PPC’s Proposed Methodology for Transmission … Pricing/Transmission...PPC’s proposed...

Establishment, Organisation and Pilot Operation of the HTSO

PPC’s Proposed Methodology for Transmission Pricing

25 July 2000

TABLE OF CONTENTS

EXECUTIVE SUMMARY I

1. INTRODUCTION 1

2. ALLOCATION OF COSTS AND REVENUES 2 2.1. Defining Allowed Costs 2 2.2. Allocating Costs to Services 6 2.3. Updating Revenues and Charges Over Time 8 2.4. Conclusion 9

3. BOUNDARIES BETWEEN BUSINESSES AND CHARGES 10 3.1. The Boundaries of the HTSO’s Activities 10 3.2. Ownership Boundaries 11 3.3. Boundaries between the Transmission System and Connections 12 3.4. Sharing the Cost of Connection Assets 14 3.5. Summary 16

4. TRANSMISSION PRICING METHODOLOGY 18 4.1. Adoption of Location-Specific Pricing 18 4.2. Criteria for Selection of DC Load Flow Methodology 19 4.3. Aggregation by Zones 19 4.4. Generation/Demand Split 21 4.5. Treatment of Hydro Plant in the Model 21 4.6. Source of Data for Inputs 22

5. DATA SOURCES AND ASSUMPTIONS 23 5.1. Identification of Data Sources 23 5.2. Transmission System Configuration Review 23 5.3. Provision of Information 23 5.4. Updating Information 24 5.5. Omitted Lines 24 5.6. Asset Valuation 25 5.7. Annualised Costs: Depreciation, Rate of Return and Operation and

Maintenance 25 5.8. Defining Zone Boundaries in the Future 25 5.9. Dealing with Volatility 26

6. CONCLUSION 28

APPENDIX A. NGC RULES FOR SHARING CONNECTIONS 29

APPENDIX B. TRANSMISSION LOSSES 31

B.1. Marginal Cost Approach 31 B.2. Reconciling Charges and Costs 32 B.3. Generator/Demand Split 33 B.4. Pro-rata Dispatch 34 B.5. Ex-ante Calculation 34 B.6. Conclusion 34

APPENDIX C. INTERCONNECTORS 36 C.1. EU Constraints on Interconnector Pricing 36 C.2. Principles of Capacity Allocation 37 C.3. Responsibility for Variation in Capacity 39 C.4. Consistency with the Market Rules 40 C.5. HTSO Policy on Defining Interconnector Capacity 41 C.6. Summary 41

000725 final ppc transmission pricing.doc

Executive Summary

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EXECUTIVE SUMMARY

PPC’s proposed transmission pricing methodology has been reviewed under Task 5 of the Project for Establishment of the HTSO. In assessing PPC’s proposals, we have taken into account the desirable characteristics of a charging structure and practices elsewhere in the EU.

The design of any tariff setting regime begins with defining and allocating the costs to be recovered from consumers. Stable rules and principles are important for setting charges in the electricity industry, where irreversible investments have long lives and investors will only commit funds when they are confident of receiving a reasonable rate of return. A full set of tariff setting rules covers the calculation of total allowed costs (the “revenue requirement”), the allocation of those costs between different services and users to define charges, and how charges (or the revenue requirement) are updated each year.

Calculation of transmission charges requires defined limits around the HTSO’s business activities and defined policies on cost allocation. To date, these issues have been discussed in terms of the boundaries between businesses (and in particular between transmission and distribution) and between charges (for transmission and connection). Responsibility for the operation of the assets must also be clearly allocated between distribution and transmission businesses. The HTSO must then apply a robust distinction between the transmission system and connection assets paid for by specific parties. We have made a number of recommendations regarding the boundaries between businesses and charges.

PPC’s proposed methodology for transmission pricing effectively aims to allocate the total costs of the transmission system among the various users of that system. We agree with the adoption of location-specific pricing and support adoption of DC load flow models as familiar to participants in the electricity industry. We also conclude that PPC has made a reasonable effort at defining zones. However, we recommend that PPC follow the likely EU practice of allocating generation no more than 30 per cent of the costs of transmission, rather than the proposed 50 per cent. We also suggest that the model allocate generation to hydro plant pro-rata to its “expected capacity” rather than its installed capacity. In addition, we have a number of proposals regarding the sources of the data inputs used in the model, aimed at increasing the model’s transparency and predictability.

In appendices to this report, we discuss three related issues in transmission pricing. We first set out a proposed rule for sharing the cost of connections between different users. We discuss PPC’s proposed method of allocating transmission losses and suggest that it will need to be amended to avoid giving incentives for inefficient by-pass of the transmission system. Finally, we discuss how interconnector capacity should be allocated and suggest that the HTSO apply its normal transmission pricing policy to flows over interconnectors.

Introduction

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1. INTRODUCTION

This paper is the main deliverable of Task 5 for the Project for the Establishment of the HTSO: verification of transmission pricing and tariff structure. The terms on which access to the transmission system is made available will form an important part of the new system trading arrangements. PPC has developed proposals for transmission terms that cover the level and structure of usage charges, connection charges, and the allocation and treatment of losses. The objective of Task 5 is to undertake a review of PPC’s transmission proposals, providing comments and alternative proposals where appropriate.

In assessing PPC’s proposed methodology, we have taken into account practices elsewhere in the EU and conformity with the EU Electricity Directive,1 as well as consideration of the extent to which the proposals provide the correct economic signals and meet all the desirable criteria.

The foundation of any tariff regime is the definition and allocation of costs to be recovered from consumers. Section 2 sets out the basic principles underpinning a complete set of pricing rules for transmission and connection services.

Cost allocation requires that boundaries be drawn between transmission and distribution and between transmission charges and connection charges. A discussion of the boundaries between businesses and charges is provided in Section 3.

The transmission pricing methodology proposed by PPC is essentially intended to allocate the revenue requirement of the transmission system to the various users of that system. In Sections 4 and 5, we comment on each element of PPC’s proposed methodology in turn, and make some detailed recommendations regarding the sources of the data inputs. Our findings and suggestions are summarised in section 6.

In addition, this report contains three appendices that cover special issues raised during the course of our discussions with PPC. Appendix A sets out an example of the type of rule that can be used to share the cost of connections used by more than one party, drawing upon the experience of the National Grid Company in England and Wales. Appendix B considers the proposed method of charging for transmission losses, whilst the treatment of Greece’s interconnectors is considered in Appendix C.

We look forward to presenting this paper to the Steering Committee.

1 Directive 96/92/EC of the European Parliament and of the Council of 19 December 1996 concerning common rules for the internal market in electricity.

Allocation of Costs and Revenues

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2. ALLOCATION OF COSTS AND REVENUES

The starting point for any discussion of transmission pricing is the definition and allocation of costs to be recovered from system users. The electricity industry is characterised by long-term irreversible investments. If companies in the electricity sector are to attract capital for efficient investment, costs and charges must be defined according to stable rules and principles. Rules set out how costs are to be defined and allocated now; principles define how rules can be amended to meet defined objectives better. Otherwise, individual investors (ie both the transmission company and the generators) will be exposed to “opportunism” of various forms, and they will be reluctant to invest for fear of failing to make a reasonable rate of return.

A complete set of tariff setting rules needs to cover the following elements:

1. How the total of allowed costs is calculated, in order to define a revenue requirement;

2. How allowed costs are allocated among different services and users, to define charges; and

3. How the revenue requirement (or the individual charges) are updated from year to year.

In this section, we describe briefly how these rules operate in the context of high voltage transmission and connection services.

2.1. Defining Allowed Costs

The total costs of a transmission business are normally divided into three components: operating costs; depreciation; and the rate of return on capital. The HTSO needs to set up accounting rules to define each of these costs in relation to transmission, and in particular the boundary between its costs and those of the rest of PPC.

The case of the HTSO is complicated by the fact that the HTSO will not own transmission assets or incur the related operating costs. The relevant assets will be owned by the Transmission Business Unit (TBU), Distribution Business Unit (DBU) and possibly by others. These parties will charge their costs to the HTSO a “Transmission Control Agreement”, and the HTSO will recover these costs through charges for transmission (and connections). As far as the HTSO is concerned, its costs may be defined entirely by the terms of the leases and contracts with asset owners. However, both the HTSO and the asset owners will need proper accounting rules to ensure that costs are allocated to individual assets (transmission, distribution, or connection) and recovered from the relevant users.


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2.1.1. Operating Costs

Operating costs are costs expensed within the year in which they are incurred. Normally, there is little problem in defining them, since they can be observed in actual payments. However, some areas will require clarification:

• Scope of HTSO activities: PPC will perform a number of functions and incur a wide range of costs, both directly and through leases and long-term contracts with service providers and asset owners. The HTSO’s accounting rules need to define which functions it is carrying out and, hence, which operating costs can legitimately be recovered via which charge. Although this sounds straightforward, the treatment of costs can be ambiguous when one part of PPC provides services to HTSO or vice versa.

• Transfer prices for services provided to HTSO by PPC: if the HTSO pays for services provided by PPC, a rule is needed to prevent strategic use of transfer prices and inefficient cross-subsidies. The price charged for such services may be equated to a “market rate”, either if the market price for the service is easily observable, or if the contract has been awarded by an open tender. If neither of these options exists, the transfer price must be set either by a valuation rule (eg value of the alternative) or by reference to the costs of the service provider. In the case of assets owned and maintained by TBU and DBU, the associated costs provide the most useful basis for transfer-pricing under the Transmission Control Agreement. Local tax law may provide a useful set of guidelines as to what methods of valuation and cost allocation are allowed in transfer prices.

• Allocation of costs incurred by HTSO for services provided to others: The HTSO will, initially at least, have a limited number of functions associated with the main monopoly business of running the grid. However, at any time, the HTSO may start to provide services to others in competitive markets (eg data services, forecasting, modelling, civil engineering and other contracting services). In such cases, the revenue requirement normally excludes the costs incurred to provide these “excluded services” (and the revenue earned from them falls outside the revenue restriction).

The HTSO therefore needs accounting rules that define the scope of those costs to be counted as operating costs of the HTSO. The accounts of the HTSO will therefore show as costs:

- Contract payments under the Transmission Control Agreements to cover investment costs (depreciation and return), by asset;

- Contract payments under the Transmission Control Agreements to cover


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operating costs, by asset;

- Actual costs of depreciation and return, plus operating costs, passed directly to the HTSO under the Transmission Control Agreement, by asset; and

- Costs incurred directly by the HTSO.

2.1.2. Depreciation

Calculating a depreciation charge requires three factors: a gross asset value; an asset life; and a “depreciation profile”. Each owner of transmission assets will need to record these items for every asset that it owns, so that depreciation charges can be calculated. The HTSO will then need to consolidate the information in a “Transmission Registry” covering all assets, so that either lease payments or actual costs can be allocated to the appropriate charge (see below).

Gross asset values can be shown in two different ways: the “historic cost” of the original purchase; or the “current cost” of its value to the business at the current time. The choice between these two basic options, and their variants, is a matter that lies outside the scope of the current report, but we return briefly to the choice in discussing the rate of return.

Asset lives are a matter of choice, since they determine how charges are spread through time, not how long assets remain in operation. To avoid opportunism, asset lives for each category of asset should be set by reference to established practice, so that attempts to change the lives have to be justified. Established practice may be defined by local tax law, PPC’s practice in the past, or European standards.

A “depreciation profile” is the formula that allocates the gross asset value to each year over the asset’s life. In most regimes, the profile is a simple straight-line – eg the value of the asset is charged equally to every year of its life. However, economic depreciation tends to be more “accelerated”, to reflect the effect of technological obsolescence, rising operating costs over time, and the risk of becoming redundant. The result is to raise depreciation charges in the early years of an asset’s life. On the other hand, in its transmission pricing model, PPC has used “annuity depreciation”, which defines a constant combined annual cost of depreciation and the rate of return. Compared with straight-line depreciation, annuity depreciation results in lower depreciation at first, and higher depreciation later.

When setting a revenue requirement, we recommend use of a simple variant of economic depreciation, for the sake of economic efficiency and transparency.2 For example, depreciation could be the sum of a constant amount (straight-line depreciation) plus a small

2 The use of annuity depreciation to set individual transmission charges is not subject to the same concerns, and has the advantage that the charge is independent of the age of any specific asset.


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percentage of the asset value (to cover the devaluation of assets implied by continuous technical progress). Some conventional depreciation rules achieve more or less the same effect (eg “sum of the digits”). For some years, the UK industry used a “tilted” depreciation profile (3% per year for 20 years; then 2% per year for 20 years). Any of these schemes for accelerating depreciation would be appropriate. The key criteria for choosing one should be that it is likely to be accepted for some time to come.

We also recommend that Transmission Registries should show the values of each asset in one field and any customer contribution in another field. Hence, an asset paid for by customers and donated to PPC would initially have a gross value of X and a customer contribution of –X, giving a combined value of 0. Both the gross value and the customer contribution would then have to be depreciated. (Using the same rate of depreciation for both is not essential, but ensures that annual charges and net values remain equal to zero.) The purpose of calculating the net value and depreciation of the asset is to allow costs to be shared, if new users connect to and share existing assets.

The HTSO’s Transmission Registry should also show the estimated replacement cost of the asset, for the purpose of calculating the “expansion coefficient” needed in PPC’s proposed transmission pricing methodology. (Alternatively, the Registry should show enough information to allow the replacement cost to be identified from other records.)

2.1.3. The rate of return on capital

The rate of return is the only cost item not visible in the accounts, since it includes the cost of equity that must be estimated from data on the stock market. (The cost of debt can – and should - be derived from the accounts.) In estimating the cost of equity, the aim is to provide a rate of return that is comparable to that offered by other companies with a similar risk profile, so that the regulated company can attract finance for investment.

Various methods of estimating the cost of equity are available, including the Capital Asset Pricing Model, Dividends Growth Model and Asset Pricing Theory. Each method has advantages and disadvantages, associated mainly with the availability of data. In practice, the regulator can adjust the outcome of any method so as to provide higher or lower returns, eg by giving a more or less generous allowance for future taxes. The most efficient approach is to set up a formula using, as far as possible, observable and independent data, so that the scope for discretion and dispute is minimised. The formula should then be changed only if there is strong evidence that the company cannot attract capital, or has an excessive incentive to invest.

The allowed rate of return can be defined in nominal terms (ie as observed in financial markets), or in real terms (the nominal rate, less the inflation rate). Whichever method is chosen must be consistent with the approach to asset valuation. If assets are depreciated at their historic cost, the regulator must offer compensation for inflation by allowing the


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nominal rate of return. Conversely, if assets are revalued each year, the allowed rate of return must be reduced by the same rate of revaluation.3 Otherwise, over the long-run, the company’s rate of return will bear little resemblance to the rate of return in other industries.

2.1.4. Summary

To define the total revenue requirement of the HTSO, it will be necessary to establish a number of accounting rules that define and allocate costs. These rules must cover:

• Definition of the costs of the HTSO’s regulated functions;

• Transfer pricing for services provided to and by other parts of PPC;

• Allocation of corporate overheads;

• Valuation of assets; and

• Asset lives and depreciation profiles.

In addition, it is advisable to adopt a formula or rule for setting the rate of return. This formula should update the rate of return using observable indices. Such a formula may not be as responsive to changes in conditions as a re-estimation from afresh. However, long-term efficiency benefits more from the application of objective procedures than from subjective attempts to estimate the rate of return “accurately”.

To make these rules stable, it is often useful to tie them to established practices, such as local tax laws, PPC’s own procedures, or international standards. However, some deviations can be permitted, if they have a good justification in terms of the overall objectives of regulation.

2.2. Allocating Costs to Services

The HTSO will offer a number of discrete services, including each single connection, and transmission charges for generation and demand in different zones. Further rules are required to allocate the costs identified above to the various services, charges and users.

2.2.1. Transmission versus connections

The transmission pricing method examined by PPC is essentially a method of allocating the total cost of the transmission system to its various users. This method is discussed in greater detail below. To apply this method, however, the HTSO will need to divide its costs

3 This factor is easiest to understand if assets are valued upwards each year in line with movements in the Retail Price Index. The same rate of change can then be deducted from the nominal rate of return. Adjustments are more difficult to calculate and predict, if assets can be revalued by different amounts (eg to reflect replacement costs).


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between (1) those recovered through transmission charges and (2) those recovered from other charges – primarily connection charges.

2.2.2. Depreciation of, and return on, assets

For depreciation charges and the rate of return, cost allocation depends on the attribution of individual assets. The Transmission Registry mentioned above therefore needs to assign each asset to a category of charge (transmission, connection, etc). In the case of connection assets, the Registry must also assign each asset to a particular connection and to a particular user (or group of users, if the asset is shared).

2.2.3. Operating costs

Operating costs can then be allocated to charges directly via an accounting rule, or indirectly, by assigning them to a particular asset (and to the charge associated with that asset). The method of allocating operating costs should, as far as possible, link costs to charges or assets as they are incurred, for example, by assigning each maintenance job a number, and allocating the costs of this job to the asset being maintained. However, some costs will have to be shared among different charges and assets, by applying an allocation formula.

2.2.4. Principles for choosing cost allocation rules

Accountants prefer to allocate costs pro rata to some indicator of the extent to which an activity (transmission or connection) incurs the cost. For example, the cost of the personnel department may be allocated in proportion to the number of full-time equivalent employees involved in some activity, on the grounds that personnel costs depend on the number of employees being administered. In practice, some of these rules appear rather arbitrary. For example:

• Until 1996/97, the National Grid Company (NGC) in Britain allocated maintenance costs in proportion to an asset’s Gross Asset Value, even though older assets are likely to need more maintenance than newer ones. (Eventually, however, the regulator demanded that NGC allocate the costs directly, by job number.)

• Sometimes, it is difficult to say whether corporate overhead costs should be allocated between different departments in proportion to (1) employees (ie personnel management responsibilities), (2) expenditure (ie financial responsibilities) or (3) capital employed (ie responsibility to shareholders).

Where the HTSO faces a choice between several cost allocation rules, the most transparent and objective approach is to apply an economic criterion to select a rule, and then to apply the rule rigidly for the sake of stability. In these instances, the main economic criterion of cost


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allocation is efficiency: whether allocating more or less costs to one service rather than another will improve or distort the efficiency of choices by users. Sometimes, economic efficiency will suggest a need to switch to a different approach, but the temptation should be resisted, unless the case for a change is overwhelming. Frequent changes in accounting rules will create unnecessary uncertainty and disputes.

2.3. Updating Revenues and Charges Over Time

The third set of rules defines how revenues and charges will be updated over time. These rules may take the form of price caps (or revenue caps) set by the regulator, or they may be procedures for updating revenues and charges as costs change. In practice, most regulatory systems require a mixture of price caps and rules for updating the price caps. In defining these rules, the key choices are:

• Whether the regulator sets an overall limit on charges (eg average price cap, tariff basket, revenue cap), or a limit on individual charges;

• Whether these limits are updated for some years in line with observable indices (such as the retail price index, or RPI), or whether they are updated every year in line with movements in the HTSO’s actual costs;

• Whether the HTSO has any flexibility to change individual charges within the limits imposed by the regulatory controls (eg by raising some charges and/or dropping other charges).

The process of designing these rules and controls requires careful consideration of the factors that will change transmission costs over the coming years. A fixed price cap is good for encouraging short-term (productive) efficiency, but it may move out of line with actual costs. When revenues differ from costs, long-term productive efficiency will suffer (if the rate of return earned by investors falls too low), as will allocative efficiency (if prices no longer reflect costs and distort decisions by users). It must therefore be anticipated that price caps will be revised at some time in the future and these revisions should be governed by procedures to redefine and allocate costs, as set out above.


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2.4. Conclusion

This section does not set out a complete description of the regulatory process, but it defines the main features necessary for the calculation of transmission and connection charges. It the following sections, we assume that the HTSO has established its own Transmission Registry and other accounting systems needed to define costs and to assign costs and assets to specific charges. We then discuss the question of the “boundary” between transmission and distribution, and between the transmission system and connections, as matters of cost allocation. Finally, we discuss the rules and procedures used to convert the total cost of the transmission system into charges for use of the transmission system.

Boundaries Between Businesses and Charges

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3. BOUNDARIES BETWEEN BUSINESSES AND CHARGES

The unbundling of transmission charges has raised a number of questions about the scope of the HTSO’s business and its policy on cost allocation when designing charges. These questions have been posed by PPC in terms of “boundaries” between businesses (specifically between transmission and distribution) and between charges (between transmission charges and connection charges). In the following sections, we discuss first the boundaries of the activities of the HTSO. We then discuss the boundary (within HTSO) between transmission charges and connection charges, and related issues of charging policy.

3.1. The Boundaries of the HTSO’s Activities

Increasingly, the respective responsibilities of transmission and distribution businesses are normally defined by reference to a voltage, whereby assets above a certain voltage are defined as transmission and the rest as distribution. The Greek law does not adopt such a well-defined boundary for the activities of the HTSO, since it defines the (distribution) Network as covering “medium and low voltage lines and installations for electricity distribution as well as high voltage lines and installations that have been incorporated into this network.”4 The distribution business is currently responsible for a number of high voltage (150kV) assets in Athens and Thessaloniki. As in many other countries, of course, the transmission business owns lower voltage connection assets. The solution to this boundary question is to set aside the question of “ownership” and to focus on the need for efficient operations and cost allocation.

3.1.1. Efficient operations

We understand that the separation of control over 150 kV assets between transmission and distribution is sub-optimal. We therefore recommend that all 150kV assets should be operated as part of a single “transmission system”. We would prefer that ownership of the 150 kV assets is transferred from the distribution business to the transmission business. However, such a transfer is not necessary to achieve efficient operations. Many “national” grid companies operate both their own high voltage assets and assets leased from other companies.5 An alternative solution is for the distribution business to lease the 150kV assets to the HTSO, for inclusion in the unified transmission system. Provided the lease gave the HTSO sufficient control over operations, this approach will also be efficient.

4 Law No 2773, 21 December 1999, Liberalisation of the Electricity Market - Regulation of energy policy issues and other provisions, Article 2.

5 In Norway, Statnett owns about 80% of the “main grid”. In the Netherlands, TenneT owns about 70% of the high voltage transmission network. REE, in Spain, owns about 98% of the 400 kV system and 27% of the 220 kV system. In the US, FERC’s Order 2000 encouraged utilities to form “Regional Transmission Organizations” or RTOs, to integrate the operation of the transmission assets that they own separately.


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The HTSO will have a Transmission Control Agreement with the transmission business. The similar agreement could easily cover the HTSO’s relationship with the distribution business over the use of its 150kV assets. The HTSO would then include the cost of leasing all such assets within its charges for using the transmission system.

3.1.2. Cost allocation

The HTSO needs to set charges to cover its costs. The annual costs of the transmission business were provisionally estimated at GDR 60 billion, but the estimate will need to be refined, especially if the HTSO acquires or leases assets from the distribution business as well as the transmission business. The HTSO’s total costs will be divided between transmission charges and connection charges (see below). The transmission pricing methodology proposed by PPC then allocates the costs of the transmission system among its users.

In principle, this methodology could use any description of the network, but the use of the transmission system managed by the HTSO will minimise complaints and disputes. Application of the methodology therefore depends on the boundary between the transmission system and any connections owned by the TBU.

3.2. Ownership Boundaries

Connections belonging to the TBU are defined by two boundaries: the ownership boundary between the TBU and the connected party; and the cost allocation boundary between the transmission system and connection assets. We discuss ownership boundaries below and cost allocation in the next section.

3.2.1. Ownership boundary – TBU and transmission connected customers

This boundary already exists for existing customers and there is no reason to change it. In future, however, the HTSO may have to accommodate demands by customers to build and own their own connections, or to have a third party carry out these functions. In such cases, the ownership boundary will be drawn more flexibly, depending upon who builds what assets.

3.2.2. Ownership boundary – TBU and distribution networks

This boundary is inside the current PPC and is therefore less well defined. Distribution networks take power from 150 kV lines, through a 150kV/20kV transformer, onto 20kV lines. We recommended above that 150 kV lines should be incorporated into the HTSO; the 20 kV lines belong to distribution. The only question surrounds the intervening transformers.


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It does not actually matter who owns any asset, so long as property rights are well defined and there are no transactions costs to prevent it being used efficiently by people other than its owner. In our discussion paper, we suggested that ownership of the transformers should be allocated to the party who can most efficiently arrange upgrades to capacity. The purpose of this proposal is to minimise transactions costs, by integrating the decision to add transformer capacity with the ability to collect information on demand growth. In practice, such information is available most readily to the distribution business. We therefore recommend that the transformers feeding distribution networks be allocated to distribution. In any case, the HTSO’s system will have to allow for distribution networks to install and own (or contract for) their own transformers in future.

The HTSO may wish to retain control over connected capacity, in order to avoid overloading lines within the existing transmission system (since demand cannot be despatched). Rather than controlling access through physical control of assets, the HTSO will need to develop contractual devices to prevent anyone from installing a large transformer which allows demand to overload the lines feeding it.

Placing the boundary of transmission on the high voltage side of the transformer means that meters should normally be fitted on the same side, to ensure that losses within the transmission and distribution systems are allocated accurately. In some cases, meters will already be fixed to the low voltage side of the transformer. In such cases, the meter reading used for settlement purposes will need to be adjusted by an allowance to cover losses within the transformer. To be specific, the volume of power taken by the distribution system through this transformer will have to be calculated as the actual meter reading plus losses within the transformer. Transformer losses are often modelled as a fixed amount (“iron losses”) plus a variable amount related to power flows (“copper losses”).

3.2.3. Ownership boundary – TBU and generation

A similar question arises over the allocation of step-up transformers (20kV/150kV or 20kV/400kV) between generators and the transmission network. Once again, the decision about the time to upgrade transformers lies with the generator concerned. We therefore recommend that 20kV/150kV and 20kV/400kV transformers be allocated to the generation business, as at present. As above, the HTSO will need contractual devices to prevent insecure connections to the transmission system.

3.3. Boundaries between the Transmission System and Connections

The transmission system is that part of the high voltage network whose costs are recovered via transmission charges, rather than via connection charges. Up till now, PPC has treated a number of high voltage assets as connections, particularly the 150kV or 400 kV lines running from the nearest sub-station to the transformer of a customer, distribution network or generator. This approach appears to be inconsistent with the proposed method of


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transmission pricing, which treats such lines as part of the transmission system and assigns them a marginal cost (“expansion coefficient”).

3.3.1. Motivations for change

In principle, the inconsistency of approach could be tolerated, as it does not create any problems for total cost recovery or efficiency. The assets treated as connections will enter the Transmission Register marked as such. This means that the costs associated with such assets (opex, depreciation and return) will not be included in the revenue to be raised from transmission charges. Instead, these costs will be covered by a lump-sum payment (“customer contribution”) and/or annual charges paid by the connected party. Where connection assets have been paid for in full, they will attract no additional charge.

However, this approach may lead to disputes in the future. Users may complain that they are being double-charged for connection assets – once at the time of installation and once again in the estimation of incremental costs. For this reason, most systems have adopted – or are moving towards – a sharp distinction between the transmission system and connection assets. Such systems usually adopt a “shallow” definition of connections, meaning only those dedicated lines required to serve individual users.

We therefore recommend that PPC determine a consistent policy for the treatment of assets when determining transmission charges and connection charges. No asset that is used in the calculation of transmission charges should also be used in the calculation of connection charges.

3.3.2. Allocation of assets to connections

To implement our recommendation, PPC needs to reconcile the treatment of the high voltage lines that run (1) from a transmission substation to the step-down transformers of customers and distribution networks, or (2) from the step-up transformers of generators to a transmission substation. With regard to existing lines of this type, we would recommend that they simply be incorporated into the transmission system, as per PPC’s transmission pricing methodology.

In future, the HTSO should adopt a “shallow” connection policy that encompasses the high voltage lines dedicated to individual users. The charges for connections should include:

1. The incremental cost of lines between the nearest transmission substation and the transformer at the user’s end;

2. any cost borne by the HTSO for installation of new transformer capacity at the user’s site;

3. any cost incurred to alter the transmission substation to accommodate the new


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connection;

4. any charge paid to another user for sharing an asset defined as a connection (See below).

The Transmission Registry should clearly identify whether lines are treated as transmission system lines or connections, and should ensure that the cost of connections are not included in the revenue requirement for the transmission system.

3.3.3. Fall-back position for existing lines

The proposal in the previous section distinguishes between existing and new connections. We do not believe that this distinction is discriminatory, or that it should encounter any other legal problems. However, PPC may find it necessary to develop a policy on connection charges for existing high voltage lines. In this case, we would make the following recommendations:

• Where an existing line is dedicated to one user (generator, distribution or consumer), it should be classed as a connection asset and covered by a contract with the user concerned;

• Where an existing line is already used by more than one user, it should henceforth be treated as part of the transmission system.

In both cases, to the extent that the asset has already been paid for by the user concerned, it will not incur any further charges (either connection charges in the first case or transmission revenue requirement in the second case). The replacement cost of these assets will affect the determination of the “expansion coefficient” used to allocate the transmission system revenue requirement to zonal charges, but not the level of total transmission charges.

We believe that this approach avoids unnecessary effort to redefine the allocation of past connections, which in any case will have been fully paid for.

3.4. Sharing the Cost of Connection Assets

As connection assets have been defined above, it is possible that new users will wish to connect to and to share the use of connection assets that have been paid for by other users. In the past, PPC has simply charged each user the incremental cost of making the new connection, and then incorporated the assets into the transmission system.

This approach appears to be relatively efficient, in that users paid the incremental costs of their demands on the system. Looking forward, however, this approach looks “unfair” to the original user. It may provoke disputes from original users who object to paying for


15

assets subsequently used by others.

In the past, such disputes have not arisen. Generation, transmission and distribution were all part of PPC and consumers paid a tariff which was known to reflect national, amalgamated costs, rather than the actual costs incurred. However, the unbundling of services is likely to lead to demands for an unbundling of costs. Independent generators and consumers will be less willing to accept apparent “cross-subsidies” of potential competitors.

We therefore recommend that PPC draw up a policy for sharing connection assets in order to clearly establish the rules before disputes arise. This policy needs to:

• clearly define the charges that are to be shared;

• clearly define the basis for an annual rental fee when a new customer wishes to use a connection asset which has already been paid for by an existing customer;

• define the sharing of annual operating costs (repairs and maintenance); and

• state how the costs of depreciation and return on capital will be calculated.

The sharing rules adopted by the National Grid Company appear to have been accepted in the UK, and their adoption by PPC will reduce the need to devise alternatives. In any case, the key requirement is only to set up the basic property rights of users who pay for connections; if they wish, they can always negotiate alternative sharing formulae.

When a new user connects to an existing connection asset, he will then pay a rental charge to the existing user of the shared asset. The charge to the new user should reflect the valuation of assets according to the principles used to set annual transmission revenues and any annual connection charges.

PPC will need to devise charges for the use of connections put in place some time ago (but clearly already paid for by a consumer). To do so, PPC will need to keep a registry of gross and net capital costs. If information on the original asset cost is not available, PPC may have to use information on replacement costs provided by the Transmission Registry.6

6 Charges can be based on a fixed “historic” cost of acquiring the asset at some time, plus the nominal rate of return. Alternatively, the asset value can incorporate an annual adjustment for inflation, in which case the rate of return must be the real rate of return, ie, the nominal rate less the inflation rate.


16

3.5. Summary

It is critical that from the start, PPC (1) define robust boundaries between the transmission system and the specific assets to be paid by connected parties and (2) clearly allocate the responsibilities for the operation of the assets between the distribution and transmission businesses. Our key recommendations discussed above can be summarised as follows:

• All 150kV lines should be operate as part of a single “transmission system”, even those currently owned and operated by the distribution business. These lines should not therefore be treated as if they were “incorporated within the (distribution) network” for the purposes of Article 2 of law No. 2773.

• We would prefer the transmission business to be the owner of all 150 kV assets (rather than the distribution business), but such a reallocation is not necessary to achieve efficient operations. It is sufficient for the distribution business to lease its 150 kV assets to the HTSO via a Transmission Control Agreement, just like the transmission business.

• The ownership boundary between TBU and future transmission connected customers should depend upon who builds what assets.

• The transformers feeding distribution networks should be allocated to distribution and the 20kV/150kV and 20kV/400kV transformers between generators and the transmission network should be allocated to the generation business, as at present. The HTSO should develop contractual devices to prevent insecure connection to the transmission business.

• The costs associated with connection assets should be covered by a lump-sum payment and/or annual charges paid by the connected party.

• PPC should establish a consistent policy for the treatment of assets when determining transmission charges and connection charges. No asset that is used in the calculation of transmission charges should also be used in the calculation of connection charges. Therefore, the Transmission Registry should ensure that the costs associated with connection assets are not included in the revenue to be raised from transmission charges.

• Existing high voltage lines that run (1) from a transmission substation to the step-down transformers of customers and distribution networks, or (2) from the step-up transformers of generators to a transmission substation should be incorporated into the transmission system.

• In the future, the HTSO should adopt a “shallow” connection policy that encompasses


17

the high voltage lines dedicated to individual users.

• In the case of existing connections, if an existing line is dedicated to one user it should be classed as a connection asset and covered by a contract or agreement. However, if the line is currently used by more than one user, it should be treated as part of the transmission system.

• It is efficient to allow for connection assets to be shared. However, PPC should develop clear and stable allocation rules for sharing connection assets that provide certainty and avoid disputes. These rules should define clearly the charges to be shared.

• To determine the charges for use of connections put in place some time ago, PPC will need to keep a registry of gross and net capital costs. If this information is not available, PPC could use the information on replacement costs provided by the Transmission Registry.

Transmission Pricing Methodology

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4. TRANSMISSION PRICING METHODOLOGY

PPC has proposed a transmission pricing methodology that is essentially intended to allocate the revenue requirement of the transmission system (excluding connections) to the various users of the system. The key elements of this approach are:

1. Differentiation of transmission charges by zone, to encourage efficient location of generation and demand;

2. Use of a DC load flow model to estimate the marginal investment cost of injections and withdrawals at each node;

3. Averaging of nodal charges over “zones” (six for generation and two for demand);

4. Division of total revenues between generation and demand in the proportion 50/50;

5. Consumption is charged on the basis of demand at peak times; generators are charged for installed capacity, except for hydro generators who are charged for 50 per cent of installed capacity;

6. Use of current data and forecasts for 2001 to estimate charges for 2001, with provision for minor updates each year and a major review in 2005.

We have comments on each element, and some detailed recommendations on the sources of input data.

4.1. Adoption of Location-Specific Pricing

Transmission prices have to serve several functions. The most important function is simply to recover the total costs of the transmission system, to that the transmission company can continue to finance its activities. A secondary function is to encourage efficient short-term decisions by existing generators and users, which normally means that charges are based on a measure of connected (or installed) capacity, or maximum demand, to avoid distorting usage when the system is not constrained. The next most important decision is whether or not to have charges that differ by location, or to adopt a common national tariff (the “postage-stamp” system).

The adoption of location-specific pricing can only really be justified as a means to promote efficient location of generation and demand, by signalling the costs imposed by different users. (Any notion that such allocation of costs is “fair” can easily be countered by an alternative definition of fairness, and therefore provides no useful guidance). In practice, the allocation of a fixed revenue requirement among existing users faces many obstacles in encouraging efficient investment decisions by users:

1. Efficient signals to users would have to signal only marginal costs; however,


19

2. tariffs actually reflect a total revenue requirement based on sunk costs; and

3. in any case, estimates of marginal costs can be so subjective and unpredictable that investors do not base their decisions on them anyway.

These problems might suggest that attempts to signal marginal cost are ultimately unfruitful. In fact, many electricity markets have adopted nodal (or zonal) pricing of energy, as an alternative method of encouraging efficient location of generation and demand. However, many electricity markets are constrained by the desire to maintain a national electricity market, either for political reasons or to create a more liquid contract market. In cases of national electricity markets, of which Greece is one, energy pricing does not provide the necessary signals. It is possible to use several other methods, including quantity limits the amount of generation and demand that can be added in different parts of the network, because of limits on capacity availability. However, it would be unwise to ignore one important tool, ie the ability of transmission pricing to provide some incentive for more efficient location of generation and demand.

Therefore, we agree with PPC’s decision to vary transmission pricing by location.

4.2. Criteria for Selection of DC Load Flow Methodology

PPC considered two basic approaches to estimating marginal costs:

1. the “transport model” favoured by NGC (which simulates flows from A to B by the shortest route); and

2. the “DC load flow model” (which incorporates Kirchoff’s laws and directs flows from A to B via different lines in inverse proportion to their resistance).

In our Discussion Paper, we expressed concern about the decision criteria used to arrive at the preferred methodology. It is not clear if the selection of the DC load flow model was based on a priori identification of DC load flows as a more accurate model, or a posteriori evaluation of the results. The latter approach would imply that complex modelling was redundant, since PPC already knew what prices were required. However, we would support the adoption of DC load flow models as familiar to many people in the electricity industry and more likely to reflect the actual implications of additional injections and withdrawals. We would, however, recommend that PPC make the model available to the public, so that existing and potential system users can estimate current and future charges.

4.3. Aggregation by Zones

PPC has used its chosen model to estimate marginal costs for each node on the network, but has then decided to aggregate nodal charges by zone. Within a zone, the relevant charge is


20

calculated as an average of nodal charges, weighted by the assumed (peak time) level of injections/withdrawals. The decision to average charges appears reasonable to us, as it removes a degree of variation in charges which may be hard to justify, given the somewhat subjective and imprecise nature of the marginal cost estimates. The use of an average weighted by the assumed data on flows appears to be entirely reasonable.

It is not clear how the study team decided to define the zones within which nodal charges are averaged. PPC sent us the original nodal charges, listed by zone, but no description of the method by which the zones were defined, other than a general explanation that they combine nodes that are close together in geography and marginal costs. Examining the nodal prices, we cannot see any evidence that the nodes are clustered around particular values, to justify the location of zonal boundaries. The following table shows particular values for the nodal prices within each zone, specifically:

1. the minimum, the maximum and the average;

2. the standard deviation (a measure of variation); and

3. the ratio of the standard deviation to the average (a measure of relative variation).

Table 1 Variation of Nodal Transmission Prices

Zone Min Max Average STD STD/AVG

1 80.108 623.192 190.158 110.415 0.581 2 - 26.768 696.564 73.655 74.524 1.012 3 113.716 917.250 303.450 181.550 0.598 4 187.915 566.622 374.820 53.489 0.143 5 206.306 385.918 293.636 52.639 0.179 6 - 12.417 1,680.212 301.851 292.914 0.970

These figures show wide variation within zones and overlapping ranges between zones, suggesting that nodal prices do not in themselves provide well-defined boundaries. This finding is not particularly surprising. Steven Stoft has made the same point in relation to the zonal averaging of energy prices.7 It is therefore not surprising that PPC has to base the definition of zones on somewhat subjective grounds, including administrative boundaries or a perception of the physical realities of the transmission system.

7 S. Stoft, Transmission Pricing Zones: Simple or Complex?, Electricity Journal, Jan/ Feb. 1997


21

The problem is therefore not how to define zonal boundaries now, but how they will be updated over time. NGC has had to amend zonal boundaries several times since 1990, and each time the reallocation of generators from one zone to another has caused regulatory problems, since their transmission charges may change radically. This means that investors place little confidence in the continuation of existing price signals – and hence existing price signals play relatively little part in pricing decisions.

Such problems will not emerge until PPC next reviews its transmission pricing methodology, but even now PPC needs to adopt certain principles, so that uncertainty does not undermine the incentives provided by existing charges. In particular, PPC needs to explain that zones will only be adjusted to provide better signals about transmission constraints, but that any such decisions will take into account the need to maintain long-term stability of signals to actual investors. Ultimately, PPC may need to consider some form of longer-term arrangement, in which generators pay the tariff that applied when they connected, not the tariff calculated most recently.

Overall, therefore, we are forced to conclude that PPC has probably made a reasonable effort at defining zones, and has amalgamated charges within zones using an acceptable method, but that PPC needs to set down its policy on revising zones in the future.

4.4. Generation/Demand Split

The PPC methodology proposes that both generation and demand customers should each pay 50% of the total costs. We recommend that PPC follow the likely EU practice of allocating generation no more that 30%. The main argument for this is that transmission pricing is principally a matter of allocating sunk costs, which are collected more efficiently from consumers whose decisions about investment and use of electricity tends to be less price-sensitive than generators’ decisions about investment and production of electricity. We also believe that there is no major disadvantage in offering negative charges to generators in deficit zones. (NGC has operated such charges for many years.) However, we recommend that the payment of such charges should be made conditional on the generator providing suitable proof that his plant is available to run when it is needed; in the absence of such proof, the generator should receive no benefit (and pay no charge).

4.5. Treatment of Hydro Plant in the Model

All dispatch in the model is pro-rata to “installed capacity”. The rationale for using this approach (given by NGC) is:

1. It avoids having to forecast future variable costs, including fuel costs;

2. It reflects a uniform discounting of capacity, equal to the reserve margin, to reflect


22

the probability of an outage at peak times.

However, once the locational price is determined, hydro generation is only charged for half its installed capacity. This decision was made on the basis that hydro is low load factor plant, and generation installation costs are high, which the study teams considered sufficient to differentiate it from low load factor thermal plant.

We have some doubts about the rationale given for this approach. Other plant will have low load factors, and it is perverse to reward plant because its costs are high. This rationale is likely to lead to other claims for discounts.

Having discussed the underlying rationale with the study team, we recommend instead that the model allocate generation to hydro plants pro-rata to its “expected capacity”, rather than its installed capacity. This expected capacity (which is a reflection of the concept in item 2 above) would be equal to the expected output of hydro plants (in general) over peak periods, based on historical statistics for all hydro plant. The generation and power output of thermal plants would then be allocated pro-rata to their “net installed capacity” up to the level needed to meet the system peak load. In this way, the hydro plant’s “expected capacity” will enter the model directly on a consistent basis with the charging policy.

4.6. Source of Data for Inputs

Finally, in line with our comments above about the need for charges to be stable or predictable, if they are to influence long-term investment decisions, we have some proposals for agreeing the sources of input data to be used in setting prices now and updating them later. These proposals are set out in the following chapter.

Data Sources and assumptions

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5. DATA SOURCES AND ASSUMPTIONS

The source and type of data used is crucial to the transparency and predictability of the methodology. If there is scope to use different data sets to achieve different results, disputes are bound to arise. Below, we summarise our main recommendations regarding the sources of data.

5.1. Identification of Data Sources

We recommend PPC use known data sources. To minimise uncertainty and the potential for disputes, PPC should establish defined procedures for collecting, storing and updating the necessary information. Whenever possible, the data source should be objective, ie, it should be based on known and observable data, such as the current configuration of the system, committed investments, and actual invoices paid. PPC should avoid using subjective forecasts for future investment in transmission or generation. The pricing method should use data only for the subsequent year, in order to capitalise on objective data about system conditions.

5.2. Transmission System Configuration Review

PPC suggest that the transmission system configuration should be reviewed every five years, at which time new nodal prices should be recalculated. Five years is considered sufficient to avoid creating volatile conditions for potential investors.

We recommend that PPC provides clarification with regard to which year (ie the year five years into the future, the subsequent year or some other year) would be used as the basis for the future reviews. In line with our previous recommendation, we suggest that each review should use the latest actual data, or data for the subsequent year.

5.3. Provision of Information

PPC propose that the software to be used for the zonal price calculation should be made available along with the transmission network data, including information on possible relevant modifications or additions.


24

We would support this approach, to the point where it would be worth including the obligation to provide information on charging procedures in the licence of (or regulations covering) the HTSO. The HTSO would be obliged to make the information available to the public at large, ie to any potential investor. The HTSO may wish to charge a fee for the provision of such information, but the fee should only cover the cost of time and materials incurred in sending out the relevant information. If the HTSO tries to charge a price that reflects the value of the information, potential competitors may complain that the HTSO is discriminating against them.8

5.4. Updating Information

We agree with PPC that a Transmission Registry will be required to provide up-to-date information on every type of equipment belonging to the transmission system, but we strongly recommend that PPC include only the most objective information on replacement costs, ie prices actually paid rather than PPC’s estimated budgets. As we explained in Section 2.1 we recommend that the Transmission Registry assign each asset to a category of charge (transmission, connection, etc). In the case of connection assets, the Registry must also assign each asset to a particular connection and to a particular user (or group of users, if the asset is shared).

We also recommend the use of indexation to the level of general prices (Retail Price Index), or to observed prices paid by PPC (if an objective index can be assembled from such data) to update information between actual purchases.

PPC should then set out the rules on converting this information into expansion coefficients. These rules may occasionally need to be amended to deal with new technology (and the elimination of information on old technology), but the amendment to the rules should be explained and justified through public consultations.

5.5. Omitted Lines

Lines not likely to be used under system peak load conditions were not taken into account in structuring the optimal network in the DC load flow methodology. Given that the omission of these lines does not appear to have any effect on zonal prices, we believe it would be more transparent to assume that all the lines are used.

8 NGC is only allowed to charge the incremental costs of supplying information on the transmission system, despite having no interest in generation, as the Transmission Licence imposes an obligation on NGC to make the information available. The point of such obligations is to override commercial incentives to withhold information in order to exploit monopoly power.


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5.6. Asset Valuation

PPC have proposed that in the future all assets should be categorised under three different categories (ie lines, cables and stations), and a single expansion coefficient defined for each category. This approach is preferred as the range between the maximum and minimum tariff, and hence the relative prices between zones, is greater thus providing sharper locational signals. This does not seem to be a good basis for selection, as it presupposes that wider differentials are better, but the selection has now been made and there is no good reason for reversing it.

Nevertheless, we recommend that, to avoid future controversy, PPC devise objective and transparent rules for collecting data on asset values and for compiling the expansion coefficient for the model. PPC should write down the rules used and apply them mechanistically.

5.7. Annualised Costs: Depreciation, Rate of Return and Operation and Maintenance

The PPC methodology uses an annuity from of depreciation, in order to extract an annual charge that does not depend upon the age of the assets. This annuity procedure delays depreciation (because the rate of return is higher in earlier years). Whether this delay results in figures that are higher or lower than the “real” level of depreciation is difficult to establish – and largely irrelevant, since it is only used to allocate costs among users, not to define the total revenue requirement. However, PPC could encounter many disputes from market participants over depreciation policy. To minimise these disputes, we recommend that PPC carefully record the assumptions used from the beginning. PPC should say explicitly that the annuity depreciation is used to produce an annual cost irrespective of asset age.

In addition, we recommend that PPC states clearly how the rate of return and the operation and maintenance cots used in the annuity calculation have been derived. As we explained in section 2.1.3, the most efficient way to determine the rate of return is to set up a formula using, as far as possible, observable and independent data, so that the scope for discretion and dispute is minimised.

5.8. Defining Zone Boundaries in the Future

In order to select the zones, PPC used two main criteria: proximity of nodes and relative prices (ie nodes are grouped together if they are close to each other and have similar prices).

It is important to bear in mind that in future calculations prices may not be similar at nodes that are located close to each other (especially after the connection of a new large customer). The HTSO may decide that such prices are anomalous, and should be hidden by zonal


26

averages, or that zonal boundaries should be redrawn. However, the process of defining zones can have a large impact on the charges paid by an existing generator or user and should not depend upon subjective treatment of anomalies.

Given the difficulty of predicting where zones will be defined in the future, PPC can only help potential investors in two ways:

• By signalling clearly that zonal boundaries may change and that investors need to arrange contractual protection against the consequences; and/or

• By providing some stability in charges to new generators and consumers.

The next section explains how the HTSO can offer some stability in charges in the face of all sources of volatility.

5.9. Dealing with Volatility

PPC’s examination of its proposed methodology suggests that the results are relatively stable. We note that NGC’s charges have only changed dramatically when NGC adopted a new method of charging; repeated use of the same methodology has not produced volatility so far. We do not therefore anticipate much volatility in the HTSO’s charges.

However, the Greek transmission system is relatively small, by international standards, and a new large user (generation or demand) could have a significant effect on the calculation of marginal costs, if it affected flows at a lot of nodes within a zone. NGC’s users have faced different charges when NGC changed the number or boundaries of charging zones. In practice, therefore, there is no way to predict the scale of future variation.

If the level of volatility is deemed unacceptably high in future, there are a range of mitigation techniques which can be employed. The most commonly used techniques include the use of:

• rolling averages;

• capping price changes from one period to the next or capping individual prices for a fixed period of time (eg 3 to 5 years); and

• offering contractual guarantees of stable charges for some time (eg a 15 year tariff).

PPC has proposed to fix prices for a 5 year time horizon. To maintain economic incentives, it will be important to signal any future changes after the end of that horizon. However, the transition to new charges should be phased in over 5 years. Given our concerns over the method of calculating charges, we believe that such smoothing is advisable, in order to


27

avoid creating inexplicable shocks.

PPC could also offer a reimbursement to generators connecting within one 5 year period (eg 2001-2005), if the associated zonal charge in the next 5 year period (2006-2010) differs by more than a certain amount. This reimbursement would not be available to generators who connected within the next 5 year period, in order to preserve economic signals. In practice, since transmission charges are a relatively small proportion of total costs, such guarantees are unlikely to be necessary. However, a similar regime of longer term guarantees would provide a useful means to reconcile stability with efficiency, if it transpires that system conditions change quickly and that transmission prices need to be revised more frequently than every 5 years.

Conclusion

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6. CONCLUSION

The system of transmission pricing proposed by PPC adopts concepts and methodologies which are found in other systems, or which will be familiar to many in the electricity industry. It serves one major purpose, ie to signal the economic advantages and disadvantages of locating generation and demand in different parts of the system.

Our review of experience with a similar approach adopted by the National Grid Company in England and Wales suggests that the incentives provided by such a scheme are enhanced, if the scheme is transparent and predictable. We have therefore made a variety of suggestions for improving the method’s transparency, by identifying data sources and formalising rules. These suggestions are intended to give investors more confidence that they can predict future transmission prices and will not face the risk of a sudden, unforeseen increase in transmission charges. Eliminating such risks will remove the temptation and need to spread generator plant all around the system (which would otherwise undermine the short-term incentives in transmission charges).

It is nevertheless impossible to guarantee that the methodology will never demand major changes in transmission prices. We have therefore set out at least the principles of different schemes for reducing the implied volatility of charges. In practice, we do not believe that these schemes will be needed until the next major review, in 2005, and may never be required if the methodology itself remains the same.

Appendix A

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APPENDIX A. NGC RULES FOR SHARING CONNECTIONS

The National Grid Company’s usual process of allocating connection assets between users at a shared connection site is based on a proportional sharing of the (annualised) cost of the assets that each customer requires. The basic principle for cost sharing is what NGC refers to as the "left hand rule" where "the connection asset requirements of each customer are placed in the left hand column of the allocation matrix and the remaining requirements emanate from there."9

The following example illustrates the rule. It is taken from NGC's "Statement of Charges for Use of System and Connection to the System for the year 1999/2000". Suppose a connection site has three users connected, users A, B and C. These users require 1, 4 and 2 units, respectively, of a particular type of connection asset, but they can share the assets. As a result, 4 units are built, to cater for the maximum demand from user B. The first unit is required by all three users, and hence is shared equally among them, one-third each. The second unit is required only by B and C, who share a half each. The remaining units are assigned only to B. The resulting allocation of charges for the 4 units in operation is shown in Table 2.

Table 2 Example of Shared Asset Allocation

User Required Units

Allocation of Units Allocation of Total Charges

1 2 3 4 A 1 1/3 - - - = 1/3 ÷ 4 = 0.083

B 4 1/3 1/2 1 1 = (1/3 +1/2+1+1) ÷ 4 = 0.708

C 2 1/3 1/2 - - = (1/3 +1/2 ) ÷ 4 = 0.208 Total 7 = 1.000

This system allocates annual charges including operating costs, depreciation of the original cost of investment and a rate of return. This method avoids disagreement over the share of charges to be allocated to users who arrive some years after construction of the asset. In principle, a similar approach could be used in the case of an asset that had been fully paid off by a user at the time of construction. As long as figures for operating costs, depreciation and return can still be calculated using standard approaches (asset lives, etc), the same

9 NGC (1999) Statement of Charges for Use of System and Connection the System for the year 1999/2000

Appendix A

30

method could then be used to calculate an annual rental fee, to be paid by the new user to the original user.

The purpose of these allocation rules is to provide certainty and to avoid disputes. In meeting this aim, almost any allocation rule will suffice, provided that it is stable. The parties can always negotiate side payments to improve incentives. For instance, supposing that C is willing to share assets, but only if he pays less than 10% of the total charge, not the 20.8% required by the formula. Either A or B, or both, can write a contract to reimburse C for 10.8% of the charge. All the parties will then be better off, since C will bear 10% of the cost of the existing assets (rather than none).

In practice, it is unlikely that such agreements are ever made explicitly, but there always exists the possibility for “horse-trading” (eg over the timing and duration of the outage needed to connect the new user). It does not matter therefore whether the pro rata sharing is “economically efficient” in itself.

Appendix B

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APPENDIX B. TRANSMISSION LOSSES

PPC has proposed using a marginal loss approach for the allocation of losses, where marginal loss factors are set ex-ante for both time of day and season and are fully allocated to generation users. Losses are allocated using scaled marginal loss factors based on the sensitivity to incremental changes in generation. A DC load flow approximation is used to calculate the marginal loss factors. The net generation of each unit is adjusted during settlement in order to account for its loss responsibility. The method can be implemented during settlement, for each hour using real data (although simplification possibilities will be examined). The question over the ex-ante or ex-post calculation of the loss sensitivities is still an open one. Assumptions of economic and pro-rata dispatch have been examined and pro-rata dispatch is favoured.

The proposed methodology raises a number of issues and we comment on the flowing facets of the approach below:

• use of a marginal cost approach;

• adoption of a pro-rata dispatch assumption; and

• ex-ante calculation of loss factors.

Our conclusions are summarised at the end of this section.

B.1. Marginal Cost Approach

A possible merit in using a marginal cost approach is that it promotes economic efficiency. However, the potential to promote efficiency is limited by a number of factors.

First, subjective estimates of charges will not inspire confidence and will be ignored in, or even distort, investors’ decisions. Charges will be subjective if they are based on forecasts.

Second, the marginal cost of losses is only one element of marginal costs and may actually run counter to economic pricing if other elements are ignored. In particular, the marginal costs of transmission constraints are only approximated by PPC’s proposed transmission pricing system.

Third, as we discuss further below, the use of pro rata despatch, rather than forecast despatch, is almost certain to produce results that differ from actual marginal costs.

The method proposed by PPC represents one way to allocate losses. However, before implementing it, PPC needs to ascertain (a) whether the proposed method will produce estimates close to actual marginal costs and (b) how inputs into the proposed method can be

Appendix B

32

made as objective as possible. If the method proves to lack objectivity, and to be a poor measure of marginal costs, it would be better to adopt a simpler (more objective) method of allocation.

The following comments are intended to improve the operation of the current proposal.

B.2. Reconciling Charges and Costs

Revenues set at marginal cost will be greater than the cost of average losses. Marginal loss factors thus over-recover total costs, and a number of alternatives exist to mitigate this effect, including:

• scaling the loss factors; and

• offsetting residual revenue against other charges.

We discuss each of these in turn.

B.2.1. Scaling

The scaling of loss factors can be either proportional or fixed, as set out in the following diagram.

Loss Factor (LF) Scaling

LF

0

LF

0

Proportional Fixed

In the left hand diagram, marginal loss factors are scaled to meet actual system losses, by applying a multiplicative factor. The final charges do not reflect the marginal cost of losses, since they are scaled (ie proportionate scaling also distorts the differential). This approach undermines the economic efficiency that use of a marginal cost approach is supposed to promote.

In the right hand diagram, marginal loss factors are augmented by an additive (flat-rate) loss factor, so that total charges match total losses. In this example, charges are reduced, but the effect could go the other way. This approach preserves the differentials, but still makes the

Appendix B

33

level of any individual user’s charge dependent on the somewhat unpredictable ratio of marginal losses to the average. This unpredictability will undermine incentives.

B.2.2. Reducing Other Charges

The residual revenue over-recovered by the use of a marginal cost measure could be used to offset other charges, where the sum over marginal costs is less than the average costs. This sum could be offset either directly against transmission charges or against the “Uplift” account in general. This approach has the advantage of using a surplus derived from economic pricing to offset other charges that might distort incentives.

B.2.3. Conclusion

We recommend that any attempt to introduce marginal losses should be uncompromised by the existence of potential surpluses, and therefore that relative differentials should not be scaled.

B.3. Generator/Demand Split

The proposed methodology allocates all the costs of transmission losses to generation, and none to demand. Transmission losses are therefore a cost that generators will have to recover from their sales of power. This decision will affect the value of existing generators to whom transmission losses are a deduction from their net revenues. However, it will not affect the efficiency of despatch among existing generators, which depends on the relative level of the charge for losses, not the absolute level.

One problem worth considering is the potential for arbitrage between the generator and demand charges at a single node. Suppose that any generator connected to the transmission system at node A incurs a large penalty factor for marginal losses. An industrial consumer taking power from the same node (or at least from a nearby node) pays no losses and receives no offsetting benefit (unlike in transmission pricing). The consumer will have an incentive to sign a contract with a generator (either a new one or a generator previously connected to transmission node A) to connect to the consumer’s site directly (or via a distribution network), thereby by-passing the transmission grid and avoiding the generator’s charge for losses. Such by-pass may be inefficient, and also reduces the customer base from which the HTSO can recover its total revenues. Since marginal losses can be quite high, this possibility is a real one.

The only solution is to allocate losses to generators and demand on the same basis, but inversely. Hence, if a generator at node A pays for marginal losses at 10 per cent of its output, a consumer would receive a benefit equal to 10 per cent of its demand. Then, it makes no difference whether or not the power passes over the transmission grid. If it does, the generator pays a charge and the consumer receives a equal rebate, adding up to a zero

Appendix B

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charge in all. The charge for by-passing the transmission network would also be zero.

Given the difficulty of identifying what is generation and what is demand within a consumer’s site (or even with an uncooperative distribution network), we would recommend that transmission losses be allocated to generation and demand on the same basis. That is, the charge (multiplier) for demand should be the negative (inverse) of the charge (multiplier) for generation. We have allowed for this possibility in the System Trading Agreement10 (although the rules as written will also accommodate the PPC proposal.)

Given a single distribution business and national uniform tariff, demand charges for losses will be spread even over all non-eligible customers and the prices they pay will not reflect the differential allocation of marginal losses by location. However, the loss factors would affect the prices paid by eligible customers and will prevent strengthening the signals for uneconomic by-pass of the transmission network. This factor will become more important if the range of customers able to choose their providers is widened in the future.

B.4. Pro-rata Dispatch

The rationale behind adoption of a pro-rata dispatch assumption is not clear. Except at peak times (when pro-rata despatch coincides with expected merit order despatch – see section 4.5), the results will not reflect marginal costs and will not therefore promote efficiency. We recommend use of an objective measure of actual dispatch, eg a measure of the actual flows across the system.

B.5. Ex-ante Calculation

The main concerns we have with systems for calculating marginal losses in advance is the reliance on forecast information. We recommend that PPC establish defined sources for all the relevant data inputs. Estimates of actual flows across the system could be taken either from actual data for the previous year, or formal planning data used by the HTSO to develop its transmission system.

B.6. Conclusion

PPC’s proposed approach could be made more transparent and efficient by adjusting the methodology in three ways:

10 Definition and Description of Electricity System Trading Arrangements in Greece, version of 18 July 2000, section 10.9.

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1. replacing the scaling of marginal loss factors with offsetting the over-recovered revenue against Uplift;

2. replacing the pro-rata dispatch assumption with some measure of actual dispatch; and

3. adopting well-defined sources for all relevant data inputs.

We would also recommend that the HTSO adopt the same charges for demand as for generator, although the charge (multiplier) for demand would be the negative (inverse) of the charge (multiplier) for generation.

If these changes cannot be made it may be preferable to adopt a relatively simple method of cost allocation, eg a non-marginal approach such as allocating the cost of losses to retail sales to consumers, until such time as the Greek market develops more diverse price signals by location.

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APPENDIX C. INTERCONNECTORS

The treatment of Greece’s interconnectors requires special consideration, although the same principles should apply. In recent years, the European Commission has shown particular interest in “cross-border trade” within the EU and any resulting rules may, conceivably, constrain the HTSO’s freedom of action. Discussions at EU level have also suggested that the proportion of transmission charges levied on generation should be “harmonised”. For the moment, however, we cannot identify any hard and fast constraints on interconnector pricing in Greece. The following section therefore looks ahead to possible constraints (and how the HTSO should anticipate them) and to the other issues of interconnector operation, namely defining and allocating capacity.

C.1. EU Constraints on Interconnector Pricing

Transmission lines that connect national borders with the rest of the transmission system are, in principle, no different from the lines that connect domestic generators to the rest of the transmission system. To minimise barriers to trade, the European Commission would like to avoid “pancaking”, that is the phenomenon whereby a power flow over several networks attracts a number of separate transmission charges, each reflecting the allocation of sunk costs. Such charges will inefficiently discourage long-distance trade. As a result, the Commission has suggested that transmission charges on generation should be kept to the minimum needed to provide locational incentives, and that cross-border flows (transit) within the EU should be exempt from special charges.

The association of European Transmission System Operators (ETSO) recently published a proposal for charging cross-border flows designed to harmonise the system within the continental members of UCTE. ETSO has proposed the following:

1. A non-transaction based solution;

2. A remuneration of each TSO for cross-border exchanges that is cost reflective and that takes account of the cost of losses and the usage of the infrastructure;

3. A unique European tariff paid by exporting generators and traders (fee per kWh based on declared exports);

4. An international fee of 2 Euro/MWh.

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PPC is concerned that this proposal might apply to its own transmission charges for imports. In practice, however, there are good reasons to suspect that the ETSO proposal outlined above will not apply to Greece’s imports:

• The proposal applies explicitly to flows within the area covered by contiguous (directly interconnected) EU members of UCTE;

• There are special arrangements for flows to/from non-EU members and to/from systems connected to the UCTE by DC links (including UK and Nordel);

• The proposal itself contains slight inconsistency, being both a “non-transaction based solution” and a charge on “declared exports” (ie on a specific class of transactions).

Greece is not a member of the interconnected EU-UCTE system, and will not be for some time, so it is unlikely that any of these proposals will apply to Greece. The only concern for the HTSO will be that sudden changes (new EU members and restoration of integrated AC links) will place Greece within the EU-UCTE system and subject to a particular policy on interconnector charges. In order to cope with such changes, the HTSO should ensure that the costs of interconnector assets are incorporated within the transmission system as a whole, and can be reallocated to other users if any EU policy prevents charges being levied on users of interconnectors.

In the mean time, the HTSO should set transmission prices for flows into (and/or out of) Greece on the same basis as for other nodes.

C.2. Principles of Capacity Allocation

Currently, the capacity available for inflows from neighbouring countries is allocated (on the Greek side) to PPC. In future, PPC (in the form of the HTSO) will need to allocate the capacity to other users.

To begin with, the basis for defining the volume and allocating it among potential users should reflect any long-term contracts or agreements for sales of power at the border, for instance, agreements with the TSO-equivalents within neighbouring countries. These trading partners would sell their power in the new market (at market prices) and would pay transmission charges on the normal basis for the privilege. Alternatively, they may wish to transfer power to a trader at the border (and they may have a contractual right to do so). In such cases, the receiving trader would be responsible for selling the power in the Greek market and would pay the HTSO any related transmission charges.

In future, other producers (from other countries) may secure access for a power flow over the networks of neighbouring countries and into Greece. In such cases, the TSO-equivalents in neighbouring countries will effectively be reassigning capacity on their own networks and

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on the interconnectors within Greece. The HTSO should allow such reassignments to take place, provided that the alternative supplier meets the requirements of Greek law (in terms of the reliability of foreign supplies) and the conditions of market membership.

Ultimately, the right to use interconnector capacity will revert to the HTSO (on behalf of PPC), when existing contracts and other arrangements come to an end. At that point, the HTSO will have to decide how to reallocate the rights. Here, the recent experience of the Netherlands is instructive.

Import capacity into the Netherlands is substantial (compared with the size of the market), but a large proportion is allocated to the power trading company Sep n.v. (in respect of long-term contracts for the import of power), and the total capacity depends on local conditions. Following long discussions with the regulator (DTe), TenneT (the transmission system operator) made approximately 1 GW of capacity available to traders, for sales to and from the Amsterdam power exchange. TenneT invited applications for the capacity, having announced that all applications would receive a pro rata share of what was available. Anticipating that their applications would be scaled down, traders applied for a huge volume of capacity, reputed to be 350 GW. Consequently, each trader received only a small fraction (approximately one 350th) of the capacity they had applied for. Some Dutch distribution companies were left seriously short of energy sources, having relied on receiving a larger share of import capacity. As a result of their distress purchases, the market price soared.

The effects of this process were due to specific features of the Dutch system.11 In the UK, OFGEM has managed to allocate capacity on the Scotland-England interconnector. However, the number of potential users of the Scotland-England interconnector is limited by the small number of producers and traders in Scotland. The Dutch example shows that simple procedures can lead to unforeseen outcomes, when a large number of traders compete for capacity. In particular, pro rata allocation distorts the incentive to submit realistic applications.

If applications are unlikely to exceed available capacity, a simple approach is possible, for example announcing an open season for applications and granting users what they have applied for. However, if a large number of traders would apply for spare capacity, such that their applications exceed by far what is available, the most efficient solution is an auction. The European Commission’s discussions of cross-border trade over transmission constraints

11 Sep n.v. had power to spare, but was legally constrained from selling it at any price less than a punitive (full cost) tariff. When the distribution companies turned to the Amsterdam Power Exchange in distress, prices rose dramatically, touching Euro 450/MWh, until Sep n.v was released from its obligation not to sell more contracts.

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do not rule out auctions as a method of allocation.12 The HTSO will need to decide what system is appropriate for conditions at the time in Greece.

Whatever system is used to allocate capacity rights, it will be necessary to define the volume of such rights, as discussed below.

C.3. Responsibility for Variation in Capacity

In order to demonstrate that capacity has been allocated fairly, the HTSO needs to know at all times (1) what capacity is available and (2) which traders have rights over what capacity. However, most contracts for use of interconnectors are relatively long-term, which presents the HTSO (and any TSO) with an information problem.

Interconnector capacity varies unpredictably over time, especially within an integrated AC system. The (draft) Market Rules assume that traders using an interconnector are only paid for the volumes that they are able to deliver, and are not compensated for being constrained off. The HTSO will therefore define in real time what capacity is actually available for imports, and must be able to define long-term contracts for capacity that, ultimately, match this figure. Essentially, there are two ways to do this:

1. Define contract capacity as a share of what the HTSO declares as available in real-time, such that the shares allocated to users add up to 100%; or

2. Define contract capacity as an amount fixed by reference to factors other than actual capacity (or just fixed in MW), and appoint an Interconnector Operator as the party responsible for net imbalances (imports or exports) flowing over the interconnector.

Under the former option, all flows over the interconnector are assigned to one of the contracting parties.

Under the latter option, ordinary users might contract, say, for 90 MW of an interconnector whose capacity is normally 100 MW, but may be 85 MW. Contract users always schedule imports of 90 MW, regardless of actual capacity, to make full use of their contract rights. When the interconnector is operating at the full level, the interconnector operator will be paid for the additional import of 10 MW. When the interconnector is only available for 85 MW, the interconnector operator will then be charged for an implied export of 5 MW.

12 The Commission would prefer that any resulting revenues are devoted to investment in the grid. Such investment might not be efficient and we would not therefore recommend such a rigid approach. Instead, we would suggest that any revenues from auctions be used to cover the sunk costs of the transmission network, ie to cover part of the HTSO’s revenue requirement.

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Either of these systems will work satisfactorily in a developed market economy, in which all traders are creditworthy. However, the Balkans are still prone to fears over the creditworthiness of individual players. The HTSO will be able to impose a creditworthiness test on users who apply for contract capacity, but the role of interconnector operator can only be assigned to a party able to accommodate short-term flows between Greece and its neighbours. In practical terms, therefore, the only candidates for the role of interconnector operator in the short- to medium-term are the system operators of the neighbouring systems, not all of whom will necessarily achieve the required level of creditworthiness. This is a serious consideration since, on some occasions at least, the interconnector operator will be held responsible for implied exports from Greece and will therefore owe money to the new market. Given concerns over creditworthiness, the HTSO needs to establish contracts for use of the interconnectors that ensure that power is only exported to users who have passed the tests for market membership.

C.4. Consistency with the Market Rules

The market rules (System Trading Agreement or STA) require interconnector users to submit day-ahead offers and states that they will be paid System Marginal Price for flows in the “constrained” forecast generation schedule.13 In practice, this means that the HTSO will apply the second option – adjusting contract rights to match available capacity – up until the day-ahead stage. From that time onward, users with a contractual right to interconnector capacity will have a “firm” right (ie one that is not affected by changes in circumstances). This arrangement will allow traders to plan their use of the interconnector, and to arrange the required level of foreign production and its transmission to the Greek border.

The HTSO can only ensure that the market remains financially sound by checking the creditworthiness of users applying for interconnector capacity, and by minimising unintended exports to parties who are not creditworthy. If interconnector capacity contracts give a firm right at the day ahead stage, there is always a possibility that actual capacity will be higher or lower than the sum of these contract rights. If capacity is higher, the interconnector operator will record a de facto import into Greece; these imports present no problem of creditworthiness, since they imply a payment to the interconnector operator. If capacity is lower, the interconnector operator will record an implied export from Greece; since the interconnector operator will be liable for the cost of the power.

In practice, the risk of capacity falling below the figure announced day-ahead will be small. However, to avoid problems of creditworthiness, the HTSO will need to ensure that its policy tends towards the conservative, ie that the day-ahead level of capacity is generally less than what is actually available. The result of such a policy will be to allow more or less

13 Definition and Description of Electricity System Trading Arrangements in Greece, version of 18 July 2000, section 10.8.

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permanent imports from the interconnector operator, such that the market always owes money to the interconnector operators and not vice versa.

We therefore recommend that the HTSO define interconnector contract rights as a share of capacity declared available at the day ahead stage, such that shares add up to 100% of a figure which is a conservative (under-)estimate of actual capacity.

C.5. HTSO Policy on Defining Interconnector Capacity

Although the HTSO will only define what capacity is available a day in advance, users of the interconnector will need information on what the HTSO expects to be available in order: (1) to assess long-term contracts for interconnector capacity; and (2) to prepare for submission of day-ahead offers and bids into the electricity market. We therefore recommend that the HTSO provides advance information on the capacity that will be available.

With regard to long-term capacity, the HTSO will only provide an indicative forecast, but should also set out the policy it will follow when determining capacity on the day. This policy should cover:

1. Thermal measures of capacity and transmission security standards that will determine the maximum allowable flow over the interconnectors at any time;

2. Factors internal to the HTSO’s system that will determine the level of interconnector capacity that is consistent with transmission security standards (eg constraints within the transmission system that limit the scope for imports); and

3. Prior allocations of capacity for inter-TSO reserve within the wider integrated system.

In time for the submission of each offer, the HTSO should then provide updated forecasts of available capacity, following the same policy. The forecast of capacity available in hour H needs to be updated at regular intervals (monthly, weekly), to allow users of the interconnector to arrange foreign production and its transmission to the Greek border. As discussed above, this policy should be conservative, such that actual capacity tends on average to exceed forecasts (to minimise unwanted exports).

C.6. Summary

Examination of the debate at European level suggests that the HTSO will have considerable discretion for several years to come over the design of interconnector access, and the allocation of interconnector capacity. Greece’s neighbours are outside the EU and, in any case, the European Commission recognises the need for special capacity rationing systems when there is frequently a transmission constraint, as at Greece’s borders. DC links between

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the EU-UCTE system and the UK and Nordel are covered by special arrangements, as would any DC link between Greece and other EU countries (ie Italy). The experience of DC interconnectors is likely to be more informative than arrangements within the EU-UCTE.

We propose that the HTSO define interconnector rights as a percentage share of capacity declared available in time for day-ahead submission of offers and bids. The HTSO should publish the policy used to define this level of capacity and should issue forecasts some time in advance. For the purpose of maintaining creditworthiness, the HTSO’s policy on capacity declarations should be a conservative one, to ensure that availability usually increases within the day, allowing imports from interconnector operators (ie from the TSOs in neighbouring countries). This approach will be consistent with the current design of the market rules.

The charge for use of interconnectors should apply the same policy as transmission pricing for inflows from generators (and, conceivably, outflows to consumers). Should this approach eventually prove inconsistent, the HTSO will need to recover the costs associated with interconnectors from other users of the transmission system.

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