Improved regulatory models for efficient investment and loss reduction in electricity networks

8/14/2019 Improved regulatory models for efficient investment and loss reduction in electricity networks

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Final Report.Analysis of Insufficient Regulatory Incentives for Investments

into Electric Networks. An Update.

submitted to: European Copper Institute (ECI),

Avenue de Tervueren 168, b-10; B-1150 Brussels; Belgium

submitted by: KEMA Consulting GmbH,

Kurt-Schumacher-Str. 8, 53113 Bonn, Germany

Dr. Konstantin Petrov / Rosaria Nunes

Experience you can trust

Bonn, January 2009


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This document has been prepared by KEMA on behalf of ECI and may not be published or made available to

third parties without the prior permission of KEMA.


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Table of Contents

European Copper Institute ProprietaryUpdate Study Insufficient Regulatory Incentives January 2009

i

1. ............................................................................................................................1Introduction

2. .............................................................................................3Overview of Regulatory Models

2.1 ..............................................................................3Rationale for Economic Regulation

2.2 ...........................................................................................5Current Regulatory Models

2.2.1 ................................................................................5Rate of Return Regulation

2.2.2 ................................................................................................. 6Cap Regulation

2.2.3 .......................................................................................12Yardstick Regulation

2.3 ........................................................................................................13Quality of Supply

3. ......................................................15Analysis of Regulatory Schemes in Selected Countries

3.1 ............................................................................................................... 15Great Britain

3.1.1 .................................................................................15Institutional Background

3.1.2 ..................................................................................15Electricity Transmission

3.1.3 ..................................................................................... 21Electricity Distribution

3.2 .....................................................................................................................29Germany



3.2.3 ..................................................................................... 34Electricity Distribution3.3 ................................................................................................................ 37Netherlands




3.4 .......................................................................................................................43Norway


3.4.2 ........................................................ 43Electricity Transmission and Distribution

3.5 ..........................................................................................................................46Spain

3.5.1 .................................................................................46Institutional Background3.5.2 ..................................................................................47Electricity Transmission


4. .....................................................................60Analysing Incentives for Efficient Investments

4.1 .........................................................................60Classification of Economic Efficiency

4.2 .......................................................................................61Choice of Regulatory Model

4.3 ................................................................................62Treatment of OPEX and CAPEX

4.3.1 ...........................66Cap Regulation - Building blocks versus TOTEX approach


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4.4 ...................................................................................................68Treatment of Losses

4.4.1 ..............................................................................................68Network Losses

4.4.2 ...............................................................................................69Valuing Losses

4.4.3 .......................................................... 71Incentive Schemes for Loss Reduction

5. ......................................................................................73Case Study on Distribution Losses

5.1 ............................................................................................74ERGEGs Position Paper

5.1.1 .........................................................................74Benefits of Losses Reduction

5.1.2 .........................................................................74Calculation of Network losses

5.1.3 .....................................................................75Procurement of Network Losses

5.1.4 ..................................................................75Regulatory Incentive Mechanisms

5.2 .................................................................................75Simplified Cost-Benefit Analysis

5.2.1 ........................................................................................................76Approach

5.2.2 ............................................................................................................80Results

5.3 .................................................................85Analysis of Regulatory Incentives in Spain

5.3.1 ..............................................85Distribution Loss-Reduction Incentive Scheme

5.3.2 ......................................................................................86Feasible Investments

5.3.3 .................................................................................86Benefit Retention Period5.3.4 ............................ 87Trade-off between Incremental CAPEX and Loss Savings

5.3.5 .....................................87Improvement of the Spanish Loss Incentive Scheme

5.3.6 ......................90Integration of Cost of Losses into the Revenue Requirements

6. .........................................................................................................................91Conclusions

7. ............................................................................................................94Selected References

APPENDIX 1 ................................................................98Germany Cap Setting Methodology

APPENDIX 2 ...................................100Germany - Quantity Adjustment Factor for Distribution

APPENDIX 3 ....................................................................102Case Studies on Network Losses


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Tables


iii

Table 1: Transformer Purchase Price and Estimated Losses.....................................................78

Table 2: Projected wholesale price (simple annual average) in Spain (from 2008 to 2020).......80


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Figures


iv

Figure 1: Cap regulation with decreasing price level ....................................................................8

Figure 2: Types of cap regulation ...............................................................................................10

Figure 3: Regulatory Account .....................................................................................................32

Figure 4: Economic regulation from 2007 Annual procedure...................................................45

Figure 5: Allowed revenues and tariff setting..............................................................................46

Figure 6: Benefits associated with operating expenditure savings .............................................63

Figure 7: Benefits associated with capital expenditure savings..................................................65

Figure 8: Results 400 kVA transformers .....................................................................................81

Figure 9: Results 630 kVA transformers .....................................................................................81

Figure 10: Results 400 kVA transformers (i=6%; I=+/-20%)....................................................82

Figure 11: Results 630 kVA transformers (i=6%; I=+/-20%)....................................................83

Figure 12: Results 400 kVA transformers (i=6%; P=+/-10%) ...................................................84

Figure 13: Results 630 kVA transformers (i=6%; P=+/-10%) ...................................................84

Figure 14: Illustration of Reduction of Allowed Inefficient Costs .................................................99


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1. Introduction

In 2002 KEMA Consulting prepared a report on Insufficient Regulatory Incentives for Efficient

Investments into Electric Networks for the European Copper Institute (ECI). In this report KEMA

Consulting studied the properties of the regulatory regimes in three countries (Britain, the Neth-

erlands and Spain) and their potential impacts for investing in efficient capital-intensive equip-

ment for electricity networks. The study identified several reasons why such equipment may not

be purchased by companies operating under cap regulation.

The ECI has asked KEMA Consulting to update the previous study, analysing incentives for effi-

cient investments taking into account the current regulatory models. In addition, KEMA should

extend the study by adding a new chapter. The new chapter deals with the regulatory treatmentof distribution network losses in the context of the new European Commission (EC) regulations.

The Strategic European Energy Review puts a clear focus on greenhouse gas emissions; there-

fore the European Commission has set a strategic objective to reduce CO2 emissions by (at

least) 20% by 2020. The efficient use of energy and reduction in primary energy consumption

would help to achieve the targets. The Energy Efficiency Action Plan has set an indicative goal

of reducing energy consumption by 20% by 2020. It suggests several initiatives to improve en-

ergy efficiency in the coming years. Network loss reduction in the power systems is one of these

initiatives. This issue was discussed in the recent consultation paper Treatment of Losses by

Network Operators published by the European Regulators Group for Electricity and Gas

(ERGEG)1. ERGEG is currently developing a set of recommendations for establishing effective

loss reduction incentives for the electricity network operators.

The structure of the remainder of this report is set out as follows:

Chapter 2: Overview of Regulatory Models

This chapter takes a closer look at the regulatory models in Europe and describes their main

characteristics. This chapter serves as an initial step in preparing the discussion on incentives

for efficient investments.

1This Position Paper may be found at www.energy-regulators.eu/portal/page/portal/EER_HOME


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Chapter 3: Analysis of Regulatory Schemes in Selected Countries

This chapter contains a detailed description of the regulatory regimes in five selected countries

namely Great Britain, Germany, the Netherlands, Norway and Spain, in order to demonstrate

how the regulatory models are implemented in practice.

Chapter 4: Analysing Incentives for Efficient Investments

Whereas the two previous chapters provide an examination of theoretical developments and

applications of regulatory models in practice, this chapter focuses on how regulation provides

incentives to encourage efficient investments and loss reduction programmes.

Chapter 5: Case Study on Distribution Losses

The chapter provides a summary of the ERGEGs report on the regulatory incentives for loss

reduction. In addition, we prepare examples for cost benefits analysis supporting the decision to

invest in an energy-efficient distribution transformer. A case study is carried out for Spain.

Chapter 6: Conclusions and Recommendations

This chapter summarises the project findings and provides recommendations for potential im-

provements.


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2. Overview of Regulatory Models

2.1 Rationale for Economic Regulation

In a narrower definition, regulation may be defined as any actions by government or specialised

authorities to control specific parameters of companies, such as price, revenue, cost and quality

(KEMA, 2002).

The traditional economic rationale for regulation concerns the maximisation of efficiency in mo-

nopolistic industries.

Economic theory advocates that firms have the strongest incentives to provide best service to

customers in terms of price and quality of service when they are in competition. Therefore,

power industry reforms have introduced competition wherever possible (e.g. power generation,

wholesale and retail markets). Competition, however, is not feasible in all segments of the

power sector; transmission and distribution networks (and their related functions such as system

control and balancing) remain natural monopolies.

Natural monopolies arise if duplication of an infrastructure or service provision is uneconomic,

i.e. the character of the technology and demand dictate that the service is cheaper if the de-mand is met by a single firm rather than by competing firms. The underlying source of this prob-

lem is subadditivity of costs. Assume that one firm produces a given level of output xand that

there are two other firms producingxandxsuch thatx+x=x. Then, subadditivity implies that

c(x)


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tions may also be able to reduce costs by having proportionately lower overheads or by being

able to employ more specialised and efficient personnel.

Scope economies can be found in the joint provision electricity and telecommunication services

using the same infrastructure components.

Sometimes it is argued that the presence of economies of scale is not sufficient by itself to elimi-

nate the possibility of some form of competition. This is because even in the presence of scale

economies, competition might be likely in a market if it were possible for an entrant to gain mar-

ket share by undercutting the incumbents prices, and then exit from the market when the in-

cumbent firm responded with a price cut of its own. In such circumstances, the simple threat of

competition would be enough to prevent the possibility of excess monopoly profits. If this proc-

ess is to work, however, the entrant must be capable of leaving the industry without incurring

excessive costs when the incumbent firm responds by cutting its prices. For this to be the case,the technology must be such that the entrant does not have to make irrecoverable investments

in order to enter the market, in other words there must be no sunk costs. Electricity distribution

networks need large and long-lived investments that cannot be recovered before an entrant

leaves the industry. Hence the role of potential competition in disciplining an incumbent firm with

a monopoly distribution network is very limited.

As a result the monopolistic areas of electricity businesses (i.e. transmission and distribution)

are controlled and monitored by regulatory authorities. One of the regulators tasks is to ensure

that the transmission and distribution companies do not exploit their market power by operating

inefficiently and charging high prices and/or inadequate quality of supply. In other words, a good

regulatory regime should provide companies with similar opportunities and incentives to those

they would face in a competitive market. However, in mimicking market forces, the regulators

should also balance this duty with the need to consider the interests of network owners, in order

to ensure that network businesses earn a reasonable rate of return on their (efficient incurred)

investment (Scarsi and Petrov, 2004).

A further economic rationale for regulation is to deal with the market failure in relation to exter-

nalities. Some transactions give rise to societal benefits or costs that are not internalised into

the markets pricing mechanism. They concern the third party effects of certain transactions thatthe principal parties are not economically motivated to consider as part of their pricing analysis.

For example, incentive regulation mechanisms can be designed to encourage utilities to main-

tain and improve energy efficiency and environmental protection practices.


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2.2 Current Regulatory Models

2.2.1 Rate of Return Regulation

Under rate of return pricing, the regulator sets prices for the utility in such a way that they cover

the utilitys costs of production and include a rate of return on capital that is sufficient to maintain

the investors willingness to replace or expand the companys assets. Hence it is referred to as

rate of return regulation. This regulation method is also known as "cost of service" or "cost-plus"

regulation (with the allowed rate of return representing the "plus" element). It is still widely prac-

ticed in the USA while in Europe many regulators have implemented incentive regulation

schemes.

An example of a simplified formula for rate of return price control is set out below.

11 * ttt RABRORTCR

Where:

R t allowed revenue in t

TCt-1 total cost in the previous year (inflated)

ROR (allowed) rate of return

RABt-1 regulatory asset base

It shows that the allowed revenue in the year concerned, year t, is set equal to costs (operating

and maintenance costs and depreciation) of the previous year, plus an amount to give a normal

return on the capital invested. The allowed revenue is converted in tariffs which remain the

same for a period until they are reviewed in the next round. The allowed revenue and prices are

generally set usually every one or two years.

Rate of return regulation is flexible and responsive to the regulatory authoritys wishes concern-

ing service quality and other matters, because the regulatory authority can allow or disallow any

costs it chooses.

It has nevertheless two well-known and significant disadvantages. Firstly it does not provide in-

centives to control and reduce costs. The company knows it will be able to recover increasing

costs with a subsequent increase in price in the following year. Provided that price reviews take


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place with sufficient frequency, the company pays no penalty for inefficiency. Suppose the regu-

lator tries to reduce costs by setting prices so that costs in real terms are a certain percentage

lower than last years costs. The company has no incentive to make these costs savings; if they

are made, they are in effective immediately taken from the company and given to consumers inthe form of lower prices. The company does not gain from efforts to reduce costs, as the rate of

return earned on capital is still the same. Hence there is no reward for the effort of holding costs

down or reducing them.

Secondly, it provides an incentive for the company to over-invest in capital equipment and plant.

Assuming that the rate of return is set at an adequate level, the regulated company could invest

more and more in plant and equipment and other assets and therefore under rate of return regu-

lation, the company can earn an adequate return on its larger investment. This incentive is

clearly increased if the utility is earning a higher than normal rate of return. This feature of rate

of return regulation is sometimes known as gold-plating2. It can be difficult for the regulator to

identify this over-investment by inspecting investment plans, and hence prevent it from happen-

ing.

Numerous regulatory methodologies have been developed to counteract the deficiencies of rate

of return regulation to various degrees. All these alternative methodologies focus on the estab-

lishment of incentive mechanisms by moving from rate of return to incentive based forms of

price regulation, and to the application of comparative approaches by means of benchmarking

as opposed to the only individual performance assessment of network service providers.

2.2.2 Cap Regulation

The cap refers to the upper limit that is placed on prices or revenue, hence the term price

cap or revenue cap. It was first applied on a large scale to British Telecom in the UK in 1984.

Cap regulation is designed to give the utility a strong incentive to reduce costs. This is partly

done by setting the prices or revenues that a company can earn over a number of years inde-

pendently of the costs it incurs over this time. It is also achieved by allowing the company to

keep at least a portion of the benefits of any efficiency improvements over an assumed level of

improvements.

Under cap regulation, prices or revenues are set in advance usually for a period of three to five

years, allowing the company to benefit from any cost savings made during that period, but re-

2This behaviour is also known as Averch-Johnson effect (see Averch and Johnson (1962)).


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calculated at regular intervals in order to bring them back into line with underlying costs. The

main difference between cap regulation and traditional rate of return regulation is that under the

former system, prices are no longer directly based on the companys actual costs. At one ex-

treme, under a pure rate of return scheme, prices would be set on the basis of the companysactual costs. This provides no incentives for higher productivity. The other extreme is to com-

pletely unlink prices from actual costs; this provides very strong incentives for productivity im-

provement. Cap systems are located somewhere between these two extremes. That is, prices

and costs are detached from each other, but not to their full extent; there still remains some in-

terdependency.

In order to take account of unpredictable rates of inflation in an economy, a cap regulation re-

gime typically allows a company to vary its prices / revenue in any year by an amount linked to

the overall level of inflation, as measured by the percentage change in an appropriate price in-

dex. This is often on an historical basis. This inflation adjusted price / revenue level is then usu-

ally adjusted by a percentage, the X factor that reflects, among other things, the real change to

costs that the regulator assumes is reasonable. The name RPI-X is often used, as RPI (or Re-

tail Prices Index) is the name of the general prices index in the UK.

The starting level and the development path of prices / revenue are fixed such that under nor-

mal conditions, the utility will earn a fair rate of return in each period. This implies the imposition

of a time path of price / revenue ceilings for a period usually extending over several years. The

easiest way to calculate the price path is according to the following formula:

)1(1 XCPIPP tt

Where:

P price;

CPI inflation (consumer price index);

X productivity growth rate; and

t time index.

The same formula could be applied to a revenue cap replacing the price (P) with the revenue

(R) of the company.


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Figure 1 depicts a possible price development path over the regulatory period 3. If the regulated

company manages to improve its efficiency more than is required by the regulator, an additional

profit is generated (yellow field).

Price

time

Benefit to customers(lower prices)

Benefit to firm(higher profit)

Expected improvement(RPI-X)

Actual improvement

Regulatory period

Price

time

Benefit to customers(lower prices)

Benefit to firm(higher profit)

Expected improvement(RPI-X)

Actual improvement

Regulatory period

Figure 1: Cap regulation with decreasing price level

The price / revenue development path does not need to be necessarily decreasing. There are

several cases where the company may be allowed to increase its network charges. The circum-

stances where this might occur can be as follows:

Inflation is higher than the efficiency requirement of the regulator;

High investment needs are recognised by the regulator and included explicitly in the

specified revenue or price path;

OPEX (e.g. labour and/or material cost) increases with a rate which is higher than gen-

eral inflation and the regulator agrees on this increase;

The price control formula incorporates demand growth and associated revenue adjust-

ments; and

3The regulatory period is generally defined as the period of time for which the upper limit to prices or

revenues is set in advance. Often this upper limit is indexed over the regulatory period to a measure ofinflation and/or changes on other cost drivers.


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The initial price / revenue at the start of regulation is below the cost reflective price level

and there is a need to ensure gradual convergence towards a cost reflective level.

2.2.2.1 Types of Cap Regulation

As mentioned above, in cap regulation the cap, or upper limit, may be placed on prices or reve-

nue. Price caps can be divided into:

Individual price caps, where the regulator sets the upper limit for each individual price.

This is the most direct form of price control, but its application is limited to situations

where the number of services provided is small and stable and costs are easily identifi-

able.

Tariff baskets, where prices are grouped into one or more baskets on the basis of theservices to which they apply. A representative weighted average price for the basket is

calculated and an upper limit or cap is then applied to the weighted average price. The

service provider faces a cap on this weighted average price, which increases over time

on the basis of a RPI-X formula. Advantages of tariff baskets include that in theory the

business has an incentive to adopt economically efficient prices and it is consistent with

the principle of light-handed regulation. However, the tariff basket is sometimes found in

practice to be difficult to understand and to implement. In deriving the weighted average

price, the weights chosen may be based on a range of factors, these factors are typically

based on either the revenue or quantity shares of each service in the basket. These

weights may be fixed at the start of the regulatory period and then held constant

throughout the period, or alternatively, reset at suitable intervals.

While with price caps the limit is applied to the actual price or an average of the actual prices

charged, with a revenue cap, the upper limit is applied to the revenue earned. Revenue caps

can be divided into:

Fixed revenuecaps or a pure revenue cap as it is sometimes referred to. The cap or

upper limit of revenue is set at the start of the control period as an absolute amount and

is adjusted each year only for general price inflation and the X factor. It is sometimescalled a fixed cap, because the amount of allowed revenue does not normally vary

automatically with a change in volume.

What we refer to as a variable revenue capand which we define as one where the al-

lowed revenues are indexed (in addition to CPI-X), generally to some measure of


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2.2.2.2 Price versus Revenue Caps

One basic difference between price and revenue caps is the way they respond to changes in

the quantity demanded. Under a price cap, a service providers revenue will move in the same

direction as any change in the quantity demanded, and hence the risk of an unexpected change

to demand can be said to lie with the service provider. Under a revenue cap, the level of reve-

nue is guaranteed for the service provider, and hence the risk of a demand change can be said

to lie with the customer.

The appropriateness of the different types of cap will depend partly on how the costs of provid-

ing the regulated service change with differences in demand. For example, assume that cost

structure of a business is such that the average cost per unit sold does not vary with a change

in the volume sold. Under a simple price cap, the business average revenue will not vary with a

change in the volume sold and total costs will move in proportion with total revenue. Hence aprice cap would be appropriate in that under it there should be no change in the service pro-

viders rate of return with a change in demand.

On the other hand, if there were little change in total costs with a difference in demand, then a

revenue cap incorporating properly selected cost drivers may be a more appropriate means of

price control. However, depending on how the price cap regime is designed, a price cap

scheme may encourage the service providers to establish efficient tariffs systems, e.g. using

tariff basket caps.

2.2.2.3 Setting the Cap

The most commonly-used ways of setting the cap are the:

1. Building blocks approach under this the regulator first assesses the maximum regu-

lated revenue (MAR) of the regulated entity for each year of the regulatory period by as-

sessing separately for each year the components of the maximum revenue; e.g. the

OPEX, depreciation, regulated assets base (RAB) and (in order to calculate the depre-

ciation and RAB) the CAPEX. The next step is to convert this series of MARs into a cap

formula with a starting value that is adjusted each year by an X factor and inflation. The

regulator does this by selecting the starting value and calculating an X so that the pre-

sent value of the revenues under the cap formula should be the same as the present

value of the series of projected MARs. This step is referred to as the smoothing pro-

cedure and we refer in this report to the resultant X as the smoothing X.


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2. Total expenditure or TOTEX approach - under this approach, the regulator does not

consider OPEX and CAPEX projections separately on a year by year basis. Tradition-

ally, no differentiation is made between OPEX and CAPEX. The potential for efficiency

increases in the TOTEX is determined entirely from a benchmarking exercise. Someregulators (e.g. in Norway, Germany and Austria) set the annual TOTEX efficiency re-

duction equal to the X in the cap formula. Others, e.g. in the Netherlands, use the

smoothing procedure described above for the building blocks approach. In this case,

they apply the annual TOTEX efficiency reduction to get the projected maximum allowed

revenue for each year. Using this step would allow the regulator, for instance, to add

non-controllable costs to the maximum allowed revenue for each year, before applying

the smoothing procedure.

We discuss the differences between the two approaches further in Chapter 4.

2.2.3 Yardstick Regulation

Under the regime of yardstick regulation, prices or revenues are indexed to an average of indus-

try performance as opposed to the companys own values. Yardstick regulation is not based on

an assessment of the cost position of individual utilities but upon a comparison of prices or cost

positions and cost determinants between companies. Under a "yardstick" mechanism based on

price information, utilities are not allowed to charge higher prices than some statistical mean

price that is calculated over all utilities, unless this was justified by their "special operating condi-

tions".

This form of price control was suggested by Shleifer (1985) 5. Each in a group of comparable

regional monopolists has a price cap determined by the average cost of the others in the group.

The advantages of this method of regulation include that it is transparent, non-intrusive, com-

pletely de-linked from the price control and there is little scope of gaming. It provides a strong

incentive to operate better than the yardstick as this would generate profits. In turn, more effi-

cient operation will bring down the yardstick and will hence lower prices to end-customers in the

longer term. This effect is very similar to the dynamics of competitive forces.

However, it tends to require frequent calculation and provides strong incentives to firms to in-crease their volumes sold. In addition, problems with the practical implementation of yardstick

regulation include that:

5See Shleifer, A. (1985) A Theory of Yardstick Competition, Rand Journal of Economics, Vol. 16, pp.

319-327.


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minimum standards are used: overall standards or guaranteed standards. Overall standards

measure performance at the system level (e.g. customer minutes lost, percentage of customers

with an outage, or some aggregated quality index). The disadvantage is that they only pick up

the average performance; there may still be substantial differences between individual custom-ers. This leads to allocative inefficiency due to the lack of the penalties discriminating power.

Individual standards score better in this regard as they relate to the level of service delivered to

individual customers. Here compensations are given to those who were actually affected by

sub-standard performance. The symbolic value of the individual compensation can also be quite

substantial. The general disadvantage of minimum standards is that companies who are ex-

pected to maximise profits will be driven towards them i.e. they will not deliver higher quality

levels than strictly required. The effect of this is that quality levels will eventually converge to-

wards the level of the standard which is not likely to be the optimal level in any case.

Quality incentive schemes can be seen as an extension of a minimum standard because they

introduce a direct link between the companys revenue and the level of quality performance.

Performance can be measured at different levels ranging anywhere between the system level

and the performance delivered to individual customers. The penalty/reward structure maps the

level of performance with the financial impact (either a penalty or reward). There are a large

number of possible incentive structures. The structure may be symmetrical or asymmetrical,

continuous or discrete, etc. Dead bands may be applied while the amount of penalties and re-

wards may or may not be bounded. The level of penalty and award is essential. Setting too low

penalties (or too high rewards) may hamper the incentives while too high penalties can increase

risk for the company.


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3. Analysis of Regulatory Schemes in Selected

Countries

While the theoretical literature on regulatory models is quite rich, it still provides relatively little

guidance for practical application in real world circumstances. Therefore, it is important to take

into account international experience, in order to identify existing facts in the regulatory prac-

tice.

To illustrate the impact of regulation on investment decisions by electric utilities, this section

comprises a detailed description of the regulatory regimes in five selected countries, namely

Great Britain, Germany, the Netherlands, Norway and Spain. Each of these countries is dis-

cussed separately, starting out with a brief general overview. In addition, the price control formu-

lae, which are at the heart of the price regulation of network companies, are explained in detail.

3.1 Great Britain

3.1.1 Institutional Background

Electricity reforms have been led by the Electricity Act of 1989, the Utilities Act 2000, the Com-

petition Act 1998 and the Enterprise Act 2002 which resulted in the unbundling and privatisation

of the electricity industry and introduction of access to the networks and competition into the

wholesale and retail markets. The market has been fully open for all customers since 1998. In

the area of electricity, the Office of the Gas and Electricity Markets (Ofgem) is responsible for

protecting consumers, which it does by promoting competition, wherever appropriate, and regu-

lating the monopoly companies which run the electricity networks.

3.1.2 Electricity Transmission

The price control formula and conditions for the Transmission Operators (TOs) are contained in

their licences. This price control does not cover the revenues of transmission system operation


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activities. We have used the Electricity Transmission Licence of the National Grid Electricity

Transmission (NGET)6, as the source of our findings.

3.1.2.1 Cap formula

The current price control runs from April 2007 - March 2012 and is based on a revenue cap.

This is referred to as the Transmission Network Revenue Restriction and has the following for-

mula:

tttttttttttt KTSDISERIELCCxIncRAIPPTTIRGPRTO

Where:

TOt is the maximum revenue;

PR t is the base transmission revenue; see 3.1.2.2 below;

TIRG t is the aggregate of the annual revenue allowances for specified transmission investment

projects relating to the transmission investment for renewable generation (TIRG); see

3.1.2.7 below;

PT t is the revenue adjustment term for allowed pass through items; see 3.1.2.4 below;

IPt is the revenue adjustment term for incentive payments; see 3.1.2.5 below;

CxIncRAt is the revenue adjustment term for the capital expenditure incentive (it equals zero for

all years other than that starting in April 2012); see 3.1.2.7 below;

LC t is the revenue adjustment term for the full recovery of efficiently logged up costs ad-

justed for financing costs (it equals zero for all years other than that starting in April

2012); see 3.1.2.6 below;

IEt is the specified allowance for the costs associated with the issuance of new equity (ap-

plies to the Scottish TOs, SPTL and SHETL, only);

ER t is the specified allowance for the price control extension reconciliation revenue adjust-

ment term;

6 http://www.ofgem.gov.uk/Networks/Trans/Pages/Trans.aspx
http://www.ofgem.gov.uk/Networks/Trans/Pages/Trans.aspxhttp://www.ofgem.gov.uk/Networks/Trans/Pages/Trans.aspx


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DISt is the difference between the total amount charged to the licensee (i.e. NGET) by Scot-

tish Hydro-Electric Transmission Ltd. (SHETL) and Scottish Power Transmission Limited

(SPTL) in respect of site-specific charges (i.e. charges for necessary items in carrying

out of works and the provision and installation of electric lines or electrical plant or me-ters) and the total income recovered by the licensee in respect of excluded services in

relevant year t-1 from customers;

TSt is the difference between the total amount charged to the licensee by SHETL and SPTL

in respect of transmission owner undertaking works (which include works at a relevant

connection site) and the total income received by the licensee in respect of users who

terminate relevant bilateral agreements for connection and/or access rights to the trans-

mission system for relevant year t-1 (including capital contributions);

Kt is the revenue restriction correction term; see chapter 3.1.2.3 below.

All of the above terms are for year t, unless noted otherwise, which means the 12 months

starting 1 April of year t.

3.1.2.2 Cap-setting methodology

Ofgem uses the building block approach to set the cap. Through the base transmission reve-

nue term PR in the cap formula, what are effectively the controllable costs are adjusted each

year for annual inflation (RPI) and, from 2008 onwards, for an efficiency factor, X. PR is calcu-

lated from 2008 onwards from the following formula:

10011

XRPIPRPR ttt

Where:

PR t-1 is the base transmission revenue in relevant year t-1 and shall be calculated in the

same manner as PR t (references to the relevant year shall be used);

RPIt is the percentage change (whether of a positive or a negative value) in the arithmetic

average of the Retail Price Index numbers published or determined with respect to each

of the six months from May to October (both inclusive) in relevant year t-1 and that is

published or determined with respect to the same months in relevant year t-2;


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X is set at two. Ofgem views it is appropriate to establish a rising revenue profile to ensure

that revenues are aligned more closely to the rising trend of CAPEX due to substantial

increases in investment envisaged over the 5 year period.

3.1.2.3 Restriction correction term

The revenue restriction correction term, K, is the main mechanism for adjusting the maximum

revenue for differences between the maximum and actual revenues of the TO. It is calculated

according to the following formula:

100111

ttttt

PIITOARK

1tAR is the transmission network revenue for year t-1;

1tTO is the maximum revenue in year t-1, except for 2007, when it is the maximum revenue

(Mt) for 2006;

tI is the average specified rate (which is the average of the daily base rates of Barclays

Bank PLC current from time to time during the period in respect of which any calculation

falls to be made);

tPI is the penalty interest rate in year t which is equal to:

Four, where 1 has a positive value and transmission network revenue in

year t-1 exceeds the maximum revenue in year t-1 by more than 2.75 per cent;

1 tt TOAR

Zero, otherwise.

3.1.2.4 Cost pass-through items

The regulator notes in its final proposals for the current price control (Ofgem, 2006) that it ac-

cepts that transmission companies incur OPEX costs over which they have little or no influence

(non-controllable). It recommends a continuation of the approach under which several items of

non-controllable costs are subject to pass-through arrangements, such that the companies are


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able to recover the costs that they actually incur. It notes that licence fees (paid to the regulator)

will be treated as non-controllable OPEX.

The cost pass-through term PT t in the transmission revenue cap formula consists of the sum of

a number of items that are listed in the transmission licence 7. For some of these items the term

PT t includes the full amount of the cost incurred by the TO in year t . For others the term PT t

includes an amount equal to the difference between an assumed cost (specified in the licence)

and the actual cost incurred in year t.

3.1.2.5 Incentive payments

The revenue adjustment term for incentive payments (IP) equals the sum of three components

that concern respectively8:

Reliability incentive: the maximum revenue is adjusted in year t to give a pen-

alty/(benefit) for under/(over) performance in year t-1 against a loss of supply volume

target;

Innovation funding incentive: in year t, this passes through a specified percentage

(equal to 80%), linked to the TOs base transmission revenue (PR in the cap) for year t,

of spending on eligible R&D projects. The schemes for transmission will ring-fence an

amount equal to the greater of 0.5 per cent of allowed revenue or 5,000,000 each year;

Rates of leakage of SF6 (Sulphur Hexafluoride): if for year t the actual leakage rate is

less than the target leakage rate, the leakage term equals 0.002 * the TOs base reve-

nue.

3.1.2.6 Logged-up costs

The logged-up costs approach is a mechanism for handling what the regulator refers to as

known unknowns. These are specified costs that are dependent on external factors and whose

7For further details see Special Condition D4 of the Electricity Transmission Licence for National Grid

Electricity Plc.

8Further details of the incentive payments can be found in Transmission Price Control Review: Final Pro-

posals, Ref 206/06, December 2006, (Chapter 9) and in the Electricity Transmission Licence of NationalGrid Electricity Plc (Special Condition D5).


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level over the regulatory period is uncertain. These costs can have a CAPEX and/or an OPEX

element.

The general procedure is that the TO "logs up" (i.e. records) with the regulator the costs in-

curred under the specified cost categories over 2007-2012. It does this by recording the costs in

its annual Regulatory Reporting Pack submissions. The costs are subject to an ex-post effi-

ciency check at the next price review by the regulator. The TO is then remunerated at the be-

ginning of the next regulatory period (i.e. in the year starting April 2012) via the logged-up

costs term LC t for the efficiently incurred eligible costs.

3.1.2.7 Capital expenditure

Transmission investment for renewable generation (TIRG)

The allowed revenue in year t for specified investment projects relating to renewable generation

is calculated according to the formula provided under the above term. For NGET, the specified

projects include circuit reinforcement relating to the England - Scotland Interconnection. One of

the reasons these investment projects are treated separately under the TIRG term is that they

involve high levels of expenditure and their timing and actual cost are uncertain.

In certain specified conditions, the TO can apply to the regulator for a change to some of the

components of the TIRG term. Any change requires the regulators approval, via a determina-

tion.

Capital Expenditure Incentive

As noted above, the revenue adjustment term for the capital expenditure incentive equals zero

in all years other than the year starting April 2012. It is designed to provide a one-off adjustment

to maximum revenue in the first year of the next price review period, starting in April 2012, to

achieve a number of objectives with regard to the CAPEX spend in the current review period

(April 2007- March 2012). These objectives include, among others9:

9Further details of the capital expenditure incentive revenue adjustment can be found in Transmission

Price Control Review: Final Proposals, Ref 206/06, December 2006 (Chapters 7 and 9) and in the Elec-tricity Transmission Licence of National Grid Electricity Plc (Special Condition D9).


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22

Two price controls now apply to the distribution charges:

One charge restriction relates to the level of allowed demand revenue that may be re-

covered from demand use of system charges by the licensee;

The other charge restriction relates to the level of allowed network generation revenue

that may be recovered from generation use of system charges by the licensee.

In addition, there are separate charge restrictions on the metering charges and charges levied

by the distribution business outside its distribution services area.

Here we further discuss only the restriction on the allowed demand revenue; as we understand

that the others are not relevant to the scope of work.

Many aspects of the revenue adjustment for distribution demand revenue are similar to those for

transmission, and our review below is largely based on identifying the differences between the

two. The document we use is the distribution licence issued in 2005 (Ofgem, 2005).

3.1.3.1 Cap Formula

The current price control runs from April 2005 to March 2010 and is based on a revenue cap,

which is referred to as the allowed demand revenue. This is calculated according to the follow-

ing formula:

ttttt KDIPPTBRAD

Where:

ADt is the allowed demand revenue;

BRt is the amount of base demand revenue; see 3.1.3.2 below;

PT t is the revenue adjustment for allowed pass through items; see 3.1.3.4 below;

IPt is the total amount of incentive revenue, in year t (the incentive revenue includes the

incentive adjustment for distribution losses, quality of service and innovation funding in-

centive; see 3.1.3.5)

KDt is the correction factor, whether of a positive or negative value; see 3.1.3.3.

All of the above terms are for year t, unless otherwise noted, which means the 12 months start-

ing from 1 April of year t. In the following sections, we describe these terms and how they are


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24

Where:

PU revenue allowance for low voltage (LV) and high voltage (HV);

PE revenue allowance for extra high voltage (EHV);

GRt growth term

1

11

**

**5,0

t

t

t

itoi

itoi

t GRC

C

DP

DPGR

P0i for each distribution unit category i(voltage level) the corresponding value of P0 that ap-

plies in respect of that category

Dit total number of units distributed in year t to premises directly connected to the distribu-

tion system in distribution unit category i.

Ct number of energised or de-energised exit points on the licensees distribution system in

the relevant year t,

PIADt price index adjuster, which in the relevant year commencing 1 April 2005 has the value

of 1 and in each subsequent relevant year is derived from the following formula:

1100

1

ttt PLAD

XRPIPLAD

Where:

RPIt percentage change in RPI (calculated as for transmission)

X Productivity improvement factor

MGt Merger adjustment is set equal to a specified base amount inflated by growth in the RPI.

3.1.3.3 Correction Factor

The correction factor KD is the main mechanism for adjusting the allowed demand revenue for

differences between the allowed and actual revenues of the distribution licensee. The formula

for calculating this is basically the same as that for the revenue restriction correction term, ex-


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cept that the penalty interest rates are different and, superficially, different names are used for

some variables. It is calculated according to the following formula:

100

1*11 ttttt PRIADRDKD

1tRD is the regulated demand revenue for year t-1

1tAD is the demand revenue in year t-1, except for 2007, when it is the maximum revenue

(Mt) for 2006.

tI is the average specified rate (which is the average of the daily base rates of Barclays

Bank PLCcurrent from time to time during the period in respect of which any calculationfalls to be made.)

tPR is the penalty interest rate in year t which is equal to:

Three, where the combined distribution network revenue 10 in year t-1 exceeds the

combined allowed distribution network revenue11 in year t-1 by more than 2.0 per

cent;

Zero, where the combined distribution network revenue in year t-1 is less than the

combined allowed distribution network revenue in year t-1 by more than 2.0 per

cent;

1.5, otherwise.

3.1.3.4 Cost Pass-Through Items

The pass-through term PT t in the distribution demand revenue cap formula consists of the sum

of a number of items that are listed in the distribution licence (Ofgem, 2004) and also given be-

low. For some of these items (items 3 and 4), the term PT t includes the full amount of the cost

10The combined distribution network revenue is the total amount of regulated demand revenue and net-

work generation revenue.

11The combined allowed distribution network revenue is the total amount of allowed demand revenue and

allowed network generation revenue.


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incurred by the TO in year t. For others (items 1 and 2), the term PT t includes an amount

equal to the difference between an assumed cost (specified in the licence) and the actual cost

incurred in year t. Item 5 is effectively a revenue item.

The items included in PT t are:

The revenue adjustment term for the licence fee payments (made to the regulator) in

year t

The revenue adjustment term for the non-domestic rates paid in year t.

An amount representing an adjustment for other pass-through costs. This is defined

as settlement run-off costs (whose calculation is specified) plus those costs which

the licensee considers, and the regulator approves, should be treated as miscellane-

ous pass-through items

An amount in year t representing an adjustment for Arrangements for the Recovery

of Uncertain Costs. (See section 3.1.3.6 below.)

Minus:

the amount received by the licensee arising from any direction given by the Secre-

tary of State in accordance with the Energy Act in relation to assistance for high cost

distributors.

We understand that the correction factor will adjust the allowed revenue for any deviation (in

million ) between the ex ante and ex post values of these cost pass-through items.

3.1.3.5 Incentive Payments

The revenue adjustment term for incentive payments (IPt) is derived in accordance with the fol-

lowing formula (Ofgem, 2004):

tttt IFIIQILIP

Where:

tIL is the distribution losses incentive adjustment in year t;


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tIQ is the quality performance incentive adjustment in year t; and

tIFI is the innovation funding incentive adjustment in year t.

The term is calculated by the following formula:tIL

tttt LALPIALLRIL **

Where:

LR is the distribution losses incentive rate set at 48/MWh for units distributed after 1 April

2005;

tPIAL it assumes the value 1 in 2004 and in each subsequent year is adjusted for inflation (us-

ing Retail Price Indices);

tL is the adjusted distribution losses calculated through the difference between adjusted

system entry volumes and adjusted units distributed12; and

tAL is an amount representing the target level of distribution losses.

The quality performance incentive adjustment (i.e. ) provides for revenue adjustments to re-

flect the performance of the licensee in achieving targets for quality of supply, to reward best

practice and to adjust for severe weather with regard to supply restoration.

tIQ

13

The innovation funding incentive scheme ( ) is designed to provide for revenue adjustments

that reflect the performance of the licensee in relation to its investment in innovation. This term

is calculated in accordance to the following formula:

tIFI

ttttt KIFICBRIFIEptriIFI *005.0min*

Where:

12For further details see Special Condition C1 of the electricity distribution licence (paragraphs 3 to 5).

13For further details on the formula to derive the quality performance incentive adjustment see Special

Condition C2 of the electricity distribution licence.


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tIFIE is the eligible IFI expenditure for year t;

tCBR means combined distribution network revenue i.e. the total amount of regulated demand

revenue and network generation revenue;

tptri is the pass-through factor applicable for the relevant year t as set out in Special Condi-

tion C3 of the electricity distribution licence; and

tKIFI is the IFI carry forward in relation to the incentive scheme as established in the IFI an-

nual report for year t-1.

Not all variables in these three components would be known accurately before the start of year

t, i.e. when the ex ante maximum revenue is set. Hence, as noted in section 3.1.3.3, the differ-ence between the forecast and actual values of these components would be included in the cor-

rection made with the correction term, K t.

We note that the regulator may at any time change the allowed losses percentage used in cal-

culating the losses adjustment. The change would, however, not take effect until the year after

that in which it was changed.

3.1.3.6 Arrangements for the Recovery of Uncertain Costs

This mechanism is designed to enable revenue adjustments to recover the efficient costs in-

curred within certain categories of costs pursuant to the licensees compliance with specified

enactments. The cost categories are:

Electrical Safety, Quality and Continuity (ESQCR) costs (Electrical Safety, Quality

and Continuity Regulations 2002);

Road occupation costs (made pursuant to the New Roads and Street Works Act

1991);

Permit scheme costs (pursuant to the Traffic Management Act 2004).

The licensee may, by notice to the regulator, propose a revenue adjustment if it believes that

the costs of complying with the above legislation are likely to be a material amount, i.e. likely to

exceed 1% of base demand revenue for year t = 2005.


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The Authority may, within four months, determine (or reject) the revenue adjustment. If it has

made a determination on the application within four months of receiving it, the licensee may no-

tify the regulator that the adjustment will take effect. Any revenue adjustment will be included as

an allowed pass-through item.

3.2 Germany


The electricity regulator in Germany is the Federal Network Agency (Bundesnetzagentur) for

Electricity, Gas, Telecommunications, Post and Railway, which operates within the scope of

business of the German Federal Ministry of Economics and Technology. The legal framework

for electricity and gas is set in the Energy Industry Act (EnWG), which came into force in July

2005. The Ordinance for Incentive Regulation (BMWi, 2007) contains the rules for calculating

the allowed revenues of the regulated network operators for electricity (and gas), both transmis-

sion and distribution networks. Under the Ordinance, the electricity transmission and distribution

network activities are subject to a revenue cap and the first regulatory period is five years long,

from 2009-2013 for both transmission and distribution.

As the German regulator is finalising the preparations for the introduction of incentive regulation

by 1 January 2009, the chapter on Germany cannot be based on what happens in practice, butrather on the provisions of the Ordinance and our understanding of how these are likely to be

interpreted.

The same revenue cap formula is used for the transmission and distribution networks, except

that the transmission formula does not have the quantity adjustment term or quality factor which

the distribution formula has. The Ordinance sets out the revenue cap formula for distribution in

full, while for transmission it does not provide the full formula but explains the exceptions from

the distribution formula.


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3.2.2.1 Cap Formula

The German electricity transmission network is divided into four control areas, each of which

has a separate TSO providing both transmission network infrastructure and system operation

functions14. The revenue cap below covers both these functions.

Under the Ordinance the allowed revenues of each TSO are calculated according to the reve-

nue cap which we understand would be written as follows15:

t

tbtvnbtdnbt PF

VPI

VPIKAVKAKAEO

0

0,0,, 1

Where:

EOt is the allowed revenue, year t

KAdnb,t is the non-controllable costs, year t

KAvnb,0 is the efficient costs, base year

Vt is the reduction factor for inefficient costs in year t

KAb,0 is the inefficient costs, base year

VPI t is the CPI for year t-2

VPI0 is the CPI base year

PF t is the general productivity factor year t

Further explanation of these terms is given below and in Appendix 1.

14The four TSOs are: E.ON Netz GmbH; RWE Transportnetz Strom GmbH; Vattenfall Europe Transmis-

sion AG; and EnBW Transportnetze AG.

15The ordinance does not contain this formula; it is KEMAs formulaic interpretation of the description in

the Ordinance of the revenue cap that applies to the transmission companies.


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3.2.2.2 Cap Setting Methodology

The regulator does not use the building blocks approach, but sets the cap on the basis of

TOTEX adjusted for efficiency increases. The networks total costs are divided between:

Non-controllable costs (KAdnb,t in the cap formula), and

Controllable costs (KAvnb,0 + KAb,0 in the cap formula).

The controllable costs are adjusted for two efficiency components:

A general productivity improvement target, (PF t in the cap formula) which the ordi-

nance sets as 1,25% p.a. in the first regulatory period;

An individual (to each company) efficiency improvement target, which according tothe ordinance is determined from a range of benchmarking techniques.

The individual efficiency target is used to determine the percentage of controllable costs that are

considered inefficient and the reduction factor for inefficient costs (V t in the cap formula) is set

so that these costs are reduced to zero over a ten year period.

The ordinance provides that cost data of the regulated companies for 2006, adjusted to base

year prices, shall be used in establishing the opening value for the first year of the price review

period, i.e. 200916.

3.2.2.3 Revenue Adjustments Regulatory Account

The main mechanism for adjusting for differences between allowed and actual revenues is the

regulatory account. Such an account is established for each regulated company to record over

time the deviations between the actual and the allowed revenues.

The regulated company is required to submit to the regulator by 30 June each year the realised

revenue and energy transmitted for the previous year (January to December). The regulator has

the responsibility first to approve these and secondly to calculate the difference between the ac-tual and allowed revenues, which it records in the regulatory account.

16For the second regulatory period (2014-2018) the cost data used to determine the opening value is de-

rived from the year 2011.


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When calculating the allowed revenue (i.e. the ex post allowed revenue), we understand that

the regulator will use the actual values for the non-controllable costs. In other words the regula-

tory account mechanism will take account of the impact of:

The differences between the forecast and realised values of the non-controllable

costs (listed below); and

Price-setting deviation, as defined in section 3.2.2.2 above.

The amount in the regulatory account will accumulate interest based on the average risk free

rate on government bonds over the last ten years as published by the Deutsche Bundesbank.

The total balance in the regulatory account by the start of the fifth year of each regulatory period

will be recovered over the following period, via the non-controllable cost items. Hence for the

first period, the total balance, including interest, accumulated in the account for the first four

years of the period will be recovered / repaid with interest over the five years of the next regula-

tory period as an addition/ deduction of non-controllable costs over this time17.

The figure below illustrates an example of how the regulatory account works:

Revenue Cap

Year 1 2 3 4 5 6 7 8 9

Regulatory Account1. Regulatory Period


+

-(1+i)4

(1+i)3

(1+i)

-A1

A3

A2

Deviation

Upward deviation isbeared by the network

operator. Interest is

applied on the averagefixed capital

Balance is shared over 5 years

of the following regulatory

period. Either as addition /

deduction to non-controllable

costs

Interest rates will apply!

-A4(1+i)2

Revenue Cap

Year 1 2 3 4 5 6 7 8 9



+

-(1+i)4

(1+i)3

(1+i)

-A1

A3

A2

Deviation

Upward deviation isbeared by the network

operator. Interest is

applied on the averagefixed capital

Balance is shared over 5 years

of the following regulatory

period. Either as addition /

deduction to non-controllable

costs

Interest rates will apply!

-A4(1+i)2

Figure 3: Regulatory Account

17For the second price control period, the balance on the regulatory account from year five of the first

regulatory period to year four of the second regulatory price period will be recovered / repaid over the fiveyears of the third control period.


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If the actual realised revenues exceed by more than 5% of the allowed revenues in one year

(say year t), the network operator is required to adjust its allowed revenues and network

charges accordingly by 1 January of presumably the following year.

3.2.2.4 Non-controllable Costs

The ordinance specifies that the non-controllable costs are:

Those associated with a legal obligation (under the Renewable Energy Act 2004)

that the network operator must abide by. For example, it has the obligation to con-

nect a power plant generated by renewable energy to its network;

Concession levy. This is a fee or some type of right that the network owner has to

pay to the municipality. For example, for a cable under a street, the network owner

has to pay for the use of the area under the street;

Taxes, including property tax and other operating taxes but excluding corporation

tax;

Upstream network charges, e.g. the cost for distribution networks of purchasing

transmission services (does not apply to transmission networks);

The net balance from the regulatory account;

Additional costs of constructing underground cables for, e.g. network reinforcement;

Costs for payment to embedded generators (avoided network charges) (does not

apply to transmission networks);

Costs of the employee committee/staff council. Companies are required to have such

committees/councils if they have more than a minimum number of employees;

Agreements made with the unions in regard to salaries e.g. standardised benefits,

pensions etc for all employees who are part of the salary scheme set by the unions.Also additional employee agreements made between the employee and employer

which do not fall under the general unions agreements are included here. These in-

clude bonuses and targets set on an individual basis and private health insurance;


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Investment budget allowance. An explanation of this is given below; it applies only to

transmission.

3.2.2.5 Investment Budget Adjustment

For TSOs there is a mechanism called the investment budget, which enables the allowed

revenue (ex-ante) to be adjusted, between price reviews, for the capital costs (depreciation and

allowed return) of certain types of investments. These investments would include those required

for the expansion or reinforcement of the transmission network, connection of new generators or

the integration of the national with international networks. Specific examples include:

New lines to connect off-shore power plants;

New underground cables;

Necessary restructuring measures to ensure the technical security of the network is

maintained.

The TSO is required to apply for the investment budget at least 6 months before the start of the

calendar year in which the cost of the investment will be shown, either as a full amount or par-

tially in the accounts of the TSO. One approval can be requested to cover an investment taking

place over several years. The capital return on the approved investment budget for each year

will be included in the non-controllable costs for the duration of the approval. After expiry of the

duration of the approval, the residual asset value of the investment budgets will be transferred

to the regulatory asset base.

It is not yet clear whether the investment budget component of the non-controllable costs will be

adjusted by the regulator on an ex post basis for differences between the approved and realised

costs.

3.2.3 Electricity Distribution

3.2.3.1 Cap Formula

There are over 800 distribution system operators in Germany. As explained earlier, their allowed

revenues are set using the same cap formula that is used for transmission, except that the dis-

tribution formula has two additional terms for quantity and quality adjustment.


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by the regulator, the allowed revenue for year t+2 will be adjusted through the approved quantity

adjustment term (EF t).

The specified cost drivers are:

Energy supply area;

Number of connection points;

Peak Load (relevant for the transformation level of the networks)18.

The quantity adjustment term is calculated for each voltage level (HV, MV, LV) and for each of

the transformation phases (HV-MV, MV-LV). The formula is given in Appendix 219.

3.2.3.4 Quality Adjustment Factor

In accordance with the legislation, quality regulation will be adopted in the electricity sector at

the beginning of the second regulatory period (from 2014) at the latest.

The quality factor depends on several quality indicators: duration of outages (UD), frequency of

outages (UH), unserved energy (NGE) and volume of lost load (NGL). In each case the devia-

tion of the network operator from the reference value for the quality indicator is determined (=

expressed in the brackets of the formulae). This value is monetised and weighted to determine

the quality factor:

tNetzfNGLNGLtNetzfNGENGEtNetzfUHUHtNetzfUDUDt

NGLNGLqNGENGEq

UHUHqUDUDqQ

,Re,Re

,Re,Re

Where:

tQ profit or loss for quality in year t of the regulatory period.

Weighting factor for the quality element (sum of these factors equals 1)

18In Germany the quantity adjustment factor differs for each network level. While energy supply area and

number of connection is considered to be relevant for line costs, peak load is the major driver of trans-former costs.

19We note that the formula for the quantity adjustment factor refers to variables for year t, which appears

inconsistent with the provisions in the Ordinance that the adjustment is made on a time-lagged basis (i.e.by two years).


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Monetising factor (value of each quality indicator)

The BNetzA is currently investigating the values of the quality indicators for different customer

groups. In addition, the decision on how to determine the reference value for the quality indica-tors is still outstanding.

3.3 Netherlands


According to the Electricity Act 1998, separate companies are charged with operating transmis-

sion and distribution electricity networks. In the Netherlands there is only one transmission sys-

tem operator (TSO), TenneT, who is responsible for the transmission of electricity at national

level (i.e. it manages networks of 220kV and above). The regional network operators, on the

other hand, are responsible for provision of electricity distribution services in the different re-

gions.

The regulation in the Netherlands is carried out by the Office of Energy Regulation (Ener-

giekamer20 as of 1 June 2008). This regulatory body is subordinated to the Ministry of Eco-

nomic Affairs and operates as a chamber within the Netherlands Competition Authority (NMa).


The current regulatory period in the Netherlands (for electricity transmission) is the third one and

extends from the year 2007 up to and including the year 2010. The system of regulation for the

current regulatory period includes three main changes compared to the previous one. One

change relates to the duration of the regulatory period, which was extended from three to four

years. In addition, a frontier shift was introduced which applies to the operating costs and the

cost of capital of the investments after the year 2000. Another change refers to the method for

calculation of the allowed cost of capital. The Board of Directors of the Netherlands CompetitionAuthority (the Board) is responsible for determining what level of compensation for the cost of

capital is reasonable in the case of TenneT (NMa, 2006a).

20Previously known as Directie Toezicht Energie (Dte).


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3.3.2.1 Price control formula

The Dutch TSO is regulated on the basis of revenue caps. TenneT's tariffs are set to cover its

efficient costs. The total allowed revenues are adjusted annually in line with the relative change

in the consumer price index (CPI) and the required efficiency increase (X factor). The allowed

revenue is determined annually using the following formula:

1*100

1

tt TIXCPI

TI

Where:

TI the total revenues based on the tariffs for the year t respectively for year t-1;

CPI the relative change in the consumer price index; and

X the discount to promote efficient operations (X factor).

Prior to the regulatory period, the Board estimates the CPI on the basis of the latest information

available. At the end of the regulatory period, the allowed revenue is corrected to account the

difference between the estimated and actual inflation. This difference is incorporated in the tar-

iffs for the next regulatory period.

3.3.2.2 Exceptional investment

To guarantee security of supply in the Netherlands, a separate assessment system is used for

assessing investments in expansion. The system for regulating TenneT deviates from the sys-

tem used to regulate the regional electricity companies. Yardstick competition does not apply to

the regulation of TenneT.

During a regulatory period, TenneT may submit a proposal for an exceptional investment to the

regulator. TenneT submits such proposals annually to the regulator before 1 October together

with the annual tariff proposal. If the regulator approves the proposal for the exceptional invest-

ment, TenneT is allowed to adjust its tariffs to account for the operating cost and annual capital

return (depreciation and return on assets) of the approved investments.


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ity improvement is driven by the average quality performance of network industry. If a

network operator invests in quality and achieves higher quality than other network

operators, this network operator may therefore charge higher tariffs.

In accordance with the Electricity Act, the Board determines the volume parameters at the start

of the regulatory period. These volume parameters apply for the entire regulatory period. A cor-

rection is made in the case of changes in the volumes, compared to those used to determine

the allowed revenue in the preceding regulatory period.

3.3.3.1 Determining the allowed revenues

The allowed revenue is determined with the following formula:

1*100

1

tt TIqXCPI

TI

Where:

TI total revenues from the tariffs for the year t or, alternatively, the year t-1, i.e. the sum of

the products of each tariff of the network operator and the volume parameter for the

network operator for each tariff component;

CPI change in the consumer price index;

X efficiency factor;

q quality term.

The initial revenue for the third regulatory period is set equal to the allowed revenue for 2006.

The total allowed revenues are adjusted annually in line with the consumer price index (CPI),

the X factor and the q factor.

The Board may additionally adjust the tariffs in the case of incorrect or incomplete data.

3.3.3.2 Standardised economic costs

In order to ensure the comparability between the companies for the purposes of efficiency ana-

lysis, new reporting standards (regulatory accounting rules) were drawn up. The network opera-

tors report annually on (amongst others) cost data, taking into account the regulatory accounting


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rules. The rules set standard asset life for regulatory purposes and rules for establishment of

regulatory asset base. Based on the rules, the companies calculate their standardised costs in-

cluding the annual capital return, i.e. st

Improved regulatory models for efficient investment and loss reduction in electricity networks

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