International Experience of Electricity Transmission Pricing

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Appendix 1

International Experience of Electricity Transmission Pricing

A Research Paper

  1. United Kingdom

The UK electricity market
The Pool is the trading mechanism through which the majority of electricity is sold and purchased in bulk in England and Wales. Licensed generators and suppliers are required to be pool members and, with certain exceptions, to sell all their output and purchase all their requirements through the pool. The National Grid Company (NGC) is not a pool member but provides services to the pool.
The services provided by NGC as part of its transmission business are:

  • transmission network use of system services.

  • transmission service activities, which are activities undertaken by NGC as part of the transmission business in the development and operation of the transmission system so as to minimise the costs of operating the system.

  • connection services.

Current transmission pricing regime
The national grid pricing system is based on various components: the transmission use of system (TUOS) tariff and charges based on transmission losses1, reactive power and constraints payments. TUOS charges are partially differentiated by location, but are based on a series of geographical zones, not on specific nodes.
In order to levy charges, NGC apportions assets to one of two charging categories: (i) transmission network use of system charges and (ii) connection charges.

Transmission network use of system charges

Transmission network use of system charges reflect the cost of installing, operating and maintaining the transmission system. The Investment Cost Related Pricing (ICRP) methodology introduced by the National Grid Company (NGC) in 1993/94 remains the basis of transmission network use of system charging in 1997/98.

  • Charges for supplier demand – suppliers pay demand charges based on the average of the demand supplied during the three settlement periods or half hours forming the system demand peak.

  • Charges for generation – charges for centrally despatched generation will initially be based on the generator’s forecast of the sum of the highest registered capacity. Generators subject to central dispatch pay charges on the basis of the total maximum registered capacity declared for settlement purposes.

The transmission network use of system tariff is calculated using a transport model. This ICRP transport model calculates the marginal costs of investment in the transmission system which would be required as a consequence of an increase in demand or generation at each connection point on the transmission system. The pattern of flows and likely congestion means that transmission charges for loads are higher in the SouthEast where transmission charges for generating are low.

Transmission service charges

NGC recovers revenue in relation to transmission service activity via transmission services use of system charges. These charges were first levied in 1997/98.
Customers pay transmission services use of system charges based on unadjusted gross demand less an adjustment defined under the terms of the Pooling and Settlement Agreement.

Connection charges

Connection charges are intended to enable NGC to recover, with a reasonable rate of return, the costs directly or indirectly incurred in providing, installing and maintaining the assets necessary for connection to the transmission system. A major issue therefore relates to identifying the boundary between assets which fall into the connection category and those which fall into the network use of system category.
The capital elements of connection costs are chargeable in the form of ongoing charges or as a capital sum, which may be paid by the customer as a capital contribution.
The capital base for a connection charge is the Gross Asset Value (GAV) and Net Asset Value (NAV) of each connection asset. The GAV comprises all of the costs of a connection asset including the cost of purchase, transport, installation and interest during construction and the costs of designing and engineering the asset. The NAV is the average (ie mid year) depreciated GAV and is used for charge calculation.
A capital contribution of the full GAV at the time of commissioning will reduce capital charges to zero.
Where more than one customer is connected at a connection site, certain connection assets will be subject to shared usage as they provide benefit to more than one customer. In this case, the costs of connection assets are shared.

  1. Norway

Industry Framework
Before 1992, Norway’s electricity industry was categorised by large vertically integrated companies. The Norwegian Energy Act of 1991 sets out the framework for the restructuring of the industry, which consisted of:

  • the separation of generation (Stafkraft) and transmission. Statnett was formed to take responsibility for transmission.

  • the formation of a market system operator (Statnett Market, a subsidiary of Statnett)

  • common carriage

  • ringfencing of distribution and generation

  • regulation of infrastructure owners by the Norwegian Water Resources and Energy Administration (NVE) in cooperation with the Norwegian Price and Cartel Board (Prisdirektoratet)

Transmission Pricing

The basic principle of tariff setting in Norway is marginal cost pricing under the constraint of a revenue or rate of return approach. An energy charge is set at short-run marginal cost, which recovers between 30 and 40% of total revenue required, while the remaining revenue is recovered via capacity and fixed charges. This balances the objectives of economic efficiency and revenue sufficiency for the network owner.

Revenue Determination

Transmission prices are set in Norway, firstly by setting overall revenue necessary to cover expenses for operation of the system and to provide an adequate return to shareholders.
Historically, the overall revenue for the business was set using a rate of return approach. More recently this approach has been seen as inconsistent with achieving a technical efficiency potential implied by cost modelling of the industry.
From 1 January 1997, the NVE introduced “incentive based regulation”. The approach determines a base level of allowable income by adding:

  • operating costs (average of utility's costs for the years 1994 and 1995);

  • network losses;

  • depreciation (straight line on historic cost); and

  • a return of 8.3%2 (on depreciated historic cost of assets).

Utilities may earn a higher return than 8.3% through reductions in operating costs. Utilities are to allowed to earn up to 15.3% return, returns above this must be given back to customers in the following year.

Transition of the base income level is adjusted from year to year by inflation, 50% of sales growth and an efficiency factor. DEA analysis is used to quantify the efficiency factor for each utility.

Allocation of Revenue to Prices

Once the overall revenue has been determined, this is translated to prices.
Until 1992, transmission rates were distance related charges. This was reviewed as part of the reform process as it was seen to be an unsatisfactory arrangement, for example it penalised long distance transmission without reflecting the actual costs involved.
In 1992 a new, three part tariff was introduced. The structure was seen to be more consistent with a competitive market. The structure incorporates a connection charge, an energy charge and a capacity fee:

  • the energy fee is time of day and seasonally dependent, and is set to recover the cost of electricity losses at spot prices.

  • the connection charge is charged per kW, based on non-interuptible peak power consumption.

  • a capacity fee is charged per kW, based on winter peak, and is revenue residual.

  • an additional capacity fee is charged per kW for transportation through any bottlenecks in the grid. The fee corresponds to the price difference in the spot market between the two sides of the bottleneck.

  1. United States

Structural Reform in the Electricity Industry

Reforms in the US electricity industry started from a different platform from that in other countries such as the UK. Firstly, reforms have been influenced by the experience gained in deregulation of the natural gas industry. Also, before reform, the US electricity industry was categorised by a plethora of vertically integrated utilities, most of which were privately owned. This has led to a different development of a competitive market for electricity.
Functional unbundling of wholesale services and open access to transportation systems were seen to be critical for effective competition3. This led to the introduction of the Energy Policy Act in 1992. The Act included provisions instructing the Federal Energy Regulatory Commission (FERC) to issue an order making transmission services available to any party.
On 24 April 1996, FERC issued Order 888 and 889. Order 888 requires utilities to unbundle transmission, distribution and wholesale generation services and establishes transmission service as a common carrier service. The order also requires jurisdictional utilities that own, control or operate transmission lines to file non-discriminatory open access tariffs to FERC for approval. Order 889, also known as the OASIS rule, requires utilities to share transmission capacity, pricing and other information necessary to obtaining an open access non-discriminatory transmission service. The order also notes that utilities may wish to go beyond functional separation and turn transmission to an independent systems operator (ISO). The ISO would co-ordinate the use of the transmission system and ensure the principle of non-discriminatory use of the transmission system is upheld.
In January 1998 four ISOs were in operation and conditionally approved by FERC. Three more were either close to approval or arrangements were expected to be filed within a few months. This means that the SouthEast is now the only large region in the US without an ISO and access arrangements.
Most of the ISO tariff arrangements use the individual tariffs of the utilities for a transitionary period, with the view to moving to a uniform approach over the next few years. However, one common feature of the ISO arrangements is congestion management with a set of associated charges.
The following table summarises the proposed pricing arrangements for the ISOs in the US :



Start date

Transmission rates

Congestion Management

California ISO

Initially zonal (based on customers’ service territory location), but within 2 years of operation a uniform arrangement is to be developed by the ISO

Zonal; ISO may schedule voluntary trades; users pay for inter zonal congestion, receive value for relief; adjustment bids for intra-zonal redispatch


ISO-New England

Postage-stamp access charge by region after transition period

ISO dispatches out-of-merit resources when capacity available, charges by hour and area

mid 97


Zonal (network service); ISO uses locational marginal cost (MC)

Locational MC



New York ISO

Zonal (based on customers’ service territory location)

Uses voluntary bids (increment or decrement); locational energy pricing reflects congestion


Texas ISO

Access charge plus impact charge per MW-mile

TOs must redispatch (with the help of ISO); all users share costs (for planned transactions), individual users otherwise


Midwest ISO

Zonal rates (based on customers’ service territory location) to be phased to a uniform rate

ISO provides information for transmission customers; all users share costs incurred to avoid curtailment of firm supply




Access charge by region, capacity reservation for price certainty

Take bids on power purchase/sale to create reverse flow; paid by those causing congestion


(1.7.00 for congestion)




Take bids on power purchase/sale to create reverse flow; paid by those causing congestion

by 2002

The following sections describe the transmission pricing arrangements in various areas in more detail.

An example: IndeGO’s pricing arrangements in the Northwest
IndeGO has proposed a transmission pricing scheme which includes the following elements:

  • an access charge;

  • a congestion charge; and

  • tradeable transmission capacity rights.

The access charge is to recover IndeGO’s cost of day to day system upkeep which would include operations and maintenance expenses, depreciation and return on the assets employed (the “rate base”). The access charge is to be a uniform charge by “price area”, the boundaries of which are set according to constraints on the system or by natural system separation. (Natural system separation is aligned to the ownership of the transmission systems.) It is to be billed annually and charged according to a customer’s load: on an average of the past 12 monthly co-incident peaks.

A commitment to the long-term payment of the access charge would provide users with a tradeable transmission capacity reservation. This would provide them with price certainty but not physical scheduling rights.
Expansion of the system is to be funded generally through the issue of new transmission capacity rights, except for very large, separate new loads. These will be charged a one-off charge set at the incremental cost of supplying the additional load.
The management of congestion is to be done using congestion charges and tradeable transmission capacity rights. Customers are to make day ahead bids for use of the transmission system. If total bids exceed capacity, IndeGO will seek bids from customers for paid usage reductions. IndeGO then charges all transmission customers at the rate paid for usage reduction. Customer payment can be made by turning in a transmission capacity reservation or by cash.

  1. New Zealand

The New Zealand electricity market
The New Zealand Electricity Market (NZEM) is a self-regulatory environment which provides the basis for the trading of electricity. NZEM is a set of rules by which participants in the market agree to conduct business. They provide for the buying and selling of electricity at the wholesale level via a pooled arrangement. Electricity is priced at market clearing levels. The market is voluntary and pool bypass is possible.

Broad approach to transmission pricing

New Zealand’s broad approach is that, for economic efficiency, fixed transmission costs ought to be recovered by fixed charges and variable costs by variable charges. This philosophy has been applied in New Zealand in both the transmission and distribution sectors.

Arguably, there are problems with this approach:

  • customers may argue that existing infrastructure represents sunk costs which they should not pay for.

  • locking customers into fixed charges that are difficult to avoid means that the assets may be maintained in their current configuration, even if better alternatives exist. While the approach described may maximise short-run efficiency, it may be sub-optimal from a dynamic efficiency standpoint.

TransPower (the New Zealand transmission network operator) has completed a substantial body of work on transmission pricing and has developed a theoretical basis for pricing access to and the use of transmission assets. Under the approach, the bulk of the network asset costs would be charged by way of long-term take-or-pay access contracts or “capacity rights”.4

There are a variety of mechanisms for sunk cost recovery via transmission pricing:

  • a mechanism where price is independent of current or future use. The initial allocation would presumably be based upon some historic usage concept. Payments might vary from year-to-year based upon variations in TransPower’s (the transmission authority’s) expenses but would not vary according to intensity of transmission system use.

  • payments for sunk costs would be made on a current usage basis and would increase or decrease proportionally as intensity of use changed.

  • payments based upon rolling averages of past usage.5

The principal issue is whether the charges by which sunk costs are recovered should be avoidable.

  • unavoidable – sunk cost recovery charges don’t change with usage - incentives to invest may not be efficient.

  • avoidable – (i) environmental concerns reflected in incentives in relation to demand reduction; and (ii) removes incentives to build extra capacity sooner than required.

The revised pricing principles agreed to the by New Zealand Government in August 1994 allowed for some avoidability in sunk costs where customers permanently reduce their requirements for transmission capacity because:

  • the ODV methodology used to value TransPower’s assets requires TransPower to write down the value of assets where there is a permanent reduction in their utilisation;

  • given that TransPower is a natural monopoly, the potential to avoid transmission charges is one of the few mechanisms available to customers (and shareholders) to put pressure on TransPower’s prices and therefore its costs.

Current transmission charging regime

The transmission pricing system is based on the following charges:

Connection and network charges

In order to achieve better price stability, individual assets, for the purpose of calculating the network and connection charges, will be valued on the basis of their optimised replacement cost (ORC). This avoids the price step effect that occurs on the replacement of an asset at the end of its serviceable life.

  • Connection charges recover the costs associated with assets downstream of a transmission voltage bus in each substation which connects a customer. It is comprised of an asset based component (ABC) and a maintenance based component (MBC).

  • Network charges recover the costs associated with network assets (ie either transmission lines or substations). This charge is also comprised of an asset based component and a maintenance based component.

Capacity charges
The capacity charge is calculated by multiplying the capacity charge revenue by the capacity charge allocation for that point of connection. For the 1996/97 prices, the capacity charge allocation for a point of connection has been calculated as:
70% of the initial capacity charge share
plus 10% of the winter 1993 peak share

plus 10% of the winter 1994 peak share

plus 10% of the winter 1995 peak share

The initial capacity charge share was the allocation derived for the 1994/5 capacity charge.

Demand charges
There are two demand charge options:

  • Option A – Customers nominate their level of Demand Entitlement at each of their supply points. Demands in excess of Demand Entitlement are allowable but, if they occur at certain times, will be charged for in each half hour in which they occur at the Excess Demand Charge (EDC) rate, in $/kW per half hour rate. The EDC is a strong signal to purchase Demand Entitlement close the expected maximum winter demand.

  • Option B – Each customer’s initial Demand Entitlement for each supply point is set equal to that supply point’s maximum demand in the period 1 June 1995 to 30 August 1995. Excess demand is allowable, but if it occurs at a certain time, the Demand Entitlement will be incremented to the new maximum demand which will set a higher Demand Charge for the remainder of the year. The new Demand Entitlement level will be maintained until it is once again exceeded (when a new higher level will be set) or the contract terminates.

HVDC Charge allocation

The high voltage direct current (HVDC) assets are all associated with the inter-island transmission link. The HVDC cost is divided between charges to generators and charges to other grid users. 47% of the HVDC charge is payable by ECNZ and Contact Energy Ltd. The remaining 53% of the total HVDC cost is recovered through network, capacity and demand charges to other grid users. The island differential adjustment redistributes $7.9million in charges from the South Island to the North Island to offset the effect of the HVDC charges on South Island customers.6

  1. South America

5.1 Chile

Chile, which deregulated its electricity industry from 1980 to 1990, was the first nation in the world to develop a competitive electricity market through the application of marginal or incremental cost principles and a combination of a pool, retail wheeling and access. The process featured large scale privatisation, which was part of a broader rationalisation of the Chilean economy, and was seen as an opportunity to reduce government involvement in industrial activities.
Transmission Pricing
Initial restructuring of the industry put no restrictions on the electricity companies in terms of vertical and horizontal separation. This led to transmission lines being run by subsidiaries of the generation companies. It was established in law that all prices were to reflect efficient costs, and third parties were to be given use of transmission lines.
Transmission prices are not explicitly regulated, but most of the principles for the calculation of prices are set out in law. Total costs to be recovered by the transmission owner include the costs of O&M, administration, billing and a return (based on replacement cost). Prices are paid by generators and have two components: a basic toll or entry fee plus a wheeling charge.
The entry fee attempts to recover the cost impact of the generator in its defined “area of influence” in the grid. The fee is calculated as a fraction of the total transmission costs proportional to the power output capability of each generator. Calculation of the wheeling charge is specified in the electricity law and is charged for a generator’s transportation of electricity out of its “area of influence”.
The result is an aggregated nodal price at each substation, reflecting both costs of transmission and generation. The prices attempt to signal to prospective generators where in the system the value of incremental generating capacity is higher or lower due to the distribution of demand for electricity and location of alternative supplies of electricity.
The methodology for setting total costs and the entry fee have been subject to much criticism. There have been disagreements on the determination of the generators “areas of influence” and the load allocated to it, and the use of replacement costs. Most of the disagreements have been attributed to the cross ownership of transmission and generation companies7 which led to a forced separation of ownership between transmission and generation in 1993.

Distribution Pricing

In Chile, distribution companies are exclusive franchises and their prices are regulated.

The costs reflected in prices, including O&M, administration, billing, losses and a return of between 6% and 14% on replacement cost, are based on a hypothetical “model utility”. The benchmarked costs are revised every four years and account for size and load density. A profit earned above benchmarked performance is allowed to be retained by shareholders.
Tariffs reflect the sum of the nodal price and the “distribution value added”. The tariff is generally structured to have three components: a fixed charge, a demand charge and an energy charge, depending on the sophistication of metering. The energy charge is the energy node price plus the cost of energy losses through the distribution network, while the demand and fixed charges are levied to recover residual costs.
Experience with the arrangements suggests that an asymmetry of information between the distributors and regulators has limited its success, particularly in the area of determining an appropriate value of assets for pricing.

5.2 Argentina

Argentina began restructuring its electricity industry in 1992. Deregulation was based on the Chilean and UK experience, and was implemented with the aim of correcting severe operational and financial difficulties of the government owned utilities.
The reforms fundamentally restructured the electricity sector, with vertical and horizontal separation of the government owned utilities. The objective was to establish a system that would maximise opportunities for competition, and reduce the need for regulation. Regulation of transmission and distribution services was seen to be necessary, and in July of 1992, Ente Nacional Regulador de la Electricidad was established as the electricity regulator.
Transmission and regional distribution businesses are franchised to the private sector and prices are subject to price cap regulation.
The transmission price is made up of three components: an energy charge, a capacity/transportation charge and a connection charge.

  • The energy charge is paid to recover the variable cost of transmission (about 25% of total costs). It is based on costs at interconnection nodes and is specified in electricity law.

  • The connection charge is paid by all members of the wholesale electricity market, as a contribution toward maintenance of connection equipment.

  • The capacity charge is paid to recover the operations and maintenance of transmission lines.

“Electricity’s Big Bang - ISOs: A Grid by Grid Comparison”, Public Utilities Fortnightly, 1 January 1998, pp 44-45
Culy J.G., E.G. Read and B.D. Wright “The evolution of New Zealand’s electricity supply industry” in Chapter 8 of International Comparisons of Electricity Regulation edited by Richard J Gilbert and Edward P. Kahn, Cambridge University Press, 1996, p312.
Frame Rodney “Sunk Transmission Cost Recovery Issues

Paper commissioned by the National Economic Research Associates Inc (NERA).

HJALMARSSON, Lennart “From club-regulation to market competition in the Scandinavian electricity supply industry” in International Comparisons of Electricity Regulation edited by Richard J Gilbert and Edward P. Kahn, Cambridge University Press, 1996 pp126 - 177
HOGAN, William W “ A Wholesale Pool Spot Market Must be Administered by the Independent System Operator: Avoiding the Separation Fallacy”, The Electricity Journal, December 1995, p 26 – 37
Lalor R. Peter and Hernan Garcia, “Reshaping Power Markets: Lessons from South America”, The Electricity Journal, March 1996, p63-71
Newbery David M. and Richard Green “Regulation, public ownership and privatisation of the English electricity industry” in Chapter 2 of International Comparisons of Electricity Regulation edited by Richard J Gilbert and Edward P. Kahn, Cambridge University Press, 1996, p25.
Officials Committee on Energy Policy “Pricing Principles for Electricity Transmission”, December 1994 (Commercial-in-Confidence).
Sgroi Daniel “Transmission pricing and plant location” Energy Utilities, October 1995, p30.
TABORS, Richard D., Transmission System Management and Pricing: New Paradigms and International Experience, IEEE, 1993
The National Grid Company plc “Statement of Charges For Use of the Transmission System and for Connection to the Transmission System”, April 1997.
Thompson Bob “New Zealand goes to market”, Electricity Supply Magazine, p22.
Trans Power New Zealand Limited “Transmission Charges Application of the Price Methodology for the 1996/97 Contract Year”

1 Transmission losses are an area of concern. Around 2% of demand is always lost by heating the wire through which the electricity is transmitted (representing about a quarter of the costs of transmission). These losses are proportional to distance. The electricity Pool pricing system does not take any of this into account.

2 The market interest rate on a medium-term government bond plus 1% (for risk)

3 NSW Departmentt of Energy, The Changing Structure of the Electricity Industry, Chapter 7 (

“Electricity’s Big Bang - ISOs: A Grid by Grid Comparison”, Public Utilities Fortnightly, 1 January 1998, p 44

4 Culy J.G, “The evolution of New Zealand’s electricity supply industry” in International Comparisons of Electricity Regulation, p360

5 Frame, Rodney Sunk Transmission Cost Recovery Issues, p2

6 Trans Power New Zealand Limited Transmission Charges Application of the Price Methodology for the 1996/7 Contract Year

7 Lalor R. Peter and Hernan Garcia, “Reshaping Power Markets: Lessons from South America”, The Electricity Journal, March 1996, p71

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