The Italian Power Exchange

Transcription

1 Industry Report The Italian Power Exchange Research Department May 2004

2 The Italian Power Exchange Contents Executive Summary Power exchange models The Power Exchange within the Italian electricity market How the markets work: electricity market regulations and conditions governing dispatch services Electricity market regulations Indices for monitoring the market and measures to promote competition Bilateral contracts and contracts for difference signed by the Single Buyer The first trading results on the Italian Power Exchange The international experience: the most significant results Physical power exchanges Financial power exchanges in Europe Nordpool...42 Appendix 1: The reserve market and transitional payment system for capacity in Appendix 2: Load profiling and resolution 118/ A.1 Summary of the various methods...47 A.2 The Italian option: AEEG resolution 118/ May 2004 By: Luigi Napolano Research Department Tel Appendix 2: load profiling and resolution 118/03 by the Osservatorio Energia department of REF, whom we would like to thank for their valuable contribution With thanks to Alberto Capuano Structured Finance Banca Intesa for his cooperation in preparing the document 1

3 Industry Report May

4 The Italian Power Exchange Executive Summary On 1 April this year, five years after the Bersani decree came into effect, the Italian Power Exchange (IPEX) was launched. Since it is seen by many as epitomising the process of electricity market liberalisation, expectations are high: in theory, the IPEX will create competition between producers, provide end customers with a trading area in which they can freely choose their supplier, generate incentives to create an electricity derivatives market and eventually allow electricity prices to fall in Italy. This report will take a closer look at the new system, with a view to gauging how far these expectations can realistically be met. Our main conclusion is hardly revolutionary: wherever they are, and however they are run, power exchanges merely reflect the structure of the underlying market. In other words, price levels, trends and volatility depend primarily on the structure and efficiency of a country s power generation system; secondly, they depend on the market structure ie the number of producers, traders and wholesalers operating on the market and to what degree supply is concentrated. Lagging way behind is the way the exchange itself operates, and even then it only has a very slight influence on the market s efficiency. Power exchanges can therefore be seen as holding up a mirror to the system rather than changing it. This was clearly highlighted in the UK, in the days of the old England and Wales Pool. In the ten years of the E&W Pool s existence, the wholesale market price remained broadly stable, or even rose 1. At that time, the UK s power generation system was antiquated, based on coal-fired and nuclear plants, and there were only two operators, National Power and Powergen, formed when the government split up the old public monopoly, plus the then state-owned British Energy, which was given the country s nuclear plants. The regulator stepped in on several occasions to stop market manipulation, and even forced the companies to sell off assets to encourage the arrival of new entrants, without however making a big difference to wholesale prices. The incentive to collude in a market consisting of just a few operators was just too strong. So does the UK experience mean that power exchanges are useless? Not at all. The existence of a regulated market with clear and transparent rules for all operators, the easing of the counterparty risk and the liquidity to trading that such a market brings, are all factors that allow a benchmark price to be formed for the system as a whole. This price has a number of functions, since it: is considered by investors in their spending decisions; is used to set tariffs for end customers; can be used by financial operators to build indices and develop derivative products to hedge price risks. Of course, for this to happen, the market needs to reach a certain size, and must be considered credible by operators. If it succeeds in doing this, then its impact can be significant, but only in the medium to long term. The UK system again demonstrates the practical impact of power exchanges. During the lifetime of the E&W Pool, there was a flourishing OTC market of mediumterm supply contracts (generally lasting up to two years) ie fixed-price forward sale contracts and hedging contracts such as contracts for difference, in which the producer pays the buyer the difference between the 1 Consumer prices came down mainly via regulatory intervention on transmission and distribution tariffs 3

5 Industry Report May 2004 market price and the price set out in the contract, where this is lower, and vice versa if the market price is lower than the contract price. Even more importantly, foreign providers wishing to enter the UK market could refer to a series of historical market prices, which was stable and credible enough to be used as a basis for investment decisions. This encouraged investment in combined cycle gas turbine (CCGT) plants, which were more efficient than existing plants and thus generated higher margins than those produced by the Pool. In the space of only a few years, the UK electricity system was transformed, becoming more efficient and sophisticated both technically (since the country s power plants increased their yields), and in terms of the types of contract used in trading. When the E&W Pool was abolished in April 2000, the market continued to operate efficiently: volumes of bilateral and swap contracts which by now had become well established increased further. The investments made previously led to a situation of overcapacity, which immediately caused prices to plummet. Although this caused severe problems for a number of companies, it was highly beneficial to consumers. Overall, therefore, the existence of power exchange facilitates the liberalisation process and makes it more fluid, to the extent that it makes prices and how they are formed more transparent. It does not change them, however: it is investment, demand, and the degree of concentration of the market that change price trends, rather than the other way around. Moreover, the characteristics of electricity as a commodity mean that even in the most efficient and competitive system, some operations will remain highly complex. The fact that it is impossible to store electricity or continuously balance supply and demand (leading to blackouts, which however are not socially acceptable, since electricity is an essential public service) leads to volatility in prices, which can be as much as ten or twenty times higher than those of other commodities. While the historical volatility of oil, for example, stands at 30-40%, and that of natural gas is around 50%, price volatility on the most efficient power exchanges can easily be as much as %, with peaks standing at a factor of more than 12 at times of particular pressure. The characteristics of the underlying element make the basis risk on futures extremely high, and options very expensive: this explains why swaps in the form of CFDs (contracts for differences) have been so successful. Operating on the power exchange and related derivatives markets is therefore not an easy task, and those operators with a physical back-up (ie production plants) are at a clear advantage, in that they can limit the risk of unbalanced supply or demand positions; however, other traders and financial institutions can operate successfully if they have an in-depth knowledge of the dynamics of the main electricity market. 2 As a result, we should not expect miracles in the early days of the Italian power exchange, since Italy s production industry is still affected by a number of technical constraints and by a high degree of concentration in supply. 2 Note that unlike markets for other commodities, such as oil, the electricity markets have strong local characteristics, in that they are inevitably linked to a physical network. Going beyond national boundaries is only possible where there is physical integration between markets, ie where the interconnections between different countries have been strengthened. In some senses, this is already the reality in Nordic countries and continental Europe. 4

6 The Italian Power Exchange Only as new plants in the process of receiving authorisation or under construction (some by new operators) come on stream will consumer prices be able to fall, although they will never drop as low as they are in other European countries that use more coal-fired and nuclear plants. As for financial instruments, we expect bilateral contracts and CFDs to continue to be preferred by operators. However, the liquidity and degree of transparency that the IPEX will give the market should provide operators with the information they need to decide where to invest in production and the grid, and what action to take to avoid market manipulation. These issues are discussed in more detail below. In the first section, we classify power exchanges, dividing them into two macro-categories: i) the physical exchanges, which includes several exchanges in the US exchanges, one in Spain and one in Italy in the sense that they provide operators with information on plant scheduling and management, and reflect technical management methods in market mechanisms; and ii) the financial power exchanges in Germany, France, the Netherlands and the UK, which do not provide information on scheduling or technical issues, but are solely markets intended to increase the liquidity and transparency of the type of contracts most often used by suppliers and purchasers. The two types of exchange are the expression of very different economic and energy policies: on the one hand, those that see the exchanges as an instrument to facilitate market liberalisation, while on the other, those that from a certain viewpoint consider liberalisation as a given and afford private operators the freedom to structure a regulated market independently, if they believe that this instrument can facilitate trading and represent an efficient method for generating profit. Clearly, the aims of the two types of power exchange are very different: as a result, any evaluation of their effectiveness must be based on different parameters. In light of the results set out in the first section, the second section puts the Italian power exchange in the context of the market and regulatory environment established by Sistema Italia The regulations are then set out, together with the results of the first month of trading, and we conclude that the Italian power exchange will be unable to lower prices in the short term, given the market conditions, but that it may be a useful way of bringing operational aspects closer to the trading process, with benchmark prices eventually being established, with the essential functions described above. In section three, we summarise the main experiences of the US and Europe, with a brief description of the key features and results, based on the framework set out in section one. There are two appendices at the end of the report. The first describes the transitional tariff regulations for 2004 and sets out the guidelines for the capacity market in the future. The second explains the concept of load profiling by the Osservatorio Energia department of the REF (finance and economics research institute) in Milan one of the most important technical measures that is meant to ensure that the application of new scheduling and dispatch methods introduced with the launch of the power exchange does not cause operational or financial imbalances in relation to the installation of meters for Italian users. 5

7 Industry Report May Power exchange models What is a power exchange and what is its purpose? These are fundamental questions, as all power exchanges in liberalised markets are set up differently according to the purpose for which they are created. In the widest sense of the term, power exchanges are regulated, centralised markets where operators trade electricity purchase and sale contracts. These contracts may be physical or financial: from this distinction arises the different setup of each market. Power exchanges based on the trading of physical contracts are intended to set injection and withdrawal schedules on the electricity grid in a decentralised way (ie through purchase and sale bids submitted by operators). In other words, they use the market to define the unit commitment the schedule of generating plants. This is usually known as the day ahead market, in which producers make their electricity sale offers and where they are chosen to generate electricity based on an ascending order of price (merit order), until demand is completely satisfied. Demand may be set centrally by an independent system operator (ISO), or noncentrally by demand-side operators. Physical exchanges that use market scheduling criteria to select plants include the old UK Power Pool, Spain s OMEL, NordPool, which groups Nordic countries, and Italy s IPEX, as well as numerous exchanges in the US. Note that not necessarily all supply and demand move through the power exchange. Operators may be allowed to sell their electricity on the exchange which acts as a demand-side aggregator or to form agreements privately among themselves, through bilateral or forward contracts. Institutional operators ie the transmission grid operator or the power exchange operator depending on the regulatory system are then responsible for reconciling electricity flows resulting from the merit order and the bilateral contracts so as to ensure that electricity supply and demand are always balanced. Only the old England & Wales Power Pool and (to all intents and purposes) the OMEL are compulsory exchanges. The balance between supply and demand on this type of market is usually determined on an hourly basis, as this reflects the scheduling requirements of the electricity system. The price that results from this balance is known as the system marginal price (SMP), as it is fixed by the last unit required to generate power. This may be a single national price or the market may be divided according to grid flows and bottlenecks. This is known as dynamic market splitting; the market may be split into zones when bottlenecks emerge between the different areas served, and in this case, each area sets its own supply/demand balance and its own zonal price. A number of exchanges operate as zonal markets, including NordPool, the PJM, NePool and the NYPP in the US and the IPEX in Italy. OMEL is the largest market to use the SMP mechanism, apart from the now defunct England & Wales Power Pool, the first ever power exchange. Additional markets may be set up alongside the day ahead market on physical power exchanges, and are used to adjust the unit commitment set on the day ahead market to the real-time dispatch of generating plants 3. Intraday markets, operating in one or more sessions, may thus be set up to allow operators to adjust supply as data on demand becomes more precise. Furthermore, other markets may be used to supply the dispatcher with the 3 As electricity cannot be stored, a central operator must manage grid flows in such a way as to constantly match demand with supply in real time. This dispatch role is usually filled by the national grid operator, in Italy the GRTN. 6

8 The Italian Power Exchange resources necessary to adjust the system (electricity reserves, resolving congestion, balancing etc) in real time. On these markets, operators make offers of their availability to supply these services. Based on the information at its disposal, if the dispatcher needs the services, it pays the operators for their availability based on the offers submitted, and its decision is final. This price rule is known as pay-as-bid. As we will see, the IPEX is not the only exchange to make use of adjustment markets and markets providing system services. The OMEL and the US exchanges are also structured this way to some extent. Even the UK s current system (NETA), which is based solely on bilateral agreements between operators, has a centralised dispatch market managed by the UK s national grid operator. Power exchanges that act as centralised markets for exclusively financial contracts have completely different structures and objectives. Such power exchanges do not reflect the operating schedules of power plants, but merely serve as a centralised trading platform, providing counterparty guarantees, contractual standardisation and transparency of transactions and prices. In other words, contract management and the physical management of electricity flows are separate and move independently of each other. These types of exchange are not necessarily created by the authorities: they may also be the result of independent initiatives by private operators. Operators on these exchanges usually trade products that replicate the underlying physical electricity sale contracts, such as baseload contracts, (for continuous supply over the whole day) or peakload (for supplies in peak hours only), hourly spot contracts, and forward contracts for weekly supplies. They also trade futures contracts (monthly, seasonal and annual) and options based on the indices constructed on the simple contracts described above. This type of power exchange model is currently the most widespread in Europe and includes Germany s EEX, the APX in the Netherlands, France s Powernext market and the UKPX. These markets usually handle lower volumes of electricity than physical exchanges, but prices are more volatile and are better used to structure derivative contracts to hedge against price risk. Note however that the main derivative instrument used to hedge against price risk is a contract typically traded on over the counter (OTC) systems, a swap often called a contract for difference (CFD) on the electricity market. Operators use this contract to hedge against forward operations in which the sale of electricity is agreed at a fixed price; usually, the producer pays the consumer the difference between the market benchmark price and the price set out in the contract, where this is lower, and vice versa if the market price is lower than the contract price. Clearly, it is crucial to set out in the contract the indices to be used in settling these differences. Although swaps and CFDs do not usually form part of a regulated market, power exchanges may still have a role, as they often serve as a clearing house in OTC dealing. This is the case with NordPool, where clearing is by far the main source of volumes and revenues for all products. As clearly illustrated above, these two macro-types of power exchanges may be set up differently or even combined. For example, NordPool, a noncompulsory exchange, uses market splitting to set a merit order and therefore shares some of the features of a physical exchange, but it also operates a futures and options exchange, and acts as a clearing house for OTC swap trading. In the zonal physical markets of the US, operators trade in derivatives that hedge the fluctuations in the price of transmission rights, 7

9 Industry Report May 2004 that is the price spread between two zones that represents the cost of keeping an interconnection line in use between the two areas. Some electricity systems have capacity markets, which establish short/mediumterm reserve capacity requirements in order to maintain the reserve margin. Operators on these markets are paid for their commitment to supply this power (which implies the construction of new plants for the supply of longterm capacity). The table below shows the main features of the largest power exchanges currently operating in Europe and the US, including the IPEX. Fig. 1 Main features of the largest power exchanges in Europe and the US Unit Comm itment Compulsory Hourly market SMP/ Zonal Other products (baseload Intraday mkts Capacity mkt Mkt serv. disp. Deriv mkt Clearing House OTC mkt etc) E&WPowerPool Yes Yes Yes SMP No No No No No No UKPX No No Yes SMP Yes No No No No Yes OMEL Yes No* Yes SMP No Yes No Yes No No PowerNext No No Yes SMP Yes No No No Yes No EEX No No Yes SMP Yes No No No Yes Yes NordPool Yes No Yes Zonal No No No No Yes Yes APX No No Yes SMP Yes No No No No No IPEX Yes No Yes Zonal No Yes Yes** Yes Yes*** No PJM Yes No Yes Zonal No No Yes Yes Yes**** No NYPool Yes No Yes Zonal No No Yes Yes Yes**** No NePool Yes No Yes Zonal No No Yes Yes Yes**** No * The OMEL may be considered a practically compulsory exchange, given the incentives that Spanish regulation offers parties operating on this market ** Expected to begin in 2005 *** To be set up in the future **** The only derivatives traded are those relating to transmission rights (ie the price spread between two zones). These products hedge against the risk of congestion costs Source: Banca Intesa The choice of which exchange model to adopt is therefore chiefly based on energy policy decisions agreed by legislators and operators and the requirements that the exchange is expected to meet. The creation of a power exchange may therefore be a fundamental step in the liberalisation process, insofar as prices representative of the system are established through a transparent and competitive process. A power exchange is therefore able to accomplish the task required by all regulated markets: that is to provide a benchmark price for operators that can be used in OTC trades, to value investment projects and to structure derivative contracts. Power exchanges should not however be expected to provide answers to problems such as high prices, grid congestion or blackouts. They reflect the underlying system, and at most may shed light on its various merits and defects, but only long-term investment can improve the state of the system itself. 8

10 The Italian Power Exchange 2. The Power Exchange within the Italian electricity market Electricity market operator the GME is responsible for the structure and management of the power exchange, which is only one of the institutions that make up Italy s electricity system. This must bring together: The industrial structure of the Italian electricity system, which is largely based on low-cost imports from central Europe. Italy s thermoelectric system is currently being restructured and upgraded, while the transmission system is undergoing modifications in line with the reconfiguration of the generating system; The system inherited from before liberalisation (for example, the system of priority dispatch and incentive tariffs reserved for plants fuelled by renewable sources and cogeneration plants covered by the CIP6 provision); The numerous measures that have marked the liberalisation process. The process began with the law implementing European directive 92/96 (also known as the Bersani decree), which came into force on 1 April 1999, and was then progressively incorporated and amended following industry ministry resolutions. These established the framework that was then introduced by power market regulator the AEEG, in accordance with the technical requirements outlined by transmission grid operator, the GRTN. The GME established the market model, subject to approval from the industry ministry following consultation with the AEEG, and was responsible for managing it in agreement with the GRTN. Lastly, the Single Buyer (AU) was set up to guarantee supply to the franchised market, that is parties not yet free to choose their own supplier, which today represent 40-45% of overall demand on the Italian system 4. Fig. 2 Institutions in the Italian electricity market MAP INDUSTRY MINISTRY The ministry responsible for energy policy 100% GRTN NATIONAL TRANS -MISSION GRID OPERATOR (ISO) Manages the National grid AEEG ELECTRICITY & GAS MARKET REGULATOR Sets tariffs and regulates the market based on ind ustry ministry guide lines Source: Banca Intesa 100% 100% AU SOLE BUYER Guarantees supply for franchised market GME ELECTRICITY MARKET OPERATOR Responsible for creating & running exchange (IPEX) 4 Demand is expected to be completely liberalised by July

11 Industry Report May 2004 Placing the power exchange within the structure of the Italian electricity market may be of use, and the document published by the industry ministry in July 2003 may be a good starting point. This document established the framework for Italy s market system, and issued guidelines on Sistema Italia Sistema Italia 2004 not only sets out the basic regulations for the power exchange, but also establishes the framework for the Italian electricity system as a whole. It is therefore important to place the power exchange within the wider context of the Italian electricity sector. Note however that the model adopted by the Italian power exchange is largely inspired by NordPool and the US markets (which could essentially be described as voluntary exchanges based on zonal prices), but unlike its counterparts, the Italian market is more strongly geared towards physical bilateral contracts than trading. Sistema Italia 2004 has tackled a series of issues (allocation of CIP6 electricity and imports, the role of the GRTN etc.) that emerged in the first period of the sector s liberalisation. The industry ministry s guidelines are summarised below: Sistema Italia 2004 comprises a power exchange known as the IPEX (Italian Power Exchange), which includes a day ahead market and an adjustment market and which will be run by the GME, and a dispatch market services, including a balancing market, reserve market and congestion management market, run by the GRTN; The power exchange will be optional in that operators will be allowed to continue providing power directly to end customers under bilateral contracts, and only the electricity remaining after that will have to be sold on the power exchange; The GRTN buys and is responsible for allocating the electricity generated by CIP6 plants. This electricity is therefore not necessarily traded on the exchange, and it is reasonable to expect that auctions to re-allocate this electricity to third parties will continue; Import capacity is to be distributed according to bilateral contracts: ie via the current mechanism of pro rata allocation (which is likely to require only a little tweaking). Owners of import capacity may also sell their electricity on the power exchange, under conditions to be set out by the AEEG; Electricity produced by plants of less than 10 MVA will be taken by the GRTN and sold on the power exchange; Franchised customers will be supplied by the Single Buyer, a wholly publicly-owned company that guarantees supplies, via electricity purchased on the power exchange, long-term import contracts reserved for the franchised market and bilateral contracts with domestic producers. These last will be selected through competitive bidding, and may not account for more than 25% of the Single Buyer s requirements. Given that the franchised market is expected to represent 40-45% of overall demand in Italy in July 2005, at least 60-65% of this electricity should eventually be supplied on the exchange, which immediately guarantees the Italian exchange abundant liquidity in volume terms. The Single Buyer s operating guidelines are therefore essential, as over the next few years, it will be the main contractual counterparty on the demand side, both for the exchange and directly for producers, if they sign bilateral contracts that bypass the exchange. 10

12 The Italian Power Exchange The diagram below shows the organisation of the Italian electricity system, since the launch of the power exchange in April Fig. 3 - Organisation of Sistema Italia 2004 Producers Traders Bilateral Eligible cust. Bilateral CIP 6 energy - bilateral import Pwr. exch. - SMP CIP 6 energybilateral import GRTN Pwr. exch. - SMP GME Electricity market Day-aheadMarket Adjustment market Dispatch resources GRTN Dispatch market Congestion market Balancing market Reserve market CIP 6 auction Pro rata allocation bilateral import Bilateral via bidding max 25% of Sole Buyer s req. L-T import contracts Dispatch resources Single Buyer Franchised cust. Source: Banca Intesa from the document Organised system of buying and selling electricity: guidelines for the Sistema Italia 2004 AEEG-MAP, 31 July 2003 As for how the markets will be organised, Sistema Italia 2004 also set out the main guidelines for the power exchange, distinguishing between the power exchange (or the day ahead market, which defines the unit commitment, and the adjustment market) and the dispatch services market (or the markets to supply resources for balancing, reserves and congestion management between grid nodes). Power Exchange The power exchange is formed in the following way: The market will be formed by minimum price/quantity supply offers and maximum price/quantity demand bids. Prices will be formed using the System Marginal Price (SMP) mechanism. Here, the market is divided into zones 5 and each generating unit is given the SMP of the zone in which it is located. Calculation of the zonal balance will also take account of the injection and withdrawal schedules set out in bilateral contracts (discussed below). End customers will pay just a single national price, calculated as the average zonal price weighted for consumption. 5 The zones were established by the GRTN and approved by the AEEG with resolution 125/02. These will remain unchanged in the exchange s first three years and may subsequently be changed. 11

13 Industry Report May 2004 The GME as receiver of the electricity sold on the power exchange and the owners of bilateral contracts have the right to receive from or pay to the GRTN a fee for resolving congestion. This fee is equivalent to the price difference between the zones where congestion occurs. Payments will initially be managed by the GME. Once an energy derivatives market has been launched, this task may be handed over to a specific body that will act as a clearing house, along the lines of NordPool. Dispatch market The GRTN uses market mechanisms to supply the resources necessary to manage grid congestion, provide sufficient reserve capacity and ensure that injections and withdrawals are balanced in real time (balancing). As for the reserve service, the GRTN will set out in contract form the generating and consumption units suitable for operating reserve and cold standby and will award them a capacity payment. As for the reserve service, the GRTN will set out in contract form the generating and consumption units suitable for operating reserve and cold standby and will award them a capacity payment. Reserve and balancing costs are covered by tariffs borne by consumers of dispatched power (that is end customers) through payments regulated and set by the AEEG. Units essential for the security of the system are included under separate contracts. The AEEG regulates the cost of this service, which is borne by end customers. The tables below show the Italian electricity market, the structure of the system, the pricing regulation of each market and how the zonal market is organised in six areas (plus interconnection points with abroad). Fig. 4 Organisation of the Italian electricity market Day ahead market (DAM) Adjustment market (MA) Dispatch services market (DSM) Resource traded Power Power Electricity to resolve congestion Electricity for balancing Admitted operators* All All Users admitted by the GRTN Pricing regulation Zonal SMP Zonal SMP Pay as bid * The demand side will not operate for the first year of the market demand is instead determined by GRTN forecasts Source: GME 12

14 The Italian Power Exchange Fig. 5 Structure of the zones and estimated maximum transport capacity (winter 2003) Source: GME 13

15 Industry Report May How the markets work: electricity market regulations and conditions governing dispatch services Once industry ministry policies had established the general framework of the electricity system, the GME, AEEG and the GRTN issued regulations regarding the organisation of the wholesale electricity market, thereby giving it its basic physical structure. The rules governing the electricity market are set out in section 3.1. The following sections explore two fundamental issues that will continue to have a significant impact on how the exchange works. These are: i) the supervision of the electricity market, that is the indices used to monitor and measures to promote the market; and ii) operating procedures for the Single Buyer, which are fundamental in setting both the tariff to be borne by the end customers and how the Single Buyer will work on the electricity market. 3.1 Electricity market regulations AEEG resolution 168/03 and subsequent amendments and additions on conditions for dispatch services the most important of which is resolution 48/04 regulates procedures for assigning rights to transport capacity, the roles of the various parties operating in the power market, the dispatch procedures for bilateral contracts, and the payments operators receive or must make to take part in the various markets. The resolution s basic elements are. 1. Transport and dispatch services A dispatch and a transport contract must be signed with the GRTN. This contract is a necessary condition for access to transport services, which is granted once an agreement with the local distributor has been signed. Owners of a production facility (more than 10 MVA), consumers and the Single Buyer must sign this contract, while parties that have signed import contracts are not obliged to do so. These parties may also appoint an agent for the transport and dispatch contracts (this may be an undisclosed agent). The points where power is put into the grid, and, equally, drawn from it are those that relate to a production facilities of the same type, within the same zone, and included in the transport and dispatch contracts. These are also the points where imbalances are calculated, which give rise to an operator s rights/obligations to draw power from/put power into the grid. There must therefore be a single party dealing with the GRTN in respect of transport and dispatch. This party may be the owner of a production facility or a consuming facility, or an agent of the same, even without representation typically, a wholesaler. It should be remembered that to sign a transport contract, and party must demonstrate that it has a contract for physical deliveries. The connection made by AEEG between the transport and dispatch contracts therefore involves the requirement for a contract that makes physical power available (in whatever form). There is considerable simplification of the legal responsibilities, in that under the new regulations a single party is responsible to the GRTN. 14

16 The Italian Power Exchange 2. Who takes part in the market Offers may be made either directly by consumers of dispatched power, as defined above (offers made directly on the power exchange), or by market operators. Market operators are parties that can register, with the aim of dispatching to the GRTN, purchase and sale contracts negotiated outside the offer system (known as bilateral contracts). These parties are: Under the regulations, consumers of dispatched power and the power market operator in effect the equivalent of a wholesaler; The GRTN with regard to CIP6 plants and imports. For the latter, the GRTN may authorise third parties to take on the role of market operator; Wholesalers, if recognised by the consumers of dispatched power, with the exception of plants designated as essential to the power system s security; The Single Buyer, as guarantor of supply to franchised customers. The regulations thus comply with the guidelines of Sistema Italia 2004, in that they allow all parties to make offers directly on the market or to sign bilateral contracts, and also safeguard the mechanisms for assigning CIP6 power and imports bilaterally. As market operator for the points where power is put into the grid, the GRTN is free to assign this power bilaterally outside the offer system (CIP6 auctions) and to authorise third parties to be market operators (and thus authorised to sign bilateral contracts outside the offer system) as regards import capacity that is not destined for the franchised market (for which, by contrast, it acts on its own account), thus safeguarding the present pro rata allocation mechanism. 3. Procedure for bilateral contracts Market operators inform the GRTN of their plans for putting power into and drawing power from the grid as demanded by their contracts, at least six hours in advance of the time for presentation of offers on the DAM. These plans may be made known separately by the selling and buying operators, but they must always be the same. If this condition is not met the GRTN will consider them invalid; If more or less power has been put into the grid or drawn from it than contained in the plans submitted to the GRTN, this electricity is considered to have been bought or sold within the dispatch market; The exchange of power made by a qualified market operator, either into or from the grid, is regarded as equivalent to a sale or purchase contract drawn up outside the offer system. The procedures for fulfilling bilateral contracts give prominence to the physical nature of the Italian power market. The obligation to submit to the GRTN plans to draw off and put in equivalent amounts of power greatly favours wholesale sellers and buyers (ie all wholesalers that have a supply contract whether a tolling, PPA, bilateral, or any other type of contract) over pure traders which, by definition, are only net buyers on the power market. This puts small operators at a disadvantage, as they could otherwise use the exchange to acquire the electricity they need to meet their own sales contracts. 15

17 Industry Report May How the DAM works The DAM is run by power market operator, the GME; The GRTN informs the GME, the day before the DAM transactions are completed, of the transit limits between zones, the programmes contained in sale or purchase contracts signed outside the offer system, and the allocation procedures in the event of a number of marginal offers at the same price; In the event of several sales offers at the same price, the following order of priority applies: units essential for security; production facilities supplied from unprogrammable renewable sources (wind, photovoltaic, or wave power); production facilities supplied from programmable renewable sources (hydroelectric, waste to energy, biomass) or cogeneration; CIP6 production units; sale or purchase contracts signed outside the offer system; other offers. Programmes for putting electricity into, and drawing it from, the grid in compliance with sale and purchase contracts negotiated outside the offer system are equivalent to zero price sales offers and purchase offers with no price indicated, respectively; The price paid to producers is the marginal price in each zone; The price paid by purchasers, is a single price, calculated as an average of the zonal prices, in which the weighting is provided by the volumes of energy in the offers made in each zone. The quantities needed to ensure the system s security are determined from a list updated annually by the GRTN and communicated to the GME at least 12 hours before the DAM closes. In this event: offers to sell/buy are presented directly by the dispatch user and are equivalent to zero price offers (or with no price indicated); these units receive the zonal price, to which is added a sum equal to the difference between this price and the variable cost the units are deemed to incur; furthermore, the dispatch user can request, for these units, that the sum be calculated again, so that it covers the full cost or production, where the payment received is not enough to cover fixed costs; in this case, the dispatch user responsible for such units is obliged to offer the entirety of its power at pure variable cost in all situations where the plant is not considered essential for the system s security. 5. How the adjustment market works This market is managed by the GME, which accepts sale or purchase offers while respecting the residual limits of exchange in each zone; Both sales and purchase offers are valued at the zonal price; Adjustments are not possible for sale or purchase contracts negotiated outside the offer system: for the rest, the order of priority in the event of 16

18 The Italian Power Exchange several offers at the same price is identical to that on the DAM, with balanced offers having priority; For the market s first year of operation, buyers whether direct end users or wholesalers cannot take part in the adjustment market. 6. The dispatch service The GRTN procures the resources necessary for this service through both market and non-market mechanisms. The dispatch services market is run by the GRTN, which makes use of various market mechanisms to procure resources to: manage congestion; manage active secondary and tertiary reserves; balance injection and withdrawal in real time. Participants in dispatch service markets must make available all the power they have at their disposal, and are remunerated on the pay-asbid principle; The GRTN uses non-market mechanisms to procure the following services: primary reserve or frequency regulation; regulation of tension through provision of reactive power; Black Start service (load rejection, remote disconnection and restoration of the electricity service following blackouts). 7. Payments for the dispatch service The structure of the various payments works to (i) ensure that the costs of all dispatch services (congestion, reserve, and balancing) are covered; (ii) to send the market a clear signal of the value of these resources; and (iii) to prevent operators from exploiting arbitrage opportunities offered by the structure of a sequential power exchange and the option not to respect balancing orders. Experience in other markets (California and US power exchanges, but also NETA) shows that where there are several markets in sequence, such as the day ahead market, adjustment sessions and the balancing market, operators that are technically able to do so have an incentive to create fictitious shortages on the planning market and to make offers as close as possible to dispatch in real time, where they can secure more advantageous terms. Moreover, balancing markets are potentially easier to manipulate. To assign a fair price to all these services and to avoid these risks, the AEEG proposes various types of payment for dispatch services: Payments for assignment of rights to use transport capacity, which are to be paid pursuant to the purchase and sale contracts negotiated outside the market and the GME, which is thus equivalent to a wholesaler. The transport payment is typical of zonal markets in that it is essentially a function (power put into and drawn from the grid being equal) of the price difference between zones, ie of the level of congestion (if there is no congestion the price is the same nationwide). The payment is payable by all operators in the market, ie parties that negotiate bilateral contracts and the GME, which acts as a wholesaler for all parties that put power onto the grid, and the sum it pays or 17

19 Industry Report May 2004 receives is calculated as the balance of all positions derived from this type of offer. The GME then transfers the resulting balance to the GRTN, or is compensated by it if the balance is negative. It should be pointed out that there are two payments for use of the grid, one relating to the offers made on the DAM, and one to those made on the adjustment market. Since purchase and sale contracts cannot be introduced on the latter, the payment for use of the grid on the adjustment market is payable only by the GME. Revenue coming to the GRTN from transport payments should be used to organise a capacity payments market between zones (Financial Transmission Rights or FTR) or to eliminate congestion by investment in developing the power grid. Imbalance payments, which covers the electricity injected/withdrawn at a dispatch point exceeding or falling short of that set out in the injection/withdrawal schedule. All dispatch users must make these payments, excluding imports. It should be pointed out that production units using non-programmable renewable energy sources must make an imbalance payment equal to the zonal price set by the market the day before. These payments differ depending on whether the imbalance is positive or negative: in the event of a positive imbalance (excess supply), if the aggregate of imbalances in the zone is positive the payment is equal to the smallest difference between the lowest offer price accepted on the balancing market, and the zonal market price set by the market the previous day. If the zonal aggregate is negative, the payment is equal to the zonal market price on the DAM; in the event of a negative imbalance (excess demand), the payment structure is reversed, and the payment is equal to the zonal market price the previous day if the zone s aggregate imbalance is negative, and to the smallest difference between the zonal market price the previous day and the highest offer accepted on the balancing market. Payments for failing to comply with dispatch orders, which punish operators selected in dispatch markets that do not carry out the orders of the GRTN. It should be remembered that operators that take part in the dispatch service market offer availability to the GRTN; this availability must then be put into operation by the GRTN on the basis of events that take place in real time. It may happen that certain parties, having said they would have availability, then find themselves unable to provide a service, in which case they must be penalised. Such payments are applicable, of course, only to those dispatch points that have taken part in dispatch service markets. They apply in the event that the GRTN has accepted sale offers on the balancing market and, where the aggregate imbalance in the zone is positive, the imbalance at the dispatch point is the opposite 6. In unit terms the payments are equal to: for sale offers, to the difference between the zonal sale price on the DAM and the sale offer price accepted for the dispatch point; for purchase offers, to the difference between the purchase offer price on the dispatch service market and the zonal sale price on the DAM. This unit payment is applied to a quantity equal to the lesser of the absolute value of the accepted offer and the absolute value of the sum of the imbalance of the balancing point to which the offer refers and the 6 This applies to purchase offers in the opposite scenario. 18

20 The Italian Power Exchange accepted offers that precede the offer price, which is around that set by the GRTN. The penalty is thus in proportion to the extent of the damage caused by not complying with the GRTN s order. The non-arbitrage payment, to be paid by or to consumption units operating on the market and those that make offers on the adjustment and dispatch market, calculated as the difference between the zonal sale price and the DAM purchase price, and applied to offers made on subsequent markets. The payment is intended to prevent operators from carrying out arbitrage transactions on subsequent markets, by exploiting the difference between zonal prices and the single national price. Payments for providing dispatch resources, payable by end users of dispatch services. (i) Suppliers of dispatch facilities are paid according to the pay-as-bid principle based on offers they make on the dispatch services markets managed by the GRTN. (ii) Parties that produce imbalances make imbalance payments as set out at the first bullet point above. (iii) The majority of end users must of course pay the charges relating to the dispatch service provided by the GRTN, which essentially are applicable when there are differences between what has been paid by parties responsible for imbalances and what is acknowledged to parties that provide the service. The unit payment is calculated by relating this difference to total energy volumes. Payments to parties that are essential for maintaining the system s security, which are payable by all consumers and are equal to the ratio between unit costs (see paragraph 4) and the total amount of electricity drawn from the grid. Payments for making production capacity available to parties that provide capacity for use in critical times. This payment was introduced by resolution 48/04, and must be borne by all users of dispatch services withdrawing electricity from the grid. During the transition period, operators will be paid according to the method outlined in appendix 1. From 2005, they will be remunerated through a specially created capacity market. Fig. 6 Structure of payment flows for dispatch services Market operator GME Rights to use trans sport cap. DAM Rights to use tran Rights to use transport sport cap. DAM adjustment mkt GRTN Imbalance Non-arbitrage Dispatch resources Failure to comply With balancing orders Remuneration of essential units Sufficient capacity User of dispatched power Source: Banca Intesa from AEEG resolutions 168/03 and 49/04 19

21 Industry Report May Transition period The AEEG has drawn up transitional regulations for 2004, bearing in mind that this will be the market s first year, and that certain new procedures such as load profiling are completely untried. There are two main transitional measures: (i) The GRTN can intervene both on the day before and the adjustment market, when the forecast loads are 10% above or below the offers presented on the DAM, for offers that do not exceed 70% of that difference. In such cases, the payments and charges for GRTN are calculated exactly as for any other operator. There is clearly concern that the load profiling mechanism (see appendix 2) for consumers who do not have an hourly meter may at first lead to errors that could cause security problems in the system; (ii) Operators in the market for consumption units essentially pure wholesalers cannot operate on the adjustment market in 2004, as this is reserved solely for the production side for the first year. 3.2 Indices for monitoring the market and measures to promote competition The instruments used to monitor the market are among the most important implementing measures relating to the launch of the power exchange. They include a series of indices that provide average prices and reveal any anticompetitive practices by operators or the abuse of dominant positions. Furthermore, some measures have been taken to promote competition, in light of the fact that Italy's generating systems bears many of the hallmarks of an oligopoly, with ENEL and the three ex-gencos generating around 75% of the country's total output. These indices and measures to promote competition were established by resolution 21/04 and subsequent resolution 49/04. The resolutions tackle three issues, both for when the power market will be fully operational, and for this year s transition phase: 1. indices for monitoring the power market (prices and average figures), which are the responsibility of the GME for the day ahead and adjustment markets, and the responsibility of the GRTN for the dispatch market; 2. specific indices for checking operators market shares, with responsibilities as above; 3. measures to promote competition. The details of these are as follows: General monitoring indices provide indications of average prices, their volatility and concentration of supply. Furthermore, the power market operator must draw up a monthly price index, called the settlement index, defined as a moving average over the previous 12 months, calculated from the amounts traded on the markets. Although this is not explicitly stated, we can assume that these indices may be made public, together with the hourly power demand for each zone, the GRTN s responsibility; Specific indices are more interesting, their main objective being to shed light on dominant positions on the markets. The AEEG certainly has access to these indices, as stated in the resolution, but it is less likely that they will be made public. For the day ahead and adjustment markets, which work on a zonal basis, the GRTN must draw up indices for each operator s market share, the number of hours during which a given operator s supply was marginal, the difference between the prices offered by each operator for 20

22 The Italian Power Exchange each unit and the typical marginal production costs of these, the difference between the zonal costs and the single power purchase price, and finally the quantity of the last accepted offer compared with the total of accepted offers within that zone. On the dispatch services market, the GRTN sets indices for the share of each operator on the market, the number of hours during which the power supply was marginal (broken down by type of service), and the difference between the offers made by each operator and the prices specified in the offers of other parties (also broken down by type of service). Furthermore, the GRTN must draw up indices for availability of capacity. For each hour, zone and market operator, the GRTN must calculate the difference between the supply that is actually available 7 and the proportion of an operator s supply not already committed under a contract 8. This difference, in relation to the specific level of demand in each zone, is called the residual supply index and will typically be less than 100%. The difference between 100% and the residual supply index, multiplied by the demand figure, sets the volumes each operator must provide to ensure the security of the zone s supply. Measures to promote competition. This is the resolution s most interesting aspect, at least as regards the sections that set operating procedures for the Single Buyer. This buyer can sign bilateral annual supply contracts with operators, for a total amount no lower than 25% of the consumption forecast on the franchised market 9, in each zone and during each one-hour period. Contracting parties were selected by descending auctions held on 15 April, starting from a price set at the 2004 wholesale price (calculated from the sum of the Ct component and those relating to the coverage of fixed production costs, net of reserve and balancing payments). 10 Bilateral contracts provides the Single Buyer with available capacity based on a fixed price independent of that set on the exchange. In contracts for difference, the purchase price paid by operators to the Single Buyer is equal to the single purchase price set at the power exchange 11, while the price paid by the Single Buyer will be the price set by the auction. This allows the Single Buyer to set the sale price of its own energy in advance, limiting its risks and, when the system is fully functional, possibly cushioning end users from volatility on the power exchange. Operators that sign these contracts with the Single Buyer will have a similar degree of price certainty, securing for themselves natural coverage on the market without the corresponding risks. The measure that sets the maximum acceptable price on the day ahead market at EUR 500 MWh is less significant. In effect, price peaks above these levels occur very rarely in the year and their effect on average prices is limited even though they have a strong psychological impact both on the market and on consumers. This measure should therefore have a limited effect in practice. 7 Calculated as the sum of the net efficient power (that is each plant s capacity excluding instances when the plant is offline for ordinary maintenance, and sales of CIP6 energy) in a given zone and net imports in that zone in an operator s availability. 8 This is the capacity effectively available minus a coefficient that takes into account unforeseen unavailability and the capacity allocated for sale through contracts for difference. 9 Net of CIP6 energy and that provided by imports available to the Sole Buyer. 10 See section 2.3 for auction starting prices specifically for bilateral contracts and the different types of contracts for difference. 11 These prices will be different for each contract, according to the hours they cover. 21

23 Industry Report May Bilateral contracts and contracts for difference signed by the Single Buyer A closer analysis of bilateral contracts and contracts for difference signed by the Single Buyer is important, both to establish the average prices that will be paid by end users under the tariff, and because the Single Buyer, as guarantor of supply to the franchised market, is a key player in this first phase of the power market. The Single Buyer s requirements for 2004 are estimated at around 170 TWh (over 50% of total Italian demand) covering the whole demand of non-eligible clients as well as of those parties that, while eligible customers, have preferred to remain within the regulations that will be applied to the franchised market. The procedures for the Single Buyer s purchase of power, and the prices it pays, are therefore fundamental given the significant impact they can have on the market. 12 The Single Buyer has several supply sources: the power exchange, CIP6 contracts, and imports reserved for it by law. It may also sign bilateral contracts for a share not exceeding 25% of its annual needs and, finally, it can sign contracts for difference (CFDs), to hedge against price volatility risks. The price to be borne by tariff-paying consumers will be an average of all these supply sources. The Single Buyer therefore safeguards the liquidity of the exchange, because much of its power must be bought on the day ahead market 13. By signing bilateral contracts and CFDs, it also allows operators to reduce market risk (regarding price and volume) and offers a form of credit, which favours stable cash flows and encourages the financing of new investments. Moreover, the Single Buyer s differential contracts are a significant new development for the Italian power market, and could act as a platform from which to launch a secondary market in derivative contracts, albeit one with a strong physical component. They also offer a way of covering risk both for the Single Buyer and for producers, in line with the most advanced international models. The procedures by which the Single Buyer signs its bilateral contracts and CFDs were published in two announcements made on 12 and 18 March 2004, in which the Single Buyer applied the provisions established in AEEG resolution 21/04. Regarding the award of bilateral contracts, the Single Buyer called producers and wholesalers to a descending auction at a defined price (essentially the tariff for covering fixed production costs net of reserve and balancing payments), to assign 4,800 MW of baseload capacity to be allocated in 10 MW blocks. This capacity is divided up into seven macro-zones, as set out in the following table. 12 It could be argued that one reason for the delay in the launch of the power exchange was the prolonged uncertainty regarding regulation, which has no international parallels. 13 The forecast total demand for the franchised market in 2004 is 170 TWh, of which 126 TWh is needed from the moment the power exchange comes into operation. Of these, 55 TWh (about 44% of the market) will be sourced directly on the exchange, 19 TWh through CFDs, and about 31 TWh from bilateral contracts. 22

24 The Italian Power Exchange Fig. 7 Capacity assigned by the Single Buyer by zone Zone Capacity Total Source: Single Buyer Fig. 8 Auction price for bilateral contracts Wholesale prices Rf bf Auction base price (Euro/MWh) Source: Single Buyer Contracts were allocated to parties offering the biggest discount a discount that can vary from block to block. Where two offers were equal, contracts were awarded to parties that offered the biggest quantity, that is, made offers on more than one block; if this had failed to resolve the matter, capacity would have been assigned pro rata. Operators that were assigned capacity were paid according to their offer, to which the April 2004 Ct 14 was added. Contracts become effective once the auction results are published on the Single Buyer s website, and will remain in force until end The auction results were published on 23 March; 11 groups were awarded contracts, including the main Italian producers, two large foreign producers, and some of the main Italian municipal companies. 14 The April Ct is EUR 36/MWh. 15 The Sole Buyer will probably be able to continue to sign bilateral contracts and CFDs in the coming years. 23

25 Industry Report May 2004 Fig. 9 Allocation of bilateral contracts Source: Single Buyer Contracts for difference will be allocated by descending auction, in which the participants must apply a discount to a benchmark strike price announced by the Single Buyer. This strike price, discounted and increased by the Ct component for April 2004, will act as a benchmark for price settlement. If the national average price on the exchange is higher than the strike price, producers will have to pay the Single Buyer the difference, and vice versa. This simple framework, which is the same in all contracts for difference, is applied to Italy s specific zonal market and in the current transition phase, in which the old tariff system and the new system of time bands coexist. Specifically, the Single Buyer s announcement establishes that: Contracts came into force from the moment dispatch based on economic merit comes into operation and will run until the end of the year; The Single Buyer offers four types of contract; Banded (baseload) contracts, for a total of 1,750 MW per month, under which electricity is sold in a band for the duration of the entire day; Mid Merit contracts, for a total of 2,850 MW per month of the second and third quarters of the year, and 4,675 MW per month in the fourth quarter. These cover the period from 8am to 11pm every day; Peak Load 1 contracts, for a total of 1,525 MW per month in the second quarter, 3,150 MW per month in the third, and 1,975 MW per month in the fourth, for supply between 9am and 1pm. Peak Load 2 contracts, for 1,275 MW per month in the second quarter, 3,600 MW per month in the third, and 1,975 MW per month in the fourth. In the second quarter, this will be between 6pm and 11pm, in the third between 7pm and 10pm, and in the fourth between 5pm and 10pm. These totals are divided among the different zones, as set out in the tables attached to the Single Buyer s announcement. Bids must be for bands of 25 MW, or multiples thereof. The auction base price is calculated on the basis of the AEEG s resolutions, which establish the component covering fixed production costs (AEEG resolution 203/02) net of the components covering reserve and balancing costs (AEEG resolution 36/02). These figures are then applied to the times contained in the various contracts, according to the new bands (reset in resolution 05/04). 24

26 The Italian Power Exchange Fig Base calculation prices and strike prices in contracts for difference to be signed with the AEEG Wholesale price Euro/MWh Rf Euro/MWh Bf Euro/MWh Basis prices Euro/MWh Basis price per pruduct (Euro/MWh) Source: Single Buyer Producers applied a discount also differentiated by band to these base auction prices. This figure, increased by the April 2004 Ct, sets the strike price for each month and each product. Note that, since some of the auctions for CFDs on peak contracts attracted little interest, AEEG resolution 49/04 established that these contracts might be offered again, still using PG as the basis of the auction, but increased by 2% to attract a larger number of operators. The average national price to which the strike price will be compared was calculated, for each contract, on the basis of the price emerging in the zone and within the times of each individual contract. The successful bidders are those that offer the biggest discounts. Quantities are shared pro rata where these discounts are the same. Note that not all available capacity was assigned after the two auctions; the capacity not taken up was especially in the peak bands. The operators that secured the most capacity were ENEL Produzione and Endesa Italia, with less going to AEM Milano, ATEL, EdF, and ENIPower. 25

27 Industry Report May The first trading results on the Italian Power Exchange The data is necessarily incomplete, but results of the first month s trading on the IPEX seem to show that considerable volumes were traded, with prices showing little variation, though it is still early to talk of volatility indices. On the day ahead market, daily liquidity is sound, largely because operators are obliged to offer on the exchange all production not contractually committed through dedicated sales or bilateral contracts. Some 300 GWh per day pass through the exchange on working days, or about 30% of the daily volume required by the Italian electricity system, totalling 7.4 TWh in April. Hourly volumes traded on the exchange vary somewhat, while the profile for bilateral contracts is much flatter. This means that the total volumes traded can be divided into two main clusters: basic daily demand (or empty hours), and peak demand (full hours), between 0800 and 2200 on working days. At first glance, this seems surprising, since it shows that the system of four time bands, which many observers thought the market would follow, has been abandoned. Instead, the market immediately adopted the bands used by the European and US wholesale markets, which are more suited to companies operating and contractual practices. The band prices published by the GME bear this out: purchase prices in the F2 and F3 bands have been very similar (EUR 68.84/MWh and EUR 66.99/MWh respectively), while prices in F4 were EUR 40.63/MWh. The reduced level of competition 16 and the absence of demand pressure at this time of year led to relatively low daily purchase price variations (compared with the prices that can be achieved by power exchanges), averaging about 45%. Oddly, there was greater volatility during base hours than during peak hours, partly because of low demand in April (which leads to relatively few price peaks) and partly because peak plants have more influence on the market than base plants. Fig MGP IPEX, 6 April The Hirschman-Herfindahl index for April calculated by the GME shows a good level of competition only in the northern area, while there is a high level of oligopoly in the south, especially in Sicily. 26

28 The Italian Power Exchange Fig MGP IPEX, 7 April 2004 Source: GME Although purchase prices resulting from the merit order method cannot strictly speaking be compared with tariffs on the franchised market, it should be noted that average purchase prices on working days rose slightly above the old PG N. Average prices during the empty hours rose above the Ct price set for April. Fig. 13 Single national price average on IPEX, EUR/MWh Calculated on total volumes (A) Calculated on exchange volumes (B) Difference (B-A) 01-Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Apr Average Working day average Weekend/holiday average Source: Banca Intesa calculations from GME data 27

29 Industry Report May 2004 This may appear worrying given that demand is greater in summer, when the reserve margin of Italy s production system is reduced to around 5% 17, but the introduction of competition was always likely to make producers increase their margins. Prices are likely to hover around these tariff levels for some time to come, with the old PG N representing the lower limit of average purchase prices. On the other hand, the temporary arrangements for 2004 and the bilateral contracts signed by the Single Buyer at the old tariff level provide an important benchmark for average prices on the exchange and, as long as competition remains at its present modest level, operators have no incentive to reduce margins for now. Like gas prices, electricity prices will only start to fall when new combined-cycle plants come on stream and more operators become active on the market. In the short term, the component for covering supply costs may therefore rise in the tariff for end users, given that this will reflect the Single Buyer s average costs for securing supplies, and that it buys a considerable proportion of this (around 60%) on the IPEX, especially in peak hours 18. Fig MGP IPEX figures, 1-30 April /MWh 01-apr 03-apr 05-apr 07-apr 09-apr 11-apr 13-apr 15-apr 17-apr Volumes GWh Bilaterals GWh Max Weighted Average Source: Banca Intesa from GME data Min 19-apr 21-apr 23-apr 25-apr 27-apr 29-apr GWh A look at zonal prices shows that the averages (calculated from the quantity sold) are higher than the single national purchase price; they have naturally shown greater variations, thus confirming the stabilising influence of the single national price on purchase prices for buyers Higher rainfall during the early months of the year, and especially the heavy snowfalls of the winter, suggest that hydroelectric production will be high, which could increase this margin. 18 It can be no coincidence that the auction for peak hour CFDs held by the Sole Buyer attracted virtually no interest on two occasions, even though in theory full subscription of peak hour CFDs would have emptied the IPEX 19 The single national price averaged within a range of EUR 2-85/MWh, while zonal prices moved within the full range allowed by market rules, EUR 0-499/MWh 28

30 The Italian Power Exchange Fig. 15 Average zonal prices, 1-30 April 2004 Source: GME monthly report, April 2004 The market was more active in northern Italy, where most trading took place (45% of sales and 52% of purchases) and where 48% of total demand was offered on the exchange. The market tended to form three macro-areas: a) the mainland (where, however, for 50% of the time the Calabria and Rossano Calabro region separated itself, and for 17.25% of the time, the north and central northern areas were separated); b) Sicily; and c) Sardinia, with the last two acting as de facto autonomous zones. Separation of zones did not lead to great price variations between the different areas, but it produced a considerable congestion charge (EUR 4.4 million in April), a sign of frequent congestion which could increase at peak times. Drawing any conclusions on trends on the IPEX may be premature, given its short history to date. However, certain fundamental characteristics forecast by operators in the sector seem to have emerged: volumes and prices have stabilised at high levels, the new structure of offers at peak and base hours (replacing the old band system) has shown low volatility, congestion has been frequent, with separation of mainland and island markets, and often Calabria, and, finally, the north has proved more competitive than the south. Volumes traded on the adjustment market were naturally much lower some 8% of those traded on the day ahead market whiles prices have been in line with those of the day ahead market. The first real test for the IPEX will come in the hot summer months, which last June threw Italy s power system into crisis. It will be interesting to see whether the exchange will experience supply shortages as a result of the price peak mechanism. 29

31 Industry Report May The international experience: the most significant results Comparing European power exchanges has little significance if it fails to take into account the distinction made in section 1 between physical and financial power exchanges. The purpose for which they were set up has different effects both on volumes and the products traded on them. Comparisons are therefore meaningful if made on similar models or at least those belonging to the same family of power exchange. We have identified two groups of power exchange, one linked to plant scheduling and dispatch and the other, purely financial exchanges. Spain s OMEL and the three US exchanges the New England Power Pool (NePool), the New York Power Pool (NYPP) and the PJM belong to the first category; France s Powernext, Germany s EEX, the APX in the Netherlands and the UKPX in the UK belong to the second. NordPool is a special case, as it combines features typical of both physical and more financial exchanges. Clearly, we cannot offer a detailed comparison of the specific features of all the power exchanges here, although these characteristics go a long way to explaining the nature of the exchanges themselves, as well as price levels and movements. However, we will try to describe the main features of each of these exchanges, and thereby establish what type of exchange they are and explain some of their results. 4.1 Physical power exchanges The physical power exchanges we have analysed (the OMEL, NePool, NYPool and PJM), are very similar: They have a day ahead scheduling market based on hourly prices; This market is not officially compulsory, but since bilateral contracts also pass through the exchange, the merit order and prices generated by the system reflect the system price; The three US exchanges operate a zonal pricing system, while the OMEL applies the system marginal price; They operate congestion management systems; the OMEL and the NYPP have a specific market for this, while the other exchanges use Locational Marginal Prices (LMP) 20 ; They all have market systems to provide dispatch resources, also known as ancillary services (reserve and balancing). The US exchanges also operate capacity markets, both to provide shortterm reserves and to build up long-term capacity. US exchanges have set up contracts hedging against the congestion risk, that is the price spread between the zones. These contracts, known as Financial Transmission Rights (FTR), are traded on a specific market and operate like swaps. They are based on the actual congestion cost on the NYPP, and on the price spread between zones on the NEPool 20 LMPs are made up of three components; the electricity component, a component covering congestion costs and another covering the costs of specific grid losses. The last two components vary according to area and allow zonal prices to be formed. While these do not constitute a true congestion price, they provide an important indication of costs relating to congestion. 30

32 The Italian Power Exchange and PJM, and hedge the holder against the risk resulting from any strong fluctuations in price caused by grid bottlenecks. These exchanges have many features in common, given that: i) they are directly managed by an ISO in the case of the US exchanges, or companies closely linked to the grid operator; ii) the volumes traded on the DAM represent a fairly significant portion of total physical trades. Nearly all electricity generated by Spain passes through the OMEL, on average 600 GWh a day, equivalent to around 220 TWh in 2003; 50% of supply is traded on the spot market (around 80 TWh a year) on the NYPool, while this figure falls to a little over 30% on the PJM and NePool; iii) price volatility 21 is about the same on all four exchanges, and is considerably lower than that on financial exchanges; iv) trading volumes on sequential markets (for adjustment rather than congestion or ancillary services markets) are much lower, as operators use them to adjust their positions. The resulting prices also tend to fall in line with those on the DAM, partly because the regulation puts restrictions on supply, intended to prevent anti-competitive practices. v) capacity markets do not seem to have met with much success, while instruments hedging against congestion costs are generally becoming increasingly popular. Fig. 16 Main figures for physical power exchanges OMEL PJM NePool NYPP Baseload Peak Baseload Peak Baseload Peak Capacity traded (GW) Average prices /MWh $/MWh $/MWh $/MWh $/MWh $/MWh $7MWh Volatility * Prices refer to 01/01/01 14/03/04. Bloomberg data for the NePool refers to 01/01/01-20/02/03 Source: Banca Intesa from various sources These exchanges therefore tend to replicate, in a decentralised and marketbased system, the instruments usually adopted by operators in the physical management of the system. They are set up to provide operators with incentives to guarantee supply, which, in theory, they are no longer obliged to provide as part of a public service remit. They therefore tend to be fairly complex, and closely linked to technical aspects and awareness of the situation in the plants and on the grid. Very often, they are heavily regulated so as to limit the market power created through continuous trading between a few operators on the same markets. From another viewpoint however, in light of the market s complex and technical nature, operators have less incentive to set up purely financial contracts, which have only registered modest growth, mainly as a result of operators hedging against purely physical risks such as grid congestion. These markets therefore tend to be the preserve of sector operators, particularly those with production capacity. In many ways, Italy s Power Exchange falls within this category of market. 21 Volatility is calculated as the standard deviation of the differences between weekly price averages (calculated every day on a rolling basis). The OMEL uses the average system price, while the US exchanges use the average zonal prices or LMP, provided by Bloomberg 31

33 Industry Report May Analysis of individual markets OMEL Spain s OMEL is the only physical exchange in Europe excluding the Italian exchange and from many viewpoints, it serves as the best comparison for the IBEX. The OMEL was set up in 1999, and consists of a day ahead market, six adjustment sessions, a session to resolve congestion, and a market for ancillary services. The day ahead market is an hourly spot market (that is a classic day ahead market - DAM), that determines a non-zonal system marginal price (SMP), which acts as a benchmark for the entire Spanish electricity system. Although the exchange is not compulsory, the incentives offered 22 mean that nearly all electricity generated in Spain is offered on the DAM; volumes traded in 2003 totalled around 600 GWh a day, almost 100% of Spanish consumption. The price on the DAM is on average fairly low at around EUR 30/MWh, with a fairly reasonable level of volatility for a power exchange; this is because prices are largely stable, given that the whole supply passes through the exchange and the Spanish market is fairly oligopolistic, with two large operators, Endesa and Iberdrola, accounting for 55-60% of supply. The only truly price peak 23 recorded in the last few years was in early 2002, following a serious drought that cut hydroelectric capacity (which accounts for almost 30% of capacity), and which also increased annual price volatility. Fig. 17 Average prices and daily volatility on the OMEL Average prices /MWh Volatility Source: Banca Intesa on OMEL data Fig Average prices and daily volatility on the OMEL /MWh /0 /0 /0 /0 /0 /0 /0 /0 /0 /0 /1 /1 /1 /0 /0 /0 /0 /0 /0 /0 /0 /0 /1 /1 /1 /0 /0 /0 /0 /0 /0 /0 /0 /0 /0 /1 /1 /1 /0 /0 /0 1/ 2/ 3/ 4/ 5/ 6/ 7/ 7/ 8/ 9/ 0/ 1/ 2/ 1/ 2/ 3/ 4/ 5/ 6/ 7/ 8/ 9/ 0/ 1/ 2/ 1/ 2/ 3/ 3/ 4/ 5/ 6/ 7/ 8/ 9/ 0/ 1/ 2/ 1/ 2/ 3/ Avg prices Source: Banca Intesa on OMEL data Daily volatility 22 Operators that do not take part on the exchange were not awarded stranded costs. 23 Calculated on the basis of moving averages, to show whether or not price peaks have a significant impact on the average price. Price peaks often only last one day on power exchanges, and while significant, they do not have a serious impact on average system prices. This criterion is used throughout our analysis. 32

34 The Italian Power Exchange The intraday adjustment market has much lower volumes around 80 GWh a day, generally concentrated in the first session. Prices are on average lower than on the DAM which suggests that speculators do not operate on the market and that Spanish regulation has managed to prevent anticompetitive practices on sequential markets. Volatility is however higher than on the DAM, owing to the lower volumes traded. Lastly, on the ancillary services market, the OMEL supplies electricity for primary, secondary and tertiary regulation, and resolves imbalances. The cost of these ancillary services is around 3-4% of the total cost of the electricity, which seems to be in the upper band of costs typical of these services at international level 24. However, as there has never been a system blackout, nor very high prices that have affected consumers, we may conclude that the system works fairly well. PJM NePool PJM These three US markets have many characteristics in common, in addition to the way they are organised. First, the three markets are geographically very close, in that they are all located in the east of the US. The PJM is the largest of the three markets, with annual demand of 325 TWh, while the NePool and NYPP are smaller in size, with demand peaking at around 25 GW and total annual demand at around 160 TWh. Demand on all three markets peaks in the summer, while supply is mainly generated by traditional fossil fuels (coal, fuel oil) and nuclear power, and is not particularly efficient; average prices are fairly low. Bottlenecks occur quite frequently, because the high-tension grid in the east of the US is rather inefficient. Local blackouts 25 are therefore a common occurrence by European standards. The three regions are interconnected and trade between operators on the different exchanges is fairly brisk. The three markets are therefore organised in a similar way, reflecting the similar structure of the industry in the three regions. In 1999, the ISOs of the PJM and of New England began to decentralise scheduling, through a noncompulsory exchange with zonal prices (or Locational Marginal Prices, LMP), and at the same time, set up a market to manage imbalances (real time market) and one to supply capacity. The model has developed over the years, with the continuous modification of significant nodes on the grid, the creation of an FTR market to hedge against congestion costs implicit in zonal prices and ancillary services markets. The NYPP began operations in 2001, following a broadly similar market model, but adopting clear congestion prices, which in other systems are shadow prices obtainable through zonal prices. The volumes traded on the three markets are modest. In terms of liquidity, the NePool makes most use of the spot market, accounting for around 60% of the total load. The quantity is around 50% on the NYPP and falls to around 30% for the PJM. The PJM is still however considered to be the most competitive and efficient market, because it is larger, and has more operators and a lower average system price. Price peaks have been relatively frequent. They have mainly been the result of frequent bottlenecks and therefore severe congestion on the system. The 24 These are usually estimated at around 2-3% of the total price 25 The last significant blackout affected around 300,000 users in the Cape Cod area, and followed the huge blackout of summer 2002, which affected over 50 million people. 33

35 Industry Report May 2004 exchanges have also experienced problems of anti-competitive practices owing to artificial supply shortages generated by the sale of electricity to other interconnected systems. If prices are high on neighbouring wholesale markets, operators have an incentive to sell significant output in those areas. This may lead to a temporary reduction in the reserve margin in the area of origin, and therefore push prices up; in other words, price peaks are imported from neighbouring regions. In the past, regulators have frequently needed to intervene for this reason. As mentioned earlier, the PJM has the lowest average prices (baseload prices at around USD 20/MWh compared to around USD 36/MWh on the NYPP and over USD 43/MWh on the NePool). Price peaks are however rather frequent, and generally fall between USD 100 and 200/MWh, although in , prices even peaked above USD 300/MWh. Note that prices peak at the same time on all three markets, showing that regardless of their levels, the three markets are closely linked. The markets have similar levels of volatility, both as regards price peaks and baseload prices. Interestingly, the volatility of baseload prices on these markets is comparable with that on the Spanish market. Fig. 19 Average prices and daily volatility on baseload prices on the PJM, NYPP and NePool PJM NYPP NePool* Avg prices $/MWh Volatility Avg prices $/MWh Volatility Avg prices $/MWh Volatility n.a. n.a. *data available to 28/02/03 Source: Banca Intesa from Bloomberg data Fig. 20 Average prices and daily volatility on peakload prices on the PJM, NYPP and NePool PJM NYPP NePool* Avg prices $/MWh Volatility Avg prices $/MWh Volatility Avg prices $/MWh Volatility n.a. n.a. *data available to 28/02/03 Source: Banca Intesa from Bloomberg data 34

36 The Italian Power Exchange Fig. 21 and 21b Average baseload and peakload prices on the PJM, NYPP and NePool* $/MWh $/MWh /01/01 01/03/01 01/05/01 01/07/01 01/09/01 01/11/01 01/01/02 01/03/02 01/05/02 01/07/02 01/09/02 01/11/02 01/01/03 01/03/03 01/05/03 01/07/03 01/09/03 01/11/03 01/01/04 01/03/04 01/01/01 01/03/01 01/05/01 01/07/01 01/09/01 01/11/01 01/01/02 01/03/02 01/05/02 01/07/02 01/09/02 01/11/02 01/01/03 01/03/03 01/05/03 01/07/03 01/09/03 01/11/03 01/01/04 01/03/04 NePool NYPool PJM *data available to 28/02/03 Source: Banca Intesa from Bloomberg data NePool NYPool PJM The most interesting factor on other markets is that of congestion prices. The analysis of congestion prices on the NYPP clearly shows how these are nearly always present during peaks, while volatility is fairly high volatility and has increased over the last year, following particularly serious problems on the grid in The average congestion price is not high (around USD 11/MWh) and, given the low volumes, it only adds around 0.1 cents/kwh to consumer prices, which is comparable to that paid implicitly in the zonal prices on the other two systems. Fig. 22 Congestion prices on the NYPP* 10 01/01/01 01/03/01 01/05/01 01/07/01 01/09/01 01/11/01 01/01/02 01/03/02 01/05/02 01/07/02 01/09/02 01/11/02 01/01/03 01/03/03 01/05/03 01/07/03 01/09/03 01/11/03 01/01/04 01/03/ $/MWh On peak Off peak * average congestion prices are usually indicated with a minus sign Source: Banca Intesa on Bloomberg data On the other markets, interest in the FTR market is growing, while volumes and prices on capacity markets are of little significance. The real-time ancillary services, congestion and capacity markets do however make up a significant portion of the wholesale electricity price paid by consumers. 35

37 Industry Report May Financial power exchanges in Europe The financial power exchanges that we have considered for this report (EEX, PowerNext, APX and UKPX) have the following aspects in common: They do not provide merit orders; planning and management are worked out independently by the local network operator (or operators). They generally provide products that reflect the trading methods used on the market, especially baseload and peakload contracts and a market for spot trading on an hourly basis (mainly for balancing purposes). They provide different price indices for evaluating market performance, especially as regards elements underlying derivatives contracts. Furthermore, these exchanges have or plan to acquire in the near future a futures market with traditional maturities (weekly, monthly or quarterly futures contracts). Some of the exchanges also operate as clearing houses for OTC-traded derivative contracts (mainly swaps or CFDs). The success of these power exchanges therefore depends on the credibility that they have acquired with operators and their ability to offer alternatives to the bilateral contracts traditionally used by electricity market producers and consumers. The more successful these markets are in attracting clients, the more liquid the market becomes, and the prices that emerge then become benchmarks. Thus, the critical success factors for these markets are trading volumes and product volatility. Fig. 23 Volumes and volatility on financial power exchanges in Europe EEX PowerNext APX UKPX Volumes (TWh/month) Volatility (historical) Source: Banca Intesa from Bloomberg data and figures from power exchanges It is immediately apparent that the volumes traded are lower than on the physical power exchanges discussed above although the parameters used to assess them are different while market volatility is greater. This is because electricity is traded on the market in various forms, using different types of financial contract, and it is no longer simply physical production that is sold on the power exchange. However, relatively high volumes are traded on the German EEX market, which is the market used by the main electricity traders on continental Europe. Volumes traded on the French PowerNext exchange are still somewhat modest, partly because it was the last to open, but also because of a high degree of concentration on the French market, which represents a high barrier to entry. The low trading volumes, as well as the financial characteristics of the products, tend to increase price volatility. This is particularly high on the Netherlands APX market, because transit limits on import lines mean that prices can be easily manipulated, which threatens to damage the market s reputation and its development. The UK market, meanwhile is small, but growing. 36

38 The Italian Power Exchange Fig. 24 Average prices on European power exchanges January 2001-March /MWh /11/01 26/12/01 26/01/02 26/02/02 26/03/02 26/04/02 26/05/02 26/06/02 26/07/02 26/08/02 26/09/02 26/10/02 26/11/02 26/12/02 26/01/03 26/02/03 26/03/03 26/04/03 26/05/03 26/06/03 26/07/03 26/08/03 26/09/03 26/10/03 26/11/03 26/12/03 26/01/04 26/02/04 Source: Banca Intesa from Bloomberg data UK Germany Powernext APX The characteristics of these markets mean that prices tend to peak more often, particularly on Spain s OMEL. Figure 24 shows average prices for hourly spot contracts on the main markets. Peaks on physical exchanges occur more frequently and reach higher levels, particularly on the Dutch market European power exchanges in detail EEX Germany s EEX (European Energy Exchange), based in Leipzig, is the product of the 2002 merger between the LPX (Leipzig Power Exchange) and the former EEX, which was in Frankfurt. The LPX was managed by NordPool, and was based on a day ahead hourly spot market, while on the former EEX, only block contracts (baseload and peakload) were traded. The new EEX has elements of both: it is based on an hourly day ahead market, although pre-defined blocks of hours are also available for day ahead purchase and sale, which are therefore considered spot contracts for the electricity market. The market operates via a price/quantity auction for the day ahead market and structured products for blocks of hours, which are currently: - Off-peak contract I (1am - 8am); - Off-peak contract II (9pm - 12am); - Night (1am - 6am); - Morning (7am - 10am); - Business (9am - 4pm); - High Noon (11am - 2pm); - Afternoon (3pm - 6pm); - Rush Hour (5pm - 8pm); - Evening (7pm - 12am). 37

39 Industry Report May 2004 In addition to hourly contracts and those covering blocks of hours, contracts in which the underlying element is the hourly prices of the day ahead market for base hours and peak hours (and separately, for the weekend) can be traded on the EEX via the continuous trading system, rather than the hourly auction process. More recently, the EEX has begun offering the opportunity to trade futures contracts, with weekly, monthly, quarterly and yearly maturities. The latest launch by the EEX concerns clearing services for OTC contracts on the German market. Volumes rose continuously on the EEX until 2003, largely driven by the launch of futures trading. Of the 30 TWh currently traded on the EEX, almost 25 TWh relates to futures. Of these, annual contracts account for the majority of contracts traded (almost 75% of the total), while weekly and monthly contracts are more liquid. Quarterly contracts cover volumes of just over 3 TWh, while monthly contracts account for just under 2 TWh. Note that of the 25 TWh traded as futures contracts, at least 15 TWh relates to OTC contracts, which therefore represent the lion s share of contracts traded on the German market. The auction-based spot market (both hourly and for blocks of hours) accounts for trading volumes of just over 5 TWh, while continuous trading has yet to make an impact (48 GWh/month). The EEX is currently the main market for Germany and most of continental Europe, particularly for futures transactions. It acts as a benchmark for transactions on the Benelux markets (in competition with the Netherlands APX), the Baltic states and Poland (in competition with NordPool), and other markets in eastern Europe (Hungary, Czech Republic, Slovakia) that are net exporters to Germany. Given the large volumes traded between France and Germany (mostly from France to Germany), the EEX also provides the benchmark price for French exports, and with the opening up of the French market, it could become an electricity trading hub for continental Europe. Prices are fairly stable, with averages at just over EUR 29/MWh for baseload contracts and just over EUR 37/MWh for peakload contracts between January 2003 and 15 March Importantly, the difference between the two prices has been relatively constant, indicating a degree of market stability, except for a couple of brief periods at the beginning of 2003, and during the dry period the previous summer, when peak prices soared (often above EUR 150/MWh), expanding the spread between contracts. Volatility, however, was rather high (67% for baseload prices and over 160% for peakload prices), highlighting what was a particularly difficult year for the central European electricity market. 38

40 The Italian Power Exchange Fig. 25 Difference between baseload and peakload prices on the EEX, January 2003-March /MWh /1 23/1 14/2 8/3 30/3 21/4 13/5 4/6 26/6 18/7 9/8 31/8 22/9 14/10 5/11 27/11 19/12 10/1 1/2 23/2 Source: Banca Intesa calculations from EEX data PowerNext Launched in November 2001, the French power exchange PowerNext is less developed than its German counterpart. PowerNext is 51%-owned by a joint venture between the Euronext market and a company (HGRT) formed by French, Belgian and Dutch network operators, while the other 49% is owned by large financial institutions and electricity operators (BNP Paribas, EdF, Electrabel, Société General, Total, Endesa and Atel). Trading is so far limited to around 1 TWh/month, on an hourly day ahead basis only (the corresponding German market is therefore five times larger). In June 2004, a number of futures products were launched: baseload (ie 24 hours) and peakload (from 8am to 8pm on working days), with monthly (one, two or three months), quarterly and yearly (one or two years) maturities. The aim is to repeat the success of the EEX futures market. Established as a national power exchange, Powernext is destined to become a competitor of Germany s EEX. Despite the lower volumes traded, however, PowerNext displays similar levels of volatility to EEX (historical standard deviation of 2.60 versus 2.47 for the EEX) and comparable prices (average price in 2003 EUR 29.35/MWh). The correlation between the average daily prices recorded on the two power exchanges is particularly high: between November 2001 and March 2004, the correlation was around 92%, indicating that these two major markets are converging, and that there is a movement towards supranational power exchanges, whereby network constraints do not prevent the flow of considerable quantities of electricity. 39

41 Industry Report May 2004 Fig. 26 Daily prices on the EEX and PowerNext, November 2001-March /MWh /11/01 26/01/02 26/03/02 26/05/02 26/07/02 26/09/02 26/11/02 26/01/03 26/03/03 26/05/03 26/07/03 26/09/03 26/11/03 26/01/04 EEX Pow ernext Source: Banca Intesa calculations from Bloomberg data APX The Amsterdam Power Exchange (APX) is a non-compulsory exchange based in the Netherlands. It opened in May 1999 and is run by the Dutch grid operator TenneT, and is one of the first European power exchanges to be structured since its launch as a day ahead market only, with hourly spot transactions (on which prices are calculated using indices for electricity sold as baseload and peakload). The way the APX operates has always been controversial with operators. Effectively, the fairly modest trading volumes (a record of 1 TWh/month was reached only recently), and in particular, the geographical location of the Dutch network, which is subject to bottlenecks on the import lines from France and Germany, have led to a very high level of average price volatility (historical standard deviation of over 6.4, while in 2003 average volatility jumped to 9.98). It is clear that in this situation the risks for operators were far too high, and potentially discouraging to operators. The Dutch authorities have frequently run investigations to see if prices were being manipulated. In particular, the main foreign operators were suspected of reducing transmission capacity into the Netherlands, thereby creating artificial shortages on the Dutch market and inflating prices. There is nothing new in this, however: the same phenomenon has often been observed on the US market, and was the subject of fierce debate during the Californian electricity crisis. This is an example of the risks that can arise in a liberalised market. In practice, the Dutch market has registered record prices the most often, even when there are no shortages (as there were last summer), which is why the market has lost some credibility with operators. Another difficulty for the Dutch market comes from the strong competition represented by the EEX, which has an advantage in terms of size and types of product, and by Powernext, which in a short space of time has grown to be the same size as the APX. In our view, the APX could continue to maintain its position, given that there are relatively few interconnections between the Dutch and French and German markets, while in the medium term it looks set to be overshadowed by the other European markets. 40

42 The Italian Power Exchange Fig. 27 Average daily prices on the APX, January 2001-March /MWh /01/01 08/04/01 08/07/01 08/10/01 08/01/02 08/04/02 08/07/02 08/10/02 08/01/03 08/04/03 08/07/03 08/10/03 08/01/04 Source: Banca Intesa calculations from Bloomberg data UKPX The New Electricity Trading Agreement (NETA), which came into force in 2000, changed the UK market significantly, from a compulsory power exchange to a solely bilateral market, except with regard to the selection of balancing resources in real time. The change from a compulsory system did not, however, result in the disappearance of all organised markets. Taking an independent approach, three markets emerged with the aim of acting as market places for certain standardised products and operating as a clearing house for OTC contracts, which were expected to see major growth. Of the three markets, the IPE (International Petroleum Exchange) folded very quickly, while the two others are still operating: the APX (Automatic Power Exchange), operated by a specialised supplier of IT systems for commodities risk management, and the UK Power Exchange launched by OM, the company that manages the exchange in Stockholm 26. The UK Power exchange has been the most successful of these markets, and is therefore described here. The UKPX manages a broad product portfolio, and: acts as a trading platform for daily spot contracts (divided into working and non-working days) and half-hour spot contracts (also organised into blocks of two and four hours); also operates as a trading platform for a large number of futures contracts (weekly, monthly, quarterly and yearly); operates as a matching broker recognised by the UK financial authorities for OTC products. After a difficult start, partly caused by the change in regulations that led to a situation of oversupply on the UK generation market, sending prices tumbling and triggering a financial crisis for several projects and companies, the UKPX seems to have gradually found its feet particularly over the last year as volumes increased fivefold to around 1.5 TWh per month. In addition to industrial operators, several financial institutions specialising in 26 The UKPX is in the process of being acquired by the Amsterdam Power Exchange 41

43 Industry Report May 2004 the commodities market began operating on the market, attracted by the increase in average prices from around EUR 10/MWh to EUR 15/MWh, thereby boosting liquidity as indicated by an accompanying increase in volatility, although this remained below the levels typical of financial exchanges, and is still very low (standard deviation of 0.72). While continuing to be dominated by OTC transactions, which as in Germany accounted for far higher volumes than on centralised markets, the UKPX is gradually establishing its credibility. Fig. 28 Average daily prices on the UKPX, January 2001-March /MWh /01/01 08/04/01 08/07/01 08/10/01 08/01/02 08/04/02 08/07/02 08/10/02 08/01/03 08/04/03 08/07/03 08/10/03 08/01/04 Source: Banca Intesa calculations from Bloomberg data 4.3 Nordpool The NordPool is the exchange covering the main Nordic countries, and is largely considered to be the most successful example of all the centralised electricity markets. It was founded in 1995, and has undergone several changes since then, to the extent that it now represents a model that would be difficult to copy in other countries. The NordPool was formed after the initial merger of the Norwegian and Swedish electricity markets, which were later joined by the Danish and Finnish markets, and more recently by the market based in the Dutch province of Zeeland. NordPool started out as a physical market, in which a merit order divided into zones was defined on a dynamic basis depending on electricity flows onto the grid, or market splitting (this is different from the zonal system used by the Italian market, where the areas are pre-defined). The use of market splitting means that different prices can be defined for each zone, while the zones can be modified within reasonable limits depending on where bottlenecks are identified. As a result, NordPool provides national grid operators with indications of the merit order relative to plant production, in relation to the proportion of supply that goes into the centralised day ahead market (called NordPool Elspot). The grid operators then compare these results with the capacity sold on the grid via bilateral (or forward) contracts, and define the merit order and the zonal division of the market. Around 30% of the electricity consumed in the countries mentioned passes through Elspot (112 TWh in 2002). Because Elspott is well-run and has proved successful, the company has been encouraged to extend the products offered by NordPool especially physical products, via the Elbas 42

44 The Italian Power Exchange balancing market, in which the necessary resources for dispatch in real time are selected (just under 1 TWh in 2002). However, NordPool s real success stems from two other products: futures contracts with traditional monthly and quarterly maturities (up to two years) traded on the Eltermin market, which does not appear to be very liquid; in particular, the function of clearing house of the growing OTC market in the Nordic countries, a market which has grown enormously since 2000 on the back of substantial growth in forward and swap contracts (mainly CFDs). Contracts covering around 150 TWh/month are traded and cleared on NordPool (in practice these are cleared more often than traded). NordPool has two major advantages: i) offers are extremely competitive, due to the presence of a large number of operators, especially in Norway; ii) prices are very low thanks to the mix of hydroelectric and nuclear power (except in Denmark). Because of such favourable conditions, the regulators have built a market model that takes into account the region s physical characteristics (imposing a zonal pricing mechanism) as well as its contractual characteristics (the long tradition of medium-term bilateral contracts, which usually last for a year), thereby ensuring that the market operates efficiently. However, the Nordic market model has also been criticised for a number of reasons. First, the market s dependence on hydroelectric power was the cause of some criticism during last year s dry period, as prices soared and even after the reservoirs had slowly filled up again average prices were far higher than historical levels (over EUR 36/MWh, versus EUR 25/MWh in ). These problems could have been eased, according to some observers, by investment in gas cogeneration plants, taking advantage of substantial resources in the North Sea. Second, criticism has been levelled at the modest performance of futures contracts on the NordPool (trading actually fell last year), which have not appealed to operators in the same way as bilateral and CFD contracts traded on the OTC market. Third, some observers have questioned whether deregulation was really necessary, given that prices in Sweden and Norway were already the world s lowest and that shortages were virtually unknown; however, the issue of whether a regulated monopoly or liberalised market would be preferable has yet to be resolved as regards both NordPool and the other deregulated markets. 43

45 Industry Report May 2004 Fig. 29 Average daily prices on the NordPool, January 2001-March /MWh /01/01 08/04/01 08/07/01 08/10/01 08/01/02 08/04/02 08/07/02 08/10/02 08/01/03 08/04/03 08/07/03 08/10/03 08/01/04 Source: Banca Intesa calculations from Bloomberg data 44

46 The Italian Power Exchange Appendix 1: The reserve market and transitional payment system for capacity in 2004 After the blackout of September 2003, one of the measures taken to ensure that the power system would be both adequate and secure was the setting of a payment for companies prepared to make capacity available at critical times (ie times of greatest demand) during the year, by means of market mechanisms. Through ministerial decree 379/03, the industry ministry set guidelines for the capacity market, and also put in place a transitional mechanism of fixed payments for The AEEG incorporated the guidelines in its resolution 48/04. The guidelines for the future capacity market relate essentially to methodology and the rules governing how the market itself will work are still being drawn up. The procedures put in place by the ministry and the AEEG governing the transition period are of more immediate interest however. First of all, they are aimed at safeguarding the adequacy of Italy s power generation system, that is, its ability to cope with shortages of supply at times when demand is critical 27, in the medium to long term. The consultation document therefore largely redefines the reserve capacity payments 28 until a market procedure for supplying these resources is established. This therefore defines the regulations for assigning the payment r f, for an approximate total of EUR m for The basic concept is that these payments should go to parties that make capacity available at the critical times identified by the GRTN. These payments consist of : A monthly payment and; An additional payment aimed at compensating for loss of revenue compared to what would have been generated if official tariffs had been in force (in the event of different prices emerging on the power exchange. The method proposed by the AEEG will be integrated with the dispatch regulations established by resolution 168/03, and establishes that: As set out in article 5 of decree 379/03, all plants within Italy s national borders are eligible for payment, except CIP6 plants (for which there are already generous incentives to make their power available), nonprogrammable renewable sources, and the share of power already committed in bilateral contracts outside the offer system; The capacity that must be made available by parties that demand it, is equal to the difference between the maximum power declared by a party and the total amount of power to be put on the grid in accordance with the bilateral contracts; The monthly payment is differentiated between the hours of peak and medium criticality, on the basis of total output as defined by the AEEG. The formula for calculating this, which fits with the new bands set by the AEEG, is, for each hour of high criticality: 27 Critical days are determined by the GRTN. 28 Note that alongside reserve capacity there is remuneration of reserve energy, that is, payment for the amounts actually made available by operators in real time. This reserve will be supplied from the dispatch market. Overall therefore, the cost of reserve when the system is fully operational may be higher than at present. 45

47 Industry Report May 2004 CAP AC 1, F = GCAP 1 α * * β AC MW AC F where G CAP1 is total output made available by the AEEG for the capacity made available in the hours of high criticality; α is the distribution coefficient between the hours of high and medium criticality, and is equal to 0.7; MW is the available productive capacity estimated by the GRTN; and β is the conversion coefficients of the various times in the time bands of days with high criticality 29. As stated above, the additional payment is a function of any differences between the revenue on the basis of present tariffs (RICR) and the price that will be set on the exchange (RICE). It will be made only if the difference between the two is positive. The RICR revenue is calculated by multiplying the PGn price and the energy sold on the wholesale power market at critical times, while RICE is calculated by multiplying the maximum difference between the average hourly price of electricity on the wholesale market and the PGn multiplied by a coefficient of 0.8, for the quantities sold during the same critical hours. Any positive difference in favour of producers cannot in any event be more than S i a figure set by the AEEG. The charge arising from these payments will be paid, as now, by the users of dispatch services withdrawing electricity from the grid. The component, called CD and set by the GRTN, will be fixed as equal to the present component r f. To maximise the capacity made available to cover demand on critical days, the AEEG stipulates that producers wishing to be remunerated for upgrading capacity can propose to their end users that the existing contract is terminated and a contract for difference is drawn up, guaranteeing the same volumes and prices as the previous contract. If the end user does not accept this proposal, the producer may terminate the contract without notice. The AEEG believes that this transitional mechanism will remain in force until the end of Meanwhile, rules will have to be established to secure reserve capacity through market mechanisms, which should replace the administrative mechanism (and therefore the CD component) described above for the transition period. At present, the guidelines are set according to the first four articles of ministerial decree 379/03. The GRTN is responsible for setting the future market s regulations for reserve capacity within six months of the decree s publication (that is, by the end of June), following the AEEG s final decision, which will come into force after its consultation document. The capacity market will clearly have to ensure that the price is transparent and non-discriminatory, sufficiently high to safeguard the system s adequacy, and at the same time does not impose extra costs on consumers. The price that emerges, if effective in practice, should tend towards the long-term marginal cost of a peak plant. The GRTN must therefore not only establish the capacity the system needs to function adequately, but also set the appropriate rules for this market to work efficiently. 29 The formula is naturally mirrored for days of medium criticality, with the coefficient α equal to 0.3 and with the figure MW that is established for times of medium criticality. 46

48 The Italian Power Exchange Appendix 2: Load profiling and resolution 118/03 By Osservatorio Energia REF Load profiling is a term for the procedures used to calculate the usage profiles of customers who do not have an hourly meter. It is therefore an important mechanism for the regulation of payments for wholesale electricity allocated to these customers under the new system of hourly management, which has been in place since the launch of the power exchange. The various types of load profiling that can be applied are described below, as are the procedures chosen by the Italian regulator through resolution 118/03. A.1 Summary of the various methods Load profiling (LP) is the study of the electricity consumption habits of groups or categories of consumers, to estimate the amount of power they use each hour and produce load profiles, which can be calculated using various techniques. This is not a new development resulting from market liberalisation, but a tool that has long been used for system planning and for regulatory purposes; liberalisation has however changed its role and value. LP is a second best choice compared with hourly metering of all consumption but, in the medium term, it is needed to help develop competition in the power market and especially in the provision of supply, as it allows all end users even those not yet equipped with an hourly meter to choose their supplier. The techniques, methods, and forecasting models used depend on a number of technical factors related to costs, but also on economic policy issues and the context in which these are applied. Techniques for building profiles Consumers are categorised according to common characteristics (such as geographical location and economic consumption category), and each group is given a profile. Various approaches can be used to define load profiles: these vary in complexity, accuracy, and naturally cost (because of the information needed and the time and cost involved in gathering it). The basic criteria in choosing an LP method are accuracy and sophistication of the estimates it produces, and the cost of producing or improving these estimates. The choice of the best method is subject to various limitations, such as the availability of the necessary data and other information, technology that makes gathering these easier and the time needed. The more complex and accurate methods also cost more, and the trade-off between cost and accuracy is vital in choosing the method. The choice cannot therefore be the same for any system, but depends on the nature and limitations of the system where it will be applied. These methods are briefly outlined below and can be grouped in three main categories: System Residual Profiling; Load Research Sample; Deemed Profiling. The first group contains methods that calculate profiles based on the system s load curve: System Load Shape (SLS) and Net System Load Shape (NSLS). The second contains dynamic statistical methods (Lagged 47

49 Industry Report May 2004 Dynamic Load Profile, True Dynamic Load Profile), which use data for the day in question to determine load profiles, and static statistical methods (Static Load Profile), which are based on analysis of historical data, mixed methods (static but corrected with current data Adjusted Load Profile), and methods based on economic, econometric or statistical models, which estimate profiles by looking at the current trends in certain variables that affect electricity use (Proxy Day Load Profile). The third group contains all the methods used to build load profiles for consumption classes whose use is predictable (for example street lighting and traffic lights). These are called Non-Metered Load Profiles, and can be calculated using an engineering approach, calculating the hourly pattern of this consumption using data from other areas or by combining different approaches. The various methods are outlined below. System Load Shape and Net System Load Shape These two methods, which are very similar, use a single curve to describe consumption by all consumers not equipped with an hourly meter. SLS uses the system s load curve, while NSLS uses the load curve excluding use by consumers with hourly meters and adjusted to allow for leakage. The main disadvantages of these two methods, which must be balanced against their extreme simplicity and almost zero cost, are their highly generic nature, which limits their ability to reflect true consumption since they do not distinguish between users. The NSLS method (on which the LP by area used in Norway is based) reduces the problem, albeit minimally, by introducing greater homogeneity. Static Load Profiling and Adjusted Static Load Profiling This method produces approximate load curves for typical days and user categories, based on historical averages for electricity use; these are used to calculate static consumption profiles. This method is also a simple way to calculate and manage profiles, is easily understood by market players, and produces highly accurate estimates. However, two of these advantages have attendant disadvantages. Because of its simplicity, the method risks overlooking factors that may have considerable impact on consumption; and accuracy has its cost in the price paid to gather the information and the financial resources needed to implement the method (including research on consumption, sample selection, and the time needed to gather historical data on consumption, which is at least 24 months). Adjusted Static Load Profiling has the special feature that it allows typical profiles to be corrected based on figures for certain specific variables that affect the day for which use needs to be estimated (the target day). Proxy Day Load Profiling This method uses models and theoretical hypotheses regarding the impact of certain variables on electricity consumption. To forecast use on the target day, it uses consumption figures for a sample of consumers during a day that has features in common (for example, the same air temperature). This retains the simplicity of the static method but takes into account the impact of various factors on consumption, producing even more sophisticated forecasts. However, it also introduces a model a set of theoretical hypotheses on how consumption should be forecast and therefore also risks connected to errors in calculating the theoretical model. It is also less readily understandable and thus less readily accepted by market players. Like the static method, but perhaps more so, it involves high research costs and long implementation timescales, in the absence of historical data (at least 12 months before the first day on which consumption is forecast). 48

50 The Italian Power Exchange True Dynamic Load Profiling and Lagged Dynamic Load Profiling True dynamic load profiling is defined as the daily analysis of a sample of consumers drawn from those whose consumption is measured on an hourly basis, in order to produce load profiles that reflect the true current use by consumers not metered on an hourly basis on a given target day. Dynamic profiles offer sophisticated and prompt forecasts that reflect the impact of factors on consumption. It does not use models, which reduces the risk of errors and makes it easier for market players to understand. Applying the dynamic profile method does not require a long series of historical data gathered over months or years one of the main limitations in building static profiles but it is the most costly forecasting method because all consumers in the sample need remote meters that not only record data for hourly use but transmit them so that they can be gathered and analysed daily. Lagged Dynamic Load Profiling differs in the frequency with which data is gathered and analysed, and usually operates alongside other methods for settlement operations. Non-Metered Load Profiling Consumption due to street lighting, traffic lights and other use that does not involve hourly meters may be measured per hour using engineering methods. Typically, the total amount and duration of this use is known, so building profiles for different times of the day that take into account variations in certain parameters, such as sunset and sunrise times, is fairly straightforward. Load Profiling by Area and Load Profiling by Category The methods described above may give rise to various LP models depending on which are used and how they are applied to a given electrical system. The two main LP models applied in highly liberalised European sectors are LP by area and LP by category, the first in Norway and the second in the UK. Load Profiling by Area This belongs in the NSLS method category. However, the load curve used as a basis for calculation is not that for the whole system but for a given area considered a subsystem in its own right. Curves are therefore not determined in advance, but on the basis of figures for hourly energy input into the system (area). Electricity use for each area is subtracted from this figure to give an Adjusted Area Load Profile (AALP) and from this in turn, leaks are subtracted (as a percentage of AAL or as a forecast figure). The figure thus obtained is no less than total consumption, hour by hour, in the area in question, which must then be applied to consumers without hourly meters (for example, based on consumption). The most critical aspect of this process is determining the amount to be attributed to each consumer, since the grid operator s unbalanced positions relating to dispatch and supply are set based on this amount and the figure for leakage. The main advantages of this method are its simplicity, low cost (because limited information and technological input are needed), and rapid implementation, which allows the market to be opened up to all end users more quickly than when hourly meters are used. Load Profiling by Category This subdivides consumers into categories according to the typical features of their use. It then applies a consumption profile to each category and 49

51 Industry Report May 2004 based on this classification, allocates electricity consumption, net of consumption measured with hourly meters, among consumers not thus equipped. The underlying principle is to group consumers into homogeneous categories believed to use electricity at similar times. This approach also distinguishes between the various methods of forecasting profiles for each category (static, dynamic, and engineering-based) through which each category is assigned a coefficient from which total use during each hour is calculated. Since this involves profiles calculated in advance, this does not guarantee that the total forecast use matches total use by non-metered users on an hourly basis, and consumption above or below forecast needs to be distributed among individual consumers. The imbalance between actual and forecast consumption by end users leads to uncertainty regarding the use that suppliers will experience hour by hour. This method can produce accurate forecasts and allows the difference between the consumption habits of different groups of users to be taken into account, but it is more complex and generally more expensive than LP by area, partly because it requires mechanisms to correct errors in forecasts. A.2 The Italian option: AEEG resolution 118/03 With resolution 118/03, AEEG opted for a similar mechanism to that used in Sweden and Norway: load profiling by area, which differentiates load profiles on an hourly basis between different regions but without distinguishing between types of customer, mainly for reasons of simplicity. The main elements outlined in resolution 118/03 are: area; area residual use; distribution of area residual use; calculation of financial terms and conditions. The profiles of users not equipped with hourly meters are determined using the various areas into which the system is divided as a reference point. The total hourly consumption of both free and franchised customers not equipped with hourly meters can be calculated for each area: this is called the area residual use. It is assumed that the load profile of each individual user is the same as the overall area profile, and the electricity used in a given hour is divided among users based on coefficients fixed in advance. The difference between the power calculated on the basis of the coefficients and that actually used over the year determines the payment of the financial terms through an annual adjustment. Area This defines the section of the grid on which the load profiles are calculated. It consists of all the injection and withdrawal points within a single zone of the system belonging to a distribution company that has at least one connection point to the high-voltage grid. This last is defined as the main distribution company; secondary distribution companies which have no high voltage connection may be linked to its grid directly or indirectly through other secondary companies. Where a secondary distribution company is linked to several main distribution companies, it will be included in the area of the distribution company with most connections to the highvoltage grid. 50

52 The Italian Power Exchange Area residual use This defines the hourly withdrawal profile and is calculated as the difference between: hourly injections at interconnection points with other areas or with the national transmission grid and at the entry points in the area in question, and; hourly withdrawals at interconnection points with other areas or with the national transmission grid and at withdrawal points equipped with hourly meters within the area in question. Where injection and withdrawal cannot be measured on an hourly basis, conventional profiles are adopted thus: use for public lighting will be measured by means of engineering-type load-profiling mechanisms, to be defined by a forthcoming AEEG resolution; injection and withdrawal at interconnection points with other areas or with the national transmission grid and at entry points not equipped with hourly meters will have a constant profile at all hours of the day; injection and withdrawal at interconnection points between distribution companies in the same area not equipped with hourly meters will have the same profile as the area as a whole. Furthermore, all medium- and low-voltage use points in the franchised market will not be treated on an hourly basis, even where they have hourly meters. Distribution of area residual use An area s residual use is divided between the different users using coefficients calculated in advance. The relevant users are the holders of dispatch contracts and, therefore, for the franchised market are the guarantor of supplies to franchised customers, and for the free market the end users themselves or, more accurately, the wholesaler that supplies them. The coefficient for dividing use between customers not subject to hourly metering is calculated as the ratio between: electricity used during the previous year by all customers not subject to hourly metering included in the same dispatch contract and belonging to the same area, and; electricity used during the previous year by all customers not subject to hourly metering in the area. Area residual use by the guarantor of the franchised market is calculated as the difference between the total residual use of the area and the use attributed to all other users of dispatch services. To pass costs on to franchised end users, the use attributed to the guarantor of supply to the franchised market for a given area will be further divided up if more than one distributor is present. Coefficients are determined based on franchised consumption broken down by individual distributor in relation to the total franchised consumption in the area, always using figures for the previous year. Given that there may be considerable variation in the makeup of customers subject to load profiling over a year, coefficients will be updated monthly. The possibility that a customer may switch from the franchised to the free market, change supplier, install an hourly meter, or start or terminate a service connection can substantially alter the level of use relating to a 51

53 Industry Report May 2004 given dispatch contract. For this reason, the division coefficients are adjusted by the 20th of each month and are effective from the following month. Note that the adjustments only affect individual dispatch contracts; the calculation system is always based on figures for the previous year, not on consumption for the current year. The effects of these variations come into play when the coefficients are updated. If, for example, a free market customer installs an hourly meter, that customer will be treated on an hourly basis only from the first day of the second month after it has notified the distribution company of the change. Calculation of financial terms and conditions Because payments made based on coefficients set in advance may not correspond to the payments due for the electricity actually used, the GRTN operates a balancing payment mechanism. For withdrawal points not subject to hourly metering, users of dispatch services other than the guarantor of supply to the franchised market must, by 31 March, receive (if the balance is positive) or pay (if negative) the product of: the average price of the electricity used during the previous calendar year, calculated as an average, weighted by the area s residual use, of the hourly purchase prices on the day ahead market and the dispatch charges applicable to use in each individual hour (reserve and debottlenecking, but not balancing, for which regulations will be defined at a later date) and; the difference between the total electricity used during the previous calendar year (adjusted using standard leakage coefficients) and the electricity use attributed during the same year on the basis of the distribution coefficients for the area s residual area calculated in advance. By 31 March, the guarantor of supply to the franchised market must also deduct an amount for each area, where the net total relating to the users of other dispatch services is positive, or pay out an amount for each area where the net total is negative. In setting the financial terms and conditions, the GRTN uses agreements with distribution companies approved by the AEEG and, if figures do not refer to the calendar year, uses the daily pro rata criterion. 52

54 The Italian Power Exchange This material has been prepared by Banca Intesa. Information and opinions have been obtained from sources believed to be reliable, but no representation of warranty is made as to their accuracy or correctness. This report has been prepared solely for information purposes and is not intended as an offer or solicitation with respect to the purchase or sale of any financial products. This document may only be reproduced or published together with the name of Banca Intesa. 53