TODAY’S STUDY: WIND AND EU MARKETS

Connections are hard to make and harder to maintain but when they fall into place everything flows more efficiently and effectively.

It is possible to be rich in a single energy resource and still be impoverished by its limitations. Some energy sources are cheap but debilitatingly dirty. Others are abundant but problematically variable.

Because there is no single energy resource right now that solves every energy need everywhere, the wise choice is to be connected. Build an energy-carrying infrastructure to share many regions’ resources and build an energy-trading forum so the regions can meet in the marketplace and see to their own unique and fluctuating needs.

The report highlighted below is another in the four-part Smart Power Market Project (see last week’s first post, POWER MARKETS FOR NEW ENERGY). The Project is an assessment of Europe’s effort to include the New Energies into an advanced, comprehensive and efficient energy marketplace.

Connection-building comes more readily to Europe, where efforts to be loners and cowboys only led to disastrous and tragic wars over the last five centuries. The U.S. is still struggling to hear its better angels’ chorus singing about a comprehensive national energy policy and a new national transmission system.

Here’s hoping the 2010 fires in Russia and floods in Pakistan and the 2011 horrors in Australia will be enough and further consequences of an increasingly tempestuous and severe climate aren't necessary for this nation’s electorate to hear the deep soul and soaring harmonies of the New Energy choir singing about this good earth's sun, wind, deep heat and flowing waters.

Balancing and Intraday Market Design: Options for Wind Integration
Frieder Borggrefe and Karsten Neuhof, January 2011 (Climate Policy Initiative)

Executive Summary

EU Member States increase deployment of intermittent renewable energy sources to deliver the 20% renewable target formulated in the European Renewables Directive of 2008.

To incorporate these intermittent sources, a power market needs to be flexible enough to accommodate short-term forecasts and quick turn transactions. This flexibility is particularly valuable with respect to wind energy, where wind forecast uncertainty decreases from 15% to 4% in the last 24 hours before actual generation (from observed data in Germany). Therefore, intraday and balancing markets need to be adjusted to make full use of the flexibility of the transmission system and the different generation technologies to effectively respond to increased uncertainty.

The paper explores whether the power market designs in European countries offer opportunities and incentives for market participants to realise these technological opportunities.

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We assess whether current power market designs in several countries allow for their flexibility to adequately handle wind intermittency, in particular whether they:

1. Facilitate system-wide intraday adjustments to respond to improving wind forecasts,
- to ensure that the least cost generation capacity provides power and ancillary services.

2. Allow for the joint provision and adjustment of energy and balancing services:
- to reduce the amount of capacity needed to provide balancing services and to operate on part load.

3. Manage the joint provision of power across multiple hours:
- a broader set of actors can contribute energy and balancing services in day-ahead and intraday markets if they can coordinate sales across adjacent hours (thus more accurately reflecting technical constraints of power stations like ramp-up rates or start-up costs).

4. Capture benefits from international integration of the power system:
- the transmission network is the most flexible component of the power system, but requires fully integrated intraday and balancing markets to replace more costly generation assets and enhance system security.

5. Integrate the demand side into intraday and balancing markets:
- creating incentives and systems that allow the demand side to fully contribute to the available flexibility.

6. Effectively monitor market power:
- to ensure that cost-reflective intraday pricing bids encourage efficient dispatch choices and 1.) Limits costs for integrating intermittent renewables, 2.) Reduces the risk for market participants exposed to intraday adjustments, and 3.) Limits the need for utilities to balance within their portfolio and thus increases participation.

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When evaluating market designs based on these six criteria, it becomes apparent that none of the current power market designs applied across European countries fully meets all of them. The approach used in the US (locational marginal pricing/nodal pricing), however, provides appropriate price signals for the economic design and evaluation of the EU power grid and encourages the effective use of transmission capacity while improving interfaces between balancing and intraday markets.

The EU has made some progress towards integrating power markets, but today’s intraday and balancing market designs are far from a fully efficient and harmonised market. In the third Energy Package, the EU laid out a path for further regulatory harmonisation, which aims to foster a common energy market. The paper provides criteria that the market design must satisfy in order to support the large scale integration of renewables. It illustrates the value and importance of closely integrated operation and market designs for the European electricity system.

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Introduction

The growing share of wind and other intermittent generation sources in the European power supply increases the uncertainty about power production in day-ahead and longer-term predictions2. More accurate forecasts closer to production time reduce this uncertainty. This paper provides six criteria that power market designs need to satisfy in order to allow market participants and system operators to make full use of this information and thus limit the uncertainty and facilitate integration of intermittent renewable energy sources at lower costs and larger volumes, while also increasing system security.

European Member States and the Commission have committed in the EU Renewables Directive to the large-scale deployment of intermittent renewable energy sources across Europe and are assessing barriers that could cause delays and increase costs.

The paper addresses the three distinct types of markets currently used by most EU Member States:

1) Day-ahead markets that clear the day before power is provided; 2) Intraday markets that allow for adjustments after the closure of the day-ahead market until gate-closure, typically about one hour before real time; and 3) Balancing markets that are used by the system operator to resolve remaining imbalances. How does their design and limited integration across time and countries, constrain the full use of flexibility that generation, transmission, and demand can offer, and what options exist for improvements?

Historically, balancing markets have been the only markets to provide reserve and response operations. System operators contract this reserve and response capacity in day-ahead and longer-term markets with generators to provide flexibility that can be called upon on short notice to balance the system when forced power plant outages or load prediction errors occur. Balancing was only necessary for events of small probabilities (power station failures) or for small volumes (as in the case of load prediction errors); the amount of reserve capacity contracted was thus large compared to the small share of actual electricity requested. Balancing services were provided nationally, or in the case of Germany, within the region of the TSO. Mutual support between regions was restricted to emergency situations, such as unexpected power plant failures, and not remunerated (only energy that was provided had to be returned). Most power markets imposed penalties for deviations from day-ahead schedules to limit demand for balancing power.

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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 2008. Therefore, intraday and balancing markets need to be adjusted to allow the TSOs to appropriately respond to increased uncertainty.

The forecast error for wind decreases distinctly with a shorter lead-time (DENA, 2005; DENA, 2010; Focken et al, 2002; Von Roon and Wagner, 2009). In markets unable to adapt to changing wind forecasts during the day, large volumes of real-time balancing are required, and because of the high uncertainty of wind 24-36 hours ahead of physical feed-in, a significant amount of balancing reserve capacity is required. EWIS (2010) and Tradewind (2009) quantify the resulting additional costs for electricity generation due to the increased start-up and part-load costs to provide balancing power.

Different studies (Muesgens and Neuhoff, 2002; Tradewind 2009) point out that system costs for balancing wind uncertainty can be significantly reduced if an improved market design allows for optimisation of dispatch across the entire system based on wind forecasts with lead-times reduced to 1-4 hours ahead of physical dispatch. In addition, the design of markets for intraday balancing and markets for improved congestion management can also increase efficiencies.

This paper explores the different market design options to allow for intraday optimisation of the power system in the presence of wind power…

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Uncertainty of wind forecasts, and opportunities to reduce it

The power system has to deal with three main sources of uncertainty: demand uncertainty and load prediction errors3, failure of power plants, and the uncertainty of wind. Figure 1 illustrates that the aggregate uncertainty about the balance of power supply and demand increases with uncertainties of the individual components.

The following factors need to be considered when evaluating the impact of wind uncertainty on the power system:

 Uncertainty about wind projections decline during the last 24 hours. The demand and supply uncertainty that has to be balanced in real time can be reduced significantly if additional information and updated wind forecasts within the last hours before physical dispatch are used effectively.

 The aggregate uncertainty is less than the sum of the individual uncertainties as long as errors in wind projections, demand projections, and power failure stations are not fully
correlated (Dany and Haubrich, 2002). The factor that can contribute the biggest real-time imbalance of supply and demand is likely the failure of large power stations or transmission lines. If uncertainty in predictions of wind output is smaller than uncertainties about other factors, it might only have a small impact on real-time balancing needs.

There are three ways to reduce uncertainty.

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Improve the accuracy of wind forecasts

The accuracy of the wind power forecast has significantly improved in recent years. In Germany, the 24h forecasting error5 for the aggregate output from German wind turbines was significantly reduced from 6.1% in 2007 to 5.6 % in 2008 (Von Roon and Wagner, 2009). Future improvements of wind forecasting can be obtained based on improvements of the available wind models as well as their coupling. Further improvements of wind models will lead to an increase in forecasting accuracy in the coming years. The German DENA II study (DENA, 2010) predicts forecast errors onshore might be reduced by as much as 41% by 2020.

Despite this expected improvement in wind forecasts, the DENA grid study (DENA, 2005 and Bartels, 2006) shows that the uncertainty about predicting the absolute volume of wind output day-ahead will increase as wind penetration grows. Thus the demand for positive and negative balancing power, primarily for the time frame >15 minutes will likely increase if the current power market designs are maintained

. In short, improved wind forecasts alone will not be enough to reduce uncertainty sufficiently - we need to consider other options for reducing or managing uncertainty.

Reduce the lead-time for wind forecasts through intraday markets

The lead-time of wind forecast strictly determines forecast accuracy. When the wind forecast changes from a day-ahead forecast to an intraday forecast with a 1-4 hour lead-time, the errors decrease drastically. Figure 2 displays the percentage of the total installed capacity for a 1-,2-,4-,8- hour and day-ahead forecast for Germany in 2008. The average forecast error (RMSE) is reduced to 3.8% of the installed capacity compared to 5.9% (7.0%) of the 24h (36h) day-ahead forecast. (Smeers, 2008; Von Roon and Wagner, 2009)

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Average wind output over larger areas

Large wind areas can reduce uncertainty in the overall wind feed-in. The correlation of wind feed-in and uncertainty strongly depends on the distance between wind farms (Figure 4) and therefore also on the size of the investigated area. This effect can be observed even for significantly large areas. The integration of the German transmission system operators (TSOs) into one market in 2009 provided a good example. The day-ahead (24h) forecast error (RMSE) for each of the four TSOs was between 6.6% and 7.8%. Bundling the region reduced the forecast error to 5.9% (Figure 3).

This paper focuses on these last two opportunities and thus investigates the institutional perspective: reducing lead time through 1) intraday markets and by 2) increasing the size of wind areas.

…3 Flexibility of the power system to deal with the uncertainty…4 The challenges for the current power market system…5 Developments in the EU towards an integrated market design…

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Conclusions

All long-term electricity scenarios show a large increase in installed wind capacities within Europe in the coming decades. Despite significant improvements in wind forecasting, the day-ahead forecasts will induce increasing uncertainty into the European electricity system. It will therefore be essential to make use of two factors: the improving wind forecasts within the hours between the day-ahead market and real-time dispatch, and the full flexibility that the generation, transmission, and demand side of the power system can offer to limit cost increases to deal with this (wind-) uncertainty and to ensure full system security.

The power market design therefore has to satisfy six criteria:

1. Facilitate system-wide intraday adjustments to respond to improving wind forecasts:
- to ensure that the least cost generation capacity provides power and ancillary services.

2. Allow for the joint provision and adjustment of energy and balancing services:
- to reduce the amount of capacity needed to provide balancing services and to operate on part load.

3. Manage the joint provision of power across multiple hours:
- a broader set of actors can contribute energy and balancing services in day-ahead and intraday markets if they can coordinate sales across adjacent hours (thus more accurately reflecting technical constraints of power stations like ramp-up rates or start-up costs).

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4. Capture benefits from international integration of the power system:
- the transmission network is the most flexible component of the power system, but requires fully integrated intraday and balancing markets to replace more costly generation assets and enhance system security.

5. Integrate the demand side into intraday and balancing markets:
- creating incentives and systems that allow the demand side to fully contribute to the available flexibility.

6. Effectively monitor market power:
- to ensure that cost-reflective intraday pricing bids encourage efficient dispatch choices and 1.) Limits costs for integrating intermittent renewables, 2.) Reduces the risk for market participants exposed to intraday adjustments, and 3.) Limits the need for utilities to balance within their portfolio and thus increases participation.

When comparing market designs based on these six criteria, it becomes apparent that none of the current power market designs applied across European countries fully meets all of them. In contrast, the power market design that has been initially used in PJM and by New York ISO and that has since been adopted in Texas and California does satisfy all six criteria listed in this paper. The assessment in the accompanying paper on congestion management suggests that the PJM type power market design (locational marginal pricing) also performs well with regard to the effective usage of transmission capacity.

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Given the positive attributes of an alternative design, this raises the question of whether the current process of gradual EU power market design improvements can facilitate the implementation of such a design. The paper argues that more coordination and initiative at the EU level will be necessary to facilitate the effective operation of the common European markets. While some of the stakeholders might be reluctant to contribute to such a development, European consumers will benefit and EU Member States will be supported in their achievement of the renewable targets formulated in the EU renewable directive.

The third Energy Package provides opportunities to complement the bottom-up approach pursued so far on European power market design with top-down requirements. One cornerstone of the Energy package is the centralized organizational structure that is currently in place. As many market participants have disincentives to fully support a bottom-up transition to an integrated power market design, the provisions from the Energy Package might become essential in the European pursuit of a harmonized and effective power market design.