ESTUDIOS SOBRE LA ECONOMÍA ESPAÑOLA

M. Dolores Furió Julio J. Lucia

EEE 222

June 2006

ISSN 1696-6384

Las opiniones contenidas en los Documentos de la Serie EEE, reflejan exclusivamente las de los autores y no necesariamente las de FEDEA.

The opinions in the EEE Series are the responsibility of the authors an therefore, do not necessarily coincide with those of the FEDEA.

M. Dolores Furió * Julio J. Lucia

Departmento de Economía Financiera y Actuarial Universidad de Valencia Avda. de los Naranjos s/n 46022 – Valencia Spain

First version, March 2006 This (third) version, June 2006

Corresponding author.

Full postal address: Dpto. de Economía Financiera y Actuarial Facultad de Economía (Universidad de Valencia) Avda. de los Naranjos s/n 46022-Valencia Spain

Abstract

This paper empirically investigates how the economic incentives embodied in the rules governing the resolution of transmission constraints in the Spanish wholesale electricity market have influenced the trading strategies spanning all the sections of the market followed by buyers and sellers. The results show several facts with far reaching consequences. First, participants in the spot market follow dynamic trading strategies that span all the sections of the market, i.e. their strategies take into account the effects of participation in one section of the market over another. Second, the results show the importance of the structure of economic incentives implied by the regulations in explaining the trading behaviour of market participants. In particular, producers seem to be able to recognize and exploit the consequences of their role in the resolution of transmission constraints, and buyers respond to the way congestion costs are billed to them. Third, participation in the resolution of transmission constraints does not affect the revenues of all production facilities in the same way, due to the different roles they play in the procedure, coupled with the asymmetric reward scheme. Finally, the results shed light on what should be expected of the recent reforms in the aforementioned rules.

JEL classification: L51; L94

Keywords: Wholesale electricity market regulation; Transmission constraints; Strategic bidding; Market power

1. Introduction

As a result of the market-oriented reforms that have been taking place in many industrialized countries since the 1990s, new economic considerations have come into play in the restructured electricity industries. In particular, the structure of economic incentives introduced by each regulatory regime plays a central role in the behaviour of participants in the new wholesale spot electricity markets (including pools or exchanges as well as bilateral contracting) that lie at the core of the reforms throughout the world.

These new wholesale markets for electricity were intended to allocate production and determine prices in a competitive and efficient manner. In the Spanish case, the spot market for electricity (the so-called “production market”) comprises two sections or “markets”: the day-ahead market (named the “daily market”) and the closer-to-real-time “intra-day market”. Participation in the market is voluntary since bilateral physical trading is also permitted (although the bilateral trading volume has been extremely low to date).

Nonetheless, the technology of electricity generation, storage and delivery make a reliable transmission network a necessary condition for an efficient electricity market. As a large body of the literature on the new wholesale electricity markets has properly pointed out, technical factors underlying transmission network limitations and bottlenecks may have a crucial influence over the behaviour of generators, and thus these factors may significantly affect the resultant allocation of production as well as the final prices paid for the electricity.

This paper is aimed at investigating empirically, for the first time, how the dynamic trading strategies spanning all the sections of the Spanish electricity market followed by both buyers and sellers are influenced by the economic incentives implied by the rules and regulations that apply to the resolution of transmission constraints.

Several relevant conclusions can be reached from the empirical evidence provided in this paper. First, participants in the spot electricity market follow complex dynamic trading strategies that involve all the sections of the market. In other words, their dynamic strategies take the interconnections of their participation in both sections of the market into account. Second, it is shown that the trading behaviour of market participants in the two sections of the market is substantially influenced by the structure of economic incentives implied by the regulation governing the management of transmission constraints. In particular, buyers respond to the way congestion costs are billed to them by abandoning the daily market in favour of the intra-day market as far as possible. Additionally, the participation of producers in the intra-day market is strongly conditioned by the specific role they play in the resolution of transmission constraints in the daily market and the related asymmetric reward scheme. Third, several underlying technical factors explain the strategic role played by some generation facilities in the resolution of transmission constraints, and ultimately determine that the dynamic trading strategies do not affect the revenues of all production facilities in the same way.

Though many advances have been made in the analysis of the Spanish electricity market and the Spanish electricity industry at large, with diverse objectives, this paper makes several significant contributions to the existing literature.

First, this paper contributes to the literature that deals with the trading behaviour of participants in the Spanish electricity market. As far as we know, this is the first paper that explores the behaviour of the participants in the intra-day section of the Spanish electricity market. In the previous literature on the Spanish market, the intra-day market has largely been considered as unimportant or inconsequential, based on the fact that it represents a small fraction of the wholesale market in terms of volume of trading. Thus, virtually all the attention was paid to the day-ahead section of the electricity market. Though this focus may make perfect sense for some research purposes, we show that the intra-day section of the market deserves particular attention. It is, after all, an integrant part of the spot market and, as the analysis carried out in this paper clearly proves, it sheds light on the way traders use the spot market as a whole as well as on the type of motivations that underlie their behaviour. This contribution may be especially relevant for those papers aimed at modelling the strategic bidding behaviour in the Spanish power system, since our results show that there is a causal relationship between the participation in different sections of the market.

Second, by concentrating on the unexplored issue of the rules that govern the congestion management system, this paper contributes to highlighting the importance of the structure of economic incentives implied by the regulation of the Spanish electricity market on the behaviour of market participants. Most papers published to date that covered this topic concentrated on the effects that the structure of economic incentives implied by the recovery of stranded costs through the so-called Competition Transition Costs (CTCs) mechanism may have had on the generators’ bidding behaviour. It is generally admitted that, since the payments received by the incumbent generators through this mechanism are inversely related to the level of market prices, this has reduced the firms’ incentives to raise prices (see, for example, Green, 2001; Kühn and Machado, 2004; Campres and Fabra, 2005; Fabra and Toro, 2005). Other incentives analyzed so far have been those related to the capacity payments (they could have limited the amount of bilateral trading, since producers are entitled to receive capacity payments only if they participate in the daily market), as well as those included in the schemes for rewarding transmission and distribution firms (see Campres and Fabra, 2005). The issue of the economic incentives implied by the rules that govern the resolution of network constraints, however, remained largely unexplored to date.

Third, many authors have previously warned about the causal relationship between the existence of network congestion and the exercise of local market power, given the characteristics of the Spanish electricity industry (e.g. Fabra-Utray, 2004; Campres y Fabra, 2005). As a matter of fact, in 2004 the Competition Court (“Tribunal de Defensa de la Competencia”) found evidence of the exercise of local market power in the bidding strategies followed by some generation firms in the daily market in November 2001. The empirical evidence provided in this paper, which states that some generation units play a strategic role in the resolution of network constraints, coupled with the asymmetric payment scheme implemented to reward the firms’ contribution to the resolution of constraints, is closely related to this literature. It strongly suggests that some strategic generators might have followed bidding strategies trying to exercise unilateral local market power. A complete analysis of this possibility is, however, outside the scope of this paper and has been left for future research.

Overall, the facts reported in this paper can hardly be considered as episodic or anecdotal. On the contrary, we claim that important regulatory lessons can be extracted from them, which proves the far reaching consequences of our results. As a matter of fact, we briefly discuss some of these regulatory issues at the end, including the new rules that govern the resolution of transmission constrains since July 2005, in light of our results.

The remainder of this paper is organized as follows: A brief review of the features of the Spanish electricity market that are relevant from the point of view of this article is made in Section 2, to make this article self-contained.¹ Section 3 describes the data used in this paper and its sources. A general analysis of the energy involved in the procedure to resolve transmission constraints in the daily market together with their technical causes in the short run is carried out in Section 4. In Sections 5 and 6, respectively, careful analyses of the implications of the congestion management rules on the behaviour of buyers and sellers are performed. We conclude in Section 7 with some final remarks, including a discussion of the new rules that have been in force since July, 2005.

2. The Spanish Electricity Market

2.1. Overview

The Electricity Sector Law 54/1997, of 27 November 1997, constitutes the point of reference for the liberalization process of the electricity industry in Spain. Undoubtedly, one of the main consequences of this Law was the implementation of a competitive wholesale electricity spot market. The management of the new market was divided into two broad areas and assigned to two distinctive entities. On one hand, the Market Operator (Operador del Mercado Ibérico de Energía-Polo Español S.A., OMEL) is in charge of the economic management of the market. On the other hand, the technical management of the transmission system is entrusted to the System Operator (Red Eléctrica de España S.A., REE).

The electricity market is organized into two markets: a daily market, which is a day-ahead market to negotiate electricity for delivery in any specific hour during the following day, and a subsequent intra-day market, which is defined as an adjustment market in which participants may modify the positions previously assumed in the daily market (Royal Decree 2019/1997 of 26 December 1997).² Over-the-counter physical bilateral contracting is also allowed, although bilateral agreements have to be communicated to the market operator so as to facilitate the technical management of the system. 3

Every day, once the physical bilateral trades have been communicated and the daily market has been cleared, the system operator evaluates the technical viability of the dispatch schedule, in order to guarantee the security, quality, and reliability of supplies throughout the transmission grid. The main consequence of the congestion management procedure in the daily market is that the scheduled allocation of electricity supplies (bilaterally and market traded) can be modified due to security constraints and reliability requirements. Another consequence is that the system operator may also impose limitations on the intra-day market trades, aimed at avoiding further congestion. Additionally, another congestion management protocol is implemented after the intra-day market clearing, although the effects in terms of modifications of the resulting delivery commitments are much less important.⁴ Finally, the system operating processes also include the management of ancillary services and real-time imbalances. ⁵

¹ For a recent complete description and discussion of the Spanish electricity industry and the market, see for example Crampes and Fabra (2005). Arocena et al. (1999) and Green (2001) provide two early critical assessments of the reform. A recent very complete description and discussion in Spanish of the market is contained in the book by Fabra-Utray (2004).

² The California Power Exchange (CALPX), which stopped operations in January 2001, managed a day-ahead market together with the so-called “day-of market”.

³ From January 2000 to December 2005, bilateral trades remained close to 1% of the total electricity traded through the day-ahead market.

2.2. Daily Market

Supply-side participants in the daily market are essentially the Spanish electricity producers. Most of them are obliged to submit supply bids to the daily market for the amount of available capacity of their production units that has not been previously committed through bilateral trades.⁶ Demand-side participants in the daily market include: distributors, retailers, and qualified consumers.⁷ External agents (those located in external systems) can either buy or sell electricity in the daily market.

Participants in the daily market can submit their bids until 10:00 a.m. of any day (trading day, d) for delivery the subsequent day (operating day, d+1). They trade electricity independently for delivery in each one of the twenty-four hours of the following day, through 24 distinctive uniform price auctions. The market operator determines the corresponding dispatches and prices according to the market-clearing and marginal-price criteria. In other words, after appropriately ordering the purchase and sale bids, the resultant demand and supply curves are superimposed. The intersection between the curves determines the merit-order (unconstrained) dispatch as well as the marginal price (i.e. the price of the last accepted supply bid) for the corresponding hour. Each hourly (unconstrained) marginal price is received by all suppliers and paid by all buyers that have to deliver or take delivery in the corresponding hour.

A dispatch schedule, or Daily Base Operating Schedule (“Programa Diario Base de Funcionamiento”, PDBF, in Spanish) is formed by joining the resultant merit order dispatch in the daily market, the physical bilateral arrangements that mature on the operating day (d+1) and the scheduled dispatch by the available production units exempted from the obligation to present bids in the daily market (such as production units in the special regime) together. The market operator communicates this schedule, together with the out-of-merit order related to the daily market, to the system operator at 11:00 a.m., so as to evaluate its technical viability.

⁴ In 2005, for instance, the energy involved in the resolution of transmission constraints after the intra-day market only amounted to 0.62% of the energy required to modify the daily market unconstrained dispatch.

⁵ The management of ancillary services include several procedures: primary regulation, secondary regulation, tertiary regulation, voltage control, and service restoration (Royal Decree 2019/1997).

⁶ Basically, this obligation does not apply to small production facilities (with an installed capacity lower than 50 MW), producers under the so-called special regime (essentially, cogeneration, renewable energy and bio-fuelled production units), and self-producers (selling their surpluses).

Qualified consumers can freely choose to purchase electricity either totally or partially in the daily market, instead of under the regulated tariff regime. From 1 January 2003, all consumers become qualified consumers simply by getting registered in the special Register of Qualified Consumers. Distributors are obliged to purchase a fraction of production under the special regime, and the rest of their electricity needs must be covered through purchases in the daily market.

2.3. Resolution of transmission constraints in the daily market

Every hourly merit order dispatch, together with every hourly marginal price, included in the PDBF can be modified due to the consideration of security constraints and reliability requirements. In order to establish the necessary modifications, REE evaluates the PDBF sequentially. Firstly, it determines whether the available international interconnection capacity is exceeded, and it may withdraw either sale or purchase bids that involve international interconnections, accordingly. Secondly, the security and reliability constraints in the Spanish transmission system are considered. It is worth emphasizing that only production units take part in the procedure for resolving any transmission constraint (as a result, some production units may be required to run, while others may be required not to run), and the supplies for the previously matched demand remain guaranteed under any circumstances. This way, a security-constrained dispatch, or Daily Viable Schedule (“Programa Viable Diario”, PVD, in Spanish), is obtained before 2:00 p.m. (of day d), which includes the changes made to the PDBF.

The modifications made to the scheduled allocation of production of the PDBF also imply changes to the revenues of those production units involved in the resolution of transmission constraints. As far as this paper is concerned, until the end of June 2005, an asymmetric reward scheme was applied to the involved generation units that had previously participated in the daily market (Royal Decree 2019, of 26 December 1997). On one hand, the production units required not to operate took back the corresponding expected revenues (equal to the amount of electricity withdrawn from the PDBF multiplied by the marginal price). Thus, the withdrawal of energy from the scheduled dispatch did not imply any extra remuneration. On the other hand, the production units that were required to operate obtained an income that depended on the price of its pending (out-of-merit) sale bid in the daily market.⁸ In case there were no pending supply bids in the daily market, the electricity injected to the system in order to solve technical constraints was remunerated at the marginal price in the daily market increased by 15 per cent.

Hence, the difference between the price that was paid to the production units for the electricity added to the system and the marginal price in the daily market represents the cost derived from the

⁸ To be precise, the price used to remunerate the electricity required to solve technical constraints is the average of the out-of-merit block prices submitted to the daily market. This price can then be different for each production unit and for each hour. (An offer can be divided into a maximum of 25 blocks for each hour. Each block refers to a production load with a different price.)

management of technical constraints. That cost was billed to buyers in the daily market as well as to buyers trading bilaterally, proportionally to their relative consumption.

2.4. Intra-day market

Once the PDV has been determined, participants in the Spanish electricity market have the opportunity to again trade electricity with the same hourly delivery periods, at the intra-day market. Thus, participants can adjust their previous commitments in the electricity market before the actual delivery takes place.

The intra-day market consists of six (consecutive) trading sessions during which participants can submit sale and purchase bids for delivery of electricity in a given (decreasing) number of hours (as the operating hours approach).¹⁰ They are organized as uniform-price auctions in which the market operator determines the clearing prices (which are referred to as the intra-day marginal prices) by matching the hourly supply and demand curves.

With regard to the intra-day market participation rules, every production unit that is authorised to submit bids to the daily market can do the same to the intra-day market. However, the consumption units that are authorised to submit bids to the daily market may participate in an intra-day market session provided that they had previously participated in the daily market for the corresponding hourly delivery period. Additionally, as opposed to the daily market, both production and consumption units can submit supply as well as purchase bids to the intra-day market.

Once the market-clearing results are obtained, the system operator checks whether any new network congestion or reliability problems arise after the addition of the resultant delivery commitments to the PVD. If that were the case, a new process for managing transmission constraints would then be initiated. Based on a merit-order criterion, REE selects the purchase and sale bids previously committed in the intra-day market that have to be withdrawn from the system. Therefore, in contrast with the resolution procedure after the closing of the daily market, the new procedure can affect both production and consumption units, and transmission constraints are solved based on the bids made exclusively to the intra-day market. The cash flows generated in this case are settled by means of rectifications on the accounts of the involved units. The total cash inflow for the units that finally will not take delivery (of possibly only a fraction) of the energy is thus identical to the total cash outflow for the units which are ordered not to deliver the exact same amount of energy. No extra costs are generated in this procedure, since the total cash flows are computed by multiplying the amount of electricity withdrawn from the dispatch schedule by the hourly marginal price of the corresponding intra-day session.

⁹ During the first session (which opens at 4:00pm, day d) it is possible to trade electricity for delivery during any of the 24 hours of the following day, together with each one of the last four hours of day d.

¹⁰ The “day-of market” of the CALPX included three trading sessions (with operating horizons that included between five and twelve hours).

3. Data

In this section we detail the series of data used in this paper. The sources of raw data were OMEL and REE.

The series downloaded from the webpage of OMEL (www.omel.es) are: (i) the 24 series (one for each hour) of the daily energy added to resolve transmissions constraints in the daily market; (ii) the 24 series (one for each hour) of the daily marginal price in the daily market; (iii) the individual series for each generation company of the daily amount of energy traded up to the intra-day market (each datum is the aggregate of the energy sold in the daily market, the net energy involved in resolving restrictions in the daily market, and the energy traded in the intra-day market); (iv) the individual series for each generation company of the daily amount of energy traded up to the resolution of transmission constraints in the daily market (each datum is the aggregate of the energy sold in the daily market and the net energy involved in resolving restrictions in the daily market); and (v) the individual series for each generation company of the daily amount of energy traded in the daily market. Finally, we also retrieved a series of the monthly bilaterally-traded energy from the monthly Market Reports posted by OMEL on its web page. All the series were available for the sample period from 1 January 2000 through to 31 December 2005, except for the first one which was only available until 30 June 2005.

By subtracting the fourth series above from the third, we computed two new individual series for each company of the daily net traded energy (net sold energy, if the result of the difference is negative, and net purchased energy, if it is positive, respectively) in the intra-day market. We also computed a monthly arithmetic average of the marginal price in the daily market. Finally, we computed several series of monthly and annual data by aggregation of the corresponding series of daily data mentioned above.

The monthly Statistical Bulletins of Electric Energy (“Boletín Estadístico de Energía Eléctrica”) issued by REE (and posted on its web page: www.ree.es) provided us with the following series of monthly data: (i) the energy added to the system for resolving transmission constraints in the daily market; (ii) the energy traded in the intra-day market according to its final purpose (three pieces of data corresponding to, respectively, the adjustment of previously committed market positions, pumping needs, and consumption needs); (iii) the monthly average price in the resolution of congestion in the daily market; and (iv) the monthly weighted average price in the intra-day market. The available issues of the Bulletin were those from January 2000 to November 2005.

Additionally, REE provided us with individual series for each generation company of the monthly amount of energy added to and withdrawn from the PDBF in order to resolve transmission constraints in the daily market. The sample period for these series is: January 2002 to December 2005.

4. General analysis of the energy involved in the management of transmission constraints in the daily market

In this section we perform a general analysis of the evolution over time of the amount of power involved in the resolution of transmission constraints once the daily market is closed. (Recall that only production units are affected by the transmission constraints resolution procedure.) In particular, we concentrate on the importance of the general criteria applied by the system operator while managing transmission constrains. In the next two sections we will investigate in detail how congestion management rules and regulations may have influenced the trading behaviour of both consumption and production units.

4.1. Energy involved in resolving transmission constraints

Figure 1 depicts the total amount of energy involved every year in the transmission constraints resolution process in the daily market, at an hourly level (year 2005 only accumulates the energy for the first six months, due to reasons of data unavailability). After excluding the incomplete year 2005 from the analysis, two facts can be clearly identified. First, there is a clear hourly pattern closely related to the hourly pattern of demand. As a matter of fact, the maximum quantities of energy involved in the transmission constraints resolution process take place during the hours with the heaviest demand (in Spain, this typically occurs between 10:00 a.m. and 1:00 p.m. and, later, between 6:00 p.m. and 9:00 p.m.). Second, there are two anomalous years in the sample, namely 2002 and 2004. They include, respectively, the lowest and the highest levels of energy involved in the resolution procedure.

[INSERT FIGURE 1 ABOUT HERE]

Figure 2 shows the monthly energy required to solve transmission constraints after the closing time of the daily market, from January 2000 to November 2005. Two facts emerge from an examination of the evolution of the monthly energy. First, there is a general seasonal pattern (with one dip and two peaks during the year). This pattern is clearly related to the seasonal behaviour of the demand (see Pardo et al., 2002). Second, two anomalous periods can be identified: (i) Year 2002 - during the first half of this year the amount of electricity required to solve transmission constraints was abnormally low; (ii) the July 2004 to February 2005 period - during this period the amount of electricity involved in the transmission constraints resolution process was clearly greater than usual.

[INSERT FIGURE 2 ABOUT HERE]

4.2. Criteria applied by the system operator to the management of transmission constraints

The system operating protocols implemented by the Spanish system operator are aimed at maintaining the security, quality and reliability of supplies. The efficient management of transmission constraints is based on several factors and criteria that need to be properly analyzed and evaluated. REE (at least partially) discloses ex post the main factors that determine the total amount of energy involved in the resolution of transmission constraints, through its monthly statistical bulletin. The criteria that were more frequently disclosed by REE in the period that runs from January 2000 to November 2005 are threefold. The first is the level of demand in terms of both energy and load. Broadly speaking, the higher the level of demand, the higher the probability of network congestion due to the fact that the network capacity is physically limited. Therefore, during periods of heavy demand, the system operator manages a larger quantity of electricity in the resolution of transmission constraints. To be more precise, this is especially true when the increase in electricity needs concentrates in specific zones having deficits of installed capacity.

The second factor is the unavailability of thermal power stations, as well as the unavailability of network lines. In particular, REE reiterates that a minimum level of thermal energy is needed in the daily market scheduled dispatch, in order to guarantee the security of the system. Hence, if some thermal plants are not available (because of technical overhaul, unforeseen decoupling needs, etc.), then REE may require a higher amount of electricity from other thermal power stations through the transmission constraints resolution process. This is especially true for those plants located in zones that are critical due to their high consumption level, such as the centre of Spain and the south-eastern coastal area (Cataluña, Andalucía and Levante).

Third is the generation mix of the daily market dispatch schedule. When REE detects that the relative amount of thermal electricity matched in the daily market compared to the level of hydroelectricity is below the minimum level required to guarantee the reliability of the system, it will ask for additional thermal electricity by means of the transmission constraints resolution process. This criterion is mainly related to the convenience of keeping some hydroelectric power available to cover unexpected peaks in demand, due to the relatively cheap and quick responsiveness of hydroelectric plants. ¹¹

Clearly, the first factor constitutes the prominent explanation for the hourly and seasonal patterns observed in Figures 1 and 2, respectively. The last two factors, on the contrary, seem to be crucial to explain the anomalous periods identified above. The huge increase in electricity demand in the unusually cold and dry winter of 2001-2002 gave rise to forced rolling blackouts in the central region of Spain in December 2001. The hydroelectric power lessened considerably, resulting in a greater amount of thermal electricity matched in the daily market relative to the amount of hydroelectricity traded. Besides, REE justifies the increment in the amount of electricity involved in the resolution of transmission constraints during the July 2004 to February 2005 period by explaining that the large quantities of hydroelectricity compared to the thermal electricity traded in the daily market made it necessary to ask for additional thermal power.

¹¹ Another criterion much less frequently mentioned by REE was the “power factor”. In essence, it is related to the quality and the reliability of the dispatch. The higher the power factor is, the less energy required due to the transmission constraints resolution process.

4.3. Test of technical factors explaining the amount of energy involved in the resolution of transmission constraints

We now estimate a linear regression model that explains the amount of energy involved in the resolution of transmission constraints through the main underlying variables mentioned above. The model is designed to provide a simple independent rough test of the application of the general criteria disclosed by the system operator. The model however is not intended to provide a complete analysis of the underlying factors that affect the energy needed to resolve congestion, since this type of analysis is outside the scope of this paper.

According to the criteria applied to the management of network constraints in the daily market, the amount of energy involved in the resolution of constraints should be fundamentally linked to the level of demand (here the zonal factor plays a crucial role), as well as to the proportion of hydroelectric energy to thermal energy in the daily market session.

Hence, the first explanatory variable included in the model is the seasonal behaviour of the amount of energy required to resolve network constraints in the daily market. To capture this (average) seasonal pattern into the model, we included four seasonal dummy (binary) variables. Firstly, this seasonal pattern is of course related to the average seasonal level of demand. Furthermore, it is also expected to be related to the production capacity of the electricity system, via the general seasonal level of hydroelectric reserves. Finally, it also incorporates an approximate zonal effect, since most of the unusual increases in demand that are located in specific zones are also concentrated in particular seasons of the year.

Another explanatory variable included in the model is related to the proportion of hydroelectric energy to thermal energy included in the daily market dispatch schedule. To be precise, we include a dummy variable in the model that takes the value one when the hydroelectric-to-thermal energy ratio is above 0.4, and zero otherwise. This is motivated by the scatter diagram in Figure 3. This figure plots the level of energy required to solve any congestion in the PBDF against the hydroelectric-to-thermal ratio (both amounts of energy refer to the daily market), for the winter and spring months (December to May, both inclusive) excluding the anomalous period (see Figure 2) that runs from July 2004 to February 2005. It shows that in winter and spring, the level of energy required to solve constraints when this technological ratio is above 0.4 is usually significantly higher than the level of required energy when this ratio is below 0.4.¹² This fact can be explained by the following technological criterion applied by REE. When there is an improper high value of the ratio (approximately above 0.4), it adjusts the PDBF by increasing the level of energy required to solve constraints, so as to keep a higher amount of hydropower available in case it is required to deal with unexpected peaks in demand, due to its quick response.

[INSERT FIGURE 3 ABOUT HERE]

Finally, we included three binary variables that account for the special circumstances of three unusual periods (see Figure 2). The first includes the unusually cold and dry months of December 2001 and January 2002; the second runs from July 2004 to February 2005; and the third is the period from July 2005 to November 2005, when the new rules governing the procedure to resolve network constraints apply.

The model to be estimated is given by the following equation:

\[\begin{array}{r l} T C _ {t} & = \alpha_ {1} D _ {\text { SPRING }} + \alpha_ {2} D _ {\text { SUMMER }} + \alpha_ {3} D _ {\text { AUTUMN }} + \alpha_ {4} D _ {\text { WINTER }} \\ & + \beta D _ {\frac {H}{T} > 0. 4} + \gamma_ {1} D _ {\text { DEC01JAN02 }} + \gamma_ {2} D _ {\text { JUL04FEB05 }} + \gamma_ {3} D _ {\text { JUL05NOV05 }} + \varepsilon_ {t} \end{array}\]

where t indicates time, is the monthly energy required to solve transmission constraints, is the monthly energy included in the PDBF, every stands for a binary variable (details given above) that takes the value 1 if the condition indicated in the subscript COND is true and zero otherwise, and is the random disturbance.¹³

The model was estimated using monthly data for the sample period January 2000 to November 2005. The results for the estimation are reported in Table 1. They show that the model is able to explain a substantial portion of the energy required to solving the network congestion (the R-Squared statistic is 72%).

[INSERT TABLE 1 ABOUT HERE]

As was expected, the results show that there exists a seasonal pattern in the energy demanded by the system operator within the resolution of transmission constraints after the daily market. The

¹² During the remaining seasons of the year, the value of this ratio was always below 0.4.

¹³ The seasons were defined in the following way. Spring refers to the months from March to May (both inclusive), summer is June to August, autumn is September to November, and winter is December to February.

highest average level of energy is required during the months of June, July and August. This is consistent with the fact that the main pressure on the demand side usually takes place during the summer due to the high temperature and, in the Spanish case, this pressure is typically concentrated in some critical tourist areas such as Cataluña and Levante where the levels of electricity consumption are much higher than during the rest of the year. The lowest average level of required energy occurs in the spring months, when the level of demand is usually relatively low and the level of the reservoirs is relatively high. Additionally, the parameter that accompanies the dummy variable that accounts for the differential effect when the hydro-to-thermal ratio is large is positive. This was also expected, and confirms that when the level of hydroelectricity matched in the daily market is large as compared to the level of thermal electricity, the energy required by the system operator through the transmission constraints management jumps to a higher level than that related to the level of demand. Finally, the three binary variables that identify the anomalous periods also have the expected signs. The coefficient of shows a negative effect in the amount of energy demanded by the system operator to solve technical transmissions. This could be explained by an unusually limited capacity of hydroelectric generation (these two months are included in a very dry period), which could not be translated into hydropower matched in the daily market. The coefficient accompanying D_JUL04FEB05 show that during this period the energy required for solving transmission constraints was notably higher than usual. We will study this period in depth in the next sections. From the negative sign of the coefficient that accompanies it can be concluded that the total energy demanded to resolve transmission constraints has been lower than usual from the date on which the rules related to transmission constraints changed.

5. Influence of the transmission constraints management rules over the consumption units’ behaviour

5.1. Economic incentives and trading strategies

We now elaborate on the expected implications of the rules governing the resolution of transmission constrains on the trading behaviour of consumption units. Recall that until 30 June 2005, the remuneration for the out-of-merit energy added to the system as a result of the mechanism for resolving transmission constraints was at least equal to the corresponding marginal price in the daily market. The (non-negative) difference between the price at which the required energy was remunerated and the daily marginal price resulted in extra income for the production units that injected electricity into the system.

This extra income means an extra cost for the consumption units that have purchased energy in the daily market or have taken part in bilateral contracts (they incur the extra cost proportionally to their consumption level). Additionally, recall that there is no extra cost derived from the equivalent procedure for resolving transmission constraints once the intra-day market clears. These two facts together constitute an economic incentive for consumption units (buyers in the daily market) to submit their purchase bids to the intra-day market, instead of submitting them to the daily market (or contracting bilaterally).¹⁴ Notice that the importance of the incentive crucially depends on the amount of (out-of-merit) energy involved in the resolution of transmission constraints after the closing time of the daily market.

Any trading strategy designed to avoid the extra cost will only succeed if the consumption unit eventually gets the same desired amount of energy in the intra-day market at a price not greater than the price to be paid because of its participation in the daily market (including the extra cost derived from the resolution of constraints). In other words, there exist some risks involved in this type of strategy. For one thing, there are some liquidity concerns. The consumption unit may find it more difficult to get the desired amount of energy at reasonable prices in the intra-day market as compared to the daily market. In this regard, however, one should keep in mind that the intra-day market comprises six trading sessions, as opposed to the unique trading session of the daily market. Needless to say, the success of any strategy implemented to avoid the extra cost will ultimately depend on the behaviour of the remaining participants in the market; namely, the generation units and the system operator. We will comment extensively on this issue later on.

5.2. Evidence of the trading strategies implemented by consumption units

The available data show several facts that are consistent with the type of strategy explained above designed to avoid the extra costs.

First of all, for motivational reasons we will have a look at the importance of the economic incentive, measured as the extra cost that was paid for the energy purchased in the daily market (or bilaterally) during the sample period. From January 2000 to June 2005, the average extra cost amounted to 5.25% of the marginal price in the daily market. The average extra cost increased, as expected, to 8.41% of the marginal price in the daily market for the period that runs from July 2004 to February 2005.

¹⁴ The National Energy Commission (“Comisión Nacional de la Energía”, CNE), in a report of proposals to change the regulations of the transmission constraints resolution process (see CNE, 2002), recognized the importance of the incentive. Indeed, the CNE asserted that some buyers were leaving the daily market to purchase the electricity in the intra-day market, in order to avoid the cost derived from the resolution of transmission constraints in the daily market.

Consider now the liquidity concerns. On one hand, the energy matched in the intra-day market relative to the daily market is in general very low.¹⁵ This suggests that a lack of enough sellers in the intra-day market could have limited the scale of the movement of electricity purchases from the daily market towards the intra-day market. On the other hand, however, during the period in which a huge increase in the energy required by the system operator to manage congestion in the daily market is observed (see Figure 2), the (relative) volume of trading by consumption units in the intra-day market is almost four times the volume of trading during the previous period. Indeed, from January 2000 to May 2004, the energy purchased by these units in the intra-day market relative to the energy acquired in the daily market was only 2.08%. During the next nine months, however, these same units purchased in the intra-day market 7.86% of the energy acquired in the daily market.

Hence, although generally speaking it may have been difficult, or sometimes even impossible, to implement the abovementioned trading strategy on the part of the consumption units due to the relative lack of liquidity in the intra-day market throughout the whole sample period, such liquidity concerns seem to have been significantly less important precisely when the economic incentive became much more relevant, i.e. when the amount of (out-of-merit) energy required in the congestion management procedure soared and , accordingly, so did the extra cost. Additionally, an analysis, not shown here to save space, of the distribution of this noticeable increase in the purchases made by consumption units throughout the available trading sessions in the intra-day market reveals that the increase was concentrated in the first session of the intra daily market (which allows trading at day d for delivery in each of the 24 hours of the day ahead, d+1).

All these facts are consistent with the notion of consumption units that, driven by the abovementioned economic incentives, abandon the daily market in favour of the intra-day market, and that seize the first available trading opportunity in the intra-day market in order to minimize the involved risks.

Finally, in order to verify that this increase in purchases carried out by consumption units in the intra-day market has taken place against the daily market, we must distinguish between the energy that is traded in order to modify commitments previously made in the daily market, and the new energy that means a net increase in production in response to the additional demand (to satisfy either additional consumption or pumping needs), and compare them to the evolution of the energy traded in the daily market.

To this aim, we calculate three daily ratios that relate the energy acquired in the intra-day market due to a given objective to the energy acquired in the daily market. To be precise, we compute the following three daily ratios: (i) the proportion of energy traded in the intra-day market in order to adjust previously assumed market positions to the total energy traded in the daily market; (ii) the proportion of energy traded in the intra-day market for pumping needs to the total energy traded in the daily market; and (iii) the proportion of energy traded in the intra-day market for consumption needs to the total energy traded in the daily market. Figure 4 shows the evolution of the ratios (in percentage) from January 2000 to June 2005.

1 ⁵ During 2005, for example, the energy matched in the intra-day market added up to 20.471 GWh. This is only 8.4% of the total energy matched in both (daily and intra-day) sections of the electricity market.

[INSERT FIGURE 4 ABOUT HERE]

This figure clearly shows that the third ratio is the only one that jumps to unusual high levels from June 2004 to February 2005. This result confirms the fact that the daily market has lost ground in favour of the intra-day market because of the strategic bidding of consumption units. This behaviour is totally consistent with the aforementioned structure of economic incentives that lies in the rules governing the resolution of transmission constraints in the Spanish electricity market (compare Figures 2 and 4).

In conclusion, the obligation to bear the cost derived from the resolution of transmission constraints in the daily market has become an economic incentive for consumption units to leave the daily market (and possibly also bilateral contracting) in favour of the intra-day market. As the amount of energy involved in the management of transmission constraints after the daily market increases, this incentive becomes more relevant and consumption units seem to respond accordingly.

6. Influence of the transmission constraints management rules over the production units’ behaviour

6.1. Economic incentives and trading strategies

The aforementioned extra cost (above the daily marginal price) incurred by the consumption units equals the extra remuneration that is received by the production units that are required to generate electricity to solve transmission constraints. As a matter of fact, from January 2000 to June 2005, the average price used to remunerate the electricity needed to solve transmission constraints in the daily market was, on average, 265% greater than the daily marginal price. Therefore, any production unit would greatly benefit from generating electricity in response to a requirement to solve transmission constraints in the daily market. In fact, the extra remuneration acts as an economic incentive to provoke such a necessity on the part of the strategic generators in the mechanism to solve transmission constraints. It is worth emphasizing that very frequently constraints can be relieved only by a unique generator (Fabra-Utray, 2004, pg. 213).

Nevertheless, any trading strategy carried out with this aim faces some limitations and risks. On one hand, production units are obliged to present sale offers in the daily market for their available electricity (the available electricity results from deducting the electricity traded bilaterally from the total electricity that each production unit is able to generate). This obligation makes any strategy based on refraining from offering some generation units in the daily market extremely difficult to be sustained for some time. ¹⁶ On the other hand, any strategy based on strategic bidding (using prices as the strategic variable) in the daily market must bear the risk of finally not being required to dispatch electricity to resolve technical constraints. For one thing, it is the system operator who eventually decides the exact amount of electricity that is necessary as well as the production units that must provide it, according to technical criteria. Nevertheless, the available pending energy to be dispatched after the daily market can be offered for sale later on in the intra-day market (together with the electricity that is withdrawn by the system operator from daily-market scheduled dispatch to manage transmission constraints). Notice that this is the moment when the availability of sufficient counterparties provided by consumption units, which are willing to purchase the electricity in the intra-day market in order to avoid the extra payment, plays a central role in substantially reducing the risk of not being dispatched.

All of this notwithstanding, at least some strategic generators have a clear economic incentive to avoid being dispatched (at least, for a part of the available energy) in the daily market, as well as to try to be called up in the subsequent transmission constraints resolution process. This goal could be reached by increasing the offered price for sale in the daily market. If the production unit were finally required to deliver energy to resolve congestion, the necessary energy would be remunerated at a higher price.

Of course, the probability of succeeding crucially depends on some technical factors that affect the resolution of congestion, such as the geographical location of the plants as well as the type of technology used to produce the electricity. ¹⁷ We will elaborate on these types of considerations later on.

6.2. Evidence of trading strategies by the main generators in the intra-day market

We now analyze the participation of the main producers in the resolution of transmission constraints. This will allow the detection of differences in the role they played in the resolution of constraints, which in turn may have a significant influence on their participation in the subsequent intra-day market. Afterwards, we will explore in detail to what extent their participation in the intraday market is determined by their previous participation in the resolution of constraints.

¹⁶ For example, a strategy could consist in offering in the daily market an amount of thermal energy that is lower than the total available amount. This would be extremely difficult to be put into practice since the system operator has continuously at his disposal all the information corresponding to the availability of the plants.

¹⁷ The Annex contains the generation mix corresponding to the main Spanish production entities.

a) Estimation of the revenues obtained by the main generators in the resolution of transmission constraints and in the intra-day market

To begin with, we now roughly estimate the monthly revenues for the main generators in the Spanish electric system, that result from their participation in the transmission constraints resolution process as well as in the intra-day market from January 2002 to June 2005. The analysis of these estimates is mainly of a motivational nature. A highly probable different participation of the main generators in a process to resolve a problem that is merely technical is expected to cause an asymmetric distribution of the extra income provided by the price (above the daily market price) that is used to remunerate the energy added to solve transmission constraints. Additionally, the energy withdrawn from the daily-market scheduled dispatch to resolve constraints constitutes a surplus of electricity that can be offered for sale in the intra-day market (as long as it is not restricted to do so by the system operator in order to avoid further network congestion after the intra-day market). It is thus also interesting to estimate the revenue obtained by the main generators in the intra-day market, for comparison purposes.

To be precise, the net income, I(TC)_i, obtained by a generator (say, i) from its participation in the resolution of transmission constraints in the daily market for a given month has been estimated by the following formula:

I(TC)_i = [(monthly energy generated to resolve transmission constraints)_i × monthly average price used to remunerate that energy] – [(monthly energy withdrawn to resolve transmission constraints)_i × monthly average of the daily marginal price]

Notice that a negative value for I(TC)_i simply means that the amount of energy withdrawn from the scheduled dispatch has been greater than the amount of energy additionally supplied to the system.

The monthly net revenue, I(I-D)_i, obtained by generator i due to its participation in the intraday market has been estimated through the following formula:

I(I-D)_i = (monthly electricity sold in the intra-day market – monthly electricity purchased in the intra-day market)_i x monthly average intra-day marginal price

Figure 5 depicts the estimates for the monthly revenues (in euros) corresponding to each one of the main generators in the Spanish electric system as a result of their participation in the resolution of transmission constraints (in the daily market) and in the intra-day market, from January 2002 to June 2005.

[INSERT FIGURE 5 ABOUT HERE]

According to these estimates, from June 2004 to February 2005, Endesa Generación did not gain on average as a result of its participation in the resolution of transmission constraints in the daily market. At the same time, it had noticeable incomes in the intra-day market. In actual fact, Endesa Generación was a net seller in the intra-day market during most of these months, as its positive estimated outcome confirms.

On the other hand, Iberdrola Generación obtained additional revenues thanks to its participation (which mainly consisted in delivering electricity) in the resolution of transmission constraints in the daily market, and in the intra-day market as well. During the period June 2004 to February 2005, results become more prominent. To a lesser extent, the same thing can be stated with regard to Unión Fenosa Generación, Viesgo Generación and Gas Natural SDG Generación.

b) Participation of each generator in the resolution of transmission constraints

Motivated by the previous results, we now carry out a detailed analysis of the participation of each generator in the resolution of network constraints in the daily market. Table 2 reports the monthly amount of electricity that was added to or withdrawn from the scheduled dispatch by each one of the main generation companies, in order to resolve transmission constraints in the daily market, for the sample period January 2002 to June 2005.

[INSERT TABLE 2 ABOUT HERE]

The data confirms several relevant facts. First, though most of the reported companies are required to add as well as withdraw energy every month, the monthly net contribution of each company to the resolution of constraints is usually of the same type. Endesa Generación and Hidrocantábrico Generación have mainly withdrawn electricity, while Viesgo Generación, Gas Natural SDG Generación, and Unión Fenosa have all added more electricity than the amount withdrawn during most of the period. The case of Iberdrola Generación is unusual, since although it was required to withdraw more electricity from the scheduled dispatch than add to it until May 2004, from that moment onwards it was mainly required to play the opposite role.

Second, the total amount of energy required to be added to and withdrawn from the scheduled dispatch to avoid congestion have been unevenly allocated among the involved generation companies. Furthermore, the relative contribution of each company changed significantly from June 2004 onwards. To be precise, during the period June 2004 to February 2005, Iberdrola Generación became the main contributor to the resolution of transmission constraints, with more than 50% of the energy added by the companies reported in Table 2, followed by Viesgo Generación (17.93%), Gas Natural

SDG Generación (11.38%), Endesa Generación (11.15%), Unión Fenosa Generación (8.35%), and finally Hidrocantábrico (0.08%). During the same period, the cases of Viesgo Generación and Gas Natural SDG Generación are remarkable, since the energy added by these companies to resolve transmission constraints accounted for, respectively, 29.96% and 24.27% of the total energy traded by each of them in the daily market.¹⁸ With regard to the energy withdrawn, up to May 2004 Endesa Generación (followed by Iberdrola Generación) was the generator that had to withdraw the most energy from the daily market due to transmission constraints. Besides, during the second half of 2004 and the first two months of 2005, Endesa Generación reinforced its overall contribution by withdrawing 75.5% of the total energy withdrawn by the main companies reported in Table 2, in sharp contrast with Iberdrola Generación, which only withdrew 10.5% (the remaining percentages are: Hidrocantábrico Generación 5.5%, Unión Fenosa Generación 3.8%, Viesgo Generación 3.4%, and Gas Natural SDG Generación 1.3%).

In summary, each generator was required to help alleviate transmission constraints in the daily market in a very different way during the considered period. While some entities basically injected the system with energy, thus profiting from the aforementioned favourable remuneration, others mainly withdrew electricity. Of course, there is some rationale behind this result. One particular technical reason that could explain the fact that some specific generators are more frequently required to add electricity by the system operator (even based on the application of a preventive criterion to guarantee the reliability of the transmission system) is the physical location of their thermal power stations. It makes sense that generators whose thermal plants are located in areas of relative high levels of electricity consumption are required to add electricity into the system more frequently, since there exists a greater probability of network congestion.

c) Trading strategies in the intra-day market

From the results reported above, it is clear that each generation company follows a distinctive trading strategy in the intra-day section of the electricity market, which is likely to be strongly conditioned by the different role they are required to play in the previous resolution of transmission constraints in the daily market. We will now explore this link.

Consider, for instance, the case of Endesa Generación. Figure 6 allows the comparison of the amount of energy added to and withdrawn from the daily market scheduled dispatch due to congestion reasons with the energy sold and purchased in the intra-day market (a negative sign has been added to the amount of energy withdrawn and purchased, respectively, to make the four lines more distinguishable from each other).

¹⁸ Compare with the cases of Iberdrola 6.52%, Endesa 0.78%, Hidrocantábrico 0.04%, and Unión Fenosa 2.18%.

[INSERT FIGURE 6 ABOUT HERE]

It can be observed that in the case of Endesa Generación, most increases in the energy withdrawn are followed by increases in the energy sold in the intra-day market. This relationship can be statistically tested by means of a simple linear regression model, with the monthly amount of energy sold by Endesa Generación in the intra-day market during month t) as the dependent variable, and the energy that this company was required to withdraw in the resolution of transmission constraints during month t) as the independent variable. The regression has been estimated for the whole sample period, from January 2002 to June 2005. The estimated regression line is:

\[E G _ {-} S _ {t} = 1 7. 7 3 + 0. 3 2 E G _ {-} W _ {t} \tag {1.0}\]

where the numbers inside the parenthesis indicate the value of the usual t-Student statistic for each estimated parameter, and the R-Squared statistic equals 68.31% (this implies a linear correlation coefficient of 82.6%). The evidence provided by this result indicates that the amount of energy sold in the intra-day market by Endesa Generación is strongly determined by the amount of energy withdrawn by the same company for resolving transmission constraints. It also suggests that Endesa tries to resell in the intra-day market as much of the previously withdrawn energy as possible, with the limitations imposed by the system operator for the intra-day market after considering the transmission constraints in the daily market. The same regression was estimated for the rest of the main generators, and the result obtained was the non-existence of a linear link between the two variables.

Consider now the case of Iberdrola Generación, which can be analyzed in detail from Figure 7 (the variables depicted are defined as in Figure 6).

[INSERT FIGURE 7 ABOUT HERE]

In contrast with the case of Endesa, the energy sold by Iberdrola Generación in the intra-day market can not come in many instances from the energy withdrawn from the daily-market scheduled dispatch to solve transmission constraints. In actual fact, during the abovementioned relevant period running from June 2004 to February 2005, the amount of energy withdrawn by Iberdrola Generación from the scheduled dispatch is much smaller than the quantity sold in the intra-day market. Furthermore, there is a simultaneous significant increase in the electricity added to solve transmission constraints during this period.

6.3. Evidence of trading strategies in the daily market

Overall, the facts reported above suggest strategic behaviour on the part of some generation companies (notably, Iberdrola Generación), which plays a central role in the resolution of network constraints in the daily market. Eventually, their behaviour would allow them to gain some extra revenues, due to the rules applied to remunerate their participation.

In any event, the trading strategies do necessarily span all the sections of the Spanish electricity market. We now relate the participation in the daily market to the participation in other sections of the market. This provides some additional evidence on the type of strategy that some relevant generators could have implemented. We also provide some evidence on the role that the technical factor may have played. We conclude with some anecdotal evidence that clearly suggests strategic bidding in the daily market on the part of some producers.

Firstly, we compare the evolution over time of the allocation of the dispatch (i) in the daily market (see Table 3, Panel A), (ii) in the resolution of transmission constraints (Panel B), and (iii) in the intra-day market (Panel C).

[INSERT TABLE 3 ABOUT HERE]

The variations reported in Table 3 state that, from 2003 to 2004, the increase in the energy added to the system to solve technical constraints in the daily market (48%) together with the growth in the energy sold in the intra-day market (72%) were accompanied by a noticeable decrease of more than 12% in the energy traded by Iberdrola Generación in the daily market. The underlying trend strengthened from the first half of 2004 to the first half of 2005, when there was a 16% reduction in the energy traded in the daily market together with a 149% increase in the energy added to solve technical constraints in the daily market, and an 89% increase in the energy sold in the intra-day market. As well, Viesgo Generación experienced a significant 36% reduction in the energy traded in the daily market, together with a 31% increase in the energy added to solve technical constraints, and a 170% increase in the energy sold in the intra-day market, from 2003 to 2004. Therefore, in the cases of both Iberdrola Generación and Viesgo Generación, the intra-day market is not only used to adjust previously assumed market positions, according to the rationale that inspired the design of the market, but it is considered as a new opportunity to sell the surplus electricity.

Secondly, if these results are to be determined by a trading behaviour related to the role played by some strategic companies in the resolution of the network congestion, we should find some link with the technical factors that underlie such role. With regard to the technological (generation mix) factor, there is some evidence consistent with a replacement of hydroelectric power with thermal power in the daily market by generators that own this last generation source. In this sense, for instance, the linear correlation coefficients (computed with monthly data) between the monthly energy traded in the daily market by Iberdrola Generación and the monthly hydroelectric power that could be produced by the whole Spanish electricity industry were 69% and 73%, respectively, during 2003 and 2004, as opposed to the significantly lower coefficient of 24% during the year 2002. This drastic change in the correlation between the hydropower sold in the daily market by a given company and the amount of available hydropower in the whole Spanish electric system is consistent with strategic bidding carried out by the company in favour of the hydroelectric power.

Finally, there is some anecdotal evidence that suggests that the results provided above have been triggered by the strategic bidding of some generators, which seek to benefit from the high remuneration received when they are required to add energy to the system to alleviate network constraints. Interestingly, the end of the unusual period studied above, running from June 2004 to February 2005, did not coincide with the implementation of the new rules governing the resolution of transmission constraints in the daily market (these were in force from 1 July 2005), as it could be expected. On the contrary, it is highly remarkable that the drastic reduction in the additional energy required to solve transmission constraints in the daily market that put an end to the unusual period took place on 8 March 2005. This is just one day after Endesa submitted a formal complaint to the Defence of Competition Service (“Servicio de Defensa de la Competencia”) about an alleged market price manipulation carried out by Iberdrola Generación, Gas Natural SDG Generación and Viesgo Generación through their offers submitted to the daily market. Concretely, Endesa Generación accused them of submitting very high price offers to the daily market auction in order to be excluded from the scheduled dispatch, and to be required later on to add energy through the transmission constraints resolution process. ¹⁹ In response to the complaint by Endesa, the Defence of Competition Service started investigating Iberdrola Generación and Gas Natural SDG Generación in February 2006.

Several facts are indeed quite revealing in this regard. On 8 March 2005, the system operator required from the production units a total of 1,202 MWh in order to solve technical constraints once the daily market cleared, in sharp contrast with the 11,076 MWh required just one day earlier. The energy added to solve transmission constraints in the daily market during March 2005 added up to 144,912 MWh, which is 65% less than the quantity needed in February 2005, and just 22% of the monthly average added electricity during the nine previous months.

We conclude by recalling that in Section 5.2 we proved that during the period running from June 2004 to February 2005, a great deal of the energy previously purchased in the daily market by consumption units turned out to be purchased in the intra-day market. The results in this section suggest that this energy found its counterparty in the increasing energy sales made by generators during the same period. Probably, the migration by consumption units from the daily to the intra-day section of the market started some time before this period since the incentive existed for a long time (the CNE report mentioned in footnote 14 dated back to April 2002). It is, however, during the

¹⁹ The related news can be found in the Spanish economic press (see for example: www.cincodias.com). Some days before, 4 March 2005, this economic newspaper commented that Endesa criticized the drastic reduction in the supply by Iberdrola Generación and it wondered about possible reasons that could explain this fact (such as technical problems including a lack of fuel).

abovementioned particular period when it became more noticeable due to an increased interest in selling electricity in the intra-day market shown by some production units due to their strategic behaviour.

7. Final remarks

The broad empirical evidence provided in this paper clearly supports the view that, until the end of June 2005, both sellers and buyers followed trading strategies that were strongly influenced by the rules that determined the remuneration for the additional energy required to solve transmission constraints and the way the resulting implicit cost was billed to consumption units. The evidence provided also clearly suggests that the trading strategies followed by some generators were related to their strategic role in the resolution of transmission constraints. The ultimate factors that determine such dominant influence in the short run are technical in nature.

Our results have several far reaching consequences from the point of view of the regulator. For instance, our results confirm that both production facilities as well as consumption units followed trading strategies spanning all the sections of the Spanish electricity market. A relevant consequence of this fact is that, contrary to the regulator’s desire, the first session of the intra-day market seems to have been used in practice as a second session of the day-ahead market. Additionally, not only did the rules in force until the end of June 2005 prove to be inadequate to prevent such behaviour, but they brought a structure of economic incentives that sustained the undesired behaviour.

Our results can also be used to shed some light on what should be expected from the new set of rules that govern the management of transmission constraints since 1 July 2005 (Royal Decree 2351 of 23 December 2004). The cornerstone of this reform is a new procedure to determine the price used to remunerate the energy required to be added into the system to resolve transmission constraints in the daily market, coupled with a new way of billing the extra cost to consumption units. The new pricing mechanism results from organizing a pay-as-bid or discriminatory auction, if necessary, to which producers submit their specific offers to add energy to the system in order to solve transmission constraints. The required energy will be paid at a price resulting from the offers presented specifically to provide that service. The costs derived from the transmission constraints resolution process in the daily market are defrayed by consumption units, proportionally to all their purchases in the electricity market; i.e. considering not only the energy purchased through the daily market and bilaterally, but also through the intra-day market. ²⁰ The energy withdrawn from the scheduled dispatch keeps being considered as cancellations of previous commitments, and no extra cost is derived from them. Finally, the rules that apply to the resolution of transmission constraints after the closing time of the intra-day market do not change.

²⁰ With the exception of the pumping facilities and consumption units whose purchases satisfy supply needs located outside of the Spanish electric system, which are not required to pay those costs.

Therefore, under this new set of rules, the incentive for consumption units to leave the daily market in favour of the intra-day market (to avoid the costs derived from the management of transmission constraints in the daily market) disappears. The offers made by production units to add energy specifically to solve any transmission constraints, if needed, are intended to avoid possible interferences in the daily market price, and to put some competitive pressure on the determination of prices. In our opinion, this competition is hardly expected to succeed in practice, as long as the restrictions continue to be resolved necessarily by only a thin number of companies in most cases.

Unfortunately, the unavailability of data on the energy traded in the intra-day market according to different final purposes, as well as of the price used to pay the energy added to solve transmission constraints beyond November 2005, does not allow the evaluation of the consequences of the new rules. The limited data available to date, however, seems to support our prediction on the lack of competitive pressure in the procedure. From July 2005 to November 2005, although the energy required by the system operator to resolve transmission constraints decreased, Iberdrola Generación and Viesgo Generación continued to be net sellers of energy in the procedure to resolve constraints in the daily market. Endesa Generación and Hidrocantábrico Generación kept on withdrawing more energy than added. However, what is noticeable was the change in the participation by Unión Fenosa Generación and Gas Natural SDG Generación, since they changed to withdraw more energy than added in each of the considered months. Nonetheless, a complete analysis of the generators participation in the resolution of transmission constraints under the new set of rules is necessarily left for future research.

Annex

Installed capacity (in percent) of the main generators in the Spanish electric system, as of 2005 (except U. Fenosa: 2003). Source of data: web pages of each of the considered companies (www.endesa.es, www.iberdrola.es, www.hcenergia.com, www.unionfenosa.es, www.gasnatural.com, www.enelviesgo.es)

Acknowledgements

This paper greatly benefited from discussions with Vicente Meneu and Ángel Pardo. We are also grateful to F. Climent and seminar participants at Universidad Politécnica de Madrid, for useful comments and suggestions, as well as to REE for providing us with some additional data. Financial support provided by the Spanish Ministry of Education and Science (DGICYT) and FEDER, under the project REN2003-08871, is gratefully acknowledged. The usual disclaimer applies.

References

1. Arocena P., Kühn K-U., Regibeau P. 1999. Regulatory reform in the Spanish electricity industry: a missed opportunity for competition. Energy Policy 27, 387-399.
2. CNE 2002. Comisión Nacional de la Energía: Informe sobre propuestas de modificación de la normativa relativa a la resolución de las restricciones técnicas en el mercado eléctrico, Abril 2002. Available at www.cne.es
3. Crampes C., Fabra N. 2005. The Spanish Electricity Industry: Plus ça change… Energy Journal 26, 127-154.
4. Fabra N., Toro J. 2005. Price wars and collusion in the Spanish electricity market. International Journal of Industrial Organization 23, 155-181.
5. Fabra-Utray J. 2004. Un mercado para la electricidad. ¿Liberación o regulación? Instituto Pascual Maoz del Territorio, Urbanismo y Medio Ambiente de la Universidad Carlos III de Madrid. Marcial Pons, Madrid.
6. Green R. 2001. Markets for electricity in Europe. Oxford Review of Economic Policy 17, 329-345.
7. Kühn K-U., Machado M. 2004. Bilateral market power and vertical integration in the Spanish electricity spot market, CEPR discussion paper series, No. 4590.
8. Pardo A., Meneu V., Valor E. 2002. Temperature and seasonality influences on Spanish electricity load, Energy Economics 24, 55-70.
9. REE, 2000-2005. Boletín Estadístico de Energía Eléctrica. Available at www.ree.es

Figure 1. Hourly energy involved in the resolution of transmission constraints in the daily market, every year (January 2000 to June 2005)

Figure 2. Monthly energy involved in the resolution of transmission constraints in the daily market (January 2000 to November 2005)

Figure 3. Energy required to resolve congestion in the PBDF versus hydro-to-thermal ratio (H/T), in winter and spring (Jan. 2000 to Jun. 2004, Mar.2005 to Nov.2005)

Figure 4. Daily proportion (in percentage) of energy traded in the intra-day market with different purposes (consumption, adjustments and pumping needs) to the energy traded in the daily market.

Figure 5. Estimated monthly revenues (in millions of euros) obtained by the main generators from their participation in the resolution of transmission constraints in the daily market (continuous line) and in the intra-day market (dotted line). January 2002 – June 2005.

Figure 6. Participation of Endesa Generación in the resolution of transmission constraints and in the intra-day market

Figure 6. Participation of Iberdrola Generación in the resolution of transmission constraints and in the intra-day market

Table 1. Results for the linear regression model of the energy required to resolve transmission constraints (January 2000 to November 2005)

Table 2. Monthly added (+) and withdrawn (–) energy (in GWh) by the main generators in the resolution of transmission constraints in the daily market. January 2002 to June 2005.

Table 3. Energy sold in the daily market (Panel A), energy added to the system in the resolution of transmission constraints in the daily market (Panel B), and energy sold in the intra-day market (Panel C), by generator. January 2002 to June 2005 Panel A: Energy sold in the daily market

Panel B: Energy added to solve transmission constraints

Panel C: Energy sold in the intra-day market

* Energy variation from January-June 2004 to January-June 2005