ENTSO-E has sought to involve stakeholders at each stage of the NC CACM drafting process. A stakeholder group, made up of pan-European associations, has met throughout the code development process and provided advice and support. Open workshops have also been held, both in Brussels and facilitated by national TSOs, to allow other interested parties to contribute. All parties were invited to respond to the public consultation on the draft NC CACM (over 2000 comments were received) and numerous bilateral meetings with interested parties were also held.

Recording the large volume of comments received during consultation was done using a specific template, which allowed comments on a particular code article to be considered and then validated and discussed by the various drafting teams. A small number of submissions went beyond an individual code article and resulted in a review of the code structure. These comments, which were focussed on issues such as consultation and approvals, led to the inclusion of common articles at the beginning of the network code to clarify these points.

There are a number of projects in place across Europe today which have coupled spot markets or are trialling intraday arrangements. These projects have provided useful input for the NC CACM development process. They will continue to play a key role in expanding the European market in the period until the code is in place, and beyond. It should be noted that the code does not seek to ‘reinvent the wheel’ and it is expected that progress made to date will be facilitated by the code and built upon.

The ACER framework guideline on the NC CACM covers capacity calculation, day ahead markets, intraday markets and forward markets. However, the European Commission specifically requested that forward markets be dealt with at a later stage. This was to enable the completion of a consultancy study on the subject. ENTSO-E is currently drafting the Forward Capacity Allocation (FCA) code and expects to submit it to ACER by the end of September 2013. The NC FCA code will interface with many of the general provisions of the CACM code, as well as with capacity calculation rules. In drafting the NC FCA, ENTSO-E will ensure consistency in the areas where the two codes overlap, while including forward specific provisions where necessary.

Balancing was not part of the EU Target Model but is an important aspect of creating a well-functioning pan-European market. ENTSO-E is currently drafting the Network Code on Electricity Balancing and is expected to submit it to ACER by December 2013. The main interactions relate to capacity calculation (and reservation of capacity for balancing services) and to the design of intraday markets, which are chronologically and functionally contiguous to the balancing markets.

Bidding zones are network areas within which market participants can offer energy – in the day ahead, intraday and longer-term market time frames – without having to acquire transmission capacity to conclude their trades. TSOs manage the transmission network to ensure that there is no congestion within each bidding zone, so that market participants can trade with each other without constraints.

Bidding zones are important because they provide transparency to market participants on network congestions and associated costs, while they allow TSOs to limit commercial exchanges between bidding zones when these can create network security issues. Depending on the size and configuration of bidding zones, the grid operation by TSOs can be more or less complex and costly, while electricity markets’ efficiency, liquidity and concentration can also be affected .

A bidding zone border does not necessarily need to coincide with a national border. It is possible to have several zones within a country or one zone with several countries inside. Until now, bidding zones have usually been aligned with Member State borders. However, there are some countries in Europe, such as Norway, Sweden and Italy, where several bidding zones currently exist. On the other hand, Germany and Austria constitute one single bidding zone.

Setting bidding zones requires a set of careful trade-offs to be made. On one hand, it is important to consider the current and future status of the transmission network within and between bidding areas: system security constraints, structural bottlenecks, typical power flows, etc. In fact, an ideal bidding zone configuration should enhance the TSOs’ ability to ensure operational security, taking into account the (present and future) capabilities of the transmission network in relation to the (present and expected) physical and commercial electricity flows.

On the other hand, market aspects also have to be considered carefully. For instance, the larger the bidding zones the greater the liquidity (and thus competition among market participants) within that bidding zone. At the same time, costs sustained by TSOs for keeping the network uncongested within one bidding zone also depend on the size and configuration of all the related bidding zones.

Lastly, changes to bidding zone configurations create costs for market participants to adapt their processes and strategies. A certain degree of stability over time may be desirable for this reason.

Regulators approve bidding zone configurations, which are proposed by TSOs after having consulted stakeholders.

ACER’s framework guidelines state that zones shall be robust over time. As no further guidance has been given by regulators as to how long a bidding zone should remain as is, or the regulatory nature of a choice to change a bidding zone, ENTSO-E has kept the initial wording of CACM framework guidance in the draft CACM network code. The expected duration of the zones will be subject to further guidance from regulators, for instance when they review bidding zone configurations or approve an amended bidding zone configuration. Stakeholders will be consulted on such proposals, including on the time needed to prepare before changing the zones.

The efficiency of the current bidding zone configuration is assessed every two years. The assessment consists of a technical report prepared by TSOs and an evaluation of market structure and possible market power issues prepared by regulators and ACER. The analysis included in the technical report is based on data on re-dispatching/countertrading costs, adverse effects of internal transactions on other bidding zones and structural congestions. Based on these assessments, the regulators and ACER evaluate if further measures on a bidding zone configuration are to be taken.

The regional process as described in NC CACM for reviewing bidding zone configurations covers all kinds of bidding zones in Europe. However, there are currently two countries, Italy and Norway, where the process to review bidding zone configurations may require specific attention. In Italy, some bidding zones may have negligible or no impact on neighbouring grids and application of a regional process may not introduce any added value. In Norway, due to the hydro-generation situation, risks to security of supply may be increased and there is a need to establish a temporary new bidding zone configuration in a short time frame. However, if this specific process were to be applied, it would be notified and justified to neighbouring TSOs and NRAs.

The coordinated net transfer capacity (NTC) method is based on the principle of pre-defining a certain level of maximum commercial exchange capabilities for each border between bidding zones. The flow-based method, instead of calculating aggregated transfer capabilities per bidding zone, determines physical margins on each “critical grid element” (transmission lines which are likely to become congested) and their influencing factors (how each critical grid element is affected or affects another critical grid element). This normally allows an increase in cross-border transmission capacity where it is most needed because it more accurately reflects the actual situation on the grid.

The most effective way to calculate capacity depends on the characteristics of a particular market and neither methodology fits all markets perfectly. Generally speaking, the flow based method is preferable in networks with lots of lines impacting on each other (called a meshed network), while NTC-based capacity calculation is suitable for more radial networks. Overall, the suitable method needs to be determined based on the structure and topology of the grid in question.

A number of requirements included in the code are yet to be fully tested in practice, including the flow-based methodology for capacity allocation. This means that they might need to be modified and updated based on experience. The approach implemented in the code will avoid prescribing requirements that could quickly become obsolete, and will ensure the relevance of the code in future years.

Merging of individual grid models from each TSO to form a common grid model (CGM) takes place at the European level. Coordination and calculation of capacities is performed on a regional level. Data collection from generators and loads, the building of individual grid models and validation of calculated capacities takes place at the national or TSO level.

TSOs will establish arrangements for the European merging function. This may include establishing a new common entity or enlarging the responsibilities of existing TSO entities. TSOs will establish arrangements for the regional capacity calculation function at a regional level. The arrangements will define the responsibilities and organisational issues for capacity calculation at a regional level.

An individual grid model is a representation of the network of a particular TSO. It is produced in a standard way so that it can become part of a Europe wide network model through a process called merging. This common grid model is the basis for assessing security and calculating capacity across Europe.

Compatibility is ensured using a common net position rule (i.e. a bidding zone will be in surplus, deficit or balanced as regards to power balance). All TSOs have to agree on a rule to define net positions for their individual grid models. The sum of the European net positions will always be zero after imports/exports from third countries are taken into account.

Having a unique Europe- wide approach to capacity calculation at the date when the network code enters into force is not feasible. Regional capacity calculation is a second best solution but a step towards the final goal. There is a clear longer-term target to merge flow-based capacity calculation regions into a single region and/or enlarge capacity calculation regions over time.

A bidding zone border can only belong to one capacity calculation region (and this is not the case with the current European regional initiatives (ERI), with for example, the German-French border belonging to both the Central Western Europe (CWE) Region and the Central Southern European (CSE) Region). This property is required because only one coordinated capacity calculator should compute the capacity on each bidding zone border. Initial capacity calculation regions will be based on regions defined in Congestion Management Guidelines annexed to Regulation (EC) 714/2009, but without the overlapping of regions to ensure coordination in capacity calculation.

The changeover to the FB method will occur gradually when certain conditions are fulfilled. The first regions to adopt the FB method will be the Continental European networks. Other regions will follow when the criteria to use a co-ordinated NTC approach are no longer applicable. However, it is possible that some regions will not apply FB at all. Such networks are less meshed, e.g. in the case of interconnections of or between large peninsulas or islands in Europe.

General dispatch information helps TSOs evaluate which generation units are forecast to be in operation for every market time unit in the day ahead and intraday markets. TSOs need information to prepare their individual grid model and generation shift keys (GSKs) for capacity calculation. TSOs use GSKs to evaluate injections and off-takes from the grid in capacity calculation. GSKs will be applied in order to translate generation patterns into power flows across bidding zone borders, and calculate maximum allowed power flows.

The estimation of GSKs is done by TSOs with information related to generation dispatch relevant for capacity calculation (mostly extra high voltage grids).This information is needed to improve the accuracy of capacity calculation compared to the present situation, where assumptions for individual grid models and GSKs are made by TSOs.

When a TSO cannot deliver their capacity calculation input for technical reasons, the overall European capacity calculation process should not be compromised. TSOs will thus agree on a fallback procedure for such situations, which would remain exceptional. Such fallback solutions will be developed as part of the capacity calculation methodology and will be under regulatory approval

Intraday markets take place during the day of operation, as opposed to day ahead markets where trades are concluded the day before the physical delivery of the electricity. Intraday markets are an important tool for market participants to adjust their positions by buying/selling electricity in deficit/excess, as their needs may change after the closure of the day ahead market and before real time operations. This might occur because a power plant may generate less than planned due to a fault, or demand from customers may be higher due to colder weather than expected.

Continuous trading is a type of negotiation mechanism used by some existing intraday platforms. It constitutes the key feature of the European intraday Target Model. Market participants are able to access bids and offers from other market participants in a continuous manner, normally up to one hour before real time. Bids and offers can be selected as soon as they become available. This is commonly called “Point-and-Click”.

In Iberia, Italy and Ireland, current intraday markets are based on auctions rather than continuous trading. This means that bids and offers from market participants are collected during a certain period (e.g. 4 hours before delivery in the Iberian market) and the most competitive are matched together after the auction closes. The European Target Model, translated first in the framework guidelines and then in the NC CACM, allows regional auctions to complement the continuous trading solution in certain cases, as long as these auctions have adequate bidding deadlines to be coordinated with, and linked to, the pan-European Target Model. At the moment, it is not clear how existing auctions may need to be adapted to be linked with the European continuous trading mechanism. The NC CACM makes provisions for existing auctions to find their own solutions in order to integrate with continuous trading, while only requiring the avoidance of adverse impacts on liquidity or discrimination against market participants.

The intraday market opens after the closure of the day ahead market and the subsequent capacity calculations made to assess the level of cross-zonal capacity available in the intraday timeframe. Today, the intraday cross-zonal opening time is harmonised at a regional level.

The intraday market closure time depends on the length of the operational process needed by each system operator before the delivery of electricity to the buyer. Today, the intraday closure time is harmonised to a certain extent at the regional level, but not across Europe. The NC CACM requires the introduction of a single harmonised closure time which should be at the earliest one hour before real time.

Renewable power producers, and in particular wind generators, cannot plan with certainty the amount of electricity that they will generate each day, as this depends on the location and speed of wind over time, which can only be approximately forecast. Such forecasts become very reliable only two to three hours before real time. The intraday market allows renewable producers to adjust their positions close to real time and reduce their imbalance (difference between scheduled production and real production), and related costs.

Capacity may be priced when the time of receipt of the request or order is not sufficient to allocate capacity efficiently. This can happen when the intraday market opens, since orders can already be accumulated in the trading platform when capacity is made available; or when orders have accumulated in the platform due to the absence of cross-zonal capacity and new capacity is made available during the day.

Market operators are in charge of operating local trading platforms, collecting orders from market participants, matching trades and publishing prices. Some countries are still creating power exchanges, which will normally fulfil the role of running the intraday market.

Market coupling is a method for integrating markets which allows two or more wholesale electricity market areas (normally corresponding to a national territory) to be merged into a single market area, as long as there is sufficient transmission capacity available between those markets. With market coupling, the daily cross-border transmission capacity between the various areas is not sold separately (explicitly auctioned) among the market parties, but is implicitly made available via energy transactions on power exchanges on either side of the border (hence the term implicit auction). Buyers and sellers on a power exchange can match their bids and offers submitted via another power exchange as if it was one single market area, without the need to separately acquire the corresponding transmission capacity necessary to transport electricity between the two (or more) market areas.

The day ahead market is the wholesale market in which parties (generators, traders, and end users) can submit bids and offers to buy or sell energy for delivery on the following day. Day ahead markets are at the core of European electricity markets. Most physical trade of electricity takes place on day ahead markets.

Day ahead markets can be run by organised markets such as power exchanges, where a central trading platform collects bids and offers from market participants, and acts as a central counterparty (i.e. the power exchange is the intermediary between every buyer and seller). They can also be not centrally organised (hence not run by any intermediary or trading venue operator) but based on bilateral trades of electricity between buyers and sellers. These transactions, concluded outside of power exchanges, are part of what is commonly known as the “over the counter (OTC)” market.

Power exchanges collect bids and offers from buyers and sellers, match them and calculate prices. TSOs calculate and update capacities that are available for trading and schedule electricity flows on their transmission network resulting from day ahead market trades.

In some countries such as Italy and Spain, power exchanges are a monopoly function regulated by national law. In others, power exchanges can offer their services in competition with one another.

Due to the relative difficulties in forecasting wind, renewable generators need to be able to adapt their positions as close as possible to real time. To do this, there needs to be lots of buyers and sellers in the intraday market (known as liquidity). The NC CACM facilitates the creation of this market by bringing together buyers and sellers from all over Europe, thus increasing the trading possibilities. Moreover, the code will introduce an intraday market gate closure (the deadline for concluding trades) closer to real time, i.e. only one hour before real time. This should reduce risks of imbalances for renewable generators and lower their costs.

Coupling markets can provide efficiency benefits in both the short- and long-term. Implicit auctions make more efficient use of available capacity and mean that power flows on the basis of price differences. In the longer-term, these larger markets and increased liquidity can create more robust price references and more certainty around market design, which can reduce risk for investors in generation or load.

The CACM code should facilitate greater competition in generation and supply by expanding the size of markets and reducing concentration. The market coupling process will facilitate wholesale electricity price convergence, meaning that prices will rise in some places and fall in others. Overall, this process should deliver economic benefits for Europe and use the assets we have more efficiently.

Existing transmission capacity will be calculated in an optimised way due to greater coordination, and allocated in a more efficient way. The integration of day ahead and intraday markets will allow buyers and sellers to match their bids and offers over a much larger market area, thus increasing trading opportunities.

By reducing uncertainty and increasing liquidity in wholesale markets, the code will create greater market price reliability and stability, thus ensuring greater attractiveness for potential investors.

European electricity markets have progressively developed and integrated since the liberalisation introduced by the First Energy Package in 1996. There Full integration is on track but the challenges ahead are numerous and complex.

Integration of electricity markets is well advanced, especially in the day ahead period, where a number of national markets are coupled at the regional level. Initiatives have been undertaken in Central-Western Europe (France, Germany, Benelux); the Nordic region (Denmark, Sweden, Norway, Finland, Estonia); the Iberian Peninsula; Czech Republic, Slovakia and Hungary; Italy and Slovenia). At the level of intraday markets, with the exception of the Nordic regional market, integration is less advanced, with cross-border trading platforms mainly developed bilaterally between Member States.

Single rules are needed to allow market participants to trade seamlessly across all of Europe as if it was one single electricity market. Without harmonised rules, transmission capacities, prices and flows cannot be uniformly calculated since every national market applies their own specific rules. The result is a more complex and less efficient system.

The NC CACM takes account of, and builds on, past and ongoing regional market integration projects in capacity calculation, day ahead market coupling and cross-border intraday markets. The code accommodates current regional projects as much as possible while ensuring their convergence towards the Target Model and full integration into one single European market.

The NC CACM (Network Code for Capacity Allocation and Congestion Management) is a set of rules which will introduce a single approach to cross-border electricity trading in Europe. This is based on the so-called electricity “Target Model”, which proposes a market design for each timeframe (i.e. forward markets, day ahead and intraday markets) and a coordinated approach to capacity calculation. Consensus around this model was achieved through extensive discussions since 2008 between European policy makers and stakeholders such as EC, Regulators, ETSO, Europex, EURELECTRIC, and EFET. Once adopted as law, the NC CACM will be applied across Europe.

The NC CACM implements an electricity market design, which has been developed and refined over a period of over five years and has widespread support across Europe. It has four basic elements:

• A day ahead market in which cross border transmission capacity and energy are auctioned together. Energy prices across borders only differ if there is congestion on transmission networks.
• Intraday markets, which allow market actors to trade close to real time, allowing them to manage risks and respond to changing conditions such as varying weather forecasts.
• A coordinated approach to transmission capacity calculation including the innovative “flow-based” method; with the objective of making the best use of the power lines which interconnect Europe.
• The definition of a series of bidding zones based on transparent criteria, reflecting both transmission congestion and the need to promote competition while respecting system security.

Together these elements will create a pan-European electricity market for the first time.

The objective of the NC CACM is to create the largest and most competitive electricity market in the world. The code sets out rules that will transition from the current system, in which there are various sets of different rules in different countries or regions, to a single set of market rules applied across Europe. It will increase cross-border competition, enhance stability, reduce risk and deliver substantial efficiency savings to consumers, estimated at €5 billion annually by the European Commission.

The NC CACM, when adopted by the European Commission, will have the same legal standing as European regulations and be directly applicable in all Member States. Network codes only regulate cross-border aspects of national electricity markets, so national electricity rules or grid codes with no cross-border dimension will not be affected.