| |Brussels, 12.08.2005

SG-Greffe(2005)D/204452/53

To the notifying parties

Dear Sir/Madam,

Subject : Case No COMP/M.3729 – EDF/AEM/EDISON.

Notification of 07.07.2005 pursuant to Article 4 of Council Regulation No 139/2004[1].

1. On 07/07/2005, the Commission received a notification of a proposed concentration by which the undertakings Electricité de France S.A. (“EDF”, France) and AEM S.p.A. (“AEM”, Italy) acquire joint control of Edison S.p.A. (“Edison”, Italy) by way of purchase of shares.

I. THE PARTIES

2. EDF is the French electricity incumbent, wholly owned by the French State. According to the information provided by the parties, the French Government has advanced plans to list EDF on the stock exchange by the end of 2005. EDF is active in the generation, transmission (through its subsidiary RTE, acting as French Transmission System Operator, “TSO”), distribution, supply, and trade of electricity and related services, mainly in France but with a large presence also across the EEA.

3. In Italy, EDF has very limited power generation capacity through its subsidiaries Fenice S.p.A (“Fenice”) and EDEV Italia S.p.A. (“EDEV Italia”) and is mainly active via imports from the Northern borders.

4. It is also worth noting that Electricité de France International SA (“EDFI”, a wholly-owned subsidiary of EDF) has an indirect, non controlling participation in the Swiss company Aare Tessin AG für Elektrizität (“Atel”), which has some activities in the Italian electricity sector. Atel is exclusively controlled by the Swiss company Motor Columbus AG (“Motor Columbus”), which owns 58.5% of Atel’s share capital[2]. As recently clarified by the Commission[3], Motor Columbus is in turn exclusively controlled by the Swiss company UBS AG (“UBS”), which owns 55.6% of its share capital[4]. This participation allows UBS to control Motor Columbus’s general assembly and gives power to determine the strategic decisions of the company through its board[5].

5. AEM is an Italian energy company solely controlled by the municipality of Milan. AEM is active in the utility services sector and, in particular, in the generation, transmission, distribution, trading and sale of electricity and in the distribution and sale of gas and heat, mainly in Italy.

6. AEM has some power generation capacity in the North of Italy and contractual rights to manage part of the generation capacity of Edipower S.p.A. (“Edipower”). Edipower is a company controlled by Edison, which acquired one of the three generation companies that the former monopolist Enel S.p.A. (“Enel”) had to dispose of according to Italian law[6]. Under a tolling agreement and a power purchase agreement concluded in 2003 between Edipower and some of its shareholders, 50% of Edipower’s generation capacity is managed by Edison, 20% by AEM, 20% by Atel and 10% by SIET Spa of the AEM Torino group (“AEM Torino”; altogether, the “tollers”)[7]. Within their quota, the tollers can decide Edipower’s production and independently sell the corresponding electricity, with the exception that they are not allowed to present offers in the ancillary services market (see below), where only Edipower can participate[8].

7. Edison is an Italian energy company controlled by Italenergia Bis S.p.A. (“IEB”), an unlisted holding company, owning approximately 63% of Edison’s share capital. EDF currently holds a non-controlling 18% shareholding in IEB with a legislative limitation to the exercise of its voting rights to 2%[9]. The legislative limitation of EDF’s voting rights should in principle be lifted following the adoption of a Law Decree modifying the previous legislation[10].

8. Edison is active in the generation, transmission, and supply of electricity and the production, transportation, distribution and supply of natural gas, mainly in Italy. Moreover, as indicated above, it controls Edipower and manages 50% of its generation capacity under the tolling agreement and the power purchase agreement mentioned above.

II. THE NOTIFIED TRANSACTION

9. In 2001 the special vehicle company Italenergia SpA (“Italenergia”), controlled by the FIAT group, acquired control of the Italian company Montedison SpA (“Montedison”) and, through the latter, of Montedison’s subsidiary Edison. EDF took part to this operation, acquiring a non-controlling 18% shareholding in Italenergia with a legislative limitation to the exercise of its voting rights to 2%[11]. In 2002, the shareholders of Italenergia reached an agreement for restructuring and re-financing the holding company, to be renamed hence Italenergia Bis (IEB). This agreement did not give rise to a new concentration within the meaning of Article 3 of Council Regulation 4064/89.

10. Earlier this year, the other IEB’s shareholders exerted a number of options for the sale of their participation in IEB to EDF. In this context, and after the modification of the Italian legislation limiting EDF’s voting rights in IEB, EDF and AEM agreed to realise the notified transaction in order to acquire joint control over Edison. This will be achieved by means of a special-purpose vehicle named Transalpina di Energia S.p.A. (“TdE”), in which EDF, through its wholly-owned subsidiary WGRM Holding 4 S.p.A. (“WGRM”), and Delmi S.p.A. (“Delmi”), a company solely controlled by AEM, will have equal holdings and equal representation. Through their joint control over TdE, EDF and AEM will therefore acquire joint control over Edison.

11. In particular, it is agreed that, first EDF will acquire control over IEB[12], and second that EDF shall procure (or, prior to such event, shall use its best efforts to procure) that IEB sells to TdE Edison’s ordinary shares and warrants (convertible into Edison’s ordinary shares until December 31, 2007), held by IEB at the date of the transfer. As a result of the transfer, TdE (and thus, indirectly, EDF and AEM) will acquire control of Edison. Within 30 days, TdE will then launch a mandatory tender offer over the remaining Edison’s shares, in accordance with the Italian stock-exchange law, as well as a voluntary tender offer on the remaining warrants in circulation.

12. Following these offers, it is agreed that (i) TdE will hold, together with the shares and warrants acquired from IEB, at least 51%, but no more than 60%, of Edison’s fully diluted share capital; and (ii) EDF will hold a direct participation in Edison[13] which, added to half of Edison’s securities held by TdE (and assuming conversion of all Edison’s warrants), will allow it to reach an aggregate economic interest of 50% of Edison’s voting capital. Any remaining shares and warrants tendered in the Tender Offers will be allocated to Delmi[14].

III. CONCENTRATION WITH COMMUNITY DIMENSION

13. As indicated, with the notified transaction EDF and AEM will acquire joint control over Edison. This transaction therefore constitutes a concentration within the meaning of Article 3(1)(b) of Council Regulation 139/2004.

14. EDF, AEM and Edison have a combined aggregate world-wide turnover of more than EUR 5 billion. Each of them has a Community-wide turnover in excess of EUR 250 million, but they do not achieve more than two-thirds of their aggregate Community-wide turnover within one and the same Member State. The notified operation therefore has a Community dimension pursuant to Article 1(2) of Regulation 139/2004.

IV. RELEVANT MARKETS

15. EDF, AEM and Edison mainly focus in the electricity sector. While AEM and Edison have also some activities in the gas sector, there are no markets affected by the notified concentration in the latter sector[15]. The analysis of the notified concentration will therefore be carried out with regard to the relevant electricity markets.

16. In previous decisions[16], the Commission has considered the following markets in the electricity sector: wholesale supply of electricity, ancillary services, transmission, distribution, and retail supply (with a possible distinction between large and small customers). Given the activities of the parties, in the present decision the Commission will consider wholesale electricity (in Italy and France), ancillary services (in Italy) and retail electricity (in Italy)[17].

1. Relevant product markets

Wholesale electricity in Italy

17. The wholesale supply of electricity, as defined in recent decisions of the Commission[18], encompasses the production of electricity at power stations and the import of electricity through interconnectors for purpose of resale to retailers or to a lesser extent directly to large industrial end-users.

18. More in detail, in Italy, operators on the supply side in the wholesale market include a large number of generators, importers and traders. On the demand side, operators include the Single Buyer (procuring electricity for non-eligible customers), retailers (procuring electricity for eligible customers), traders and some large eligible users. There are virtually no exports on the demand side[19], given the large price differential between Italy and neighbouring countries which has always been above 20€/MWh[20]. Moreover, the market test conducted by the Commission showed that there is consensus among the operators that a significant price difference will remain even taking into account the large build-out of new generation[21].

19. On the supply side, generators have to nominate the day before operation their injections in the network to the Italian TSO Gestore della Rete di Trasmissione Nazionale SpA (“GRTN”). This can result from two ways of deciding to produce electricity: generators either have concluded a bilateral contract (within their group or with a third party) to sell electricity to a given buyer or they have made a bid that has been accepted on the Italian Power Exchange (“IPEX”, see infra).

20. There is one specific exception: the operators who still hold a “CIP6” contract. These contracts were signed before liberalisation for a variety of plants (using fossil-fuel or green energy) and there is no possibility for other generation units to become “CIP6” units as well. Following several amendments during the process of liberalisation, the CIP6 units sell their energy to GRTN in advance (with a commitment to produce a given level of energy) and GRTN sells it back through IPEX at the price set by IPEX (these units are price takers). In other words, the electricity of CIP6 units is available on the market for all buyers like the electricity of any other generation unit (it does not constitute a separate market), but it does not affect the competitive conditions between sellers of energy on the market as its amount is set in advance and it takes the price decided by the market.

21. Also on the supply side, importers have to nominate the power that they will import into Italy following two possible methods of securing interconnector capacity: either importers bid directly into one of the virtual zones at the Italian border and their bid is accepted in that zone[22] or they secure import capacity through the allocation method used by foreign TSOs on the portion of the capacity that is not managed by GRTN. Under the latter option, importers can either conclude bilateral contracts with customers or they can bid directly in the power exchange IPEX.

22. On the demand side, most retailers largely rely on the generation of their generation affiliate and/or conclude bilateral contracts in advance; then, on the day before operation, retailers adjust their purchases to meet their demand on the day of operation by buying additional electricity or selling their surplus on IPEX. The Single Buyer used to buy its energy through bilateral contracts as well, but changed strategy in 2005 and bought a large part of its generation capacity on the IPEX, while covering the risk of price variation for part of these purchases through Contract for Differences concluded bilaterally[23].

23. IPEX does not offer products with a term longer than day-ahead so that buyers looking for forward contracts have to conclude them bilaterally. That being said, there is no obstacle for a buyer or a seller to switch from bilateral contracts to purchases or sales on IPEX and all the operators consulted by the Commission in the market test considered that they are part of the same market. While bilateral contracts were initially much larger than IPEX (70.94%% vs. 29.06% of total generation in 2004), the respective positions of these two segments of the wholesale market have been reversed in 2005 (22.23% vs. 67.77% for the period January-May2005). The number of operators registered in IPEX has jumped from a range of 35-39 in 2004 to a range of 78-81 in the first five months of 2005. The number of operators constantly operating in IPEX has jumped from a range of 18-19 in 2004 to a range of 56-58 in the first five months of 2005[24]. Thus it is important to understand the functioning of IPEX.

24. IPEX was launched on 1 April 2004 and is managed by the Gestore del Mercato Elettrico (“GME”), a company controlled by GRTN. In the power exchange, producers, importers, retailers, the GRTN[25], eligible customers and the Single Buyer participate in a competitive bidding process for the sale and purchase of electricity[26]. More in detail, in order to ensure a steady supply of electricity, IPEX is organized in three different markets, namely: the Mercato del Giorno Prima or MGP (the “day-ahead market”); the Mercato di Aggiustamento or MA (the “adjustment market”); the Mercato dei servizi di dispacciamento or MSD (the “ancillary service market”).

25. In the day-ahead market, sellers and buyers submit calls and offers for electricity to be supplied on the day following the transaction under the supervision of GME. GME is responsible for matching electricity demand and supply, by constructing the curve of demand adding up the quantities demanded (starting from the calls without price down to those with the lowest price) and the curve of supply adding up the quantities offered (starting with bids with a zero-price up to the highest bids at the maximum price authorised[27]). The point where the demand and offer curves cross defines the market “clearing price”. All bids of offer with a price under the clearing price are accepted and all demand bids with a price above the clearing price are accepted

26. The “adjustment market” allows some technical variations in the schedules agreed upon in the day-ahead market in order, for example, to make sure that a generation unit is not turned off for a single hour because it would have been selected for all hours except that one through the bidding process. Given this limited role of the adjustment market, both day-ahead and adjustment markets will from now on be referred to together as the day-ahead market. Afterwards GME defines power injection (supply) and withdrawal (demand) schedules and communicates these schedules to the TSO (GRTN).

27. That being done, GRTN and, consequently GME, must take into account the physical network limitations that place constraints on the transport of electricity from particular generation facilities to consumers and may result in congestion. If there is no congestion, GME can maintain a single clearing price throughout Italy. However, if congestion occurs (a very frequent situation on the Italian market), GRTN may impose the GME to divide the market into various zones, in which different clearing prices may be set for certain zones. Suppliers who bid in the market are paid then at the clearing price that is applicable in the zone where they produce. In such a case, the GME will still determine one national price for all purchasers on the power exchange, called the “unified national price” (or “ Prezzo Unico Nazionale ” - “PUN”), based on an average of the different clearing prices set in the various zones weighted based on the volumes sold in each zone[28].

28. All in all, this functioning does not affect the product market definition and, as stated in paragraph 17, the wholesale electricity market encompasses the production of electricity at power stations and the import of electricity through interconnectors, whether sold bilaterally or through IPEX. However, this functioning of the market may affect the geographic market as will be explained below.

Ancillary services in Italy

29. Electricity networks require that wholesale market participants provide at the request of the TSO a number of services to maintain the quality of supplies and operational reliability of the system, including the balance between supply and demand. This leads to the existence of a separate market for ancillary services which consists of reserve capacity and other services.

30. As noted above, in Italy the ancillary services market is managed in IPEX. The ancillary services market is a market separate from the day-ahead market in which producers submit bids to increase or decrease the volume of energy to be supplied to or withdrawn format the request of GRTN (and customers may in theory submit bids to reduce their consumption) in order to permit the real-time balancing of supply and demand required for the physical delivery of electricity. This market opens after the closure of the day-ahead market and generators can place bids in this market for the generation capacity that remains at their disposal after the day-ahead market. There are two kinds of bids.

31. The first kind of bids concerns offers to increase or decrease the volume of energy that could be implemented during the day of operation . For this category of bids, GRTN accepts during the day of operation the bids that it needs to balance demand and supply over the networks. Then, at the moment they are selected during the day of operation, the units selected have a small delay to implement the request of GRTN.

32. The second kind of bids concerns offers to increase or decrease the volume of energy that will be implemented already before the day of operation. Such bids from producers offer to guarantee the availability of reserve power. The GRTN procures in that way reserve production capacity on a zonal basis. For this category of bids, GRTN accepts the bids during the day-ahead, the generators selected modify their generation plan as requested and the reserves are used, when need be, automatically by GRTN during the day of operation.

33. Generators can bid a given unit in any of those two categories, provided the unit is already forecast to produce after the day-ahead market. Prices are determined on the basis of a “pay-as-bid” mechanism between producers and GRTN. GRTN selects the bids depending on the nature and localisation of the problem to be solved and the price of the bids.

Retail electricity in Italy

34. Electricity retail supply consists in the sale of electricity to the final consumer[29]. On the supply side, there are the retailers, which may be vertically integrated with electricity generators and source the electricity from a parent company or acquire the electricity on the free wholesale market through bilateral contracts or on the power exchange. On the demand side, it is possible to distinguish the eligible customers, who are free to choose their supplier, and non eligible customers, which are bound to their local retailer. For the purpose of the present decision, the Commission will focus on the supply to eligible customers, as this is the only segment in which competition can take place[30].

35. In Italy, in conformity with directive 2003/54/EC, as of July 1, 2004, all non-household end-users are eligible customers, representing a potential market, open to competition, of 225 TWh[31]. Until July 1, 2004, only the larger customers (essentially industries) were eligible[32]. Household customers will become eligible only in 2007. Currently, the eligible customers can choose to purchase the electricity from a supplier of their choice on a non-regulated regime or to remain in a regulated regime, being supplied at a regulated tariff by their local retailer. Considering that competition only plays for the customers having switched to the non-regulated regime and that those customers cannot go back to the regulated regime, the Commission’s analysis will essentially focus on the conditions of competition in the non-regulated regime.

36. In previous decisions the Commission further segmented the retail electricity market distinguishing (i) large industrial customers that are connected to the high and medium voltage grid and (ii) smaller industrial, commercial and household customers that are connected to the low-voltage grid[33]. For the purpose of the present decision this question can be left open, as the notified concentration does not raise competition concerns in any case.

Wholesale electricity in France

37. For the sake of completeness, the Commission will consider whether the concentration may have an impact in the French wholesale electricity market. However, for the purpose of the present decision, it is not necessary to examine in detail the functioning of this market.

2. Relevant geographic markets

Wholesale electricity in Italy

38. In previous decisions, the Commission has always considered that wholesale electricity markets are national in scope.

39. However, as indicated above, in Italy, GRTN, and consequently GME, may theoretically divide the market in many possible zones[34]. In practice, the segmentation almost always occurs only between the seven “geographical zones”. Further, some geographical zones often have the same price, as shown by GME in its analysis of the configuration of zones for 2004[35]. The geographical zones of Centre North, Centre South and South most of the time constituted a single zone, Sardinia was almost always isolated, the North was isolated 26% of the time, Sicily was isolated 41% of the time and Calabria often isolated from both the South and Sicily. This result is coherent with the approach taken by the Italian Energy Authority ( Autorità per l’Energia Elettrica e il Gas , “AEEG”) and the Italian Competition Authority ( Autorità Garante della Concorrenza nel Mercato, “AGCM”) in a Joint Report published on 9 February 2005 (the “Joint Report”)[36]. The Joint Report carried its analysis on four macro-zones[37]: the North zone (covering the geographical zone of North), the Macro-South zone (covering the zones of Centre North, Centre South and South), Macro-Sicily (covering the geographical zones of Sicily and Calabria) and Sardinia.

40. The figures published by GME in its monthly trading reports during 2005 so far[38] and aggregated in the following table show that the day-ahead market continues to be usually split into different pricing zones due to congestion for more than three fourths of the hours in a given month[39]. Further, according to the same reports, the geographical zones North and Centre-North are usually the geographical zones with the lowest price, and Calabria and South the geographical zones with the highest price.

Percentage of hours without splitting into different zones (single price) | 17% | 20% | 29% | 23% | 17% | 12% |

Minimum average selling price of a geographical zone in €/MWh (and corresponding geographical zone) | 63.16 (CN) | 62.87 (CN) | 59.70 (CN) | 51.20 (CN) | 49.02 (N) | 57.81 (N) |

Maximum average selling price of a geographical zone in €/MWh (and corresponding geographical zone) | 76.54 (S) | 73.33 (S) | 68.40 (S) | 57.49 (S) | 61.46 (CA) | 68.68 (CA) |

Source: GME.

41. These mechanisms and statistical data about prices may point towards the existence of zonal markets. That being said, the analysis carried out by the Commission on the narrowest possible market (geographical zones, i.e. North and Macro-Sicily where the parties have virtually all of their activities) shows that the transaction does not raise any concern. Accordingly, the issue of whether the geographic market is national or zonal can be left open.

Ancillary services in Italy

42. In previous decisions, the Commission has always considered that ancillary services markets are national in scope. However, as explained above, the purchases carried out by GRTN on a zonal basis may point towards the existence of zonal markets. The analysis carried out by the Commission on the narrowest possible markets (geographical zones, i.e. North and Macro-Sicily where the parties have virtually all of their activities) shows that the transaction does not raise any concern Accordingly, the issue of whether the geographic market is national or zonal can be left open.

Retail electricity in Italy

43. The notifying parties argue that the retail electricity market in Italy is national in scope. This is in line with the previous Commission practice[40], also with specific regard to Italy[41].

44. The fact that at the wholesale level there might be several zonal markets does not appear to change this situation, given that the price splitting and the price compensation mechanisms between the different zones only concern the supply side. As indicated above, the purchasers always pay the single national price (PUN), irrespective of the place of delivery. In this regard, it should in particular be noted that the main retailers are active at national level and have a homogeneous pricing policy throughout the national territory.

45. The retail electricity market therefore appears to have a national dimension. For the sake of completeness, the Commission will however show that the notified concentration is not likely to raise competition concerns even at macro-regional level (in particular in the North zone where the retail activity of the parties is focused).

Wholesale electricity in France

46. In previous decisions, the Commission has always considered the electricity wholesale market as national. For the purpose of this decision, it is not necessary to evaluate further the precise geographic dimension of the market, as the concentration does not raise competition concerns in any case.

V. COMPETITIVE ASSESSMENT

1. Wholesale electricity in Italy

Non-coordinated effects

47. As already indicated, EDF has very little generation capacity in Italy, where it is mainly active through imports from the Northern borders. AEM has several power plants in the North of Italy and manages a part (20%) of Edipower’s generation capacity, which is mainly located in the North and Macro-Sicily zones. Finally, Edison has generation capacity mainly in the North and Macro-Sicily zones and manages a part (50%) of Edipower’s generation capacity.

48. Given the geographical location of the parties, the notified concentration may have a more important competitive impact in the North and Macro-Sicily zones. As some elements indicate that within Italy there may be a number of macro-regional wholesale electricity markets, the Commission’s analysis will focus on a possible North Italian market and a possible Macro-Sicily market. It is clear indeed that, if the concentration does not raise competition concerns in these possible narrower markets, it cannot raise concerns in a wider Italian market, where the position of EDF, AEM and Edison vis-à-vis their competitors and clients is weaker.

49. In order to evaluate whether the notified concentration raises competition concerns, the Commission will examine the main structural changes brought by this concentration, taking also into account EDF’s and AEM’s activities outside the joint venture. In this respect, even if EDF and AEM will continue to have independent activities in the Italian electricity market(s) beside those of the joint venture Edison, the Commission will assume that they will align to a large extent their competitive behaviour to that of Edison. It cannot be excluded however that in particular circumstances EDF and AEM may have different strategic goals, in order to maximise their own profits outside the joint venture.

50. This analysis should be carried out having in mind from the outset that the Italian wholesale market(s) are characterised by the presence of a very strong operator, Enel, which controls a very large part of the generation capacity in all the macro-regions (56% of the generation capacity at national level and 47% in the North zone which is by far the largest zone for consumption and generation). Further, Enel is indispensable to cover the demand in a very large part of the time (44% of the time in the North zone, 100% in the Macro-South zone, 29% of the time in Sardinia, and 24% in the Macro-Sicily zone in 2004)[42]. After the proposed concentration, EDF, AEM and Edison all together will continue to have a much smaller size than Enel.

51. To assess if the notified concentration may nevertheless significantly impede effective competition in the Italian wholesale electricity market(s), the Commission will examine the possible competitive impact of the concentration (i) due to EDF’s position as an importer of electricity in the North of Italy[43] and (ii) due to AEM’s competitive position in the Italian market(s). The Commission will then (iii) draw its conclusions on the competitive effects of the notified concentration considering together these two aspects.

(i) The possible impact due to EDF’s position as importer of electricity in the North of Italy

52. Italy is largely dependent on imports, which represented about 16% of the total available energy in 2003 and 14% in 2004. Italy is the Member State that imports the highest proportion of its electricity among the EU Member States[44].

53. The electricity is mainly imported in Italy from Switzerland and France and, to a more limited extent, from Slovenia, Austria and Greece. The level of imports in 2004 from these countries is indicated in the table below.

Country | Electricity imported to Italy in 2004 (GWh) | Electricity exported from Italy in 2004 (GWh) |

France | 17,228.9 | 576.1 |

Switzerland | 19,987.5 | 14.3 |

Austria | 1,626.4 | 0.0 |

Slovenia | 6,164.3 | 4.6 |

Greece | 1,418.5 | 195.8 |

Total | 46,425.7 | 790.8 |

Net import/export balance | 45,634.8 |

Source: GRTN.

54. In such a situation, it is important to examine EDF’s position in relation to imports, in particular on the French border, in order to evaluate whether the acquisition of joint control over Edison might change its import strategy. In particular, it should be considered whether EDF would have the means and the incentives to reduce imports’ volume and/or to increase imports’ price in order to raise prices in the North of Italy and, as a consequence, EDF's profits either directly or through its participation in Edison.

55. In this regard, it should be noted that the imports in Italy depend on the physically available interconnection capacity. Currently, a part of this capacity is reserved for the long term contracts concluded by EDF and Atel with Enel before the liberalisation of the electricity markets. The rest of the capacity is allocated half by GRTN and half by the TSO of the different neighbouring countries. Part of the capacity to be allocated by the GRTN is however reserved by Italian authorities to the Italian Single Buyer (which is responsible for the supply of electricity to the regulated market), to Vatican and San Marino, to the company Raetia Energie and, to a more limited extent, to Edison. The current situation of the interconnection capacity between Italy and the different neighbouring countries is shown by the table below.

Long term contracts | 1,455 (EDF/Enel) | 600 (Atel/Enel) | 0 | 0 | 0 |

Capacity allocated to Vatican and San Marin | 95 | 0 | 0 | 0 | 0 |

Capacity allocated to Edison and Raetia Energie | 0 | 190[45] | 0 | 0 | 0 |

Capacity allocated by grid operators other than GRTN | 597 | 1,625 | 110 | 190 | 50 |

Capacity allocated by GRTN to the free market | 349 | 1,038 | 60 | 215 | 50 |

Capacity allocated by GRTN to the Single Buyer | 154 | 397 | 50 | 0 | 0 |

Source: AEEG. Figures describe current situation from January 2005.

56. Taking into account the criteria for the allocation of the interconnection capacity at the Italian boarders, it appears however that EDF is not in a position to control to a significant extent the volume and/or the price of the imports in Italy, for the following reasons.

57. First, as far as the EDF/Enel long term contract is concerned, it should be noted that the terms of this contract, signed in 1988, are already fixed and leave little flexibility to EDF. It is also important to note that, pursuant to Italian law, the electricity sold to Enel under this contract does not go in the free market, but has to be acquired by the Single Buyer for the supply to non-eligible customers[46]. Thus, EDF cannot affect the competitive conditions on the market with this contract. It should be noted that this contract has a limited duration and will expire at the end of 2007: by January 2008 at the latest[47], the capacity reserved for this contract will therefore be allocated by the French and Italian TSO on the basis of the general rules.

58. Second, EDF has no preferential access concerning the interconnection capacity allocated by the Italian TSO (GRTN). According to the mechanism approved by the Italian Energy Regulator, GRTN allocates the capacity under its responsibility which is not reserved for the Single Buyer, the Vatican and San Marino by an implicit auction. This works on the basis of “virtual biding zones” covering each border[48]. In each zone, operators make sale or purchase offers of electricity and interconnection capacity is then allocated implicitly to the offers that are selected[49]. This mechanism therefore allows the allocation of interconnection capacity in a non-discriminatory way, and does not favour EDF or any other operator in having access to this capacity. Moreover, given that imports are always profitable and will remain so for the foreseeable future (see paragraph 18), imports are price-takers and the price of the virtual zone never influences the price of the physical zones decided in IPEX[50].

59. Third, EDF has no preferential access concerning the interconnection capacity allocated by the French TSO (RTE). According to the mechanism approved by the French Energy Regulator, RTE allocates the capacity under its responsibility by an explicit auction mechanism: eligible operators[51] bid for the access to this capacity, which is allocated to the best bidders on a “pay as you bid” scheme. Once the operators have acquired the right to have access to the interconnection capacity, they can use this capacity to sell electricity in Italy. This mechanism therefore also allows the allocation of interconnection capacity in a non-discriminatory way, and does not favour EDF or any other operator in having access to this capacity. The fact that EDF has no preferential access to the capacity allocated by RTE is also demonstrated by the data on the allocation of capacity in the first six months of 2005, which show that EDF only obtained in average around [10-20]% of the available capacity. By comparison, another operator, Endesa, obtained around 34% of the available capacity.[52]

60. Fourth, EDF has no preferential access concerning the interconnection capacity allocated by the Swiss, Austrian, Slovenian and Greek TSOs . In particular, the Swiss TSO essentially grants a preferential access to the Swiss operators (Atel, BKW, EGL, EOS, NOK and Ratia Energie), while Austrian, Slovenian and Greek TSOs have non-discriminatory explicit auction mechanisms.

61. From the above considerations, it appears that EDF is in competition with a significant number of operators to get access to the available interconnection capacity. This competition is particularly strong, due to the important price differentials between the Italian and the neighbouring spot markets prices, which has been always above 20€/MWh[53]. In this regard, it should be noted that this price differential is so high that operators which do not have generation capacity in the neighbouring countries have also a strong incentive to acquire electricity in these countries (through bilateral contracts or in the power exchange) and resell it in Italy.

62. In particular, if EDF significantly reduced its imports in Italy, the corresponding interconnection capacity would be allocated to other operators and the overall level of imports would remain unchanged. The prices in the North of Italy would therefore not be affected and EDF would simply reduce its import revenues.

63. Also, if EDF booked capacity through the RTE auction without using it, this strategy would cost EDF the price of the auction and EDF would have to recoup this cost (which is usually close to the price difference between Italy and other markets, i.e. around 40% of the Italian price[54]) and the foregone profit (which is at least[55] the price difference between Italy and other markets, i.e. around 40% of the Italian price) through higher benefits on its production in Italy. Further, if this practice drove up prices in Italy, this would create more competition in the auction for access to interconnection capacity, thus driving up the costs of such a practice. This appears a very costly activity compared to the more straightforward profits obtained from selling directly imports into Italy

64. The competitors’ reaction would equally deprive of effect a possible attempt to raise the prices of its imports of electricity and, as a consequence, the prices in the North of Italy. As a matter of fact, this strategy would not be possible under the GRTN implicit auction mechanism, as EDF’s higher sell offers would probably be unsuccessful and the interconnection capacity would be allocated to other operators.

65. This strategy would also not be credible under the RTE explicit auction mechanism, where EDF can acquire the interconnection capacity and then decide the price at which to sell electricity in Italy. Assuming indeed that EDF higher selling prices could actually bring an increase of the prices in the North of Italy, this would increase the price difference between France and Italy and therefore the profits for the importers. In order to realise these higher profits, the operators competing for the access to the interconnection capacity would thus bid higher prices in RTE’s explicit auctions, undermining EDF’s strategy.

66. In light of the foregoing, it therefore appears that the high degree of competition for the import of electricity in Italy (due to the high price differential with the neighbouring countries) and the fact that EDF has no advantages in getting access to the available interconnection capacity do not allow EDF to significantly control the volume and/or the price of the electricity imported in Italy.

67. Moreover, it does not appear that in the longer term EDF could significantly influence the volume of electricity imported in Italy by blocking or delaying RTE’s projects for the development of new interconnection lines.

68. In this regard, it should be first noted that it is far from established that EDF would have an interest in limiting the development of new interconnection capacity by RTE, considering the profitability of this kind of projects between France and Italy.

69. It also has to be considered that the development of new lines largely depends from the decisions adopted by the competent national authorities. The possibility for EDF to influence the decisions on the construction of new lines appears therefore quite limited.

70. In addition, it is important to underline that the Italian authorities can develop new lines on other borders, and in particular on the Swiss, the Austrian and the Slovenian ones. Currently, a project for a new 380kV line with Slovenia and a project for a new 132kV line with Austria are being developed. The Italian authorities could thus react to any possible intervention of EDF to delay or block the construction of new lines at the French border[56] by developing new projects on the other borders. Hence, this strategy might be counterproductive for EDF.

71. As a consequence, it appears that an intervention of EDF to block or delay the construction of new lines by RTE is not very likely and would not significantly reduce the volume of the imports in the long term.

72. For the abovementioned reasons, there is no reason to consider that the concentration will have a significant impact on the wholesale market in the North of Italy due to EDF’s position as importer.

(ii) The possible impact of AEM’s competitive position in the Italian market(s)

73. First of all, it must be noted that AEM does not add a very large part of the total generation available in the market. The following table provides the share of the working generation capacity of the main operators on the market in the different zones and in Italy as a whole. Even in the North zone where it has most of its capacity, AEM would add only 6.6% of the total generation capacity and the parties would, after the transaction, combine 18.3% of the total generation capacity. This is much smaller than Enel which controls 47.3% of the capacity in that zone. In the Macro-Sicily zone, AEM would add 4.4% of the total generation capacity and the parties would have 15.5% of the total generation capacity after the transaction, compared to 52.3% for Enel. Thus the transaction does not seem to challenge Enel's position on the basis of the working capacity of the operators involved.

Firm | Working capacity, 04-09/2004 |

AEM (including its Edipower stake) | 6.6% | 0.5%* | 4.4%* | 0% | 4.1% |

EDF | <1% | <1% | <1% | <1% | <1% |

Total parties | 18.3% | 3.9% | 15.5% | 0% | 12.3% |

Enel | 47.3% | 71.9% | 52.3% | 38.9% | 56.0% |

GRTN (CIP 6 energy) | 5.4% | 13.7% | 15.2% | 23.8% | 9.8% |

Endesa | 7.7% | 4.1% | 4,1% | 30,8% | 7.1% |

Enipower | 5.8% | 1.7% | 0% | 0% | 3.7% |

Tirreno Power | 2.2% | 2.2% | 0% | 0% | 1.9% |

Idroenergia | 2.1% | 0% | 0% | 0% | 1.1% |

Atel (including its Edipower stake) | 2.7% | 0.5%* | 4.4%* | 0% | 2% |

SIET (including its Edipower stake) | 2.6% | 0.3%* | 2.2%* | 0% | 1.7% |

Asm Brescia | 1.6% | 0% | 0% | 0% | 0.9% |

Aceaelectrabel | 0% | 1.3% | 0% | 0% | 0.5% |

Others | 4.4% | 0.5% | 6.1% | 6.5% | 3.2% |

Total | 100% | 100% | 100% | 100% | 100% |

Source: Joint Report and Commission calculations. An asterisk (*) indicates that the operator has capacity in that region only through Edipower.

74. Given the rules about systematic dispatching of certain generation (CIP6) and given that operators may have differing generation portfolios and thus differing competitive advantages, it is important to check the share of effective generation taking into account CIP6 production[57]. Data provided by AEEG to the Commission show that the position of the parties as well as that of Enel are not as big as their plant portfolio size (the effect being bigger for Enel which has a much larger portfolio), whereas several other operators have in fact a bigger market share on the basis of effective generation. The same data show also the impact of the systematic dispatch of CIP6 energy, which represents several times more than its corresponding share of available effective generation. In any event, on that basis the transaction reinforces the second operator without giving rise to any concerns in the light of the difference remaining with Enel and the existence of the several other important operators.

75. Further, the Parties noted that the Joint Report has concluded that EDF and AEM were not indispensable (not even potentially) to cover demand in any of the four macro-zones, and that Edipower was indispensable to cover demand only in the Macro-Sicily zone (Edipower was in particular absolutely indispensable for 19% of the hours). On that basis and on the basis of the results of the same analysis for Enel, the Parties found that the transaction would not lead to any serious concern.

76. In order to check the validity of this statement, AEEG has provided to the Commission an update of this analysis for AEM-Edipower-Edison together[58] and for Enel for the period January-June 2005.

77. According to this updated analysis, AEM-Edipower-Edison together would not be “absolutely indispensable” anymore to cover the demand in the Macro-Sicily area during the considered period[59] whereas it would be “absolutely indispensable” to cover demand for 1.2% of the hours in the North zone. Moreover, AEM-Edipower-Edison together were potentially indispensable during 5.5% of the hours by combining the Macro-South and North zones. In addition, it should be noted that the position of AEM and Edison would be even less pivotal as they actually control only 70% of Edipower’s capacity (the rest being controlled by the other tollers, Atel and SIET)[60].

78. As regards Enel, the conclusion of AEEG was that, for the period January-June 2005, Enel was still “absolutely indispensable” to cover demand for 38.9% of the hours in the North zone and 15.9% of the hours in Macro-Sicily, and was “potentially indispensable” for 95.7% of the hours by combining the Macro-South and North zones.

79. Thus, this updated analysis confirms the assertion of the parties that the merger does not affect seriously the strong position of Enel in the market and that Enel is almost always the absolutely indispensable operator necessary to meet demand. By contrast, the position of the parties is not enhanced by the transaction.

80. That being said, the Commission is aware that market shares and such structural data may not be sufficient to analyse competition in electricity markets. Indeed, an operator can also influence the price in a power exchange such as IPEX even if it is not indispensable to meet demand[61].

81. In IPEX, operators bid power of each of their generation unit separately and, as explained above, IPEX aggregates quantities proposed by bids from the lowest bid-price to the highest one, creating a bidding curve. When determining their bid characteristics, operators take into account their costs as well as other parameters and constraints:

82. operators can actually assign some of their production for their own downstream retail activities and sell only the surplus in the power exchange: in such cases, they do not bid some units at all and they sell a variable surplus quantity on the exchange, which means that units may be bid at some hours or during some periods and not during others;

83. Italian regulations impose that some generation units (CIP6) are systematically dispatched and thus bid at zero (accepting whatever price the market decides)[62];

84. Some units are systematically bid at zero by their owners due to technological constraints[63];

85. Some operators may actually bid higher than their costs for other reasons[64].

86. Points a, b, and c above reduce in practice the number of non-zero bids. This creates other (or more) possibilities for an operator’s bids to constitute a continuous part of the non-zero bidding curve. Points a and d modify the bidding curve over time[65].

87. The demand in electricity power exchanges (also in IPEX) is relatively inelastic and thus the demand side curve is very close to a downwards step whose vertical line cuts the offer curve at a level that depends on the hour in the day, economic activity, climatic conditions and other factors.

88. If an operator’s bids constitute almost a continuous part of the bidding curve for a substantial range of the total amount of electricity offered, and if the demand falls during some hours in this range, this operator can first witness that its bids are systematically setting the price when demand falls within this range and then increase its bids, theoretically up to the level of the next competitor’s bids on the bidding curve, when it estimates that demand will fall within the range of the bidding curve where it has a significant number of bids. This is all the more feasible in IPEX as the Italian TSO publishes an estimate of the level of demand for each half hour the day before and the actual level of demand ex-post. It could be argued that an operator is also in a position to do so if its bids constitute most of the bids in a part of the bidding curve (i.e. a few other small bids interspersed with its bids will not affect it).

89. If the transaction led to the creation of a situation where AEM-EDF-Edison would “control” a range of the bidding curve, it could in principle affect competition. The transaction could in principle lead to such a situations if the addition of AEM’s bids to those of Edison (EDF has virtually no generation capacity to bid in IPEX and imports have no impact on the bidding curve[66]) leads AEM-EDF-Edison to be the only (or quasi-only) bidder in a given and sufficiently large range of the bidding curve. In order to assess this, the AEEG has provided the Commission with figures about the results of bidding in IPEX.

90. In the North zone, during the period January-June 2005, Enel bids have been setting on average every month the price for [85-95]% of the hours, Edison for [0-5]% of the hours, AEM for [0-5]% of the hours, and other operators for [0-5]% of the hours. Clearly, Enel is controlling most of the bidding curve to be able to set the price so often in that zone. In terms of volume, Enel determined the price on [85-95]% of the total volume sold during the period, whereas Edison determined the price on [0-5]% of the total volume sold during the period and AEM on [0-5]%. Thus the volumes sold do not modify substantially the picture[67]. Further in 2004, as published in the 2004 annual report of GME, Enel had been setting the price for 82.5% of the hours, substantially less than during the first semester of 2005. Thus the capacity of Enel to set prices does not seem to be decreasing, but rather the contrary. Accordingly, there is no reason to believe that the parties can actually control the bidding curve on their own and push up prices through their bids.

91. In the Macro-Sicily zone, during the period January-June 2005, Enel bids have been setting on average every month the price for [85-95]% of the hours, Edison for [0-5]% of the hours, AEM for [0-5]% of the hours, and other operators for [0-5]% of the hours. Clearly, in this zone as well, Enel is controlling most of the bidding curve to be able to set the price so often in that zone. In terms of volume, Enel determined the price on [85-95]% of the total volume sold during the period, whereas Edison determined the price on [0-10]% of the total volume sold during the period and AEM on [0-5]%. Thus the volumes sold do not modify substantially the picture. Further in 2004, as published in the 2004 annual report of GME, Enel had been setting the price for 85.9% of the hours, substantially less than during the first semester of 2005. Thus, once again, the capacity of Enel to set prices does not seem to be decreasing, but rather the contrary. Accordingly, there is no reason to believe that the parties can actually control the bidding curve on their own and push up prices through their bids.

92. In light of the foregoing, there is therefore no reason to believe that situations where AEM-EDF-Edison could “control” the bidding curve and push up prices in IPEX would occur more often after the transaction than before.

93. Accordingly, the Commission considers that that the notified concentration does not have a significant impact on competition in the Italian wholesale electricity market(s) due to AEM’s competitive position.

(iii) Conclusion

94. Since the notified concentration does not have a significant impact in the Italian wholesale electricity market(s) due to EDF’s imports nor due to AEM’s competitive position in Italy, the Commission considers that it will not have non-coordinated effects so as to significantly impede effective competition.

Coordinated effects

95. Some market participants have expressed to the Commission concerns about a possible coordination between EDF-AEM-Edison and Enel.

96. In this regard, it should be mentioned that Enel has recently signed with EDF a Memorandum of Understanding which includes the following provisions: [...].

97. While bilateral contracts are not transparent and differ from each other, electricity sold on the IPEX day-ahead market has standard characteristics and covers about two thirds of total generation in Italy. Thus, at least theoretically, there might be a possibility that coordination takes place in IPEX if, instead of having three operators controlling a large part of the bidding curve (as explained above), only two operators do so.

98. That being said, the transaction might raise questions of coordination only if it creates means and incentives to coordinate significantly higher than those existing before. That may in theory stem from the fact that Edison-AEM-EDF now represents a larger and more attractive partner for coordination.

99. However, it is important to recall that Enel is already (see paragraphs 86 and 87) setting prices most of the time in the North and Macro-Sicily zones and that other operators are setting prices for a negligible amount of hours. Thus a coordination aimed at raising electricity prices could in theory take place with Enel, but not with other operators.

100. Further, a hypothetical coordination between AEM-EDF-Edison and Enel, if practicable, might be interesting only for a limited number of hours during the year given the already very large number of hours when Enel is setting the price. Moreover, the asymmetry of market position between AEM-EDF-Edison and Enel makes this coordination unlikely, if practicable. Further, coordinating with Edison is already possible for Enel before the transaction and AEM is not adding a substantial price-setting power. On top of that, there are other operators on IPEX. This further reduces the likelihood of coordination. Thus, to start with, the transaction does not appear to put seriously into question in the short term the leader-follower situation in IPEX.

101. In addition, certain conditions are necessary for coordination to be likely and sustainable: the EC Court of First Instance[68] has considered that coordinating firms must be able to monitor each other’s behaviour to a sufficient degree, a credible deterrence must be available in case of deviation and the reactions of outsiders must not jeopardise the expected results of coordination.

102. Firstly, monitoring of each other in IPEX is far from being an easy task: there is no publication of the bids of operators, and no publication of which bid has set the entire market or zonal clearing price(s). There are mainly publications of the market(s) clearing prices. Thus it is very difficult to monitor that partners of a coordination strategy effectively abide by their promises, unless one represents a large part of the bids that are close to the bids determining the clearing price and thereby can guess the behaviour of the partners which are also close to the determining bid. Only Enel is in such a position according to the frequency of price-setting.

103. Secondly, where deviation is profitable, the main deterrence to punish deviation available to generators in Italy active on IPEX is to return to their previous behaviour or to bid more aggressively than their previous behaviour. Only Enel has the means to retaliate against another generator, as it could induce a price decrease in the North zone while recouping losses with higher prices in other zones where it is stronger (in particular Macro-South)[69]. But all others have no real possibility to sustain such strategy given that it would cost them without any perspective of convincing the partner to return to coordination. This conclusion is supported by the Joint Report which states that Enel is the only operator in a position to credibly threaten retaliation against other operators.

104. That being said, the MoU may establish a link (multi-markets contacts) between the two incumbents in respectively France and Italy. It could thus be argued that the entry of Enel into France through this MoU would lead to some symmetry of positions in both countries, which could alter the two incumbents’ incentives to compete in one market by fear of retaliation in the other market. It should however be considered that the respective positions of EDF/Edison and Enel in each other home markets will be very asymmetric. In effect, Enel will have a portfolio of generation in France [0-2000] which is less than 2% of the installed capacity of EDF in France (102GW), whereas Enel will have only twice as much generation as the new entity in Italy. It would thus be very costly for EDF to retaliate against a lack of coordination in Italy through a decrease in French price, as EDF would be much more affected by a decrease of prices in France than Enel would be by a decrease of prices in Italy. In addition, AEM would need to compensate EDF for any such strategy. In this respect, the MoU does not provide more retaliatory power to the parties.

105. Thirdly, other operators could disturb coordination . Notably, entry in the North zone is going to be very substantial during the period 2004-2007 and could continue to be so given the need for investment in generation in Italy. As shown in the table hereafter extracted from the Joint Report, during the period 2004-2007, various operators will add 9,127MW of new capacity in the North zone. At the same time, effective generation was already at a level of 39,912MW in the North zone[70] in 2004 according to the same report. Peak demand in the North is estimated to reach a maximum of [25,000-40,000]MW by the end of 2007 according to GRTN[71]. Thus this new capacity will be far exceeding the growth of demand and total generation capacity in the North (not including imports) will exceed by far peak demand at the end of 2007.

106. The parties and Enel constitute around 27% of the added capacity, thus they could estimate the impact of new entry to that extent. But many other bids by competitors introducing new generation will be added in IPEX. Many market participants indicated to the Commission that the generation units portfolios will be modified as more and more gas-fired plants will replace (more costly) oil-fired ones in the price setting segment of the market. This will modify substantially the bidding curve, notably by inserting new bids between the bids of the coordinating entities, and introduce uncertainties upon it (by constant changes) that will a priori hamper substantially any possible coordination.

2002 | 2003 | 2004 |

EGL Italia | 5.7 | 6.9% | 9.7 | 10.4% | 13.1 | 11.6% |

Energia | 5.2 | 6.3% | 6.6 | 7% | 7.1 | 6.2% |

Dalmine Energie | 2.7 | 3.3% | 3.5 | 3.7% | 3.6 | 3.1 |

Energia e Territorio | - | - | 1.8 | 1.9% | 3.4 | 3% |

Total | 82.1 | 100% | 93.2 | 100% | <112.9 [77] | 100% |

109. Source: AEEG's 2002, 2003 and 2004 annual reports.

110. In such a situation, the notified concentration does not appear to raise competition concerns. In this regard, it should be considered that EDF, AEM and Edison have a relatively small joint market share and face strong competition from the incumbent Enel as well as many other operators.

111. It should also be noted that the data for the years 2002 and 2003 concern a period when essentially only the larger customers connected to the high-voltage and medium-voltage grid were eligible. These data show that, with regards to this specific group of customers, the parties also face a strong competition from several operators, and in particular from Enel, EGL Italia and Energia, in a very dynamic and competitive market. The data of 2004, which include six months in which all non-household customers were eligible, show furthermore that, on this larger customer base, the parties had a lower share. This implies that, as far as the smaller non-household customers are concerned, the parties’ share is smaller and they face an even stronger competition. Moreover, it should be mentioned that in the next years, following the liberalisation of the household customers, Enel will very likely benefit from being by far the larger incumbent retailer both at national and macro-regional level.

112. Finally, it appears that this evaluation would remain unchanged also considering the retail supply of electricity in the North of Italy. The parties provided that EDF, AEM and Edison’s 2004 sales in the North zone represented, respectively, [0-5]%, [0-5]%, and [0-10]% of total sales to eligible customers located in this area, i.e. less than [10-15]% all together. In the absence of statistical data on the sales of the different operators in this zone, it is not possible to provide figures for other operators. Nevertheless, this shows that the position of the parties in the North zone of Italy is not significantly different from that at national level and that the transaction as such does not raise competition concerns.

113. In the light of the foregoing, the Commission considers that the notified concentration does not significantly impede effective competition in the retail market(s).

4. Wholesale electricity in France

114. Some market participants have expressed concerns that, absent the merger, Edison might likely enter the French wholesale market and that the transaction thus removes a potential competitor for EDF. These claims have not been substantiated and it seems rather that there are little or no indications that, absent the merger, Edison might enter the French market.

115. First, Edison is very marginally present in France, with a turnover equal to 72 EUR million in 2004 compared to a turnover of EUR 5,596 million in Italy. This activity is even smaller (relative to the size of the markets[78]) to other marginal activities carried out by Edison in Poland (EUR 90 million) and Germany (EUR 46 million): it is not an indication of a substantial economic interest in the French market.

116. Second, Edison does not own any generation capacity in France, neither through participation in plants or through long-term purchase agreements for nuclear production by EDF (as is the case of other entrants or potential entrants in the French market[79]).

117. Third, Edison will not use its generation capacity in Italy to build a customer base in France, given that the price differential between French and Italian markets will remain (see paragraph 18).

118. In conclusion, the transaction does not remove a potential competitor for EDF and certainly not a main one. Accordingly, it will not significantly impede effective competition in the French market.

VI. CONCLUSION

119. For the above reasons, the Commission has decided not to oppose the notified concentration and to declare it compatible with the common market and with the EEA Agreement. This decision is adopted in application of Article 6(1)(b) of Council Regulation (EC) No 139/2004.

For the Commission, signed Joaquin ALMUNIA Member of the Commission

[1] OJ L 24, 29.1.2004 p. 1.

[2] Atel’s current shareholding structure is as follows: 58.5% Motor Columbus, 14.9% Elektra Birseck, Münchenstein (“EBM”), 7.9% Elektra Baselland, Liestal (“EBL”), 5.8% AEM, 5% Solothurn City, 2.2% IBA, floating 3.23%, 1.23% EDFI and 1.23% Atel (self-controlled). It is important to note that there is no shareholders’ agreement between the shareholders of Atel.

[3] See case COMP/M.3444 UBS/MOTOR COLUMBUS.

[4] Motor Columbus current shareholding structure is as follows: 55.64% UBS, 20% EDFI, 15.35% EOS, 4.94% Energie Baden-Württemberg AG (“EnBW”, a company jointly controlled by EDF) and 4.07% floating.

[5] [...].

[6] See case COMP/M.2792 EDISON/EDIPOWER/EUROGEN. In this decision, it is in particular explained that, in light of Edipower’s bylaws and the shareholders’ agreements, Edison is the only company which enjoys a number of veto powers in relation to all decisions of the Board of Directors and of the Shareholders Assembly, with the exception of the budget decision (point 8).

[7] The tolling agreement and the power purchase agreement have been notified to and approved by the Italian Antitrust Authority (see the decision n. 12742 I591 Edipower/Edison Trading/AEM Trading/Atel Energia/SIET , Bulletin no. 52/2003, where the two agreements are described in greater details).

[8] This stems from the nature of ancillary services as explained in the relevant section of this decision, as such services require an immediate reaction that only the operator of the plants (Edipower) can provide.

[9] This limitation has recently been declared contrary to Article 56 EC by the Court of Justice in Case C-174/04 Commission v Italy [2005] ECR I-0000.

[10] See Law Decree of May 14, 2005, no. 81.

[11] See case COMP/M.2532 FIAT/ITALENERGIA/MONTEDISON.

[12] This will happen in execution of the put options exercised by the other shareholders of IEB.

[13] EDF currently holds a 2.3% direct stake in Edison. Following the closing of the put option agreements, EDF will increase its direct stake in Edison to 5.3%.

[14] Concerning EDF and Delmi direct participations in Edison, it is agreed that they (i) shall vote their respective direct shareholdings in Edison, or abstain from voting or attending the meeting, in conformity with the behaviour of TdE and (ii) shall not use any right attached to such direct shareholdings in a manner inconsistent with any decision of TdE.

[15] On the notion of “affected market”, see section 6 III of Annex I to Commission Regulation (EC) N° 802/2004 of 7 April 2004 implementing Council Regulation (EC) N° 139/2004 on the control of concentrations between undertakings (OJ, L 133 of 30 April, 2004, page 16). In this regard, it should be noted that EDF has no activities in the Italian natural gas sector. AEM and Edison purchase gas for the production of electricity in their power plants and supply gas to Edipower under the tolling agreement described above. AEM and Edison do not supply gas to independent power producers and have a joint market share, at national level, well below 15% in the supply of gas to other customers, irrespective of the definition of the relevant market(s) with regard to specific customers’ groups. The presence of the parties in the downstream wholesale electricity market(s) (with a share well below 25% in any possible market definition) does not affect the competitive situation in the gas markets.

[16] See case COMP/M.3440 EDP/ENI/GDP.

[17] As regards distribution, only AEM is active in Italy and only EDF is active in France. As regards transmission, only EDF is active in France (through its subsidiary RTE) and only AEM and Edison are active in Italy. More precisely, in Italy, AEM and Edison own small segments of the transmission network, but the network is wholly managed by GRTN, which is totally independent from AEM and Edison.

[18] See case COMP/M.3440 EDP/ENI/GDP.

[19] According to the data published by the Italian Energy Authority Autorità per l’Energia Elettrica e il Gas (“AEEG”) on its website in July 2005, exports represented 792 GWh out of a total demand of 301,400 GWh in 2004 (i.e. less than 0.3%).

[20] Source: European Commission, Fourth Benchmarking Report, Annual Report on the Implementation of the Gas and Electricity Internal Market, Communication from the Commission, COM (2004) 863, 5.1.2005, Annex 1.

[21] Operators justify it notably on the basis of the different generation portfolios in France (mainly nuclear), in Switzerland (hydro) and in Italy (fossil-fuel, most notably gas). Accordingly, imports will remain price-takers on the Italian market.

[22] The virtual zones correspond to the half of the capacity of interconnectors at the Italian border that is managed by GRTN, the other half of the capacity of interconnectors is managed by the foreign TSOs on the other sides of the Italian border.

[23] For the Single Buyer, see in particular the 2005 Annual report of the regulator (pp. 183-184) available at http://www.autorita.energia.it/relaz_ann/05/04_cap_3_2005.pdf.

[24] These figures are available in the monthly trading reports published by GME on its website http://www.mercatoelettrico.org.

[25] GRTN sells “CIP6” electricity as explained above.

[26] During the initial period, i.e. from April 1, 2004 to the end of 2004, only producers were active on IPEX, the demand being passive and only constituted by the Single Buyer. Since January 1, 2005, the demand side is active and end users (directly or through retailers) may participate to IPEX by offering to buy certain quantities at specific prices (on the day-ahead and adjustment markets, cf. infra ). So far a few eligible customers have actually purchased electricity directly on IPEX.

[27] The value of offers is limited to ¬ 500/MWh.

[28] Please note that, first, volumes of electricity sold under bilateral contracts are taken into consideration to calculate the PUN, in order for the PUN to reflect the actual weight of each zone in the overall exchanges, and that, second, sellers of bilateral contracts are subject to a correcting factor equal to the difference between the PUN and the price of the zone where they are located (i.e. they are paid if that difference is negative). This system has been designed, according to the regulator AEEG, in order to address the short-term problems of congestion in the grid while giving longer-term market signals (i.e. the differential between zonal prices) independently of the forum of selling (through IPEX or a bilateral contract) in order to foster the construction of new generation capacities in zones lacking such capacities.

[29] See case COMP/M.3440 EDP/ENI/GDP.

[30] In the same sense, see for instance cases COMP/M.3318 ECS/SIBELGA and COMP/M.3268 SYDKRAFT/GRANINGE.

[31] Source: European Commission, Fourth Benchmarking Report, Annual Report on the Implementation of the Gas and Electricity Internal Market, Communication from the Commission, COM (2004) 863, 5.1.2005, Annex 1.

[32] See Article 14 of Decree Law n. 79 of 1999.

[33] See case COMP/M.3440 EDP/ENI/GDP.

[34] For system security purposes and based on physical limits to transfers of electricity, some zones have been defined by GRTN and approved by AEEG’s Decision 168/03. Geographical zones represent a portion of the national grid. The seven geographical zones are northern Italy, central-northern Italy, central-southern Italy, southern Italy, Calabria, Sicily, Sardinia. National virtual zones are Constrained Zones or Points of Limited Production. They include Turbigo, Monfalcone, Piombino, Rossano, Brindisi and Priolo. Neighbouring country’s virtual zones correspond to points of interconnection with neighbouring countries and attribute capacity on the part of the corresponding interconnectors that is managed by GRTN. These virtual zones are France, Switzerland, Austria, Slovenia, Corsica and Greece. Market zones are the aggregation of geographical and/or virtual zones such that the flows between the same zones are lower than the transmission limits notified by GRTN. This aggregation is defined on an hourly basis as a result of the resolution of the day-ahead market and adjustment market.

[35] The GME report for 2004 contains four “approfondamenti”, one of which is providing an “analysis of the zonal configurations” available at:

http://www.mercatoelettrico.org/GmeWebInglese/MenuBiblioteca/Documenti/RA_Configurazioni_zonali.pdf.

[36] The Joint Report “ Indagine consoscitiva sullo stato della liberalizzazione del settore dell’energia elettrica ” is available on the website of AEEG http://www.autorita.energia.it/elettricita/index.htm as well as on the website of AGCM, http://www.agcm.it/index.htm.

[37] The Joint Report defined these macro-zones on the basis of its analysis of residual demand.

[38] GME publishes monthly trading reports on its website http://www.mercatoelettrico.org.

[39] The average number of zones was usually above 3 during the months of 2004, whereas it is usually between 2 and 3 for the first semester of 2005. Thus the average number of zones is decreasing but market splitting remains an important feature of the market.

[40] See case COMP/M.3440 EDP/ENI/GDP.

[41] See cases COMP/M.2532 FIAT/ITALENERGIA/MONTEDISON and COMP/M.2792 EDISON/EDIPOWER/EUROGEN. This was also the evaluation of the Italian antitrust authority in case n° 13543 ASM Brescia/Ramo di azienda di Assoenergia , Bulletin n° 33-34-35/2003.

[42] See Joint Report, tables 13-16. No other operator is indispensable in the North and Macro-South zones, Endesa was indispensable in the zone of Sardinia for 67% of the time and Edipower in Macro-Sicily for 19% of the time.

[43] Imports of AEM accounted for less than [0-5]% of all imports every year during the period 2002-2004, thus AEM does not raise any competitive concerns as regards imports.

[44] Source: GRTN website, at: http://www.grtn.it/ita/sistemaelettrico/import.asp.

[45] Most of this capacity (150MW) is reserved to Raetia Energie.

[46] The Single Buyer actually resells the electricity to the different retailers which are in charge of the supply of eligible customers.

[47] The judgment of the European Court of Justice in the case C-17/03 adopted on 07/06/2005 puts into question the maintenance of this reservation.

[48] In each virtual zone, demand is constituted by what is removing electricity from the Italian market, i.e. by exports (i.e. virtually nothing in practice as explained above), and imports into Italy constitute the “offers” of the zone. On the offer side, bilateral contracts for imports are bid at zero and other interested operators can place their bids for the import of electricity (rather than for the access to the interconnection capacity): the TSO adds up all the quantities of the bids in the order of their price and the last accepted bid corresponds to the total capacity available: those operators whose bid has been accepted are certain to obtain the corresponding capacity on the interconnector. In order to offset the risks related to transportation costs involved by the price differential between zonal markets, it has also been elaborated a complex system of financial instruments for final users.

[49] The electricity corresponding to bilateral contracts is offered at zero (accepting whatever price the market decides). If there are too many bilateral contracts compared to the capacity available, capacity is allocated to them on a pro-rata basis.

[450] Ultimately, following a correction mechanism, imports done through the virtual zone without a bilateral contract are systematically paid at the price of the North zone.

[51] Entities eligible to participate in these auctions are: (i) any entity having obtained an authorization to trade power in at least one Member State of the EEA, (ii) any producer of electricity established in France and authorized to run a power plant, and (iii) any eligible customer.

[52] This figure is the average of capacity obtained by Endesa for the period January-July 2005, as advertised by that company.

[53] Source: European Commission, Fourth Benchmarking Report, Annual Report on the Implementation of the Gas and Electricity Internal Market, Communication from the Commission, COM (2004) 863, 5.1.2005, Annex 1.

[54] AEEG's 2005 annual report shows that on average during the first four months of 2005 the price was 16.85€/MWh. In practice, so long as the price remains smaller than the difference between Italy and other markets, operators who can procure in those markets can make a profit by procuring in those markets. It is all the more easy to do so as imports for operators who obtained capacity from TSO other than GRTN can now be bid directly into IPEX.

[55] In the case of EDF, which owns most generation in France, the lost benefit would be the difference between the price in Italy and the cost of production, thus even higher.

[56] In this regard, it should be noted that the only project which is being developed on the French border concerns a new line between Sardinia and Corsica. Considering that Corsica is a net importer of electricity, this line will mainly be used to export electricity to France. A delay in the development of the project would therefore have no (or very limited) impact on the Italian wholesale market.

[57] CIP6 generation is attributed to GRTN as this energy is not affecting competitive conditions between the operators, as explained above.

[58] In this regard, it should be noted that AEEG considered the whole capacity of Edipower, while in reality AEM and Edison manage together only 70% of this capacity.

[59] The change in the Macro-Sicily area stems notably from the coming online again of a plant of [...] MW of a competitor of the parties which was under maintenance during the period of the previous computation, according to AEEG. This shows how new generation capacity can change positions in the market.

[60] In practice, this overestimation is important as 30% of Edipower capacity represents 4% of the generation capacity in the North zone and 22% of the capacity of AEM-EDF-Edison.

[61] For bilateral contracts, the scope for anti-competitive practices is more reduced given the variety of characteristics of the transactions (e.g. terms and price formulas can vary), and the lack of transparency about prices and quantities sold by the different operators.

[62] According to the Article 3, paragraph 3, of the Bersani decree, the regulatory authority is responsible for fixing the criteria used to establish terms and conditions for the provision of dispatching services. The same paragraph mandates that a priority must be given to the dispatch of energy produced by renewable and cogeneration plants. AEEG's resolution n° 168/03 established accordingly in its article 19 the following order of priority for dispatching in case of an excess of supply: first, must-run units (for security purposes); second, non-programmable renewables; third, other renewables; fourth, cogeneration; fifth, CIP6; sixth, certain domestic sources of energy; seventh, bilateral contracts; eighth, other offers.

[63] For instance, co-generation units need to produce heat and the owners may thus have to bid at zero to be sure to be dispatched and produce heat for their needs or the needs of their clients.

[64] For instance, bids can take into account some strategic considerations.

[65] Operators who obtained capacity from TSOs other than GRTN can now bid directly into IPEX. However, as imports will remain price-takers (see paragraph 18), their bids will usually remain at zero.

[66] As explained before, imports in the virtual zones have no impact on the price and imports carried out with the capacity obtained from TSOs other than GRTN can be bid directly into IPEX. As imports are always profitable, they are price takers and it makes no sense to bid them at a high price with a risk to be left out while the auction fee for the capacity must be paid.

[67] The picture would have been changed if for instance one operator was setting systematically the price on peak periods, i.e. when the volumes are the highest, thus giving this operator a higher percentage for volumes than for hours of price-setting.

[68] See case T-342/99 Airtours vs. Commission [2002] ECR II-2585, paragraph 62.

[69] Following a report of AEEG in April 2005, the Italian Competition Authority has launched an investigation on possible discriminatory pricing strategies by Enel.

[70] This represents 53% of the total national effective generation capacity, which was 69,647MW.

[71] Data provided to the Commission.

[72] The energy offered by Edipower on this market is the difference between the maximum/minimum production of each plant and the sum of the energy already allocated by each toller to the day ahead market and adjustment market. Each toller (including Edison and AEM) benefits from the bid/offer to the extent of its “pro quota” for each individual unit and hour.

[73] For instance, in June 2005, for increasing energy production, only 212 bids of AEM were accepted (1% of all the accepted bids) whereas several other companies were much more active: 10991 bids for Enel, 3876 for Endesa, 1774 for Edipower, and 963 for Tirreno Power. Likewise, in June 2005, for decreasing energy production, only 35 bids of AEM were accepted (0.3% of all the accepted bids) whereas several other companies were much more active: 10233 bids for Enel, 1604 for Endesa, 1258 for Edipower, and 401 for Tirreno Power. See page 54 of the June 2005 report of GME.

[74] EDF had only 9 bids accepted during the whole period January-June 2005. See the monthly reports of GME.

[75] See Article 14 of Decree Law n. 79 of 1999.

[76] See decision n° 13543 ASM Brescia/Ramo di azienda di Assoenergia, Bulletin n° 33-34-35/2003

[77] Please note that this figure has been calculated by aggregating the sales to eligible customers realized by the main wholesalers listed in table 3.18 (pp. 139-140) of the IEA’s 2005 annual report. Accordingly, this figure underestimates, albeit to a minor extent, the total sales to eligible customers by wholesalers.

[78] The open market in 2004 was 275 TWh in France, 50 TWH in Poland and 500 TWh in Germany according to the Commission Fourth Implementation report.

[79] See in particular case COMP/M.1853 EDF/ENBW.

In the published version of this decision, some information has been omitted pursuant to Article 17(2) of Council Regulation (EC) No 139/2004 concerning non-disclosure of business secrets and other confidential information. The omissions are shown thus […]. Where possible the information omitted has been replaced by ranges of figures or a general description.

PUBLIC VERSION

MERGER PROCEDURE

ARTICLE 6(1)(b) DECISION