterhead and Hawthorn Pit in Humberside— attracting investment in the region of £700 million. The target for commissioning this link is 2018. 2.13 It also includes plans for subsea HVDC links to the Scottish mainland and the Shetland Islands, Orkney and the Western Isles, and also in Argyll and Bute region. 2.14 A subsea cable connecting Caithness to the Moray coast is also being developed, which will act as a hub for offshore wind projects in the Moray Firth. Further grid connections will be necessary to the other Round 3 offshore wind farms currently in development. In addition, interconnectors will be needed to allow renewable energy to be transmitted from the Western and Northern Isles to the mainland. 2.15 In January 2011, Scottish and Southern Energy and a consortium of Norwegian and Swedish renewable energy developments began work to assess further the options for a subsea cable between Scotland and Norway—for deployment by 2018. The Scottish European Green Energy Centre (SEGEC) in Aberdeen will play a key role in supporting the route survey stage of this important and iconic project. 2.16 Ten countries around the Northern European Seas have agreed a Memorandum of Understanding on delivering an interconnected North Seas. This joint declaration will increase cooperation between member- states in the development of offshore grid connections. It will produce a roadmap to developing the North Seas Grid by the end of 2011. DECC is taking forward this work and the Scottish Government is working closely with DECC. 2.17 In the Irish-Scottish Links in Energy Study (ISLES) project, the Scottish Government is working in partnership with the Governments of Ireland and Northern Ireland—with EU INTERREG IVA funding—on a feasibility study into development of an offshore transmission grid to exploit offshore energy off the west coasts. This project will be key to delivering a subsea grid in the Irish Sea. It will report by the end of 2011. 2.18 This project will also identify the main challenges and opportunities in an offshore interconnected grid—around interconnection, standardisation of regulatory and legal frameworks and renewable energy and infrastructure support mechanisms. 2.19 For more information on ISLES, including a summary of what the feasibility study hopes to achieve, please visit the project website (www.islesproject.eu) or contact the project manager: [email protected]

3. Responses to Questions 3.1 Whether the UK should be prioritising projects within the British Isles? 3.1.1 It is critical for the UK Government, in partnership with its devolved administrations, to identify a number of priority energy corridors in home waters to help accelerate the development of an offshore grid. Included amongst key initiatives to that end are the following: — ENSG’s report (2009) — The EC has identiﬁed priority corridors in its Strategic Energy Technology (SET) Plan and investment priority work in the EU Energy Infrastructure Plan. — National Grid has been working on the Offshore Development Information Statement (ODIS) that ﬂags up the areas of resource. — Rounds 1, 2 and 3 licensing rounds are identifying priority areas for development. — DECC/Ofgem are leading work to assess options for Coordinated Offshore Transmission networks. — Scottish Ministers have undertaken an Environmental Impact Assessment (EIA) of the six priority development sites across Scotland. — Marine Scotland is aligning Scotland offshore planning powers to identify priority development in the offshore marine environment (in the same way that the Scottish Government covered onshore with its National Planning Framework 2 (NPF2) published in mid-2009). — The British-Irish Council (BIC) All-Islands Approach is identifying priority areas for joint working. 3.1.2 Clearly it is very important for the UK not to lose sight of its natural competitive advantage in renewables. However, focusing on UK interests alone is not the way forward, not only in view of our obligation to meet EU-wide energy reduction targets but to take advantage of funding steams that will give priority to collaborative working towards the delivery of offshore infrastructure. cobber Pack: U PL: CWE1 [E] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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3.1.3 Moreover, a key driver for investing in harvesting a renewable bonanza is export. The potential renewable electricity resource far exceeds demand in the UK and Ireland, and the surplus needs to be sold on at best commercial price. Without a uniﬁed European energy market and the infrastructure to transport electricity, the UK could not make best commercial use of its renewable resources, in itself a major disincentive to the private investment that is critical for development of grid infrastructure. 3.1.4 The UK Government should support the transfer the evidence base from current ground-breaking projects like ISLES to a wider EU audience and seek further EU funding to pave the way for the implementation of an offshore grid off Britain and Ireland as part of a major EU-wide initiative like the supergrid.

3.2 How this would fit with a wider European project? 3.2.1 This answer has two elements: (a) the EU-wide context and regulatory framework in which energy markets operate; (b) North Seas Countries Offshore Grid Initiative (NSCOGI), the EU’s strategic vehicle for the delivery of an offshore grid. 3.2.2 Energy markets operate both within a stringent EU framework that requires compliance with directives and, in particular, through the current implementation of the “Third Package”, a series of reforms to liberalise and unbundle European energy markets. Energy Commissioner Gunther Oettinger framed the context for an offshore grid, observing that the “obligation of solidarity among member-states will be null and void without an internal infrastructure and interconnectors across external borders and maritime areas” (Energy 2020 document and address to European Network of Transmission System Operators for Electricity [ENTSO-E] 10/ 2/11). Complementary to this process is a more sustainable onshore network fit for purpose, i.e. capable of receiving and transmitting offshore electricity, which is highly problematic with the current ageing electricity infrastructure throughout much of Europe. 3.2.3 EU guidelines, plans and directives that govern the planning and implementation of an offshore grid include: — EU Congestion Management Guidelines. — EU Internal Energy Market Packages. — EU Energy Climate Change Package. — EU Renewable Energy targets. — RE Directive and MS Action Plans to 2020. — EU SET Plan. 3.2.4 In addition, three elements of the strategic policy initiative “Europe 2020” are particularly relevant to an offshore grid: 1. Energy infrastructure priorities for 2020 and beyond—A Blueprint for an integrated European energy network. 2. A strategy for competitive, sustainable and secure energy. 3. Energy Roadmap 2050. 3.2.5 NSCOGI is contributing to achieving the goals of the EU Third Energy Liberalisation Package. Through providing the infrastructure to help transport electricity purchased on the open market, NSCOGI is critical to the unbundling, freeing-up and enhancement of electricity markets in the EU. Integrated, not fragmented, markets are what the EU member-states require in order to facilitate greater flows of electricity across borders. 3.2.6 NSCOGI, through flagship projects like ISLES, is encouraging a modular approach to offshore network development and offering access to onshore networks for offshore renewables. In addition, it can maximise the 'bankability' of both the renewable generation capacity and the network capacity by: facilitating generators' access to multiple markets; maximising the utilisation of expensive offshore networks; contributing towards management of variability and uncertainty of renewables through sharing of reserve across larger areas. 3.2.7 Two potential outcomes of a joined-up electricity market in Europe are a more stable and secure supply and better competition amongst generators to force prices down, and it being possible for member-states to meet renewables targets by buying green electricity from other member-states. As long as protocols exist to prevent a member-state from having first claim on electricity, and a market for trading renewables across the EU being in place, then a supergrid would balance intermittency of electricity supply.

3.3 Your experience of planning/financing difficulties? 3.3.1 In furtherance of its ambition to become a renewable energy powerhouse, Scotland is striving to align its onshore and offshore planning powers (as noted above). On financing, a measure designed to promote the use of renewables is the Scottish Low Carbon Finance Initiative project led by the First Minister. This scheme is seeking to support Scotland's industries to adapt to and exploit low carbon business opportunities and help grow that sector. cobber Pack: U PL: CWE1 [O] Processed: [21-09-2011 13:37] Job: 014588 Unit: PG01

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3.3.2 In the context of offshore grid planning difficulties are synonymous with what is often termed the “regulatory challenge”. The ISLES study has identified challenging regulatory, territorial and political hurdles, and a complex patchwork of powers in three jurisdictions, including: — mix of offshore generation and regulatory frameworks; — mix of onshore grid capacity and regulatory frameworks; — mix of interconnection and networks; — mix of transmission pricing and market regimes, e.g. BETTA in the UK and the SEM on the island of Ireland; — mix of subsidy/incentive and charging, and capital cost recovery schemes; and — mix of sovereign state interest contributing to different targets—mutual and individual. 3.3.3 ISLES is examining the challenges of creating an offshore grid in a tripartite context. While its results are specific to the planning and regulatory landscape in the GB and Irish system, the study is highlighting issues that are broadly common across EU member-states. This homogeneity is additional to the application of EU directives which already bring a degree of convergence of policy throughout the Community, admittedly well short of a ‘Common Energy Policy’ for which there appears to be little appetite, either at EU or member- state level. On the other hand, can the development and regulation of a supergrid, while market driven, be left entirely to the market? 3.3.4 Cost estimates for the first phases of an offshore supergrid range from £30 billion projected by NSCOGI to £34 billion estimated by Friends of the Supergrid. The majority of this finance will be private, through investment in offshore renewable schemes and charges levied on customers, through bills, for upgrades to offshore and onshore infrastructure. Creating the conditions in which investment in offshore renewables is seen as attractive is a major challenge to governments. Put differently, this means solving the regulatory puzzle to remove uncertainty and a potential barrier to investment. 3.3.5 Moreover, offshore schemes that contain an element of ownership or match funding from public or EU sources are likely to be more attractive to the private sector, particularly in the context of offshore investment often being regarded as risky. The stamp of government or the EU, for instance the Europe 2020 Project Bond Initiative, should send a clear signal to investors that risk is being shared or minimised. The likelihood of offshore assets being stranded is, therefore, reduced, which clears another hurdle to private investment. 3.3.6 A case study that illustrates some of the planning or regulatory difficulties inherent in offshore connections between counties is that of the East-West Interconnector between Ireland and Great Britain (Wales) and the Moyle Interconnector between Northern Ireland and Great Britain (Scotland). 3.3.7 The East-West Interconnector, owned by Eirgrid and part financed by the European Investment Bank, when completed in 2012, will link up two sovereign states. Hence it is licensed by Ofgem and Commission for Energy Regulation (CER) in Ireland. The Moyle Interconnector, mutually owned, runs between two devolved areas of a sovereign state. The commonality between the two is a single market arrangement, namely the Single Electricity Market in force throughout the island of Ireland since 2007, and that both connect to Great Britain where a separate, but single, market arrangement applies. 3.3.8 Other areas of difference between the two assets are capacity, with Moyle being much more modest, and commercial arrangements whereby east-west electricity flows on Moyle are much larger than those permitted in the opposite direction. 3.3.9 In general terms, interconnection is often a merchant activity and not part of a regulated asset base. A common policy for the regulation of interconnection is needed but interconnection must not be treated differently to other offshore developments.

3.4 The UK’s ﬁrst steps to contribute to the development of an offshore grid? 3.4.1 The ﬁrst steps have already been taken through the interconnections already in place around the UK and those planned. At policy level, initiatives like the ISLES project and the UK’s becoming a signatory to NSCOGI, as well as its membership of the Adamowitsch Group, are advancing the understanding of the practical, policy, political, regulatory and legislative challenges in delivering offshore grid. 3.4.2 Collaborative and inter-governmental initiatives that seek to accelerate offshore grid development are highly valued by the EC and much more likely to receive funding towards implementation. An example of a funding stream that would be relevant in this context is the Trans European Energy Networks (TEN-E). June 2011

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