1. Electricity network tariff regulation The Italian experience
Electricity network tariff regulation
The Italian experience
Claudia Malandra - Emma Putzu
Tariffs department
Milan, 4th march 2010
Autorità per l’energia elettrica e il gas
Autorità per l’energia elettrica e il gas – Tariffs Department

2. Summary Introductory notes
Electricity network industry in Italy
Transmission
Distribution
Metering
Tariffs department main tasks
General questions related to network tariffs regulation
Criteria for tariffs regulation: the Italian legal framework
Criteria for tariffs regulation: the AEEG objectives
Tariffs setting process
Determination of the allowed costs
Cost allocation to customers groups
Tariffs setting
Domestic tariffs and vulnerable customers protection scheme

3. Transmission – From vertical integration to ownership unbundling
1962: nationalization of electricity industry: ENEL owns more than 90% of National Electricity Transmission Network
1993: beginning of privatization process (ENEL Spa)
1999: reorganization of electricity sector - a separated company is constituted as independent system operator (ISO)
under National Decree n. 79/99: property and management of National Transmission Network have to been separated
2004: from ISO to TSO – re-unification of ISO and ownership into a new independent electricity grid company (TERNA Spa) independent from ENEL – full ownership unbundling
Transmission assets are owned by: Terna Spa ( 98%), companies owned by municipalities, Railroad and other private companies
Progressive acquisition of assets from other owners
Company (belongs to ENEL S.p.A.) that owns more than 90% of National Electricity Transmission Network (high voltage and extra-high voltage);
Established under National Decree n. 79/99: property and management of National Transmission Network have to been separated;
But:
Law n. 290/2003 provides that:
Property and management of the Network have to been unified;
Any company that has activities in electricity or gas production, import, distribution and sale sectors, cannot own more than 20% of stockholders’ equity of companies that own and manage national electricity or gas network;
.P.C.M. 11 May 2004:
Not later than 31 October 2005 property and management of the network are unified;
Any company that has activities in electricity production, import, distribution and sale sector, doesn’t own more than 5% of the TERNA stockholders’ equity;
ENEL reduces its equity interests in TERNA stockholders’ equity: since the 1st July 2004 ENEL doesn’t own more than 20% of the stockholders’ equity, but it can exercise its right to vote (to elect administrators) only for 5% of the TERNA stockholders’ equity;
June 2004: 50% of TERNA has been placed in Pool

4. Transmission – Key Figures
Length of the lines:
380 kV about km
220 kV about km
kV about km
Trafo station:
380 kV N. 131
220 kV N. 148
150/132 kV N. 100
Number of transporters:
7 but … 98,23% of the network is owned by TERNA
Regulatory asset value or Rate Asset Base (RAB) (2008):
million Euro
Allowed operating costs (2008):
340 million Euro
Allowed capital costs (2008):
710 million Euro Remuneration of net invested capital
Total installed capacity:
119 GVA

6. Distribution – From vertical integration to legal and functional unbundling
1962: nationalization of electricity industry (ENEL)
Beside ENEL survived local distribution companies, owned by municipalities, small distribution companies operating in small non interconnected islands and a few other small companies (mutual companies)
In general all the companies were vertical integrated
1993: beginning of privatization process (ENEL Spa)
1999: reorganization of electricity sector – ENEL and companies serving more than final customers have to create a separate company for distribution and supply (legal unbundling)
ENEL Distribuzione Spa is constituted
2007: legal and functional unbundling of distribution and supply for companies serving more than final customers
companies serving less than final customers have to guarantee accounting unbundling of distribution and supply
distribution companies are also responsible for metering activities

7. Distribution – Key Figures
Length of the lines (31 December 2008):
High and very high voltage (km) 20,061
Medium Voltage (km) 372,239
Low Voltage (km) 815,041
Numbers of distributors:
143
Regulatory Asset Base (RAB) (2008):
21,000 million Euro
Allowed operating costs (2008):
2,000 million Euro
Allowed capital costs (2008):
 2,500 million Euro
Commercial costs of distribution
 630 million Euro

8. Metering – Key Figures
Regulatory asset value or Rate Asset Base (RAB) (2008):
 3,200 million Euro
Allowed operating costs (2008):
 260 million Euro
Allowed capital costs (2008):
 520 million Euro

9. Tariff department main tasks
Criteria for regulating tariffs of regulated infrastructures (electricity and gas)
Focus on non-competitive activities:
Electricity: transmission (HV), distribution (MV, LV) and metering
Tariffs setting and periodical revisions
Unbundling criteria and monitoring unbundling implementation
Functional unbundling (focus on infrastructural companies governance)
Transparency of accounts
Tariffs setting for levies (system charges) applied in order to finance activities of general interest (financing of R&D, decommissioning of old nuclear power plants, incentives to renewable energy)

10. Transport Tariff (TRAS c€/kWh) Metering tariff (MIS1 MIS3)
Prices and electricity tariffs in the III regulatory period
Price/Tariff
Costs
Generation
Price
Fuel and dispatching costs
Dispatching
FOCUS ON
Transmission
Transport Tariff (TRAS c€/kWh)
Transmission costs
Distribution
Distribution Tariff
Distribution costs
Metering costs
Metering
Metering tariff (MIS1 MIS3)
Supply
Supply costs
Price

11. Infrastructures cost and metering
Incidence of regulated activities on the final average customer bill (first quarter 2010)
(A) Production costs
63,8%
Taxes
14,0%
(B) System charges 8%
Infrastructures cost and metering
15,4 %
Regulated infrastructure tariffs represent:
about 15% of the electricity total price for household customers
(A) Production costs are inclusive of fuel costs, fixed generation costs dispaching costs. Production-capacity and interruptibility service, service remunerations and UC1 UC6 and PPE components
(B) System charges are inclusive of all components, plus component Uc4 and component MCT

12. Criteria for tariffs regulation: legal framework
Law no. 481/95
Transparency
Use of pre-determined criteria
Safeguard the interest of users and consumers
Reconcile the economic and financial objectives of electricity companies with general social objectives, environmental protection and efficient use of resources
Single tariff, by class of customers, at national level
Use of price-cap formula to increase efficiency
by establishing a transparent and reliable tariff system based on pre-defined criteria and by promoting the interests of users and consumers". The tariff system is required "to reconcile the economic and financial goals of electricity and gas operators with general social goals, and with environmental protection and the efficient use of resources".

13. Criteria for tariffs regulation: AEEG objectives
Incentive to efficiency: price-cap & profit-sharing
Transparency: separated transparent tariffs for different activities (transmission, distribution etc.), set in advance in order to avoid cross-subsidies between regulated and non-regulated activities
Simplicity: clear and simple tariffs for regulated activities facilitate the possibility to compare the non-regulated part of the final price (supply) and, therefore, competition in liberalised segments
Stability of regulation: reduce regulatory risks and, as a consequence, cost of capital

14. Efficiency incentives
The allowed costs
Efficiency incentives
OPERATING COSTS
Profit sharing
Price cap +
DEPRECIATION
Standard life +
CAPITAL REMUNERATION
Regulatory asset base

15. The operating costs
Operating costs or costs of external resources (personnel, procurement of materials and services) have to be reported in separate accounts and have to be documented
Annual revision by price cap mechanism + Profit sharing
Any operating cost reduction achieved in the first regulatory period, as a result of productivity gain over the 4% per-year target, has been shared between electricity companies and customers.
The companies’ share of the extra-gains was set at 50% in the last price control review.

16. Historical revalued cost
CAPEX
RAB =
+ net asset value
+ circulating capital
- Trust fund recovery
Historical revalued cost
The historical costs are revalue using the gross fixed investment deflator measured by the National Statistics Office
Rate of return
WACC
CAPITAL REMUNERATION

17. Capital remuneration (WACC)
Equity cost:
CAPM
Debt cost:
Risk free rate(*) + spread over (depending from real cost of regulated companies
WACC
Risk free rate is calculate using the 12 month average of gross returns on the 10 years Treasury bond (BTP)
Capital remuneration is calculated as weighted average of cost of equity and debt cost Weighted Average Cost of Capital (WACC)
(*) Risk free rate is calculated using the 12 month average of gross returns on the 10-years Treasury bond (BTP) benchmark taken by Bank of Italy

18. The WACC formula (1) Where: Ke is the return allowed on equity
T is the tax rate
E is the equity
D is the debt
Kd is the debt rate
tc is the tax shield
rpi is the expected average inflation rate

19. The WACC formula (2) Ke = rf + i (rm – rf) Where : rf risk free rate
The allowed return on equity has been calculated according to the CAPM methodology. CAPM is a model describing the relationship between risk and expected return that is used in the pricing of risky securities. CAPM says that the expected return of a security or a portfolio equals the rate on a risk-free security plus a risk premium.
  Ke = rf + i (rm – rf)
Where :
rf risk free rate
 systematic risk of the activity
rm expected market return

20. The WACC formula (3)
Parameters and rates used to fix WACC for period

21. Capital remuneration: more incentives for new investments
Adequate incentives for new strategic investments
Price-cap regulation needs quality regulation in order to avoid risks of lack of investments and bad technical performance
Quality regulation may not be sufficient: specific incentives for new investments (extra remuneration for some strategic investments crucial to facilitate competition)

22. From the allowed costs …to the cost allocation matrix
LV - Customers
MV - Customers
HV - Customers
Transmission Grid
HV – Distribution Grid
The allowed costs are allocated to differents customers following voltage connection.
MV - Distribution Grid
LV - Distribution Grid
Metering
Billing & Co.

23. Cost allocation to different customer groups
LV - Customers
MV - Customers
HV - Customers
Street lighting
Street lighting
Household
Other uses
Other uses

24. Cost allocation criteria 1/1
Network features
Transmission Grid
Meshed network – shared resource
Peak demand of customer groups
HV – Distribution Grid
Cost allocation criteria
Fix costs of transmission and distribution are allocated to different type of users on the basis of the load profile (in different hours of the day there is a different congestion so different costs)
Tariff component is calculated as energy consumption in each price period of each customer group weighted by prices per unit where prices are set following a peak load pricing approach

25. Cost allocation criteria 2/2
Network features
Costs allocation criteria
Mostly radial network – only partially shared resource
Costs are independent from the peak demand
Maximum subscribed demand of power (MV) customers/
Maximum subscribed demand of power corrected by a contemporary factor for LV customers
MV - Distribution Grid
Radial network/
Mostly dedicated resource
Costs are independent from the peak demand;
Effective demand of power
LV - Distribution Grid
Metering
Partially dedicated/Partially shared resources
Contractual average complexity of customer groups/
Costs of dedicated equipment
Subscribed demand
Billing & Co.

26. Balancing stability and cost reflectivity
The allocation criteria are the same from 1999
In order to balance the two potentially conflicting objectives of tariff stability and cost reflectivity, for the second and third regulatory periods the Italian Regulator, has decided only to adjust the vector of tariff constraints at the beginning of each regulatory period in function of the total allowed cost variations, keeping steady the cost allocation weights

27. Transmission and Distribution Services: Tariffs by Customer Types (€c/kWh)
The average national tariff covering transmission, distribution and metering costs for 2009 increased – as a whole – by 1.7% in comparison with 2008, i.e. from €c/kWh to €c/kWh. Increases were chiefly due to the high inflation rate (+2.4%). recorded in the months preceding the annual update, which rate is used in the formula applied for updating operating costs in accordance with the price-cap method. This implied a nominal increase of the portion of transmission and distribution charges covering operating costs, despite the annual recovery of efficiency on such costs as imposed by the applicable regulation.
The increase of tariffs further reflects a rise in gross and net invested capital, as a consequence of the investments made by operators and the effect of the revaluation of such investments, which revaluation is obtained by applying the gross fixed investment deflator measured by the Italian Statistical Institute (ISTAT).

28. The tariff system evolution
1997 – First tariff reform (del. 70/97)
First code of tariff regulation (2001)
2000 – 2003:
First regulatory period
2004 – 2007: del. n.5/04
Second regulatory period
Pool (1/4/2004)
Supply full opening
(1/7/2007)
Social protection for vulnerable clients ( )
2008 – 2011: del. n. 348/07
Third regulatory period

29. Relevant features of the tariff structure before the regulatory intervention
Tariffs did not reflect cost structure by customer class
Tariffs were higher than costs for non-residential low- voltage customers
Tariffs were lower than costs for high-voltage customers
Special tariff regime for State Railways, aluminium smelters and energy-intensive industries
Tariffs did not reflect cost of services (No unbundling between generation, transmission and distribution costs)

30. Relevant features of the tariff structure in the first and in the second regulatory period
Four yearly revision of tariff criteria (duration of regulatory period)
Tariffs were more cost reflective for different class of consumers
Unbundling of different costs of transmission, distribution and generation
The Regulator set the constraint on revenues and companies set tariffs
Distributors propose and the regulator approves tariffs options. Tariff options have to comply with constraints V1 and V2 set by the Regulator

31. Transmission and distribution tariff (not for domestic users) (del. no
Transmission tariff
Single tariff, by class of customers, at national level (energy tariff expressed in euro cent per kWh, flat without variation according to consumption level), yearly revision
Distribution tariff
Single tariff, by class of customers, at national level
Compulsory tariff for all distributors joint with a compensation mechanism in order to guarantee costs recover
Yearly revision
Three parts tariff
Flat component expressed in euro cent per customer per year
Power component expressed in euro cent per kW per year
Energy component expressed in euro cent per kWh

32. Metering tariff (not for domestic users) (del. no. 348/07)
Metering service
Meter installation, maintenance, meter riding and billing.
Metering tariff
Single tariff, by class of customers, at national level
Yearly revision
Flat tariff
MIS1: Power component expressed in euro cent per customer per year
MIS3: Energy component expressed in euro cent per kWh (only for street lighting)

33. The tariffs revision method
Tariffs component are fixed at the beginning of the regulatory period (four years) and yearly revised:
Capex component (non subjected to price cap):
The tariff components covering the allowed costs for the return on invested capital are adjusted annually by reviewing the capital itself using the average annual change in the gross fixed investment deflator measured by the National Statistics Office, and taking into account: any net investments carried out by companies the previous year; the incremental remuneration for new strategic investments, and the energy variation
Operating cost are subjected to price cap and revised yearly :
In the third regulatory period has been set a target productivity gain (X- factor) of 2.3% for transmission, 1.9% for distribution and 5% for metering.

34. Domestic tariffs Three domestic tariffs: D1, D2 and D3
D1 tariff is a reference tariff for domestic customers.
It is a cost reflective tariff but it is not applied to the customers
D2 tariff is for domestic customers in their place of residence, with contractual power till 3.3 kW (about 80% of domestic customers).
D3 tariffs is for:
domestic customers in their place of residence with contractual power over 3.3 kW and
domestic consumers in their spare homes (about 20% of domestic customers).
Tariffs D2 and D3 are set on the basis of the level of D1 tariff.

35. D1 structure D1 is a three parts tariff:
Flat component: expressed in euro cent per customer per year;
Power component: expressed in euro cent per kW per year;
Energy component: expressed in euro cent per kWh, (flat, without variations according to consumption level)

36. D2 and D3 structure D2 and D3 are three parts tariffs: Flat component
Power component
Energy component: increasing when the consumption level increases

37. D2 and D3 as transitory tariffs
D2 and D3 cross-subsidies are relevant
low-consuming customers with D2 pay less than high-consuming ones with D2 and customers with D3
For example, single men could pay less than low income families with a lot of children
Tariffs D2 and D3 are considered transitory tariffs moving towards D1 tariff.
Subsidies removal have to be gradual and linked to the implementation of a special tariff for vulnerable customers (the so-called “social tariff”). .

38. D2 convergence towards D1
Total Expenditure for residential customers (taxes not included)
Autorità per l’energia elettrica e il gas

39. D3 convergence towards D1
Total Expenditure for non-residential customers (taxes not included)
Autorità per l’energia elettrica e il gas

40. Social tariff and vulnerable customers
Social tariff is based on a political decision from the Parliament and Government
Vulnerability is defined according to economic or health conditions:
People with economic disadvantages
Customers in weak health conditions, requiring specific electrical appliances in order to survive
Additionality of benefits for customers in both conditions
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41. Social tariff Aim Compensation Burden recovery
To guarantee an average saving of 20% in electricity expenditure
The system is fully compatible with competitive energy markets
Compensation
Lump sum varying with the number of family members
Applied as a discount in the billing
Burden recovery
“Ad hoc” tariff component charged to all final users of the electric system, based on electricity consumption
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42. Access to social tariff
Based on existing indicators of family’s economic conditions (ISEE), already in use for TLC, schools, etc
ISEE is an indicator of poverty, not of “fuel poverty”
Application form ahs to be processed by local authorities (Municipalities)
Local authorities send relevant information to distributors through a computer system
Local authorities and distributors make controls
Activation of the discount in the billing
Yearly renovation required with new ISEE
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43. Figures Social tariff system has been working since 2009
Families which apply before February 2009 received the compensation for 2008 too.
More than 1 million people were admitted to the compensation in 2009 (about 90% for economic disadvantages; less than 10% for weak health conditions)
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44. Estimated annual consumption
Customers’ savings
Economic disadvantages
Family members
Estimated annual consumption
(kWh)
2008 bonus
(euro)
2009 bonus
2010 bonus
1-2 members
2200 60 58 56
3-4 members
2700 78 75 72
More than 4 members
4000
135
130
124
Yearly revision according to D2 trend
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45. Customers’ savings Weak health conditions 150 144 138
2008 bonus
(euro)
2009 bonus
2010 bonus
150
144
138
Yearly revision according to D2 trend
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46. Characteristics of the regulated pricing system for domestic consumers
Convergence towards cost-reflective tariff
Protection more focused on really vulnerable customers
Neutrality with respect to the liberalisation process
Promotion of efficient use of resources
Coherence with EU Directive
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47. Thank you
Questions?

48. Back up

49. THE WACC FORMULA (4)
Parameters and rates used to fix WACC for period

50. X factor
Planned productivity gains (X-factor) for the annual updating of operating costs
Activity
Regulatory period
Transmission
Distribution
Metering
4.0%
2.5%
3.5%
2.3%
1.9%
5.0%

51. CONSTRAINTS V1 AND V2 & TARIFF OPTIONS
II REGULATORY PERIOD - DISTRIBUTION TARIFF OPTIONS FOR FINAL NON-RESIDENTIAL CUSTOMERS
CONSTRAINTS V1 AND V2 & TARIFF OPTIONS
CONSTRAINT V1
Maximum total annual revenue which can be obtained by the distributor from a single customer category (verified ex-post). It is calculated on the basis of TV1 option.
CONSTRAINT V2
Maximum price, related to a standard quality service, which determines the maximum expense for each customer (verified ex-ante). It is calculated on the basis of TV2 option.
TARIFF OPTIONS
Distributors propose and the regulator approves tariffs options. Tariff options have to comply with constraints V1 and V2.

52. Protected –Tariff Service - Reference Prices for Average Consumers (with an annual Consumption of 2,700 kWh and a Power Capacity of 3 kW)
taxes general system charges (components A, UC4 and MCT) supply costs (including components UC1, UC5 and PPE) network costs (including components UC3 and UC6)

53. The equalization mechanism – del. no. 348/07
Law no. 481/95 fix single tariff at nation level and the introduction of equalization mechanisms between operators that have different costs of service.
Single tariff at national level imply that tariff components are set on the basis of average costs of users network but costs of services depend on users served and land features
The equalization mechanism guarantee the operators to recover allowed costs