Demand Side Services (DSR)
European Union Electricity Market Glossary

 


 

 

 

The so-called 'Winter Energy Package' defines a 'demand response' as the change of electricity load by final customers from their normal or current consumption patterns in response to market signals, including time-variable electricity prices or incentive payments, or in response to acceptance of the final customer's bid, alone or through aggregation, to sell demand reduction or increase at a price in organised markets as defined in Commission Implementing Regulation (EU) No 1348/2014 (Article 2(16) of the Proposal for a Directive of the European Parliament and of the Council on the internal market for electricity (recast) on common rules for the internal market in electricity (recast), 30.11.2016, COM(2016) 864 final 2016/0380 (COD)).

 

Pursuant to Article 2(29) of the Directive 2009/72/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in electricity and repealing Directive 2003/54/E 'energy efficiency/demand-side management' means a global or integrated approach aimed at influencing the amount and timing of electricity consumption in order to reduce primary energy consumption and peak loads by giving precedence to investments in energy efficiency measures, or other measures, such as interruptible supply contracts, over investments to increase generation capacity, if the former are the most effective and economical option, taking into account the positive environmental impact of reduced energy consumption and the security of supply and distribution cost aspects related to it.

 

In general, demand participation in electricity markets requires that consumers have:

- the equipment (e.g. smart meters),

- the real-time information, and

- the contracts that allow them to react to price increases and to adapt their electricity consumption accordingly.

 

In general, the connection point of the demand unit providing DSR services for transmission purposes is not explicitly restricted to transmission connected parties. However, for practical reasons (metering, number of parties used to achieve given response, administration etc.), it has been more common up to now for transmission connected entities or large distribution-connected customers, to offer such services.


It is the wide industry's expectation and a vision driven by policy makers that DSR services will expand to more (if not all) users. In this sense, the requirements of the network code aim to provide a sound technical basis in a timely manner for the expected evolution of such services, keeping in mind the proportionality of desired level of detail to be harmonized at a European level, and without imposing any restrictions on the financial and commercial aspects of providing and ordering such services.

 

Network Code on Demand Connection, Frequently Asked Questions, 21 December 2012, p. 23, 24

 

 

Network Code on Demand Connection (DCC) and Electricity Balancing Network Code (NC EB) provide a framework for demand side participation.

 

Pursuant to the NC EB:

 

- pricing methods for each standard product for balancing energy should strive for an economically efficient use of demand-side response and other balancing resources subject to operational security limits.

 

- the participation of demand side response including aggregation facilities and energy storage should be facilitated,

 

- terms and conditions for Balancing Service Providers must allow the aggregation of demand side response, the aggregation of generation units, or the aggregation of demand side response and generation units within a responsibility area or scheduling area when appropriate to offer balancing services.

 

However, ACER's Recommendation of 20 July 2015 (03/2015) on the Network Code on Electricity Balancing acknowledges that providers of the demand-side response my face important entry barriers into the balancing services market and difficulties to compete on a level playing field in particular with energy suppliers, hence, it proposes to introduce a new provision to the Electricity Balancing Network Code related to the independent Balancing Service Provider (for details see here).

 

 

Implicit and explicit demand response

 

 

 Demand response can be implemented with two divergent approaches, based on:

 

- direct consumer reaction to time-varying electricity supply prices that consumers are exposed to in the retail market - the implicit demand response, or

 

- individual or aggregated flexible demand which is sold in power markets - explicit demand response (see ACER/CEER Annual Report on the Results of Monitoring the Internal Electricity and Gas Markets in 2015, Retail Market, November 2016, p. 24, 25, Ensuring a level-playing field in the development of Demand Response, Reaction of EFET, EURELECTRIC and Europex to the Clean Energy Package, 16 May 2017, p. 1).

 

Implicit demand response

 

Implicit demand response is understood as voluntary changes by end-consumers in their usual electricity consumption patterns in response to short-term (day-ahead and intraday) market signals.

 

It is rightly observed by the said document Reaction of EFET, EURELECTRIC and Europex to the Clean Energy Package of 16 May 2017 that "implicit demand response is already a daily reality for many residential customers in Europe with a dual meter and a tariff for peak and off-peak hours, for instance" and that this form of demand response is likely to develop further with the roll-out of smart meters.

 

Explicit demand response

 

Explicit demand response means that consumers (on their own or through Demand Side Response Aggregators (DSR Aggregators)) are rewarded for their willingness to change their demand for electricity at a given point in time, usually in response to a specific system operators' request).

 

The explicit demand response can be performed by large consumers themselves or DSR Aggregators - being a generic name used with respect to retailers or independent aggregators which act on behalf of a pool of consumers.

 

Explicit demand response has already developed among larger industrial customers directly acting on the market.

 

Rules for the connection of demand units used by a demand facility or a closed distribution system to provide demand response services to system operators are specifically stipulated in Articles 27 - 33 DCC.

 

 

 

Article 17 of the Proposal for a Directive of the European Parliament and of the Council on the internal market for electricity (recast) on common rules for the internal market in electricity (recast), 30.11.2016, COM(2016) 864 final 2016/0380 (COD)

 

Demand response

 

1. Member States shall ensure that national regulatory authorities encourage final customers, including those offering demand response through aggregators, to participate alongside generators in a non-discriminatory manner in all organised markets.

 

2. Member States shall ensure that transmission system operators and distribution system operators when procuring ancillary services, treat demand response providers, including independent aggregators, in a non-discriminatory manner, on the basis of their technical capabilities.

 

3. Member States shall ensure that their regulatory framework encourages the participation of aggregators in the retail market and that it contains at least the following elements:

 

(a) the right for each aggregator to enter the market without consent from other market participants;

 

(b) transparent rules clearly assigning roles and responsibilities to all market participants;

 

(c) transparent rules and procedures for data exchange between market participants that ensure easy access to data on equal and non-discriminatory terms while fully protecting commercial data;

 

(d) aggregators shall not be required to pay compensation to suppliers or generators;

 

(e) a conflict resolution mechanism between market participants.

 

4. In order to ensure that balancing costs and benefits induced by aggregators are fairly assigned to market participants, Member States may exceptionally allow compensation payments between aggregators and balancing responsible parties. Such compensation payments must be limited to situations where one market participant induces imbalances to another market participant resulting in a financial cost.
Such exceptional compensation payments shall be subject to approval by the national regulatory authorities and monitored by the Agency.

 

5. Member States shall ensure access to and foster participation of demand response, including through independent aggregators in all organised markets. Member States shall ensure that national regulatory authorities or, where their national legal system so requires, transmission system operators and distribution system operators in close cooperation with demand service providers and final customers define technical modalities for participation of demand response in these markets on the basis of the technical requirements of these markets and the capabilities of demand response.
Such specifications shall include the participation of aggregators.

 

 

 

 

DCC Articles 27 - 33

 

TITLE III
CONNECTION OF DEMAND UNITS USED BY A DEMAND FACILITY OR A CLOSED DISTRIBUTION SYSTEM TO PROVIDE DEMAND RESPONSE SERVICES TO SYSTEM OPERATORS

 

CHAPTER 1
General requirements

 

Article 27

General provisions


1. Demand response services provided to system operators shall be distinguished based on the following categories:

(a) remotely controlled:
(i) demand response active power control;
(ii) demand response reactive power control;
(iii) demand response transmission constraint management.

(b) autonomously controlled:
(i) demand response system frequency control;
(ii) demand response very fast active power control.

2. Demand facilities and closed distribution systems may provide demand response services to relevant system operators and relevant TSOs. Demand response services can include, jointly or separately, upward or downward modification of demand.

3. The categories referred to in paragraph 1 are not exclusive and this Regulation does not prevent other categories from being developed. This Regulation does not apply to demand response services provided to other entities than relevant system operators or relevant TSOs.

 

Article 28

Specific provisions for demand units with demand response active power control, reactive power control and transmission constraint management

 

1. Demand facilities and closed distribution systems may offer demand response active power control, demand response reactive power control, or demand response transmission constraint management to relevant system operators and relevant TSOs.

 

2. Demand units with demand response active power control, demand response reactive power control, or demand response transmission constraint management shall comply with the following requirements, either individually or, where it is not part of a transmission-connected demand facility, collectively as part of demand aggregation through a third party:
(a) be capable of operating across the frequency ranges specified in Article 12(1) and the extended range specified in Article 12(2);
(b) be capable of operating across the voltage ranges specified in Article 13 if connected at a voltage level at or above 110 kV; 

(c) be capable of operating across the normal operational voltage range of the system at the connection point, specified by the relevant system operator, if connected at a voltage level below 110 kV. This range shall take into account existing standards and shall, prior to approval in accordance with Article 6, be subject to consultation with the relevant stakeholders in accordance with Article 9(1);
(d) be capable of controlling power consumption from the network in a range equal to the range contracted, directly or indirectly through a third party, by the relevant TSO;
(e) be equipped to receive instructions, directly or indirectly through a third party, from the relevant system operator or the relevant TSO to modify their demand and to transfer the necessary information. The relevant system operator shall make publicly available the technical specifications approved to enable this transfer of information. For demand units connected at a voltage level below 110 kV, these specifications shall, prior to approval in accordance with Article 6, be subject to consultation with the relevant stakeholders in accordance with Article 9(1);
(f) be capable of adjusting its power consumption within a time period specified by the relevant system operator or the relevant TSO. For demand units connected at a voltage level below 110 kV, these specifications shall, prior to approval in accordance with Article 6, be subject to consultation with the relevant stakeholders in accordance with Article 9(1);
(g) be capable of full execution of an instruction issued by the relevant system operator or the relevant TSO to modify its power consumption to the limits of the electrical protection safeguards, unless a contractually agreed method is in place with the relevant system operator or relevant TSO for the replacement of their contribution (including aggregated demand facilities' contribution through a third party);
(h) once a modification to power consumption has taken place and for the duration of the requested modification, only modify the demand used to provide the service if required by the relevant system operator or relevant TSO to the limits of the electrical protection safeguards, unless a contractually agreed method is in place with the relevant system operator or relevant TSO for the replacement of their contribution (including aggregated demand facilities' contribution through a third party). Instructions to modify power consumption may have immediate or delayed effects;
(i) notify the relevant system operator or relevant TSO of the modification of demand response capacity. The relevant system operator or relevant TSO shall specify the modalities of the notification;
(j) where the relevant system operator or the relevant TSO, directly or indirectly through a third party, command the modification of the power consumption, enable the modification of a part of its demand in response to an instruction by the relevant system operator or the relevant TSO, within the limits agreed with the demand facility owner or the CDSO and according to the demand unit settings;
(k) have the withstand capability to not disconnect from the system due to the rate-of-change-of-frequency up to a value specified by the relevant TSO. With regard to this withstand capability, the value of rate-of-change-of-frequency shall be calculated over a 500 ms time frame. For demand units connected at a voltage level below 110 kV, these specifications shall, prior to approval in accordance with Article 6, be subject to consultation with the relevant stakeholders in accordance with Article 9(1);
(l) where modification to the power consumption is specified via frequency or voltage control, or both, and via pre-alert signal sent by the relevant system operator or the relevant TSO, be equipped to receive, directly or indirectly through a third party, the instructions from the relevant system operator or the relevant TSO, to measure the frequency or voltage value, or both, to command the demand trip and to transfer the information. The relevant system operator shall specify and publish the technical specifications approved to enable this transfer of information. For demand units connected at a voltage level below 110 kV, these specifications shall, prior to approval in accordance with Article 6, be subject to consultation with the relevant stakeholders in accordance with Article 9(1).

 

3. For voltage control with disconnection or reconnection of static compensation facilities, each transmission-connected demand facility or transmission-connected closed distribution system shall be able to connect or disconnect its static compensation facilities, directly or indirectly, either individually or commonly as part of demand aggregation through a third party, in response to an instruction transmitted by the relevant TSO, or in the conditions set forth in the contract between the relevant TSO and the demand facility owner or the CDSO.

 

Article 29

Specific provisions for demand units with demand response system frequency control

 

1. Demand facilities and closed distribution systems may offer demand response system frequency control to relevant system operators and relevant TSOs.

 

2. Demand units with demand response system frequency control shall comply with the following requirements, either individually or, where it is not part of a transmission-connected demand facility, collectively as part of demand aggregation through a third party:
(a) be capable of operating across the frequency ranges specified in Article 12(1) and the extended range specified in Article 12(2);
(b) be capable of operating across the voltage ranges specified in Article 13 if connected at a voltage level at or above 110 kV;
(c) be capable of operating across the normal operational voltage range of the system at the connection point, specified by the relevant system operator, if connected at a voltage level below 110 kV. This range shall take into account existing standards, and shall, prior to approval in accordance with Article 6, be subject to consultation with the relevant stakeholders in accordance with Article 9(1);
(d) be equipped with a control system that is insensitive within a dead band around the nominal system frequency of 50,00 Hz, of a width to be specified by the relevant TSO in consultation with the TSOs in the synchronous area. For demand units connected at a voltage level below 110 kV, these specifications shall, prior to approval in accordance with Article 6, be subject to consultation with the relevant stakeholders in accordance with Article 9(1);
(e) be capable of, upon return to frequency within the dead band specified in paragraph 2(d), initiating a random time delay of up to 5 minutes before resuming normal operation.
The maximum frequency deviation from nominal value of 50,00 Hz to respond to shall be specified by the relevant TSO in coordination with the TSOs in the synchronous area. For demand units connected at a voltage level below 110 kV, these specifications shall, prior to approval in accordance with Article 6, be subject to consultation with the relevant stakeholders in accordance with Article 9(1).
The demand shall be increased or decreased for a system frequency above or below the dead band of nominal (50,00 Hz) respectively;
(f) be equipped with a controller that measures the actual system frequency. Measurements shall be updated at least every 0,2 seconds;
(g) be able to detect a change in system frequency of 0,01 Hz, in order to give overall linear proportional system response, with regard to the demand response system frequency control's sensitivity and accuracy of the frequency measurement and the consequent modification of the demand. The demand unit shall be capable of a rapid detection and response to changes in system frequency, to be specified by the relevant TSO in coordination with the TSOs in the synchronous area. An offset in the steady-state measurement of frequency shall be acceptable up to 0,05 Hz.

 

Article 30

Specific provisions for demand units with demand response very fast active power control

 

1. The relevant TSO in coordination with the relevant system operator may agree with a demand facility owner or a CDSO (including, but not restricted to, through a third party) on a contract for the delivery of demand response very fast active power control.
2. If the agreement referred to in paragraph 1 takes place, the contract referred to in paragraph 1 shall specify:
(a) a change of active power related to a measure such as the rate-of-change-of-frequency for that portion of its demand;
(b) the operating principle of this control system and the associated performance parameters;
(c) the response time for very fast active power control, which shall not be longer than 2 seconds.

 

CHAPTER 2
Operational notification procedure

 

Article 31

General provisions

 

1. The operational notification procedure for demand units used by a demand facility or a closed distribution system to provide demand response to system operators shall be distinguished between:
(a) demand units within a demand facility or a closed distribution system connected at a voltage level of or below 1 000 V;
(b) demand units within a demand facility or a closed distribution system connected at a voltage level above 1 000 V.
2. Each demand facility owner or CDSO, providing demand response to a relevant system operator or a relevant TSO, shall confirm to the relevant system operator, or relevant TSO, directly or indirectly through a third party, its ability to satisfy the technical design and operational requirements as referred to in Chapter 1 of Title III of this Regulation.
3. The demand facility owner or the CDSO shall notify, directly or indirectly, through a third party, the relevant system operator or relevant TSO, in advance of any decision to cease offering demand response services and/or about the permanent removal of the demand unit with demand response. This information may be aggregated as specified by the relevant system operator or relevant TSO.
4. The relevant system operator shall specify and make publicly available further details concerning the operational notification procedure.

 

Article 32

Procedures for demand units within a demand facility or a closed distribution system connected at a voltage level of or below 1 000 V

 

1. The operational notification procedure for a demand unit within a demand facility or a closed distribution system connected at a voltage level of or below 1 000 V shall comprise an installation document.
2. The installation document template shall be provided by the relevant system operator, and the contents agreed with the relevant TSO, either directly or indirectly through a third party.
3. Based on an installation document, the demand facility owner or the CDSO shall submit information, directly or indirectly through a third party, to the relevant system operator or relevant TSO. The date of this submission shall be prior to the offer in the market of the capacity of the demand response by the demand unit. The requirements set in the installation document shall differentiate between different types of connections and between the different categories of demand response services.
4. For subsequent demand units with demand response, separate installation documents shall be provided.
5. The content of the installation document of individual demand units may be aggregated by the relevant system operator or relevant TSO.
6. The installation document shall contain the following items:
(a) the location at which the demand unit with demand response is connected to the network;
(b) the maximum capacity of the demand response installation in kW;
(c) the type of demand response services;
(d) the demand unit certificate and the equipment certificate as relevant for the demand response service, or if not available, equivalent information;
(e) the contact details of the demand facility owner, the closed distribution system operator or the third party aggregating the demand units from the demand facility or the closed distribution system.

 

Article 33

Procedures for demand units within a demand facility or a closed distribution system connected at a voltage level above 1 000 V

 

1. The operational notification procedure for a demand unit within a demand facility or a closed distribution system connected at a voltage level above 1 000 V shall comprise a DRUD. The relevant system operator, in coordination with the relevant TSO, shall specify the content required for the DRUD. The content of the DRUD shall require a statement of compliance which contains the information in Articles 36 to 47 for demand facilities and closed distribution systems, but the compliance requirements in Articles 36 to 47 for demand facilities and closed distribution systems can be simplified to a single operational notification stage as well as be reduced. The demand facility owner or CDSO shall provide the information required and submit it to the relevant system operator. Subsequent demand units with demand response shall provide separate DRUDs.

2. Based on the DRUD, the relevant system operator shall issue a FON to the demand facility owner or CDSO.

 

 

 

 

Energy Efficiency Directive Article 15(8)

 

Member States shall ensure that national energy regulatory authorities encourage demand side resources, such as demand response, to participate alongside supply in wholesale and retail markets.

 

Subject to technical constraints inherent in managing networks, Member States shall ensure that transmission system operators and distribution system operators, in meeting requirements for balancing and ancillary services, treat demand response providers, including aggregators, in a non-discriminatory manner, on the basis of their technical capabilities.

 

Subject to technical constraints inherent in managing networks, Member States shall promote access to and participation of demand response in balancing, reserve and other system services markets, inter alia by requiring national energy regulatory authorities or, where their national regulatory systems so require, transmission system operators and distribution system operators in close cooperation with demand service providers and consumers, to define technical modalities for participation in these markets on the basis of the technical requirements of these markets and the capabilities of demand response. Such specifications shall include the participation of aggregators.

 

 

 


 

 

 

 

Interruptibility schemes

 

A subcategory of strategic reserves, interruptibility schemes were found in six of the Member States included in the sector inquiry: Germany, Italy, Ireland, Poland, Portugal, and Spain.


• Since 2010, Italy also has operated two interruptibility schemes: one for the two main islands (contracting 500 MW in each of Sardinia and Sicily) and another for the mainland contracting 3,300 MW.

 

• Between 2013 and 2016 German TSOs have organised monthly tenders for 3,000 MW of sheddable load provided by consumers larger than 50MW. The scheme is presently being revised.

 

• In September 2012, the Polish TSO launched a tender to attract demand response services. The first tender failed to attract any bids but four subsequent tenders between 2013 and 2015 resulted in 200 MW demand response capacity being contracted.

 

• Since 2011, Portugal has operated an interruptibility scheme. 1,392.7 MW of capacity was contracted under the scheme in 2014.

 

• Since 2007 Spain has operated an interruptibility scheme. 3 GW of capacity was contracted in 2015.

 

• In Ireland the Powersave scheme, operated by Eirgrid, is a voluntary scheme encouraging large and medium sized customers to reduce their demand when total system demand is close to available supply. With up to 50 MW of total demand reduction potential it is considerably smaller than the other schemes.

In most schemes, beneficiaries are paid a fixed price for each MW of demand response made available as well as a price for demand reductions actually made (energy delivered). In Poland and Ireland beneficiaries are only paid for energy delivered and receive no availability payment.

There is a difference between schemes that have been established by the TSO to provide it with a valuable tool for ensuring system stability and schemes that have been introduced by the government to request a fixed amount of demand response to be contracted. Also where the capacity is requested by the government it may have a useful function, but the distinction is relevant from a state aid perspective. For instance, the interruptible load scheme established by the German government may be used by the TSOs for re-dispatch purposes. By temporarily switching off loads in the South, the need for north-south flows is alleviated.

 

...

 

Eligibility

 

By definition the interruptibility schemes are limited to demand response capacity. Some schemes have further restrictions on eligibility, such as minimum size requirements.
None of the interruptibility schemes are open to beneficiaries located in other Member States.

 

...

 

Allocation

 

All schemes allocate contracts through a competitive process, except Portugal and Ireland which set prices administratively. In Germany, currently demand for the service generally outweighs supply so prices are set administratively. Amendments to the scheme may address this issue by reducing the total demand.

 

...

 

Capacity product

 

In all schemes, large energy users must agree to be automatically disconnected when needed by the TSO. There is generally no prior notice and disconnection is often instant. Interruptions can last for up to several hours.

There are schemes where the product specification allows the TSO to respond to immediate balancing issues, such as frequency restoration, whereby it immediately remotely disconnects contracted loads, such as the German and Italian schemes. There are also schemes aimed at alleviating adequacy concerns of a longer term, such as the Irish scheme in which consumers are obliged to reduce their loads themselves upon notification by the TSO at least 30 minutes before the 'Powersave' event starts. Beneficiaries in the Irish scheme do not have to reduce their consumption, but are only rewarded if they do reduce their demand.

 

...

 


beneficiaries of interruptibility schemes are typically paid a fixed price for the demand response that they commit to make available when needed, as well as a price for demand reductions actually delivered.


The sector inquiry found interruptibility schemes in six of the Member States covered by the inquiry: Germany, Italy, Ireland, Poland, Portugal, and Spain. Interruptibility schemes are a particular type of strategic reserve which only includes demand response capacity.


6.2.3.1 Ability to address capacity shortages


There are various reasons why governments or TSOs develop interruptibility schemes. Where used to procure demand response capacity to cover a general capacity shortage – as opposed to ancillary services to manage short term frequency deviations – interruptibility schemes can reduce incentives to invest in flexible generation capacity, in the same way as strategic reserves do. Whether interruptibility schemes actually have this effect depends to a large extent on their design.


Most of the interruptibility schemes currently in place are used by the TSO as an ancillary service, i.e. as an instrument the TSO uses after gate closure, remotely and without any prior notice to the providers of the service. In such cases, the impact of the schemes on market incentives is limited. Moreover, the fact that more demand response potential may be activated thanks to the specific support of the scheme may offset part of the need for additional flexible generation capacity as underlined in sub-section 2.3.1.


Re-dispatch services can be provided by other, competing sources of flexibility so they do not necessarily have to be provided solely by demand response. A scheme limited to demand response excludes other providers of flexibility and therefore Public authorities choosing to introduce DSR-specific measures should ensure they can justify any limited eligibility criteria. One justification for separate interruptibility schemes for re-dispatch purposes may be their potential to unlock new capacities and create flexibility that would otherwise not have been at the TSO's disposal.


Regarding their geographic scope, whilst interruptibility schemes generally apply country-wide, their use can be local if the TSO sees a purely local need for shedding loads, for instance in response to network constraints. This is the case for the German interruptible load scheme which, as underlined in sub-section 3.2.3 can be used by the TSOs to compensate for congestions between the North and the South.

 

From a timing perspective, the implementation of interruptibility schemes does not in principle require long-term investments or commitments and therefore can be seen as an appropriate measure if the problem is of transitional nature. For instance, the relatively short contract times applied in interruptibility schemes (see sub-section 5.2.2.4) have the advantage of allowing for amending demand quickly. However, there is no evidence from the sector inquiry that interruptibility schemes are used mainly or solely as transitional mechanisms.


6.2.3.2 Possible competition distortions and impact on market structure


Most of the interruptibility schemes currently in place are relatively small in size and where this is the case their impact on electricity market functioning is unlikely to be significant. Moreover, as underlined in Chapter 2, there is a growing need for a flexible demand side and interruptibility schemes can be appropriate to kick-start the development of demand response that will in future be able to compete with other sources of flexibility on the wholesale or the balancing market. The effects of interruptibility schemes need to be monitored closely however as they have the potential to distort industrial markets if the selection criteria (and in particular minimum size requirements: see sub-section 5.2.2.2) are unnecessarily restrictive. Where schemes are devised by the government rather than independently by the TSO it will be particularly important to ensure that they truly serve the purpose of providing a service that is needed by the TSO at proportionate cost and without disproportionately affecting competition with other sources of flexibility. When this is not the case, these schemes risks becoming – as put forward by various respondents to the sector inquiry – aid to the industrial energy users frequently selected to provide the contracted demand response.

 

6.2.3.3 Conclusions on interruptibility schemes

 

Whilst the benefits of unlocking additional demand response potential are apparent, the design of interruptibility is essential to ensuring that such schemes truly provide added value to the TSO in ensuring system security in a cost-efficient way. Interruptibility schemes do not appear to provide an enduring solution to a capacity shortage problem, but in the short term may be appropriate to help develop demand response. In the longer term, there may be an enduring need for particular ancillary services procured by TSOs from demand response, but in order to reduce the risk of over-compensating the providers of such services, requirements should be specified and beneficiaries selected through competitions open to all potential providers.

 

Commission Staff Working Document, Accompanying the document Report from the Commission, Interim Report of the Sector Inquiry on Capacity Mechanisms {C(2016) 2107 final}, 13.4.2016 SWD(2016) 119 final, p. 47, 48, 117, 118


 

 

 

Market designs with integrated supply and DSR solutions

 

Suppliers are at the interface between consumers and markets and therefore are well placed to value DSR. Flexibility clauses can be integrated in a supply contract, giving the supplier additional tools to optimise its portfolio and reduce sourcing costs. In return, the consumer may reduce its costs compared with a standard supply contract.

 

No other market participant is impacted, and all details are settled in a bilateral contract between supplier and consumer. Two market design solutions can be implemented, depending on whether the consum-er receives price incentives or direct load variation orders from the supplier.

 

a. Variable supply price model

 

In this model, the consumer pays the supplier a variable supply price. The possible variations of the supply price are set contractually, and the consumer can adapt its consumption in response to price variations.


Supply price indexation on market prices makes the price signal more accurate, but also more risky and complex to manage for consumers. The supplier anticipates the behaviour of the consumer in response to the price signal.

 

This information is used by the BRP source to balance its portfolio. This model represents a large share of existing DSR in Europe, notablY for small consumers equipped with smart meters.

 

b. Supplier load control model

 

The flexibility clause in a supply contract can provide for direct supplier load control in specific situations. In such cases, the consumer is expected to curtail its load of a predefined volume at the request of the supplier, which can then be used by the BRP source to take part in balancing markets, self-balance its portfolio or benefit from high market price situations. This type of integrated supply and exibility typically targets industrial consumers.

 

From a market design perspective, a bundled approach for supply and DSR is the simplest way to implement DSR and avoids interfering with other stakeholders.

 

However, it does not allow aggregators to operate independently from suppliers, which may prevent unlocking the full DSR potential in some markets. Complementing this model with other solutions should thus be considered. The economic efficiency of the variable supply price model, compared to the supplier load control model, is reduced if there is a significant gap between energy retail and market prices.

 

Market Design for Demand Side Response Policy Paper, ENTSO-E, November 2015, p. 13 - 14

 

 

 

 

 

Market designs with DSR dissociated from supply


Market designs dissociating DSR from supply require giving direct market access to the consumer or to an independent aggregator on its behalf to sell DSR on the market. Access to the day-ahead and intraday energy markets is organised via a BRP.

 

Specific market design issues associated with DSR dissociated from supply


Allowing an independent aggregator to participate in the day-ahead, intraday or balancing energy market is not straightforward and raises conceptual challenges. It also has collateral impacts on the supplier and on the BRP source. Four major issues need to be addressed.

 

Transfer of energy

 

When performing a DSR-activation, an independent aggregator transfers energy from the BRP source or supplier to another market party. This transfer of energy must therefore be associated with fair compensation between the independent aggregator and BRP source or supplier (while preserving balancing incentives). The fairness of this compensation requires covering the sourcing cost of the BRP source/supplier, which could require accounting for their different sourcing strategies and types of consumers while not creating excessive risks for independent aggregators.
If this is not done appropriately, due to risk management reasons, suppliers might start redefining their sourcing strategy depending on the compensation price. On the other hand, full exposure of independent aggregators to the sourcing strategy of suppliers could threaten their viability.

 

BRP source imbalance risk

 

A DSR activation for balancing purposes impacts the balancing perimeter of the BRP source because the latter is put in imbalance without any control or forecasting possibility over it. is is referred to as "BRP source imbalance risk". Consequently, the BRP source should be compensated for those imbalances. An additional issue might be potential deviation between energy sold by the aggregator to a third party and actual energy activated. It is important to clearly assign that deviation.

 

Information to BRP source and supplier

 

BRPs play a pivotal role in the electricity market. To maintain a balanced position, BRPs actively forecast their generation and demand in their balancing perimeter to the same extent as suppliers do with their customer portfolio. By balancing their own positions, BRPs support the balance of the whole electricity system. If not aware of DSR activations, the BRP source could counterbalance that by reducing (or increasing) generation. Therefore, an accurate assessment of the modification of consumption (or generation) is important to avoid erroneously interpreting it as normal customer behaviour. Finally, BRPs need to be able to check the impact of a DSR activation on their portfolio, allowing a correct settlement with other parties. Hence, for balancing, settlement and forecasting reasons, BRPs and/or suppliers should be informed timely and in an appropriate level of detail when a DSR activation has occurred.

 

Confidentiality


A market design allowing dissociation of supply and exibility should not be exclusive of bundled solutions. Independent aggregators and suppliers can therefore compete to get access to DSR potential. Since the identification and development of DSR potential is part of the core business for aggregators, if DSR activations are notified at individual levels to suppliers of affected consumers, suppliers can benefit for free from the identification efforts of the aggregators. Therefore, a certain level of confidentiality needs to be assured. However, lack of transparency may be an important barrier to facilitating competition among different types of DSR operators. Confidentiality principles should similarly apply to suppliers and aggregators.
A differentiation is to be made between the pre- and post-contracting phase of a flexibility contract between an independent aggregator and the end user.

 

Confidentiality in the pre-contracting phase means that the BRP source or supplier of the end user does not need to be informed that the end user is entering into a contractual relationship with an independent aggregator. As such, the end user and independent aggregator are not hindered in signing a flexibility contract. In a competitive retail market in which suppliers are willing to allow exibility contracts at reasonable conditions, this might be a lesser concern.

 

Confidentiality in the post-contracting phase means that the BRP source or supplier is not aware of a flexibility contract with DSR activations performed by independent aggregators in its portfolio and that all processes (activation, notification, settlement, etc.) are managed to maintain this confidentiality. It is technically challenging to achieve this because meter data has to be corrected to hide changes in consumption patterns.

 

At the same time, because end users will have grow-ing opportunities to value their flexibility, they should also be made aware of the associated responsibilities. For instance, end users might have the contractual obligation to inform all relevant parties (supplier/BRP source) of changes in their consumption profile and has to ensure that there are neither gaps nor overlaps between the contracts they conclude (supply contract, exibility contract, etc.). Hence, end users must be aware that the conditions of their supply contracts on DSR-activations can be important when comparing and negotiating with different suppliers.

Consequently, the "Information to BRP source" and "Confidentiality" issues can lead to contradictory requirements, with diverging interests between BRPs and aggregators. Correct balance between this post- contracting confidentiality and the necessary appropriate information to the BRP source or supplier can be found without compromising competition in DSR markets (between independent aggregator and supplier/BRP source and between independent aggregators), complexity and fairness principles. In practice, a choice needs to be made between safeguarding post- contracting confidentiality, potentially fostering further the development of DSR by protecting independent aggregators, and the potential risk of an increase of balancing needs because balancing quality of BRPs may be affected. Since ensuring both principles at the same time may increase the complexity of the associated market design, a choice on this trade-off needs to be made by policy-makers, taking into account the specificities of the market context.

 

A. Bilateral agreement model

 

The bilateral agreement model is a market design in which the independent aggregator and the BRP source conclude a bilateral agreement to solve the specific market design issues arising from the dissociation of DSR from supply. By nature, this model requires the supplier or the BRP source to be involved in the agreement. This requires a consideration of the impact of the confidentiality issue.

This bilateral agreement is a commercial contract between the independent aggregator and the BRP source or the supplier. However, it requires that both parties are willing to enter into such a contract; hence, competition issues can arise. If the BRP source/supplier refuses to sign bilateral agreements with independent aggregators, or only at an excessive transfer price, it can exert a form of monopoly over flexibility.

The introduction of standard contract templates defined by regulation can facilitate the conclusion of such contracts and provide for easier regulatory monitoring and competition oversight. If the aggregator is the consumer itself, the bilateral agreement can be included in the supply contract.
To solve the transfer of energy and BRP source imbalance risk challenges, the bilateral agreement covers the settlement of the transfer of energy between the

BRP source and the aggregator in case of DSR activation. Typically, a bilaterally agreed-upon transfer price is paid between the BRP source and the aggregator for the energy sold on the market. Such provisions can take the form of a delegation of balancing responsibility from the BRP source to the independent aggregator.

 

Bilateral agreement model allows independent aggregators to operate with a low degree of complexity. It ensures fairness for impacted stakeholders because they express consent in the agreement. The economic efficiency of this model depends on the conditions in the contracts. Competition concerns might occur for independent aggregators because their participation depends on the goodwill of the supplier/BRP source, although this could be solved with regulated, enforceable standard contracts.

 

B. Market designs without bilateral agreement

 

Market designs without bilateral agreement allow aggregators to act independently from suppliers. These models di er from the bilateral agreement model in the way the transfer of energy is dealt with and settled between parties.
In a market design without bilateral agreement, BRP source imbalance risk is solved by neutralising the activated energy (i.e., delta between baseline and metered energy) in the BRP source perimeter. During the imbalance allocation process, the calculated activated energy per BRP source and per imbalance settlement period is used to perform BRP source imbalance risk neutralisation and settlement based on the conditions of the existing BRP contract. Hence, the calculated activated energy is assigned to the BRP source perimeter. In the wholesale day-ahead and intraday markets, independent aggregators are associated with a BRP that assumes this balancing responsibility for the sold or requested energy from a DSR-activation.
In the balancing timeframe, any potential deviation between requested and activated energy is allocated to the independent aggregator either as an imbalance to its associated BRP or as an activation penalty to an independent BSP and is settled accordingly.

The information issue for BRP source is tackled by requiring independent aggregators to schedule DSR activations and inform the TSO and, if applicable, DSO, in a similar way as scheduling obligations apply for generation, including location information if relevant. The TSO informs the BRP source in due time with the requested flexibility activation to avoid counterbalancing.
In all the models below, the pre-contracting confidentiality issue is resolved. Subject to the national contexts, post-confidentiality might be an issue and might affect the choice for a specific market design.

 

A) Supplier settlement for DSR activations

 

In this model, the energy sold on the market by the independent aggregator is invoiced to the consumer by the supplier as if it had been consumed. This way, the transfer of energy is settled directly between the consumer and supplier at the contractual supply price.
In case the aggregator is not the consumer, compensation from the DSR operator to the consumer is necessary, at least to cover the costs of the non-consumed invoiced energy. Such arrangements fall under the contractual relationship between the aggregator and the consumer.

 

Two different possible solutions can be implemented for the supplier to invoice the activated energy following DSR activation.

• Single billing: The supplier receives merged metering information for each consumer without distinction between the consumed energy and the energy of DSR activations. This merging process is performed by the metering entity, for instance, a DSO or the TSO. The model ensures post-contracting confidentiality. However, it could require implementation of complex additional corrective processes, e.g., if taxation differs between consumed energy and the energy of DSR activations.

• Double billing: For each consumer, the supplier receives separate metering information for the consumed energy and the energy of DSR activations from the metering entity. The consumer pays both energies at the supply price to the supplier. This model does not raise concerns regarding the invoicing of grid tariffs, taxes and levies. Moreover, it allows suppliers to have different ways of dealing with the transfer of energy issue per category of clients.

Both models have the advantage that cost reflective DSR bids from consumers or an aggregator on their behalf lead to efficient arbitrage between market prices and usage value without distortions in the merit order.

 

B) Central settlement for DSR activations

 

In this model, the settlement of the transfer of energy is performed by a neutral central entity, which can be a DSO, the TSO or a third party.

The central settlement model requires a wholesale settlement price between the independent aggregator and the BRP source to settle the transfer of energy. This settlement price is:
• either the individual supply price of the activated consumers, which raises feasibility issues because it implies that all individual supply prices are centralised at this neutral entity; or
• a reference price that requires some form of regulatory approval. Such a price can be a segment price per type of customers or a price formula re ecting the market-based settlement price.

This model ensures post-contracting confidentiality for independent aggregators. However, the transfer price can differ from the real supply price of impacted end users, which is not economically optimal. In cases in which a regulatory intervention determines the central settlement price, special care should be taken to preserve a level playing field between different actors in the market. Finally, depending on the chosen solution, such a transfer price might limit the degrees of freedom to suppliers in negotiating innovative supply contracts with end users.

 

Market designs without bilateral agreement ensure pre-contracting confidentiality and allow independent aggregators to act without consent from suppliers/BRPs. In addition, some of these models make post-contracting confidentiality of DSR activations possible, which further reinforces competition between suppliers and independent aggregators. Economic efficiency is ensured if the price to settle the transfer of energy with suppliers is cost-reflective. However, such solutions require heavy and complex evolutions of the market design, which will take time to develop.

 

Market Design for Demand Side Response Policy Paper, ENTSO-E, November 2015, p. 14 - 19

 

 

 

Demand-side response can be applied to distribute a part of a consumer's energy demand to hours of onsite renewable energy generation so as to increase the self-consumption rate, while also avoiding demand peaks. A common application of DSR in commercial buildings is the installation of smart thermostats that regulate electricity demand to avoid high peaks. In some cases, it might not even be necessary to install any device, since the re-arranging of energy- intensive processes from the evening/night to day hours might be sufficient to distribute energy consumption to better match onsite renewable generation.

 

Demand-side response in households can involve the use of smart appliances (e.g. washing machine, tumble dryers, dishwasher, refrigerator etc.). It is estimated that the volume of controllable smart appliances in the EU by 2025 will be at least 60 GW – shifting this load from peak times to other periods can reduce peak-generation needs in the EU by about 10%. Research has found that an effective use of demand-side response may yield annual savings in the order of €60-80 billion by 2030. However, multiple factors condition the ability of households to participate actively in demand-side response markets.

 

Functioning electricity wholesale and retail markets will incentivize demand-side response via the price signals, as prices will be low in periods of abundant generation and high in periods with high demand and limited supply. Automated load shifting through demand-side response measures could be enabled through home energy management infrastructure (e.g. gateways/smart energy boxes, that can coordinate supply and -ready home equipment for demand-side response using a smart meter). Consumers self-generating renewable energy should therefore not only be enabled and encouraged to adapt their consumption to the availability of their electricity production but also to offer flexibility to the wider energy system, including through aggregators.

 

Commission Staff Working Document "Best practices on Renewable Energy Self-generation", 15 July 2015, COM(2015) 339 final, p. 5

 

 

 

 

 

Examples of DSR services from various EU Member States

 

 Belgium

 

Interruptibility contracts exist with some demand users connected at 36kV and above. The contracts typically include interruptibility of a given quantity of MW, that can be activated a few times per year and for a duration of typically a few hours.

 

Asymmetrical Primary Frequency Reserve contracts exist for some demand users connected at 36kV and above. A linear power-frequency reaction is implemented from 50.1Hz up to 50.2Hz.

 

Finland

 

Fingrid has contracted some transmission connected industrial loads (voluntary service) to be used as "frequency controlled disturbance reserve" and as "fast disturbance reserve". The control is simple disconnection of load (in one or several steps) below specified frequency threshold value in a frequency range 49.9 - 49.5 Hz when those loads are utilized as frequency controlled disturbance reserves. For loads acting as fast disturbance reserve, the control is manual (requirement for activation is within 15 minutes).

 

At the moment, schemes do not extend to distribution connected customers. In principle there is no barrier for that, but in practice it is more laborious to collect and manage equivalent total reserve from smaller individual loads.

 

The applied schemes are prescribed by contractual agreements and required capabilities are briefly described in public documents. In general, the idea is that frequency controlled loads shall give a response equivalent to that of rotating machines.

 

If the service provider fails to deliver the service, compensation will be charged by the TSO.

 

France

 

RTE is establishing new schemes for DSR, with both Transmission and Distribution Connected Demand Facilities, via aggregators.

 

The scheme for Demand Facilities is prescribed by a French Law (NOME n°2010/1488 from 7 dec. 2010). These schemes are then established via invitation to tenders, whereafter the Demand Facility or Aggregator shall sign a bilateral agreement. DSR are then offered via the balancing mechanism. The above only applies to voluntary load curtailment. There is no prescribed capability in terms of frequency or voltage withstand capacities.

 

If the contracted DSR is not provided, penalties are set in the bilateral agreement.

 

Great Britain

 

A number of commercial services exist, in which demand side participants are eligible to enter. These services are not generally restricted to transmission connected parties. Services include Firm Frequency Response, Frequency Control by Demand Management, Short Term Operating Reserve and Fast Reserve, all being voluntary, commercial tendered services with generally generic service conditions being applicable, with non-payment, financial penalties or termination of contract used in case of failing to deliver the service.

 

Ireland

 

At present, three regulated demand side schemes are in use, the Winter Peak Demand Reduction Scheme (WPDRS) (peak shaving), Powersave Scheme (load management) and Short Term Active Response (STAR) (emergency contracted power cut complementing reserves). Additionally to those schemes, demand side units participating in the market are developing in Ireland.

 

Italy

 

Contracts exist with some industrial facility owners for disconnection of (part of) their load. The customers could be connected to the transmission or distribution network. Documents with requirements, standard agreements and technical information to operate the system are included in Grid Code. If the customer fails to comply with the disconnection request by the TSO 3 times, the agreements may be cancelled.

 

Norway

 

In Norway, Statnett operates different kinds of DSR services:


 

- A scheme for DSR which in principle is open for all consumers, also distribution connected customers. These customers will benefit through a reduced network tariff. In case of failing to deliver DSR, the reduction will have to be paid back. The scheme is based on voluntary agreements.

 


- DSR- Low frequency (BFK in Norway) is mandatory if asked for by Statnett as TSO (rights given by national law). The end user will be compensated

for the installation of necessary equipment/technology for these purposes, and

based on cost recovery, when DSR is utilized.
The end user can also be connected to the distribution network.

 


- DSR as a reserve for energy shortage (ENOP-Energy Options in Norway). Statnett operates a scheme directed towards key (large) consumers on higher voltage levels to get the rights to disconnect consumption when needed for certain periods (in dry winters etc). This is a voluntary agreement where the consumer will receive a fixed (option) payment for the services, and in addition, an agreed payment in case the option is materialized. 


 

- DSR as a part of the tertiary reserves. Statnett operates a tertiary reserve market where both producers and consumers (voluntarily) can offer production/consumption as reserve capacity.

 

Portugal

 

DSR schemes are in operation today, focusing on transmission system management ("Interruptible Demand Consumers").
Schemes are applicable to demand users connected in VHV, HV and MV, therefore, the schemes may extend to distribution connected costumers. 
Schemes are published in government decree ("Portaria n.o 529/2010 de 29 de Julho"). In case a contracted DSR service is not delivered, penalties are enforced and, in most severe cases, contract annulment may occur.

 

Slovakia

 

Demand Facilities connected to the Transmission Network can voluntarily provide Demand Side Response Active Power Control. The requirements DSR APC are prescribed by National Connection Code. The Grid Codes do not oblige the Demand facility to pay any penalty if DSR service is not delivered.

 

Spain

 

- Interruptibility service: provided by end users to the TSO consisting on a reduction of the "active power" to a level required by the TSO. The supply of the service and its economic issues are previously agreed on in the current regulation and in the contract signed between the two parties. It is a scheme oriented to large industrial consumers that have to meet strong requirements. The interruptibility service improves the security and reliability of the electricity supply as well as the modulation of the daily load shape. Nowadays the service is provided by both transmission and distribution connected consumers, and in all cases the service is managed by the TSO. The prequalification and contractual process is completely regulated. A strong relationship is achieved during this process between the TSO and the consumer. Distribution companies do not have any role in this process. Strong penalties are included in the current regulatory framework in case of not fulfilling the annual load shape requirements or in case of not decreasing the active demand to the firm power level in case of a reduction order sent by the TSO.

 

- Time of use tariffs scheme: consists of the establishment of different static prices depending on the hour of the day and the season of the year. The tariffs are higher in the peak hours than during off-peak hours. It can be applied to all the end users (both transmission and distribution connected) but its implementation in the residential sector is currently very limited. Application of the scheme is mandatory for all consumers with more than 15 kW of contracted power. At a system level, 72% of the total supplied energy is under this tariff scheme. Penalties are established if the active power demanded exceeds the contracted power in that tariff period.

 

Poland

 

Polish Transmission System Operator (PSE) and PGE Mining and Conventional Energy (PGE GiEK) have signed on 22 March 2013 the first on the Polish electricity market agreement regarding Demand Side Services (DSR). Further analogous actions regarding even 500 MW with another contractors are announced by PSE.

PGE GiEK is the subsidiary of PGE which, in turn, possess the position of the Polish largest utility taking in account the electricity generation fleet.

A new service i.e. "negawats" consists in a customer's load reduction on transmission system operator's (TSO) demand. The service represents an important element of the electricity system defence, however of an extraordinary character. It may be also used for electricity system optimistation.

The agreement was executed in effect of the open public tender carried out by the PSE according to the public procurements procedures. It was directed to most significant electricity customers offering the greatest demand reduction capability within relatively urgent time-limits.

The tender was split in 8 separate parts and the PGE GiEK's bid related to 2 of them. Both bids offered 750 PLN for each MWh of reduced load.

In effect of tender PGE GiEK became the first in the Polish market service provider for DSR. The service will involve PGE GiEK's mining activity in the Belchatow lignite mine. DSR will be performed by switching off PGE GiEK's appliances, in such a way, however, the supplies of lignite to the Belchatow power plant were not disturbed.

Given current levels of demand, it is possible for PGE GiEK to reduce load in this manner in the range of 25-30 MW.

 

Network Code on Demand Connection, Frequently Asked Questions, 21 December 2012, p. 24-26, other media

 

 

 

 

Demand Response Services under REMIT reporting

 

 

Contracts involving a customer providing demand response services to a supplier and/or an aggregator qualify as a wholesale energy products and must be reported under REMIT on a continuous basis (Article 3(1)(a)(ii) of Commission Implementing Regulation (EU) No 1348/2014, ACER's Questions and Answers on REMIT, Question II.4.52).

 

However, if a supplier or aggregator sells demand response volume they contracted from customers to the Transmission System Operator (TSO), this contract between supplier or aggregator and TSO should be reported only upon reasoned request of the ACER on an ad hoc basis.

 

 

 

 

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Last Updated on Friday, 22 September 2017 21:28
 

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