One set of rules
Building a secure, competitive and low-carbon European electricity sector and the internal energy market are ambitious targets, based on a common set of rules. These rules are the network codes. The codes are a technical rulebook, that complements existing legislation by defining a common ‘code of conduct’ for all. Generators, grid operators, traders and all other players in the sector will adopt the same practices and business processes.
State of play: where do we stand after eight years?
Between 2009 and March 2017, ENTSO-E has developed, jointly with ACER and stakeholders, eight network codes. The approval of the Electricity Balancing Guideline by EU member states in March 2017 marked the end of that process. All codes have now entered into force, and ENTSO-E’s resources are now mostly focused on their implementation, detailed hereafter. The codes need to remain up-to-date with market and technological developments. Their review is an ongoing process which ENTSO-E will work on jointly with ACER over the years to come.
ENTSO-E shall elaborate network codes in the areas referred to in paragraph 6 of this Article upon a request addressed to it by the Commission in accordance with Article 6(6) (Regulation 714/2009, Article 8(1))
The codes are grouped into three families:
- Market codes move market integration forward, for more competition and resource optimisation. They set rules for capacity calculation and allocation, day-ahead and intraday markets, forward markets and balancing markets. The CACM Regulation entered the third year of its official implementation period in August 2017. The Forward Capacity Allocation Regulation entered its second year of implementation in October 2017. Finally, the Electricity Balancing Guideline was approved in comitology in March 2017 and entered into force on 18 December 2017. Several implementation projects at the European and regional levels are already ongoing or planned.
- Operational codes reinforce the reliability of the system through state-of-the-art and harmonised rules for operating the grid. They cover system operation, regional cooperation and emergency situations. The System Operation Guideline entered into force on 14 September 2017 and the Emergency and Restoration Network Code on 18 December 2017. Several implementation projects with deliverables on the pan-European and regional levels have already begun.
- Connection codes set the EU-wide conditions for linking all actors safely to the grid, including renewables and smart consumption. They include the technical requirements for generation and demand facilities and high-voltage direct current (HVDC) connections.
Although their implementation is the responsibility of each EU member state, ENTSO-E acts as a platform to share information and good practices, especially through the publication of implementation guidance documents. ENTSO-E also monitors the implementation of the three codes, looking in particular at divergences in national implementation.
The codes beyond the EU
ENTSO-E’s membership includes non-EU countries, including Albania, Bosnia and Herzegovina, Switzerland, Iceland, Montenegro, FYR of Macedonia, Norway, Serbia and Turkey as observer. These countries, depending on their legal ties with the EU, may have to implement the network codes. For example, Norway must implement the 3rd package and the network codes, while Switzerland does not have an electricity agreement with the EU and does not implement the network codes.
Implementing the codes: A collective exercise
Entry into force of the codes means they become binding EU law, to be applied by European and national players. Implementation often requires a combination of national decisions, regional agreements, and pan-European methodologies and tools. All market participants, DSOs, TSOs and regulators are involved in various ways.
What are ENTSO-E and TSOs’ roles in the implementation?
The codes define which entity is responsible for each implementation task.
- ENTSO-E oversees part of the implementation tasks.
- Additionally, ENTSO-E facilitates the tasks attributed to ‘all TSOs’. ‘All TSOs’ refers to the TSOs of all EU countries (pan-European ‘all TSOs’), or to the TSOs of a specific EU region (regional ‘all TSOs’). The TSOs whose countries are not member of the EU are also involved in the development phase. Because TSOs have decided that ENTSO-E’s structures are the most suitable vehicle to facilitate the delivery of pan-European tasks and some regional tasks, ENTSO-E facilitates the decision-making process. However, the validation of the deliverables to be submitted to NRAs is made by ‘all TSOs’, not by ENTSO-E.
Once submitted to all EU NRAs (or to those of the respective region), all NRAs must similarly reach a decision to formally adopt the deliverable and make it legally binding. In case they cannot reach a consensus, a safety net process involving ACER is foreseen.
European Stakeholder Committees
Implementing the codes requires the involvement of the whole electricity community, at the EU, regional and national levels. Implementation tasks for all codes require extensive public consultations and the organisation of workshops involving stakeholders. In addition, ACER and ENTSO-E have set up European Stakeholders Committees, with three main missions:
- to contribute to a more informed decision-making process for the methodologies and rules still to be developed;
- to monitor progress in implementation;
- to serve as a platform to share general views on implementation.
The Market Stakeholders Committee launched in 2015, followed by the Grid Connection Stakeholders Committee in 2016, and the System Operations Stakeholders Committee in 2017. The Balancing Stakeholder Group also meets regularly to discuss the implementation of the Electricity Balancing Guideline. ENTSO-E supports these committees by taking charge, with ACER, of the preparation and development of meetings, providing secretariat services, informing stakeholders of progress, and making available all minutes and documents of the meetings on its website.
In 2017, ENTSO-E launched the Q&A, or Issue Logger tool, with the support of ACER, the European Commission and stakeholders participating in the European Stakeholders Committees. Each meeting of the Committees concludes with the elaboration of a list of technical questions on the implementation of the codes. The questions that are deemed of wider interest are recorded in the Issue Logger Tool, and a responsible party (most often ENTSO-E, but also the European Commission and ACER) is appointed to provide an answer to each question. By making questions and answers available to all, the Tool aims to enhance public access to and exchange of information regarding the implementation of the codes.
Better information for better stakeholder engagement
To help improve the understanding of the codes and their implementation, online training on network codes was initiated by ENTSO-E with the Florence School of Regulation, in collaboration with the European Commission and ACER. The pilot was launched in October 2017, focusing on the market codes, and the interactions with the system operation codes. The training was very successful, with around 140 participants and positive feedback. After the first pilot, the training will be further developed to cover all electricity codes. In parallel, ENTSO-E has entirely reviewed its webpages on network codes, so that information on the latest and upcoming implementation steps is more easily accessible to all stakeholders
Overview of implementation activities in 2017
The CACM Regulation
The rules set by the CACM Regulation provide the basis for the implementation of a single energy market across Europe. The CACM Regulation sets out the methods for allocating capacity in day-ahead and intraday timescales and outlines the way in which capacity will be calculated across the different zones. Because it was the first code to enter into force, in August 2015, the implementation of the CACM Regulation is well under way. The following implementation steps were ongoing in 2017.
The Bidding zones study
The CACM Regulation (Article 34) organises the regular reporting by ENTSO-E on the efficiency of the existing bidding zone configuration. Current bidding zones generally correspond to member state boundaries. For completion of the IEM, it is important to analyse the robustness of this structure and whether it is appropriate for future market needs. An efficient configuration of bidding zones maximises social welfare by optimising electricity exchanges across Europe. Since 2012, ENTSO-E and the TSOs of central Europe have been working on the early implementation of CACM Article 34, via a pilot project to elaborate methodologies for the assessment and a review of bidding zone configurations.
In December 2016, ACER issued a request for a review of the bidding zone configuration as specified in CACM Article 32(4). This review covered Austria, Belgium, Czech Republic, Denmark, France, Germany, Hungary, Italy, Luxembourg, the Netherlands, Poland, Slovakia and Slovenia, with a legal deadline of 21 March 2018. Over 2017, the participating TSOs have re-defined the scope of the project so as to be able to deliver by the legal deadline, run the computations and formally submitted the methodologies and assumptions to NRAs. ENTSO-E’s role was that of a facilitator, supporting the participating TSOs in the process.
26 Oct 2017: formal submission to NRAs of methodologies and assumptions, for a three months consultation, as per CACM Article 32 (4) (a)
Dec 2017: workshop with NRA representatives on the methodologies, the difficulties encountered and what could realistically be achieved in the time available
9 Feb – 9 Mar 2018: Public consultation on the draft Bidding Zone Review
5 April 2018: Publication of the Bidding Zone Review
The chosen approach is based on a selection of ex ante defined configurations, encompassing a splitting or merging of the existing bidding zones. They include a separation of Austria from Germany / Luxembourg, a split of the ‘big countries’ France, Germany / Luxembourg and Poland and a further split of France and Germany / Luxembourg into three zones. To also consider the implications of merging zones, the combinations of Belgium with the Netherlands and the Czech Republic with Slovakia have also been considered.
These configurations were analysed and compared over large physical areas using a flow base methodology, which is a first anywhere in the world. TSOs used detailed grid and market models to simulate market and system operations for the different configurations analysed. Assumptions had to be made on the future grid, generation and demand developments as well as on the future generation cost structures.
This first attempt at analysing bidding zone configurations in Europe demonstrated the significant technical complexity of the task. The participating TSOs considered that the evaluation presented in the first edition of the Bidding Zone Review did not provide sufficient evidence for a modification of or for maintaining of the current bidding zone configuration. Therefore they recommended that, given the lack of clear evidence, the current bidding zone delimitation be maintained. Further work is ongoing on the TSOs side to assess and learn from the current review, so that more concrete recommendations will be available in future.
Aug 2016: All TSOs submitted 1st version of the methodology
Feb 2017: NRAs requested amendments
Apr 2017: all TSOs submitted the amended proposal to NRAs
June 2017: NRAs forwarded the decision to ACER
14 Dec 2017: ACER approved the final methodology
The cross-zonal intraday capacity pricing methodology
This methodology aims to provide signal for use of scarce capacity, provide signals for investments and contribute to the efficient functioning of the intraday market.
By 14 August 2017 (24 months after entry into force), all TSOs must submit a proposed methodology for cross-zonal intraday capacity pricing to all NRAs (Article 55, CACM)
The legal framework for this proposal is described in the CACM Regulation Article 55, but specific provisions of the Transparency Regulation (Articles 11(1) and 11(2)) were also considered. When elaborating the proposal, all TSOs considered several models for this methodology and concluded that the most appropriate would be a combined model with continuous trading and pricing of intraday cross-zonal capacity through auctions.
11 April – 12 May 2017: Public consultation and workshop
Aug 2017: all TSOs submit the proposal to all NRAs. At the time of finalisation of this report, NRAs’ decision had not been received.
The advantage of the chosen methodology is that it is compatible with the concept of the Single Intraday Coupling as introduced in the CACM Regulation (XBID project). It allows for an efficient pricing of the intraday cross-zonal capacity through the intraday auctions and can be implemented without a fundamental review of the algorithm of the XBID solution.
Congestion income distribution methodology
Congestion income should be understood as the revenues received as a result of capacity allocation. It will be assigned to each bidding zone border based on the rules described in the distribution methodology, and then distributed to the TSOs on each side of a bidding zone border or, via the relevant TSOs, to third party asset owners. In August 2016, all TSOs submitted to NRAs a first version of the proposed methodology as per Article 73 of the CACM Regulation.
By 14 August 2016 (12 months after entry into force), all TSOs must submit a proposed methodology for congestion income distribution to all NRAs (Article 73, CACM)
However, NRAs requested that TSOs amend their proposal, principally because NRAs considered that specific arrangements for socio-economic benefits, capacity allocation constraints or potential future principles related to capacity allocation were not legitimate grounds for congestion income sharing.
Methodologies for calculating scheduled exchanges resulting from single day-ahead and intraday coupling
TSOs submitted individual proposals for methodologies for calculating scheduled exchanges by the legal deadline of 14 December 2016. However, NRAs considered that the proposal should come from ‘all TSOs’, and not from individual TSOs, and requested that all TSOs resubmit the proposals by February 2018.
By 14 December 2016 (16 months after entry into force), all TSOs shall submit to all NRAs proposals for methodologies for calculating scheduled exchanges resulting from single day-ahead and intraday coupling (Article 43 and 56, CACM)
The proposed methodologies as re-submitted by all TSOs cover scheduled exchanges between bidding zones and scheduling areas resulting from single day-ahead and intraday coupling. All NRAs’ decision is expected in June 2018.
3 Nov – 3 Dec 2017: Public consultation and workshop on all TSOs proposals for scheduled exchanges methodologies
Feb 2018: all TSOs submit the two proposals to all NRAs
Cross-zonal gate opening and gate closure times for intraday coupling
In accordance with Article 59(1) of CACM, all TSOs submitted a proposal to all NRAs end 2016. Upon NRAs request, all TSOs submitted an amended proposal in September 2017. NRAs requested that ACER adopt a decision, due by May 2018, because they could not reach an agreement regarding specific capacity calculation regions or bidding zone borders.
By 14 December 2016 (16 months after entry into force), all TSOs shall be responsible for proposing the intraday cross-zonal gate opening and intraday cross-zonal gate closure times (Article 59(1))
Proposals for amendment to the determination of Capacity Calculation Regions
Attributing new bidding zone borders in a timely fashion is essential for providing the clearest possible framework for the implementation of the CACM (Article 15) and FCA (Article 8) regulations. All TSOs’ initial proposal for Capacity Calculation Regions (CCR) delimitation, submitted in November 2015 and approved by ACER the following year, only considered bidding zone borders due to interconnections that were planned to be commissioned before 2018. Consequently, the bidding zone borders created by newly established interconnectors were not yet attributed to a CCR. This is the case of the future Belgian – Great Britain bidding zone border, resulting from the Nemo link, the installation of which began in the summer of 2017 and which is expected to be taken into use in early 2019. All TSOs proposed in 2017 to attribute it to the Channel CCR.
Belgium-GB BZ border: 7 Apr – 8 May 2017: all TSOs put proposal to public consultation. No responses were received.
18 Sept 2017: all NRAs adopted the position that BE-GB proposal meets the requirements of the CACM Regulation Q1 2018: all NRAs proceed with national decisions
Also not yet included in the CCR delimitation are the Denmark 1 – The Netherlands (DK1 – NL) border resulting from the Cobra cable interconnection, two future interconnections of the France-Great Britain (FR-GB) bidding zone border and the future ALEGrO interconnection on the bidding zone border Belgium-Germany/Luxembourg.
DK1-NL, FR-GB and ALEGrO 15 Nov – 20 Dec: all TSOs put proposal to public consultation. At the time of completion of this report, all TSOs proposal was foreseen to be submitted in mid-April 2018.
Capacity Calculation Regions’ tasks
The main deliverables at CCR level in 2017 were the delivery of proposals for fallback procedures and for capacity calculation methodologies. ENTSO-E supports the CCRs in these tasks by providing its Consultation Hub.
Fallback procedures ensure that cross border capacity can be provided to the market, even in the event that the single day-ahead coupling process is unable to produce results. Fallback procedures must be robust, timely and non-discriminatory.
By December 2016 (16 months after entry into force) all TSOs in each CCR shall submit a proposal for fallback procedures (Art 44 CACM)
This deliverable was due by December 2016, however, due to the lengthy decision-making process within CCRs, several CCRs only submitted their proposal on the fallback procedures in 20171. All proposals were submitted to a public consultation process.
Capacity calculation methodologies
All TSOs in each CCR must develop a capacity calculation methodology based on a flow-based approach (or coordinated NTC approach with justification), as specified in Article 20 CACM. This is only the first step in the process, as Article 21 further requires that CCR’s capacity calculation methodology be harmonised by 31 December 2020.
By September 2017 (10 months after the approval of the proposal for the determination of CCRs) all TSOs in each CCR shall submit a proposal for a common coordinated capacity calculation methodology (Art 20 CACM)
Over 2017, CCRs put their proposals to public consultation and submitted them to the relevant NRAs2. Not all CCRs’ proposed capacity calculation methodologies have been approved yet, because some NRAs have requested amendments. Approval of the methodology triggers a four months delay for the TSOs of the concerned CCR to jointly set up the coordinated capacity calculators needed for the deployment of the Common Grid Model.
1 The Channel CCR’s proposal was being re-submitted to public consultation in March 2018.
2 Two of the CCRs submitted their proposals to public consultation after the legal deadline, the South-East Europe CCR in December 2017 and the IT North CCR in Feb-March 2018.
Maps: Capacity Calculation Regions
As required by Article 9 of the CACM Regulation, all Nominated Electricity Market Operators (NEMOs) – defined as the entities designated to perform tasks related to single day-ahead or single intraday coupling – submitted to NRAs in February 2017 proposals on methodologies around the intraday and day-ahead algorithms (Art. 37 (5) and 37 (1)) and related products (Art. 40 (1) and Art. 53 (1)), as well as backup methodologies (Art. 36 (3)), and a proposal on minimum and maximum clearing prices (Art. 41(2) and Art. 54(2)). All proposals were submitted to public consultation in November-December 2016.
In July 2017, NRAs requested amendments to NEMOs’ proposals on algorithms and back-up methodologies. Revised proposals were resubmitted in November 2017. NRAs referred the proposal on minimum and maximum clearing prices to ACER, who published on 20 November 2017 two decisions on the harmonised maximum and minimum clearing prices SDAC and SIDC.
Plan for the market coupling operator function
The market coupling operator (MCO) Plan includes all the steps necessary to accomplish a European market coupling operator function to integrate European day-ahead and intraday power markets. It will serve as the framework enabling the successful development and operation of market coupling in all EU member states in the years to come. In April 2016, all NEMOs submitted to all NRAS a first version of the MCO Plan. Following a request to amend the proposal, all NEMOs submitted a reviewed Plan in December 2016. In June 2017, NRAs approved the MCO Plan.
The MCO Plan confirms the adoption of Price Coupling of Regions3 solution as the basis for pan-European single day-ahead coupling. Regarding intraday, it enshrines the adoption of the Cross-Border Intraday XBID solution as the basis for pan-European single intraday coupling. According to the MCO plan, the implementation of the SDAC and SIDC shall in any case not last longer than 12 months following the date of approval of the MCO Plan. The CACM Regulation requires that NEMOs and TSOs jointly organise the day to day management of the SDAC and SIDC. The NEMOs and the TSOs are now defining the governance structure for this management with the aim of having it implemented by 2019.
3 Our Annual Work Programme for 2017 foresaw the drafting of a plan to extend the Multi-Regional Coupling to neighbouring regions. This activity has been cancelled following the identification in the MCO Plan of the Price Coupling of Regions as the solution to implement the SDAC.
The Forward Capacity Allocation Regulation
The FCA Regulation, which entered into force on 17 October 2016, sets out rules regarding the type of long-term transmission rights that can be allocated via explicit auction, and the way holders of transmission rights are compensated in case their right is curtailed. The overarching goal is to promote the development of liquid and competitive forward markets in a coordinated way across Europe, and provide market participants with the ability to hedge their risk associated with cross-border electricity trading.
Harmonised allocation rules for long-term transmission rights
An important component of the FCA, harmonised allocation rules (HAR, Article 51 of the FCA Regulation) deal with the procedures for auctioning transmission rights, the terms on which market participants may participate in explicit auctions and the terms for use of cross-zonal capacity. The rules, submitted by all TSOs in April 2017 and approved by ACER in November, apply to the long-term allocations as from 1st January 2018.
The current version of the HAR was the outcome of previous steps taken as part of the early implementation of the FCA Regulation. The first HAR proposal, approved by relevant NRAs in 2015, applied for the long-term auctions of 2016. An updated version applied for long-term auctions in 2017.
By 17 April 2017 (6 months after entry into force), all TSOs shall submit a proposal for harmonised allocation rules for long-term transmission rights (FCA Regulation Article 51)
16 Jan – 17 Feb: Public consultation
Apr 2017: all TSOs submit the HAR proposal and the regional or border specific annexes to the relevant NRAs
Aug 2017: NRAs request ACER to adopt a decision
Nov 2017: ACER approves the HAR
Functional requirements for the establishment of the Single Allocation Platform
The Single Allocation Platform (SAP) will facilitate the allocation of long-term transmission rights and the transfer of these rights among market participants at European level. In addition, it should contribute to a transparent and non-discriminatory allocation of long-term transmission rights.
By 17 April 2017 (6 months after entry into force), all TSOs shall submit to all NRAs a proposal for the establishment and development of the SAP and for its cost-sharing methodology (FCA Regulation Article 49 and 59)
In their joint proposal submitted in April 2017, all TSOs proposed to entrust the operation of the SAP to the Joint Allocation Office (JAO). The JAO is a joint service company of 20 TSOs from 17 countries, performing the yearly, monthly and daily auctions of transmission rights on 27 borders in Europe. The JAO allocates capacity on TSOs’ behalf and is not independent from them: allocation of cross-border capacities remains ultimately the responsibility of TSOs. It is already allocating forward capacities in line with the main body of the HAR since 2015.
Apr 2017: all TSOs submitted proposal for the establishment of the SAP to all NRAs
18 Sept 2017: NRAs adopted position that TSOs’ proposal meets the requirements of the FCA Regulation and as such can be approved by all NRAs.
By end 2017: each NRA adopted national decision
For AC borders having allocations on the SAP, the platform should be operational by December 2018 (i.e. within 12months after all NRAs’ approval). Forward capacity allocations on DC interconnectors is due to take place on the SAP no later than December 2019 (24 months after NRAs’ approval).
Long-term transmission rights
One of the key deliverables at the regional level under the FCA Regulation is the regional design of long-term transmission rights (Article 31). TSOs in each capacity calculation region where long-term transmission rights exist must jointly develop a proposal for the regional design of long-term transmission rights to be issued on each bidding zone border within the capacity calculation region.
By 17 April 2017 (6 months after entry into force), TSOs in each capacity calculation region where long-term transmission rights exist shall jointly develop a proposal for the regional design of long-term transmission rights to be issued on each bidding zone border within the capacity calculation region. (Article 31 FCA Regulation)
Throughout 2017, the proposals for each CCRs were elaborated by the respective TSOs and put to public consultation. For most CCRs, the proposals were approved by the concerned NRAs. When that was not possible, the decision was forwarded to ACER.
Nomination rules - borders with physical transmission rights
As per Article 36(2) of the FCA Regulation, a proposal on nomination rules was due by all TSOs issuing physical transmission rights on a bidding zone border. Nomination rules describe the process by which a holder of a physical transmission right and its counterparty notify the respective TSOs of the use of the respective long-term cross-zonal capacity.
By 17 October 2017 (12 months after entry into force), all TSOs issuing physical transmission rights on a bidding zone border shall submit a proposal for nomination rules for electricity exchange schedules between bidding zones (Article 36(2) FCA Regulation)
27 June – 18 Aug: Public consultation and webinar 17
Oct 2017: concerned TSOs submitted the proposals to the relevant NRAs for approval. At the time of finalisation of this report, the NRAs’ decision was expected in April 2018.
The understanding of the TSOs issuing physical transmission rights is that the proposals had to be submitted per bidding zone border. Therefore, the proposals have been prepared, consulted and submitted at least at bidding zone border level. Overall, 14 proposals were submitted to the relevant NRAs in October 2017.
Statistical analysis of long-term cross-zonal capacity compared to short-term allocation
Because of the delay in the approval of the CACM capacity calculation methodologies (CCR task under CACM, see above), this activity has been postponed. In addition, it has been decided that it will be conducted primarily at the regional level.
The Electricity Balancing Guideline
Electricity balancing is the process by which TSOs ensure, in real time, sufficient energy to balance inevitable differences between supply and demand. The Guideline on Electricity Balancing (GLEB) aims to move Europe from the current situation, in which most balancing is carried out at a national level, to a situation in which larger markets allow the resources available in Europe to be used in a more effective way.
16 March 2017: EU member states approve the GLEB in comitology
18 Dec 2017: The GLEB enters into force
The Guideline sets a framework for common European rules and European platforms for cross-border balancing markets for imbalance netting, frequency restoration reserves with automatic activation (aFRR), frequency restoration reserves with manual activation (mFRR) and replacement reserves. The role of the European platforms is to secure the economically-efficient purchase and in-time activation of balancing energy. Work is ongoing on TSO-TSO settlement, imbalance settlement harmonisation, cross-zonal capacity allocation, reporting, coordination of the tasks and on the implementation frameworks for the European platforms.
Early implementation projects
For establishing the European platforms, the International Grid Control Cooperation (IGCC) project and the Trans-European Replacement Reserves Exchange (TERRE) project have been identified as implementation projects for imbalance netting and for replacement reserves in 2016. In 2017, the Platform for the International Coordination of Automated Frequency Restoration and Stable System Operation (PICASSO) project and the Manually Activated Reserves Initiative (MARI) project were approved as European implementation projects for aFRR and mFRR respectively.
The four European balancing implementation projects have greatly grown during 2017 and now cover practically all members of the regions that are mandated by the GLEB to implement the European platforms. The European implementation projects also developed further the principles for TSO-TSO and TSO-Balancing Service Provider settlement.
The International Grid Control Cooperation (IGCC) project
The imbalance netting implementation framework was drafted during 2017. After a public consultation in early 2018, ENTSO-E is studying the feedback received from stakeholders and regulators and will prepare a final proposal of the implementation framework. In 2018, IGCC will continue working on the implementation of the platform, including decisions on communications requirements, an update of the IGCC multi-lateral agreement and the study of different invoicing solutions.
The PICASSO TSOs signed a Memorandum of Understanding in July 2017. The first public consultation on the design of the aFRR Platform was launched in November 2017. The implementation framework for the exchange of balancing energy from aFRR is being prepared, and a proposal for the TSO-TSO settlement of aFRR exchanges will be drafted during 2018. The go-live of the platform is foreseen by the end of 2021.
In April 2017, MARI TSOs signed a Memorandum of Understanding for the design, implementation and operation of a new mFRR platform. MARI TSOs developed an mFRR platform design, which was published for public consultation in November 2017. In addition, regular communication with the NRAs through the Implementation Group meetings was established. The go-live is foreseen by end of 2021. MARI TSOs are preparing the mFRR Implementation Framework, which shall be submitted by December 2018.
The TERRE TSOs performed a second public consultation on the design of TERRE in July and August 2017. Moreover, the TSOs performing the reserves replacement process are preparing the RR Implementation Framework to comply with the GLEB and ran a public consultation in February-April 2018. During 2018, TERRE will continue to work on incorporating comments from stakeholders and regulators into the Implementation Framework final proposal, as well as on the implementation of the IT platform (LIBRA). The TERRE go-live is foreseen in the second half of 2019.
Frequency containment reserve
A voluntary pilot initiative supporting the implementation of the GLEB, the common market for procurement and exchange of Frequency Containment Reserve (FCR) involves 10 TSOs who procure their FCR in a common market. The project partners launched a public consultation in early 2017 to assess possible market design evolutions. The consultation collected market participants’ views on detailed design options and proposed choices to be implemented in the next phase of the project. Based on the answers received, project members prepared a proposal for the market design of FCR cooperation, as per Article 33(1) of the GLEB. The proposal was submitted to public consultation in early 2018, before submission to NRAs for approval.
The System Operation Guideline
The System Operation Guideline sets out harmonised rules on how to operate the grid to ensure the security of supply with increasing renewables. Its implementation entails several challenging tasks for TSOs at pan-European, synchronous area, and regional (CCR) levels4. Work at pan-European level is steered by ENTSO-E, while synchronous areas’ activities are steered by TSOs in the respective regional groups with the aim of harmonising as much as possible.
A large part of the implementation of the SOGL is prepared through the rollout of the five standard services by the Regional Security Coordinators5. This includes the establishment of year ahead scenarios for assessing the operation of the interconnected transmission system (Article 65), year-ahead/day-ahead/intraday common grid models from individual grid models (articles 67(1) and 70(1)), the methodology for coordinating the operational security analysis (Article 75), agreeing on the principles for assessing the relevance of assets for outage coordination (Article 84), establishing the processes for outage planning coordination (Article 83) and regional adequacy assessment (Article 81).
The SOGL entered into force on 14 September 2017, later than previously foreseen. For this reason the gantt chart showing implementation activities foreseen in our Annual Work Programme for 2017 is not displayed here, because the delayed entry into force of the SOGL has rendered it outdated.
4 The SOGL sets a number of implementation tasks at regional – meaning Capacity Calculation Regions – level. These are not the same as the areas covered by Regional Security Coordinators. The services rollout by RSCs is a pan-European task, steered by ENTSO-E.
5 Note that, among the five tasks of RSCs, coordinated capacity calculation is not specified in the SOGL but in the CACM and FCA regulations.
Synchronous area operational agreements
All TSOs of the following synchronous area – Continental Europe, Nordic, Great Britain and Ireland-Northern Ireland6 – must develop a proposal for an operational agreement.
In particular, regarding the synchronous area Continental Europe, a Synchronous Area Framework Agreement (SAFA) will replace the multi-party agreement of the Operation Handbook7. The Synchronous Area Operational Agreement will be part of the SAFA, as required by SOGL Article 118.
By 14 September 2018 (12 months after entry into force), all TSOs of each synchronous area shall jointly develop common proposals for [synchronous area operational agreements] (Article 118, SOGL)
Developed over 2017, the new policies incorporated within the SAFA are expected to be submitted (in part to NRAs, in part to all TSOs and to TSOs of the Continental Europe synchronous area) for approval in September 2018.
6 The Baltic synchronous area is exempted from this requirement.
7 The parties of the Multilateral Agreement committed themselves to fully comply with the Operation Handbook. The Operation Handbook is a comprehensive collection of technical standards for the operation of the interconnected grid of Continental Europe.
Dynamic stability assessment
The SOGL (articles 38 and 39) provides that each TSO shall perform a dynamic stability assessment at least once a year to identify the stability limits and possible stability problems in its transmission system. All TSOs of each synchronous area must coordinate the dynamic stability assessments, which shall cover all or parts of the synchronous area. In June 2017, ENTSO-E published guidelines to support TSOs in the interpretation of Article 38 and ensure consistency among the dynamic stability assessment carried out by each TSO.
Each TSO shall monitor the dynamic stability of the transmission system (Article 38, SOGL)
ENTSO-E set up a dynamic model able to reproduce the same results with a high variety of dynamic simulation tools available and in use at the different Continental Europe TSOs. In addition, a group was created to monitor and evaluate inter-area oscillations in the Continental Europe synchronous area. Its analysis show that all the oscillations have been properly damped by the affected TSOs. This group will be in charge of executing coordinated dynamic analysis for the regional group Continental Europe, in case a stability issue is detected.
In the Nordic synchronous area, the dynamic stability assessment is calculated by an embedded application in the SCADA systems of the TSOs, with the aim of monitoring the stability continuously. In both the Nordic and CE areas, several actions are ongoing to develop a coordinated method of calculating the minimum inertia by the end of 2018.
Other ongoing implementation activities
In addition, upon entry into force of the SOGL, preparatory work has begun on several other deliverables, including all TSOs’ proposal for key organisational requirements, roles and responsibilities in relation to data exchange; LFC block proposals (activity at synchronous area level); new transparency requirements for information on load-frequency control and reserves; and annual reports for implementation monitoring.
8 June 2017: Informal workshop with stakeholders on data exchange
31 Oct – 1 Dec 2017: Public consultation on all TSOs proposal on data exchange
Jan 2018: submission to NRAs of LFC block proposals (except Nordic, in April 2018)
March 2018: all TSOs proposal on data exchange submitted to all NRAs
Regional Security Coordinators
The System Operation Guideline formalises the name, existence, and role of the RSCs and makes it legally binding for all TSOs to take part. It defines RSCs as the entities owned or controlled by TSOs, in one or more capacity calculation regions, performing tasks related to TSO regional coordination.
TSOs participation in RSCs was previously ensured via a 2015 multilateral agreement between ENTSO-E and TSOs, making it mandatory for ENTSO-E members to participate in RSCs or to contract five services from them.
By end of 2017 all TSOs must confirm which RSC(s) they intend to procure services from (Multilateral agreement signed by TSOs in 2015)
RSCs must perform five tasks for the TSOs, including coordinated capacity calculation (specified in the CACM and FCA regulations), and operational planning security analysis, outage planning coordination, short-term and very short-term adequacy forecasts, and a common grid model with hourly updates (all four services specified in the SOGL).
The RSCs’ work increases efficiency in system operation; minimises risks of wide area events, such as brownouts or blackouts; and lower costs through maximised availability of transmission capacity to market participants. By end of 2017, five RSCs were established and operational, covering the whole of Europe well before the legal deadline of 27 months after entry into force of the SOGL. Only the Albanian TSO OST, ENTSO-E’s newest member since 30 March 2017, is still to appoint an RSC.
Roll-out of the five tasks
All five tasks are to be provided based on the Common Grid Model, and all data is shared via ENTSO-E’s Operational Planning Data Environment (more information on the Common Grid Model below).
28 Sept 2017: Informal workshop with stakeholders on coordinated security analysis
26 Feb – 6 Apr 2018: Public consultations on all TSOs proposals for methodologies on outage coordination and coordinated operational security analysis
Throughout 2017, the methodologies and the functional requirements for the tools to deliver short and medium-term adequacy and outage planning coordination have been prepared by ENTSO-E, with RSCs’ support. In 2018, the common (pan-European) tools will be developed for two of the tasks, outage planning coordination and adequacy assessment.
|Five tasks||Benefits for TSOs and market participants||Status|
|Regional operational security coordination||Identify operational security violations in the operational planning phase. Identify the most efficient remedial actions and recommend them to the concerned TSOs.||All RSCs are providing the service. It will evolve once the methodology for coordinating the security analysis is approved by NRAs (expected March 2019).|
|Regional outage coordination||Detect outage planning incompatibilities and the solutions to solve the incompatibilities.||Regional experimentation ongoing, development of common tools in 2018.|
|Coordinated capacity calculation for CACM||Calculate available electricity transfer capacity across borders (using flow-based or net transfer capacity methodologies). Maximise the capacity offered to the market.||All RSCs are already providing the capacity calculation service, which will evolve after the approval of the capacity calculation methodologies developed regionally according to CACM (see in Chapter 1 under CACM/CCR tasks).|
|Regional adequacy assessment||Provide TSOs with short (day-ahead) to medium (up to week-ahead) adequacy forecast, in order to be able to foresee possible critical grid situations and deal with these accordingly.||Regional experimentation ongoing, development of common tools in 2018.|
|Building of common grid model||Provide the common grid model for all timeframes and applications, to all TSOs which are served by an RSC.||(Described under ‘Common Grid Model’)|
Regional Energy Forums
In October 2017 ENTSO-E adopted its position paper “Power regions for the Energy Union: Regional Energy Forums as the way ahead” as a contribution to the broader discussion on how regional cooperation between EU member states could underpin the Energy Union. The proposed concept complements regional security coordination (which is TSO-led) by regional regulatory cooperation (NRA-led) and political cooperation (government-led) including likewise important stakeholders. In essence, the triangle of governments, regulators, TSOs plus stakeholders would form flexible Regional Energy Forums to promote holistically regional cooperation, which we consider to be crucial for further advancing the single market for electricity.
Map: Overview of the RSCs from which TSOs procure the five tasks (simplified illustration)
The Common Grid Model
The Common Grid Model (CGM) finds its legal basis in three of the network codes: the SOGL (article 64), the CACM Regulation (Article 17) and the FCA Regulation (Article 18). The CGM, and its data exchange system the Operational Planning Data Environment (OPDE), are indeed a prerequisite for several processes harmonised in the network codes, including capacity calculation, operational security analysis, outage planning and adequacy analysis.
The CGM compiles the individual grid model of each TSO, covering timeframes going from one year before real time to one hour before real time. TSOs’ individual (in most cases, national) grid models are picked up by RSCs, who, following a quality assessment and pan-European alignment process, merge them into a pan-European Common Grid Model and feed the merged Common Grid Model back into the system.
The pan-European data exchange capability within the CGM program is expected to be available for application in the business process by August 2018. The CGM is a major project for ENTSO-E, with capital expenditures in 2017 representing 2 M€ and totalizing 6 M€ since 2016. Its operating costs represent 2,2 M€ in 2017 driven by the setup of the communication network, at full deployment the overall operating costs will reach 10 M€ per year (representing in the long term more than 32% of ENTSO-E’s budget).
Implementation of the CGM needs to be consistent throughout the various processes set in the SOGL, CACM and FCA regulations, and this is why all TSOs have been tasked with the preparation of two methodologies: the CGM methodology and the generation and load data provision methodology.
The CACM generation and load data provision methodology was approved by all NRAs in early 2017, while the CACM CGM methodology was resubmitted in March 2017 following a request for amendment. Following the entry into force of the FCA Regulation, both methodologies were updated and resubmitted to NRAs in July 2017. In March 2018 all NRAs approved the FCA generation and load data provision methodology, and requested amendments to the FCA CGM methodology. In the meantime, all TSOs began reviewing both methodologies following the entry into force of the SOGL in September 2017, and a third version of the CGM methodology was submitted to all NRAs in March 2018.
Operational Planning Data Environment
The OPDE, specified by Article 114 of the SOGL, is the information platform that will support the data exchange associated with the CGM merging process. It is also the foundation of the data exchange platform for running the five core services of RSCs.
By 14 September 2019 (24 months after entry into force), ENTSO-E shall implement and operate an operational planning data environment for the storage, exchange and management of all relevant information (SOGL, Art 114).
The delivery of the main software components of the OPDE is ongoing. Central components of the distributed software (protocols EDX/ECP, Operational Planning Data Management) are up and running and their roll-out in TSOs is ongoing. The effective roll out of the minimal set up of OPDE began in 2017 and is expected to be completed in 2018.
ATOM: All TSOs’ network for non-real-time operational and market-related data communication network
The OPDE will run on a dedicated communication network called ATOM. In 2017 the fully meshed core of ATOM was established and is now operational. The core interlinks four TSOs: RTE (France), Swissgrid (Switzerland), Amprion (Germany) and APG (Austria). Other TSOs will then be linked to one of these four TSOs, with a maximum of two degrees of separation from the core. Some TSOs, such as the Nordics, are part of a regional network – meaning that they are connected to one-another via a meshed network. The connection of these regional networks to the ATOM core began in 2017 and will continue in 2018.
It was decided in 2017 that ATOM will be merged with the Electronic Highway to become the Communication Network for Market and Operations (COMO).
Standardisation of information exchange
Standards facilitate cross-border exchange and allow for efficient and reliable identification of different objects and parties relating to the internal energy market and its operations. Standards support the implementation of network codes in various ways and several of ENTSO-E’s IT tools and data environment, such as the OPDE, rely on standards.
In September 2017 the specifications developed by ENTSO-E on the exchange of data in electricity systems in Europe – the Common Grid Model Exchange Specification, or CGMES – were adopted by the International Electrotechnical Commission (IEC). This adoption makes the CGMES an internationally recognised technical specification for electricity data exchange.
ENTSO-E maintains the Electronic Data Interchange library, which regroups documents and definitions for the harmonisation and implementation of standardised electronic data interchanges between actors in the electrical industry in Europe. Several IEC standards from the European Style Market Profile have been updated in 2017 thanks to the input of ENTSO-E: Transparency, MADES (Market Data Exchange Standard), etc. In 2017 ENTSO-E cooperated with CENELEC, contributing to the Smart Energy Grid-Coordination Group and other high-level groups focused on network code implementation chaired by CENELEC.
The Emergency & Restoration Network Code
The Emergency & Restoration Network Code sets out harmonised rules on how to deal with emergency situations and restore the system as efficiently and as quickly as possible. It entered into force on 18 December 2017, and is primarily subject to implementation at a national or TSO level, although RSCs will play a role in the consistency assessments of each TSO’s system defence plan. Implementation is planned to extend until 2022.
An expert team supported by ENTSO-E has been drawn from TSO representatives involved in forming TSO’s own defence and restoration plans and in drafting the Code. The project team will focus on developing a consistent and harmonised approach to the defence and restoration measures outlined in the Regulation, to establish regional and inter-TSO coordination and assistance during an emergency state, to engage with Regional Security Coordinators to assess consistency, and to establish a harmonised approach to the suspension and restoration of market activities.
The Connection codes
While 2016 was the year when all the three connection codes (Requirement for Generators, Demand Connection, and High-Voltage Direct Current) were approved and entered into force, 2017 focused on national implementation. Each EU member state had to follow its own national process to define the parameters i.e. non-exhaustive requirements and boundary thresholds. The final submission of those was – by regulation – May 2017 for RfG and September 2017 for DCC and HVDC.
By six months after their entry into force (and thereafter every two years), ENTSO-E shall prepare non-binding written guidance concerning the elements of each of the three connection codes requiring national decisions. (Article 56 DCC, Article 75 HVDC, Article 58 RfG)
ENTSO-E’s role is to monitor this implementation process, but also to assist with the development and delivery of non-binding written guidance – Implementation Guidance Documents (IGDs) – to its members and other system operators. The IGDs were drafted and published by October 2016 (for RfG) and by March 2017 (for HVDC and DC), in compliance with the legal requirement of six months after the entry into force of each regulation, and are expected every two years.
In order to further support TSOs and other system operators in their comprehension and implementation of the connection codes, ENTSO-E continued to develop additional IGDs. The new IGDs were developed with the support of stakeholders from the development/drafting phase onward, via workshops, public surveys and expert groups. The IGDs that were elaborated heavily during 2017 were the eight frequency-related IGDs, an IGD on cost-benefit analysis and an IGD on compliance monitoring. Three IGDs on HVDC-related aspects were also developed during 2017, and published for consultation in March 2018.
Mar, Jul, Oct: Three workshops with stakeholders on the connection codes frequency parameters
2 Mar 2017: Workshop with stakeholders, decision to set up an expert group on CBA
8 Mar 2017: Publication of updated IGD on Compliance Testing and Monitoring
10 Aug 217: Publication of IGD on high penetration of power electronic interfaced power sources
Jan 2018: Publication of report on Inter-TSO coordination in connection network codes implementation
5 Feb 2018: Publication of IGD on the frequency related parameters
29 Jan – 2 Mar 2018: Public consultation on the IGD on CBA
26 Mar – 4 May: Public consultation on the HVDC-IGDs
Development of the IGDs is fuelled by discussions with stakeholders, taking place through the three expert groups on compliance monitoring, fast fault current injection (both set up in 2016) and cost benefit analysis (set up in May 2017) and in the Grid Connection Stakeholder Committee. The improvement and use of the active library and the creation of the Issue Logger tool have also contributed to the exchange of knowledge, experience and good practices.
Additionally, ENTSO-E emphasised the enhancing of inter-TSO coordination activities, via the elaboration of a report on inter-TSO coordination released in January 2018. The connection codes require TSOs to coordinate when establishing certain requirements, either at synchronous area level or between adjacent TSOs.
Monitoring the implementation: Are the codes delivering?
ENTSO-E is entrusted with the tasks of monitoring and analysing the implementation of the network codes and guidelines, and their effect on the harmonisation of applicable rules aimed at facilitating market integration (Article 8(8) of Regulation (EC) No 714/2009).
Monitoring activities entail the elaboration of monitoring plans and monitoring reports, as well as the collection of data (so-called ‘Lists of information’), including the identification of data to be collected and the design and implementation of interfaces for data collection. Work started in 2016 for CACM and continued over 2017 for CACM, FCA and the connection codes.
Progress and potential problems with the implementation of the
Single Day-Ahead and Intraday Coupling
ENTSO-E’s biannual reports provides an account of the current state-of-play and challenges in the implementation of single day-ahead and intraday coupling, and take stock of the progress achieved so far in the coupling of electricity markets through the different projects in place, namely the day-ahead market coupling project (Multi-Regional Coupling project (MRC)) and the intraday market coupling project (XBID).
ENTSO-E must report every six months on the progress and potential problems with the implementation of the Single Day-Ahead and Intraday Coupling, including the choice of different available options in each country (Article 82(2)(a) CACM & Monitoring Plan)
The 2nd (covering the period from August 2016 to February 2017) and 3rd (February 2017 to August 2017) reports highlight the transversal progress in day-ahead and intraday coupling in terms of all TSOs’ and all NEMOs’ deliverables. In particular, the reports note the approval by ACER of the all TSOs proposal on CCR delimitation, stressing that the establishment of the Core CCR in a single step will likely prove to be a challenge for all involved parties including TSOs, NEMOs and NRAs.
13 Feb 2017: Publication of the 2nd report on the progress and potential problems with the implementation of the Single Day-Ahead and Intraday Coupling
14 Aug 2017: Publication of the 3rd report
In addition, the reports find that the MRC project continued to operate day-ahead coupling without any major incident. Progress and achievements in the MRC extension projects include the extension of flow-based in MRC operations to Austria in November 2016 and the recognition of PSE as a full member as of July 2017.
ACER’s decision to establish a Core CCR is being followed through, as TSOs and NEMOs in the former CEE Region which are not yet coupled via the MRC project have started the joint Core Flow-Based Market Coupling project.
Regarding XBID, the reports find that the project continues to make substantive progress, despite the go-live date having been postponed from Q3 2017 to Q1 20188
8 In January 2018 it was announced that the go-live date of XBID has been postponed to 12-13 June 2018. User Acceptance Testing is complete and final readiness preparation is underway.
Reporting on capacity calculation and allocation
ENTSO-E’s report on capacity calculation and allocation was delivered to ACER on 14 August 2017. The CACM Regulation specifies that it is up to ACER to decide whether to publish the report. It has not been published so far.
By 14 August 2017 (two years after entry into force), ENTSO-E shall submit to ACER a report on capacity calculation and allocation (Article 31, CACM)
FCA’s Monitoring Plan and list of relevant information
The Monitoring Plan submitted in April 2017 outlines how ENTSO-E will perform its monitoring tasks, based on the reports and updates to be delivered by ENTSO-E, TSOs and the SAP Operator in accordance with the FCA Regulation. The main reports to be delivered will be the following: (i) a report on the progress and potential problems with the implementation of forward capacity allocation; (ii) a report on the effectiveness of splitting long-term cross-zonal capacity; (iii) a report on capacity calculation and allocation; and (iv) a report on the effectiveness of the operation of the forward capacity allocation and the single allocation platform.
By 17 April 2017 (six months after entry into force) ENTSO-E shall submit to ACER the plan for monitoring the implementation of the FCA Regulation and the establishment of the SAP (Article 63, FCA)
Moreover, ACER delivered to ENTSO-E a list of data that should be communicated by ENTSO-E to ACER in accordance with Article 63(3) of the FCA Regulation. The exact details of the data items in this list are currently being further clarified.
Monitoring the implementation at national level of the connection codes
ENTSO-E’s monitoring activities will be based on the list of information shared by ACER. This task is already under coordination. Implementation of the connection codes takes place at national level. Therefore, to collect all relevant information necessary to monitor their implementation, ENTSO-E has developed the so-called ‘Active library’, compiling relevant information and documents for each country. In 2017, ENTSO-E worked on improving the Active Library by adding public information for each EU member state and for some other countries (e.g. some Energy Community Members).
ENTSO-E shall monitor the implementation of each of the three connection codes, looking in particular at any divergences in the national implementation and whether the choice of values and ranges in the requirements specified in each regulation continue to be valid (Article 76, HVDC; Article 57, DC; Article 59, RfG)
In addition, ENTSO-E has developed a summary monitoring excel file where all the non-exhaustive requirements (values, ranges and status) are integrated as soon as they are available. This table aims to provide a high-level view of any possible divergence among the TSOs. This activity is still ongoing and will be completed by Q2 2018.
Monitoring the implementation of the connection codes is proving to be a challenge, due to the multiple national implementation processes. Retrieving information is a continuous effort. ENTSO-E will continue supporting the TSOs with internal coordination activities and by providing non-binding guidance when needed.
Overall, network codes have already delivered, and will deliver further, as early implementation and pilots show. The process itself of developing the codes has led to substantial improvements in aligning market design, operations and rules to converge towards a common target approach. Further monitoring and assessment of the value created by network codes can be found in ACER’s market monitoring reports.
Figure: The value created by network codes9
9 FTI / ENTSO-E 2018, presented at the joint conference on network codes with ACER, the EC and ENTSOG of 4 May 2017