Integration of European Electricity Balancing Markets
Abstract
:1. Introduction
2. European Commission Regulations on the Electricity Market Integration
- Regulation 1222/2015/EC of 24 July 2015 establishing a guideline on capacity allocation and congestion management [13]: This regulation includes detailed provisions on cross-zonal capacity (CZC) allocation and congestion management. The most remarkable provisions are the following:
- (a)
- The introduction of the flow-based transmission capacity calculation methodology. It is noted that in specific cases, if required, the net transmission capacity-based methodology can apply. The core advantage of the former is that it takes into account the physical flows on the interconnections, which are being calculated in accordance with the physical laws (Kirchhoff’s Laws) [14]. In other words, physical flows on interconnectors are different from the respective scheduled commercial power exchanges in the sense that, in reality, electricity flows from an exporting market area to an importing one through different paths (interconnectors) and not directly through the interconnector connecting such market areas (there is a distinction between the physical and economic perspectives). For example, in a highly meshed network as is the European one, a scheduled commercial exchange between Germany and France will partially flow directly between the two countries since the other portion will go through the routes Netherlands-Belgium-France, Switzerland-France and Switzerland-Italy-France. Hence, it becomes apparent that the latter methodology (net transmission capacity-based) fails in meshed electricity networks since it ignores the physical perspective;
- (b)
- The adoption of the implicit capacity allocation approach. In accordance with this allocation approach, the capacity between two market areas is allocated based on the market price difference between such market areas, and a netting of the flows in opposite directions may be achieved;
- (c)
- The definition of capacity calculation regions (CCRs) is geographic areas in which a coordinated capacity calculation is applied. According to [15], eight CCRs have been defined: Baltic (Poland, Lithuania, Estonia, and Latvia), Core (France, Belgium, The Netherlands, Germany, Austria, Czech Republic, Slovakia, Poland, Croatia, Hungary, and Romania), Greece-Italy, Hansa (The Netherlands, Germany, Poland, and Denmark), Italy North (Italy North, France, and Austria), Nordic (Sweden, Finland, and Denmark), South East Europe (Romania, Bulgaria, and Greece), and South West Europe (France, Spain, and Portugal).
- Regulation 2017/2195/EC of 23 November 2017 establishing a guideline on electricity balancing [16]: This regulation refers to the balancing markets and outlines the requirements that shall be met towards the integration of this market segment, namely: (a) the definition of common rules for the procurement and the settlement of balancing reserves (frequency containment reserves (FCR), automatic frequency restoration reserves (aFRR), manual frequency restoration reserves (mFRR), and replacement reserves (RR)); (b) the definition of standard balancing products to be exchanged between European market areas; (c) the establishment of common clearing platforms for the activation of balancing energy from aFRR, mFRR, and RR.
- Regulation 2017/1485/EC of 2 August 2017 establishing a guideline on electricity transmission system operation [17]: This regulation includes all the technical and operational guidelines that the European TSOs shall meet in order to ensure the normal functioning of their system networks and, consequently, the continuous supply of electricity.
3. Electricity Balancing Market Integration
3.1. High-Level Architecture of the Balancing Market
- (a)
- The balancing capacity market, which includes all the required actions taken proactively by a TSO in order to reserve well in advance enough balancing capacity from the balance service providers (BSPs) so as to be able to cover, in real-time, its imbalance needs by activating such reserves. In other words, the TSO secures the availability of BSPs that may be requested in real-time, if needed, to provide balancing energy. According to Regulation 2017/1485/EC [17], there are the following four types of balancing capacity:
- FCR, also called a primary control reserve;
- aFRR, also called a secondary control reserve;
- mFRR, also called a fast tertiary control reserve or load-following reserve in the U.S.;
- RR, also called slow tertiary control reserve.
- (b)
- The balancing energy market, which includes all the required actions taken by a TSO in order to activate the capacity reserved in the balancing capacity market. Depending on the magnitude and direction (short or long) of the system imbalance (being the difference between demand and supply at each dispatch period), the TSO activates the appropriate volume of balancing energy. In general, in the case of a system shortage, upward balancing energy orders (BEOs) are activated, whereas in the case of a system surplus, downward BEOs are accepted for activation. The acceptance of the BEOs is based on their respective offer prices, and the general rule is that the upward orders with the lowest price and the downward orders with the highest price are accepted first to cover the system imbalance needs. Notably, the TSO compensates the BSPs for the provision of upward balancing energy while, on the other hand, BSPs pay back the TSO for the provision of downward balancing energy. Regarding the activation sequence of the reserves (Figure 2), the following is valid:
- FCR constitutes the fastest balancing service to face a disturbance between supply and demand. It is activated within seconds (up to 30 s) after the appearance of the disturbance, and it is automatically provided through the kinetic energy of the connected generators. Its core objective is to stabilize the grid frequency to a new acceptable level close to the respective nominal frequency (50 Hz). It is noted that in the case of interconnected power systems, all systems jointly contribute to the provision of such a service. FCR is also called “primary reserve” in other ancillary services markets;
- aFRR is utilized for the full restoration of the nominal grid frequency, and it is activated for up to 5–7.5 min after a disturbance. Unlike FCR, in the case of interconnected power systems, aFRR is activated only in the power system where the imbalance is experienced. aFRR is also called “secondary reserve” in other markets and “regulation” in the U.S. RTOs;
- mFRR is utilized to release aFRR and it is activated for up to 12.5–15 min after a disturbance; mFRR can be included in the broader scope of tertiary control and can also be named “fast tertiary reserve” or “load-following reserve” [20]. mFRR is used for “load following” purposes, i.e., it helps to manage the system load and RES injection variability and uncertainty for timeframes that exceed 10 min [21];
- RR is utilized to release or support the required level of FRR potential, so that the latter is available for future imbalances, and it is activated from 30 min to 60 min after a disturbance. RR is also included in the broader scope of tertiary control and can be named “slow tertiary reserve” or “contingency reserve”.
- (c)
- The imbalance settlement is an ex-post process that allocates the costs derived from the operation of the balancing capacity and balancing energy markets to the balance responsible parties (BRPs), for example, to retailers with non-dispatchable load portfolios or to RES aggregators with non-dispatchable RES portfolios, based on the concept of balance responsibility. BRPs are entities that undertake the responsibility for settling the imbalances between their market schedules, as obtained from the clearing of the respective spot markets (day-ahead and intra-day) and the metered/allocated production (for RES aggregators) or consumption (for retailers). Such imbalances are penalized, and they are settled at the imbalance price. In general, BRPs with a short position pay to the TSO the respective amounts, while BRPs with a long position get paid by the TSO. There are several imbalance settlement schemes, such as single pricing (which is the preferred scheme for the European Commission [16]), dual pricing, as well as variations of these with additive cost components. A detailed analysis follows in Section 3.2.
3.2. Design Variables for Balancing Market Harmonization and Integration
- Dispatch period: the time-interval (usually quarter-hourly) over which the BEOs are activated [26];
- Imbalance settlement period: the time-interval (hourly, half-hourly, or quarter-hourly) over which the BRP imbalances are calculated and settled [26]. For example, Greece, Germany, Belgium, The Netherlands, Austria, Slovakia, Hungary, and Romania apply a quarter-hourly imbalance settlement period [28]. While France and Ireland are the only control areas to apply a half-hourly settlement period, while the Nordic countries and Spain apply an hourly settlement period [28]. It is noted that the shorter the imbalance settlement period, the more challenging it is for BRPs to be balanced, and hence accurate forecasting processes shall be developed;
- Balancing products: there are three types of balancing products, namely, FCR, FRR (with manual and automatic activation), and RR, for which different procurement processes and system/zonal requirements may be defined;
- Timings of the balancing market: the timings include the gate opening and closure times for the submission of BEOs by BSPs and imbalance needs by TSOs as well as the appropriate coordination with the clearing timings of the spot markets (day-ahead and intra-day markets);
- Procurement mechanism: BSPs provide balancing services to the TSO through bidding in the balancing market using specific types of balancing products. Another way for procuring balancing services is the bilateral contracting between the TSOs and the BSPs;
- Reserve requirements: they constitute the required amount of power capacity that must be reserved in advance in order for a TSO to safeguard the generation/demand balance and the normal operation of the power system in real-time. For each of the above-defined balancing products, a different quantification method applies [29]. However, the exact quantification method per reserve type has been homogenized by ENTSO-E in the Regulation 2017/1485/EC (Article 153 for FCR, Article 157 for FRR and Article 160 for RR) [17];
- Order specifications: the BSPs shall submit BEOs respecting the order submission rules, such as the maximum and minimum order price limits, volume, location, activation time, activation duration and activation method. Obviously, in a coupled balancing market such requirements must be aligned between the involved TSOs (control areas), otherwise no coupling can be performed;
- Activation mechanism: it constitutes the process followed by a TSO for the activation of BEOs. There exist the following two main mechanisms: (a) pro-rata activation, where a TSO activates reserves to cover an imbalance in proportion to the size of the contracted reserves of each BSP; (b) merit-order activation, where a TSO covers its imbalance needs with the cheapest BEOs submitted by the BSPs. The former mechanism does not provide a signal of balancing prices, while the latter requires the existence of standard products [30,31]. The Regulation 2017/2195/EC [16] follows the second market-based approach. An additional factor for this variable is the time of activation. Notably, it is useful to distinguish between reactive and proactive activation. On one hand, reactive activation pursues curative objectives such as containing frequency deviation or restoring the frequency (FCR and FRR are principally deemed reactive processes since they observe the imbalance status and employ reserves to contain and restore the frequency) [32,33]. On the other hand, proactive activation follows preventive objectives such as reducing the future imbalance, creating reserve margins, or relieving congestion (RR can be classified as a proactive process);
- Balancing energy pricing mechanism: it constitutes the method used by a TSO for settling the activated BEOs. There are the following two pricing mechanisms, namely: (a) pay-as-bid pricing and (b) marginal pricing. With marginal pricing, all accepted BEOs are remunerated with the order price of the last (marginal) BEO activated from a merit order list. The main advantage of the pay-as-bid mechanism is the fact that the BSPs receive the price they bid, while the disadvantageous point is the lack of a clear market reference price. On the other hand, the marginal mechanism provides a transparent price derivation and imbalance price calculation, but it may lead to higher procurement costs and imbalance settlement prices [34]. In the marginal pricing scheme, the balancing energy prices can be regarded as an index of the very short-term marginal cost of increasing/decreasing production to achieve system balancing, thus it can provide the economic signals to potential investors of flexible resources for the expected revenues from providing frequency-response and flexibility services to the TSO. All European TSOs follow the marginal pricing scheme based on the provisions of Article 30 of Regulation 2017/2195/EC [16];
- Imbalance volume calculation methodology: the methodology through which imbalance volumes of BRPs are quantified varies across European TSOs. According to [35,36], there are the following three methodologies for the calculation of the imbalance volumes: (a) the first one considers that all generation and consumption resources are included in the same balance perimeter, thus they are part of the same BRP. Meaning that this BRP is responsible over the whole portfolio (both energy production and consumption), and that consumption imbalances could be offset by production imbalances (indicatively, this scheme is followed in France, Germany, Belgium, the Netherlands, and Poland [28]); (b) The second one under which all generation resources constitute one balance perimeter and all consumption resources constitute another balance perimeter, without having the possibility to net the imbalances among each other (indicatively, this scheme is followed in Spain, Norway, Finland, Sweden, and Denmark [28]). (c) each generating unit constitutes a separate balance perimeter of the BRP and all consumption resources constitute a distinct balance perimeter of the BRP (indicatively, this scheme is followed in Italy and Greece [28]);
- Imbalance pricing mechanism: the method used by a TSO to calculate the imbalance settlement price for a given imbalance settlement period, at which all debits/credits between BRPs and the TSO will be settled. This calculation is based on the prices of the upward and downward BEOs activated to cover the imbalance for the concerned imbalance settlement period. The controversial point in this variable is whether the imbalance settlement prices for a given position in the system (either short or long) shall be identical (single imbalance pricing) or not (dual imbalance pricing) [37,38]. In the former mechanism, as shown in Table 1, only one imbalance settlement price is derived, which applies to all BRPs, independently of their respective individual positions, and it is equal to the price that occurred for the dominant direction of the system imbalance. To be more precise, if the system is short, then the imbalance settlement price is equal to the price of the marginally accepted upward BEO for markets with marginal pricing or the average price of all accepted upward BEOs for markets with pay-as-bid pricing (Pup in Table 1). In the same vein, if the system is long, then the imbalance settlement price is equal to the price of the marginally accepted downward BEO for markets with marginal pricing or the average price of all accepted downward BEOs for markets with pay-as-bid pricing (Pdn in Table 1).
- (a)
- BRPs with the short position pay the price of the marginally accepted upward BEO or the average price of all accepted upward BEOs (Pup in Table 2) and BRPs with long position get paid at the price of the marginally accepted downward BEO or at the average price of all accepted downward BEOs (Pdn in Table 2);
- (b)
- BRPs with the opposite position against the system position pay or get paid at the price of the day-ahead market [39] (PDAM in Table 3), while BRPs with the same position against the system position pay or get paid at the price of the marginally accepted upward or downward BEO or at the average price of all accepted upward or downward BEOs (Pup and Pdn in Table 3).
- Timing of settlement: the frequency (weekly or monthly) and time of financial settlement between the TSOs and BSPs for the provided balancing services and between the TSOs and BRPs for the imbalances of the latter;
- Integration model: There are the following three integration models for the balancing markets: (a) the BSP-TSO model; (b) the TSO-TSO with a common merit order list; (c) the TSO-TSO without a common merit order list. The preferable integration model in the Regulation 2017/2195/EC is the TSO-TSO with common merit order list. Detailed provisions on each of the above integration models are provided in Section 3.3.2, Section 3.3.3 and Section 3.3.4 below.
3.3. Main Balancing Market Integration Models
3.3.1. Imbalance Netting
- The TSO A pays to the TSO B the amount 30 × EUR 25 = EUR +750;
- The financial benefits for TSO A amount to EUR 2700−EUR 750 = EUR 1950;
- The financial losses for TSO B amount to EUR 750−EUR 1200 = EUR −450;
- The increase in the overall welfare amounts to EUR 1950−EUR 450 = EUR 1500.
3.3.2. BSP-TSO Model
- (a)
- BSPs are permitted to participate only in one balancing market by explicitly declaring their preference. In principle, BSPs tend to participate in balancing markets with high balancing energy prices for profit maximization purposes. Of course, this strategy results in higher balancing energy prices in the control areas with low balancing energy prices;
- (b)
- BSPs are permitted to participate in more than one balancing market. This case poses challenging tasks to the respective TSOs since they have to deal with high uncertainties regarding the availability and activation of BEOs so as to cover their imbalance needs. Consequently, strict and concrete allocation processes must be defined.
3.3.3. TSO-TSO with Common Merit Order List
3.3.4. TSO-TSO without Common Merit Order List
4. Example of Three Integrated Balancing Markets with Common Merit Order List
5. European Balancing Market Integration Projects
5.1. Introduction
- FCR cooperation;
- International Grid Control Cooperation (IGCC);
- Platform for the International Coordination of Automated Frequency Restoration and Stable System Operation (PICASSO);
- Manually Activated Reserves Initiative (MARI);
- Trans European Replacement Reserves Exchange (TERRE);
5.2. Balancing Market Initiatives
5.2.1. FCR Cooperation
5.2.2. International Grid Control Cooperation (IGCC)
5.2.3. Platform for the International Coordination of Automated Frequency Restoration and Stable System Operation (PICASSO)
5.2.4. Manually Activated Reserves Initiative (MARI)
5.2.5. Trans European Replacement Reserves Exchange (TERRE)
5.2.6. Exchange and Sharing of Reserves
6. Existing Literature in Balancing Market Integration
7. Conclusions
Author Contributions
Funding
Conflicts of Interest
Abbreviations
ACER | Agency for the Coopeartion of Energy Regulators |
aFRR | Automatic frequency restoration reserve |
AGC | Automatic generation control |
BEO | Balancing energy order |
BESS | Battery energy storage system |
BM | Balancing market |
BRP | Balance responsible party |
BSP | Balance service provider |
CA | Control area |
CCR | Capacity calculation region |
CMOL | Common merit order list |
CZC | Cross-zonal capacity |
DAM | Day-ahead market |
DC | Direct current |
EC | European Commission |
ENTSO-E | European Network of Transmission System Operators for Electricity |
EUPHEMIA | European Hybrid Electricity Market Integration Algorithm |
FCR | Frequency containment reserve |
IEM | Internal Energy Market |
IGCC | International Grid Control Cooperation |
IDM | Intra-day market |
JAO | Joint allocation office |
LP | Linear programming |
mFRR | Manual frequency restoration reserve |
MARI | Manually Activated Reserves Initiative |
MILP | Mixed integer linear programming |
MRC | Multi regional coupling |
NEMOs | Nominated electricity market operators |
NLP | Non-linear programming |
NRA | National regulatory authorities |
OCGT | Open cycle gas turbine |
PICASSO | Platform for the International Coordination of Automated Frequency Restoration and Stable System Operation |
RES | Renewable energy sources |
RR | Replacement reserve |
RTO | Regional transmission operator |
SDAC | Single day-ahead coupling |
SIDC | Single intra-day coupling |
TERRE | Trans European Replacement Reserves Exchange |
TSO | Transmission system operator |
XBID | Cross-border intra-day |
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Single Pricing Mechanism | System Short | System Long |
---|---|---|
BRP short | Pup | Pdn |
BRP long | Pup | Pdn |
Dual Pricing Mechanism | System Short | System Long |
---|---|---|
BRP short | Pup | Pup |
BRP long | Pdn | Pdn |
Dual Pricing Mechanism | System Short | System Long |
---|---|---|
BRP short | Pup | PDAM |
BRP long | PDAM | Pdn |
Control Area | CA1 | CA2 | CA3 |
---|---|---|---|
TSO Orders | |||
Price [EUR/MWh] | 70 | 80 | 85 |
Quantity [MWh] | 50 | 70 | 40 |
BSP BEOs | |||
Price [EUR/MWh] | 45 | 20 | 30 |
Quantity [MWh] | 80 | 100 | 100 |
Order ID | Control Area | Price [EUR/MWh] | Quantity [MWh] |
---|---|---|---|
1 | 2 | 20 | 100 |
2 | 3 | 30 | 100 |
3 | 1 | 45 | 80 |
Order ID | Control Area | Price [EUR/MWh] | Quantity [MWh] |
---|---|---|---|
1 | 3 | 85 | 40 |
2 | 2 | 80 | 70 |
3 | 1 | 70 | 50 |
Ref. | Markets | Methodology | Modeling | Network CONSTRAINTS | Products Exchanged and Related Platforms | Imbalance Netting? | Integration Model | Case Study/Analysis Period | Balancing Cost Reduction [mEUR & %] |
---|---|---|---|---|---|---|---|---|---|
[71] | BM | Simulation | LP | Flow-based | Balancing energy from secondary and tertiary reserves (PICASSO and MARI) | Yes | TSO-TSO with CMOL | Italy, Austria, and Slovenia (one year) | 82.8 mEUR 60% |
[72] | BM | Data analysis | - | - | RR (TERRE) | No | TSO-TSO with CMOL | Portugal, Spain, France (three years) | 13.4 mEUR 30% |
[73] | BM | Simulation | MILP | NTC-based | Balancing energy | Yes | BSP-TSO | Nordic, Germany, The Netherlands (one year) | 26.1 mEUR 75% |
[74] | DAM, BM | Simulation | MILP | NTC-based | Balancing capacity and energy | Yes | TSO-TSO with CMOL | Nordic, Germany, The Netherlands (one year) | 204 mEUR 75% |
[75] | BM | Simulation | - | NTC-based | Balancing capacity and energy | Yes | TSO-TSO with CMOL | Nordic, Germany, The Netherlands (one year) | 80 mEUR 44.5% |
[76] | BM | Simulation | - | - | Balancing energy from secondary reserves (PICASSO) | No | BSP-TSO | Norway, The Netherlands | - |
[78] | DAM, IDM, BM | Simulation | MILP | Flow-based | Balancing capacity and energy | - | - | All EU Member States (one year) | 5800 mEUR 76% |
[79] | DAM, BM | Simulation | - | NTC-based | aFRR (PICASSO) | - | - | Norway, Germany (three years) | - |
[80] | BM | Simulation | NLP | NTC-based | Balancing energy from tertiary reserves (MARI and TERRE) | No | - | Great Britain, France (one year) | - |
BM | Simulation | NLP | NTC-based | Balancing energy from tertiary reserves (MARI and TERRE) | Yes | - | Nordic (one year) | - | |
[81] | DAM, IDM, BM | Data analysis | - | - | Balancing energy | - | - | Selected interconnectors (one year) | 1300 mEUR 41% |
[83] | BM | Simulation | MILP | NTC-based | RR (TERRE) | Yes | TSO-TSO with CMOL | All countries participating in TERRE project | - |
[84] | BM | Simulation | MILP | NTC-based | mFRR (MARI) | Yes | TSO-TSO with CMOL | All countries participating in MARI project | - |
[85] | BM | Simulation | - | NTC-based | Balancing energy | Yes | TSO-TSO with CMOL | Belgium, France (one day) | 0.05 mEUR 6% |
[86] | BM | Simulation | LP | NTC-based | mFRR (MARI) | No | - | Italy | - |
[87] | BM | Simulation | MILP | NTC-based | RR (TERRE) | No | - | Greece | - |
[88] | BM | Simulation | - | - | Primary reserves | - | - | United Kingdom, Continental Europe | - |
[89] | BM | Simulation | MILP | Flow-based | aFRR and mFRR (PICASSO and MARI) | No | TSO-TSO with CMOL | Austria, Belgium, Germany, The Netherlands (one year) | - |
[90] | DAM, BM | Simulation | MILP | NTC-based | aFRR and mFRR (PICASSO and MARI) | Yes | TSO-TSO with CMOL | Austria, Germany, Switzerland (one year) | - |
[91] | BM | Simulation | - | - | aFRR (PICASSO) | - | - | Belgium, France, Germany, The Netherlands, Portugal, Spain (one year) | - |
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Roumkos, C.; Biskas, P.N.; Marneris, I.G. Integration of European Electricity Balancing Markets. Energies 2022, 15, 2240. https://doi.org/10.3390/en15062240
Roumkos C, Biskas PN, Marneris IG. Integration of European Electricity Balancing Markets. Energies. 2022; 15(6):2240. https://doi.org/10.3390/en15062240
Chicago/Turabian StyleRoumkos, Christos, Pandelis N. Biskas, and Ilias G. Marneris. 2022. "Integration of European Electricity Balancing Markets" Energies 15, no. 6: 2240. https://doi.org/10.3390/en15062240