NATIONAL CONFERENCE ON REGULATION IN ... - Argentina.gob.ar Setting Power Sector.pdf/$… · “TARIFF SETTING IN THE POWER SECTOR” TERI NEW DELHI, NOVEMBER 14, 2000 JUAN LEGISA

Note: The following professionals have participated in this paper: Eng. Ernesto Kerszberg, Eng. Ciro Bohorquez and Economist Eduardo Lerner

NATIONAL CONFERENCE ON REGULATION IN

“INFRASTRUCTURE SERVICES: PROGRESS AND WAY FORWARD”

“TARIFF SETTING IN THE POWER SECTOR”

TERI

NEW DELHI, NOVEMBER 14, 2000

JUAN LEGISA , PRESIDENT

National Electricity Regulatory Commission (ENRE)

Republic of Argentina

The Argentine Electric Power Pricing System

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THE ARGENTINE ELECTRIC POWER PRICING SYSTEM

1- THE WHOLESALE ELECTRICITY MARKET 2- REMUNERATION FOR TRANSMISSION 3- DISTRIBUTION RATES 4- RATE ASPECTS IN THE REGULATORY FRAMEWORK


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THE ARGENTINE ELECTRIC POWER PRICING SYSTEM

1 - THE WHOLESALE ELECTRICITY MARKET

The Wholesale Electricity Market (WEM) consists of:

a) An Options Market comprised of contracts involving amounts, prices and conditions freely agreed upon by and between buyers and sellers;

b) A Spot Market where prices are established on an hourly basis according to the economic cost of production, represented by the Short Term Marginal Cost as measured at the System Load Centre;

c) A quarterly stabilisation System for Spot Market Prices, intended for Distributor purchases.

Furthermore, each WEM agent has:

* one or more exchange points on the Electric Power System; * one or more Market entry or exit points where his purchase / sale price is

defined. The value of energy is that set by the market. The Wholesale Electricity Market is the point where supply and demand meet. CAMMESA arranges all offered units in order according to increasing variable

costs. Then the economic dispatch is made by accepting the necessary machines offered to cover demand, selected in the above-mentioned order.

The energy price is defined on an hourly basis at the cost of the machine whose offer was accepted to cover the next MW to be supplied. This is the so-called optimum dispatch. The Market Price (MP) is defined at the resulting energy price for optimum dispatch in the Market, and is given by the Market cost of that machine.

Said value is understood to represent the price that buyers are willing to pay for their energy demands. The remuneration for capacity is an economic sign that generators perceive in order to supply the highest generation capacity requirements that may arise in the System. In the Argentine WEM, this goal is comprised in a variable remuneration for capacity made available either as dispatch operating capacity or reserve capacity. 1.1- Market Price and Node Prices Where are market prices set? In a system covering such a large territorial expanse as Argentina’s, the Market should be a geographically located site and the Market organisation and rules should take


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into account the relative location of supply and demand throughout the electric power system. In the Argentine WEM, the “Market” is located so as to coincide with the System Load Centre (the Ezeiza 500 kV node in the Gran Buenos Aires / Litoral Area), and each user’s Market Entry / Exit point is located on the Transmission Grid.

The energy price is defined in that Market Node and is called Market Price (MP):

In each of the other nodes in the grid the energy price must denote the cost of taking the energy to or from the Market node.

In each node of the transmission grid one energy price is defined, the Node Price (PN), calculated on the basis of the altered PM of the cost of transmission between the Market and said point. Said cost is valued as the marginal cost of grid losses.

The same applies to the capacity price. Once the capacity price is defined in the market node, the price at each node is determined altering said price by a factor that represents the quality of its link with the Market (measured as the price surcharges that the disconnection of transmission restrictions thereof generates in the Market).

The energy cost of a generator in the Market is given by its operating marginal cost plus the cost of transmission from its grid connection node up to the Market. Therefore, the farther a node is from the load centre, the dearer will be the energy exported from a remote node.

Perceived from the Market side, the longer the distance the lower will be the price which one is willing to pay in order to bring energy from another area, since the transmission cost will be added to the price. Thus, the value of energy coming from an exporting area decreases gradually to the extent that it is located far from the Market and/or is poorlyconnected to the Market.

In turn, the energy and capacity price for demand increases to the extent that it is located far from the Market (importing areas).

Consequently, the adopted pricing system takes into account the physical layout of the Argentina Grid System as well as the importance and quality of transmission links.

1.2- Node Factor and Adaptation Factor 1.2.1- Node Factor

The cost of energy Transmission between the Market and a node is valued as the

marginal cost of grid losses. This is expressed in the WEM remuneration system through the Node Factor.

The so-called Node Factor (NF) of a system node is the ratio of the marginal cost

associated with meeting a unit load variation in said bus from the System Load Centre to the marginal cost of supplying the same variation at the Load Centre. The Node Factor is a measure of the marginal cost of losses related to the transmission link between the node and the load centre, and the flow between them.

A Node Factor shall be associated to each bus for each representative load state.


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For each Market Price, there is a node price at each transmission grid node passing on Market Price up to the node, multiplied by the Node Factor.

The Node Factor of node I is determined as follows:

FNi = 1 + (∂ Perd / ∂ Pdi)

where:

∂ Perd / ∂ Pdi : the derivative of grid losses to demand capacity of node i.

This is calculated based on a model of the transmission grid through a load flow, and a unit demand variation (∆Pdi) is simulated at each node, thus obtaining the pertinent variation of system losses (∆Perd), taking the Market node as floating bus.

1.2.2- Adaptation Factor

The quality and reliability of a link between a system node and the Load Centre is measured by excess costs and energy not supplied caused in the Market due to transmission restrictions. These excess costs are represented by an Adaptation Factor (FA). For each representative state, each grid bus shall be associated to an Adaptation Factor representing the excess costs related to the existence of a transmission system subject to contingencies between the node and the Market.

Adaptation Factor FAi of a "i" node is related to the excess costs occurred, in the receiving nodes, for consumer agents when the High Voltage Transmission interconnections suffer forced outages. This factor shall represent the capacity price at Node “i” to the Market price ratio when the node is linked to the Market without any restrictions.

The Adaptation Factor of Node “i” (FAi) is calculated with the ratio of excess costs produced by the transmission restrictions in node “i” to the value of Capacity Made Available to the Market by the node average capacity for the hours on which capacity is remuneratedremunerated.

∑ SOBRECOSTil

FAi = 1 + ------------------------------------- POTMED * $PPAD * NHRP

1.2.3- Local Prices

So far we have referred to the prices that are defined when dispatch can be made under optimum conditions, not hindered by any kind of restraints. When the Transmission System generates a restraint which does not allow optimum dispatch, an active limitation is deemed to exist. In this case, the group of nodes affected by the restraint and which


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represent a market in itself with its corresponding Local Price (LP) is defined as an Area Dissociated from the Market.

Said restraint is deemed to prevent linking the entire area’s generation and demand with the Market. Such dissociation is complete when the area becomes disconnected, and it is partial when there is a reduction in the transmission capacity. In both cases, the area will have its own price, the so-called Local Price (LP). The local price of an exporting area will be lower than the Market Price, while the local price of an importing area will be higher.

Therefore, for each Market Price arising from dispatch in the market, there is a price in each node (PN) of the Transmission Grid, which will be defined as:

* The Market Price passed on up to the node, multiplied by its Node Factor, if the area where the node is located is linked to the Market without any restraints affecting optimum dispatch;

* The Local Price resulting in the area, passed on up to the node, where the node is located within an Area Dissociated from the Market, multiplied by its Node Factor.

1.3- Prices Charged by Suppliers

Generators are remunerated to the extent that they produce energy according to

the optimum dispatch carried out by CAMMESA, and offer capacity made available which is accepted by CAMMESA.

1.3.1- Remuneration for Energy

Energy sold to the WHOLESALE ELECTRICITY MARKET (WEM) is remunerated on the basis of the hourly prices arising in actual operation, except as regards those machines that are operating on forced generation instead of on optimum dispatch, which only receive their operating costs.

At each hour "h", the price of energy (PEN) in a node “n” depends on whether said node is or is not located within a dissociated area.

? If it refers to an area linked to the Market, the node price of energy is calculated at the Market Price (MP) passed on up to the node through the node factor (NF).

PENhn = MPh x NFhn

? If energy is dispatched in a Dissociated area “a”, the node price is calculated at the Local Price (LP) of the area, passed on up to the node through the corresponding node factor.

PENhn = LPha x NFhn

Each hour of energy sold by a machine to the WHOLESALE ELECTRICITY MARKET (WEM) is remunerated at the energy price at such node, except in the following cases:


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? Any machine on forced generation upon a Distributor’s request: The generation thereof is not the result of dispatch but of covering non-dispatched demand. Such generation is remunerated at the operating cost.

? Any machine on forced generation on account of Transmission requirement: Such generation is remunerated at the operating cost.

? The energy of a leading-edge turbo-steam machine (TVP) during non-peak hours on working days when it may be required to operate on forced generation at the rated minimum capacity, is remunerated at the Price of Energy Generated by Machines Operating on Forced Generation upon Peak Requirement ($FORPI), except where said price is higher that its operating cost, in which case it is remunerated at its operating cost.

? The energy of a thermal machine on forced generation during the hours in which it is forced to operate at the minimum rated capacity, is remunerated at its operating cost;

The energy price takes into account the reserve adopted for regulation and, therefore, the total hourly remuneration for energy to Generators already includes an additional remuneration due to the revolving reserve with which the WHOLESALE ELECTRICITY MARKET (WEM) operates.

Forced generation is not taken into account to calculate prices and is remunerated only at operating cost.

1.3.2- Remuneration for Capacity Made Available

At each hour, Capacity Made Available (PPAD) of a machine is understood to mean the maximum capacity that said machine can deliver, during that hour, to the WHOLESALE ELECTRICITY MARKET (WEM). Said value is given by the maximum power generable restricted according to the maximum transmissible capacity.

In the WHOLESALE ELECTRICITY MARKET (WEM), capacity made available will be paid to those machines that are generating, plus to those available machines that are not generating but were taken into account in pre-dispatch or which are considered as operating reserve. This remuneration is paid during certain hours of the week defined by the Energy Secretariat.

The Price for Capacity in the Market ($PPAD) is calculated as the sum of two values:

? A Base Price ($BASE) defined in 5 US$/ MW per hour during which capacity is paid (US$ / hrp).

? A Reliability Price ($CONF), with a minimum value of 5 US$ / MW per hour during which capacity is paid (US$ / hrp), which is determined by the ENERGY SECRETARIAT, MINISTRY OF ECONOMY, PUBLIC WORKS AND SERVICES.

$PPAD (US$/MW hfv) = $BASE + $CONF

Since May 1st, 1994, the Reliability Price is established in 5 US$ / MW per hour, then, the Price for Capacity in the Market is 10 US$ / MW per hour. Each node of the


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High Voltage Transmission System is assigned a Top Price for Capacity in the Node, transferring the Price for Capacity in the Market to the node, multiplying it by said node’s Adaptation Factor.

Generated capacity is remunerated at the Price for Capacity in the Market ($PPAD) passed on to the node through the Adaptation Factor (FA) during the relevant hours. Each machine that is generating during any given hour, including forced machines, is remunerated for the capacity delivered to the Spot Market, calculated as the net operated capacity less contracted capacity.

Each thermal machine not dispatched in spite of having been considered in service during pre-dispatch, is remunerated for the capacity made available provided that the machine is available around the clock and starts upon requirement.

The agreed cold reserve, i.e., leading-edge machines accepted in the cold reserve bid plus any machines added during re-dispatch, at the price arising from the cold reserve bid ($PRES), i.e., the (MW/PPAD) price of the most expensive machine in the merit list among those accepted as daily cold reserve during pre-dispatch plus any machines that may have been added during re-dispatch, passed on to the node through the adaptation factor. The cold reserve machines are paid for their net capacity offered in the cold reserve bid.

Net capacity is calculated discounting auxiliary services. To calculate the net capacity operated and net capacity made available any transmission and/or distribution restraints that may restrict their maximum generable capacity are taken into account.

Any failure of a machine to come into reserve negatively affects its future possibilities, relegating it to the end of the merit list, if offered as reserve once again. If any such machine should fail to comply with its reserve commitment three times in the course of two months, a stricter penalty will be applied to it: said machine shall not be allowed to participate in a cold reserve bid during the next six months

1.4- Prices Paid by Demand

In the WEM there are three types of user demand according to the price they pay for energy.

- Large Users and Self-Generators who pay the hourly energy price in their node, i.e., the MP market price times its Node Factor

- Generators for their purchases to meet contracts, who pay the hourly energy price, i.e., the MP market price

- Distributors, who pay a stabilised price per quarter of the prices foreseen for the Spot Market, the so-called Seasonal Price.

Each Distributor, Large User and Self-Generator of the WHOLESALE ELECTRICITY MARKET (WEM) will pay for its purchase of demand capacity, its purchase of reserve and its purchase of capacity-related services at a fixed price for each Quarterly Period.

1.4.1- Seasonal Prices to Distributors


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Seasonal Prices are set periodically according to the binomial rate calculated on the basis of the WEM operation as forecast by CAMMESA at the energy price that takes into account the probable marginal cost, and a price for capacity requirements to cover demand, reserve level and other services related to the WEM’s operating quality. The Energy Prices defined for three different time slots: the valley hour period, the peak hour period and the remaining hour period.

Two six-month periods (Seasonal Periods) are considered in each year, each divided into two three-month sub-periods (Quarterly Periods).

* The Winter Seasonal Period: comprises the days from May 1st through October 31st of each year, both included, and is divided into the first Winter Quarter (May to July) and the Second Winter Quarter (August of each year to October of each year).

* The Summer Seasonal Period comprises the days from November 1st through April 30th, both included, and is divided into the First Summer Quarter (November to January) and the Second Summer Quarter (February to April).

To calculate seasonal prices, CAMMESA programs the semester using medium term operation and simulation models, which determine the optimum hydrothermal dispatch in each week of the period.

Also, CAMMESA agrees with Distributors the desired service quality and, accordingly, the relevant reserve requirements and their cost.

As a result of the above programming, an Energy Price is determined for each Distributor in each rate period (peak, valley and remaining hours), calculated as the weighted average in each week of the MP, plus any differences for energy valued at a different prices (LP, operating costs, etc.) altered by its node factors.

To calculate the node factors of each quarter, CAMMESA must establish foreseen typical states defined by characteristic configurations expected in the Transmission grid and load states during the valley, peak and remaining hours. For these typical states, CAMMESA has to simulate the foreseen dispatch and flows and calculate the Seasonal Node Factor for each WEM Entry / Exit Point in each time slot, according to the method mentioned above;

The monthly charge for capacity corresponding to each Distributor, Self-Generator and Large User of the WHOLESALE ELECTRICITY MARKET (WEM) shall be the sum of:

* The charge for dispatched capacity;

* The charge for capacity reserve;

* The charge for capacity-related services.

The charge for dispatched capacity is determined by multiplying the capacity purchase made in the WHOLESALE ELECTRICITY MARKET (WEM) during the month by the Base Price for Dispatched Capacity plus the Reliability Price corresponding to quarter “t”, passed on to its node through the Adaptation Factor.


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The charge for capacity reserve is calculated by adding the following values:

a) Integration of the remuneration for reserve capacity foreseen.

b) Integration of the remuneration for monthly base capacity.

c) Integration of the remuneration for cold reserve per hour during which capacity is paid times the net capacity made available to the non-generating machines and considered as reserve, by the price offered in the cold reserve bid ($MESFRIA).

d) A discount corresponding to the revolving reserve foreseen to regulate frequency, included in the Charge for Capacity-Related Services.

The charge for capacity-related services if set taking into account the remuneration in the month of revolving reserve capacity to regulate frequency, the balance of secondary regulation service and the resulting balance for the month in penalties for non-compliance with the load-shedding obligations after a cut-off requirement due to shortage and/or failure at the WEM.

2 - REMUNERATION FOR TRANSMISSION

2.1- Remuneration to Providers of the Transmission Technical Function

As seen above, the WEM Agents who use the transmission service are Generators, Distributors and Large Users. On the other hand, it is used also by those who provide the Transmission Technical Function, i.e. Carriers, and also Generators, Distributors and Large Users. Described below is the remuneration corresponding to each type of provider. 2.1.1- Remuneration to Carriers and for Additional Provision of the Transmission Technical Function to Generators and Distributors. Although there are slight differences, the remuneration to concessionaires of the High Voltage Transmission System (TRANSENER), for Regional Transmission System (DISTRO’s), and to the Additional Providers of the Transmission Technical Function to Generators and Distributors (PAFTT) is similar in essence. Concession contracts with carriers include an initial rate table which is valid for the term of 5 years and is adjusted in successive 5-year periods according to the following principles:

• Rates shall be proportionate to the company’s degree of efficiency

• They shall establish the top price set for each type of service, to be determined by ENRE according to the market indicators that may show changes in the values o f goods and /or services.


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• Said indicators, in turn, shall be adjusted up or down by a factor intended to encourage efficiency and investments.

• The adjustments shall show any change in costs beyond the concessionaire’s control.

• As from the second rate period, the concessionaire’s remuneration for connection and transmission capacity, may be reduced on a yearly basis by an efficiency encouragement factor, to be determined by ENRE for each rate period and which shall not exceed 1% per annum or more than a cumulative 5 % throughout the rest of the service period.

The revenues that make up such remuneration are: a) Connection revenues Is the remuneration for the service of connection of the user’s instalations to the transmission grid by means of especially dedicated control and transformation equipment. Cover the operating and maintenance costs of transformation and control equipment in stations. The connection revenue is calculated on the basis of an hourly-value charge, payable to the Carrier for all the hours in the period during which the equipment of said link was available. Said charge is not paid to the Carrier during the hours that said equipment was unavailable, and is liable to application of a penalty by ENRE. b) Transmission Capacity Revenues This revenue refers to transmission lines and related equipment, such as breakers, disconnectors, reactive power compensation equipment, etc. This revenue is determined on the basis of a charge defined by an hourly value per 100 km of line and is different for each voltage level. Said value is determined on the basis of the standard operating and maintenance costs of those facilities. Just like the connection charge, it is payable to the Carrier for all the hours in the period in which the like was available. Said charge is not paid to the Carrier during the hours that said equipment was unavailable, and is liable to application of a penalty by ENRE. The initial values of these charges were also defined by the Energy Secretariat in the Concession Agreements and are adjusted semi-annually by ENRE based on the US inflation rates. c) Electric Power Carried Revenue The electric power carried revenue is determined based on the difference between the value of the energy received in the receiving node and that of the energy supplied at the delivery node in each line, when the prices of both nodes differ by the marginal value of grid losses and the value of excess costs produced to consumers related to the


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receiving node, because of long and short periods of unavailability in the TRANSMISSION SYSTEM. The total remuneration for electric power carried is set for each 5-year rate period for Carriers and every 2 years for the Aditional Providers of the Transmission Technical Function (PAFTT), and is the rate arising from the average of annual revenues forecast on this account for said period. Such forecasts are calculated by Compañía Administradora del Mercado Mayorista Eléctrico S.A. (CAMMESA) and are submitted to ENRE for approval, enclosing the concessionaire’s opinion. The initial annual amounts were defined by the Energy Secretariat when the transmission systems were delivered under concessions, and are adjusted semi-annually by ENRE according to the US inflation rate, and in each rate period as mentioned in the foregoing paragraph. Every Month the carrier receives a value equal to the twelfth part of said remuneration. 2.1.2- Remuneration for Additional Provision of the Transmission Technical Function to

Large Users or Distributors This remuneration is set on the basis of the toll rates payable by Large Users and new Distributors. Since in this case the amounts and items the Provider receives are the same as those paid by Large Users, this remuneration will be described below together with the description of the charges paid by users.

2.2- Users’ Rate System

In the foregoing item we referred to the amounts that each Carrier or PAFTT is paid every month. Next is a description of the procedure implemented to collect said amounts from users the Transmission Technical Function. 2.2.1- Rate system for users of Carriers and Additional Providers of the Transmission

Technical Function to Generators and Distributors. Collection is carried out by collecting from each user the fixed and variable charges for transmission use. Figure 4 is a flow diagram schematically summarising said charges.

- Variable charges for electric power carried. - Connection fixed charges. - Supplementary fixed charges

The transmission grid users implicitly pay the electric power carried charges

(through the node and adaptation factors) and explicitly pay the other two charges.


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MARKETPRICE OFENERGY

NODE FACTOR

MARKETPRICE OFCAPACITY

ADAPTATIONFACTOR

NODE PRICEOF ENERGY

ENERGY

NODE PRICEOF CAPACITY

CAPACITY

ENERGYCHARGE

VARIABLECHARGES

TRANSMISSIONSERVICECHARGE

CAPACITYCHARGE

VALUE FIXED BYS.E. AFECTED BY

COMPLEMENTARY F.C.OR CANON IN THE

NEWS COMPLEMENTARYCHARGE

FIXEDCHARGES

CONECTION ANDTRANSFORMATION

CHARGES

TRANSMISSIONCAPACITYCHARGES

UNAVAILABILITYHOURS

(PENALTIES)

Figure 4

Collection of the High Voltage (TRANSENER) and Regional Transmission (DISTRO´s) Charges


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a) Variable Electric Power Carried Charges Each WEM member has one node assigned on the transmission grid (to which it is linked), characterised by two parameters called the Node Factor (NF) and the Adaptation Factor (FA). These factors are determined by studying the transmission grid and taking into account the grid losses (NF) and surcharges originating in contingencies occurred in the transmission grid (FA) . As mentioned earlier, this charge is implicitly paid by each WEM member through the node and adaptation factors. Once the energy and capacity prices are defined in the Market node (MP and $PPDA, respectively), a WEM Agent connected to the transmission grid in node k will have a price for: the energy, which is:

PEk = FNk * MP and capacity, equal to:

PPADk = FAk * $PPAD The Adaptation Factor takes into account possible failures in the transmission system that may preclude supplying total or partial demand at the exemplary node k and/or that may imply the need for redispatch, which affects the Market Prices. A node linked to the market by networks and/or equipment so that the existence of failures that may totally or partially prevent the energy supply according to forecasts without contingencies is statistically possible, shall have an FA higher than 1. The WEM Agents implicitly pay variable charges through the differences between the prices at which (the demand) pay or (the generators) collect for the energy and capacity at their node and the relevant Market node prices. b) Fixed Connection charges The WEM users pay a connection charge for the service of linking their facilities to the transmission grid through the especially dedicated control and transformation equipment. If the connection equipment is shared by several users, each such user proportionally pays the maximum capacity required at that connection. The charge is by the hour, and user pay for all the hours in the period during which the connection was available. c) Supplementary Fixed Charge


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Users shall pay a supplementary hourly charge for their marginal use of the transmission system (for ET lines and equipment not especially dedicated to their connection). The supplementary charge consists of two components. One is the remuneration for transmission capacity, that is paid to Carriers for the transmission lines operation and maintenance costs. The other refers to the remuneration for electric power carried, set by ENRE. The total supplementary charge to be collected consists of the remuneration for transmission capacity plus the difference between the remuneration set by ENRE and collection of the variable charges for electric power carried implicitly paid by the Agents. The latter difference represents the amount required to cover the uncollected portion of the payment set by ENRE for Carriers. Once the total supplementary charge to be collected has been defined, it has to be distributed among the users who share the use of transmission lines. The charge payable by each Agent is determined by CAMMESA, establishing the use the each user makes of each line by applying the so-called areas-of-influence-of-a-node method, which seeks to apportion payment of the supplementary charge of a transmission system line among the users thereof according to the marginal use they make of said line. Area of influence of a node is understood to mean the set of elements (lines) of the transmission system whose capacity flow is increase in the event of higher demand at the node in question or in generation. To this end, capacity flow charts are prepared representing all the operation state carried out during the year before each seasonal program made by CAMMESA. The purpose of applying this method is to find a factor of each user’s share in payment of the supplementary charge of each line for the entire next quarter. This factor will be the average of partial factor obtained in each of these representative estates to which the method has been applied, each square-weighted by the duration of said representative flow during the period under analysis, i.e., the hours of the year before the period under analysis represented by said flow. To obtain this, to each node in the system a demand increase unit is applied to check on which lines does the flow increase. Each line where flow increases after applying a demand increase to a node is within the area of influence of said node. The charge on each line is distributed among all the nodes that have said line in its area of influence, according to the increase that has produced the higher demand in each node. Once this has been applied to all nodes and all lines in the system, finally it is determined for each node which lines are within its area of influence, i.e., for which lines should a portion be paid and in what proportion. All of TRANSENER users pay directly according to this proportion.


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DISTRO users: Generators pay directly according to this proportion. Distributors and Large Users pay the portion corresponding to demand in the proportion of their demand capacity within the total DISTRO’s demand. PAFTT users: Generators pay directly according to this proportion. Distributors pay the same as in DISTRO’s. Large Users pay a toll rate. The monthly charge is determined proportionally to the hourly supplementary charge determined by CAMMESA for each link in each seasonal period, in the percentage of their share in the node and according to the time that each link is effectively available. By way of example we can say that supplementary charge share in the total transmission of SADI, including TRANSENER and the DISTRO’s, is approximately 61 % for Generators, 36 % for Distributors and the remaining 3 % is for Large Users. 2.2.2- Rate system for users of the Additional Provision of the Transmission Technical

Function to Large Users or new Distributors. In this case the Energy Secretariat issued Resolution SE 154/94, amended and extended by Resolution 406/96 (See Annex III), regulating the manner in which toll rate payments must be made. The basic guidelines are the following: A Large User required to pay toll to an Additional Provider of the Transmission Technical Function shall agree the toll cost with said Provider. If no agreement is reached, either party may resort to the Energy Secretariat for the Secretariat to determine the pertinent toll rate, based on the provisions of the above mentioned resolutions. Said rate is determined according to the capacity and energy prices in the Wholesale Electricity Market and certain multiplication factors, which vary in each province. Furthermore, the proportional portion corresponding to the National Energy Fund and the proportion of High Voltage Transmission and DISTRO’s paid by the Provider of the Transmission Technical Function is also included in the rate. The proportion is determined according to the maximum capacity required by the Large User with respect to the maximum capacity required by the Provider. It also includes a system to reduce the toll value as a result of failure to meet the quality requirements, since all toll services are associated with a certain service quality standard that must be met.


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All the above methodology does not include Large Users connected to Distributors who hold concessions granted by the National State (Edenor, Edesur and Edelap), because the toll rates are set in their concession contracts. Neither does it include any Distributors that may reach an agreement with respect to the toll payment terms. A Large User may pay the toll rate directly to the Provider, if so agreed upon; otherwise, CAMMESA may be designated to collect, i.e., to collect from the Large User and pay the relevant Provider.

2.3 - Transmission Accounts

As mentioned earlier with respect to the Energy and Capacity Funds and according to the provisions of section 11 of the Remuneration System for High Voltage Electric Power Transmission, Annex 16 to The Procedures, CAMMESA shall manage the TRANSMISSION DEVIATION ACCOUNT created by Resolutions issued by the ENERGY SECRETARIAT under the provisions of Section 36, Law No. 24,065, for the purpose of absorbing any differences that may arise monthly between the Concessionaire’s remuneration and the amounts payable to the USERS of the TRANSMISSION PUBLIC SERVICE pursuant the aforesaid regulations. CAMMESA is responsible for making the calculations required to determine the pertinent remuneration and charges. In turn, by order and for the account of agents, CAMMESA shall issue the invoices, collect, record the pertinent credits and manage the transmission deviation accounts. 2.3.1- Transmission Deviation Accounts

Both for High Voltage Transmission and Regional Transmission System, if the monthly amount invoiced by CAMMESA to the Users of the Transmission Public Service fell short of the revenues appropriately due to the concessionaire, CAMMESA shall debit said shortage from the Transmission Deviation Account respectively corresponding to High Voltage or Regional Transmission System. If the funds in said Account were insufficient, a credit in favor of the concessionaire shall be entered until funds are available. Said credits shall accrue interest on a monthly basis at the rate applied by Banco de la Nación Argentina to 30-day discount operations. On the other hand, if a deficit accumulated in this Account, every six months CAMMESA shall add to the calculation of seasonal prices to be charged to users of the transmission public service, the adjustments required to cancel the debts with the concessionaire. 2.3.1.1- High Voltage Carrier, Regional Transmission System (DISTRO’s) and Additional

Provision of the Transmission Technical Function (PAFTT) Accounts. According to regulations in force, any Agent who renders the service of an electric link with SADI or between Agents with facilities connected to SADI, is a Provider of the Transmission Technical Function (PFTT). This definition encompasses the High Voltage Carrier, the Regional Transmission System and the Additional Provider of the Transmission Technical Function (PAFTT), i.e., one who, while not having a transmission public service concession, make its facilities available for electric power transmission.


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Each PFTT shall have a specific Deviation Account. The revenues collected from PFTT Users as Total Variable Collection for Electric Power Carried, Connection Charge and Supplementary Charge are entered in the relevant Deviation Account specifically corresponding to that PFTT. In turn, disbursements originating in remuneration to the PFTT are debited from that Account, provided that funds are available therein. The revenues and disbursements corresponding to an PFTT Independent Carrier are credited to and debited from a dedicated subaccount under said Deviation Account. Any penalties or discounts to the PFTT arising from unavailability or reduced capacity of an equipment are credited to the Users of said equipment as discounts in their connection and supplementary charges, this being the sole remuneration they will receive for any such failures. The penalties or discounts arising from supervision of the Independent Carriers’ operation are credited to the Deviation Account of the respective PFTT. If the monthly revenues billed to users fell short of the disbursement appropriately credited to the PFTT and the funds in the Deviation Account were insufficient, a credit shall be recorded in favor of the PFTT until funds are available. Said credits shall accrue a monthly interest, in accordance with the provisions of the pertinent Concession Contract for HIGH VOLTAGE CARRIERS and DISTROs, and of Annex 28 of the Procedures for the PAFTT. The PFTT shall transfer the credits to the Independent Carriers, if they belong to a Subaccount with a deficit. The carrier’s credits shall be affected by the proportionality factor associated with collections to the WEM debtors. If the monthly amount billed were higher than the disbursement for which the PFTT is a credit, the surplus balance shall remain in the Deviation Account. In the event that deficit accumulates in an account, the OED will include it in calculation of the supplementary charges at the time of preparing the Seasonal Program, to settle de debts with the PFTT. 2.3.2- Transmission Capacity Restrictions Surplus Accounts

The funds originating in Variable Collection of Local Price of Energy shall accumulate in an Transmission Capacity Restrictions Surplus Account as a result of reduced performance of High Voltage Carriers and Regional Transmission System. Each Carrier shall have a Subaccount under the Transmission Capacity Restrictions Surplus Account. The Transmission Capacity Restrictions Surplus Account will be managed by OED, which every month will report the amounts accumulated in each Subaccount of the Transmission Capacity Restrictions Surplus Account. The balance of a Subaccount under the Transmission Capacity Restrictions Surplus Account of a High Voltage Carrier or DISTRO will be applied only to payment of the supplementary charge during the depreciation period of any enlargements carried out


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by public invitation to tender, which may produce a reduction in the transmission restrictions generated by the local prices in the Carrier’s area. Interest accrued on Surplus Subaccount balance will be credited to said Sub accounts. 2.3.2.1. High Voltage Surplus Accounts The term “High Voltage Transmission System Corridor” is understood to mean a number of electric power transmission lines that link electricity regions or geographical areas to each other. Within the WEM, the following lines are defined:

? ? Comahue - Buenos Aires Transmission Corridor. ? ? Centro - Litoral Transmission Corridor. ? ? Centro - NOA Transmission Corridor ? ? Centro - Cuyo Transmission Corridor. ? ? Rincón de Santa María - Litoral Transmission Corridor. ? ? Salto Grande - Buenos Aires Transmission Corridor. ? ?Litoral - Buenos Aires Transmission Corridor.

Each transmission Corridor in the High Voltage Transmission System will have a Subaccount under the Transmission Capacity Restrictions Surplus Account 2.3.2.2. Regional Transmission System Surplus Accounts The funds origination in Variable Collection for Local Price of Energy of line will accumulate in the Transmission Capacity Restrictions Surplus Account of the DISTRO to which the line belongs. 3 - DISTRIBUTION RATES After the enactment of the Electricity Regulatory Framework set forth in Law No. 24,065, a deep reform and reorganization of the Argentine electric power sector took place, based on the principles of setting rates supported by economic rationality, pursuing efficiency in the allotment of resources, introducing competition in those segments wherever it is possible and regulated rates in the segments that constitute a natural monopoly. The legal background of the power sector’s current arrangement is found in said Law No. 24,065, its predecessor, Law No. 15,336 and the regulations issued by the National Executive. As general policy, the following goals have been established: a) to protect the users’ rights adequately; b) to promote competitiveness in the electricity production and demand markets and to encourage investments to ensure long-term supply; c) to promote operation, reliability, equality, free access, non discrimination and generalized use of the electricity transmission and distributions services and facilities; d) to regulate the electricity transmission and distribution activities ensuring that the rates applied to the services are fair and reasonable; e) to promote the supply, transmission, distribution and efficient use of electric power establishing appropriate rate-setting methods; and f) to encourage


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private investments in productions, transmission and distribution ensuring the competitiveness of markets wherever possible.1 3.1- Economic Rationality Principle The general guiding principle is that of economic rationality and, under it, to pursue an efficient allotment of resources. The criteria used to determine prices in the National Integrated System (SIN) may be summarized as follows:2

1. The criterion of competition is established as a factor intended to foster the development of productive activity in the sector. There, the key element is break-down of the vertical organization of the previously existing State-owned power utilities and establishment of a generation market designated to be of general interest and defined as a productive activity based on private initiative with a plurality of operators competing with each other. 2. Promotion of economic efficiency based on the setting of rates according to the long-term marginal cost in order to define the “electric power” resource price, which tends to optimize the use of primary energy resources and of the capital resources invested in the sector. This led to the creation of the Wholesale Electricity Market (WEM), which approves the hourly energy prices based on the marginal cost of supply, using a merit list prepared upon the mean cost of short-term production of each generation unit, plus a “capacity” differential benefit intended to compensate capacity expansions. The latter compensation tends to denote the economic concept of capacity shortage, valued through the “cost of energy not supplied”. This way of defining electric power prices tends to be assimilated with the concept known in economic literature as the “long-term marginal cost” of electric power. 3. Since electric power demand represents an appreciation of the usefulness assigned to it by society, the market price arising from matching supply and demand constitutes a valid sign both of the shortage and usefulness of the resource. Therefore, this procedure for determining the market price implicitly supports the rational use of this resource. In this connection, upheld as a principle is pursuing as much transparency in prices as possible in the different electric power process stages, as well as allowing users greater direct access to the market. On the one hand, it is understood that the power supply rates of distributors to their end users denote either abundance or shortage arising from the wholesale market prices. On the other hand, a further purpose is to allow a direct link with the wholesale market in the case of users where, on account of the size of their demand, it may be economically and administratively rational for them to perform the metering and behavior duties inherent in that type of link. Lastly, still another purpose is to promote the emergence of an options market, with contracts freely agreed upon between supply and demand, even admitting users whose demand is 30 kW and more. 4. Pursuing as much fairness as possible among users, in an attempt that each user pay the cost of the resource he uses and the service he receives. In this connection, distributors are forbidden to use crossover subsidies between user categories, and to discriminate prices in setting rates.3


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5. Putting in place quality and safety protection measures consistent with the general interest and public service criterion. In this respect, penalties are established which may even come up to cancellation of a concession in the event of non compliance.4 6. Preventing possible monopolistic distortions or collusive practices that may hinder competition or imply abusing a predominant position in the market.5 7. Explicit subsidies are admitted intended to cover rate differences in cases of predetermined users, to be charged to specifically defined budget item. 8. A regulatory system is implemented for the activity, according to the most modern concepts and experiences in the subject matter, including the necessary supervision and control exercising sufficient jurisdiction and capacity to elucidate disputes and to take action in order to preserve the above governing principles.6 3.2- Economic Reasons for Rate Control The fundamental reason for rate regulation is of a technological type: scale economies are involved and the cost function is clearly sub-additive. This is the characteristic that defines a natural monopoly: The production costs of more than one firm are higher than those of a single firm working at the same production level. This means, in this specific case, that duplicating the distribution wire network is uneconomic. Production under monopolistic conditions is associated with economic inefficiency. The absence of competition allows firms to obtain higher profits than they would earn under competitive conditions. These higher benefits are obtained at the expense of higher prices and lower production than under competitive conditions and, therefore it is inefficient from the economic point of view. The purpose of the public service regulation is, then, to offset the above described deficiencies. The instruments used in the regulations, as described below, include setting a maximum rate, the obligation to supply all demand, quality control and determining an adequate profitability rate when calculation the maximum rates. From the viewpoint of needing to simulate a competitive market for electric power distribution, this set constitutes a unit. 3.3- The Rate System Complying with the above principles and rules, the National Executive granted concessions for rendering the electric power distribution public service in the Federal District and Greater Buenos Aires area according to the guidelines contained in the respective Concession Contracts. The provisions concerning rates contained in said contracts include provision of the public service to those users who lack the capacity for a direct link to the wholesale market. The guidelines followed in defining the Rate Tables are: - Maximum rates are established for each rate period. They consist of two terms: a) one represents the purchase cost in the WEM, and b) the other represent the distributor’s own distribution cost formed by the marginal or economic cost of grid made available to users plus grid operating and maintenance costs plus selling costs.7 - Rate periods are established (the first lasting 10 years, subsequent periods 5 years), during which rates will be adjusted only according to changes in power purchase and


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transmission costs in the WEM 8. Meanwhile, each concessionaire’s own distribution costs remain constant in real terms. 9 - Regulation of the profitability rate according to which maximum rates will be calculated for future rate periods, which shall be reasonably in relation to the firm’s degree of operating efficiency and effectiveness and shall be similar, as industry average, to that of other activities involving a similar or comparable risk at national or international level. 10 - Regulation of the quality related to the established rate, the public service concessionaires being in the obligation to supply all demand in their respective concession areas, and establishment of a quality control and penalty system. 11 - Crossover subsidies between users or user categories are forbidden. Users shall pay only the costs of the electric power process stages in which they are involved, procuring that each user pay only the cost attributable to his type of consumption. 12 In this way, every attempt is made for companies to optimize management of their businesses during each rate period by minimizing their costs. In this respect, it is important to point out that distributors are faced to a situation similar to one of perfect competition: the price is a value exogenous to the firm. Consequently, the rate system tries to preserve, vis-à-vis the authorized monopolistic activity, market conditions as closely similar to those of competition among a plurality of suppliers. Also, the purpose of these provisions is to encourage the firms, during the rte periods, to try to achieve maximum efficiency by rationalizing costs. A part of the benefits spawning from higher efficiency achieved within a rate period shall then be passed on to the users in the next rate period, when the profitability rate is set and the new costs inherent in distribution for calculation of the new rates are projected. 13 Since the vertical breakdown of the electric power system was a at the core of the sector’s restructuring strategy adopted by the State, the distributor companies have no control over the wholesale price of power. Accordingly, the purchase price of power in block in the wholesale market is passed on to the users through the Rate Table values (the so-called “passthrough” condition, in economic literature). Two purposes are thus pursued: a) that users receive the economic signs of prices in the wholesale market; and b) that distributors do not undertake extra costs for wholesale price variations. Accordingly, the distribution service concessionaires are also allowed to pass on to the rates the price of the supply contracts executed by the State before privatization, while the new contracts concluded by the distributors will only acknowledge the wholesale market price. In turn, ensured supply conditions the users’ right to obtain electric power at a minimum cost. In this respect the legislation recognizes a long period for investments in the sector to ripen, as well as the right of future generations to be supplied with electricity. Consequently, the companies should get a return on their capital investments such that it will guarantee maintenance of the infrastructure required to provide the service. Here we should point out that the pursuit of economic rationality does not restrict the State’s capacity to subsidize certain groups, but only establishes the fact that any such subsidy should be explicit. AT present, there are subsidies granted on the basis of social reasons (retirees and charities) and economic reasons (power-intensive industries). In both cases, the cost of said subsidies are covered by respective budget items charged to the Government area responsible for the subsidized sector. The law also provides for a


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Subsidiary Fund for Setoff of Regional Rates to End Users, managed by the Federal Electric Power Council (formed by the provinces). Furthermore, a special program has been put in place funded by the State intended to normalize illegal consumption in poor neighborhoods and shanty towns. 14 We should also describe the mechanism adopted to regulate profitability. A company’s the profit rate can be regulated directly, by applying to it a profitability ceiling fro a given period, or, alternatively, the price that the firm charges can be restricted, which, given a certain cost structure, determines the profitability rate obtained. The type of regulation adopted for power distribution concessions is one of the many possible in situations of a natural monopoly. The most traditional form of regulation in these cases is direct regulation of the profitability rate, used mainly in the United States (RoR - rate of return). This form fixes a maximum rate of return for the firm and the main problem it presents is that concessionaires are not encouraged to operate efficiently. Considering that specific profits are guaranteed, a tendency arises towards over-investment and higher costs. This leads to situation where investment is far from optimal, to the detriment of users. 15 Seeking to avoid the problems associated with this type of regulation, during the privatization process developed in Britain in the 1980’s a price control mechanism in real terms was proposed that included a term which allowed passing on to users part of the productivity increases achieved by the company (“price-cap” regulation). In the beginning this method was proposed for use in the privatization of British telecommunications.16 Regulation by price controls or “price-cap” (a term that should be translated as “maximum efficiency price”) partially remedies the problems found with profit regulation 17 by introducing better incentives to improve efficiency. Thus, the biggest advantage of regulation by price control is related to promoting efficiency. When a rate is set for a given period (rate period), any productivity improvement achieved by the company initially results in higher profits. Subsequently, such efficiency improvement must be passed on to the users through the future rates, which constitutes an mechanism of incentives and transfer of revenues that induces an overall, uninterrupted improvement of the public service. The general form of this method is given by the expression IPC - X+Y, where IPC is a price index denoting the variation of the concessionaire’s efficient costs and X is a reduction factor intended to pass on part of the productivity improvements to consumers. The term Y acknowledges the possibility of price increases in real terms which could be associated with allowing for higher costs to the company generated in areas beyond its control (such as environmental legislation or higher quality levels) and/or with encouraging a given type of investments. Variations of this formula have been used in the privatization of British power, gas, telecommunications and water. In Argentina, this was the method adopted for power and natural gas transmi8ssion and distribution. 3.4- Method Employed to Calculate Distribution Rates


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The costs inherent in distribution of the power distribution public service concessionaires in the metropolitan area were calculated as established in paragraphs a) and b), Section 40, of Regulatory Decree 1398/92. To that end, the average incremental cost of grids method was used, calculated on the basis of an expansion plan for minimum cost investments, required to meet the expected growth of demand in a ten-year period. 18 The grid development costs were taken into account, determined as the anticipation cost of average incremental investment in each stage of the distribution process. The grid cost calculation procedure consisted of the following steps: a) Projection of capacity demand in each stage, b) Preparation of a grid expansion plan at minimum cost with optimum service quality, c) Calculation of the average incremental cost (CIP), and d) Determination of the CIP - anticipation cost. Calculation of the operation and maintenance expenses based on an optimum service quality. Anticipation costs are the sum of the annualized average incremental cost (discounted at an annual interest rate) and the annual operation and maintenance expenses thereof. First the average incremental costs of each stage of the power process were calculated, establishing a relationship between the investments associated with expansion and a minimum grid cost and the increased capacity transmitted along the grids in each stage (also discounted at the same annual interest rate). The calculation base used was the investment plan prepared by the former Segba S.A. for grid expansion in the 1988 - 1998 period, corrected so as to eliminate investments not related to the adjusted grid expansion, and update as of December 1991. The method used was fundamentally based on a number of empirical works on rate setting at marginal costs. 19 The next step was to assign the costs of each type of grid to the various time periods based on the hours in which the load peaks appear. To this end, hourly load curves were prepared for the high, medium and low voltage lines. 20 Based on the distribution cost data of each stage in the electric power process and the hourly load state of grids, the cumulative cost was determined for each supply level and in each time period. The next step was to assign the cost, through parameters set for the first 10-year rate period, to the following adopted rate categories:

• T1 Small demands - capacity demand of less than 10 kW (Categories: residential, general and public lighting).

• T2 Medium Demands - capacity demand of more than 10 kW and less than 50 kW-

• T3. Big demands - capacity of demand of 50 kW or more (Supplied at low voltage, medium voltage and high voltage).

The criterion adopted was to meter more detailed periods whenever consumption was higher. For small demands, a fixed monthly charge and a variable charge was established. Medium demands pay a monthly charge for contracted supply capacity and a variable charge, both for a single time slot. Big demands bear a charge of contracted supply capacity broken down according to peak and non-peak hours and an energy charge broken down by peal hours, remaining hours and valley hours

Distributors’ regulation method


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The model adopted in the country is to set maximum prices, or price cap, of the formula RPI - X + Y, where RPI, in the Argentine case, is a mix of United States wholesale and retail prices, X represents an efficiency factor that can be passed on to the rates and Y is the cost of power and capacity in the wholesale market, plus the cost of transmission up to the distributors node. Furthermore, distributors are subject to given quality goals and to regular rate reviews. In the case of the nationwide distributors - Edenor, Edesur and Edelap - the first rate period lasts 10 years, after which rates will be reviewed every 5 years. At the time of the review, the regulator determines the efficiency factor X (during the first period it is equal to zero) and, consequently, the reduction in real terms that will be applied to the rates. In this connection, once the value of X is known, the company has a great incentive to improve its productivity in order to achieve a profitability rate higher than that (implicitly) acknowledged in the rate applicable to end users. As regards the term Y of the equation, the purpose is to isolate the distribution business itself from the market purchase price, transferring this cost to users (pass-through). In other words, the companies’ activity is to supply electric power, buying in the market for the account and order of their clients. To that end, it is essential to establish a difference between the various purchasing methods there are, i.e., purchase made in the spot market and purchase made in the options market (contract).

3.5- Method Employed to Update Distribution Rates In applying the above described Rate System, even though the Rate Tables have been established to be effective during the first rate period that ends in 2002, the value of rates should be updated whenever capacity, energy and transmission prices vary in the WEM. 21 The WEM seasonal prices change on a quarterly basis with each seasonal programming or reprogramming in February, March, August and November. There is also the incidence of variations in the prices of transferred contracts, which supply somewhat less than half the demand and is adjusted annually. Own distribution costs are adjusted semiannually in line with the United States composite prices. The form adopted by the rate structure (i.e., one term that represents energy and capacity purchases and another term (additive), which represents the own distribution costs) in principle render the distribution companies indifferent to the purchase price in the WEM. However, in view of the existence of non technical losses, the economic results of distributors are inversely proportional to the WEM prices. This is so because the distributors are, due to their non technical losses, buyers of a part of their own power and, accordingly, a wholesale price increase results in a higher financial loss. Since they were transferred to the private sector, the rates of power distribution companies have been modified twenty-nine times as a result of seasonal programming and reprogramming by CAMMESA and of the price variations under transferred power supply contracts.


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The variables which have a quarterly incidence on calculation of the rate values, calculated by CAMMESA every quarter, are the following: Seasonal price of Base Dispatch Capacity and Reliability Seasonal price of Cahave pacity Reserve Seasonal price of Capacity-Related Services Seasons price of energy in peak, remaining and night valley hours Seasonal charge for additional energy Node and Adaptation Factors Fixed Transmission Charges and Expansion Fee authorized for the High Voltage

Transmission System and Trunk Distribution Transmission Systems. The above variables represent a purchase cost for distributors in the WEM seasonal prices market. These values depend on the supply and demand conditions in the National Interconnected System (SIN) as a whole. They indicate the abundance of shortage of water in hydroelectric power plants on the main Argentine basins: Comahue and Parana and Uruguay Rivers. They are also indicative of the natural gas and fuel oil prices, of the availability of thermal generation machines and transmission facilities. And, obviously, of the growth of power demand throughout the country. Until May 2000, the prices of supply contracts executed by the State with Central Puerto and Central Costanera for Edenor S.A. and Edesur S.A., before distribution was transferred to the private sector, also had an incidence on calculation of adjusted rates. There is a supply contract between Edelap S.A. and Central Térmica San Nicolás, under the same conditions, which expires in December 2000. These contracts are in effect up to the year 2000.


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Edenor’s, Edesur’s and Edelap’s Rate Structure

The rate to end users consists of two terms. One term is the purchase cost of power and capacity in the wholesale market, which is directly passed on to users (pass-through). The other terms represent the compensation to the company for the electric power distribution and sale activity (one cost or distribution added value - VAD), which contemplates the cost of investment required for grid expansion and replacement, operation and maintenance of equipment and facilities dedicated to user service (the distribution added value has been calculated based on the own distribution costs, defined as the average incremental cost of grids, adjusted to an expansion plan of minimum cost investments, based on demand growth assumptions), ensuring a reasonable rate or return to companies operating efficiently (sections 40 and 41 of Law 24,065). The VAD is the part of the rate that is adjusted through the term RPI - X. This own distribution cost will depend on the consumption mode and the supply voltage. Furthermore, the Law clearly establishes a ban on crossover subsidies between user categories as well as price discrimination by the distributor (sections 42 and 44). Conversely, the law prioritizes the use of direct mechanisms such as explicit subsidies, the counterpart whereof it the allotment of specific funds provided for in the national budget to subsidize certain groups such as retirees, non-profit welfare entities and/or power-intensive sectors. To that end, section 42, paragraph a) Decree 1398/92 provides the acknowledgement of rate reductions. As a result of surveys made concerning the power demand characteristics in the former Segba, the structure of the rate table for the Edenor, Edesur and Edelap distribution companies was defined based on the type of consumption and the voltage level of supply. For small demands, a monthly fixed charge and a variable charge were set. Medium demands pay a monthly charge for contracted supply capacity and a variable charge, both for a single time slot. Big demands have a charge for contracted supply capacity broken down by peak and non-peak hours and a charge for energy broken down by peak, remaining and valley hours.

4. RATE ASPECTS IN THE REGULATORY FRAMEWORK 4.1- Law No. 24,065

SECTION 40. - The services provided by carriers and distributors shall be offered at fair and reasonable rates, which shall abide by the following principles: a) They shall give the carriers and distributors operating economically and prudently, the opportunity to earn sufficient revenues to meet the reasonable operating costs applicable to the service, taxes, depreciation and a rate of returned determined pursuant to the provisions of section 41 hereof; b) They shall take into account the reasonable differences between cost of different types of services considering the provision method, geographical location and any other characteristic that the Commission may deem relevant; c) In the case of distributor rates, the electricity selling price to users shall include a term representing the electricity purchase cost in the WEM; d) Subject to compliance with the requirements set forth in the foregoing


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paragraphs, they shall ensure the minimum reasonable cost for users consistent with assured supply.

4.1.1- Decree No. 1398/92 - Regulation of Law No. 24.065

SECTION 40. - Paragraph a) The own distribution cost for each voltage level that will make up the concession rate shall consist of. 1.- the marginal or economic cost of grids made available to the user, affected by coefficients representing the grid losses associated with the different voltage levels; 2.- the operation and maintenance costs, i.e., the expenses inherent in operation and maintenance of grids made available to users; and 3.- the selling expense, including metering and administrative expenses related to serving users. Paragraph b) Distribution costs shall be assigned to the different rate categories taking into account:

1.- the voltage at which power is supplied; and 2.- the type of consumption of each kind of user, taking into account its share in the load peaks of distribution grids.

Paragraph c) The own distribution cost shall be added to the block purchase price in the WHOLESALE ELECTRICITY MARKET, taking as reference the “Spot Market” price. Said purchase price shall be multiplied by a factor representing the grid losses related to its distribution system, according to the supply voltage level. In the event that the distributor purchases all or part of the electric power in block, under freely agreed upon contracts, the price to be passed on to the final users’ rate shall be that corresponding to the “Spot Market”. The prices of electric power block purchase contracts transferred to the awardees of the invitation to tender to be carried out in order to privatize the distribution activity performed by SERVICIOS ELÉCTRICOS DEL GRAN BUENOS AIRES SOCIEDAD ANÓNIMA, shall be passed on in full to the end users’ rate. If amendments are agreed under said contracts after said prices have been so passed on, for the purposes governed by this paragraph the shall be assimilated to freely agreed upon contracts. Each distributor shall pass on to the end users’ rate the Spot Market price (whether the purchase is made in the Spot Market or under freely agreed upon contracts), and/or price of contracts transferred in the privatization process, referred to in the


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foregoing paragraphs, weighting the proportion of the total purchase represented by each. Paragraph d) Not regulated

4.2- Law No. 24,065

SECTION 41. - The rates applied to carriers and distributors shall allow for a reasonable rate of return to the companies operating efficiently. Furthermore, the rate shall be: a) consistent with the degree of the company’s operating efficiency and effectiveness; b) similar, as industrial average, to that of other activities involving a similar or comparable risk at the national and international level.

4.2.1- Decree No. 1398/92 - Regulation of Law No. 24,065

SECTION 41. - The profitability rate is considered to be the adjustment rate determined by the NATIONAL REGULATORY COMMISSION for calculation of the own distribution costs. For that purpose, the Commission shall observe the principles defined in Section 41 of Law No. 24,065.

4.3- Law No. 24,065

SECTION 42. - Concession contracts with carriers and distributors shall include an initial rate table that shall be in effect for five (5) years and shall abide by the following principles: a) It shall establish the initial rates corresponding to each type of service offered; such bases shall be determined according to the provisions set forth in Sections 40 and 41 hereof; b) subsequent rates shall establish the maximum price that may be set for each kind of service; c) the maximum price shall be determined by the Commission according to the market indicators denoting changes in the value of goods and/or services. Said indicators, in turn, shall be adjusted upward or downward by a factor intended to encourage efficiency and, at the same time, investments in construction, operation and maintenance of facilities; d) rates shall be subject to adjustments that may allow for any change in the concessionaire’s costs beyond the concessionaire’s control; e) the costs attributable to the service rendered to a user of category of users in no case can be recovered through rates charged to other users.


SECTION 42. - The Rate System and the Rate Table that may be established in the electric power distribution and sale concession contracts, executed as a result of privatization of said activity according to the terms of Section 95 of Law No. 24,065, may be applicable for an initial period of ten (10) years, for the purpose of creating an adequate frame of reference for providing the public service. Paragraph a) Only the rate reductions in favor of retiree users, whose income does not exceed the amount determined to that end by the NATIONAL ELECTRICITY REGULATORY COMMISSION, of duly registered non-profit welfare entities and/or of power-intensive industrial sectors may remain in effect, provided that a specific budget item is allotted to compensate the concessionaire for the difference in


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revenues represented by such subsidy. In those cases, the aforesaid Commission shall proceed to obtain validation of the relevant budget items from the government area in charge of protecting the subsidized social sector and shall supervise the correct application of the differential rate system by the distributor. Paragraph b) Not regulated Paragraph c) The NATIONAL REGULATORY COMMISSION shall consider, in principle, the following factors intended to stimulate efficiency and investments in construction and maintenance of facilities: 1.- Setting the rate tables taking into account normal grid loss levels; and 2.- Application of discounts on the bills to end users in the event that the distributor fails to comply with the service quality standards established in the concession contract. Paragraph d) The rate adjustments referred to in paragraph d), Section 42, of Law No. 24,065, shall allow for variations in the price of block power purchases, according to the concept defined in the regulation of paragraph c), Section 40, of said law, and shall maintain constant the own distribution costs determined as provided for in paragraphs a) and b) of the regulation of the aforesaid section Paragraph e) Not regulated

4.4- Law No. 24,065

SECTION 43. - Upon expiration of the initial five (5) - year period, the Commission shall fix an again fix the rates for successive five (5) - year periods. Calculation of the new rates shall be made according to the provisions of sections 40 and 41 and maximum prices shall be set according to the provisions of the previous section.


SECTION 43. - Upon expiration of the initial period referred to in the regulation of Section 42 of Law No. 24,065, shall again set the rates for successive FIVE (5) - year periods.

4.5- Law No. 24,065

SECTION 44. - No carrier or distributor shall be allowed to apply differences in their rates, charges, services or any other item other than those arising from different locations, type of services or any other equivalent distinction that may be reasonably approved by the Commission.


SECTION 44. - Not regulated.

4.6- Law No. 24,065


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SECTION 45.- During the last year indicated in section 43 hereof, and subject to the regulations issued by the Commission, carriers and distributors shall request to the Commission approval of the rate tables pursuant to the provisions of section 42, which they intend to apply, stating the method, rates and other charges corresponding to each type of service, as well as their users’ classifications and general service conditions. Once approved, said rate tables shall be widely disclosed in order to duly inform the users.


SECTION 45. - Together with its rate application the distributor shall enclose all the information on which the proposal is based, and, in turn, shall supply any other information that may be requested by the NATIONAL ELECTRICITY REGULATORY COMMISSION. To study the rate proposal submitted by the distributor, the Commission shall hire the services of an independent group of consultants reputedly experienced in the sector, which shall make an alternative proposal. Based on the latter and on the concessionaire’s proposal, the NATIONAL ELECTRICITY REGULATORY COMMISSION shall establish the rate table for the next FIVE (5) years.

4.7- Law No. 24,065

SECTION 46. - Carriers and distributors shall strictly apply the rates approved by the Commission. However, they are entitled to request the Commission such modifications as they may deem necessary, if their request is based on objective and justified circumstances. Once the modification request is received, the Commission shall immediately disclose it to the public during thirty (30) days and shall convene a public hearing to be held the first working day thereafter in order to determine if the requested change abides by the provisions of this law and favor the public interest.



4.8- Law No. 24,065

SECTION 47. - The Commission shall issue a decision within one hundred and twenty (120) calendar days as from the date of the modification request; if it fails to do so, the concessionaire shall be entitled to adjust its rates according to the requested modification as if they had been effectively approved; provided, however, that the concessionaire shall reimburse to the users any difference that may arise in their favor if the modifications were not eventually approved by the Commission or if only partially approved.



4.9- Law No. 24,065


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SECTION 48. - When as a consequence of proceedings initiated officially or upon a report by private parties, the Commission considers that there are reasonable motives to hold that the carrier’s or distributor’s rate is unfair, unreasonable, unduly discriminatory or preferential, the Commission shall so notify that carrier or distributor, shall disclose it publicly, and shall convene a public hearing not less than thirty (30) days in advance. After the hearing is held, the Commission shall issue a resolution within the period set forth in the foregoing section.


SECTION 48.- If the NATIONAL ELECTRICITY REGULATORY COMMISSION qualifies as unfair and unreasonable the rate that the distributor applies ex oficio as a consequence of the provisions of Section 47, Law No. 24,065, the distributor shall apply the previous rate values as from the time the Commission notifies such qualification until expiration of the period defined for decision in the above mentioned section.

4.10- Law No. 24,065

SECTION 49. - The transmission and distribution rates are subject to top limits that will decrease annually in real terms based on automatic adjustment formulas to be set and controlled by the Commission.




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References 1 Section 2, Law No. 24,065 2 Sections 1, 2 paragraphs b), d), e) and f); 4, 6, 35, 36, 93 and 94, Law No. 24,065, and

Regulatory Decree No. 1398/92, as well as the regulatory rules issued by the former Energy Secretariat of the Nation.

3 Section 42, paragraph e), Law No. 24,065. 4 Sections 2, paragraphs a) and c), 11, 12, 13, 14, 16, 17and 26, Law No. 24,065. 5 Section 19, Law No. 24,065. 6 Sections 54 through 69 and concomitant sections of Law No. 24.065. 7 Section 40 of Law No. 24,065 and Regulatory Decree No. 1398/92. 8 Section 42 of Law 24,065 and Regulatory Decree No. 1398/92. 9 They are adjusted semiannually according to the variation in a composite wholesale and retail

price index of the United States (Paragraph D, Sub-annex 2 - Procedure to determine the Rate Table under Concession Contracts).

10 Section 41 of Law 24,065 and Regulatory Decree No. 1398/92. 11 Section 21 of Law 24,065 and Regulatory Decree No. 1398/92. 12 Section 42, paragraph e), Law No. 24.065. See below with reference to the “RPI - X+Y” method. 13 See paragraphs b) and c) of Section 41 of Law 24,065 and Regulatory Decree No. 1398/92. 14 See paragraph a) of Section 42 Regulatory Decree No. 1398/92; Decree 2443/92 and Decree

584/94. 15 In Argentina, there is a history of this type of regulation and of the problems it brings. The railway

concessions in the last century are a good example of this. 16 Regulation of British Telecommunications Profitability, Department of Trade and Industry (1983). 17 The main problem associated with any type of regulation is the asymmetry of information

between the company and the regulator. Discussions on this subject in terms of the principal - agent problem make up a substantial portion of economic literature on regulation.

18 Bastos C. and Abdala M: Transformación del sector eléctrico argentino. Editorial Antártica - Santiago de Chile (1993).

19 See, for instance, the Energy Secretariat’s report titled Privatización de SEGBA Distribución - Cálculo de las Tarifas. Another precedent in this respect is the report written by Electricité de France Rate Studies - Distrelec for the Electric Power Under secretariat - Tarifas - Estudio Económico a Nivel Nacional, April 1988.

20 For the high voltage lines, the readings taken were those of the 132 kV transformers in the HV/MV substations. For the medium voltage grid, the readings of feeders at MV of the same substations were surveyed. The low voltage grid was represented by typical curves of the different types of users (residential, general, public lighting and large users). See Energy Secretariat (1992) Privatización de SEGBA Distribución - Cálculo de las Tarifas, for detailed sampling parameters considered in each case.

21 Section 40, paragraph c) and Section 42, paragraph d) of Law No. 24.065 and Regulatory Decree No. 1398/92.


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THE RATE RESULTS OBTAINED UNDER THE POWER SECTOR’S REFORM PROCESS WILL BE REFERRED TO IN THE PRESENTATION, AFTER AN OUTLINE OF THE PRICING SYSTEM DESCRIBED HEREINABOVE. BEFORE THAT, THE CHARACTERISTICS OF THE ARGENTINE ELECTRIC POWER SYSTEM WILL BE SUMMARILY DESCRIBED.

Documents

NATIONAL CONFERENCE ON REGULATION IN ... - Argentina.gob.ar Setting Power Sector.pdf/$… · “TARIFF SETTING IN THE POWER SECTOR” TERI NEW DELHI, NOVEMBER 14, 2000 JUAN LEGISA