The term 'redispatching' in the European Union Internal Electricity Market means a measure activated by one or several system operators by altering the generation and/or load pattern in order to change physical flows in the transmission system and relieve a physical congestion (Article 2(26) of the Regulation on submission and publication of data in electricity markets).
Some Transmission System Operators (TSOs) supplement the above definition with additional elements.
According to the Core CCR TSOs’ proposal for the methodology for coordinated redispatching and countertrading in accordance with Article 35.1 of Commission Regulation (EU) 2015/1222 of 24 July 2015, “Core RD and CT Methodology” of 5 September 2018 redispatching means a measure performed by one or several TSOs by altering specific generation and/or load patterns in order to change physical flows in the transmission system and relieve physical congestions, while the location of the units considered for redispatching are known and the parameters of the resource are known.
Finally, Article 2(26) of Regulation (EU) 2019/943 of the European Parliament and of the Council of 5 June 2019 on the internal market for electricity (recast) understands redispatching as 'a measure, including curtailment, that is activated by one or more transmission system operators or distribution system operators by altering the generation, load pattern, or both, in order to change physical flows in the electricity system and relieve a physical congestion or otherwise ensure system security'.
The EU Network Code on System Operation (System Operation Guideline - SOGL) in Article 55(c) lists redispatching among services provided by third parties, through procurement when applicable, that each TSO uses for ensuring the operational security of its control area.
Redispatching in the European Union Internal Electricity Market is part of the broader scope of remedial actions (see Article 22(1)(e) of the SOGL).
Explanatory document of 5 September 2018 to the proposal for the coordinated redispatching and countertrading methodology for Capacity Calculation Region Core in accordance with Article 35 of the Commission Regulation (EU) 2015/1222 of 24 July 2015 establishing a Guideline on Capacity Allocation and Congestion Management accentuates that in case of congestion, redispatching includes the modification of particular generation and/or load patterns.
This, in more detail, means that one TSO or several TSOs request from specific generators (consumers) to start or increase the production (to decrease the load), while other specific generators (consumers) are requested to stop or reduce the production (to increase the load).
It is also useful to observe, redispatching can be prepared in different processes and in different timeframes, i.e. day-ahead, intraday and real-time.
The ACER’s REMIT Quarterly Q1/2021 provides a practical example of redispatching as below.
Constraints between the north and the south of bidding zone ‘A’ can accommodate for power flows of 1 000 MW.
The day-ahead market clears for a demand of 5 000 MWh at 50 EUR/ MWh.
The main demand centre is situated in the south, while the north is a production area.
The resulting internal bidding zone north-south trades would amount to an expected north-south physical power flow of 1 500 MW.
As a result, the system operator will have to take measures to reduce forecasted line loading by means of cost- or market-based redispatching of generation.
Line loading can be reduced by:
- having generation units in the merit order in the north redispatched down;
- concurrently, generation units outside the merit order in the south will be redispatched up to ensure the same level of generation.
Thus, the redispatching calls on power plants that are originally outside the merit order to increase production, and on cheaper power plants upstream of the congestion to reduce production, redispatching comes here at a cost.
This is the usual approach to redispatching, although more and more preventive curtailment contracts or temporary access limitations (downward redispatching) are applied, where generation units likely to cause congestion are compensated before the day ahead market.
Remuneration of activated redispatching
Remuneration of activated internal or cross-zonal redispatching differs among the EU Member States (ACER/CEER Annual Report on the Results of Monitoring the Internal Electricity Markets in 2015, September 2016, p. 27).
The most common method used is the pay-as-bid pricing followed by the regulated pricing based on either a market price (e.g. day-ahead price) or a cost-based pricing (e.g. remuneration for the cost of fuel and other costs related to the change in the operating schedule of the plant).
Also the aforementioned Core CCR TSOs’ proposal of 24 July 2015 categorises different pricing mechanisms for redispatching existing in different countries as:
- price-related, i.e. based on bids for upward regulation and downward regulation,
- cost-related, i.e. based on fuels, CO2, opportunity costs, starting costs, etc,
- cost-related plus, i.e. cost related complemented with an additional margin.
Core TSOs also mention that in a price-related mechanism the costs are known ex-ante, while in a cost-related mechanism the full costs are known only ex-post, but indicative prices are determinable.
Regulation establishing a Guideline on Capacity Allocation and Congestion Management (CACM - Regulation on market coupling)
TSOs should use a common set of remedial actions such as countertrading or redispatching to deal with both internal and cross-zonal congestion. In order to facilitate more efficient capacity allocation and to avoid unnecessary curtailments of cross-border capacities, TSOs should coordinate the use of remedial actions in capacity calculation.
TSOs should implement coordinated redispatching of cross-border relevance or countertrading at regional level or above regional level. Redispatching of cross-border relevance or countertrading should be coordinated with redispatching or countertrading internal to the control area.
Coordinated redispatching and countertrading
1. Within 16 months after the regulatory approval on capacity calculation regions referred to in Article 15, all the TSOs in each capacity calculation region shall develop a proposal for a common methodology for coordinated redispatching and countertrading. The proposal shall be subject to consultation in accordance with Article 12.
2. The methodology for coordinated redispatching and countertrading shall include actions of cross-border relevance and shall enable all TSOs in each capacity calculation region to effectively relieve physical congestion irrespective of whether the reasons for the physical congestion fall mainly outside their control area or not. The methodology for coordinated redispatching and countertrading shall address the fact that its application may significantly influence flows outside the TSO's control area.
3. Each TSO may redispatch all available generation units and loads in accordance with the appropriate mechanisms and agreements applicable to its control area, including interconnectors. By 26 months after the regulatory approval of capacity calculation regions, all TSOs in each capacity calculation region shall develop a report, subject to consultation in accordance with Article 12, assessing the progressive coordination and harmonisation of those mechanisms and agreements and including proposals. The report shall be submitted to their respective regulatory authorities for their assessment. The proposals in the report shall prevent these mechanisms and agreements from distorting the market.
4. Each TSO shall abstain from unilateral or uncoordinated redispatching and countertrading measures of cross-border relevance. Each TSO shall coordinate the use of redispatching and countertrading resources taking into account their impact on operational security and economic efficiency.
5. The relevant generation units and loads shall give TSOs the prices of redispatching and countertrading before redispatching and countertrading resources are committed.
Pricing of redispatching and countertrading shall be based on:
(a) prices in the relevant electricity markets for the relevant time-frame; or
(b) the cost of redispatching and countertrading resources calculated transparently on the basis of incurred costs.
6. Generation units and loads shall ex-ante provide all information necessary for calculating the redispatching and countertrading cost to the relevant TSOs. This information shall be shared between the relevant TSOs for redispatching and countertrading purposes only.
Redispatching mechanisms are, moreover, considered by regulators in the context of competition rules, in particular as a function of the bidding zone's size.
As the ACER's document of 31 July 2013 (The influence of existing bidding zones on electricity markets, PC_2013_E_04, p. 8) observes, redispatching is very often organised in a non-market based way and this induces further costs (i.e. loss of social welfare), which are not visible within the day-ahead market coupling.
Competition in redispatching is weaker than competition in the day-ahead market coupling.
Redispatching is often used to solve congestion in larger bidding zones.
Therefore, with an increase of redispatching linked to bidding zone size, it may be argued that the decrease of general market power in larger zones may be counterbalanced by the increase of (locational) market power of some market players in the redispatching market.
However, the magnitude of market power effects (i.e. price increase and volume of energy affected) can be quite different in both markets (i.e. day-ahead and redispatching).
As follows from the said ACER/CEER Annual Report of September 2016 (p. 27), the volumes (in GWh) for the internal redispatching for 2015 were the biggest in such EU Member States as:
- Germany - 11,127,
- Spain - 6,461,
- United Kingdom - 6,195,
- Poland - 6,065.
When it comes to the volumes for the cross-border redispatching for 2015 the most prominent EU countries were Germany (volume in GWh 1,601) and Poland (volume in GWh 1,551).
The above stake is analogous with respect to overall cost for 2015 for internal and cross-border redispatching actions (thousand euros):
- Germany - 880,500,
- Spain - 690,878,
- United Kingdom - 465,503,
- Poland - 106,400.
According to the Report of the Core TSOs of 13 December 2018 assessing the progressive coordination and harmonisation of mechanisms and agreements for redispatching and countertrading (in accordance with EU Regulation 1222/2015 article 35(3), Version for Public Consultation, p. 3) in the Core region, the impact of redispatching is not the same everywhere.
Some TSOs apply redispatching already for a long-time, whilst others only apply it occasionally or have developed non-costly remedial actions to solve their congestions.
Generally, the agreements and mechanisms used for redispatching are national, and they are often quite different due to historical reasons.
The Core TSOs consider the implementation of the requirements set out in the CACM Regulation (Regulation establishing a Guideline on Capacity Allocation and Congestion Management) as the next step.
Article 35 of the said CACM Regulation provides for some coordinated measures on redispatching.
According to the said provisions, within 16 months after the regulatory approval on Capacity Calculation Regions (CCRs), all TSOs in each CCR are required to develop a proposal for a common methodology for coordinated redispatching.
As the provisions stipulate, the said methodology "shall include actions of cross-border relevance and shall enable all TSOs in each capacity calculation region to effectively relieve physical congestion irrespective of whether the reasons for the physical congestion fall mainly outside their control area or not".
Each TSO must, moreover, abstain from unilateral or uncoordinated redispatching measures of cross-border relevance.
In accordance with Article 21(1)(b)(ii) of the CACM, the proposal for the common capacity calculation methodologies should include rules for avoiding undue discrimination between internal and cross-zonal exchanges to ensure compliance with point 1.7 of Annex I to Regulation (EC) No 714/2009.
According to Article 74(6) of the CACM, the common methodologies for the sharing of redispatching costs between TSOs must:
- ensure a fair distribution of costs and benefits between the TSOs involved,
- facilitate adherence to the general principles of congestion management under Article 16 of Regulation (EC) No 714/2009, and
- comply with the principles of transparency and non-discrimination.
The said issues were the subject of the ACER Recommendation No 2/2016 of 11 November 2016 on the common capacity calculation and redispatching and countertrading cost sharing methodologies.
When it comes to the Core CCR the TSOs submitted the above proposal on 5 September 2018 (Core CCR TSOs’ proposal for the methodology for coordinated redispatching and countertrading in accordance with Article 35.1 of Commission Regulation (EU) 2015/1222 of 24 July 2015, “Core RD and CT Methodology” - see link in the documentation section).
The methodologies at issue must be seen in the context of a minimum binding level of capacity for cross-zonal trade at the level of 70% (as from 1 January 2020) stipulated in Article 16(8) of the Regulation (EU) 2019/943 on the internal market for electricity (Recast Electricity Market Regulation).
ACER’s recommends to “[u]rgently adopt and implement regional methodologies for coordination of redispatching and countertrading (and related cost-sharing) as an absolute prerequisite to meet the 70% minimum target” (ACER Market Monitoring Report 2019 – Electricity Wholesale Markets Volume, 21.10.2020, p. 14).
It is noteworthy, the Winter Energy Package (Annex to the Proposal for a Regulation of the European Parliament and of the Council on the internal market for electricity (recast), 30.11.2016, COM(2016) 861 final 2016/0379 (COD)) entrusts Regional Operational Centres (ROCs) with the task of supporting the transmission system operators of the system operation region in administering the financial flows related to inter-transmission system operators settlements involving more than two transmission system operators, such as redispatching costs, congestion income, unintentional deviations or reserve procurement costs.
According to Article 21(1)(d) of the Regulation of the European Parliament and of the Council on the Governance of the Energy Union national objectives as regards redispatching should be included in integrated reporting the EU Member States carry out as regards the mechanisms of the internal energy market.
The role of redispatching in the European electricity system will remain significant as "the amount of congestion in European grids is expected to grow even further over the coming years, in a large part due to the vast increase of renewable energy sources and the ‘70% rule’ on margin available for cross zonal trade, originating from the Clean Energy Package" (ACER REMIT Quarterly Q1/2021, p. 6).
Possibilities for market abuse with the use of redispatching - Inc-Dec gaming
The ACER’s REMIT Quarterly Q1/2021 describes Inc-Dec gaming, referring to Increase-Decrease or alternatively to Incremental-Decremental, as a trading strategy that represents typical behaviour in anticipation to redispatching, however, with a window for market participants to modify their positions in anticipation of such remedial actions, so is there a window for arbitrage and potential abuse to take place.
Market participants applying this strategy take advantage of zones where physical congestion can be expected with high certainty, but can also exacerbate the physical congestion.
ACER refers to the example described above, where, to cover the demand, all generation capacity within the merit order is cleared or sold during day ahead or intraday.
Sell orders typically reflect variable costs, with varying levels depending on the fuel type: wind, coal, gas and diesel peak load plants, to name a few.
However, the incentive for Inc-Dec gaming is in the anticipation of congestion and subsequent redispatching, which may result in windfall profits for downward redispatched units, and a compensation for upward redispatched units.
According to the ACER, in Inc-Dec gaming, the benefitting actor upstream of the congestion, will offer a lower price than its true variable costs, for example in the day-ahead market.
The actor does this in order to increase (Inc) its output, if it expects to be redispatched down (Dec) afterwards.
By doing so, it will be able to realise the profits of its positioning during redispatch- ing through carrying out arbitrage between the day ahead market and redispatching.
In the example above, downwards redispatching is performed on 500 MW of relatively cheap power plants in the north.
By contrast, upwards redispatching involves a different principle. In order for generation capacity not to clear for the respective system demand in a spot market, its offering prices must be out of the merit order, thereby following a ‘Dec-Inc’ gaming principle, by decreasing output in the spot market in order to offer more during redispatching.
This is achievable through economic withholding by means of higher-than-actual sell orders.
Alternatively, physical withholding entails alternating actions to reduce or impede generation capacity altogether.
Next, the originally withheld volume can be activated by the TSO in upward redispatching, typically at prices paid above the cleared price in the spot market and above the generators’ marginal costs.
In the example above, upwards redispatching is performed on 500 MW of relatively expensive power plants in the south, downstream of the congestion.
ACER concludes that the REMIT is relevant to Inc-Dec gaming due to:
- the detrimental effect such a strategy could have on the final customers;
- it incentivises individual parties to anticipate congestion, thereby even risking increasing the size of congestion and negatively affecting overall welfare;
- Inc-Dec gaming involves actions on several markets that can imply behaviours that could potentially lead to market abuse.