LIBERALIZATION OF THE ELECTRICITY
SECTOR: THE CASE OF ITALY
Maggio 2009
1
The liberalization process (1)

Liberalization/privatization of public utilities in Europe started almost
20 years ago. In Italy at the beginning of the ‘90s

Before: publicly owned vertically integrated monopolies
1992: Enel becomes a public company owned by the government
(D.L. n. 333)


1995: an indipendent regulator (Autorità per l’energia elettrica e il
gas) is set up (L. 481/95)

1996: first European Directive concerning common rules for the
internal market in electricity (EU 96/92/CE)

1999: starts the restructuring os the electricity sector (DL 79/99
decree Bersani)
2
The liberalization process (2)

1999: Enel’s privatization starts: the first tranche is sold;

2003: second european Directive concerning common rules for the
internal market in electricity (EU 2003/54/CE)

2004: the Italian Power EXchange (IPEX) begins operating

July 2007: all customers are free to choose their electricity supplier
3
The liberalization process (3)
Main objectives
- increase productive efficiency;
- reduce transfers from public funds to public utilities;
A simple recepy
Competition when possible, regulation when necessary
But
….reality is not so easy
4
5
Outline

Market structure: where is competition possible? Where is
regulation necessary?

Why is electricity different?

Wholesale markets

Dispatching

Transmission and distribution

Electricity retail

Future scenarios

energy and sustainability
6
Market structure (1)
Distribution and
metering
Low voltage networks
Production
Transport and
dispatching
Technology and
different inputs:
water, fuel oil,
carbon, gas…
High voltage
networks centrally
controlled by TSO
Retail supply to
Industrial customers
Retail supply to
households
7
Market structure (2)
Where competition:

Electricity production: wholesale markets;

Electricity retail to final customers;

Metering (possibly). In Italy it is done by the distributor.
8
Market structure (3)
Where regulation:

transmission and dispatching;

distribution;

Metering (possibly)
9
Why electricity is different? (1)
Distinctive attributes:

Electricity cannot be stored: need for a network operator
continuously balancing physical supply and demand in the system by
controlling the power flows in the netwok. Relevance of netwok
congestions.

Transport: what is usually called “transport” is actually the use of a
shared infrastructure by all undertakings to balance aggregate
supply and demand.

Demand: demand is highly inelastic and has a seasonal pattern.
Moreover, because of limitations of the electricity meters and of the
data processing systems, small customers cannot be charged a
price equal to the actual costs of their supply (load profiling).

Supply: capital intensive; long term investments to enter the market
10
Why electricity is different? (2)
Therefore:

Wolesales markets are easly subject to market power exploitation:

High barriers to entry;
 Inelastic demand;
 Market splitting because of network congestion;

Coordination problems: need for a system operator and complicated
information systems.

High price volatility: wholesale prices are more volality than in other
commodity markets. Therefore the risk management issue is really
relevant

Investments: since electricity cannot be stored it is necessary to
have a capacity reserve margin to supply peak demand.
11
Wholesale markets
12
Wholesale markets (1)

Open to competition: many producers and many traders;

From 1° January 2003, no actor is allowed to produce or
import more than 50% of the total amount of electric power
produced and imported in Italy.

Enel has been required to reduce its generating capacity by
hiving off 15,000 MW. Three new Generation Companies
were created: Elettrogen, Eurogen and Interpower.

Bilateral contracts plus an organized market (Italian Power
Exchange IPEX: www.mercatoelettrico.org)
13
Wholesale markets (2)

The “Power Exchange” is a non compulsory spot market
where electricity transactions take place

It ensures the optimal management of the power plants
belonging to several actors according to their offers;

It provides a signal of transparent price upon which both
consumers and producers can take their decisions.

The core of the transactions on the IPEX is the Day-Ahead
Market (MGP) where wholesale trading of energy between
producers and wholesale customers takes place for each
hour of the following day, given the available transmission
capacity.
14
Wholesale markets (3)

Both sale (bid) and purchase (ask) offers can be submitted to
the Day-Ahead Market (MGP), consisting in a pair of quantity
(in Megawatthour-MWh) and unit-price (euro per MWh).

All offers refer to a specific hour and a specific geographic
zone

All supply offers are ranked by increasing price order into an
aggregate supply curve and all purchase bids are ranked by
decreasing price order into an aggregate demand curve.
15
Wholesale markets (4)
16
Wholesale markets (5)

If transmission constraints occur (the quantity Q* exceeds the
transmission capacity of the grid) the market is segmented in
different geographic markets (zonal markets) and prices are
differentiated by area.

Buyers pay the Single National Purchasing Price (PUN): a
weighted average of the zonal prices
17
Wholesale markets (6)
Italy
PUN
Total Quantity
Spot market
Bilateral contracts
Liquidity
69,77
26,0
16,8
9,2
64,50%
€/MWh
TWh
TWh
TWh
Example: average equilibrium prices and quantities traded
18
in February 2007 (GME, 2007).
Benefits from liberalization?
Efficiency
Averge efficiency of the italian generation plants
41,0%
40,5%
40,0%
39,5%
39,0%
38,5%
38,0%
37,5%
37,0%
36,5%
1998
1999
2000
2001
2002
2003
2004
19
Benefits from liberalization?
Investments in installed capacity
+ 11.080 MW
2002 - 2006
45% in the Nord
SOURCE: TERNA 2007
20
Benefits from liberalization?
Market power
99
Gruppo Electrabel
Altri produttori
1356
2005
2006
20.50%
21.90%
782
AEM Milano
available capacity
2006
792
64
Tirreno Power
3.80%
Tirreno Power
4%
2433
8%
Edipower
Gruppo ENI 18
Endesa Italia 24
5466
1017
8.10%
Endesa Italia
6533
Production
8.70%
5612
1120
281
Gruppo Edison
8.30%
8.90%
Gruppo ENI
9.20%
749
Edipower
7737
Gruppo Enel
14379
1019
0
11.70%
Gruppo Edison
13.10%
26160
5000
10000
Termolettrica
15000
Rinnovabile
20000
25000
38.80%
Gruppo Enel
34.80%
Idroelettrica
0%
5%
10%
15%
20%
25%
30%
35%
FONTE: Relazione annuale AEEG, 2007
21
40%
Dispatching
22
Dispatching

Terna Spa: public company responsible for dispatching

Terna ownes the transmission grid

All the undertakings have to enter a contract with Terna
for the dispatching service

A specific market is run by Terna to balance the system
after the MGP market is closed

Prices in the balancing market are very high
23
Transmission and distribution
24
Transmission and distribution (1)

These two services are natural monopolies: transmission is
done by Terna; distribution is done by local distributors
General principles (Law 481/95 and 290/03):

price cap regulation;

price discrimination on geographic ground not allowed;

Price-cap applied only to opex;

Revaluation of invested capital;

Allowed return on invested capital based on long term
risk-free rate;

profit sharing set at 50%;
25
Transmission and distribution (2)


Regulatory period of 4 years (2000-2003; 2004-2007)
Adjustment rule within the regulatory period:
Pt = Pt-1 * (infl –x + y + DSM+ Q)






Pt is the allowed price cap at time t;
Inf is inflation;
X is the productivity rate;
Y is a measure of unexpected increase in costs due to exogenous
factors;
DSM is an adjustment factor to recover costs related to demand
side management regulation;
Q is an an adjustment factor to recover costs related to better quality
26
Transmission and distribution (3)
Necessary steps to implement price-cap regulation:
 un-bundle the existing “all inclusive” tariff;
 decide how much price flexibility to leave to each distributor;
 set the “price level” for the base period equal to average
distribution costs;
 define a compensation mechanism to take care of
differences in costs among distributors;
 define the productivity parameter “X”
27
Transmission and distribution
1999
2006
Transmission
Transmission
Distribution
Distribution
Distribution
Commercial costs of distribution
+
Commercial costs of supply
Commercial costs of distribution
Metering
Metering
Fuel costs
Supply
+ commercial cost of supply
28
National average tariff for electricity
14
12
10
8
6
4
2.33
2.33
II
2003
2004
Costi trasmiss. e distribuz.
2.46
2.39
I
2.46
2.39
III IV
2.36
2.39
II
2.36
2.43
I
2.36
2.52
IV
2.36
2.52
III
2.33
2.52
II
III IV
I
II
III
IV
I
II
2.33
2.52
I
2005
Oneri generali
2006
2
0
2007
Costi di generazione
29
Minutes of consumption lost by low voltage
customers
200
180
160
140
120
100
80
60
40
20
0
1998
1999
2000
2001
2002
2003
Interruzioni di responsabilità del distributore
2004
2005
2006
Altre interruzioni
NET OF 2003 BLACK-OUT
30
Electricity retail
31
Electricity retail

European Directive 2003/54/CE: by July the first, 2007 all European
Countries have fully liberalized their retail market for electricity.

The economic debate has mainly focused on two big questions:
1.
weather and how retail competition in the electricity sector could bring
real benefits to European customers, expecially households, and
2.
weather and how customers should be protected by imposing
universal service obligations on undertakings operating in the sector

The two questions are actually related: the desirable extent of public
service obligations depends, up to a certain degree, on how
competition is expected to work
32
Why retail competition? (1)
Joskow (2000): Why do we need electricity retailers? Or can
you get it cheaper wholesale?

The peculiar attributes of electricity supply make many of the
traditional services provided by retailers in other industries irrelevant
in electricity.

Retail competition brings additional costs into the system: advertising,
promotion and customer service costs

A low-cost way for electricity consumers to buy directly would be the
wholesale market (BES)

In this way, retail consumers can receive the benefits of competitive
generation markets without incurring large increases in retailing
costs.
33
Why retail competition? (2)
Littlechild (2000): Why we need electricity retailers: A
reply to Joskow on wholesale spot price pass-through

Joskow underestimates the role of retailers with respect to
price, as opposed to quality

For most residential customers and most products, the
wholesale market is not the relevant alternative

Buying directly in the wholesale market does not avoid the
costs and complexities (e.g. load profiling)
34
What do retailers do in other sectors? (1)
Retailers usually add value to what consumers would
receive if they purchased directly in the wholesale
market.
1.
2.
3.
How:
By transporting the product and selling at convenient
locations;
By selling the product at convenient times of day and
days of the week (e.g. 24 hours shops)
By providing other services that offer consumers a more
convenient way to shop (e.g. internet stores)
35
What do retailers do in other sectors? (2)
4. By reducing search costs (selling a range of complementary
or subsitute products in the same location);
5.
By providing both pre-sale and post-sale information and
assistance to the customers;
36
Why electricity is different? (3)
Which added values from retailers?
1.
2.
3.
4.
5.
transporting the product and selling at convenient
locations; NO
selling the product at convenient times of day and days
of the week (e.g. 24 hours shops) NO
providing other services that offer consumers a more
convenient way to shop (e.g. internet stores) NO
reducing search costs (selling a range of
complementary or subsitute products in the same
location); NO
By providing both pre-sale and post-sale information
and assistance to the customers on the product; NO
37
Why electricity is different? (2)
More general:
1.
There is generally no direct physical relationship between a specific
generating source and a specific retail customer;
2.
Electricity is automatically available every second over the distribution
network and the supplier cannot be hold responsible for the physical
delibery;
3.
the only operator responsible for the physical delivery of electricity is
the transmission system operator.
The supply contract between a customer and her supplier
can be seen primarily as a financial contract.
38
How can electricity retailers provide added value?
A possible story (Joskow)
Therefore:
1.
The main added values by electricity retail suppliers
could be a financial service of risk hedging but this is
not a real issue because of poor metering
2.
They may provide new “products”, such as green
power options
3.
Retail suppliers usually do the billing
4.
Depending on market design, retail suppliers can be
responsible for other services, such as metering and
behind the meter services (eg energy management)
39
How can electricity retailers provide added value?
The other side of the coin (Littlechild) (1)
According to Littlechild, Joskow underestimates the
role of retailers with respect to price, as opposed to
quality/behind the meter services
What Littlechild calls price competition is actually
competition on risk hedging:
“The experience of Britain may be reasonably tipical.
For the first time, electricity retailers (…) asked their
customers what they wanted. Uniform fixed price, time
of the day or time of the year prices, interruptible prices,
Pool prices?”
40
How can electricity retailers provide added value?
The other side of the coin (Littlechild) (2)
Plus, Littlechild underlines the impact of retail
competition on demand elasticity:
“The customers meanwhile were equally active. (…)
They needed to estimate their likely electricity
consumption, (…) to work out load factors and seasonal
variations, and their scope for load management at
times of high prices”
…. and on wholesale markets’ performance
41
How can electricity retailers provide added value?
The other side of the coin (Littlechild) (3)
An active buying side brings to a more liquid and
efficient wholesale market:

competition will force retailers to be more careful in their
purchasing decisions, and this active demand side will
make the wholesale markets more competitive;

retailers can stimulate price responsiveness
customers: increase demand elasticity
by
42
What can retail competition do? (1)
First we have to define a benchmark:
1)
DSOs supply final customers
1)
2)
3)
4)
2)
Local monopoly
Need for price and quality regulation
Possible regulation: BES plus premium if added values
are demanded (eg. price hedging)
“Regulator knows all” kind of model
Auction to choose the retail supplier
1) Competition for the market
2) Price and quality determined by the auction
43
What can retail competition do? (2)
EXPECTED BENEFITS - COMPETITION CAN:
1. Increase productive efficiency of retailing:
by developing innovative retailing technologies that reduce
commercial costs;
2. by reducing the costs related to risk hedging
1.
2. Increase competition in the wholesale market: eg by easing
entry into the market
3. Increase allocative efficiency:
1.
By transferring all costs savings along to consumers;
44
What can retail competition do? (3)
EXPECTED COSTS - COMPETITION CAN:
1. Increase total costs:
1. By loosing economies of scope between distribution and supply
2. By increasing advertising and promotion costs
3. By increasing retailers’ profits
2. Decrease allocative efficiency:
1. Switching costs may give rise to market power
2. While new entrants can have an advantage in competing for new
customers it is very hard for them to compete for old customers
who are already attached to an incumben
3. …and any consumers who switch are likely to be less loyal,
hence less valuable, ones
45
What can retail competition do? (4)
Common barriers to effective competition:
1.
institutional barriers involving metering and data aggregation;
2.
limited unbundling of distribution and supply;
3.
limited access to reliable information on contracts and prices.
46
Universal service obligations (USOs) (1)

the European Directive 2003/54/CE on the internal
electricity market explicitly acknowledges the need for
customer protection.

Namely, the Directive requires that “Member States
ensure that all households customers and, eventually,
small firms enjoy universal service” (art. 3, point 3)

Universal service is defined as the right:
 to be supplied with electricity of a specified quality;
 at reasonable, easily and clearly comparable and
transparent prices
47
Universal service obligations (USOs) (2)

The interaction between universal service regulation and
competition in these market segments is direct and very
strong

USOs may determine the nature of competition that can be
sustained in the market.

Great attention must therefore be given to the definition of
USOs and to their implementation

ERGEG (European regulators’ group for electricity and
gas), position paper on End Users Price Regulation:
“End-user price regulation is one factor which prevents equal
access of suppliers to all customers. This has a negative
effect on the functioning of the competitive retail markets”
48
Universal service obligations (USOs) (3)

ERGEG, last June has published a Review on end-user price
regulation in European Countries

According to this review in the electricity sector in 2006, 17 out of 28
countries surveyed had some form of retail price regulation for
eligible customers (not households)

Moreover when regulated tariffs were available only a very small
percentage of customers had switched to the competitive market: in
most market segments more than 80% remained at regulated tariffs
and in many segments this percentage was close to 100%.

Finally, only in one country (Hungary) suppliers offering regulated
tariffs were chosen on the base of an open tender. What can retail
competition do?
49
Future scenarios: smart grids
Data management
50
Future scenarios: smart grids
“Smart Power System”
ICT
System design
“Smart” Metering
Load profiling
(settlement)
Regulation
DSOs incentive
regulation
“Smart” appliances
Coordination
and electronic devices DSOs and TSO Data management
“Smart” grid
Correct wholesale
Metering service
51
devices
signals
Obiettivi di sviluppo delle rinnovabili al 2020 (1)









Quota di rinnovabili su consumo interno lordo di energia
20% media EU
17% Italia - OBIETTIVO MOLTO SFIDANTE
Di cui quota di biocombustibili nel trasporto
10% media EU
10% Italia
Riduzione gas climalteranti
- 20% rispetto a 1990 EU
Obiettivi di efficienza energetica non espliciti
Ragioni dell’intervento

Le emissioni di gas serra generano un costo
ambientale di cui gli operatori non tengono conto nelle
proprie scelte

Soluzioni:
1) dare un prezzo al carbonio
2) sostenere lo sviluppo di tecnologie a basso
contenuto di carbonio, tra queste le rinnovabili



Sono due facce della stessa medaglia
Meccanismi di incentivo alle rinnovabili

Tre grandi famiglie:
Tariffe per l’energia elettrica prodotta (“feed in”)

Obbligo di acquisto di rinnovabili (“Quota”)

Contributi diretti all’investimento

Feed in tariff







Riconoscimento di una tariffa commisurata ai costi di
produzione per ogni kWh prodotto
Per un periodo sufficientemente lungo di anni
Vantaggi:
riduzione del rischio per l’investitore
Svantaggi:
Possibili errori nella definizione delle tariffe
Necessità di rivedere frequentemente le tariffe se la
tecnologia non è stabile
Quote e cv







I produttori sono obbligati ad immettere una certa %
di rinnovabili per ogni kWh prodotto;
In alternativa l’obbligo è posto sui consumatori
Spesso viene attivato un mercato organizzato per lo
scambio di certificati di produzione rinnovabile (CV)
Vantaggi:
È il mercato che seleziona dinamicamente le fonti
rinnovabili da realizzare e la loro remunerazione
Svantaggi:
Mercato difficile da disegnare; rischio
Contributi ad investimento

I contributi vengono erogati a copertura parziale dei
costi di investimento;

Vantaggi:
riduzione del rischio per l’investitore
Promuovere tecnologie capital intensive
Svantaggi:
Difficile da monitorare per evitare frodi
Possibili inefficienze nella selezione dei progetti da
incentivare





Gli incentivi in Italia
Principali meccanismi di incentivo oggi
operativi:




Feed in per impianti CIP6
Feed in per fotovoltaico
Feed in per altri impianti < 1MW
Quota obbligata e Certificati Verdi (CV)
CIP 6/92







Ambito di applicazione:
Incentivi non disponibili per nuovi impianti
Potevano essere ammesse sia rinnovabili che fonti
assimilate (es. cogenerazione)
Principali norme di riferimento
Legge n. 9/91
Provvedimento del Comitato Interministeriale
Prezzi (CIP) n. 6/92
DM 25.9.92
Conto energia (1)

Ambito di applicazione

Impianti fotovoltaici della potenza minima di 1 kW, collegati alla rete
elettrica, entrati in esercizio dopo il 30.9.2005 a seguito di nuova
costruzione, potenziamento o rifacimento totale.

Obiettivo almeno 1200 MW

Principali norme di riferimento

DM luglio 2005 (vecchio conto energia per anni 2005-2006)

DM febbraio 2007 (nuovo conto energia dal 2007)
Conto energia (2)

Tipo di incentivo: “feed in”

Tariffe incentivanti per 20 anni, che si sommano ai ricavi dell’energia
immessa in rete in caso di cessione, oppure ai risparmi sulla bolletta
in caso di autoconsumo (possibilità di fare lo “scambio sul posto”
per gli impianti fino a 20 kW)

Tariffe che premiano il grado di integrazione architettonica e l’uso
efficiente dell’energia

Richiesta di ammissione alle tariffe a valle dell’entrata in esercizio
dell’impianto (entro 60 giorni)
Conto energia (3)
FOTOVOLTAICI
Tariffe (€/kWh) per impiantiIMPIANTI
in esercizio
entro il
31 dicembre 2008 - DM feb 2007

Non integrato
2
Parzialmente
Integrato
Integrato
1 P<3
0,40
0,44
0,49
B
3  P  20
0,38
0,42
0,46
C
P  20
0,36
0,40
0,44
Potenza nominale dell Õimpianto
P (kW)
A
Fonte: GSE
1
3
Conto energia (4) - risultati al 1° nov 2007
Totale
Primo DM
MW
Nuovo DM
Numerositˆ impianti in esercizio
To
P
N
Potenza impianti in esercizio
Nuovo DM
MW
40
50,0
4.380
4.228
Totale
Primo DM
45,0
34,6
Nuovo DM
3.736
4 1,3
40,0
4 0 ,5
3.590
3.548
3.381
30,2
35,0
3.363
3 7 ,5
3 7 ,2
29,2
3 4 ,5
3.191
2.873
30,0
2.806
2.533
24,7 3 2 ,7
3 0 ,2
24,4
2.517
2 9 ,2
25,0
21,5
2 4 ,4
2 4 ,8
2.159
20,0
2 1,5
2 1,6 17,7
1.815
15,0
17 ,713,8
1.524
11,7
10,0
1.218
13 ,8
11,7
935
8,2
5,0790
680
6,5
8 ,2
681
ott-07
0 ,1
set-07
lug-07
1,0
giu-07
0 ,5
apr-07
0,5
0 ,4
1,0
0,1
3 ,3
1,8
nov-07
0 ,1
feb-07
0,1
ago-07
0 ,0
ott-06
0,0
1,0 1,9
mag-07
0 ,0
1,9 3 ,1
3,14 ,5
gen-07
0,0
0 ,0
dic-06
0,0
0 ,0
nov-06
0,0
set-06
0,0
lug-06
104
ago-06
40
giu-06
8
apr-06
0
mag-06
0
feb-06
0
16
67
mar-06
0
174
6 ,5
4,5
0,0
190
mar-07
373
442
278
0,4
3 ,8
1,0
1,8
Impianti rinnovabili < 1MW (1)

Ambito di applicazione:


Impianti a fonti rinnovabili ex art. 2, comma 1, let. A) d.lgs 387/103
entrati in esercizio dopo 1 gennaio 2008
Scelta dal produttore in alternativa ai CV

Principali norme di riferimento

Legge finanziaria 2008

Tipo di incentivo: feed in per 15 anni

Energia ritirata dal GSE e venduta sul mercato
Impianti rinnovabili < 1MW (2)








Eolico < 200 kW: 300 €/MWh
Solare PV: già prevista da conto energia
Geotermico: 200 €/MWh
Moto ondoso e forza maremotrice: 340 €/MWh
Idrico: 220 €/MWh
Rifiuti e biomasse diverse da punto successivo:
220 €/MWh
Biomasse e biogas da filiera corta (70 km): 30
€/MWh
Gas di discarica: 180 €/MWh
Quota e Certificati verdi (1)

Ambito di applicazione:


Impianti a fonti rinnovabili ex art. 2, comma 1, let. A) d.lgs 387/103 entrati in
esercizio dopo 1 aprile 1999
Rifiuti solo per la quota biodegradabile ex legge 296/06 entrati in esercizio
dopo 1 aprile 1999
Cogenerazione abbinata a teleriscaldamento e impianti ad idrogeno
(cosiddette ALTRE RINNOVABILI) se entrate in esercizio prima del 2009
Necessaria qualifica IAFR per tutti

Principali norme di riferimento

Dlgs n. 79/99 e dlgs 387/03

I DM 25 ottobre 2005

Legge finanziaria 2008


Quota e Certificati verdi (2)

Tipo di incentivo: quota con CV

I produttori e gli importatori di energia elettrica non rinnovabile devono
immettere in rete una quota di rinnovabile (% rispetto alla produzione e
import convenzionale)

la quota per la determinazione dell’obbligo 2008 è pari al 3,05% della
produzione e import convenzionale del 2007. Questa percentuale viene
aumentata dello 0,75% ogni anno a partire dal 2008 (ex L. finanziaria 2008)

Il certificato che attesta che l’energia elettrica prodotta è rinnovabile acquista
quindi un valore e può essere venduto nel mercato
Quota e Certificati verdi (3)

Modalità operative:

I CV sono titoli annuali attribuiti all’energia prodotta da
impianti alimentati da fonte rinnovabile con qualifica IAFR
Sono emessi per i primi 15 anni di piena produzione se
l’impianto è entrato in esercizio dopo l’1 gen. 2008. Eccezione
ALTRE RINNOVABILI (8 anni).
I soggetti obbligati adempiono all’obbligo annullando CV
corrispondenti presso il GSE
il GSE verifica annualmente l’adempimento degli obblighi;
I titolari di CV hanno tre anni dall’anno di emissione per
venderlo




Quota e Certificati verdi (4)

Modalità operative:

sono titoli al portatore; possono essere quindi negoziati
liberamente e possono cambiare mano più volte prima
dell’annullamento;
sono negoziati sul mercato disgiuntamente dall’energia.
dal 2008 è riconosciuto all’impianto 1 CV per ogni MWh
prodotto, moltiplicato per fattori K di aggiustamento per
tecnologia
questo equivale a modificare il valore della produzione:
maggiore è K più alta è la quantità di CV che il produttore può
vendere, a parità di produzione



CV: L.24/12/2007coefficienti K
Fonte
coefficienti moltiplicativi
per la determinazione
del numero dei CV
Eolica per impianti di taglia superiore a 200 kW
1,00
Eolica off-shore
1,10
Geotermica
0,90
Moto ondoso e maremotrice
1,80
Idraulica
1,00
Rifiuti biodegradabili, biomasse diverse da quelle di cui al punto
successivo
1,10
Biomasse e biogas derivanti da prodotti agricoli, di allevamento e
forestali, ottenuti nell'ambito di intese di filiera o contratti quadro oppure
di filiere corte (entro un raggio di 70 km).
1,80
Gas di discarica e gas residuati dai processi di depurazione e biogas
diversi da quelli del punto precedente
0,80
I valori dei coefficienti possono essere aggiornati ogni 3 anni con DM da MSE
Quota e Certificati verdi (5)

Modalità operative:

Mercato organizzato gestito dal Gestore del mercato elettrico
(www.mercatoelettrico.org), più bilaterali
Se la domanda è maggiore dell’offerta il GSE vende certificati verdi
per coprire la quota non soddisfatta dai terzi ad un prezzo di
riferimento pari a 180 €/MWh, meno il prezzo AEEG (medio orario
zonale dell’anno precedente, pari a 67,12 €/MWh nel 2007)
Il prezzo di vendita praticato dal GSE opera di fatto come un tetto al
prezzo di mercato quando vi è eccesso di domanda
Se l’offerta eccede la domanda il GSE ritira i CV in scadenza ad un
prezzo pari al prezzo GME dell’anno precedente (nel 2007 120,21
€/MWh; diventa il prezzo di ritiro nel 2009)



Contacts
Clara Poletti
Director
IEFE - Bocconi University
www.iefe.unibocconi.it
Tel. + 39 02 58363820
e.mail [email protected]
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