Alternative arrangements for renewables 3 rd October 2012 These slides are initial thoughts to aid discussion only. They are not in any way meant to signify the views of GEMA, which for the avoidance of doubt has not made any decisions on this particular issue.
Contents • Context • Current arrangements • Interactions • Options for reform • Questions for Stakeholder groups 2
Context • The amount of wind and other intermittent generation on the GB system is very likely to grow due to de-carbonisation targets and other government policies • Intermittent generators find it more difficult to forecast and balance than conventional generation, which is likely to increase balancing costs • One objective of the SCR is to increase efficiency of electricity balancing as a whole; this includes exploring options to reduce overall balancing cost of intermittent plant • It has been suggested that some form of aggregation of intermittent output could reduce overall imbalance costs • As part of EMR, DECC is currently looking into the PPA market and how it may be affected by the move from RO to CfDs 3
Current arrangements • Generators are responsible for managing their own imbalances • Smaller generators often sell their power through Power Purchase Agreements (PPAs), passing on the imbalance risk to the PPA provider such as one of the Big 6 or an independent commercial aggregator. • Independent aggregators operate in the market; with relatively low market share today (but growing) • Independent developers own and operate around 45% of existing onshore wind capacity. 4
Interaction with European legislation Draft Balancing Framework Guidelines The Network Code on Electricity Balancing shall “impose that generation units from intermittent renewable energy sources do not receive special treatment for imbalances.” Renewables Directive “...when dispatching electricity generating installations, transmission system operators shall give priority to generating installations using renewable energy sources in so far as the secure operation of the national electricity system permits and based on transparent and non- discriminatory criteria.” 5
Potential options for reform Option 1: Monitor development of independent aggregation Option 2: Some form of central aggregation Option 3: SO taking responsibility for imbalances after gate closure 6
Option 1 Option 1: Monitor independent aggregation • Aggregators are able to benefit from pooling fluctuations from a geographically-diverse portfolio • Allow for the market to absorb the current changes, particularly EMR, and to deliver more competition in the aggregation sector • Existing commercial aggregators have suggested that the introduction of CfDs is likely to remove the main barrier (price risk) in the current market for commercial aggregation services – Aggregators have indicated that by removing the price risk, the CfD would allow shorter-term contracts to be offered, covering only the imbalance risk and potentially offering better terms. • In other countries independent aggregators are successful (e.g. Spain, where aggregators operate about 60% of wind capacity) Can anything else be done to support development of this sector? Are there other barriers to entry for independent aggregators? 7
Option 1 Monitor independent aggregation: Pros & Cons Advantages: • Allow the current proposals, most notably CfDs, to be introduced before assessing the case for further intervention • Allow balancing reforms to take effect, potentially encouraging commercial aggregation, or change the way intermittents operate within the market (e.g. through a potential BEM) • No disruption of market arrangements Disadvantages: • Could take time for market to adjust to new arrangements 8
Option 2 Option 2: Central aggregator • Central aggregation could benefit from pooling fluctuations across a geographically-diverse portfolio • The potential role of an aggregator could be a combination of • Forecasting generators’ output • Trading the forecast output on behalf of generators • Submitting physical notifications on behalf of generators • Take responsibility for imbalance charges • Could be compulsory or voluntary on generators, although aggregation benefits will be larger over a wider portfolio of generation 9
Option 2 Central aggregator: Pros & cons Advantages: • Forecasting: efficiency gains through concentrating resources into a single model • Selling output: Could enable more intermittent output to be sold further ahead of real time, enabling the market to better absorb power from intermittent generation. • Balancing costs: pool fluctuations across a diverse portfolio, potentially reducing overall imbalance charges for renewables Disadvantages: • Potentially large intervention in current market arrangements, likely to crowd out independent commercial aggregators • Likely to reduce incentives for generators to invest in forecasting technologies • Cost of setting up the central aggregator, including development of central forecast model and trading capabilities • One could argue that if there are large benefits from aggregation the market for aggregation should develop and exploit these benefits without intervention • Benefits from pooling of fluctuations move from SO to central aggregator • Germany recently moved away from the TSO taking responsibility for selling wind generation due to criticism about incorrect incentives and socialised imbalance costs. 10
Option 3 Option 3: SO taking responsibility for fluctuations after gate closure • Under this option, the SO would provide forecasting services to generators and take on the risk of fluctuations to generation that deviate from these forecasts in the period between gate closure and real time • Generators would have to trade their power and would be responsible for deviation of their contracted position from the SO’s forecasts up to gate closure. 11
Option 3 SO managing fluctuations: Pros & Cons Advantages: • Reduced imbalance exposure for intermittent generators • Forecasting – efficiency gains through concentrating resources into a single model Disadvantages: • After gate closure it would be difficult to determine whether unexpected fluctuations in output are due forecasting errors (SO’s responsibility) or due to technical malfunctions (generator’s responsibility) • Would shift risk on to the SO after gate closure, who may not be best placed to manage it • Potentially discriminatory if only introduced for intermittent generation 12
Questions for stakeholder group • Is it likely that the market for independent aggregation grows following the EMR/CfD proposals? • Are there other barriers to independent aggregation? • Do the advantages of central aggregation outweigh the costs involved with this intervention? • Should the SO take over a more distinct role in dealing with intermittent output? • Is central or de-central forecasting more efficient/innovative over time? 13
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The Agency response and proposed Respondent’s comment changes in the FG, where relevant Many stakeholders supported the Framework Guidelines requirements that generation units from intermittent renewable energy sources do not receive any special treatment. It should be clearly mentioned that BRPs should be the solely Partly agree. The purpose of the responsible parties for their imbalances, bearing the Framework Guidelines is that financial risks of being imbalanced. One stakeholder intermittent renewable energy sources commented that such obligation on renewable are more responsive to the dynamics generators, if being experienced as retroactive, of the balancing market and should should provide for financial compensation. Two thus be financially responsible for their stakeholders feared that such obligations would push imbalances. This does not exclude smaller independent generators towards the larger other solutions to recover these costs utilities and decrease competition. In their opinion, it or support renewable energy sources. is more efficient that the net system variation due to load and RES uncertainty is managed by a single entity on an aggregate basis. They proposed that this should be a matter for each Member State to decide. 15
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