A European Supergrid

Memorandum submitted by Climate Policy Initiative (ESG 02)

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 [1] , 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 [1] , 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.

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 networks [1] - 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 (e.g., 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 [1] , 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.

(i) Integration with domestic congestion management

 

(ii) Joint allocation of international transmission rights

 

(iii) Integration with day ahead energy market

 

(iv) Integration with intraday/ balancing market

 

(v) Transparency of congestion management

 

Bilateral transmission rights auction

 

No

 

No

 

No

 

No

 

No

 

Joint multi-country auction of NTC rights

 

No

 

Yes

 

No

 

No

 

No

 

Multi-region day-ahead market coupling (zonal pricing)

 

No (only at zonal level)

 

Possible

 

Yes

 

No

 

No

 

Nodal pricing

 

Yes

 

Yes

 

Yes

 

Possible

 

Yes

 

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 of 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.

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.

Nodal pricing is based on the engineering solution to congestion management (Optimal Power Flow optimization) [1] . 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) [2] 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) [1] , 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 [1] . 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


[1] http://www.parliament.uk/business/committees/committees-a-z/commons-select/energy-and-climate-change-committee/news/new-inquiry-a-european-supergrid/

[1] http://ec.europa.eu/energy/renewables/grid/doc/north_sea_countries_of fshore_grid_initiative_mou.pdf.

[1] 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_win d/2010_annual_report_en.pdf.

[1] Available on www.climatepolicyinitiative.org , or can be requested by email from the authors.

[1] European Regulators’ Group for Electricity and Gas (ERGEG), www.energy-regulators,eu.

[1] Wood, A., J., Wollenberg, B. F.: “Power generation operation and control”, Wiley, 1996.

[2] Schweppe, F. C., Caramanis, M. C., Tabors, R. D., and Bohn, R. E.: “Spot pricing of electricity” , Kluwer Academic Publishers, Boston, MA, 1988.

[1] 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 08 September 2010.

[1] 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.