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Regulation 2009/714 ( 4 ) has been substantially amended several times. Since further amendments are to be made, that Regulation should be recast in the interests of clarity.

The Energy Union aims to provide final customers – household and business – with safe, secure, sustainable, competitive and affordable energy. Historically, the electricity system was dominated by vertically integrated, often publicly owned, monopolies with large centralised nuclear or fossil fuel power plants. The internal market for electricity, which has been progressively implemented since 1999, aims to deliver a real choice for all consumers in the Union new business opportunities and more cross-border trade, so as to achieve efficiency gains, competitive prices and higher standards of service, and to contribute to security of supply and sustainability. The internal market for electricity has increased competition, in particular at the wholesale level, and cross-zonal trade. It remains the foundation of an efficient energy market.

The Union's energy system is in the middle of its most profound change in decades and the electricity market is at the heart of that change. The common goal of decarbonising the energy system creates new opportunities and challenges for market participants. At the same time, technological developments allow for new forms of consumer participation and cross-border cooperation.

This Regulation establishes rules to ensure the functioning of the internal market for electricity and includes requirements related to the development of renewable forms of energy and environmental policy, in particular specific rules for certain types of renewable power-generating facilities, concerning balancing responsibility, dispatch and redispatching, as well as a threshold for CO 2 emissions of new generation capacity where such capacity is subject to temporary measures to ensure the necessary level of resource adequacy, namely, capacity mechanisms.

Electricity from renewable sources from small power-generating facilities should be granted priority dispatch either via a specific priority order in the dispatching methodology or via legal or regulatory requirements for market operators to provide this electricity on the market. Priority dispatch which has been granted in the system operation services under the same economic conditions should be considered to comply with this Regulation. In any case, priority dispatch should be deemed to be compatible with the participation in the electricity market of power-generating facilities using renewable energy sources.

State interventions, often designed in an uncoordinated manner, have led to increasing distortions of the wholesale electricity market, with negative consequences for investments and cross-border trade.

In the past, electricity customers were purely passive, often buying electricity at regulated prices which had no direct relation to the market. In the future, customers need to be enabled to fully participate in the market on equal footing with other market participants and need to be empowered to manage their energy consumption. To integrate the growing share of renewable energy, the future electricity system should make use of all available sources of flexibility, particularly demand side solutions and energy storage, and should make use of digitalisation through the integration of innovative technologies with the electricity system. To achieve effective decarbonisation at the lowest cost, the future electricity system also needs to encourage energy efficiency. The completion of the internal energy market through the effective integration of renewable energy can drive investments in the long term and can contribute to delivering the objectives of the Energy Union and the 2030 climate and energy framework, as set out in the Commission communication of 22 January 2014 entitled ‘A policy framework for climate and energy in the period from 2020 to 2030’, and endorsed in the conclusions adopted by the European Council at its meeting on 23 and 24 October 2014.

More market integration and the change towards a more volatile electricity production requires increased efforts to coordinate national energy policies with neighbours and to use the opportunities of cross-border electricity trade.

Regulatory frameworks have developed, allowing electricity to be traded across the Union. That development has been supported by the adoption of several network codes and guidelines for the integration of the electricity markets. Those network codes and guidelines contain provisions on market rules, system operation and network connection. To ensure full transparency and increase legal certainty, the main principles of market functioning and capacity allocation in the balancing, intraday, day-ahead and forward market timeframes should also be adopted pursuant to the ordinary legislative procedure and incorporated in a Union legislative single act.

Article 13 of Commission GEBR ( 5 ) establishes a process whereby transmission system operators are able to delegate all or part of their tasks to a third party. The delegating transmission system operators should remain responsible for ensuring compliance with this Regulation. Moreover, Member States should be able to assign tasks and obligations to a third party. Such assignment should be limited to tasks and obligations carried out at national level, such as imbalance settlement. The limitations on such assignment should not lead to unnecessary changes to existing national arrangements. However, transmission system operators should remain responsible for the tasks entrusted to them under Article 40 of CRIMED ( 6 ) .

With regard to balancing markets, efficient and non-distortive price formation in the procurement of balancing capacity and balancing energy requires that balancing capacity contracts do not set the price for balancing energy. This is without prejudice for the dispatching systems using an integrated scheduling process in accordance with GEBR.

Articles 18, 30 and 32 of GEBR establish that the pricing method for both standard and specific products for balancing energy should create positive incentives for market participants in keeping their own balance or helping to restore the system balance in their imbalance price area, thereby reducing system imbalances and costs to society. Such pricing approaches should strive for the economically efficient use of demand response and other balancing resources, subject to operational security limits.

The integration of balancing energy markets should facilitate the efficient functioning of the intraday market in order to provide the possibility for market participants to balance themselves as closely as possible to real time, enabled by the balancing energy gate closure times provided for in Article 24 of GEBR. Only the imbalances remaining after the end of the intraday market should be balanced by transmission system operators in the balancing market. Article 53 of GEBR also provides for the harmonisation of the imbalance settlement period at 15 minutes in the Union. That harmonisation is intended to support intraday trading and foster the development of a number of trading products with the same delivery windows.

In order to enable transmission system operators to procure and use balancing capacity in an efficient, economic and market-based manner, there is a need to foster market integration. In that regard, Title IV of GEBR establishes three methodologies through which transmission system operators are entitled to allocate cross-zonal capacity for the exchange of balancing capacity and the sharing of reserves, when supported on the basis of a cost-benefit analysis: the co-optimisation process, the market-based allocation process and the allocation based on an economic efficiency analysis. The co-optimisation allocation process is to be performed on a day-ahead basis. By contrast, it is possible to perform the market-based allocation process where the contracting is carried out not more than one week in advance of the provision of the balancing capacity and to perform the allocation based on an economic efficiency analysis where the contracting is done more than one week in advance of the provision of the balancing capacity, provided that the volumes allocated are limited and that an assessment is carried out annually. Once a methodology for the process of allocating cross-zonal capacity is approved by the relevant regulatory authorities, early application of that methodology by two or more transmission system operators could take place to allow them to gain experience and to allow for the smooth application of that methodology by more transmission system operators in the future. The application of such methodologies should nevertheless be harmonised by all transmission system operators in order to foster market integration.

Title V of GEBR established that the general objective of imbalance settlement is to ensure that balance responsible parties keep their own balance or help restore the system balance in an efficient way and to provide incentives to market participants for keeping or helping to restore the system balance. To make balancing markets and the overall energy system fit for the integration of the increasing share of variable renewable energy, imbalance prices should reflect the real-time value of energy. All market participants should be financially responsible for the imbalances they cause in the system, representing the difference between the allocated volume and the final position in the market. For demand response aggregators, the allocated volume consists of the volume of energy physically activated by the participating customers' load, based on a defined measurement and baseline methodology.

Commission GCACMR ( 7 ) sets out detailed guidelines on cross-zonal capacity allocation and congestion management in the day-ahead and intraday markets, including the requirements for the establishment of common methodologies for determining the volumes of capacity simultaneously available between bidding zones, criteria to assess efficiency and a review process for defining bidding zones. Articles 32 and 34 of GCACMR set out rules on review of bidding zone configuration, Articles 41 and 54 thereof set out harmonised limits on maximum and minimum clearing prices for day-ahead and intraday timeframes, Article 59 thereof sets out rules on intraday cross-zonal gate closure times, whereas Article 74 thereof sets out rules on redispatching and countertrading cost sharing methodologies.

Commission GFCAR ( 8 ) sets out detailed rules on cross-zonal capacity allocation in the forward markets, on the establishment of a common methodology to determine long-term cross-zonal capacity, on the establishment of a single allocation platform at European level offering long-term transmission rights, and on the possibility to return long-term transmission rights for subsequent forward capacity allocation or to transfer long-term transmission rights between market participants. Article 30 of GFCAR sets out rules on forward hedging products.

Commission NCRGCGR ( 9 ) sets out the requirements for grid connection of power-generating facilities to the interconnected system, in particular with respect to synchronous power-generating modules, power park modules and offshore power park modules. Those requirements help to ensure fair conditions of competition in the internal electricity market, to ensure system security and the integration of electricity from renewable sources, and to facilitate Union-wide trade in electricity. Articles 66 and 67 of NCRGCGR set out rules for emerging technologies in electricity generation.

Bidding zones reflecting supply and demand distribution are a cornerstone of market-based electricity trading and are a prerequisite for reaching the full potential of capacity allocation methods including the flow-based approach. Bidding zones therefore should be defined in a manner to ensure market liquidity, efficient congestion management and overall market efficiency. When a review of an existing bidding zone configuration is launched by a single regulatory authority or transmission system operator with the approval of its competent regulatory authority, for the bidding zones inside the transmission system operator's control area, if the bidding zone configuration has negligible impact on neighbouring transmission system operators' control areas, including interconnectors, and the review of bidding zone configuration is necessary to improve efficiency, to maximise cross-border trading opportunities or to maintain operational security, the transmission system operator in the relevant control area and the competent regulatory authority should be, respectively, the only transmission system operator and the only regulatory authority participating in the review. The relevant transmission system operator and the competent regulatory authority should give the neighbouring transmission system operators prior notice of the review and the results of the review should be published. It should be possible to launch a regional bidding zone review following the technical report on congestion in line with Article 14 of this Regulation or in accordance with existing procedures laid down in GCACMR.

When regional coordination centres carry out a capacity calculation, they should maximise capacity considering non-costly remedial actions and respecting the operational security limits of transmission system operators in the Capacity Calculation Region. Where the calculation does not result in capacity equal to or above the minimum capacities set out in this Regulation, regional coordination centres should consider all available costly remedial actions to further increase capacity up to the minimum capacities, including redispatching potential within and between the capacity calculation regions, while respecting the operational security limits of transmission system operators of the Capacity Calculation Regions. Transmission system operators should report accurately and transparently on all aspects of capacity calculation in accordance with this Regulation and should ensure that all information sent to regional coordination centres is accurate and fit for purpose.

When performing capacity calculation, regional coordination centres should calculate cross-zonal capacities using data from transmission system operators which respects the operational security limits of the transmission system operators' respective control areas. Transmission system operators should be able to deviate from coordinated capacity calculation where its implementation would result in a violation of the operational security limits of network elements in their control area. Those deviations should be carefully monitored and transparently reported to prevent abuse and ensure that the volume of interconnection capacity to be made available to market participants is not limited in order to solve congestion inside a bidding zone. Where an action plan is in place, the action plan should take account of deviations and address their cause.

Core market principles should set out that electricity prices are to be determined through demand and supply. Those prices should indicate when electricity is needed, thereby providing market-based incentives for investments into flexibility sources such as flexible generation, interconnection, demand response or energy storage.

While decarbonisation of the electricity sector, with energy from renewable sources becoming a major part of the market, is one of the goals of the Energy Union, it is crucial that the market removes existing barriers to cross-border trade and encourages investments into supporting infrastructure, for example, more flexible generation, interconnection, demand response and energy storage. To support this shift to variable and distributed generation, and to ensure that energy market principles are the basis for the Union's electricity markets of the future, a renewed focus on short-term markets and scarcity pricing is essential.

Short-term markets improve liquidity and competition by enabling more resources to participate fully in the market, especially those resources that are more flexible. Effective scarcity pricing will encourage market participants to react to market signals and to be available when the market most needs them and ensures that they can recover their costs in the wholesale market. It is therefore critical to ensure that administrative and implicit price caps are removed in order to allow for scarcity pricing. When fully embedded in the market structure, short-term markets and scarcity pricing contribute to the removal of other market distortive measures, such as capacity mechanisms, in order to ensure security of supply. At the same time, scarcity pricing without price caps on the wholesale market should not jeopardize the possibility of offering reliable and stable prices to final customers, in particular household customers, small and medium-sized enterprises (SMEs) and industrial customers.

Without prejudice to Articles 107, 108 and 109 of the Treaty on the Functioning of the European Union (TFEU), derogations from fundamental market principles such as balancing responsibility, market-based dispatch, or redispatch reduce flexibility signals and act as barriers to the development of solutions such as energy storage, demand response or aggregation. While derogations are still necessary to avoid an unnecessary administrative burden to certain market participants, in particular household customers and SMEs, broad derogations covering entire technologies are not consistent with the aim of achieving efficient market-based decarbonisation processes and should thus be replaced by more targeted measures.

A precondition for effective competition in the internal market for electricity is non-discriminatory, transparent and adequate charges for network use including interconnecting lines in the transmission system.

Uncoordinated curtailments of interconnector capacities increasingly limit the exchange of electricity between Member States and have become a serious obstacle to the development of a functioning internal market for electricity. The maximum level of capacity of interconnectors and the critical network elements should therefore be made available, complying with the safety standards of secure network operation including respecting the security standard for contingencies (N-1). However, there are some limitations to setting the capacity level in a meshed grid. Clear minimum levels of available capacity for cross-zonal trade need to be put in place in order to reduce the effects of loop flows and internal congestions on cross-zonal trade and to give a predictable capacity value for market participants. Where the flow-based approach is used, that minimum capacity should determine the minimum share of the capacity of a cross-zonal or an internal critical network element respecting operational security limits to be used as an input for coordinated capacity calculation under GCACMR, taking into account contingencies. The total remaining share of capacity may be used for reliability margins, loop flows and internal flows. Furthermore, in the case of foreseeable problems for ensuring grid security, derogations should be possible for a limited transitional phase. Such derogations should be accompanied by a methodology and projects providing for a long-term solution.

The transmission capacity to which the 70 % minimum capacity criterion shall apply in the net transmission capacity (NTC) approach is the maximum transmission of active power which respects operational security limits and takes into account contingencies. The coordinated calculation of this capacity also takes into account that electricity flows are distributed unevenly between individual components and is not just adding capacities of interconnecting lines. This capacity does not take into account the reliability margin, loop flows or internal flows which are taken into account within the remaining 30 %.

It is important to avoid distortion of competition resulting from the differing safety, operational and planning standards used by transmission system operators in Member States. Moreover, there should be transparency for market participants concerning available transfer capacities and the security, planning and operational standards that affect the available transfer capacities.

To efficiently steer necessary investments, prices also need to provide signals where electricity is most needed. In a zonal electricity system, correct locational signals require a coherent, objective and reliable determination of bidding zones via a transparent process. In order to ensure efficient operation and planning of the Union electricity network and to provide effective price signals for new generation capacity, demand response and transmission infrastructure, bidding zones should reflect structural congestion. In particular, cross-zonal capacity should not be reduced in order to resolve internal congestion.

To reflect the divergent principles of optimising bidding zones without jeopardising liquid markets and grid investments two options should be provided for in order to address congestion. Member States should be able to choose between a reconfiguration of their bidding zone or measures such as grid reinforcement and grid optimisation. The starting point for such a decision should be the identification of long-term structural congestions by the transmission system operator or operators of a Member State, by a report by the European Network of Transmission System Operators for Electricity (the ‘ENTSO for Electricity’) on congestion or by a bidding zone review. Member States should first try to find a common solution on how to best address congestion. In the course of doing so Member States might adopt multinational or national action plans to address congestion. For Member States which adopt an action plan to address congestion, a phase-in period in the form of a linear trajectory for the opening of interconnectors should apply. At the end of the implementation of such an action plan, Member States should have a possibility to choose whether to opt for a reconfiguration of the bidding zone(s) or whether to opt for addressing remaining congestion through remedial actions for which they bear the costs. In the latter case their bidding zone should not be reconfigured against the will of that Member State, provided that the minimum capacity is reached. The minimum level of capacity that should be used in coordinated capacity calculation should be a percentage of the capacity of a critical network element, as defined following the selection process under GCACMR, after, or, in the case of a flow-based approach, while, respecting the operational security limits in contingency situations. A Commission decision on the configuration of a bidding zone should be possible as a measure of last resort and should only amend the configuration of a bidding zone in those Member States which have opted to split the bidding zone or which have not reached the minimum level of the capacity.

Efficient decarbonisation of the electricity system via market integration requires systematically abolishing barriers to cross-border trade to overcome market fragmentation and to allow Union energy customers to fully benefit from the advantages of integrated electricity markets and competition.

This Regulation should lay down basic principles with regard to tarification and capacity allocation, while providing for the adoption of guidelines detailing further relevant principles and methodologies, in order to allow rapid adaptation to changed circumstances.

The management of congestion problems should provide correct economic signals to transmission system operators and market participants and should be based on market mechanisms.

In an open, competitive market, transmission system operators should be compensated for costs incurred as a result of hosting cross-border flows of electricity on their networks by the operators of the transmission systems from which cross-border flows originate and the systems where those flows end.

Payments and receipts resulting from compensation between transmission system operators should be taken into account when setting national network tariffs.

The actual amount payable for cross-border access to the system can vary considerably, depending on the transmission system operator involved and as a result of differences in the structure of the tarification systems applied in Member States. A certain degree of harmonisation is therefore necessary in order to avoid distortions of trade.

There should be rules on the use of revenues from congestion-management procedures, unless the specific nature of the interconnector concerned justifies an exemption from those rules.

To provide for a level playing field between all market participants, network tariffs should be applied in a way which does not positively or negatively discriminate between production connected at the distribution level and production connected at the transmission level. Network tariffs should not discriminate against energy storage, and should not create disincentives for participation in demand response or represent an obstacle to improving energy efficiency.

In order to increase transparency and comparability in tariff-setting where binding harmonisation is not seen as adequate, a best practices report on tariff methodologies should be issued by the European Agency for the Cooperation of Energy Regulators (‘ACER’) established by EUACERR ( 10 ) .

To better ensure optimal investment in the trans-European grid and to better address the challenge where viable interconnection projects cannot be built for lack of prioritisation at national level, the use of congestion rents should be reconsidered and contribute to guarantee availability and maintain or increase interconnection capacities.

In order to ensure optimal management of the electricity transmission network and to allow trading and supplying electricity across borders in the Union, the ENTSO for Electricity, should be established. The tasks of the ENTSO for Electricity should be carried out in accordance with Union's competition rules which remain applicable to the decisions of the ENTSO for Electricity. The tasks of the ENTSO for Electricity should be well-defined and its working method should ensure efficiency and transparency. The network codes prepared by the ENTSO for Electricity are not intended to replace the necessary national network codes for non-cross-border issues. Given that more effective progress may be achieved through an approach at regional level, transmission system operators should set up regional structures within the overall cooperation structure, whilst ensuring that results at regional level are compatible with network codes and non-binding ten-year network development plans at Union level. Member States should promote cooperation and monitor the effectiveness of the network at regional level. Cooperation at regional level should be compatible with progress towards a competitive and efficient internal market for electricity.

The ENTSO for Electricity should carry out a robust medium to long-term European resource adequacy assessment to provide an objective basis for the assessment of adequacy concerns. The resource adequacy concern that capacity mechanisms address should be based on the European resource adequacy assessment. That assessment may be complemented by national assessments.

The methodology for the long-term resource adequacy assessment (from ten-year-ahead to year-ahead) set out in this Regulation has a different purpose than the seasonal adequacy assessments (six months ahead) as set out in Article 9 of RPIESR ( 11 ) . Medium to long-term assessments are mainly used to identify adequacy concerns and to assess the need for capacity mechanisms whereas seasonal adequacy assessments are used to alert to short-term risks that might occur in the following six months that are likely to result in a significant deterioration of the electricity supply situation. In addition, regional coordination centres also carry out regional adequacy assessments on electricity transmission system operation. Those are very short-term adequacy assessments (from week-ahead to day-ahead) used in the context of system operation.

Before introducing capacity mechanisms, Member States should assess the regulatory distortions contributing to the related resource adequacy concern. Member States should be required to adopt measures to eliminate the identified distortions, and should adopt a timeline for their implementation. Capacity mechanisms should only be introduced to address the adequacy problems that cannot be solved through the removal of such distortions.

Member States intending to introduce capacity mechanisms should derive resource adequacy targets on the basis of a transparent and verifiable process. Member States should have the freedom to set their own desired level of security of supply.

Pursuant to Article 108 TFEU, the Commission has exclusive competence to assess the compatibility with the internal market of State aid measures which the Member States may put in place. That assessment is to be carried out on the basis of Article 107(3) TFEU and in accordance with the relevant provisions and guidelines which the Commission may adopt to that effect. This Regulation is without prejudice to the Commission's exclusive competence conferred by TFEU.

Capacity mechanisms that are in place should be reviewed in light of this Regulation.

Detailed rules for facilitating effective cross-border participation in capacity mechanisms should be laid down in this Regulation. Transmission system operators should facilitate the cross-border participation of interested producers in capacity mechanisms in other Member States. Therefore, they should calculate capacities up to which cross-border participation would be possible, should enable participation and should check availabilities. Regulatory authorities should enforce the cross-border rules in the Member States.

Capacity mechanisms should not result in overcompensation, while at the same time they should ensure security of supply. In that regard, capacity mechanisms other than strategic reserves should be constructed to ensure that the price paid for availability automatically tends to zero when the level of capacity which would be profitable on the energy market in the absence of a capacity mechanism is expected to be adequate to meet the level of capacity demanded.

To support Member States and regions facing social, industrial and economic challenges due to the energy transition, the Commission has set up a coal and carbon-intensive regions initiative. In that context, the Commission should assist Member States, including with targeted financial support to enable a ‘just transition’ in those regions, where available.

In view of the differences between national energy systems and the technical limitations of existing electricity networks, the best approach to achieving progress in market integration is often at a regional level. Regional cooperation between transmission system operators should thus be strengthened. In order to ensure efficient cooperation, a new regulatory framework should provide for stronger regional governance and regulatory oversight, including by strengthening ACER's decision-making power with respect to cross-border issues. It is possible that closer cooperation of Member States is also needed in crisis situations, to increase security of supply and to limit market distortions.

Coordination between transmission system operators at regional level has been formalised with the mandatory participation of transmission system operators in regional security coordinators. The regional coordination of transmission system operators should be further developed with an enhanced institutional framework via the establishment of regional coordination centres. The establishment of regional coordination centres should take into account existing or planned regional coordination initiatives and should support the increasingly integrated operation of electricity systems across the Union, thereby ensuring their efficient and secure performance. For that reason, it is necessary to ensure that the coordination of transmission system operators through regional coordination centres takes place across the Union. Where transmission system operators of a given region are not yet coordinated by an existing or a planned regional coordination centre, the transmission system operators in that region should establish or designate a regional coordination centre.

The geographical scope of regional coordination centres should allow them to contribute effectively to the coordination of the operations of transmission system operators across regions and should lead to enhanced system security and market efficiency. Regional coordination centres should have the flexibility to carry out their tasks in the region in the way which is best adapted to the nature of the individual tasks entrusted to them.

Regional coordination centres should carry out tasks where their regionalisation brings added value compared to tasks performed at national level. The tasks of regional coordination centres should cover the tasks carried out by regional security coordinators pursuant to the Commission GETSOR ( 12 ) as well as additional system operation, market operation and risk preparedness tasks. The tasks carried out by regional coordination centres should not include real-time operation of the electricity system.

In performing their tasks, regional coordination centres should contribute to the achievement of the 2030 and 2050 objectives set out in the climate and energy policy framework.

Regional coordination centres should primarily act in the interest of system and market operation of the region. Hence, regional coordination centres should be entrusted with the powers necessary to coordinate the actions to be taken by transmission system operators of the system operation region for certain functions and with an enhanced advisory role for the remaining functions.

The human, technical, physical and financial resources of regional coordination centres should not exceed what is strictly necessary for the fulfilment of their tasks.

The ENTSO for Electricity should ensure that the activities of regional coordination centres are coordinated across regional boundaries.

In order to increase efficiencies in the electricity distribution networks in the Union and to ensure close cooperation with transmission system operators and the ENTSO for Electricity, an entity of distribution system operators in the Union (EU DSO entity) should be established. The tasks of the EU DSO entity should be well-defined and its working method should ensure efficiency, transparency and representativeness among Union distribution system operators. The EU DSO entity should closely cooperate with the ENTSO for Electricity on the preparation and implementation of the network codes where applicable and should work on providing guidance on the integration inter alia of distributed generation and energy storage in distribution networks or other areas which relate to the management of distribution networks. The EU DSO entity should also take due account of the specificities inherent to distribution systems connected downstream with electricity systems on islands which are not connected with other electricity systems by means of interconnectors.

Increased cooperation and coordination among transmission system operators is required to create network codes for providing and managing effective and transparent access to the transmission networks across borders, and to ensure coordinated and sufficiently forward-looking planning and sound technical evolution of the transmission system in the Union, including the creation of interconnection capacities, with due regard to the environment. Those network codes should be in line with non-binding framework guidelines, which are developed by ACER. ACER should have a role in reviewing, based on matters of fact, draft network codes, including their compliance with those framework guidelines, and it should be enabled to recommend them for adoption by the Commission. ACER should assess proposed amendments to the network codes and it should be enabled to recommend them for adoption by the Commission. Transmission system operators should operate their networks in accordance with those network codes.

Experience with the development and adoption of network codes has shown that it is useful to streamline the development procedure by clarifying that ACER has the right to revise draft electricity network codes before submitting them to the Commission.

To ensure the smooth functioning of the internal market for electricity, provision should be made for procedures which allow the adoption of decisions and guidelines with regard, inter alia, to tarification and capacity allocation by the Commission whilst ensuring the involvement of regulatory authorities in that process, where appropriate through their association at Union level. Regulatory authorities, together with other relevant authorities in the Member States, have an important role to play in contributing to the proper functioning of the internal market for electricity.

All market participants have an interest in the work expected of the ENTSO for Electricity. An effective consultation process is therefore essential and existing structures that are set up to facilitate and streamline the consultation process, such as via regulatory authorities or ACER, should play an important role.

In order to ensure greater transparency regarding the entire electricity transmission network in the Union, the ENTSO for Electricity should draw up, publish and regularly update a non-binding Union-wide ten-year network development plan. Viable electricity transmission networks and necessary regional interconnections, relevant from a commercial or security of supply point of view, should be included in that network development plan.

Investments in major new infrastructure should be promoted strongly while ensuring the proper functioning of the internal market for electricity. In order to enhance the positive effect of exempted direct current interconnectors on competition and security of supply, market interest during the project-planning phase should be tested and congestion-management rules should be adopted. Where direct current interconnectors are located in the territory of more than one Member State, ACER should handle as a last resort the exemption request in order to take better account of its cross-border implications and to facilitate its administrative handling. Moreover, given the exceptional risk profile of constructing those exempt major infrastructure projects, undertakings with supply and production interests should be able to benefit from a temporary derogation from the full unbundling rules for the projects concerned. Exemptions granted under Regulation 2003/1228 ( 13 ) continue to apply until the scheduled expiry date as decided in the granted exemption decision. Offshore electricity infrastructure with dual functionality (so-called ‘offshore hybrid assets’) combining transport of offshore wind energy to shore and interconnectors, should also be eligible for exemption such as under the rules applicable to new direct current interconnectors. Where necessary, the regulatory framework should duly consider the specific situation of those assets to overcome barriers to the realisation of societally cost-efficient offshore hybrid assets.

To enhance trust in the market, its participants need to be sure that those engaging in abusive behaviour can be subject to effective, proportionate and dissuasive penalties. The competent authorities should be given the competence to investigate effectively allegations of market abuse. To that end, it is necessary that competent authorities have access to data that provides information on operational decisions made by suppliers. In the electricity market, many relevant decisions are made by the producers, which should keep information in relation to those decisions available to and easily accessible by the competent authorities for a set period. The competent authorities should, furthermore, regularly monitor whether the transmission system operators comply with the rules. Small producers with no real ability to distort the market should be exempt from that obligation.

The Member States and the competent authorities should be required to provide relevant information to the Commission. Such information should be treated confidentially by the Commission. Where necessary, the Commission should have an opportunity to request relevant information directly from undertakings concerned, provided that the competent authorities are informed.

Member States should lay down rules on penalties applicable to infringements of the provisions of this Regulation and ensure that they are implemented. Those penalties should be effective, proportionate and dissuasive.

Member States, the Energy Community Contracting Parties and other third countries which apply this Regulation or are part of the synchronous area of Continental Europe should closely cooperate on all matters concerning the development of an integrated electricity trading region and should take no measures that endanger the further integration of electricity markets or security of supply of Member States and Contracting Parties.

At the time of the adoption of Regulation 2009/714, only few rules for the internal market for electricity existed at Union level. Since then, the Union internal market has become more complex due to the fundamental change the markets are undergoing in particular regarding deployment of variable renewable electricity production. The network codes and guidelines have therefore become extensive and comprehensive and encompass both technical and general issues.

In order to ensure the minimum degree of harmonisation required for effective market functioning, the power to adopt acts in accordance with Article 290 of TFEU should be delegated to the Commission in respect of non-essential elements of certain specific areas which are fundamental for market integration. Those acts should include the adoption and amendment of certain network codes and guidelines where they supplement this Regulation, the regional cooperation of transmission system operators and regulatory authorities, financial compensations between transmission system operators, as well as the application of exemption provisions for new interconnectors. It is of particular importance that the Commission carry out appropriate consultations during its preparatory work, including at expert level, and that those consultations be conducted in accordance with the principles laid down in the Interinstitutional Agreement of 13 April 2016 ( 14 ) on Better Law-Making. In particular, to ensure equal participation in the preparation of delegated acts, the European Parliament and the Council receive all documents at the same time as Member States' experts, and their experts systematically have access to meetings of Commission expert groups dealing with the preparation of delegated acts.

In order to ensure uniform conditions for the implementation of this Regulation, implementing powers in accordance with Article 291 of TFEU should be conferred on the Commission. Those powers should be exercised in accordance with Regulation 2011/182 ( 15 ) . The examination procedure should be used for the adoption of those implementing acts.

Since the objective of this Regulation, namely the provision of a harmonised framework for cross-border exchanges of electricity, cannot be sufficiently achieved by the Member States but can rather, by reason of its scale and effects, be better achieved at Union level, the Union may adopt measures, in accordance with the principle of subsidiarity, as set out in Article 5 of the Treaty on European Union. In accordance with the principle of proportionality, as set out in that Article, this Regulation does not go beyond what is necessary in order to achieve that objective.

For reasons of coherence and legal certainty, no provision in this Regulation should prevent the application of the derogations emerging from Article 66 of CRIMED,