Existing Structure of Tariffs In Ireland:

Transmission Distribution

Supply

CER/03/298 December 19th 2003

TABLE OF CONTENTS

1 Introduction ____________________________________________________________ 2 2 Background _____________________________________________________________ 2

2.1 Objectives___________________________________________________________ 3 2.2 Scope of the Tariff Structure Review Process _______________________ 4

2.2.1 The Review of the Distribution Tariff & Connection Policy __________ 4 2.2.2 The Review of the Transmission Tariff & Connection Policy_________ 4 2.2.3 The review of the Supply tariff ____________________________________ 4

2.3 Steps of the Tariff Review Process __________________________________ 4 2.4 Guiding Principles __________________________________________________ 5 2.5 Cost Basis___________________________________________________________ 6

3 Transmission Charging__________________________________________________ 8 3.1 Introduction ________________________________________________________ 8 3.2 Determination of Transmission Allowed Revenues__________________ 8 3.3 Recovery of Costs ___________________________________________________ 8

3.3.1 Network and Non-Network Costs__________________________________ 9 3.3.2 Recovery Policy__________________________________________________ 11

3.4 Transmission Connection Policy ___________________________________12 3.4.1 Background_____________________________________________________ 12 3.4.2 Connection Assets_______________________________________________ 13 3.4.3 Connection Capital Charges _____________________________________ 14 3.4.4 Operating and Maintenance (O&M) Charges ______________________ 14 3.4.5 Decommissioning and Reinstatement (D&R) Charge ______________ 15 3.4.6 Capacity Reservation ____________________________________________ 15 3.4.7 Export and Import Capacities____________________________________ 15 3.4.8 Upfront Element of Connection Charges__________________________ 16 3.4.9 TUoS Element of Connection Charges ____________________________ 16

3.5 Transmission Use of System Charges ______________________________16 3.5.1 Overview________________________________________________________ 16 3.5.2 User Categories _________________________________________________ 17 3.5.3 TUoS Demand Charges __________________________________________ 18 3.5.4 TUoS Generation Charges _______________________________________ 21

3.6 Autoproducers and Combined Heat and Power (CHP) Producers ___24 3.6.1 Overview________________________________________________________ 24 3.6.2 Connection related Charges _____________________________________ 25 3.6.3 The Application of TUoS Charges to Autoproducers _______________ 25

3.7 Transmission Losses _______________________________________________27 3.8 Impact of MAE on Current Structure_______________________________28

3.8.1 Margadh Aibhléise na héireann/Market Arrangements for Electricity (MAE) 28 3.8.2 Wholesale Market Membership and Participation _________________ 29 3.8.3 Dispatch and Pricing ____________________________________________ 29 3.8.4 The Impact of MAE on Transmission Tariffs ______________________ 30

4 Distribution Charging__________________________________________________ 31 4.1 Introduction _______________________________________________________ 31 4.2 Distribution Connection Policy ____________________________________32

4.2.1 Definition of Connection Assets __________________________________ 32 4.2.2 Connection Charging: Present Principles & Future Objectives _____ 32 4.2.3 Levying Connection Charges _____________________________________ 34 4.2.4 Connection Charging Calculation ________________________________ 34 4.2.5 Customer Cost Assignment ______________________________________ 35 4.2.6 Cost Allocation: Deep, Shallow & Semi-shallow Charging _________ 37

4.3 Existing Connection Charging Methodology _______________________39 4.3.1 ‘Demand Customer’ Charging____________________________________ 39 4.3.2 ‘Generator Customer’ Charging __________________________________ 43

4.4 Distribution Use of System (DUoS) Charges ________________________44 4.4.1 Cost Allocation __________________________________________________ 44

4.5 Existing Structure of DUoS Tariff __________________________________45 4.5.1 Customer Categories ____________________________________________ 46 4.5.2 Structural Elements_____________________________________________ 46

5 Supply Tariff Charging _________________________________________________48 5.1 Current Cost Basis _________________________________________________48 5.2 Cost Allocation_____________________________________________________50 5.3 Existing Structure of Supply Tariff_________________________________50

5.3.1 Supply Customer Categories_____________________________________ 50 5.3.2 Structural Elements_____________________________________________ 51

6 Conclusion _____________________________________________________________53

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1 Introduction Under the Electricity Regulation Act, 1999 (ERA), the Commission is charged with approving the form and basis of charges to be applied for the connection to and use of the transmission and distribution system. Regulation 31 of Statutory Instrument No. 445 of 2000 also requires the Commission for Energy Regulation (CER) to approve arrangements that allow ESB to meet the demand of customers that are not supplied by other suppliers in the market (in the first instance from ESB’s existing generation) for the period to 19th February 2005. The Commission is now undertaking a review of the

• Transmission Use of System Charges (TUoS) and Connection Policy • Distribution Use of System Charges (DUoS) and Connection Policy • Public Electricity Supply (PES) tariffs charged to final consumers

Since 2001, tariffs have been reviewed by the CER on an annual basis with the aim of providing cost reflective tariffs for full market opening in 2005. However, the primary focus of these reviews has been on the overall level of tariffs. This is the first opportunity for the Commission to review the existing structure of tariffs since they have been in place. As part of the review the Commission will also be looking at the Connection Policies of the Transmission and Distribution businesses. It is vital that the connection cost charged to the customer is fully reflective of the cost imposed on the Networks system and consistent with the way remaining network costs are recovered from users. The purpose of this paper is to set out the Commission’s plan for managing the review of the tariff structures, and to provide background information on the current tariff structures. 2 Background One of the key issues facing the Commission, on its creation in 2000, was that electricity prices did not reflect the costs of generating, transporting and supplying electricity. The tariff increases approved over the last three years followed 15 years of effective price freezes when real tariffs (i.e. post CPI) actually fell by over 50%. This price freeze policy achieved considerable savings for customers and effected a significant reduction in ESB's cost base.

Specifically, over the last number of years the Commission has carried out a rebalancing exercise on the retail tariffs with an aim to try and achieve cost reflectivity in the long run. In addition the Use of System network tariff structures were introduced on the 19th February 2000.

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The Commission as part of this review will be taking the opportunity to review the structure of both the Supply tariffs as well as the Use of System tariffs, and associated connection policies, for both the Transmission and Distribution System.

2.1 Objectives

Any charging regime that will be implemented will aim to achieve the following objectives:

• To facilitate wholesale competition without creating artificial barriers for any generator or supplier

• To facilitate retail competition without creating artificial barriers for any supplier

• To develop efficient price signals to consumers to guide short-run and long-run consumption decisions and choice of supplier

• To encourage efficient consumptions patterns across the day and year

• To gain consistency with new market arrangements, including incentives for efficient location of new generators

• To avoid unnecessary bill impacts • To develop charges which are just and reasonable and not unfairly

discriminatory • To avoid cross-subsidies • To gain transparency and simplicity within the tariff structure • To gain consistency with government policy related to support of

renewables

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2.2 Scope of the Tariff Structure Review Process

2.2.1 The Review of the Distribution Tariff & Connection Policy

1. Customer categories 2. Allocation of costs to customer categories 3. Number of components 4. Structure of components, including definition of pricing periods 5. Interruptible tariff 6. Treatment of losses 7. Connection policy 8. Charges for special metering requested by consumer/supplier

2.2.2 The Review of the Transmission Tariff & Connection Policy

1. Customer categories 2. Allocation of costs to customer categories 3. Number of components 4. Structure of components, including definition of pricing periods 5. Connection policy

2.2.3 The review of the Supply tariff

1. Customer categories 2. Allocation of costs to customer categories 3. Number of components 4. Structure of components, including definition of pricing periods 5. Interruptible tariff 6. Methodology for mid-year adjustments.

2.3 Steps of the Tariff Review Process

The tariff structure review will broadly face the following milestones over the next few months. Throughout the tariff review the Commission will consult on any proposed alternatives that we are considering.

• Identify objectives and constraints • Determine cost basis and allocation • Conduct Cost Analysis • Identify Alternatives • Conduct Impact Analysis • Decide on Alternatives

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2.4 Guiding Principles

In pursuing these objectives the Commission will be guided by a number of fundamental principles. These guiding principles will provide high-level direction during development of the detailed plans and work products required by the project.

1. The duty to protect the interests of final consumers. Tariffs should accurately reflect the costs associated with each tariff category and should incentivise efficiency.

2. Tariff charges based to some extent on marginal costs (rather than

on average historical costs or even average reproduction cost] are more likely to send efficient price signals to users.

3. Non-discrimination: we will aim to facilitate competition in the

independent market by ensuring that tariffs across each category fully reflect the costs of supplying those consumers, and that consumers do not avoid responsibility for paying an appropriate share of costs by changing suppliers or installing autogeneration.

4. We will aim to prevent cross subsidisation between and within

different customer categories in the market.

5. We will aim to ensure that connection charges and use of system charges are consistent, so that users are not over or under charged for their connections.

6. We must consider new market arrangements and EU policies,

including those related to use of the interconnectors.

7. We must consider the effects of tariff structure changes on renewable, sustainable or alternative forms of energy.

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2.5 Cost Basis

An integral part to setting a tariff is the method for allocating costs across categories of users. Unless the costs to be recovered are allocated appropriately then the tariff structure for an individual customer category cannot achieve cost reflectivity. The Commission as part of the review will be examining the costing methods used for class allocation and tariff design by the Transmission System Operator (TSO), the Distribution System Operator (DSO) and ESB Supply.

There are at least three broad approaches to tariff setting:

• Average Historical Cost Approach • Average Replacement Cost Approach • Marginal Cost Approach

The average historical cost approach entails taking the expenses actually being incurred or allowed and a return on capital invested in the past as a starting point. This bucket of revenue is classified as being related to demand, energy consumption, and number of customers. The classified costs are then allocated across the various customer classes based on measures of their demand, energy use, and customer counts. The classified and allocated costs are then converted to tariff charges by dividing by billing units (e.g., MIC, kWh, customer-months).

The average reproduction cost approach modifies the average historical cost approach by adjusting assets values to reflect the cost of replacement. As applied by the ESB Business Units the revaluation affects the return on asset base, but not the depreciation charges.

The marginal cost approach is a forward-looking process that estimates the change in the cost of producing or delivering energy in response to a small change in customer usage. Under the new market arrangements, the marginal cost of generation will be the market price. The marginal cost of transmission is a function of (1) congestion and losses reflected in locational marginal prices, and (2) the annualised cost of incremental investment needed to accommodate load growth.

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The marginal cost of distribution is the annualised cost of incremental

local facilities needed to connect customers and the annualised cost of higher voltage facilities needed to accommodate increased use by many customers. The output from a marginal cost study is unit marginal costs – per kWh by time period, per kW of MIC, and per customer. These unit costs can be used to compute the marginal cost revenues (the marginal unit costs multiplied by units expected to be sold) by customer category and in total. Since total marginal revenue does not necessarily match the allowed revenue requirement, adjustments must be made to cover any positive or negative gap. The adjustment can be proportional (so that all classes are allocated the same percentage of their marginal cost revenues) or on a differential basis that takes other factors into account.1 In some cases regulators can use a hybrid approach, which uses a combination of marginal and average allocation of costs. For example, average historical costs could be used to allocate the revenue requirement to customer categories (eliminating the need to close the marginal cost revenue gap at the class level) and marginal costs could be used for tariff design within a category (with the gap closing done at the tariff component level). Throughout the course of the review the Commission will consider the various cost bases and will review the existing methods of cost allocation used by the Transmission, Distribution and Supply businesses. - Does this allocate costs efficiently and correctly? - Should we facilitate a polluter pays policy, should the customer who imposes a cost on the system pay for that cost in full? - Is there cross subsidisation and how should cross subsidisation be defined – in terms of average historical cost or marginal cost?

1 These factors might include bill impacts of moving to a new allocation method, or the relative

likelihood of distorting consumption decisions by adjusting charges away from marginal cost for each customer category.

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3 Transmission Charging

3.1 Introduction

Sections 34 and 35 of the Act confer powers on the Commission to issue directions in relation to the terms and basis of charges for connection and use of the transmission system. It is on this basis that the Commission determines the allowed revenue of the transmission business, which is to be recovered through the annual Transmission Use of System (TUoS) tariffs as specified in the statement of charges. Under Section 36 of the Act the Commission reviews and approves the statement of charges for use of the transmission system as prepared by the TSO.

It is the Commission’s view that the regulation of transmission prices is of central importance to the efficient performance and development of the transmission network and the equitable treatment of its users. The current structure of the TUoS tariff is can be accessed through a link given in the Appendices.

In addition, Section 34 of the Electricity Regulation Act 1999 (the Act) requires the transmission system operator (TSO) to enter into a connection agreement where appropriate with parties seeking connection to the transmission system.

3.2 Determination of Transmission Allowed Revenues 3.3 Recovery of Costs

The transmission tariffs are designed to recover the allowed costs incurred by ESBNG as TSO and ESB Networks as TAO in the operation of and investment in the transmission business.

The allowed costs recover:

(a). an efficient level of external operating expenses. External costs

to the TSO include ancillary services required for system stability and transmission constraint costs;

(b). an efficient level of internal operating expenses. Internal costs are costs over which the TSO and TAO exercise direct control, such as maintenance and overheads;

(c). an appropriate rate of return on assets (currently 6.5%); (d). an appropriate annual depreciation charge on long-term assets;

and (e). a working capital requirement for the TSO.

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The Commission’s determination of allowed revenue for 20032 amounted to €220 million and is shown in detail in Figure 1 below.

3.3.1 Network and Non-Network Costs

For the purpose of understanding the current tariff structure it is useful to categorise the costs of the transmission business under two broad headings: network and non-network costs, also referred to as wire and non-wire costs.

Item (a) in Section 3.2.1 details the non-network costs of the transmission business, which are currently treated as an external or pass-through cost (subject to them being reasonably incurred).

Items (b) through to (e) are the network costs3 associated with the physical transmission of electricity. Internal costs are directly controllable by the TSO and TAO and are subject to incentive regulation.

In 2003 network costs and non-network costs totalled €158.75 million and €61.25 million, respectively. As an indicator, in 2002 the network costs of the transmission business amounted to 71% of the overall approved revenue requirement, with non-network costs therefore constituting 29%. In 2003 this split was 72:28 and in 2004 it will be 77:23.

2 Throughout this paper the figures for allowed revenues and tariffs in 2003 are used for illustrative

purposes. 3 It should be noted that the allowed network cost figure is net of any upfront capital contributions

in the form of shallow connection charges that are paid by connecting parties in accordance with the current transmission connection policy (This is discussed in Section 3.3).

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Figure 1: 2003 Transmission Business Allowed Revenue €M (2003 prices) Constraints 21.04 Ancillary Services 38.42 Regulatory levy 0.73 Insurance 1.05

TSO External Costs 61.25

Internal Operation Costs 20.36 Service Provision 2.36 BSBU Costs 1.97 Maintenance Professional Fees (incl ESBI fees) 3.85

Telecoms 3.25 IT Operating Costs 1.88 Business Overheads 1.88 Non Network Depreciation 5.75

TSO Internal Costs 41.31

TSO Working Capital 0.80 TSO Return on Assets 1.14

Total (Working Capital + Return) 1.94

Less Other Revenue 1.78

Total TSO Revenue Requirement 102.71 Owner Operating Costs 25.43 CER levy 0.72 Owner Depreciation 39.60 Owner Operating Profit 41.17 Total TAO Revenue Requirement 106.92 Payback for 2000 under-recovery 7.55 Payback for 2001 under-recovery 2.82

Total 10.37

Total TUoS Revenue Requirement 220.00

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3.3.2 Recovery Policy

The conventional method applied by network utilities to recover total costs is through upfront connection charges (capital contributions) from first time connections and ongoing TUoS charges from all network users.

Connection charges recover the costs (or a portion of the costs4) of connection assets that are specifically installed to provide access to a single user.5 Generators and demand customers6 connecting directly to the transmission system are required to pay connection charges. The distribution system operator (DSO) is treated as a demand user of the transmission network for connection charging purposes. This is due to the fact that points of connection between the transmission and distribution networks (DSO Exits) impose the same effects on the transmission system as a demand user.

TUoS charges cover the costs of the shared network used for the bulk transportation of electricity, as well as costs of operating and maintaining them. TUoS charges also recover a portion of the connecting assets in the case of demand users as a result of the current 50% shallow connection policy as described in Section 3.3.

Generators and demand users connected directly to the transmission system are subject to TUoS, and users connected indirectly via distribution system7 are subject to both TUoS in addition to Distribution Use of System (DUoS) charges.

In summary, the sources of revenue for the transmission business include:

Connection Charges levied on:

• DSO Connections; • Transmission connected Demand customers; and • Transmission-connected Generators.

4 Demand customers currently pay 50% of the connecting asset costs with the remainder recovered

through TUoS. See Section 3. 5 Network assets can also be specifically installed for more than one user, in which case the cost is

shared between the users at the transmission station. 6 As opposed to the term ‘demand user’ which is normally applied to the ‘supplier’ of the customer.

This distinction is relevant because connection charges are applied to the demand customer whereas TUoS charges are charged to the suppliers (the demand user).

7 Distribution connected generators below 10 MW currently have a zero rate of TUoS charge.

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TUoS Charges levied on:

• Demand Users connected to the transmission and distribution system; and

• Generators connected to the transmission or distribution system.

3.4 Transmission Connection Policy

3.4.1 Background

Historically ESB employed a deep connection charging policy for both generation and demand customers. Under a deep connection approach, a generator or demand customer connecting to the transmission system is required to pay both the cost of the local connection (connection asset costs) and the incremental investment made on the wider transmission system to accommodate the additional generation capacity or load (reinforcement costs). Generators were charged 100%, while demand customers were charged 50% of the deep costs (connection asset costs and reinforcement costs8). Use of system charges were levied on users on a postage stamp basis.9

The Commission issued a ‘Deep to Shallow Connection Charges’ direction10 to ESB on 23rd December 1999 under Section 34(1) of the Act. ESB was directed to issue offers for connection to the transmission system on the basis of a shallow connection policy to both generation and demand customers. Under a shallow connection approach, the connecting customer is required to pay for the cost of network assets that are specifically installed to connect that customer to the transmission system (connection assets costs).

The rationale behind the Commission’s decision to move to a shallow connection policy was due to the substantial drawbacks of a deep policy.

8 Reinforcement costs comprise of ‘system assets’, which broadly comprise the network of routes

and substations used for the bulk transportation of electricity. 9 The postage stamp method determines an average tariff for all users. 10 See http://history.cer.ie/direction2.pdf

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In particular the Commission was of the opinion that a deep connection charging policy to be:11

• difficult and arbitrary to apply in practice; • discriminatory, notably between existing generators and new

entrants; and • not cost-reflective, in the sense that remote reinforcement can be

argued to be of benefit to a great number of customers of the transmission system, since it results in a more secure and reliable system than would otherwise have been the case.

Furthermore, the Commission’s decision reduced the upfront capital costs facing both generation and demand customers seeking connection to the transmission system and was seen as a means to reducing potential barriers to entry.

The direction made the distinction between connection and use of system assets. The connecting party would be charged directly for their respective portion of the connection assets and an ongoing operating and maintenance (O&M) charge.

Regulation 33 of SI 445 of 2000 allows generators and demand users to construct their own connection (termed ‘contestable connection’) to the transmission system. Contestability of connections12 allows parties seeking connections to take responsibility for timeliness and cost of connection assets. Ownership of the connection assets may need to be transferred to the TAO where TSO operation of the assets is necessary for system security and safety purposes.

3.4.2 Connection Assets

The Commission’s direction stated that connection assets shall include:

“A transmission station which is solely or mainly for the use of a specific user, and any tail-fed lines or cables where appropriate which similarly are used solely or mainly by a single user. For the avoidance of doubt, the switching bays at each end of the lines (or cables) shall be included as part of the line (or cable) where appropriate. Other lines and cables, which form part of the meshed grid system, shall be treated as "use-of-system" assets and not as connection assets”.

11 See Commission's comment on Charges for Connection to the ESB's Transmission System, CER, 3

December 1999.

12 See Contestability and Connection Assets, ESBNG, March 2001.

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In October 2000 the Commission approved the ‘Connection Asset Costs: Guiding Principles’ a paper by ESBNG,13 which outlined the boundary between connection and use of system transmission assets and established the principles for ESBNG to apply in deriving connection charges that fulfil the Commission’s direction.

3.4.3 Connection Capital Charges

The Commission considers the ‘least cost technically acceptable’ (LCTA) shallow connection method that is complaint with Transmission Planning Criteria (TPC) to be an important objective that the connection policy must achieve. ESBNG as TSO is required to issue connection charges on the basis of the LCTA method even where a customer is connected using a different method. If for overall optimal planning ESBNG does not select the least cost connection to accommodate a new customer then that customer will only be required to pay for the cost of the least cost connection. If, however, a customer requests a non-standard, more expensive connection then the customer will be required to pay the full ‘additional’ cost of providing this connection.

As shallow connection costs are specific to each individual user the configuration required to connect that user.

3.4.4 Operating and Maintenance (O&M) Charges

3.4.4.1 Connection Assets

ESBNG currently levies an on-going annual service charge on the connection assets as a condition of generation and demand connection agreements. The charges are described as annual O&M charges for ongoing services in respect of the relevant elements of the user’s connection equipment and the transmission station.

With regard to the issue of contestability, operational control is the responsibility of the TSO except in the case of a simple tail-fed connection. The responsibility for maintenance depends on whether the TAO or the user owns the connection assets. 3.4.4.2 System Assets

The cost of operating and maintaining the system assets is a network cost of the transmission business and is recovered through the TUoS demand and generator tariff.

13 See Connection Asset Costs: Guiding Principles, ESBNG, CER/ESB/2000/10, 12 April 2000.

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3.4.5 Decommissioning and Reinstatement (D&R) Charge

The D&R charge addresses the costs incurred in the restoration of the station site and lines and line routes to a satisfactory state once the requirement for the connection has ended. ESBNG currently estimates the cost of the D&R charge as 40% of cost of transmission line assets and 15% of transmission station assets. The connecting party is required to provide security in respect of this charge during and for a period after the term of the connection agreement. The connection agreement specifies the D&R Charge and the amount of the bond to be provided. 3.4.6 Capacity Reservation

The Commission has authorised the provision of a bond in the connection agreement to incentivise the generator or demand customer to commit to installing the Maximum Export Capacity (MEC) or Maximum Import Capacity (MIC)14 cited in the application for connection to the system and not seek to reserve capacity additional to that which is legitimately required.

The generator bond amounts to €10,000 per MW of MEC and demand customers provide a bond with a value of eighteen months worth of Network Capacity Charge per MW of MIC. The bond remains in place until the applicant’s generation plant has passed all capacity tests and for eighteen months following their Operational Date with respect to demand customers.

3.4.7 Export and Import Capacities

A generator’s MEC and a demand user’s MIC represent a connecting customer’s peak capacity requirement. MEC and MIC values are highly relevant as they generally represent the extent to which the transmission network has been designed to serve the customer and it places an upper limit on the total capacity that a customer can reasonably be expected to require of the network.

Currently the customer is charged a connection charge based on the specific shallow connection and TUoS capacity charges in accordance with its MIC and/or MEC.

14 An MIC and MEC value is the maximum power, expressed in MW or kVA, under the terms of the

connection agreement that a user can import from or export to the system at any given time.

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3.4.8 Upfront Element of Connection Charges

Transmission connected demand customers pay 50% of the shallow connection costs upfront with 50% included in TUoS charges. Transmission connected generators pay 100% shallow connection costs upfront. DSO driven connections (DSO exits) to the transmission system are treated on the same basis as demand users for charging purposes (i.e. 50% of the shallow connection costs). The historic and current connection charging policy is outlined in Table 2 below.

Table 2: Change in Connection Charging policy. Transmission Connection Policy

User Pre December 1999 Post December 1999 Generator 100% Deep 100% Shallow

Demand 50% Deep 50% Shallow

3.4.9 TUoS Element of Connection Charges

Elements of connection assets recovered through TUoS charges are initially paid upfront by the TAO. These costs become part of the TAO’s Regulatory Asset Base (RAB) for 40 years, upon which it currently earns an annual regulated return of 6.5%.

3.5 Transmission Use of System Charges

3.5.1 Overview

The TUoS charging regime is designed to recover the allowed revenue of the transmission business from all users of the network, in other words, the network and non-network costs of owning, operating and maintaining the transmission network.

In the existing tariff structure 25% of network related costs are recovered from generators users and the remaining 75% from demand users. In addition, approximately 99.5% of non-network related costs are recovered from demand users.

TUoS charges are recovered through capacity and energy charges according to the user’s category. Capacity charges are based on the maximum capacity required by the user15 (measured in MW), whilst energy charges relate to actual usage (measured in MWh).

15 MIC or MEC

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Generators face TUoS charges on the basis of their MEC and location.

Demand users are charged on the basis of both MIC and energy transfer, with 60% of the demand user’s allocation of network costs attributed on a largely fixed MW (capacity) basis and the remaining 40% of costs charged based on a MWhr (energy) basis. Non-network costs, costs associated with, for example, the procurement of Ancillary services and the costs of Constraints, are recovered through the System Services Charge (SSC) on a variable per MWhr (energy) basis.

3.5.2 User Categories

TUoS charges are recovered from demand users and generators connected to the transmission and distribution systems. ESBNG’s Demand Transmission Service (DTS) schedules contain all the applicable charges for demand users while generator related charges are contained in the Generator Transmission Service (GTS) schedules. The Autoproducer Transmission Service (ATS) schedules extend the current charging policy for both generators and demand users and recognises the special case of users who both consume and generate electricity in a single premises essentially for their own use and all Combined Heat and Power (CHP) producers.

3.5.2.1 DTS Schedule

As mentioned above the DTS schedules recover 75% of the annual network costs and approximately 99.5% of non-network costs. The remaining 0.5% is recovered through generator trip/fast wind down charges. The DTS associated charges are levied on the suppliers of three demand tariff schedules listed below for billing purposes. The DTS schedule recognises three distinct categories of demand users:

(a) Tariff Schedule DTS-T: suppliers serving customers connected

directly to the transmission system16. (b) Tariff Schedule DTS-D1: suppliers serving customers connected to

the distribution system and having a MIC of 0.5MW or above. (c) Tariff Schedule DTS-D2: suppliers serving all other users connected

to the distribution system who are not served under DTS-T or DTS-D1.

16 There are approx. 22 transmission connected demand users.

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3.5.2.2 GTS Schedule

The GTS schedules recovers 25% of the annual network costs and recognises two distinct categories of generators:

(d) Tariff Schedule GTS-T: which provides services to generators

connected directly to the transmission system. (e) Tariff Schedule GTS-D: which provides services to generators

connected indirectly to the transmission system via the distribution system.

3.5.2.3 ATS Schedule

The ATS schedules can be thought of as a hybrid of the aforementioned GTS and DTS schedules. In addition, all Combined Heat and Power (CHP) producers are charged on the same basis as autoproducers. The ATS schedule recognises two distinct categories of autoproducers.

(f) Tariff Schedule ATS-T: which provides services to generators and

suppliers serving users connected directly to the transmission system.

(g) Tariff Schedule ATS-D: which provides services to generators and suppliers serving users connected indirectly to the transmission system via the distribution system.

3.5.3 TUoS Demand Charges

3.5.3.1 Network Capacity Charge

The network capacity charge recovers, on a largely fixed basis (or per MW), 60% of the network costs allocated to demand17. The network capacity charge is based on the MIC per demand user. A proxy of this charge is charged to users on tariff schedule DTS-D2 who do not have an MIC; the proxy is based on daytime metered energy. 3.5.3.2 DTS-T

Transmission connected demand users are contracted to an MIC under the terms of their transmission connection agreement. The MIC is the specification to which the connection will be designed and forms the basis of the capacity charge for each user. The charge incorporates a bandwidth for reasonable seasonal variation in demand. Interval Metering is used to measure actual consumption and users also face an unauthorised capacity charge if they exceed their MIC. This is to incentivise demand users to accurately predict their MIC values.

17 Note: 75% of network costs are allocated to demand users.

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Bandwidth

A demand user reducing its overall demand either temporarily or permanently and thus not using their full MIC will pay lower capacity charges18 as a result of the structure of network capacity charge which incorporates a bandwidth. The bandwidth rules provide a range of tolerance in respect of the total capacity charges which users are liable to pay under periods where demands are less than their MIC. Capacity charges are calculated based on the rules outlined in ESBNG’s ‘Statement of Charges’.

A user whose MIC is less than 20 MW and highest metered demand is less than 80% of their MIC will be charged based on 80% of their MIC. A demand user with an MIC value greater than 20 MW will be charged based on their MIC value minus 4 MW, providing highest metered demand does not exceed this.

If a user wishes to reduce charges further then a more permanent reduction in their MIC would be required19.

3.5.3.3 DTS-D1

Distribution connected demand users capacity charges function in a similar way to those of DTS-T, adjusted for an appropriate distribution loss factor based on the losses associated with the distribution system. The charge also incorporates a bandwidth to allow for a reasonable seasonal variation in demand.

This charge has been modified to reflect the fact that distribution connected users, through diversity of their demands, do not have the same effect on the transmission system at the Grid Exit Point as would a directly connected user. Consequently, the network capacity charge for users under the DTS-D1 schedule is less than the corresponding charge under the DTS-T charge.

Currently there is no TUoS unauthorised usage charge for DTS-D1 users as the customer is liable to Distribution unauthorised Usage charges.

18 Users with either temporary or permanent reductions in demand additionally see an immediate

reduction in charges through their System Services Charge and Capacity Margin Charge, which are levied on a variable (MWh) basis.

19 See MIC Administration Proposal for customers connected to the Transmission System, ESBNG, 17 June 2002.

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3.5.3.4 DTS-D2

Distribution connected demand users capacity charges are based on day-hours consumption recovery.

3.5.3.5 Network Transfer Charge

The usage element of the network charge is termed the Network Transfer Charge. 40% of the network charge levied on demand users is allocated through this variable energy charge on a per MWh basis, and the charge applies across all demand user categories. This charge is based on actual MWh consumption of energy and reflects the associated use of the transmission network to transfer that energy. 3.5.3.6 System Services Charge

System Service charge primarily recovers the costs of the provision of ancillary services and transmission constraint costs.

Ancillary services are required for system stability, and include the following:

o Operating Reserve - to guard against unexpected loss of generation

user; o Reactive Power - required for voltage control; and o Black-Start Capability - in the event of a blackout.

The charge is based on approved revenue for system services costs and energy consumption. System Service Charges or non-network costs are recovered almost entirely from demand users on an energy basis through a, per MWhr charge. All demand users pay ESB National Grid a System Service charge in respect of these costs, which are then reimbursed to the providers of these services by ESBNG.

The exception is Unit Trip payments. The generator pays this when it trips off the system as this can cause voltage and other problems for the overall network. Unit Trip payments are charged to generators and netted off the non-network costs levied on demand users.

3.5.3.7 Capacity Margin Charge

Capacity margin is planned generating capacity above peak demand requirements that provides a margin of safety in the event of an expected or unexpected interruption of a generator’s production or an outage of transmission assets. Capacity margin payments are made to plants in respect of capacity available but not generating in EPUS during the time period of minimum reserve margin in the day. The price paid per MW of capacity provided was based on calculation of the annualised fixed costs of a best new entrant (BNE) OCGT. In 2004 the rate was set by a decision of the Commission.

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The Capacity Margin Charges are levied to recover the costs of providing this spare capacity required by a power system. These costs are recovered fully from demand users, and are paid by all three user classes on a day time energy basis per MWh.

The Capacity Margin charge is a pass-through cost of the TSO. It is recovered by the TSO through a separately identified item within the TUoS mechanism, and then paid by the TSO to generators providing capacity margin. Therefore, the cost of providing capacity margin is not included in the network and non-network costs described above.

3.5.3.8 Unauthorised Usage Charge

This charge applies to demand users connected directly to the transmission system (DTS-T). All metered energy in the user’s peak usage hour in excess of a demand user’s MIC is levied as an Unauthorised Usage Charge. This acts as an incentive for demand users to contract for the appropriate level of MIC.

3.5.4 TUoS Generation Charges

3.5.4.1 Network Capacity Charge

The generator network capacity charge recovers the entire network costs allocated to generation users.20 Distribution connected generators with an MEC of 10MW or above and all transmission connected generators are charged for capacity on the basis of locational use-of-system charges, which attempt to provide efficient siting signals to new generators in support of an overall efficient transmission system.

The methodology for calculating locational TUoS charges for generators is based on the Reverse MW-mile approach21. This approach allocates a share of the fixed costs of the network to the generator based on its usage of the transmission system, reflecting the fact that cost depends on the distance and direction that power is being transmitted as well as the level of power being transmitted. The methodology rewards generators which offset network flows and averages the cost of spare capacity that exists in the network across all users. There are three main steps involved in deriving transmission tariffs using the reverse MW-mile approach.

20 25% of network costs are allocated to generators. 21 A worked example of the Reverse MW-mile approach can be seen in ESB National Grid’s

document, entitled Explanatory Paper for 2004 Statement of Charges, ESBNG, 4th December 2003.

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1. Load flow analysis is first conducted to determine the use of each circuit by each generator, based on peak load conditions. Usage is then divided into:

o flows that add to overall system flow (dominant flows); and o those that counter the overall flows (reverse flows).

Generators producing dominant flows will pay for their usage whilst those producing reverse flows will be credited for reducing overall transmission flows.

2. The annual replacement costs of overall transmission assets are

then broken down on a cost per circuit basis. 3. The charge to each generator is made on their proportional

usage of each circuit multiplied by the cost of each circuit. This delivers a generator circuit charge. Per circuit charges are aggregated across all circuits to derive the generator’s aggregate locational use-of-system charge.

Due to inherent spare capacity on the intact network (as it is designed to withstand certain contingencies] the aggregate locational charges do not recover all generator related revenue requirements. The remainder of the charge is recovered on a postage stamp basis. The relative share of generator capacity charges in 2003 was approximately 90% reverse MW-mile based, and 10% postage based. The postage stamp element of the generator tariff does not provide locational signals.

Analysis has shown that generation TUoS charges have the potential to be relatively volatile especially in a situation where large amounts of generation connect to a given location. Various methods of mitigating volatility have been suggested, such as for example using rolling averages, or capping the change in any one year. 3.5.4.2 Unit Trip Payments

Unit Trip Payments are the one element of non-network costs incurred by generators. If a generator above 100MW experiences a sudden (Fast Wind-Down) or immediate (Direct Trip) loss of power it will cause significant difficulties for the management of the overall network. Generators are charged per MW over 100MW for each incidence of sudden loss of load as a means of deterring this behaviour and recovering the system costs incurred.

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3.5.4.3 Non-Firm Network Capacity Charge22

The non-firm transmission tariff is charged to all transmission connected generators for output in excess of the shallow connection capacity during commissioning and prior to the Deemed Firm Date for dispatchable generators. The charge is derived on an equivalent energy basis using the generation location based capacity charging methodology described above.

3.5.4.4 Generator Commissioning Charge23

During testing or commissioning phases a generator may not be able to accurately predict the actual level of output the unit will achieve at any specific time and can be at a significantly higher risk of outage than a fully commissioned generator. This can lead to increased operating costs for the TSO for several reasons. The TSO will generally have to commit extra units to ensure a rapid response to changes from the commissioning unit’s scheduled output and to ensure that the system remains within normal security standards. As the commissioning unit is at a significantly higher risk of tripping, the TSO will carry additional operating reserve to ensure that security of supply is not compromised. This leads to additional constraint costs under the Trading and Settlement Code and Rules and increased reserve payments.

In essence the extra costs incurred by the TSO fall into three categories:

o increased constraint costs where extra reserve is being provided; o increased costs of Reserve Premiums; and o increased run hours as commitment will assume unit does not

exist.

3.5.4.5 Interconnector Charges

Interconnector users currently pay a charge for use of the North-South Interconnector as outlined in Schedule Interconnector Transmission Schedule (ITS) in the Statement of Charges. Interconnector users exporting to Northern Ireland pay an interconnector usage charge to ESBNG.

22 For further information see Firm and Non-firm Access to the Transmission System, a direction by

CER, CER/01/72, 19 June 2001. 23 The detailed methodology used to derive this charges is provided in the paper, Generator Testing:

Background and Calculation of Commissioning Charges by ESBNG.

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There are two charges identified under the ITS schedule:

o Long-term Export Capacity Charges: Interconnector parties with Long Term Contracted Capacity Entitlement (LTCCE) to export from Republic of Ireland to Northern Ireland pay interconnector charges as set out in the relevant Interconnector Auction Agreement.

o Short-term Interconnector Usage Charges: For each trading period

granted pursuant to an allocated trade in excess of their Long Term Contracted Capacity Entitlement in the South – North direction

Interconnector capacity charges to import energy from Northern Ireland to Ireland are payable to Northern Ireland Electricity (NIE). A demand user located in Ireland will pay Transmission Use of System charges under the appropriate demand schedule to ESBNG for imports from Northern Ireland. 3.6 Autoproducers and Combined Heat and Power (CHP) Producers

3.6.1 Overview

The treatment of autoproducers under the current tariff arrangements is set out in the Commission Direction ‘Treatment of Autoproducers in the Distribution and Transmission Charging Regime’24 of 17th April 2002. On 25th September 2003 the Commission issued a direction extending the principles underlying the first direction to all CHP producers.25

The Commission largely adopted the definition of an autoproducer as defined in Europeans directive 96/92/EC. An autoproducer is any user of the network who consumes and generates electricity in single premises where such generation is essentially for the user’s own use in that single premises. Depending on internal usage patterns there may be times when these users are in a position to export electricity, whilst at other times they may need to import additional power from the network. Thus they may be importers or exporters depending on the period in question.

Autoproducers and CHP producers like other users, face connection and use-of system charges.

24 http://history.cer.ie/cer0237.pdf 25 http://www.cer.ie/cerdocs/cer03237.pdf

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The core purpose of the autoproducers Direction was to eliminate the double capacity based charges and connection charge facing autoproducers, that is, to make them liable for only one capacity based charge and one connection charge. Which particular charge an autoproducer would incur (as generator or demand user) would be determined by which ever is larger the MEC or MIC, in other words, (the predominant use) being made of the network.

3.6.2 Connection related Charges

An autoproducer with an MIC greater than or equal to its MEC is charged on the same basis as a demand user and the connection charge is based on its MIC (50% shallow). An autoproducer with an MEC greater than its MIC is charged for connection on the same basis as a generator and the connection charges are based on the Autoproducer’s MEC. Ongoing Service Charges are levied on the same basis as the Connection Charge. D&R charges are applied as normal.

3.6.3 The Application of TUoS Charges to Autoproducers

3.6.3.1 Autoproducers Connected to the Transmission System

Where an autoproducer connected to the transmission system has an MIC greater than or equal to its MEC it pays Network Capacity Charges as set out in DTS-T in accordance with the its MIC. Where an autoproducer connected to the transmission system has an MEC greater than its MIC, it pays Network Location-Based Capacity Charges set out in GTS-T of the in accordance with its MEC.

When an autoproducer connected to the transmission system imports electricity, the following TUoS charges, as set out in DTS-T and Capacity Margin Charge apply:

o Network Unauthorised Usage Charge; o Network Transfer Charge; o System Service Charge; and o Capacity Margin Charge.

When an autoproducer connected to the transmission system exports electricity the following TUoS System service charges, as set down in GTS-T apply:

o System Services Generator Direct Trip Charge; and o System Services Generator Fast Wind-down Trip Charge.

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3.6.3.2 Autoproducers Connected to the Distribution System

Where an autoproducer connected to the distribution system has an MEC less than 10MW, it is not charged generator related TUoS charges as set down in Tariff Schedule GTS-D.

3.6.3.3 Transmission Capacity Charges

Where an autoproducer connected to the distribution system has an MIC greater than or equal to its MEC it pays Network Capacity Charges as set out in DTS-D1 or DTS-D2 in accordance with the autoproducer’s MIC.

Where an autoproducer connected to the distribution system has an MEC greater than its MIC it pays Network Location-Based Capacity Charges as set out in GTS-D in accordance with its MEC .If the MEC is less than 10MW then it pays no TUoS charges).

3.6.3.4 Transmission Usage and Service Charges

When an autoproducer connected to the distribution system is importing electricity, the following TUoS charges as set out in DTS-D1 and Capacity Margin Charge will apply:

o Network Unauthorised Usage Charge; o Network Transfer Charge;

o System Service Charge; and o Capacity Margin Charge.

When an autoproducer connected to the distribution system is exporting electricity (and where the Trip Output is in excess of 100 MW) the following TUoS charges, as set down in GTS-D will apply:

o System Services Generator Direct Trip Charge; o System Services Generator Fast Wind-down Trip Charge.

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3.7 Transmission Losses

The movement of electrical energy across the transmission system is subject to losses,26 with the result that generation user requirements will marginally exceed final demand. This discrepancy is provided for through the use of Transmission Loss Adjustment Factors27 (TLAFs) applied to generators.

It is important to note that TLAFs do not form part of the TUoS tariff but are treated as a market item.

Some generators are responsible for proportionally more transmission losses than others depending on their point of connection to the grid. For this reason, transmission loss adjustment factors are site specific. Aggregate system losses are assigned to individual generators on a marginal loss basis, i.e. the losses incurred on the generator’s marginal 5MW of generation.

TLAFs may result in values for certain generators being greater than unity because output could have the effect of reducing, rather than increasing, transmission losses. Most TLAFs, however, have values of less than one. Generators take into account losses when trading by using the applicable loss factor(s) to determine tradable quantities available.

The key principles with respect to the treatment of losses as laid out by the Commission28 and ESBNG29 are:

o the costs of transmission and distribution losses are borne by

market participants who cause them, and not by the system as a whole; and

o all settlement is assumed to take place at the interface between the

transmission and distribution systems to ensure that all quantities are calculated on a consistent basis.

26 Losses arise due to heat generated in lines or cables as electricity is transported between the

generation user point and the point of demand. 27 TLAFs are defined as ‘a factor derived for the purpose of apportioning responsibility for

transmission losses amongst users of the transmission system which is used to adjust metered quantities during energy market settlement’ as in the Statement of Charges.

28 See http://history.cer.ie/cer0002.pdf 29 See Review of Transmission Loss Adjustment Factors, ESBNG, 16 April 2003.

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The following parties are subject to transmission losses:

o all generators connected to the transmission system; and o distribution connected generators, connected after 19/02/2000.

TLAFs are calculated for each generator on both a time of day (Day/Night) and seasonal basis (5 Seasons) and are published ex-ante. They are calculated by the TSO and approved by the Commission on an annual basis.

The Settlement System Administrator (SSA) uses the TLAFs assigned by ESBNG for each generating unit for the purposes of settlement of trade imbalances. The SSA uses the loss factors to adjust all generator dispatch instructions, metered outputs, and ex-post unconstrained schedule quantities to the trading point.

3.8 Impact of MAE on Current Structure

3.8.1 Margadh Aibhléise na héireann/Market Arrangements for Electricity (MAE)

Statutory Instrument (SI) 304 of 2003 sets out Regulations for the purpose of establishing a new system of trading in electricity.

MAE is a centralised wholesale electricity market. All electricity generated and consumed is cleared through this spot market. Generators must sell all their electricity to the market and all electricity consumed is purchased by suppliers participating directly from the spot market.

Electricity is bought and sold through the spot market under a market clearing mechanism. The market clearing price is the same for all sellers (generators) at the same location in the transmission system in each trading period. Buyers (suppliers) from the market pay a uniform wholesale spot market price irrespective of their demand location.30 The System Market Operator (SMO) settles all trading in the spot market.

Generators offer their output to the SMO. Generators are responsible for their own generator unit commitment and will develop offering strategies that are aimed at achieving desired levels of operation and profitability. There will be no side payments for unit start-up and shut-down and no separate capacity payments

30 The total delivered electricity cost to final consumers would include a number of cost items in

addition to the wholesale electricity spot price. These costs include market costs, transmission charges, distribution charges, PSO levies, contractual obligations, retailer mark-up, etc.

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The supply of operating reserves will be co-optimised with the energy market to

ensure that energy and reserves are dispatched in unison and to achieve an optimal allocation of both simultaneously.31

3.8.2 Wholesale Market Membership and Participation

Participation in the market involves both a membership obligation and a technical obligation. There will be three major classes of participant:

• Generators • Suppliers • Ancillary service providers.

There will be technical obligations on participants as set out in the MAE Rules or the Grid, Distribution, Metering or any other Code as appropriate.

3.8.3 Dispatch and Pricing

The market is solved simultaneously with dispatch. Dispatch is determined by considering all the system constraints: losses, transmission congestion, system security and reserves. Consequently prices will also take these factors into account. This method prices dispatch according to the technical, physical, and economic structure of the system. This approach helps ensure that market dispatch is physically feasible.32 Thus, prices can vary by location as a result of losses and congestion in the network. This leads to separate Locational Marginal Prices (LMPs) rather than a single market clearing price. Prices will be determined for each node.

Prices in the MAE will be based upon the marginal price of supplying additional electricity at each location33 - although in the case of suppliers, they will not face the pure marginal price directly.

In the MAE market:

• generators will be paid the locational marginal price at their respective injection nodes;

• suppliers will be charged at the uniform wholesale spot market price calculated as the demand-weighted average of the locational marginal prices at the withdrawal nodes in the network.

31 Regulation 3(10) and 3(11) of S.I. 304 of 2003 32 While the SMO must make every effort to ensure the market solution is technically feasible, on

some occasions the SMO may need to use reserves or other ancillary services to ensure system security.

33 This is the cheapest price offered by the next increment of generation - based on the offers received by the SMO - for supplying the increment of demand.

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3.8.4 The Impact of MAE on Transmission Tariffs

The MAE will be a centralised pool with constrained dispatch. This means that parties will not be paid constraint payments if they are not dispatched as it will be up to the generators in question to offer such that they are dispatched. This shall mean that constraint payments which are paid under the current market rules will no longer be paid and will no longer form part of the revenue requirement for recovery. This may impact upon the transmission tariff arrangements and structure.

The MAE is proposing that reserves be paid for under a ‘causer-pays’ principle. It is proposed that the reserve market cover all forms of operating reserve, primary (including interruptible load), secondary and all forms of tertiary. This would suggest that operating reserves may no longer be an element of TuoS.

Similarly losses will be built into the LMP prices, which would indicate that the TLAF (discussed in Section 3.6) will no longer be required.

The market and/or system operation expenditure may or may not continue to be recovered through TUoS. It could, for example, be recovered in some manner through the market. This issue may be considered under the MAE process and will interact with the consideration of the transmission tariff structure. 3.8.4.1 Financial Transmission Rights

In addition, the MAE will contain FTRs. Depending on how these are allocated there could be a receipt from auction revenues which could be delivered to the final customer via the TuoS, or these monies could be channelled through the market in some manner to be determined by the MAE Rules.

If this comes about it will effect the revenue requirement and could potentially affect the tariff structure. 3.8.4.2 Demand Side Management Measures

The new market will deliver short run price signals to the final customer. Price transparency will improve demand side participation and response, be it in the energy or reserve market or via supplier tariffs. This raises the question whether DSM measures should be pursued via TuoS and whether these should be included in the structure.

The Commission welcomes comment on how the MAE may impact upon the transmission tariff arrangements, and in particular how it may impact upon the structure of the transmission tariff arrangements.

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4 Distribution Charging 4.1 Introduction ESB Networks is the monopoly Distribution System Operator and charges supply companies and distribution connected generators (embedded generators) for the use of the system. The distribution tariff currently accounts for 35% of the average total end user tariff. The structure of the distribution tariff thus has a significant effect on suppliers, consumers and embedded generators. This section sets out the present policy and principles used by ESB Networks to set charges for connection to and use of the distribution system and invites comments on whether the existing policy and structure of tariffs:

• adequately reflect costs of connecting to the distribution network; • provide signals for efficient use of the system; • provide signals for efficient investment in the system; • are appropriate in view of the recent changes in and requirements

of the electricity market.

The conventional method applied by network utilities to recover their costs is through both connection charges from first time connections and use of system charges from all network customers. The Distribution System Operator in the Republic of Ireland uses this method for demand customers. Generator users of the distribution system pay connection charges, an annual Operations & Maintenance charge with respect to their export capacity plus a DUoS charge based on the Maximum Import Capacity. The present Distribution charging regime is designed to recover the cost of owning, operating and maintaining their respective networks. This document will look at both the connection charging policy and the use of system policy. Altering the amount to be recovered through the connection charges would justifiably have a corresponding reverse effect on the use of system charges (and vice-versa).

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4.2 Distribution Connection Policy

4.2.1 Definition of Connection Assets

Connection charges are intended to recover 50% of the cost of Connection Assets. These consist of:

• Dedicated Connection Assets, • Reinforcement Assets, and • Shared Network assets

Any single customer’s connection charges are based primarily on a customer’s Dedicated Connection Asset. A Dedicated Connection Asset is defined as ‘electrical network (lines, cables, switchgear etc.) used to connect a single user to the transmission or distribution system. The connection asset is specific to the user and does not form part of the connection to any other user’. A customer may also be required to pay upfront some of cost of the shared network impacted or required by the new connection. Shared Network is defined as parts of the distribution network where more than on customer is connected. Over the last number of years there has been a move towards strict adherence to the 50% policy. However, at present less that 50% of the actual cost is recovered through the Connection Charges. This issue will need to be addressed within the review.

4.2.2 Connection Charging: Present Principles & Future Objectives

ESB Distribution currently applies a set of principles when setting connection charges34:

• Equality in Treatment This is required under their licence and is based on the principle that customers with similar capacity requirements should bear similar charges subject to considerations of economic efficiency.

• Economic Efficiency Connection charges should transparently favor customer decisions that make the best use of resources. E.g. least cost principle; cost reflectivity.

34 These are listed in ESB Networks’ document “ charges for connection to the distribution system”

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• Simplicity A set of standard charges for various customer categories connected to the distribution system has clear advantages: faster quotations for customers; easier for customers to understand, reduces administrative overheads and reduces auditing overheads. Future objectives of a connection charging structure maybe expanded on to include the following:

• Equality of Treatment/Non-discrimination

Ensure a level playing field for defined customer categories, which is currently achieved through standard charging.

• Economic Efficiency

Dynamic Efficiency Connection charges provide signal for appropriate connections at appropriate locations. If the charge is not cost reflective, customers’ connection behavior may be altered e.g. rural customers should pay their proportion of cost of connection.

Increase Allocative Efficiency

Connection charges should, as far as possible, reflect actual cost of providing connections. For example, the greater the distance from the connection, the higher the cost to the DSO. This cost may not be reflected entirely in the connection charges.

Encourage Technical Efficiency

DSO should be incentivised to reduce cost of connections. This may be dealt with via the price review. Alternatively this could be achieved somehow via connection charging policy.

• Financial Sufficiency

Maintain, as far as desirable, the financial integrity of the Distribution System Operator. As the DSO’s revenue is approved on a 5-yearly basis revenue forecasting is key to this process. Revenue is forecast on the basis of projected earnings from both Distribution Use of System Charges as well as receipts from Connection charging policies. A portion of this revenue is based therefore on predicted customer connections and the charges they pay.

• Simplicity, Stability & Transparency

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Connection charges should be easily administered, relatively stable though

flexible and transparent to all customers.

• Environment & Security of Supply

Encourage CHP & embedded generation in addition to allowing a level-playing field for demand side management. The question of whether connection charging should be passive i.e. seek to reflect incremental or average costs, or whether it should be active i.e. should seek to encourage desirable behavior such as embedded or CHP generation/wind farm connections shall be considered.

4.2.3 Levying Connection Charges Connection assets are, broadly speaking, assets that provide a specific customer access to the system. Costs of connection are recovered via connection charges and Distribution Use of System (DUoS) charges – any costs of connection not collected through connection charges assessed to the specific customer are collected from customers in general through these DUoS charges. The proportion of costs of connection charged to a connecting customer depends on connection policy. This, in effect, determines the ‘boundary’ between connection assets and UoS assets for charging purposes. Possible approaches include:

• Deep Connection Policy: Charging for attributable35 cost of connection

• Shallow Connection Policy: Charging less than attributable cost of connection, i.e., no reinforcement costs.

o Semi-Shallow: Combination of Deep & Shallow charging policy

4.2.4 Connection Charging Calculation Typical steps in establishing the charges for all customers are set below:

• Establish the least cost technically acceptable (LCTA) connection method for each circumstance covered by the charge. The LCTA is the most economic technical solution which provides for the required connection asset the applicant customer and the future system requirements.

35 Attributable Cost is the marginal cost of connecting a new customer including network

reinforcement costs.

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• For each of this set of valid connection methods, determine the cost

of the dedicated connection, deduct the 50% investment allowance and add the charge for reinforcement costs as applicable to determine the standard charge for that connection method.

For the purpose of formulating standard charges, the following steps are taken:

• Determine the proportion of actual connections accounted for by each of the set of valid connection methods in the previous 12 months: i.e. the weighting factors.

• Calculate the standard charge as a weighted average of the charges for the set of valid connection methods.

In most domestic connections the standard charge is the only charge that will apply. In cases where the length of the new overhead line to be built to a single house is greater than 1 km, 100% of the costs of the line beyond 1 km is charged, in addition to the standard charge. In most business connections the standard charge and the shared network cost will apply. For some specific connections standard charges do not apply. Charges for situations outside the scope of the standard charges are calculated on a case-by-case basis but using the same general principles, e.g., 50% of the cost of connection must be paid up-front36. See section (Current Charging) for a further explanation on how standard charges are calculated for specific customer types. 4.2.5 Customer Cost Assignment As stated above, the present connection policy requires new customers connecting to the distribution network to pay a once-off connection charge. The proportion of the connection cost recovered in the connection charge depends on whether the customer is a ‘demand customer’ or a ‘generator customer’37. The DSO currently allocates connection costs on the following basis:

• Type of Customer: Demand (MIC greater than MEC) or Embedded Generator (MEC greater than MIC).

36 Examples of this cases, such as business parks, will be explained in section 4.3 37 ESB Networks has published a document “Charges for Connection to the Distribution system”.

The document sets out the principles and policy applied, to set charges for connecting to the Distribution System and sets out the methodology applied for calculating standard charges for connections. The document is available on the Commission’s website www.cer.ie.

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• ‘Demand Customer’ Type and Size: Separate charges apply to demand customers based on nature of connecting party (e.g.

farm, domestic, business etc.) and size (impact on distribution system).

Demand Generator

Connection Charge 100% Deep

Connection Charge 50% Semi-Shallow

4.2.5.1 Demand Customers Demand customers are defined as customers with a Maximum Import Capacity (MIC) greater than their Maximum Export Capacity (MEC). Of course most demand customers do not have autogeneration and, as a result, have zero MEC. Demand customers are charged:

a) 50 % of the cost of the dedicated connection asset;

b) A charge per kVA for reinforcement of the existing system, when the connection capacity is above 500 kVA. For business customers at low voltage, this charge includes 50% of the cost of the customer’s share of the capacity of the MV to LV transformer.

For customers with MIC of 500 kVA or over, this charge in general includes 25% of the average reinforcement costs.38

c) The balance is recovered via DUoS revenue.

The connection policy relies on a system of standard charges designed to achieve the objective of simplicity. The standard charges are calculated so as to recover cost items (a) and (b) outlined above.

8 The reinforcement costs are collected over a period and 25% of these are apportioned.

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4.2.5.2 Generator Customers ‘Generator customers’ are defined as embedded generators and autoproducers producing for essentially their own use and with a maximum export capacity greater than the maximum import capacity39. Generator customers do not pay DUoS charges on exported energy. Specifically, exporting autoproducers and exporting CHP producers pay neither a standing DUoS charge or capacity charges4041.

Generators are charged:

• 100% of the cost of the connection asset; • 100% of the actual cost of reinforcement (This will be zero if there

is no reinforcement);

• Generator Distribution O&M Charges to cover ongoing O&M on the connection asset and facilities added for reinforcement.

These O&M, or ‘service’, charges are to cover the operation and maintenance costs of the connection assets.

4.2.6 Cost Allocation: Deep, Shallow & Semi-shallow Charging As described above, Distribution asset costs are recovered via DUoS charges or via connection charges. Therefore, the narrower the definition of connection charges, i.e., the less assets classified as connection assets, the higher system charges must be, i.e., the more assets classified as System Assets.

39 The Autoproducer direction of October 2003 (http://www.cer.ie/cerdocs/cer03237.pdf) defines

an Autoproducer as a person who has entered into a Connection Agreement with the DSO (or TSO) and generates and consumes electricity in a Single Premises, or on whose behalf another person generates electricity in the Single Premises, essentially for the first person’s own consumption in that Single Premises. Autoproducers and CHP Producers with a Maximum Import Capacity (MIC) greater than or equal to their Maximum Export Capacity (MEC) will be deemed to be using the networks predominantly to import electricity and will be referred to, for convenience, as “Importing Autoproducers” and “Importing CHP Producers” respectively. Autoproducers and CHP Producers with an MEC greater than their MIC will be deemed to be using the networks predominantly to export electricity and will be referred to, for convenience, as “Exporting Autoproducers” and “Exporting CHP Producers”, respectively.

40 Maximum demand autoproducers with MEC>MIC don not pay Maximum Demand capacity charges.

41 They do however pay DUoS imported energy unit rates as well as low power factor surcharges.

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ESB DSO currently administers a semi-shallow connection charging policy for Demand Customers and a deep connection charging policy for generator Customers. 4.2.6.1 Shallow and Deep Assets The distinction between shallow and deep assets is important as it also reflects the distinction the DSO makes on connection and use of system assets and hence the costs that would be recovered from each tariff. Examination of this is important to ensure that due to definitions of such assets, connection charges do not subsidise use of system charges or vice versa, as this would also indicate the presence of subsidisation either within certain customer categories or between categories. The two connection policies may broadly be defined as follows:

• Deep Connection Charging • Shallow Connection Charging

4.2.6.2 Deep Connection Charging A Deep Connection Charging policy allocates more of the cost of connection to the connecting demand or generator customer, including local connection costs plus network reinforcements. Therefore, the connecting customer pays more of the cost up-front and pays less on an on-going basis. In other words, the greater the required reinforcements, the higher the connection charge. Historically, a 100% deep connection policy for domestic and demand customers was not favoured, so as to encourage customers to connect to the distribution system and ease the magnitude of the customer’s financial commitment that would be required by such a decision.

4.2.6.3 Shallow Connection Charging Under a shallow connection policy, customers are required to pay only for the local assets that are required specifically to connect the customer to the distribution system42 and for the benefit of the user. The cost of reinforcing the network beyond the connection asset is recovered through the use of system charge.

42 The connection charge is based on the new equipment or asset that has to be installed to connect

the users to the Distribution System. It is the network between the customer’s premises and the point of connection to the shared network. The cost of the connection asset includes the cost of installing:

• equipment to the terminal station; • cables and lines • metering equipment

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There are various degrees to which the shallow connection policy can be applied:

• Shallow policy includes: all substation assets such as

transformers, switchgear and busbars and exclude all overhead lines or cables and spurs between the customer and the main system.

• Semi-shallow policy includes: the connection asset required for the

customers connection including the reinforcements required at the point of connection and more general reinforcements that may be required at higher voltage levels. The portion and level at which reinforcement cost are included in the connection charges is again a subject of the tariff structure review.

4.3 Existing Connection Charging Methodology Connection charges are applied to differing customers in a number of ways. 4.3.1 ‘Demand Customer’ Charging 4.3.1.1 Domestic Customers Domestic/Farm Customers pay connection charges based on:

Standard charges only except where connections are longer than 500m from the existing network. For example: • 1km >length of connection > 500m = 50% of the connection cost is

charged. • Length of connection > 1km = 100% of the cost beyond 1km + 50%

of the first km is charged.

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Domestic/Farm customers are charged standard charges according to

status as:

• Single Homes/Housing Schemes: • Standard 12 kVA connection to a home within 500 metres of

existing MV or LV network (50 metres where LV line is underground);

• Enhanced 16 kVA connection to home within 500 metres • 17kVA – 29 kVA connection • Farm Buildings: 3kVA – 11 kVA • Housing Schemes: Defined as development of 4 houses or more.

Same as with single homes except each connection charge is based on a cost per home adjusted for length of road frontage per house in the estate.

• Apartments: Landlord + No of apartments. Same as with single homes except includes landlord.

• Other: Standard charges are calculated on a case-by-case basis on same principles.

4.3.1.2 Business Customers Business customers pay connection costs based on:

• Standard charges The schedule of these standard charges vary according to different required MIC levels:

1. MIC – 2kVA to 5000kVA; 2. MIC – 5MVA to 15MVA; 3. MIC – 15MVA to 20MVA; 4. LV Connections > 500kVA; 5. MV Connections > 15MVA; 6. MV Connection > 500kVA more than 7km from station; 7. Supplementary charge where 38kVv MIC is greater than

2500kVA and connected to circuits longer than 18km

• Shared networks charges43. In addition to standard charges, business customers requiring new MV network pay per-metre standard charges.

43 In rare cases, costs arise relating to the site which are not provided for in the standard

connection costs. These are passed on directly to the customer and are known as Exceptional Costs ex. site excavation costs significantly above average cost.

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The categorisation of business customers, for the purpose of connection charging includes:

• Any commercial/industrial customer; • All customers above and including 30kVA.

Table: Comparison of Standard Charge Composition for Domestic & Business Customer

Domestic/Farm Business

Dedicated Connection

Asset

50% 50%

Transformer Cost

(MV/LV)

(Cost per kVA of MIC)

None except where:

50% cost New MV line

(500m<x<1km)

100% cost New MV line

(x>1km)

50%

Reinforcement Cost

(MIC greater than 500

kVA)

(Cost per kVA of MIC)

None: All domestics less

than 30 kVA

25%

4.3.1.3 Temporary Connections Customers Temporary Connections pay 100% of the non-recoverable costs. This includes the cost of connection and the dismantling costs less the credit for the re-usable materials. 4.3.1.4 Business Parks In the case of Business Parks a new 110kV or 38kV network substation will be built in the development and new medium voltage network from this substation will be used to provide electrical connections to customers in the development. Electrical connections to customers in the development are provided under the standard connection charges policy.

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The Developer bears all costs over and above the least cost, technically acceptable, solution as determined by ESB Networks using its Planning Guidelines. The Developer is required to take out two separate bonds to cover the financial risk to ESB Networks during the design and construction period of the project. One or other of these bonds may be cashed by ESB Networks in the event of the Park not developing as planned. 4.3.1.5 Other Elements of Current Charging Methodology In addition to standard charges, the DSO connection charge includes the following elements:

• Refunds with respect to shared network under predefined situations;

• Increase/Decrease in MIC Charges; • Other Charges (Long/Remote Network)

Refunds Refunds on New Network As explained above, business and temporary connection customers may pay additional charges for new network, above and beyond standard charges. In those cases where additional charges are not covered by a standard charge and the asset is used within 5 years either to connect another user or for a system improvement, the DSO makes a refund44 to the original user(s). The amount of the refund is based on the relative capacities of the users. This amount is included in the connection charge of the new user. In the case of a system improvement (i.e. where investment in the system is incurred but is unrelated to a new connection) the cost is borne by ESB.

Permanent connections =MIC2*CC*/(MIC1+MIC2) Temporary connections =MIC2*CC*period/((MIC1+MIC2)*term) where: MIC1 = maximum import capacity in kVA of existing connection. MIC2 = MIC of new connection CC = the capital contribution originally charged in respect of the shared asset excluding any standard charge.

44 Refunds are not made on the basis of standard charges as standard charges already include a

refund element. For instance, when a customer is connected, the resulting connection assets required will cater for to a line and that if a new line or an existing line needs to be reinforced.

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Period = The expected time the connection will be used (years) or 40, whichever is the shorter Term = term of connection agreement for original connection or 40, whichever is the shorter. Charges for Changes to Connection Agreement Increase in Connection Capacity (MIC Increase) Where a customer requires an increase in MIC, the standard charge for the proposed capacity less the corresponding charge for the existing capacity is applied. Where new MV or 38kV network is required, the corresponding standard charge is also applied. Decrease in Connection Capacity (MIC Decrease) Customers wishing to reduce their MIC must pay the portion of the connection costs that will no longer be recovered through the use of system charges as a result of the reduction in the MIC. The charge is calculated as the standard charge of the existing capacity less the standard charge for the corresponding reduced capacity. Very Long and Remote Locations A supplementary charge is applied to very long existing network:

• MV customers with a MIC in excess if 500kVA and located greater than 7km from a station, incur standard supplementary charges.

• 38kV customers, with an MIC in excess of 2500kVA and connected to circuits longer than 18km, also incur standard supplementary charges.

4.3.2 ‘Generator Customer’ Charging Distribution-connected generation – ‘embedded’ or ‘autoproducer’ – connecting to the distribution system pay the full cost of deep connection assets, including any reinforcement cost required for their connection45. An annual operation and maintenance (O&M) charge is also applied. Where an existing customer has an agreed MIC and installs generation capacity such that it changes status from a ‘demand customer’ to a ‘generator customer’ (MEC greater than its MIC). that customer is charged for its connection based on its MEC in addition to the portion of the cost of connection that has not already been recovered via the use of system charges, less any previous connection charges relating to its MIC.

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Standard charges do not apply to generator customers as connection costs are calculated on a case-by-case basis. However the DSO publishes indicative costs based on:

• Size of Connection: o 38 kV o MV

• Substation Cost (€’000) • Cable (€’000 per km) • O/H Line (€’000 per km)

Reinforcement costs are calculated on a case-by-case basis dependent on local network configuration.

4.4 Distribution Use of System (DUoS) Charges 4.4.1 Cost Allocation The Distribution Use of System Charge is the tool that collects the allowable revenue, net of connection charge revenue, each year. For tariff charging purposes, the distribution system is divided into four voltage levels, the 110kV; 38kV; MV and LV levels. This is necessary as customers are connected to one of these levels but may not use all of them. Each level comprises the network at the level’s voltage and the transformation substations that supply it from the next higher voltage level.

The process of converting revenue requirement into distribution tariffs involves the following steps:

• Costs are broken down into capital costs and operating costs.

The costs are then categorised based on whether or not they are customer or demand related costs.

• Customer related costs are associated with providing an

electricity supply to customers; these costs are incurred irrespective of the customer’s demand for electricity e.g. meters, services, MV metering substations and 38kV customers stations

• Customer related costs are allocated on a customer number

basis. The costs are first allocated across the various system levels to arrive at a cost per system level and are then multiplied by the various customer numbers in that particular customer category.

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• Demand related costs are associated with the provision of capacity for use by all ESB’s customer, at the different Distribution networks levels e.g. MV Three phase & Single phase network, 38kV network, 110kV network, all MV/LV substations, 38kV network stations, 110kV stations and 220kV station equipment.

• Approximately 80% of Distribution costs are demand related and

20% are customer related.

• Demand related costs are associated with a particular consumption of the customer at each system level. Costs are allocated on the basis of several measures of customer category demands.

• Operating Costs excluding indirect overheads are associated with

distribution assets

• Costs associated with services and meters are directly attributed to the appropriate customer category.

• Some of the costs associated with the distribution entities are

shared by a number of customer categories; these costs are apportioned by allocation factors based on consumption levels derived from load profiles or on customer numbers depending on the nature of the cost.

• When both Capital and Operating & Maintenance costs are

allocated, the costs are aggregated so that a total cost can be attributed to each customer category.

• A reconciliation factor is applied to all apportioned costs to

account for the indirect overheads.

Once a cost is derived for each class of cost a target price is derived by using customer numbers and consumption data. 4.5 Existing Structure of DUoS Tariff

At present the Distribution tariff has various structural elements, which are outlined further on, in this section. The exact details of the tariff can be accessed through a link given in the Appendix.

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4.5.1 Customer Categories

Currently the Distribution Use of System tariffs are split by type of customer and voltage level. As part of the structure review the Commission will be considering various types of categories that could be introduced.

The current categories that are in existence are as follows.

1. Urban Domestic (DG1) 2. Rural Domestic (DG2) 3. Public Lighting (DG3) 4. Low Voltage Non-Domestic Customers (non Maximum Demand)

(DG5) 5. Low Voltage Autoproducers MEC>MIC (non Maximum Demand)

(DG 5a) 6. Low Voltage Non-Domestic Customers (Maximum Demand)

(DG6) 7. Low Voltage Autoproducers MEC>MIC (Maximum

Demand)(DG6a) 8. Medium Voltage Customers (Maximum Demand) (DG7) 9. Medium Voltage Autoproducers MEC>MIC (Maximum Demand)

(DG7a) 10. 38 kV Looped Customers (Maximum Demand) (DG8) 11. 38kV Looped Autoproducers MEC>MIC (Maximum Demand)

(DG8a) 12. 38 kV Tailed Customers (Maximum Demand) (DG9) 13. 38kV Tailed Autoproducers MEC>MIC (Maximum Demand)

(DG9a)

4.5.2 Structural Elements The structural elements of a tariff relate to the number of components in the tariff structure, whether block tariffs exist, whether it is a flat charge or a metered charge or whether there is time or seasonal differentiation. In a cost-based tariff the structure mirrors the structure of the costs to be recovered. At present the distribution tariff has the following structural elements.

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4.5.2.1 Number of Components Currently the Distribution tariff has the following components, which vary according to the customer category: Fixed Charge per month Energy Charge per kWh consumed Capacity Charge per kVA of MIC Maximum Import Capacity Penalty Power Factor Penalty KVArh

Fixed Charges serve to recover customer related costs that do not vary with usage or size of customer, such as metering. In the distribution tariff the fixed element can be seen through the standing charge which recover those costs associated with metering. Again the standing charge varies per customer category according to the associated costs. Energy charges recover costs that vary with energy delivered over the distribution network. Currently in the distribution charging regime energy /per KWh charges are applied either on a 24hour basis or on a day/night basis for all customers. The review will examine the various options open and their impacts on achieving the objectives outlined.

Capacity charges are also evident within the distribution structure. The customer is charged according to his/her metered kVA of MIC per month. These are charged to DG6 categories upwards. A customer’s Maximum Import Capacity (MIC) is the contracted maximum electrical capacity of the connection point agreed between ESB as Distribution System Operator and the customer. This measure is used to calculate the capacity charges mentioned above. In addition to a capacity charge a surcharge is applied when the customer exceeds its contracted MIC. The purpose of the surcharge is to discourage users of the distribution system from exceeding their MIC, which has considerable safety implications. The low power factor surcharge is a penalty for the amount of reactive power that is consumed. Reactive power can also be defined as “Wattless” energy

One purpose of this review will be to see if the current DUoS structure is sufficient to achieve the objectives outlined above.

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5 Supply Tariff Charging 5.1 Current Cost Basis The total cost of electricity comprises the cost of generating the electricity, transmitting it through the grid, distributing it through the network, and supplying this energy to end customers. The total cost of electricity, for the industry, can be divided approximately as follows: Generation – 53% Fuel is a large component of the generation cost, with plant capital and operating costs accounting for the remainder. Transmission – 7% This is the cost all Suppliers pay the Transmission business to transport electricity from the generating station through the transmission grid to the distribution system, or to the customer’s site for the small number of customers connected to the transmission system. The charge is called the Transmission Use of System (TUoS) tariff, which is regulated. Distribution – 35% This is the cost all Suppliers pay ESB Distribution to transport electricity from the transmission grid through the distribution system to the customer site. The charge is called the Distribution Use of System (DUoS) tariff and is regulated by the Commission. Supply – 5% Supply costs represent a small percentage of the final cost of electricity. These costs include the cost of procuring energy, administration costs and customer accounting and service costs. Licensed independent suppliers consider end-user tariffs reflecting both upstream costs described above and the Supplier’s own costs plus the following factors. When developing competitive tariffs for eligible customers:

• Quantity of electricity consumed (units of electricity measured in KWh)

• Customer’s capacity requirement- it’s Maximum Import Capacity (MIC) in the connection agreement, measured in kVA.

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• Maximum demand – the maximum capacity used in a defined period measured in MW.

• The time of day (or night) the electricity is consumed. • Service required, such as energy management • Public Service Obligation (PSO) Levy, which supports peat and

renewable generation in Ireland. This levy is paid by all electricity customers, i.e. ESB customers and customers of licensed independent suppliers.

Other costs There are also other costs, which are currently recovered through the ESB Supply tariff.

Emergency Generation The cost of emergency generation is included in this years allowed cost recovery in tariffs (2004),

Peaking Capacity Currently the annual increase in peak demand for electricity in the Republic of Ireland is running at about 4%. The continued growth in demand has necessitated ESB procuring some peaking generator units (104 MW) and contracting with NIE Power Procurement business for 167 MW of generation to provide the necessary capacity in advance of new generators coming online. A share of these costs has been included in determining the PES tariffs. Capacity Margin Experience to date would suggest that the capacity margin, administered through Taos has had only a modest impact in achieving its objective. A number of additional measures have now been taken with the aim of ensuring that supply meets demand in the short and medium term. As a result the payments have been capped in 2004. The Public Service Obligation (PSO) The PSO levy relates to the purchase by ESB of the output of certain peat generated electricity, in the interests of security of supply, and the output of certain generating stations using renewable, sustainable or alternative forms of energy under the Alternative Energy Requirement (AER) schemes, in the interests of environmental protection, in accordance with the PSO Order (S.I. No 217 of 2000). The PSO charge is levied on all customers of electricity, regardless of supplier, and appears as separate items on customer’s bills.

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5.2 Cost Allocation ESB Supply takes the set of costs outlined above and uses their allocation methods to apportion the allowed costs they have to recover from the customer categories. However, the Commission will also be considering other methods of allocating costs across customers. Each tariff should reflect the costs for that group of customers, as seen by the supply business.

The current version of ESB’s Costing and Pricing Model calculates and allocates projected total accounting cost to 12 tariff classes. The cost categories contributing to ESB revenue requirements include those mentioned earlier. The cost allocations developed within this pricing model rely on aggregate profiles of loads and generation shares that aim to track the characteristics of customers in the various tariff categories. The cost allocation model allocates costs to the 12 tariff categories. To allocate the average costs developed in the model to the more than 20 individual tariffs46 and to justify specific tariff structures requires further assumptions and calculations. ESB Supply takes these steps in a tariff construction model, which aims to calculate the true cost of supplying a customer. Each tariff calculation is divided into three sections: Cost Elements, Conversion Cost into Charge, and Tariff. These “tariffs” calculated are a starting point for the work of actually setting the tariffs each year. The final model is the calculation of the proposed set of tariffs. This model incorporates existing and proposed charges for all retail tariffs and matches them with the corresponding billing determinants to establish a complete set of charges that produce the supply revenue goal. 5.3 Existing Structure of Supply Tariff The exact details of the tariff are depicted in the appendices. 5.3.1 Supply Customer Categories Currently the Irish Electricity tariffs are split by type of customer and voltage level. As part of the structure review the Commission will be considering various types of categories that could be introduced.

46 Including group accounts, night space heating, and rural business premises rates.

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The current categories that are in existence are as follows.

• Urban Domestic (Standard, Night Saver, Night Storage) • Urban Domestic Group Account (Standard, Night Saver) • Rural Domestic (Standard, Night Saver) • Rural Domestic Group Account (Standard, Night Saver) • Residential Business Premises (Standard, Night Saver) • Commercial and Industrial General Purpose (Standard, Night-

saver, Night Storage) • Commercial and Industrial MD (Low Voltage) • Max Demand (Medium Voltage) • Max Demand (38kV) • Maximum Demand (110kV) – Transmission and Distribution • Public Lighting

5.3.2 Structural Elements As stated earlier the structural elements of a tariff relate to the number of components, block tariffs, whether it is flat charge or metered charge and whether there is time or seasonal differentiation. 5.3.2.1 Number of Components Currently the PES tariffs have the following components, which vary according to the customer category: Fixed Charges Energy Charges Metered Demand Charges Capacity Charges Power Factor Penalties MIC Penalties Many of theses elements have already been explained within the distribution section and are passed through onto the customer by the supply business through a different, although similar, structure of charges. In addition, the ESB Supply earns a margin, the cost to supply a customer, which it builds into its tariffs. The supply element of the fixed cost serves to recover customer related costs that do not vary with usage or size of customer, such as customer accounting expenses, customer information and services expenses. This is recovered through a Standing Charge.

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Energy charges should cover all energy related costs faced by the supply business. Again the Commission will be reviewing these charges and will act to examine the various options open and their impacts on achieving the objectives outlined. Metered Demand Charges, which are not explicitly evident within the distribution structure, are a traditional way to recover capacity costs. Currently this is a charge based on the maximum demand measured in one hour, whereas the responsibility for capacity costs may lie in many hours. Time differentiating demand charges requires meters, which are capable of recording peak demand in several periods. Capacity charges are also evident within the current supply structure as are the associated penalties, which have been explained earlier.

5.3.2.2 Seasonal and Time Differentiation Seasonal differentiation can be shown within the supply tariff, where there is a winter/summer split for some consumer categories. This element of the tariff acts as an agent to signal differentiation and allocation of costs. Further time differentiation is included in some tariffs, where energy charges are on a night and day basis. Such diurnal differentiation can be extended to additional pricing periods and even to real time pricing. Real time pricing involves complex metering and communication systems and may be more cost effective for larger consumers. Time differentiation can range from tariffs that change only seasonally to real-time pricing.

5.3.2.3 Block Tariffs Block tariffs are used in the supply structure and act almost like a bulk buying incentive. In the supply tariff at present, customers are charged a lower per unit charge when they consume more than a certain threshold, which varies per customer category.

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6 Conclusion Under the Electricity Regulation Act, 1999 (ERA), the Commission is charged with approving the form and basis of charges to be applied for the connection to and use of the transmission and distribution system. Regulation 31 of Statutory Instrument No. 445 of 2000 also requires the Commission for Energy Regulation (CER) to approve arrangements that allow ESB to meet the demand of customers that are not supplied by other suppliers in the market (in the first instance from ESB’s existing generation) for the period to 19th February 2005. The Commission is now undertaking a review of the

• Transmission Use of System Charges (TUoS) and Connection Policy • Distribution Use of System Charges (DUoS) and Connection Policy • Public Electricity Supply (PES) tariffs charged to final consumers

This paper is the first step in the process of this review and it specifically aims to set out the existing structure of Transmission, Distribution and Supply tariffs, and associated connection polices, that are currently in place. This paper aims to prompt response from all industry participants including consumers and representative bodies. The next stage of this review will give rise to an information paper briefly outlining what structures are in existence in other countries. This note will also included a constraints paper which will indicate any limitations, in terms of metering or market arrangements, that will affect any alternative structures for consideration.

In conclusion, the review of the present tariff structures is the first opportunity for the Commission to ensure that the tariffs, going forward, will achieve the objectives outlined in section 2.1 above. The Commission will consult throughout this review and will give interested parties every chance to input into the decision making process.

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Appendices Transmission Statement of Charges: http://www.cer.ie/cerdocs/cer03241.pdf

Distribution Statement of Charges:

http://www.cer.ie/cerdocs/cer03224.pdf

Supply Statement of Charges: http://www.cer.ie/cerdocs/cer03248.pdf

Syst

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Syst

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Fast

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ind-

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e

GTS

-T &

GTS

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lost

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00)^

2 x

rate

of 1

.154

7]

GTS

-T &

GTS

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of 0

.157

73]

Transmission Revenue Requirement (220m)

Network Costs (Wire Costs) (61.25m) Non-Network Costs (Non-wire Costs) (158.75m)

Generation Demand Generation Demand Demand

Dem

and

Syst

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Serv

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Cha

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Gen

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Loca

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-B

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(a

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1

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rgy

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is

(600

/MW

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DTS

-T, D

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1 an

d D

TS-D

2

E

nerg

y B

asis

(2

.099

6/M

Whr

)

DTS

-T, D

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1 an

d D

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2

E

nerg

y B

asis

(2

.511

6/M

Whr

)

GTS

-T a

nd G

TS-D

Cap

acit

y B

asis

(per

MW

of

ME

C)

DTS

-T a

nd D

TS-D

1

Cap

acit

y B

asis

(131

7.69

67/M

W f

or

DTS

-T,

1174

.673

9/M

W f

or

DTS

-D1)

DTS

-D2

Ene

rgyB

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(4

.363

4/M

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dur

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Day

hou

rs)

DTS

-T, D

TS-D

1 an

d D

TS-D

2

E

nerg

y B

asis

(1

.962

6/M

Whr

)

28 % in 2003 72 % in 2003

25% 75%

60% 40%

approx. 100%

Capacity Margin Charge