DISTRIBUTION NETWORK CONNECTION: CHARGING

DISTRIBUTION NETWORK CONNECTION: CHARGINGPRINCIPLES AND OPTIONS

First Published 2002 © Crown copyright

Report Number: K/EL/00283/REP DTI/Pub URN 02/1147

ContractorIlex Energy Consulting

Prepared byPeter Williams

Stephen Andrews

The work described i n this report was carried out under con tract as part of the DTI Sustainable Ener gy Programmes. The views and judgements expressed in this report are those of the contractor and do not necessarily reflect those of the DTI.

DISTRIBUTION NETWORK CONNECTION: CHARGING PRINCIPLES ANDOPTIONS

Copyright © 2002 ILEX Energy Consulting Limited

All rights reserved

No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means electronic, mechanical, photocopying, recording or

otherwise without the prior written permission of ILEX.

Disclaimer

While ILEX considers that the information and opinions given in this work are sound, all parties must rely upon their own skill and judgement when making use of it. ILEX does not make any representation or warranty, expressed or implied, as to the accuracy or completeness of the information contained in this report and assumes no responsibility for the accuracy or completeness of such information. ILEX will not assume any liability to anyone for any loss or damage arising out of the provision of this report.


TABLE OF CONTENTS

INTRODUCTION I

1. BACKGROUND TO THE EXISTING ARRANGEMENTS FORDISTRIBUTION CHARGING 1

2. PRESENT DNO PRACTICE FOR COSTING AND PRICING OFDISTRIBUTION SERVICES 13

3. INDIVIDUAL DNO APPROACH TO DUOS CHARGING 27

4. DISTRIBUTION SYSTEM CHARGING OPTIONS FOR EMBEDDEDGENERATION 37

5. EVALUATION OF CONNECTION CHARGING OPTIONS 53

6. TECHNICAL ISSUES ASSOCIATED WITH THE CONNECTION OFEMBEDDED GENERATION 65

7. POTENTIAL APPROACH TO A NEW ‘UNIVERSAL’ PRICINGREGIME 79

8. CONCLUSION 95

ANNEX A: CONSULTATION WITH SELECTED DISTRIBUTIONNETWORK OPERATORS - PROMPT QUESTIONS 99

ANNEX B: ILEX DUOS CHARGING ANALYSIS 100


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INTRODUCTION

This is the final report on the work undertaken by ILEX, on the ‘Charging Principles and Options’ project1 which was commissioned by the DTI as part of the New and Renewable Energy Programme.

This work covers the tasks of the project as described in the original proposal and subsequently formalised under contract between ILEX and the Energy Technology Support Unit (ETSU)2.

Background

Re-structuring of the electricity industry in the UK in 1989 led to the creation of Regional Electricity Companies (REC) who were responsible for the distribution and supply of electricity to local customers. Under their Public Electricity Supply (PES) licences, these regional companies were required to promote competition in energy retail (supply) and to publish charges for third party access to the distribution system.

Over recent years the distinction between the distribution and supply functions of the Public Electricity Suppliers (PESs) became more pronounced with PESs having to internally separate their supply and distribution businesses and to carefully monitor and control the flows of information between businesses. The Utilities Act 2000 formalised this split by issuing separate licences for both the ‘wires’ business (distribution) and the energy retail business (supply).

The 2000 Act, and the 1989 Act before it, establishes the business of public electricity distribution as a licensed activity. There are twelve licence distribution areas in England and Wales - each having a separate distribution licence3.

Recent Government targets for renewable and CHP generation4 will have a material impact on the distribution businesses since most of this small generation

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‘DistributionNetwork Connection: Charging Principles and Options’.

Agreement/contract ref. K/EL/00283/00/00. ETSU is now known as Future Energy Solutions.

Although, over recent years, there has been some merger and acquisition activity in the distribution business sector, the number of licensed distribution areas has remained unchanged since privatisation with some companies holding more than one distribution licence. Each licensee is required to operate its distribution system in accordance with its individual licence - based on the ‘Electricity Distribution Licence: Standard Conditions’ - as published by the Department of Trade and Industry (DTI) under the Utilities Act 2000.

Government targets are for 10% of electricity supplied to be from renewable sources and for an increase in installed CHP generation to 10GW - both by 2010.

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capacity will be embedded in local distribution networks. Whilst reform of local planning regulations and improvements to the treatment of small generation within the New Electricity Trading Arrangements (NETA) may go some way to assist in Government meeting its targets, it is widely acknowledged that successful technical and commercial integration of embedded generation into distribution networks must be achieved if the 2010 targets are to be met.

In the light of this, and following on from the work carried out by the Embedded Generation Working Group, the DTI, through ETSU, has commissioned a number of projects associated with the connection of embedded generation through its New and Renewable Energy Programme.

The application of charging principles associated with the connection of embedded generation to distribution networks can be a major factor in the commercial viability of small embedded generation schemes. This project examines the principles adopted by the Distribution Network Operators (DNOs) in setting charges for use of, and connection to, the distribution system. It will necessarily include an examination of the treatment of demand connections and how this compares and contrasts with arrangements for the connection of embedded generation. The work focuses on the electricity distribution businesses of England and Wales.

After critically examining a number of alternative charging options, the work tests three options using cost and technical information obtained from a selection of real embedded generation connection schemes.

The work goes on to explore how a new Distribution Use of System (DUoS) charging framework might be developed to accommodate embedded generation. This would have to compliment any to change to the connection charging methodology. Typical distribution system costs, and other network characteristics, are used to illustrate the revised charging framework through use of a simple system model.

Final report content

Section 1 of this report reviews the background to the existing arrangements for charging for use of the distribution system. It reviews the statutory and licence obligations on the DNOs which are relevant to connection and also considers the commercial relationships between the main participants. It also includes a review of the main sources of DNO income which are associated with the licensed distribution activity.

Section 2 examines the charging principles adopted by the DNOs and compares and contrasts the commercial arrangements applied to demand connections with those for embedded generation. The economic rationale behind the various policies is also examined. This section includes a detailed look at the mechanism and principles associated the Distribution Reinforcement Model (DRM).

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Section 3 describes the DUoS charging methodology employed by the three DNOs we consulted as part of the project work. This focuses on the differences in the use of the DRM and also looks at an alternative approach adopted by one of the DNOs.

Section 4 explores a number of alternative charging principles which could be adopted for connecting embedded generations to distribution systems. The work recently carried out by the DTI/Ofgem5 Embedded Generation Working Group (EGWG) on charging principles6 is reviewed and the various options are examined in terms of their principles and structure.

Section 5 uses the three broad charging options selected in section 4 as the basis for a study of how the charging arrangements might work in practice. The commercial implications for both embedded generators and the DNOs are examined using real project cost information and scheme designs.

Section 6 explores the ways in which the distribution system might have to change - both commercially and technically - if the numbers of embedded generators are to increase to the levels targeted by Government. The work then looks at how the existing DUoS framework could be changed to commercially accommodate the connection of embedded generation.

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The Office of Gas and Electricity Markets.

Department of Trade and Industry (DTI), Embedded Generation Working Group report - Annex 4 ‘Charging Principles’, January 2001.

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1. BACKGROUND TO THE EXISTING ARRANGEMENTSFOR DISTRIBUTION CHARGING

1.1 The section begins with a review of the charging obligations placed on DNOs courtesy of the conditions of the licence under which they operate. It reviews the statutory and licence obligations on the DNOs which are relevant to connection and also considers the commercial and contractual relationships between the main participants. It includes a review of the DNO revenue streams and how they are determined.

DNO obligations with respect to charging

1.2 As a regulated monopoly service provider, the DNOs operate within a framework of statutory rights and obligations which are relevant to charging for connection and use of the distribution system. Many of the these obligations are enshrined within the standard distribution licence conditions. Both of these are outlined and discussed in this section of the report.

Statutory requirements

1.3 The DNOs, and previously the Public Electricity Suppliers (PESs), own, operate, maintain and repair the electricity distribution networks in England and Wales. Being monopoly businesses, these activities are licensed and regulated by Ofgem.

1.4 The new Utilities Act 2000 (“the 2000 Act”) required the complete separation of the previously combined distribution and supply activities of the Public Electricity Suppliers (PESs) and introduced separate licences for the distribution and for the supply of electricity. It amends the existing Electricity Act 1989 (“the 1989 Act”) and continues to place a number of important statutory obligations on the DNOs.

General duty

1.5 There is a general duty placed on the distribution licensees to ‘...develop and maintain an efficient, co-ordinated and economical system of electricity supply’7. In addition, there are a number of specific obligations which are relevant to charging principles. These are listed below.8

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The Utilities Act 2000, Section 50(1)(a).

A more detailed review of the existing statutory and licence obligations on DNOs has been undertaken by ILEX as part of a separate project under the DTI’s New and Renewable Energy Programme - ‘Embedded Generation Connection Incentives for Distribution Network Operators’ (Agreement/contract ref. K/EL/00286/00/00).

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Recovery of expenditure

1.6 The 2000 Act gives DNOs the power to recover from the customer all costs reasonably incurred in providing the connection assets9. This provision existed in the old 1989 Act - although this right was associated with providing the customer with a supply and did not, therefore, seem to specifically provide for the costs associated with connection of a generator. The new Act goes some way to address this by referring to connection costs.

The power to require security

1.7 The 2000 Act enables the DNO to insist upon security for payment of all moneys owed for both delivery of energy (distribution use of system (DUoS) charges) and for connection10. Although this makes no specific reference to the connection of embedded generation, there is nothing to suggest that this entitlement should differentiate between demand and generation connectees.

Licences for public electricity distribution

1.8 The Distribution Network Operators (DNOs), and, previously, the Public Electricity Suppliers (PESs) are obliged, by licence, to offer terms and conditions for customers to connect to their distribution networks. This obligation applies equally to connections for both embedded generation and demand.

1.9 The distribution licence sets out the way in which the DNO businesses should operate and is the vehicle by which many of the statutory obligations contained in the 2000 Act are discharged. The licences are issued and controlled by Ofgem.

1.10 The licences contain a number of important requirements associated with charging for connection and for use of the distribution system.

Licence Condition 4

1.11 Condition 4 of the standard distribution licence conditions11 deals with DNO charges for connection to, and use of, the distribution system. It includes several important requirements associated with connection costs. The licence conditions most relevant to this work on connection and charging principles are set out below.

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The Utilities Act 2000, Section 46.

ibid. Section 47.

Electricity Distribution Licence: Standard Conditions, Section B, Condition 4 - ‘Basis of Charges for Use of System and Connection to System: Requirements for Transparency’. Note that this used to be provided for in Condition 8 of the old Public Electricity Supply (PES) licences.

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Condition 4 charging statements

1.12 One of the main obligations set out in licence Condition 4 is the requirement for licensees (DNOs) to prepare, and make readily available, details associated with charging for connection and for use of the system. This is commonly known as the ‘Condition 4 statement’.

1.13 The information which the DNOs are obliged to publish under this licence condition is twofold:

• a statement setting out the basis upon which charges will be made for connections to the licensee’s distribution system; and

• a statement setting out the basis upon which charges will be made for use of the licensees distribution system.

1.14 DNOs must prepare both statements in a form which is approved by Ofgem12 although only the use of system charging statement is required to be formally submitted to Ofgem on an annual basis13. Most DNOs review their charges in April each year and so this submission to Ofgem usually takes place in February or March each year for implementation the following April.

1.15 Although there is no need to formally submit the connection charging statement, the licence does require DNOs to review the contents of the statement - checking for accuracy and validity - on an annual basis14.

1.16 The standard licence condition15 requires the DNO use of system statement to include:

• charges for the distribution of electricity under use of system;

• a schedule of distribution loss adjustment factors16;

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The licence condition requires that approval be obtained from the ‘Authority’. This is the Gas and Electricity Markets Authority (GEMA) by whom Ofgem is governed. The powers of the Authority are provided under the Gas Act 1986, the Electricity Act 1989 and, most recently, the Utilities Act 2000. The Authority determines strategy and decides on major policy and is Chaired by Callum McCarthy. For all intents and purposes, in this context, the ‘Authority’ is synonymous with Ofgem.

Each distribution licensee is required to submit the ‘use of system’ statement to Ofgem for approval 40 days ahead of the period for which the charges contained within the statement are to apply.

Electricity Distribution Standard Licence Condition 4, Part 7(a)

ibid. Part 2.

DNOs set and publish loss factor multipliers which are then applied to metered exit point volumes in order to determine the total volume which licensed suppliers must purchase at the Grid Supply Point (GSP) group level. This is done in order to provide for electrical

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• details of the method used, and principles adopted, for setting charges for the availability of the distribution system; and

• a schedule of charges in respect of accounting and administrative services.

1.17 The same licence condition requires the DNO connection charging statement to include:

• a schedule listing the items of significant cost, together with their indicative costs, which are likely to be needed for connection to the licensees distribution system and for which connection costs may be levied;

• the method and principles on which charges will be made for any reinforcement (or extension) of the system which may be deemed a necessary part of providing the connection;

• the method adopted where, at the DNO’s discretion, the assets installed are of a size greater than is required for use of the system by the person seeking the new connection17;

• the basis of any charges for maintenance, repair and replacement of electric lines or plant provided and installed as part of making the connection; and

• the method and principles associated with charges for disconnection from the licensees distribution system and the subsequent removal of any plant or equipment.

1.18 Condition 4 goes on to state18 that DNOs should set connection charges to recover:

• the appropriate proportion of the costs directly, or indirectly, incurred in carrying out all necessary works (including provision, installation, maintenance, repair, replacement or disconnection of old assets); and

• a reasonable rate of return on the capital associated with such costs.

DNO response to a request for connection

1.19 Condition 4 also prescribes the time within which the DNO must respond to a customer in providing details of how the prospective connectees requirements

losses incurred in physically transporting energy through the distribution system to end users.

Distribution system assets are manufactured in discrete sizes and network investment does not usually, therefore, cause system capacity to increase in a continuous manner but more in a ‘lumpy’ manner. The allocation, and recovery, of any additional costs arising through the provision of lines, cables and switchgear, which are over and above the need to the new connectee, is an important issue on which the DNO’s policy needs to be made clear.

Electricity Distribution Standard Licence Condition 4, Part 4.

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might be accommodated. The DNO must respond within 28 days from the time of receiving:

• a request from the customer for connection to the network; or

• payment, where the DNO deems it necessary to charge for carrying out the estimation work19.

1.20 Where schemes are particularly complicated or likely to take an extended amount of time for other reasons, the DNO can make a request to Ofgem that the 28 day standard be relaxed.

1.21 With the 28 day period, the DNO is required to provide the prospective connectee with a statement20 showing information, for relevant parts of the network, on:

• past and future circuit capacities;

• loading on parts of the network specified in the customer request;

• forecast power flows; and

• fault levels for each distribution node covered by the request.

1.22 The licence requirements goes on to include the provision of “such further information as shall be reasonably necessary to enable such a person to identify and evaluate the opportunities available when connecting to and making use of the part or parts of the licensee’s distribution system specified in the request”21.

1.23 The DNO is also required, if so requested, to provide a commentary indicating its views as to the suitability of the parts of the distribution system in question with regard to new connections and additional load22.

1.24 The DNO is permitted, with the prior consent of Ofgem, to omit or remove from any statements it provides, information whose disclosure, in the view of Ofgem, would “seriously or prejudicially” affect the commercial interests of the DNO or any third party. The DNO can also omit any information which may place the licensee in breach of its licence obligation with regard to the restriction on the use of certain information within the distribution business23. This might be, for

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The licence allows DNOs to make a charge for estimation and design work associated with more complex connection applications. DNOs must identify such schemes within 10days of receiving the connection application from the customer (Electricity Distribution Standard Licence Condition 4, Part 11).

Electricity Distribution Standard Licence Condition 4, Part 5.

ibid. Part 5(a).

ibid. Part 5(b).

Electricity Distribution Standard Licence Condition 39, ‘Restriction on Use of Certain Information and independence of the Distribution Business’. This condition places constraints on the disclosure of, and access to, confidential information.

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example, names and commercial details associated with other parties who are considering connecting to the same part of the network.

1.25 The rights and obligations described in Condition 4 of the new distribution licences are important in that they prescribe the minimum standards to which the DNO must adhere in respect of dealing with applications for connection. It should be noted, however, that this sets out the process by which the DNO must abide and does not address the policies and methodologies adopted by the DNOs in establish the arriving at charges for network connection and for use of the distribution system.

Industry structure and commercial arrangements

1.26 At privatisation, the industry was disaggregated into a number of individual businesses carrying out one or more of the newly defined industry functions. The idea was to introduce competition - where competition was deemed possible, and to regulate - where competition was not considered practicable.

1.27 The privatised industry model drew a distinction between a number of separately licensed functions:

• generation (transmission connected);

• transmission;

• distribution; and

• supply (energy retail).

1.28 Generation and supply were deemed to have the potential to develop into competitive business functions, whilst ownership and operation of the transmission and distribution networks were recognised as being monopoly services whose activities and business revenue would require independent and centrally administered regulation.

1.29 The ownership and operation of the distribution wires networks and the buying and selling of electrical energy (energy retail) became the responsibility of the Regional Electricity Companies (REC) operating under a Public Electricity Supply (PES) licence.

1.30 Since October 2001, the functions of supply and distribution have been separately licensed activities. The commercial relationships and financial interactions between licensed suppliers, the DNOs and the end customers - be they demand connectees or embedded generators - are important when considering connection and use of system pricing issues.

1.31 Before the economic impact on various participants, of the different distribution pricing methodologies, can be explored, it is therefore important to appreciate the contractual relationship between the relevant parties involved. In particular, how the DNOs receive their income, needs to be fully understood.

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1.32 The commercial relationships between the three principal industry participants, at the distribution system level, are described by a set of three bi-lateral contracts. The three parties are:

• the energy retailers (suppliers);

• the DNOs (distributors); and

• the end users (customers).

1.33 Figure 1 below shows this ‘triangle’ of agreements.

Figure 1 - Contractual relationships between participants

CUSTOMER

7VSupply

AgreementConnectionAgreement

SUPPLIER Use of System Agreement

DISTRIBUTOR

1.34 The supply agreement is between the customer and the licensed supplier and formalises the terms upon which energy will be bought and sold between the two parties.

1.35 A use of system agreement is in place between each DNO and all licensed suppliers having customers within the DNOs licensed distribution area. It sets out the conditions of, and provisions for, use of the distribution system by licensed suppliers. End customers are not party to the use of system agreement - although the commercial terms under which a customer’s energy supplier has access to the local distribution network, will be of indirect interest to the end user.

1.36 The connection agreement is between the end customer and the local DNO to whose distribution network the customer is connected. The principle purpose of the connection agreement is to formalise the terms and conditions of connection. The connection agreement is for connection to the system only and provides neither for the supply of electricity not for use of the distribution system. A typical connection agreement might include details of:

• maximum available capacity;

- this is the contractual maximum power demand available from the connection and is usually expressed in kVA or MV A;

• limits of financial liability;

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• details of metering equipment24;

• responsibilities for housing of, and access to, connection equipment and metering. (e.g. substation access); and

• other technical issues:

- constraints for disturbing loads25;- power factor limits;- balancing of phase loads;- the consequences of faults and fault switching;- arrangements for planned outages; and- quality of supply issues.

Distribution business revenues

1.37 In order to examine connection charging principles it is also necessary to appreciate how the various charges and payments flow between the key participants.

1.38 The licensed distribution businesses have two principal sources of income associate with the DNO activity;

• charges for use of the distribution system; and

• charges for connection to the distribution system.

1.39 The charge levels associated with these two revenue streams form the two main parts of the Condition 4 statement described in paragraph 1.12 (onward) above. For all DNOs, charges for use of the distribution system represent the vast majority of the business income26.

1.40 Charges for use of the distribution network are levied on the licensed suppliers in accordance with the terms of the relevant use of system agreement between the supplier and the DNO in question. These are usually known as Distribution Use of System (DUoS) charges.

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The metering equipment detailed in the connection agreement may be limited to those items which are owned by the DNO such as metering current and voltage transformers.

Some electrical equipment, when connected to the distribution system, can cause electrical disturbance and distortion which can effect the technical quality of the power received by existing network customers. Electric welding equipment, large motors and power electronic equipment are all examples of such equipment.

The exact ratio of use of system income and connection income for a given DNO will depend upon the connection charge policy but it would not be unusual for connection revenues from connectees to represent less than 10% of the use of system revenue collected from licensed suppliers.

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1.41 Suppliers will usually recover this transportation cost by passing it through to the end customer. For larger customers the DUoS element may be disaggregated and passed through directly, whilst for smaller, domestic, customers the supplier may absorb the distribution charge element into the retail tariff.

1.42 The business of making the physical connection to the network is the responsibility of the DNO27 and the charges for carrying out this work are levied by the DNO directly to the connectee. The supplier is not usually directly involved with payment and arrangements associated with providing the connection.

1.43 Figure 2 below shows the flow of payments between the three participants - in particular, how the two revenues for connection and use of system flow to the distributor.

Figure 2 - Distribution business cashflows

CUSTOMER

(connection)(use of system)

SupplyAgreement

ConnectionAgreement

Use of System Agreement

DISTRIBUTORSUPPLIER

(use of system)


1.44 Since they principally operate as a monopoly service provider, the serviceperformance and business revenue associated with the DNO’s licensed business is regulated. Although the business structure and regulatory treatment of the DNOs

Part of the works associated with making a connection to the DNO network is now competitive under 'competition in connection' rules and can be carried out by independent accredited contractors appointed by the developer. Only the part of the connection work deemed to be non-contestable must be carried out by the local DNO or its agents.

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is beyond the scope this project28, it is necessary to set in context the way in which the DNOs are remunerated for their activities before the allocation of costs to users, via pricing mechanisms, can be properly considered.

How are DNO regulated revenues determined?

1.45 The Regulator, after consultation with each of the distribution businesses, sets the maximum revenue which the DNOs are allowed to recover from customers. This, so called ‘price control’ is set, and usually runs for, a period of five years29. This allowed revenue is based upon the regulator’s view of:

• the amount of money needed to run the distribution business (operational expenditure - Opex);

• the amount of money needed to invest in the distribution network in order to maintain required service levels and to comply with environmental and safety requirements etc. (capital expenditure - Capex);

• the worth of the existing network assets (the so-called Regulatory Asset Base, or RAB, value); and

• the financial rate of return which ought to be allowed on any existing and new investment - taking into account risks and expectations of the financial markets (the cost of capital).

Additional revenue drivers

1.46 Once the regulator has arrived at the permitted levels of capex and opex, the revenues which the DNO can earn is described in terms of the maximum average charge per unit (kWh) distributed. The allowed revenue expression includes a number of ‘tariff baskets’ in recognition of a number of individual customer groups.

1.47 In addition, the price control formula provides for a variation in the total allowed revenue in accordance with changes to:

• network losses; and

• the number of units distributed through the network.

1.48 A reduction in network losses results in additional revenue calculated in accordance with the extent to which actual system losses fall short of the allowed

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‘Embedded Generation Connection Incentives for Distribution Network Operators’ (Project No.4), also undertaken by ILEX as part of the DTI’s New and Renewable Energy Programme, looks more closely at DNO business structure and regulatory treatment of the distribution activity. ETSU contract ref. K/EL/00286/00/00.

The 1995 distribution price control review was followed by another review in 1996. This was at the behest of the then Director General of Electricity Supply (Offer) following the emergence of additional information associated with merger and acquisition activity in the sector.

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losses - calculated on a ten year rolling average basis. In addition, DNOs are allowed to retain approximately half30 of any additional revenue earned as a result of increasing unit distributed.

1.49 In simple terms, the annual allowed revenue is determined by the sum of thecapital return on the regulated asset base (appropriately adjusted for depreciation and investment) plus an amount to run the business. The basic process is shown pictorially in Figure 3.

Figure 3 - Derivation of allowed regulatory DNO revenue

THE REGULATORY ASSET BASE

% RETURN (f)INVESTMENT

DEPRECIATION

ALLOWEDREVENUE


The additional revenue is based on 50% of the tariff basket unit rates as prescribed in each DNO s licence. Since these are all-inclusive rates (i.e. include fixed elements), and, in most cases, are unlikely to match the DNOs own tariff structure, it is only possible to say that the amount that the DNO can retain is approximately half of the amount actually received as a result of distributing the additional kWh.

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1.50 It is this revenue allowance, based on what the regulator believes to be sufficient to own and operate the business, which determines how much the DNOs are permitted to charge the licensed suppliers for use of the distribution system.

1.51 It is the attribution and allocation of this allowed income, and the principles adopted for so doing, which constitutes a pricing strategy. To date, the DNOs have been reasonably free to determine how charges are levied for use of system and connection. However, with the introduction of increasing numbers of embedded generation and with the prospect of distribution networks having to be more actively managed, the methodology for costing and charging principles is attracting more regulatory attention.

1.52 The next section reviews the methodology which underlies of most of the present charging mechanisms used by the DNOs in setting charges for use of the distribution system.

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2. PRESENT DNO PRACTICE FOR COSTING AND PRICINGOF DISTRIBUTION SERVICES

2.1 Before any new commercial arrangements or charging polices can be proposed, it is important to fully understand current policy and practice and the economic and commercial rationale underpinning established methodologies. This section reviews the existing charging arrangements adopted by the distribution businesses in England and Wales and provides an opportunity to consider the extent to which these charging frameworks might successfully accommodate embedded generation.

2.2 The work focuses on the charging principles adopted by the DNOs and explores the economic basis and commercial rationale of the various charging frameworks. This is principally based on a Distribution Reinforcement Model (DRM). This section looks at the purpose and function of the DRM in some detail before going on to examine some related issues specific to embedded generation.

2.3 As part of our research for this work we undertook telephone interviews with three DNOs. In choosing which DNOs to consult we were keen to try to capture the range of charging approaches currently in force within the distribution businesses. Interest in the work and a willingness to participate were also important considerations in the decision of which DNOs to involve.

2.4 A series of questions were sent to each of the DNOs ahead of our discussions.This provided the basis of the telephone interviews and also acted as an aid memoir during discussion. Annex A gives details of the prompt questions upon which the conference calls were based.

2.5 The individual polices and practice which were highlighted during the conference calls, is described in section 4.

The Distribution Reinforcement Model (DRM)

2.6 This section provides a brief description of the DRM, focusing on the principles, objectives and high level function of the model.

Background and history

2.7 The concept of providing a network service, as distinct from providing energy, and identifying the costs of such a service was introduced in the Energy Act 1983. All the then Electricity Boards were required to establish separate charges for ‘use of the distribution system’. With the 132kV system transferring from the old CEGB31 to the Area Electricity Boards, many of the smaller, transmission

31 The Central Electricity Generating Board (CEGB)

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connected, generation sets were soon to find that they were now connected to part of the local distribution network.

2.8 In 1984, the Electricity Council32 developed a methodology for the formulation of tariffs for ‘use of the distribution system33. This approach, advocated the use of a representative model of the network for establishing use of system tariffs, known as the distribution reinforcement model (DRM).

2.9 Since its introduction the DRM has provided the foundation for distribution tariff setting for all DNOs in England and Wales. The DNOs, and previously the PESs, have, however, modified the model content over the years in order to accommodate changes in policy and local practice and to try to ensure that the representation remains accurate and relevant.

2.10 The DRM is a hypothetical, independent network, but designed as an extension to the existing network. The model is designed to be capable of supplying electricity to an additional 500MW34 of diversified demand35 at each of the voltage levels represented in the model. The DRM assumes a ‘green field’ site. The model is, essentially, a large spreadsheet.

2.11 In modelling terms, whilst the DRM does not fully simulate the actual network, it aims to simulate a scaled down version. Since the model calculates marginal costs, the 500MW figure has no particular significance other than to be large enough to have significant impact at all voltage levels in the model network, but small enough not to dilute the benefit of using a scale model.

2.12 The DRM aims to model the cost providing a distribution network service and does not model the physical electrical capability of technical performance of the network. The model uses simple, static, load information and equipment ratings to determine electrical capability based on established network design.

2.13 The DRM is populated with network asset information - using the standard equipment36 sizes which would be used for any new network construction. Since the DRM aims to emulate the actual distribution network, the network design

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Prior to privatisation, the Electricity Council acted as the national guardian and patron of the Electricity Supply Industry (ESI).

The Electricity Council, ‘Tariff Formulation Manual’, 1984.

The DRM is sometimes referred to as the ‘500MW model’.35

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Diversified demand takes into account the fact that individual loads on the system will have their maximum demands occurring at different times. This means that the maximum demand occurring at higher levels in the distribution system will be less that the simple sum of the individual maximum demands.

Transformers and switchgear of standard specification and rating and cables and lines of standard material and sizes.

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principles37 and general topological definition within the DRM usually follows the same standard and practice as is adopted for real network schemes. This includes established planning38 and operational standards.

2.14 The DRM has two principle functions:

• calculation of the costs of providing a distribution network service; and

• allocation of those costs to appropriate customers and classes of customer.

2.15 The latter of these two functions is dependent on the former - costs must be determined before they can be attributed to users. These two functions, together with a description of the DRM inputs and outputs, are given below.

DRM inputs

2.16 All costs are based on present day, functional, replacement values and include:

• design costs;

• transportation of equipment and plant to site;

• construction; and

• testing and commissioning

2.17 Given that the DRM is populated with present day equipment costs, it is sometimes described as a ‘modern equivalent asset’ model39.

2.18 All system costs are calculated according to the power demand40 at each voltage level. Where there is a need to translate demand related costs (e.g. £/kVA) into energy related charges (e.g. p/kWh), for domestic charges, for example, then this is done using annual average load factors for each customer group41.

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39

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The model is populated with typical power factors, utilisation factors, diversity factors and coincidence factors - as per the behaviour of the actual distribution system.

For example, the network planning security standard given by Engineering Recommendation P2/5, ‘Recommended Standards of Security of Supply, October 1978 impacts directly on the design of the distribution network and this design philosophy is replicated in the DRM.

Modern equivalent asset (MEA) indexation is one of the approaches used by NGC for the calculation of charges levied on DNOs for connection to the transmission network (ref. NGC ‘Statement of the Connection Charging Methodology - effective from 1 October 2001, Chapter 2). This approach, and its suitability to distribution network connections, will be explored further in the final report.

Power demand in kilo-volt-ampere (kVA or MVA), as opposed to energy utilisation in kilo-watt hour (kWh or MWh).

Most DNOs have, for many years, obtained this information from the Electricity Association as part of its load research programme.

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Review of input costs

2.19 If the yardstick DUoS price outputs are to reasonably represent the real costs associated with providing the distribution network service then the input costs must be periodically reviewed.

2.20 Some of the costs inputs are associated with high volume, relatively low cost, items of equipment - assets associated with routine connection works such as service cable, schedule rate cable laying costs and standard items of switchgear. These costs often relate to network equipment at the lower voltage levels and may be procured en-mass through the DNOs central purchasing systems.

2.21 Network assets at the higher voltages42 tend to be more specialist in nature and are usually more expensive - not only due to their larger power ratings but also due to their complexity and enhanced technical specification. These items of equipment are produced in much lower volumes and are often procured on a bespoke basis. Since the prices associated with these asset types are often derived from tender prices they can sometimes exhibit significant volatility43. Typical, or representative, price these items are often more difficult to obtain.

2.22 The high volume costs tend to be much more stable and predictable. For low volume costs, the DNOs attempt to identify medium to long-term price trends and try to avoid any short-term transient prices.

DRM outputs

2.23 The DRM calculates a complete set of annuitised tariff rates for each tariff and for each customer group. The outputs are often referred to as ‘yardstick’ tariff outputs with £/kVA/month and p/kWh yardsticks being produced for 132kV, EHV, HV and LV demand connections. The output yardstick rates represent the long run marginal costs of providing the distribution service.

Cost calculation

2.24 The DRM is capable of supplying 500MW at each of the main voltage levels contained within the model. The base model is somewhat simplified in that it employs only four distribution voltage levels, these being:

• low voltage (LV);

• high voltage (HV);

42

43

For example, assets at primary and grid voltages such as 33kV and 132kV.

One-off tender prices will represent the vendor’s commercial bid for supplying the particular item. This price may vary depending upon the time of the order, the competition, other work etc. Procuring a large power transformer (e.g. 132/11kV) is an example on when this might occur.

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• extra-high voltage (EHV44); and

• 132kV.

2.25 The DRM calculates the costs of providing the distribution network at each of the four voltage levels. This is calculated from the sum of the individual items of equipment - lines, cables, transformers and switchgear - required to provide supplies. This results in a total cost for an increase in demand of 500MW - at each voltage level within the model.

2.26 Two total demand figure are calculated at each voltage level:

• simultaneous maximum demand (SMD); and

• aggregate maximum demand (AMD)

2.27 The SMD accounts for load diversity by recognising that the maximum demand of individual loads on the network occurs at different times. The result being that the maximum demand at a higher, system, level will usually be less than the sum of the individual load maximum demands. The SMD is often used to determine the contribution which an individual load make to costs at the higher ‘system’ levels.

2.28 The AMD is simply the sum of the individual demands and does not account for diversity. It effectively assumes that all individual demands occur at the same time. The AMD is usually used to determine the contribution which an individual demand makes to the costs of providing the distribution assets ‘local’ to the point of connection where diversity is unlikely to have significant effect in reducing the equipment ratings.

Capital costs and annuities

2.29 Costs must firstly be calculated. The DRM calculates costs on a long-run margin costs (LRMC45) basis. This forward-looking incremental cost methodology is well established as the basis for calculating the costs of providing capital intensive services - such as electricity distribution46.

44

45

46

Principally 33kV in most DNO networks.

By definition, LRMC are ‘the costs arising from an increase in output where the capacity of the plant, and not just its degree of utilisation, is assumed to adjust’. This is distinct from short run marginal costs (SRMC) which cover the costs arising from an increase in the degree of utilisation of existing plant only. In distribution network terms, LRMC include the cost of capital investment whilst SRMC do not. An example of SRMC is the increase in the cost of copper losses (I2R) resulting directly from an increase in demand. LRMC would, for example, include the cost of having to increase the physical capacity of a line (by replacing it, for example) in order to accommodate increased demand.

Use of long run marginal cost principles for the costing and pricing of electricity networks was first advocated by the British Government in the 1960s.

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2.30 The base cost information within the DRM represents the total capital cost for each items of equipment - this includes the additional costs associated with operations, repair and maintenance47. DUoS tariffs are based on regular, ongoing, payments for use of the distribution system such that distribution costs are recovered over the deemed lifetime of the network assets48. This requires the total capital costs to be expressed in terms of regular annual, or monthly, payments. In order to carry our this process of annuitisation, two pieces of information are required49:

• the discount rate, or cost of capital, to be applied to the investment; and

• the number of years over which the investment is to be annuitised50.

2.31 The calculation generates an annuity factor. This is then used to covert the lifetime capital costs associated with elements of the model into a set of annualcosts51.

Cost allocation

2.32 Once the annuitised costs have been calculated, they are allocated to customer groups. At present, all of the distribution costs are allocated to demand customers.

2.33 The annuitised unit costs are usually allocated to customer groups in accordance with estimated contributions to peak power demand at each relevant level within the distribution system. Appropriate adjustments are made for the extent to which individual group maximum demands coincide with the system level maximum demands through the use of coincidence factors52. Further adjustments are made to account for network design practice and local network topology.

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48

49

50

51

52

Other ‘operational’ costs such as business overheads, are usually accounted for in a separate model, or separate part of the DRM. These are then allocated to the fixed, or ‘standing’ charge, part of the distribution tariffs.

Excluding any one-off capital payment for connection.

Some DNOs include in this calculation a factor called tilt which is included to adjust, principally, for technical obsolescence.

This is usually the nominal financial life attributed to the investment and represents the time over which the asset is deemed to fully depreciate. This is typically 40 years for many network assets.

Annuitised costs are usually given in £/kW/year and converted to £/kVA/year using appropriate power factors. As an illustration, at a capital discount rate of 6.5% and a notional investment lifetime of 40 years, a £100/kW lifetime cost would equate to £7.07/kW/year.

Coincidence factors describe the time relationship between any one, individual, demand and the total system level demand. A coincident factor of unity would suggest that a particular load’s maximum demand occurs at the same time as that on the system as a whole.

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Depreciation and asset replacement

2.34 Each of the individual items of network equipment which make up the distribution system will have a limited commercial life after which terms they will be deemed to have fully depreciated and will no longer generate a financial return. The commercial life attributed to distribution assets ought to align with the expected physical life associated with the item - although this does not always turn out tobe the case53.

2.35 Each of the DNO networks comprise a large number of assets of varying condition and age. Consequently, the asset replacement burden varies according to the average age profile of the network assets54.

2.36 The DRM calculates capital costs annuities over a fixed, notional, lifespan - typically 40 years. This means that the yardstick prices which emerge from the DRM include a provision for ongoing assets replacement. DUoS charges do not reduce as the assets age and charges are based on the average age of the network asset base. The result is that the present arrangements adopted by the majority of DNOs, means that continued payment of DUoS charges entitles network capacity to be made available to the connectee in perpetuity55.

2.37 The NGC approach to depreciation of connection assets differs from this. Connection charges are based on a relatively small number of high cost items which can be easily attributable to individual users. Under CUSC56 arrangements, these are itemised, together with their individual ages, and a return is only charged on the net asset value57. The result is that the charges paid by the DNOs to NGC for the transmission connection assets, reduce over time. The owner, NGC, effectively takes investment out of the system as the asset depreciates. The significant difference when compared to the DNO approach is that there is no ongoing asset replacement provision and user costs increase whenever the owner has to re-invest and replace time-expired assets.

53

54

55

56

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Network assets on both the distribution and transmission networks often remain in service beyond their originally intended life-span. This is the result, amongst other things, of the current regulatory regime which rewards capital efficiency and has given rise to the development and widespread use of techniques for monitoring the condition of network assets in an attempt to optimise asset replacement and maintenance costs.

The rapid growth of electricity use in the 1960s has resulted in a distribution asset age profile that reflects the high levels of investment made at that time.

To the extent of the available capacity agreed between the connectee and the DNO - as per the connection agreement.

NGC’s Connection and use of System Code (CUSC) which replaced the suit of bi-lateral agreements administered under the Master Connection and use of System Agreement (MCUSA).

The net asset value (NAV) is the depreciated value and represents the investment remaining in the assets at any given time.

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2.38 Depreciation allowance is an import issue for DNOs since it represents a significant proportion of the allowed revenue.

DUoS tariff formulation

2.39 The DRM calculates the lifetime costs of providing the distribution service whereas the allowed revenue is a result of periodic negotiations and consultation with the regulator. The regulatory allowed revenue will reflect short-term business requirements and so there will inevitably be some difference between the distribution revenue which would occur if the DRM yardstick outputs were used directly in DUoS tariffs compared with the total revenue allowed by the regulator.

2.40 It is usual, therefore, for these two figure to be reconciled using a simple scaling factor. The DUoS tariff rates are then set such that projected distribution revenues matches the price control revenue58.

2.41 The structure of DUoS charges is an important consideration. The way in which costs are calculated and charges levied can substantially affect the total cost faced by the connectee over the life of the connection. The mechanisms for costs recovery are likely to be the most challenging and important aspects of developing a charging framework which successfully accommodates embedded generation.

Non-domestic connections

2.42 Most DNOs continue to adopt the three-part tariff approach for industrial and commercial customers. This method is well established and comprises the following three elements:

• standing charge (£/customer);

• capacity charge (£/kVA59); and

• utilisation/unit charge (p/kWh).

2.43 The standing charge recovers all those costs which are not dependant upon the extent to which the facility is taken up. Business overheads and other fixed costs are recovered in this way.

2.44 The capacity charge aims to recover the costs of providing, owning and operating the distribution system at the local level. The costs associated with these local

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The difference between the ratio of fixed and variable elements in the allowed revenue formula - when compared to the tariff structures - mean that forecasting errors associated with power demand and energy volumes - will also give rise to discrepancies between actual and allowed revenues. This is accommodated through the use of a adjustment factor (k factor) in the regulatory formula which serves to subsequently adjust for any over or under recovery the following year.

Some DNOs chose to levy capacity charges based on £/kW with power factor often being managed through a separate charge element of the DUoS tariff.

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assets are mainly driven by the maximum power demand requirements and it is therefore considered appropriate to levy charges for these on a £/kVA or £/kW basis rather than according to energy volumes (e.g. p/kWh). Capacity charges are usually payable regardless of energy consumption.

2.45 The unit charge element is designed to recover the costs of providing the higher system level costs - right up to the grid supply point (GSP) assets. These costs are not recovered on a £/kVA charge basis since it is considered that the correlation between an individual connectees power demand and the costs of providing network assets at, possibly, two or three voltage levels above that of connection, is not strong enough to justify the use of capacity charges for the recovery of all network costs.

2.46 The boundary between those assets whose costs are recovered via capacity charges and those that are recovered via unit charges is defined in the DRM.

Domestic and small non-domestic connections

2.47 Although the DRM calculates the costs of providing a distribution service to domestic customers in exactly the same way as for non-domestic customers, the tariff structure is usually different.

2.48 The standing charge recovers the same costs as for the non-domestic customers, described above. The unit charge is levied to recover all of the cost of providing a distribution service which is dependent upon the extent to which the connection is taken up.

2.49 However, all domestic costs are calculated in the DRM in the same manner as for non-domestic customers and costs are then translated from £/kVA to p/kWh using standard customer group load factors.

Conclusions on the DRM

2.50 Since the yardstick outputs are scaled to fit the allowed regulatory revenues, the principal attribute of the DRM is its ability to allocate costs between customer groups on a fair, equitable and transparent basis in accordance with well established, and proven, long run marginal cost principles.

2.51 The DRM’s value is in its ability to apportion the marginal costs of distribution across users. Since outputs are scaled, it is the relativities between outputs, rather than their absolute values, to which most value is attached.

2.52 The DRM is still used by the majority of DNOs - although there are some differences between DNOs opinions on the importance of ensuring the information used by the model is populated remains current and relevant. Most DNOs make attempts to update the cost inputs on a regular basis - usually every year. It would seem from our discussions, however, that the underlying assumptions, design philosophy and asset types are reviewed for accuracy and relevance much less often.

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2.53 Some DNOs may never have reviewed some of these since privatisation. Coincident factors, diversity factors, load factors and power factors are also reviewed less frequently than prices - despite some of these having the potential to distort costs allocations more than changes to the price inputs.

2.54 The DRM does not consider embedded generation. This would seem not, however, to preclude its use in the development of a DUoS pricing framework which can properly accommodate the commercial and technical impact of embedded generation.

Charging for connection

2.55 As previously discussed, the DNOs have a licence obligation to make connections to the distribution system upon request and to recover from those being connected all reasonable costs for so doing. Although the principal source of DNO revenue is that associated with DUoS charging, connection charge revenue represents a significant amount of money for the DNOs.

2.56 Whenever a new connection is made to the distribution system, or when an existing connection is upgraded, costs are incurred in providing any new equipment or in enhancing the existing assets. These costs must be attributed to somebody - be it a group or an individual - in order that the costs can be recovered.

2.57 In essence, a new connection provides the connectee with access to an energy ‘transportation’ system - capable of delivering energy to the required location, at the required time and in accordance with the required technical parameters (e.g. power rating).

2.58 Provision of this transportation system may require use of a whole series of shared asset groups located beyond the customer’s service cable or line. Some of these individual assets may exist for the benefit of a large number of customers whilst others, such as those electrically nearest the connectee, may well only be used by a single user.

2.59 The extent to which assets are considered to be provided for individual connectees, or whether they are deemed to form a part of the general distribution system, will often dictate the way in which connection charges are derived. Connection charges refer to one-off charges which are paid by the connectee - as opposed to ongoing use of system charges which are currently paid by all demand customers and which are usually set at the same rates for all customers within a customer group.

2.60 The proportion of the costs associated with providing a new distribution network connection (or those associated with an upgrade to an existing connection) which are recovered through an initial, upfront, charge will have different effects on different parties. Since embedded generators are not charged directly for use of

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the distribution system, this debate on the classification of connection assets has, until recently, been confined to demand connectees.

2.61 However, the deliberation of where to ‘draw the line’ between connection assets and use of system assets is now an important consideration in the development of a pricing framework capable of representing embedded generation, and forms the basis of a number of alternative connection charging options which are described in section 3 of this report.

Tariff support (capital) allowances

2.62 There is, therefore, a close association between initial connection charges and the regular DUoS payment which demand customers are presently required to make. Some DNO’s DUoS charges provide for an average cost connection - with only greater than average costs being charged at the outset of the connection.

2.63 In order to prevent double-charging, a credit, or allowance, is given against the total cost of the works in recognition of the DUoS payments which the customer’s supplier will be required to make over the lifetime of the connection. This is known as tariff support allowance or capital credit and is still currently adopted by many DNOs as part of their charging policy and practice.

2.64 Costs which are not recovered through connection charges will become part of the regulatory asset base and will be recovered through DUoS charges under the price controlled conditions previously outlined. Connection charge revenue is not price regulated in this way60. The proportion of the costs associated with new and enhanced connection, which is recovered through upfront charges varies between DNOs - according to their individual capital allowance policies.

2.65 For demand connections, the Standard Distribution Licence conditions61 prescribe that no charge will normally be made for any reinforcement of the existing distribution system if the new, or increased, load requirement does not exceed 25% of the existing network capacity (at the relevant points on the system). Neither shall a charge be made for system reinforcement work carried out at more than one voltage level above the voltage of connection.

2.66 Historically, the charges for the connection of embedded generators have been applied on a ‘deep’ basis. The generator is required to pay all costs arising from connection, regardless of how ‘deep’ into the system those costs may be incurred.

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Connection charge income is classed by the regulator as 'excluded revenue’ and is not considered as part of the price control mechanism. Other excluded revenue steams include DUoS income for 132kV connected customers; the income associated with nontrading rechargeable (NTR) work and pass-through of NGC connection charges.

Electricity Distribution Standard Licence Condition 4B, ‘Requirement to Offer Terms for Use of System and Connection’ , Section 5(c)(i) and (ii).

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As such, the issue of tariff support does not arise since no DUoS is paid by the connected embedded generator. These issues are explored further in section 5.

‘GSP-charging’ methodology

2.67 The charging methodology presently adopted by the industry for charging for use of the distribution system inherently assumes that all energy supplied to demand customers originates from the transmission system and is delivered via the 132kV grid supply points (GSPs). Consequently, DUoS charges levied by the majority of DNOs aim to recover the appropriate proportion of costs for providing the distribution network from the 132kV assets down through the voltage levels to the voltage at which the connection is made.

2.68 The important consequence of this is that suppliers who purchase units of electricity from generators that may be connected at the lower voltage levels in the distribution system, are still charged for distribution services on the assumption that the energy has flowed down from the ‘top’ of the distribution system.

2.69 In practice, suppliers may use a much smaller part of the distribution system if it purchasing energy from an embedded generator and sells to a nearby load. This is particularly so if the generation and demand are electrically close. Figure 4 below illustrates how, despite possibly only using a proportion of the distribution network, suppliers who purchase energy from embedded generators are required to pay DUoS as if the energy had been supplied from the ‘top’ of the distribution system - i.e. via the GSP path.

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Figure 4 - GSP path charging

Z\y) GRID

132kV

33kV

LOADEmbeddedGeneration

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3. INDIVIDUAL DNO APPROACH TO DUOS CHARGING

3.1 This section reviews the methodology adopted by the three DNOs we interviewed - focusing particularly on the areas where policies and/or charging practices differed.

3.2 The work uses the published Condition 4 statements62 and also draws on responses to the December 2000 Ofgem consultation paper on The Structure of Electricity Distribution Charges. The DNOs we consulted as part of the work were asked to highlight any changes in policy or tariff setting practice since their submission to the consultation. The recent Ofgem consultation63 on embedded generation and publicly available responses to this consultation is also used.

3.3 All references to DNO practice are made anonymously and all summaries and/or comparisons are un-attributed. The three DNOs we interviewed will be referred to as DNO A, DNO B and DNO C.

Use of the DRM

3.4 In common with virtually all DNOs in England and Wales, two of the three DNOs we consulted still based their present charging practice on a well established, and widely accepted, methodology which was developed, nationally, in the 1980s. Some DNOs have departed (to a greater or lesser extent) from the original model and many have modified the approach to better suit local conditions and individual business circumstances.

3.5 In addition, one of the two DNOs advocated the continued use of the DRM as the basis for any new pricing practices designed to accommodate embedded generation. The DNO in question acknowledged that this would require significant changes to the way in which the DRM currently operates although it was already developing such a charging framework based around the existing DRM. This will be explored further in subsequent sections of the final report.

3.6 The third DNO we spoke to is one of the few DNOs to have departed from the ‘traditional’ approach to the costing and pricing of distribution services. The work in this section describes the principles adopted by this third DNO and explores the differences, the perceived benefits and the potential disadvantages of this alternative approach - from the perspective of each of interested party.

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Condition 4 of the Electricity Distribution Licence: Standard Conditions require DNOs to publish the basis of charges for use of, and connection to, the distribution system.

Embedded Generation: price controls, incentives and connection charging - A preliminary consultation document, Ofgem, September 2001.

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3.7 It was acknowledge by the two DNOs who still used the DRM as the basis for their charging framework, that the value of the DRM outputs are in the relative allocation of costs and not in the absolute values - due to this scaling of the DRM outputs to fit the price cap.

Departures from the standard model

3.8 The two DNOs we interviewed, who still employed the DRM in determining their DUoS tariffs, had, like most other DNOs, modified and varied the basic model to better reflect local conditions and conventions and individual planning policies. For example, some DNOs have more transformation directly from 132kV to 11kV64 than others.

3.9 DNO A no longer uses the DRM in the formulation of distribution tariff prices. However, discussions with DNO A confirmed that prior to the introduction of the new approach, the DRM had been modified and improved over the years to better reflect actual costs of owning and operating a distribution network65.

Number of distribution system voltage levels

3.10 In common with most other DNOs, the actual distribution systems of the three DNOs to which we spoke had more than four physical voltage levels within their real distribution system. This meant that in some cases, each of the four categories in the DRM represented more than one actual voltage level.

3.11 For example, DNO B has both 11kV and 6.6kV systems which are both represented by the HV category in the DRM. This increases the extent to which assets costs are averaged across voltage levels and means that applying differing DUoS rates to customers connected at these two voltage levels is difficult.

3.12 If the DRM is to be used as the basis for the formulation of embedded generation DUoS tariffs then the number of actual voltage levels may have to be accurately represented in the model. This is likely to be particularly important if any new generator tariff groups provide for only a relatively low number of embedded generators. In this case, any averaging across voltage levels may give rise to an unacceptably high number of generators being inequitably represented in terms of their true impact on distribution system costs.

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In most DNO networks, a 33kV voltage level is used between the 132kV and 11kV voltage levels. However, in some DNOs, particularly where there are large areas of high load density, such as large cities, the 33kV voltage level is sometimes bypassed and power is delivered directly from 132kV to 11kV. This gives rise to a greater than average number of 132/11kV substations.

DNO A was one of a number (approximately 7-8) of then PESs, which jointly funded a wholesale revision of the generic characteristics of the DRM by Electricity Association Technology Limited (EATL).

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DRM content

3.13 The DRM is no different from any other model in that the accuracy of its outputs (the tariff yardsticks in the case of the DRM) will depend on the quality of the inputs. The DRM inputs not only include the various asset costs but also items such as coincident and diversity factors - all of these will impact directly on the magnitude and relativities of the DRM outputs.

3.14 The DNOs we spoke to confirmed that asset cost information is usually relatively straightforward to collect - often extracted directly from project estimating systems.

3.15 DNO A confirmed that the DRM outputs were sensitive to the coincident factors used within the model. None of the DNOs we spoke to had a formal process for reviewing and ensuring that the coincident factors used remained representative and relevant. Before it stopped using the DRM as the basis for its prices setting, DNO A confirmed that none of the cost inputs to its DRM were reviewed very often. Its plans to stop using the DRM may have been a factor in this.

3.16 DNO C said that it reviews the mix of assets within the DRM every five years to check that network configurations and asset types properly represent current planning philosophy and policy. In addition, input prices were reviewed annually. Of the three DNOs we interviewed, DNO C was the strongest advocate for the continued use of the DRM, in its present form, for establishing DUoS prices.

3.17 DNO C also confirmed that the diversity factors used in its DRM were derived from internal data such that they reflected current system diversity. It is not known how often this review takes place.

3.18 As the number of embedded generators increases, the complexity of the distribution system is likely to increase - both from a technical planning and a commercial pricing perspective. If use of the DRM is to be extended to pricing for embedded generation then its content and design may have to more closely represent the physical system.

3.19 Furthermore, depending upon the rate of increase in the penetration levels of embedded generation, and any associated distribution network development, it may well be that the composition and design of the DRM will have to be reviewed more frequently that is done at present - particularly if the model outputs are to reasonably reflect actual network costs.

3.20 Although the DRM outputs are scaled to fit the regulatory price cap, allocation of costs between a higher number of, more complex, users is likely to require a more accurate representation of the real network.

3.21 In addition, items such as coincident factors may become critical to accurate modelling of the contribution to network costs made by embedded generation.This may be particularly important where embedded generators have the potential

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to reduce the maximum demands occurring at the various levels in the distribution system.

Yardstick outputs

3.22 Given that the DRM yardstick output prices are scaled to match the allowed regulatory revenue, the extent to which they concur is not of direct financial consequence - since it does not affect the total revenue earned by the DNO business. A large discrepancy may, however, indicate that the DRM inputs are no longer representative of real network costs. Although scaling may redress any inaccuracies, it is unlikely that costs will have changed by the same factor across the range of assets. There may, therefore, be some distortion in the allocation of costs to individual customer groups which may affect price relativities between users.

3.23 DNO A suggested that the yardstick outputs from its DRM were some 25-30% higher than allowed revenues. DNO B also accepted that its yardstick outputs were considerably higher than the allowed price. DNO C was more concerned with aligning the DRM outputs with the price and confirmed that in its model, the two were reasonably well matched.

3.24 From our discussions with the DNOs, it seemed that the DRM yardstick outputs being higher than the allowed revenue was most probably a result of the last distribution price control revenue reduction66 not being adequately reflected in changes to the model cost inputs.

3.25 With increased levels of embedded generation, the DRM content may need to be regularly and frequently reviewed if the gap between the model outputs and the allowed regulatory revenues is to be kept within acceptable limits.

Demand related and energy related costs and charges

3.26 Both DNO B and DNO C confirmed that they use the aggregate maximum demand (AMD) for the calculation of local, capacity driven, charges and the simultaneous (or diversified) maximum demand (SMD) for determining the costs higher up the system. This aligns with the ‘standard’ DRM approach adopted by most of the DNOs.

3.27 DNO C confirmed that the £/kVA capacity charges were used to recover the demand-driven costs at the voltage of connection, transformation to the next voltage level and 20% of the costs of the next voltage level up. The remaining 80% and all other upstream costs are recovered via p/kWh unit charges which are calculated according to SMD. Again, we believe that this is standard DRM practice and used by many DNOs. This approach is also used by DNO B.

In the last regulatory price control review, DNO revenues were cut by amounts ranging from 12% to 35% (ref. ‘Review of Public Electricity Suppliers 1998 to 2000, Distribution Price Control Review, Final Proposals, December 1999.)

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3.28 It is for further consideration whether this SMD/AMD basis could be used as the basis for embedded generation charges. Given the advantages in treating both demand and generation with some degree of consistency, it may well be that an embedded generator’s use system charges could be based on similar principles.

3.29 At the local level, where assets are provided for the sole use of the generator, the use of AMD as the basis for capacity charges would seem still to be appropriate. An embedded generator’s impact on upstream costs might still be based on SMD although these charges might be negative to reflect any benefit to the network which the generator provides at these ‘higher’ system levels.

Domestic and small non-domestic connections

3.30 DNO A, although having adopted alternative approach to its tariff setting, still follows the most common approach for domestic charge structures. DNO B adopts this same method - a simple two part tariff comprising:

• a standing charge (£/customer); and

• utilisation/unit charge (p/kWh).

3.31 DNO C has removed the standing charge element from its domestic DUoS tariff and recovers the whole of the cost of providing a distribution service to domestic connectees via unit (kWh) charges. It has, in fact, removed the standing charge element from all distribution tariffs.

3.32 Where DNOs have abolished standing charges for demand customers, there would seem no obvious reason why this should not be extended to any new generator DUoS charging framework. Any fixed element of distribution tariffs are likely to recover costs which are common to both generation and demand.

Tariff support allowances

3.33 DNO C has recently abolished tariff support allowances for all non-domestic connection work - such that new connectees (and existing connectees requiring connection upgrades) are required to pay the full costs of any work required67.

3.34 Before this capital credit was abolished, DNO C said that approximately 65% of the costs it incurred in connecting new customers (or enhancing existing connections) were recovered via connection charges - with the remaining 35% being smeared across all DUoS charges payers. ILEX are aware of other DNOs having similar ratios.

3.35 DNO A and DNO B said that they still applied tariff support although DNO A has some reservations over whether it ought to be continued.

Subject to the 25% and ‘voltage level above’ reinforcement rules given in the distribution licence.

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3.36 Tariff support allowances can introduce cost/price distortions and these are unlikely to add value to any new generator DUoS charging policy. If the aim is to reduce upfront connection charges then this is better done through careful design of the connection charge policy - in terms of the ‘depth’ of assets for which it is designed to recover.

Use of standard connection charges

3.37 DNO C, as part of its abolition of standing charges for domestic customers, has replaced the previously adopted standard connection charge for domestic connections with a policy of individual job costing for each connection project.

3.38 Standard connection charges are unlikely to be appropriate for the connection of most embedded generators due to the lack of cost reflectivity which this approach would offer. Also, the range of costs incurred in connecting a wide range of embedded generator types and sizes would not be particularly well suited to the application of a standard charge. The exception might be for domestic-scale generation where such an approach may well be economic.

Table 1 - Approach to tariff support allowances, standing charges and use of standard connection charges.

Connection typeDNO A DNO B DNO C

Tariff support applied?Domestic Yes Yes Yes

Commercial and Industrial Yes Yes No

Embedded generation No No No

Standing (fixed) charges levied in tariff?Domestic Yes Yes No

Commercial and Industrial Yes Yes No


Use of standard connection charges?Domestic Yes Yes No

Commercial and Industrial No No No


Treatment of embedded generation

3.39 In common with the practice adopted through the UK, none of the DNOs we interviewed presently charge for use of their distribution system by embedded generators. No capital allowances are applied and the connectees are therefore

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required to pay the full costs of connection - plus an amount for operations, repair and maintenance68.

3.40 Neither the ‘25% demand rule’ nor the ‘voltage level above’ rule are applied to the connection of embedded generation in any of the three DNOs we interviewed.

3.41 DNO C has, however, began to develop ideas on how embedded generation might be incorporated into the charging model. The principles behind this are explored further in section 5 of the final report.

3.42 ILEX are not aware of any DNOs that presently employs a structured commercial framework for charging embedded generators for use of the distribution system on an ongoing, tariff, basis. We are, however, aware of a number of DNOs who are actively developing ideas and considering the introduction of embedded generator DUoS.

Alternative approach to DUoS tariff setting

3.43 This section briefly describes the approach adopted by DNO A which radically departs from the methodology used by DNO B and DNO C - and the majority of DNOs in England and Wales69.

3.44 This price-setting framework does not use the DRM and attempts, instead, to set charges for use of the distribution system such that prices closer reflect the characteristics and operation of the regulatory price control.

The basic principles and philosophy

3.45 DNO A holds the view that the main purpose of DUoS tariffs should be to recover revenue allowed by the distribution prices control. The aim of this approach is to align distribution revenue streams, and hence prices, with the price control formula.

3.46 As has previously been mentioned in section 2, the price control formula allows DNO to retain approximately half of the revenue arising from the distribution of additional units (kWh). This is based on the unit rates given in each DNOs licence.

3.47 DNO A has begun a process of aligning its DUoS tariff prices such that the fixed and variable proportions match those of the price control. In this way, any increase or reduction in the allowed revenue - as a result of distributing more or

68

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The most common practice is to capitalise the lifetime operation, repairs and maintenance (O, R & M) costs and add it to the upfront connection costs. It is common for O,R&M to be applied as a simple levy on capital.

DNO A began the process of implementing its alternative approach at the start of the present distribution price control period review in April 2000 following consultation with Ofgem.

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fewer units - will align with the variation in actual DUoS revenue received. The aim is for the regulatory year-on-year adjustment70 to eventually be zero.

3.48 For DNO B and DNO C (and other DNOs in England and Wales), an increase or decrease in units distributed, with respect to that forecast, will inevitably result in a net over, or under, recovery of DUoS revenue which will need to be adjusted for in the next year’s price control.

3.49 DNO A aims, therefore to obtain 50% of its DUoS revenue from the fixed element of the tariff (e.g. standing and capacity charges for industrial and commercial customers) and 50% from the variable element of the tariff (e.g. p/kWh unitcharges)71.

3.50 In order to minimise price disturbance, DNO A has attempted to reach this target position over a number of years72.

Potential risks and benefits

3.51 DNO A claims several benefits to this approach73:

• the divergence between income and allowed revenue is minimised which reduces the risk of a breach of Distribution Licence and any financial penalties which may arise;

• the removal of the need for internal processes associated with under or over recovery;

• tariff setting will become more simple;

• DUoS pricing will become more stable; and

• a clear link to the regulatory formula improves transparency.

3.52 There do, however, appear to be one or two disadvantages which were highlighted by the other DNOs to whom we spoke as part of our research. Most notably, that the method adopted moves away from the use of a cost base. Some DNOs were

70

71

72

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This is referred to in the distribution price control formula as the ‘k’ factor.

In actual fact, because of the pass-through of NGC exit charges, and that DNO A adds this to the fixed element of the tariffs, the target proportion of fixed vs. variable elements is 54% fixed, 46% variable. DNO A, in common with other DNOs, previously had a proportion of fixed revenue of approximately 20 to 30%. This approach by DNO A has therefore required an average increase in the fixed charge element of the tariffs and a corresponding reduction in average unit charges.

The process began at the start of the current price control period in April 2000 after consultation with Ofgem.

‘The Structure of Electricity Distribution Charges - Initial Consultation Paper’, Ofgem, December 2000. Appendix, section 3.7.

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of the opinion that this introduced the risk of ‘losing-touch’ with distribution costs and their application to DUoS tariffs.

3.53 In this alternative method, tariff prices, in both absolute and relative terms, are based on what the regulator believes to be the costs of owning and operating the distribution system. Further, a move towards reducing the number of customer groups to align with the four tariff basket prices given by the price control formula, would seem to be moving further away from costs reflected pricing.

3.54 This approach does not have any obvious additional detrimental impacts on the prospect for embedded generation when compared to the DRM based methodology. However, it may be that costing and pricing of distribution services needs to become more cost reflective, rather than less, if embedded generation is to be effectively included within distribution charging mechanisms.

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4. DISTRIBUTION SYSTEM CHARGING OPTIONS FOREMBEDDED GENERATION

4.1 This section outlines the various options which could be adopted by DNOs for connection to, and use of, the distribution networks with embedded generation. It is based on the options described in the Embedded Generation Working Group (EGWG) report74.

4.2 As has been discussed in the previous sections, there is a close association between charges for connection and charges for the use of the distribution system.

4.3 The full range of connection options for embedded generation are reviewed with three connection options being selected for further scrutiny. The work in section 5 will focus on these connection charging options and will examine how each compare with the present ‘deep’ connection charging arrangements.

4.4 The physical effect of embedded generation on the distribution system - such as the impact on network power flows - needs to be considered if discussions on the design of a new DUoS pricing framework are to extend beyond the level of generic principles. The DUoS charging principles which might accompany these three connection charging options is discussed and developed in section 6.

4.5 The alternative approach to charging for use of system being considered by DNO C is described in this section at a high level. The practical implications of introducing this type of charging arrangement is also explored in the section 6.

Requirements and objectives of an effective charging framework

4.6 Any pricing framework must be capable of generating sufficient revenues for the DNO to successfully operate the business and to fulfil its statutory obligation of developing an efficient, co-ordinated and reliable distribution system. A second requirement of an ‘ideal’ framework is that network users should pay for distribution services in accordance with their contribution to total system costs.

4.7 In addition, the ideal tariff structure should be:

• fair and equitable;

• cost reflective;

• predictable and verifiable; and

• stable, easy and cost effective to implement.

Final report by the DTI/Ofgem Embedded Generation Working Group (EGWG), January 2001.

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4.8 Furthermore, a set of sound pricing arrangements might be expected to encourage DNOs to invest in the distribution network optimally (i.e. not to unnecessarily over-invest) and should also to discourage cross-subsidies and discrimination.

4.9 In practice, a pricing framework which exhibits all of these attributes is unlikely to exist and, inevitably, any practical system is likely to involve trade-offs between these ideal attributes. For example, simplicity and cost-reflectivity are likely to introduce conflicts when designing a DUoS pricing framework. Social pressures and political constraints are also likely to feature highly in any attempts to introduce a fully cost reflective charging regime free of cross-subsidy.

Review of the options set out in the final report of the Embedded Generation Working Group (EGWG)

4.10 The EGWG report outlines five broad options which could be adopted as the basis for determining the charges levied for the connection of embedded generation.

4.11 The work in this section explores these options and the potential impact on the various participants, including the regulator’s perspective.

4.12 As has been discussed in some detail in previous sections, recovery of all connection costs comprises two main considerations:

• the upfront, on-off, connection charge; and

• the ongoing, regular, payments for use of the distribution ‘system’.

4.13 In this section, we review the connection options together with the broad options for recovering any costs not covered by the connection charge. The detail of precisely how any costs not covered by the connection charge might be recovered, is examined in section 6 the report.

Option 1: ‘Deep’ connection charge policy

4.14 This is the methodology presently employed by the three DNOs we interviewed and also by all of the DNOs in England and Wales. It represents the reference case and will be used as the benchmark against which other options will be compared and contrasted.

4.15 A ‘deep’ charging policy means that all of the costs of connecting the embedded generator are charged as a one-off capital payment at the time of connection. The newly connecting generator is required to pay for all of the costs associated with making the connection and with providing a distribution network facility.

4.16 In this option, reinforcement costs associated with connection of embedded generation are not limited to the voltage of connection (nor the voltage above) - as for demand connections. Nor is there any rule to prevent a newly connecting embedded generator from been faced with the costs of reinforcement by virtue of being the last to connect.

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4.17 With reference to Figure 5, an embedded generator connecting, under a ‘deep’ connection policy, to the low voltage network at position (1), may be required to pay for any reinforcement higher up the system. This would not only include any 11kV/LV transformer costs (2-3) but also any work on the 11kV circuits (3-4). In addition, should there be a need to replace 33kV or even 132kV switchgear (5 &6) as a result of excessive fault level75, then this cost would also fall to the embedded generator.

Embedded generator’s perspective

4.18 The embedded generator is required to pay a relatively large upfront payment for connection to reflect all of the costs to which the DNO is exposed. There is no requirement for the embedded generator to pay charges for ongoing use of the system, nor does the embedded generator receive payment in circumstances where the embedded generator might reduce the total cost of distribution.

4.19 Suppliers who buy energy from embedded generators and who then supply energy to distribution demand customers are required to pay DUoS on the basis of the energy originating from the transmission system. Embedded generators do not benefit from locating electrically closer to the demand and thereby reducing energy transportation costs. Conversely, transmission connected generators are provided with clear price signals associated with their location in relation todemand76.

4.20 The deep charging approach is inconsistent with the treatment of demand connections. If increasing levels of embedded generation is to be successfully incorporated into a charging framework then this must treat both demand and generation on a fair and equitable basis.

4.21 The present deep charging approach results in embedded generation developers facing high initial capital costs. The requirement to pay large upfront costs can have significant impact on the financial viability of some embedded generation projects and may even, in some circumstances, prevent schemes from progressing.

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The connection of embedded generation, if it comprises rotating plant, will contribute to system fault levels. Existing switchgear must be capable of operating under any enhanced fault level condition. Where this is not the case it is often necessary to upgrade or replace existing switchgear. This is a common problem in urban areas and can lead to substantial costs which, under a ‘deep’ connection policy, will be charged to the embedded generator.

The charges applied by NGC for use of the transmission system recognise and reflect the relative location of supply and demand. Under the present charging methodology, generators located in close proximity to net import zones (i.e. demand centres) are charged negative transmission network use of system charges (i.e. they are paid by NGC). Details can be found in the NGC ‘Statement of the Connection Charging Methodology’ - effective from 1 October 2001.

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4.22 Existing embedded generators are not affected by the need for new embedded generators to pay deep connection costs. Once an embedded generator has paid for its connection and has connected to the distribution system, any subsequent embedded generation connections are treated in isolation.

4.23 However, the deep connection policy does mean that the connection charge levied on a new embedded generator will reflect the impact which all other existing users, including existing embedded generators, have on the distribution network.

The DNO perspective

4.24 Any departure from the present deep connection policy has would have a number of significant implications for the DNOs.

4.25 As has been discussed in the previous section, there is a direct relationship between connection charges and use of system charges. The proportion of the total costs associated with providing a new network connection which are recovered via an upfront capital contribution will have a direct effect upon the capital expenditure requirements of the DNO.

4.26 A deep connection policy results in minimum connection expenditure by the DNO and, in theory, marginally lower DUoS charges for the remainder of the existing customers base77.

4.27 One of the DNOs we interviewed had abolished tariff support allowance (capital credit) for industrial and commercial customers. This will also have the effect of reducing the DNOs net new business capital expenditure requirements. The timing of such a policy change may well effect the extent to which a DNO benefits from the way in which allowed regulatory revenue is calculated.

4.28 The present deep charging methodology represents a low risk approach for the DNOs. All of the costs are paid at the outset and the DNO is not exposed to the perceived risks associated with the possibility of assets which may subsequently become stranded if embedded generators fail to operate for the duration of the intended connection asset life.

4.29 The risk of surplus capacity, as a result of migrating load or ‘lumpy’ capacity increments, is something which has been accommodated by the DNOs, in respect of providing a network services to demand, for many years. Furthermore, the risk of generation assets becoming redundant will reduce as the number of embedded generators increases and the opportunity to re-employ assets also increases.

In practice, the number of new connectees each year compared to the total number of demand customers, is so small (typically less than 2%) that the potential reduction in general DUoS rates, for any given customer group, would be negligible.

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The demand perspective

4.30 For demand connectees, the DUoS capacity charge mechanism (£/kVA) means that any reinforcement costs which are not included in the connection charge as a result of existing surplus capacity, are still paid for through ongoing DUoS charges. A demand connectee will pay for the required capacity to be made available - regardless of the amount of connection charge. In this way, demand connectees pay for the use of surplus capacity.

4.31 For embedded generators, any ‘surplus’ capacity on the existing network can be taken up without appearing in the connection charge. Furthermore, since under a deep connection policy embedded generators are not required to pay DUoS charges, any ‘spare’ capacity can be used without direct payment.

4.32 Under the present deep connection arrangements, therefore, demand customers, ultimately, (and collectively), pay for all network capacity - including that used by embedded generators which was not included in the initial connection charge.

The regulatory perspective

4.33 The timing of any changes in connection charging policy will be of interest to the regulator since the policy adopted by the DNO is likely to impact directly on its capital expenditure requirements. For example, a move from a shallow to a deeper connection policy or the removal of tariff support allowance, will reduce the new business capital expenditure requirement of the DNO.

4.34 The important issue is that the present regulatory arrangements permit the DNO to earn a return on its allowed capital expenditure rather than on its actual capital expenditure. This provides an incentive for the DNO, not only to increase capital efficiencies but also to reduce its net capital expenditure requirements.

4.35 It is likely that any change in connection policy mid-way through a regulatory price control period would require regulatory approval. Any wind-fall gains as a result of such changes may well be clawed back by the regulator.

Option 2: Shallow generator connection charge with all reinforcement costs paid by load customers

4.36 This option would mean that the connection charge levied on embedded generators would be for the shallow connection assets only. These shallow assets are defined as the items of connection equipment up to the point of common coupling - that is, for the ‘sole-user’ assets only.

4.37 In many cases this may only cover the switchgear and cable connecting the embedded generator to the nearest point on the distribution system. With reference to Figure 5 below, this would only include the cost of the connection equipment between the embedded generator and the connection to the low voltage (LV) main cable at position 1.

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4.38 Embedded generators would not pay for use of the distribution system but demand customers would continue to pay DUoS.


4.39 This represents the most favourable option for embedded generation. The initial capital connection cost for generators would, on average, be reduced and with no ongoing charges for use of the system, total lifetime costs would be significantly reduced.

4.40 With shallow connection charges, the locational price signal associated with any additional reinforcement costs (which, under a deep connection policy would be represented in the connection charge), would be diluted. Embedded generators would be likely to face similar costs for connection to the distribution network regardless of location.

The DNO perspective

4.41 The assets associated with making new connections - whose costs are not recovered from connectees at the time of connection - will become part of the general distribution system. These costs will be added to the regulatory asset base (RAB) and will be recovered from the general demand customer base, through DUoS charges, over the lifetime of the asset - typically 40 years. This unrecovered connection expenditure represents the DNO’s net new businessexpenditure78.

4.42 Under a shallow connection regime for embedded generation, the DNO’s net new business capital expenditure would significantly increase.

4.43 A low generator connection charge may encourage the connection of embedded generation. This may lead to the need for additional DNO resource for the administration, design and construction of an increased number of generator connections.

4.44 The existing DUoS charge framework would be retained. No new systems would be required and DUoS bills would continue to be sent to the licensed suppliers in respect of each demand connection.


4.45 This represents the most inequitable option for demand customers. The total revenue recovered from all demand connectees, through DUoS charges, would need to increase to cover the additional costs of connecting embedded generation.

The total amount expended by the DNOs in connecting new customers (or upgrading existing customers) is defined as the gross new business expenditure. The gross expenditure minus the capital connection contributions is equal to the net new business expenditure.

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4.46 Demand customers would see no direct benefit from the increased charges.Newly connecting demand customers would continue to pay for connection on a ‘shallowish’ basis - where a proportion of reinforcement costs are recovered through the connection charge and the remainder through DUoS.


4.47 DUoS charges would increase by an amount which would depend on the number of new embedded generation connections and the extent of the additional capital expenditure required to connect them.

4.48 Under a shallow connection policy, the value of the regulated asset base is likely to increase. The Regulator will need to consider the impact which this may have on the DNOs and other industry participants.

4.49 It would be for the regulator to decide how any additional operational expenditure, resulting from an increased DNO workload, should be allocated. In particular, whether it should be recovered from the general demand customer base through DUoS charges or whether the shallow generator connection cost should be appropriately adjusted.

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Figure 5 - Shallow, shallowish and deep connection

132kV

33kW

llkV4-

▼D

LV

a, GRID

44-X

5* X

* X

▼D

X

X

D

▼ ▼D

tX D

EmbeddedGeneration

KEY

X = circuit breaker

$ = transformer

D = demand


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Option 3: Shallow generator connection charge with all reinforcement costs shared by all parties

4.50 This option is similar to option 2 except that any reinforcement costs, which are not included in the shallow connection charge, are shared by both demand customers and embedded generation.


4.51 The embedded generator would still only pay connection charges in accordance with the ‘shallow’ principles - i.e. only the assets for which the embedded generator is the sole user (from the embedded generator up to position 1 in Figure5).

4.52 Since, however, the embedded generators would be required to pay a share of the additional reinforcement costs, some form of generator DUoS payment would be introduced. This could be a simple entry charge based upon the agreed embedded generation connection capacity as specified in the connection agreement between the DNO and the embedded generator.

4.53 The sharing of the total costs between demand and generation would need to be decided. It may be that whilst the number of embedded generators is relatively low, some of the costs triggered by generator reinforcement could be shared with the much higher number of demand customers. As embedded generator numbers increased, the total costs of the distribution network could be equitably shared between generators and demand. In time, this may mean a reduction in the level of DUoS charges levied directly on the demand customers.

4.54 It is important to appreciate, however, that the end users of electricity, i.e. the demand takers, will ultimately pay all of the costs associated with generating, transmitting, distributing and supplying electricity. For example, the introduction of any new charges on embedded generators for use of the distribution system are likely to be reflected in an increase in the price at which the generator is willing to sell its output.

The DNO perspective

4.55 As a result of the shallow charging policy, the DNO would still only receive relatively low charge income associated with embedded generation connections.In addition, the DNO would receive a source of DUoS income from both demand and generation - although the total revenue may not exceed option 2 where all of the additional reinforcement costs are recovered via the existing demand DUoS.

4.56 This option would seem not to offer the DNO any significant advantages over option 2 and would require the DNO to develop policies and processes associated with any new generator entry charges.

4.57 The shallow connection charge would, again, dilute any locational price message although the DNOs could introduce locationally varying entry charges to

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encourage connection of embedded generation at parts of the network which may benefit.

4.58 Furthermore, a shallow charging approach increases the DNO’s risk exposure associated with the prospect of stranded assets. It is, however, for debate as to the commercial impact that this is likely to have on the DNO given the way in which its regulated revenue is calculated. Once an asset has entered the regulated asset base, the DNO is allowed to earn a regulated rate on return on it for the lifetime of the asset. Therefore, an asset which was installed as part of a legitimate generation scheme, but which is no longer used, will continue to contribute to DUoS revenues.


4.59 This option is less onerous on demand than option 2 since the generators now contribute towards any additional reinforcement costs. The net effect on demand DUoS will, however, depend upon the basis by which the reinforcement costs are shared. Whilst the numbers of embedded generator are low, there may be an increase in demand DUoS in order to control the level of generator entry charges.

4.60 Conversely, any embedded generator DUoS (entry) charge revenue may contribute towards the cost of the general distribution system - particularly when numbers of embedded generators increase and there are opportunities to exploit economies of scale in provision of the ‘generator-driven’ network assets.

4.61 Levying DUoS charges on embedded generators may indirectly transfer monopoly network costs into the competitive energy retail markets. In time, and with sufficient competition, this may reduce the total delivered cost of energy to the end customer.

4.62 The issue of stranded assets is of concern to the demand customers. The costs of any asset which has been installed with Ofgem’s blessing, and which forms part of the asset base, will be paid for by those paying DUoS, over the lifetime of the asset. Depending upon how the reinforcement costs are allocated between embedded generation and demand - this may mean that demand customers are required to bear a proportion of the cost risk of any stranded assets associated with embedded generation connections.


4.63 It would be for the regulator to decide on how the total cost of the distribution network is allocated between embedded generators and demand and the extent to which network costs are transferred between industry participants.

4.64 It is also important to decide whether generator DUoS should form part of the regulatory price control or should be treated as excluded revenue. The impact which embedded generation has on distribution system costs must be properly recognised - be it an increase in total costs or a cost saving. Any new DUoS framework, therefore, ought to be related to the total cost of providing the

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distribution system and should recognise the contribution to those total costs which each demand and generator connection makes.

4.65 On this basis, it would seem sensible for generator DUoS charges to be price regulated in the same way as demand DUoS.

Option 4: Shallowish generator connection charge with all reinforcement costs shared by all parties

4.66 This option introduces the concept of shallowish connection where some, but not all, of any upstream reinforcement costs are included in the connection charge.

4.67 Demand reinforcement costs are limited to those at the voltage of connection and one voltage level above, in addition, costs are not incurred for any deep reinforcement where the load increment does not exceed 25% of the capacity of the network - these costs are charged to general reinforcement and are smeared across all customers.

4.68 Under this option, embedded generator connection charges would be limited in their scope and could be subject to the similar rules applied to demand for capping the extent to which total reinforcement costs are included in the upfront charges.

4.69 This option advocates a DUoS charging framework for both embedded generation and demand to complement the shallowish charging methodology - based on a combination of entry and exit charges.

4.70 With reference to Figure 5 above, a shallowish charging approach might give rise to embedded generation connection charges which includes the costs of any additional low voltage (LV) assets plus a proportion of the 11kV reinforcement costs (e.g. the 11kV line at position 3-4 in the diagram).


4.71 For embedded generators, this approach would lead to upfront connection costs which are likely to be higher than those under a shallow charging policy but may be lower than the charges levied under a deep connection charge policy.

4.72 It is important to recognise that charges for any individual generation connection project under a shallow, shallowish or deep connection approach may actually be the same. The extent of the differences would depend upon the technical characteristics of the individual project and also the capability and condition of the existing network in the vicinity of the proposed point of connection.

4.73 Where an embedded generator can be readily accommodated on the network, even a deep connection policy may only lead to the DNO effectively charging for the shallow connection assets. As previously discussed however, this would suggest that generation might stand to benefit from the use of surplus capacity. For this reason, a DUoS regime, base on a system of entry charges, would be used to charge for any system costs. Exit charges would be levied on demand takers.

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4.74 Entry and exit DUoS charges could contain location price signals to promote efficient use of the network by encouraging both demand and generation to optimally locate. Entry charges (and potentially, exit charges) could be either positive or negative to reflect the contribution to network costs of individual connectees.

The DNO perspective

4.75 The impact on the DNO would be similar to that for shallow connection but with a greater proportion of the connection costs coming from capital contributions and a lesser proportion having to be funded by the DNO. The DNO’s asset base would be likely to grow with a corresponding increase in the DNO’s net new business expenditure.

4.76 As for the shallow option, the DNO would be required to develop new processes and systems associated with the introduction of a new entry/exit based DUoS regime.


4.77 Depending upon how any additional reinforcement costs are allocated between demand and generation, demand customers may see an increase in DUoS charges resulting from an expanded regulatory asset base.

4.78 However, when compared to the shallow approach, existing demand customers may face a lower risk of having to pay for redundant network capacity resulting from the subsequent demise, or re-location, of an embedded generators.

4.79 This option would seem not to be as favourable to demand customers as the deep approach where demand customers carry no cost risk associated with embedded generation reinforcement since all of the costs are levied on the generator at the outset and charges for generation and demand remain separate. In fact, under a deep charging policy, demand customers may stand to benefit from any assets which were originally installed for embedded generation, and fully paid for, but which subsequently stopped being used for generation - for what ever reason.


4.80 As for the shallow approach, the main regulatory issues are associated with the way in which system costs are allocated between generation and demand and how any new DUoS revenue will be price controlled.

Option 5: Shallowish generator connection charge for small generators and site specific charges for larger generators

4.81 This option is the same as option 4 for all participants except for the treatment of the larger embedded generators. Small and medium sized embedded generators would pay entry, and potentially transportation, charges together with a shallowish connection charge.

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4.82 The initial capital outlay faced by smaller embedded generators will be lower than those under the present deep connection charge policy. For this smaller class of embedded generator, the issues are as discussed in option 4 above. The larger embedded generators, however, would have the option of agreeing payment terms with the DNO in recognition of technical conditions and network characteristics local to the point of connection.

4.83 A larger embedded generator may be of more significance to the DNO in terms of its electrical impact on the distribution network and its ability to provide services to the distribution system such as voltage support and system security. Although it is recognised that the regulatory and commercial framework may need to be reviewed before the provision of such support services can be further developed.

4.84 This option would also provide an opportunity for those who are more able to negotiate a site specific deal, to do so. It would also provide a more cost reflective and equitable pricing policy to smaller generators whose participation in lengthy, site specific, negotiations may not be practicable nor economic.

The DNO perspective

4.85 As for option 4, the DNO would be likely to see a net increase in both its net capital expenditure requirements and the value of its asset base. It would still require new processes and systems to deal with the introduction of any new DUoS charging systems.

4.86 There may be some benefits in having a consistent approach to charging for both demand and embedded generation.

4.87 Since some of the larger generators may opt for paying more cost reflective connection charges - although, this is likely to depend on the commercial dynamics of the project development - the DNO’s capital investment requirements may reduce when compared to option 4.

4.88 The ability to negotiate site specific commercial terms may assist with network planning and may also simplify the capital investment programmes.


4.89 Many demand sites connected to the distribution system at, or above, primary voltage levels (e.g. 33kV, 132kV) already have the opportunity to agree site specific charges. There would seem to be no obvious reason why the same arrangement could not be extended to embedded generation connections.


4.90 As for option 4 - except that an increased number of site-specific charging arrangements may lead to a higher number of Ofgem determinations.

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Option 6: A further development of option 4

4.91 This is the approach being considered by one of the DNOs we interviewed as part of the work and is being developed in consultation with Ofgem. It is loosely based on option 4 but begins to develop further ideas on how a combined generation/demand DUoS charging framework might begin to look and how it would work in practice.

4.92 This alternative approach is described only in broad terms in this part of the work. A closer examination of how the DUoS charging mechanism would operate in practice needs to be considered in association with real network conditions. This will be done as part of Task C for inclusion in the final report.

4.93 This approach advocates a shallowish connection policy for both generation and demand. The ‘depth’ of connection costs paid by demand customers would continue to be limited by the ‘25%’ and ‘voltage-above’ rules.

4.94 Embedded generation would also have its connection costs limited in accordance with these two existing reinforcement rules but with an additional, similar, 25% rule, applied to fault levels for the purpose of determining switchgear replacement costs.

4.95 Both generation and demand would pay DUoS charges based on a regime of entry and exit charges. These would aim to recover all distribution system costs ‘beyond’ the shallowish connection assets plus metering and billing costs and any other relevant business overheads. Entry charges would be paid by embedded generators and exit charges by demand. Entry and exit charges would be differentiated according to voltage and may be applied at different rates for embedded generation and demand.

4.96 A further development might be for the entry and exit charges to recover the cost of providing the capacity at the voltage of connection (i.e. system costs - other than connection costs) and for an additional ‘carriage’ or ‘transportation’ charge to be levied to recover the appropriate proportion of ‘higher’ system costs. This charge might vary according the number of system voltage levels between entry and exit points.

4.97 The approach suggested by the DNO in question advocated a continuation of the supplier-hub principles such that entry, exit and any transportation charges would continue to be levied by the DNO on the licensed suppliers. This would effectively require a re-balancing of distribution system cost recovery from wholly demand-side to charging suppliers in accordance with both the quantity of electricity they put onto the system and the amount they take off.

4.98 There are a number of variations to this methodology which warrant further scrutiny and which are examined more closely in section 6.

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Selection of the options for further examination

4.99 In the light of the comments on the various connection charging options, we have selected the following three approaches for further scrutiny in the next part of the work. This work will use information from a number of real engineering schemes to assess how some of these charging options are likely to fair in practice. This is the subject of section 5.

4.100 The work in section 6 will also explore in more detail, how any new generator DUoS arrangements might work in practice.

4.101 The three options which will be applied to a selection of embedded generation development schemes are listed below together with a brief outline of their principal attributes.

Option A: Shallow connection• Connection charge recovers the cost of the new assets provided for use by the

newly connecting embedded generator only (i.e. ‘sole user’ assets).

• Any other upstream reinforcement costs would form part of the ‘system’ costs and would need to be appropriately allocated and recovered. This might be from:

- demand takers only;- embedded generators only; or- demand and embedded generators (i.e. all users).

Option B: Shallowish connection (simple approach)• Apply similar rules for embedded generation connection costs as currently

applied to demand in respect of upstream connection costs, viz:

- connection charges only include works at voltage of connection and one voltage level above; and

- connection charges only include reinforcement where additional demand exceeds 25% of the thermal rating of the existing network assets (subject to condition above).

• Simple generator DUoS (GDUoS), possibly based on contractual connection capacity (MVA/kVA) - as specified in the connection agreement.

• This GDUoS would simply recover the difference between generator deep and shallow connection costs (on average).

• There would be no tariff support allowance for generator connections and this may also be removed for demand connections.

Option C: Shallowish connection (with wholesale review of DUoS)• This is based on the approach as described in Option 6 above

• Apply similar rules for connection costs as given in Option B, viz:

5 1


- connection charges only include works at voltage of connection and one voltage level above;

- connection charges only include reinforcement where additional demand exceeds 25% of the thermal rating of the existing network assets (subject to condition above); plus

- connection charges would only include switchgear reinforcement work where the newly connecting embedded generator’s contribution to fault level (at the appropriate electrical point in the system) exceeds 25% of the switchgear fault level rating (make and/or break duty)

• Other costs associated with connection of embedded generation would become ‘system’ costs and would be recovered from both demand and embedded generation through distribution entry/exit/transportation charges.

• This would require a wholesale revision of the present ‘GSP down’ charging approach and may introduce a charging framework which:

- re-balances the allocation of distribution costs between embedded generators and demand takers;

- recognises the contribution to total system costs made by individual embedded generators (and demand);

- recognises the significance of electrical location and also the interaction with other demand/generation connections; and

- is consistent in its treatment of demand and generation.• It would be for further examination whether or not the present ‘supplier-hub’

market arrangements should be retained or whether embedded generators themselves should pay any new charges. This may not affect the total end price paid by the customer but may well impact on the competitiveness of each participant in the value chain.

Reference case - ‘deep’ connection charges for embedded generation

4.102 All alternatives would be compared and contrasted to the current arrangements where all of the distribution costs are levied on the demand takers and embedded generators pay full, ‘deep’, connection costs and no DUoS.

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5. EVALUATION OF CONNECTION CHARGING OPTIONS

5.1 This section applies the three broad charging options selected in section 4 to actual project data and examines how they might work in practice. The charging methodologies specified were:

• Option 1 - shallow connection charge with no ongoing DUoS charge;

• Option 2 - shallowish connection charge together with simple generator DUoS charges (shallowish “a”); and

• Option 3 - shallowish connection charge with a wholesale review of DUoS (shallowish “b”).

5.2 This evaluation was made up of two parts. The first was to establish the impact of the ‘upfront’ connection charges on embedded generators under each of the three options. The second was to evaluate the impact of those costs which are not recovered through the upfront capital contribution79.

Methodology

5.3 A sample of 34 real embedded generation projects were chosen. The selected projects included a variety of renewable technologies with export capacities ranging from less than 1MW to around 70MW. Table 2 provides a breakdown of the sample projects by size and technology. Some of these projects are in development and have, therefore, not as yet progressed to construction stage.

Table 2 - Breakdown of sample projects

Installed Capacity

Energy source <1MW 1-5MW 5-20MW >20MW All sizes

Wind 2 5 5 4 16

Landfill gas 3 11 1 0 15

Energy from waste 0 0 0 2 2

Other 0 0 1 0 1

All sources 5 16 7 6 34

These are likely to be allocated and recovered by some other method - most probably through ongoing charges for use of the distribution system (DUoS charge).

5 3


Connection charges

5.4 For each project a breakdown of the connection charge was provided, based on whether the costs related to the provision of sole-user assets80, switchgear replacement or other reinforcement costs.

5.5 Table 3 provides a breakdown of the input data categories provided for each project.

Table 3 - Connection cost breakdown

Cost of sole user assets

At point of connection

Generation spur81

At point of common coupling82

Switchgear replacement costs

At connection voltage

At next voltage level above

At higher voltage levels

Other reinforcement costs

At connection voltage

At next voltage level above

At higher voltage levels

Miscellaneous costs (design etc.)

Operations, Repair and Maintenance (O,R and M) allowance

80

81

82

The ‘sole-user assets’ are those assets which are provided, as part of the connection works, for the use only of the connectee in question.

Predominantly, the lines and cables installed between the generator site and the point of connection to the existing distribution system. This might be several kilometres of high voltage cable or a few meters of low voltage cable in the case where a small generator is established on the LV network.

The point of common coupling is where the assets installed for the sole use of the connectee connect to the existing distribution system. Asset use is shared upstream of the point of common coupling.

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5.6 Using this cost data a spreadsheet was used to calculate the connection charges, that would be applied under each of the three defined charging options. Table 4 provides a summary for each option demonstrating which costs would fall to the generator, together with what generators currently have to pay as part of their connection charge under the present ‘deep’ connection charge regime (status quo).

Table 4 - Connection charges under each option

Status quo(deep)

Option 1(shallow)

Option 2 Option 3(shallow-ish)

Sole user assets yes yes yes yes

Switchgear replacement

At connection voltage yes no yes 25% rule83

At next voltage level yes no yes 25% rule83

At higher voltage levels yes no yes 25% rule83

Other reinforcements

At connection voltage yes no 25% rule84 25% rule84

At next voltage level yes no 25% rule84 25% rule84

At higher voltage levels yes no no no

Application of the ‘25%’’ and ‘voltage level’ rules for calculation of reinforcement charges

5.7 The existing arrangement for new demand connections is that the connectee does not pay for any required system reinforcement where the contribution of the new

83

84

The generator is liable for switchgear replacement costs if (a) the generator’s fault contribution exceeds 25% of the make rating of the existing switchgear AND (b) the generator connection triggers the switchgear upgrade. The make-duty of the switchgear is determined at the time of maximum asymmetry (10ms). It is this make duty to which rotating embedded generation will contribute and which may give rise to ‘over-stressing’ of the existing switchgear and the subsequent need for expensive local upstream replacement.

The generator is liable for reinforcement costs if (a) the generator’s authorised export capacity exceeds 25% of the thermal rating of the existing network assets AND (b) the generator connection triggers the asset upgrade.

5 5


load to the system demand is less than 25% of the electrical capacity85 of the network - at the point where the reinforcement is required. Similarly, a new demand customer’s connection charge should not pay for any reinforcement which is required at more than one voltage level above the voltage ofconnection86.

5.8 Connection Options 2 and 3 assume a similar reinforcement rule for the connection of embedded generation84.

Fault level contribution

5.9 Option 3 assumes a similar 25% rule - but this is applied to the prospective contribution made by the generator to the system fault level. The need to upgrade existing system switchgear due to the increased fault levels can be a significant, and often prohibitive cost, for a prospective generator developer.

5.10 In Option 3 the switchgear replacement rule is that the generator only pays for switchgear upgrades if the fault contribution from the proposed generation scheme exceeds 25% of the make duty of the existing switchgear83. For other reinforcement works, the rule is that the generator only pays for asset up-rating if the generator’s authorised export capacity exceeds 25% of the stated capacity of the existing assets84.

5.11 In the analysis, the fault level contribution from the embedded generator, at the point of connection to the distribution system, was obtained for each project.

5.12 The embedded generator will contribute to fault levels at voltages other than the voltage of connection although this will be reduced by the electrical impedance of transformers and other equipment.

5.13 Due to the relatively high impedance of transformers connected at the lower voltage levels (compared with the larger, upstream, transformers) the fault level contribution downstream is often considerably less than upstream. For the purpose of the analysis, the contribution to fault level at the voltage below the voltage at which the embedded generator is connected, was considered negligible. Therefore, the analysis only considers fault level contribution at the higher systemvoltages87.

85

86

87

This electrical capacity is usually based on the thermal capability of the distribution assets.

Electricity Distribution Standard Licence Condition 4B, ‘Requirement to Offer Terms for Use of System and Connection’ , Section 5(c)(i) and (ii).

The DNOs we spoke to as part of our research confirmed that it was, principally, switchgear upstream of the point of the point of connection which was prone to overstressing and whose replacement was most likely to contribute to high generator connection costs.

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5.14 Studies were carried out to determine the approximate contribution to fault level at the voltages above that at which the embedded generator was connected88. Simple percentage decrement factors were applied to the generator fault levels to decrement the fault level figures accordingly. These are shown in Table 5.

Table 5 - Contribution of fault level to higher system voltages

Contribution to higher voltage levels

Voltage of connection 11kV 33kV 66kV

Contribution at next 75% 33% 33%system voltage level up

DUoS charges

5.15 The potential for the payment of ongoing charges is also included in each of the alternative charging options. These differ under each option whereby:

• Option 1 - no DUoS charges (as at present)

• Option 2 - simple generator DUoS charges89

• Option 3 - the introduction of a new DUoS charging regime to accommodate embedded generation (i.e. requiring a wholesale review of DUoS charging).

Findings

Connection charges

5.16 Of the thirty-four projects used in this analysis, ten projects required upstream switchgear replacement and other reinforcement costs - this is in addition to the installation of shallow connection assets. These particular projects enabled the commercial impact of the various connection charging options to be better explored and, on this basis, formed the basis for the connection charging analysis.

5.17 Figure 6 illustrates how the charges differ under each option for nine of the ten projects. As would be expected the ‘status quo’ option represents the highest cost for each project owing to connection and reinforcement costs having to be paid by an upfront “deep” charge. Option 1 incurs the least connection charge, owing to

88

89

A DNO kindly assisted by running some rudimentary loadflow models to ascertain the contribution to fault level at voltage above, and below, that of connection. This was done using typical data from various sized generators connected at different points of a real model of a DNO network.

This would be very unsophisticated and would aim, primarily, to recover the remainder of any upstream connection costs.

57


this option only recovering the cost of the “sole user” assets. With respect to Options 2 and 3, Figure 6 illustrates that Option 3 incurs a lower charge for more of the projects than does Option 2. Project 19 is shown separately in Figure 7.

Figure 6 - Connection charges for a sample number of projects

350

300

250

1 200

150

100

50

I Status quo ■ Option 1 □ Option 2 □ Option 3

9 13 14Project Number

20 21 22

Figure 7 - Connection charge under the different charging options for Project 19

2,000

Project Number

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Project No.19

5.18 Project 19 was a wind generation project with authorised export capacity of 2.1MVA (2.25MW). For this particular project the charges differ significantly under the three alternative charging options (see Figure 7).

5.19 Under the present policy of deep connection charging, Project 19 incurred costs for switchgear replacement and other reinforcement costs. The total charge amounted to just over £4,000k with the reinforcement and replacement costs accounting for over 75% of the total charge. Under Option 1, the connection charge drops to around £500k, a reduction of 87% compared with the status quo. The reason for this significant drop is due to the connection charge only including sole user assets, which incidentally was a low proportion of Project 19’s total cost of connecting to the distribution system.

5.20 Under Option 2, the connection charge reduces by 74% as compared to the status quo, so that the cost is just over £1500k. Although costs for switchgear replacement and other reinforcement costs at connection voltage (33kV) are included in this charge, the difference under this option is that Project 19’s export capacity does not exceed 25% of the thermal rating of the existing assets at the next voltage level. As a consequence the generator does not incur the replacement charge, which in this case amounted to over £2,600k.

5.21 In addition, since the ongoing costs associated with operations, repair and maintenance (O,R and M) are effectively capitalised and levied as a simple percentage on-cost on the capital cost of the connection assets, the total contribution is further reduced under Option 2.

5.22 Under Option 3, the connection charge is reduced by 81% as compared to the status quo, resulting in a cost of just under £800k. In this instance, costs for other reinforcement costs at connection voltage (33kV) are included but charges for switchgear replacement and other replacement costs at other voltage levels are not included. This is due to the Project 19’s fault contribution not exceeding 25% of the make rating of the existing switchgear and its export capacity not exceeding 25% of the thermal rating (similar to Option 2).

5.23 It should be noted that reductions do not always occur under Options 2 and 3 versus the status quo. For example, Project 7 incurs the same cost for each of these Options90. Although this project did not incur costs for switchgear replacement it did have to pay upfront charges for other reinforcement costs for existing assets at the next voltage level. This was due to Project 7’s export capacity exceeding 25% of the thermal rating of the existing assets at the next voltage level.

This does not include Option 1 since the connection charge in this case only recovers the costs of the ‘shallow’ assets installed for the sole use of the generators. This will virtually always represent the lowest connection option.

5 9


System reinforcement

5.24 The drivers for reinforcement of the distribution system are often different when associated with the connection of embedded generation than for connection of demand. This can affect the application of the 25% thermal reinforcement rule to embedded generation.

5.25 Since, at most positions on the distribution system, demand generally exceeds local generation, the power exported locally is effectively negative demand and is unlikely to trigger system reinforcement. In fact, it more likely to reduce system demand and defer reinforcement costs91 - especially at higher system levels where its output will almost certainly result in a reduction in the ‘downward flow’ from the grid supply point (GSP).

5.26 Where there is a local surplus of generation, then the connection of embedded generation may well trigger reinforcement and only in this situation would the introduction of a 25% thermal capacity rule reduce the connection charge to the generator. However, in such cases, a higher voltage connection may have already have been determined through other factors such as local voltage management issues or fault level considerations.

5.27 Application of the 25% thermal rule is usually, therefore, of limited use to reduce connection charges. The exception to this is as in the special case the project 19 where the vast majority of the costs are associated with reinforcement of the system at higher voltage levels. This is an unusual case.

DUoS Charges

5.28 The second part of this analysis was to determine how the annual use of system charge (DUoS charge) might work in practice. We use two simplified scenarios for DUoS charging. All thirty-four projects were used for this part of the work92.

5.29 The analysis in this section is based on the assumption that any new DUoS charge on export would be levied on the operating embedded generator. In practice, this may not be the case and section 6 develops a DUoS charging methodology based around the present ‘supplier-hub’ principles.

91

92

It should be noted that for the DNO to obtain true benefit from connecting embedded generation, in terms of deferral of capital expenditure, then current network security planning standards (P2/5) must recognise the contribution made by embedded generation. Furthermore, it is likely that commercial contracts would need to be in place to address issues such as redundancy and the provision of network services.

Only ten of the projects exhibited ‘interesting’ connection cost characteristics and were therefore used as the basis for further exploration in the connection charging analysis.

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Simple generator DUoS charges (Option 2)

5.30 This is the least disruptive option of the two and assumes that the connection costs represent the majority of the generator’s liability in terms of the costs or benefits it brings to the distribution network. This approach does not need to affect the existing way in which DUoS charges are calculated for demand customers and could be implemented in a relatively straightforward manner93.

5.31 Under Option 2, the DUoS charge is based on the connection voltage. This approach follows that presently used for demand where the DUoS charge based on the voltage of connection (together with customer class etc). The higher the connection voltage, the lower the charge per unit or kVA demand. Charges at the lower voltages are higher on the basis of connectee requiring to use more of the distribution system.

5.32 Generators having a higher capacity requirement pay more for use of the system - as per the present arrangements for demand. Larger generators, having to connect at higher voltage levels for - possibly for technical reasons - are, therefore, likely to pay a lower charge per unit of output than smaller units connected at the more costly lower distribution levels. This is a direct function of the present DUoS,GSP charging arrangement and will be explored further in section 6.

Wholesale review of DUoS charges (Option 3)

5.33 This option assumes radical changes to the way in which charges for use of the distribution system are calculated. It is based on the introduction of entry charges and transportation charges - but still assumes that charge fall to the embedded generator. This does not consider how demand DUoS charges would be effected. The integration of demand and generation would be required in any new DUoS charging framework and this is also considered further in section 6.

5.34 Under Option 3, the DUoS charge is based on two factors:

• Entry charge level - which uses the project’s export capacity; and

• Transport charge level - which uses the projects’ annual generated energy volume (kWh).

5.35 Similarly to Option 2, the entry charge and the transport charge decrease, the higher the voltage at which the generator is connected. Owing to the addition of

Note that the approach presently favoured and proposed by Ofgem - in advance of a more comprehensive review of DUoS charges at the time of the next distribution price control - is that any generator DUoS charge should be set so as to recover the remainder of any upstream connection costs over a period of time. This approach assumes that the initial cost of connecting the generator represents the full extent of the cost or benefit which the generator might bring to the distribution network. (Ref. Distributed generation: price controls, incentives and connection charging - further discussion, recommendations and future action, March 2002, 26/02).

6 1


the transport charge, the annual DUoS charges are significantly higher for Option 3 than for Option 2 with the average increase being 42%.

5.36 Clearly, the introduction of any new transportation charge would necessitate a complete revision of the charge structure- including a review of demand side participation.

5.37 The way in which new entry (and exit) charges might be developed, and, importantly, how it might integrate with existing demand, is addressed in more detail in section 6 - although this suggested approach is based on the supplier paying both entry and exit DUoS charges.

Assumptions

5.38 In this section, the DUoS charges used for this analysis were based on simplistic indicative figures, their relative values between voltage levels being of more significance than their absolute value. More meaningful absolute values for DUoS would need to be derived from actual system costs. This will also be examined more closely in the next section.

5.39 Figure 8 illustrates how the DUoS charges differ under Options 2 and 3 for each of the projects.

Figure 8 - DUoS charges under Options 2 and 3

□ Option 2 □ Option 3

■—rni—T~li—l~li—T~lrT~ll~

Project number

Total charge

5.40 Using a capitalised cost of the DUoS charge over a fifteen year time span, Figure 9 illustrates the total cost per unit of generated energy over this particular period

62


for each of the three options. This includes both connection and use of system charges.

Figure 9 - Total cost per unit of generated energy for the three options over fifteen years

■ Option 1 □ Option 2 □ Option 3

Project number

5.41 From Figure 9 it can be seen that for all projects there would have been a significant reduction in connection charges under Option 1, that is, a policy based on shallow connection charging with recovery of deep costs from general use of system. However, as discussed in section 4, this option may not be advantageous to the DNO’s, and the recovery of deep costs may have to be allocated on an equitable basis across the relevant participants.

5.42 The next favourable option for embedded generators, for the majority of projects, is Option 2. This is a policy based on shallowish charging with generator DUoS to recover deep costs. Although this Option does recover the upfront cost of switchgear replacement and applies the 25% rule to other reinforcement costs84, the lack of the transport level charge as part of the DUoS charge (see 5.34) ensures that this Option is often lower than Option 3.

5.43 The only projects where this outcome does not apply is for Projects 6,19 and 20 owing to their connection charges not including switchgear replacement costs as a result of the 25% rule83, thereby resulting in a lower overall charge.

Further analysis

5.44 Although this analysis has provided some useful conclusions when determining how these Options could work in practice, many of the projects in the sample had

63


5.45

5.46

94

secured connection offers with no reinforcement costs. This is hardly surprising when one considers that the process of making a formal connection application is a costly and time-consuming process. Moreover, it is of little use to a prospective generator to receive a connection offer which is too high to allow the project to go ahead on a profitable basis94.

Thus, it might be argued that the sample is reflective of the cost signals that are sent out to prospective generators under the present ‘deep charging’ arrangements.

This second phase of such a study could involve a detailed examination of how the connection charge and ongoing charge would operate depending on the voltage level at which the project is connected. For example, a scenario for each connection voltage level (i.e. 11kV, 33kV and 132kV) could be used to determine the least-cost method for providing a connection for the project. This would enable the total costs under each charging regime to be calculated, together with the allocation of these costs to each party.

For this reason, a prospective generator is well-advised to consult with the DNO before making a formal connection application, in order to ensure - by adjusting the capacity or design of the scheme - that the outcome of the formal application process will be positive.

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6. TECHNICAL ISSUES ASSOCIATED WITH THE CONNECTION OF EMBEDDED GENERATION

6.1 To date, the distribution system has essentially been a means of conveying electricity generated by the large transmission connected generation to customers connected to the lower voltage levels. But, as penetration levels of embedded generation increase over time, the function of the distribution system may change significantly. It is likely that the distribution systems will start to become a means of connecting generation and demand - particularly embedded generation and local demand.

6.2 In this section we review the role of the distribution system to date and the way in which it presently functions. The work goes on to explore how the basic function of the distribution network might change as the number of embedded generators increases.

6.3 Although this section principally addresses the technical characteristics associated with the connection of generation to distribution networks, it also considers the present commercial arrangements and discusses how these might need to change as the industry moves forward.

The role and function of the distribution system to date

6.4 Before an effective distribution charging framework can be developed, it is important to understand the purpose of the distribution system - more specifically, its original function and how this might need to change if more embedded generation is to be accommodated.

6.5 For many years the purpose of local distribution networks has been to transport electricity from the grid supply points (GSPs)95 down, in a uni-directional fashion, to end users. Whilst privatisation in 1990 may have introduced a new regulatory framework and a set of new commercial relationships, the physical operation of the system - particularly the distribution networks - has changed very little.

6.6 To date, the distribution businesses’ customers have been the licensed suppliers who require use of the distribution ‘wires’ to transport their product (units of electrical energy) from point of purchase (GSPs) to point of sale - at the end customer’s metering, or exit, point.

6.7 Despite the increase in embedded generation of recent years, the vast majority of power consumed by end customers still originates from transmission connected

The Grid Supply Points (GSPs) are where the distribution networks connect to NGCs transmission network. It is also the point at which wholesale energy is bought by the licensed suppliers for onward sale to end users customers.

65


generators and is still delivered via the transmission system at the ‘top96’ of the distribution network. Consequently, most of the power consumed by demand customers flows down from the ‘top’ of the distribution system to the point at which the demand customers are connected.

6.8 Under these conventional distribution system conditions, delivery of a unit of electricity to a customer connected at, say, low voltage (LV), will require some use of all the distribution assets between the demand connection - through all higher voltage levels - right up to the 132kV where the energy is ‘received’ from the transmission system.

Technical considerations

6.9 There are a number of technical integration issues which have been a significant contributing factor to the way in which the connection of embedded generation has been treated to date and which are likely to continue to represent major challenges as the amount of connected embedded generation increases.

‘Tapering’ of circuits

6.10 The entire distribution system has been designed on the basis of the total network power flows diminishing at each subsequent lower voltage level as demand connections reduce system loading. In many cases, these assumptions have led to network design policies which encourage physical circuit capacities to be reduced as they near demand. This is known as circuit ‘tapering’.

6.11 Tapering can inhibit multi-directional power flow and can, therefore, introduce difficulties for the integration of embedded generation - in particular, accommodating export power. Tapering is usually less of an issue at the higher voltage levels where networks are often more interconnected. At the lower voltage levels, however, (e.g. 11kV and LV) where circuits usually operate radially97, tapering can introduce significant challenges to the connection of embedded generation. Figure 10 illustrates how the power capability of a typical distribution network reduces from the grid ‘infeed’, down through the voltage levels, to the lower levels where the vast majority of demand connections are made. The line thickness on the schematic diagram indicates the current carrying capability.

96

97The 132kV voltage level in England and Wales.

A radial circuit is one which is not normally interconnected with other circuits and is designed and constructed on the basis of power flowing in one direction only (under normal conditions).

66


Figure 10 - Tapering of the distribution network

132kV

33kV

11k#"

D

LV

GRID

D

TDD KEY

* = circuit breaker

= transformer

D = demand

6.12 Figure 11 shows the how, for many years, the ‘tapered’ distribution system has led to uni-directional power flow. A distribution system with these characteristics can represent significant challenges for the connection of embedded generation.

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Figure 11 - Tapering of the distribution network

3

FOUFRfiMw

POtyZRFLOW


68


Protection

6.13 The distribution system comprises a multitude of lines, cables, transformers and switches. In the interests of network reliability and security of supply, the network is effectively sub-divided into groups of components - each of which is controlled by protective devices such as fuses or circuit breakers. The purpose of these protective devices is to detect faults and to remove faulty equipment from the system as quickly and efficiently as possible so that the ‘healthy’ parts of the network can continue to operate.

6.14 Most protection systems have been designed to operate for uni-directional power flows from the ‘top’ to the ‘bottom’ of the system. Connection of embedded generation to the lower network levels can introduce additional protection complexities as the prospect of multi-directional power flows is introduced.

Voltage control

6.15 The distribution networks are designed and operated to ensure that voltages, at each system level, are kept within statutory limits. Management of voltage is an important aspect of DNO operation - particularly in rural areas where load density is lower and distribution feeding distances tend to be longer.

6.16 The connection of embedded generation to rural networks can introduce difficulties in managing the system voltage - particularly where there may be insufficient local demand at certain times of the day98.

System fault levels

6.17 The connection of rotating plant - such as embedded generators - to distribution systems serves to increase the prospective short circuit current, or ‘fault level’ at the point of connection to the network (and also at adjacent voltage levels99). The items of plant and equipment required to perform system switching operations - the switchgear - needs to be able to operate safely under such fault conditions.

6.18 Connection of embedded generation can, therefore, increase system fault levels to the point where the existing switchgear is incapable of operating safely and needs to be changed. This can add significantly to the costs of accommodating embedded generation and often poses problems in urban areas.

98

99

At times when there is insufficient local demand to absorb embedded generator output, the generator voltage may need to rise to unacceptable levels in order to achieve the required level of export. This has been identified by the industry as being a potential barrier to the connection of increasing levels of embedded generation in rural areas - particularly since many renewable resources are located remote from areas of high load density.

Whilst embedded generation (and motors) contribute to the fault level at voltages above and below the voltage of connection, this is attenuated by circuit and transformer impedances.

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‘Fit and forget’ approach

6.19 To date, embedded generation has been merely ‘accommodated’ by the DNOs.The approach by the DNOs has been that connection of embedded generation should not prevent the network from continuing to operate as a traditional ’top- down’ system. DNOs have been of the opinion that embedded generation should not compromise, or threaten, the integrity of a distribution system - whose primary purpose is to deliver electricity from transmission connected generation to end users.

6.20 This premise will need to change if Government plans to achieve greater penetration levels of embedded generation are to be realised.

6.21 Further exploration of the technical challenges associated with incorporating embedded generation into distribution networks is beyond the scope of this work. Many of these issues are, however, now fairly well-defined and are being addressed though a variety of industry fora.

Commercial considerations

6.22 Under the present distribution charging arrangements, all of the cost of providing the distribution service is recovered from the demand takers through DUoS charges which are levied on the licensed suppliers and which form part of the suppliers retail charges.

6.23 It is assumed that all units of energy supplied to load customers flows ‘down’ from the GSP and the costs of the distribution network are calculated and allocated to demand customers on the basis of using part of each higher voltage level - right up to the grid supply point.

6.24 A model is used to calculate and allocate costs. Most DNOs still use the distribution reinforcement model (DRM) - which was developed nationally in the 1980s100.

6.25 Present practice is for DNOs not to charge for use of the system by exporting generators. Neither the generators, nor the suppliers who may purchase the export power, pay for use of the distribution system101. A supplier who buys export energy from an embedded generator for supply to a nearby load is charged, on the energy supplied to the demand, for use of the distribution system - as if the energy had been supplied via the transmission system and GSP. This was also described in section 2 (page 24) and shown graphically in Figure 4.

100

101

A full description of the DRM, together with its operation and application to distribution pricing, is given in section 2.

Note that suppliers do pay distribution use of system charges (DUoS) on import at generation sites. This charge will usually comprise, principally, of available capacity charges but will also include unit charges levied on kWh consumed.

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6.26 The current regime of charging does not recognise the true impact which embedded generators may have on the system - both in the long term and the short term. In energy retail terms, embedded generation export is currently treated simply as a means of reducing the amount of wholesale electricity the supplier has to purchase at the GSP.

6.27 Figure 12 shows the present commercial arrangements where suppliers pay exit charges on the basis of all energy being supplied from the transmission connected generators.

Figure 12 - Present arrangements are for suppliers to pay exit charges only

132kV

33kV

llkV*

LV

Oj) GRID

▼ D ▼SUPPLIERPAYSDEMANDDUoS

KEY

X = circuit breaker

= transformer

D = demand


71


The basic function of the distribution network will change

6.28 An increase in the number of embedded generators means an increase in the number of sources from which suppliers can purchase energy for retail sales. Although the transmission system is presently the principal source of supplied electricity, there is likely to be a shift towards the GSP being just one of a multitude of sources from which power can be collected and transported to connected demand.

6.29 It has been recognised by the industry that these changes in the function of distribution systems will have significant impact on distribution networks in two main areas:

• technical integration of increasing levels of embedded generation; and

• commercial arrangements associated with costing and pricing for connection and use of the system.

Technical developments

6.30 Increasing levels of embedded generation will require significant changes to the way in which the distribution networks operate. In fact, the local distribution networks are likely to start to behave more like low voltage102 transmission networks - characterised by multi-directional power flows linking local generation and local demand.

6.31 The increased levels of embedded generation, coupled with the fact that the existing distribution system is designed to facilitate power flows in some directions but not in others, may mean that not all connections to the system are able to export, or import, maximum power103 all of the time.

6.32 Participants are likely to be constrained in the extent to which they can transport power from one part of the network to another. This characteristic of limited power flows is likely to become much more of an issue as the number of generators increases and will varying according to geographic (and electrical) location of local demand and local embedded generation.

6.33 The increased number of network constraints is likely to lead to a concept of active management of distribution networks.

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103

The ‘traditional’ distribution network voltage levels in England and Wales of 132kV down to 400/230V (low voltage).

Maximum power is likely to be defined by the terms of the connection agreement and will be the contractually agreed available capacity (kVA or kW) for both demand and generation.

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Active management of distribution networks

6.34 A detailed discussion on active management of distribution networks is beyond the scope of this project work on charging principles. Nevertheless, it is worth briefly mentioning the high level concept since it may well, in future, impact upon charging principles for connection and use of system.

6.35 The basic idea of active management of distribution systems is the development of a network regime where the contribution from both generation and demand - to both network performance and customer service - is considered daily, or even on an hourly, basis. This would be a significant and material departure from the current ‘fitand forget’ approach currently adopted.

6.36 Active management of distribution networks could involve a wide range of realtime network management control and information acquisition techniques but at the very minimum is likely to involve:

• controlling the active power104 output of embedded generation;

• controlling the reactive power105 output of embedded generation; and

• real-time control of transformer tap-changers106.

6.37 The concept of active network management is to monitor, control and regulate a number of key parameters - on a real-time, or near real-time107, basis such that the distribution network can be made more receptive to the connection of embedded generation.

104

105

106

107

Control of active power (watts) allows the thermal loadings of distribution lines and cables to be controlled and would therefore provide a means of managing network constraints.

Control of reactive power (VARs) facilitates the management of system voltage - this is an important consideration when connecting distributed generation to relatively weak, rural, distribution networks.

Tap-changers are usually fitted to, or are an integral part of, power transformers. Their function is to change the transformer winding ratio in order to control the secondary terminal voltage. Large transformers, connected at the higher voltage levels, are usually fitted with tap-changers which can be operated whilst the unit is electrically loaded. Smaller transformers, connected at the lower voltages, are usually fitted with off-load tap- changers - these are not capable of being operated whilst the unit is under load. It is likely that any active network control will require on-load tap chargers. Consequently, unless the transformers connected at low voltage are either replaced or retro-fitted with on-load tap-changers, this aspect of active network management would need to be focussed on the larger transformers connected at, say, 33kV and 132kV.

Real-time actions would suggest monitoring and control on a continual basis. Near real time might mean that monitoring and corrective action is undertaken on a periodic basis. This might be as frequently as every half-hour or could mean changes to network parameters on a daily or even on a seasonal basis.

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6.38 It may be that in order to fully exploit the potential benefits of active network management, the topology of distribution systems are likely to change with networks becoming much more interconnected. These interconnected, or ‘meshed’, networks will significantly increase the level of connectivity between demand points and generation points and, under this scenario, would replace the present, predominantly radial, distribution network design and operation.

Provision of network services

6.39 The development of active networks may introduce new opportunities for participants to provide services to the DNO, or to other participants, as part of the integrated operation of the distribution system.

6.40 Whilst there will be occasions when both generation and demand connectees require the services of the distribution system for the delivery, or the consumption of energy - there may be other times when, for example, a particular generator might be able to assist in resolving constraints or in managing system voltage profile.

6.41 Alternatively, embedded generation may have a role to play in enabling local demand, or even other local generation, to have access to the local network through operating at specified times of the day in order, for example, to relieve local constraints.

6.42 In a fully developed and integrated distribution system one might also expect demand connectees to be able to provide similar network services - perhaps to permit a local generator to increase export levels or to enable a nearby demand site to increase its load. However, given the technical characteristics of generation sets - and their commercial focus - it may be that embedded generators are able to provide a wider range, of more flexible services, than those which could be provided by demand.

6.43 It is likely that these services would be provided to the DNO, as operator of the network, and the DNO would be required to coordinate providers and customers in order to deliver the necessary levels of service. The DNO’s responsibility might be to operate the distribution network - not only to fulfil statutory requirements but also to deliver any ‘special’ service standards which might have been agreed with individual participants.

6.44 Furthermore, it may be that any alternative customer/service provider framework, based on bi-lateral agreements, would still need to be coordinated and managed by the distribution network operators - as facilitators and distribution licence holders.

Security and availability of supply

6.45 If embedded generation is to provide network services which are of value to the DNOs then arrangements will need to be put in place to ensure that generators are treated in a way which is consistent with both transmission connected generation (via the grid supply points) and the distribution network assets themselves.

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6.46 This is particularly important for quality of supply issues - such as security and availability of supply108 - where the opportunity may exist to develop a competitive services marketplace.

6.47 Local, embedded, generation is likely to affect, or at least have the ability to affect, the quality of supply experienced by other connectees. For example a embedded generator may be able to offer services to improve the availability of supply to other local customers - by maintaining supplies during unscheduled outage conditions for example. In this case the DG may be able to earn payments from the DNO for providing a service which other customers either want, or are entitled to, and which would otherwise cost the DNO to provide through other means.

6.48 Conversely, connecting some generators may serve to introduce additional series elements in the reliability chain - effectively increasing the probability of failure of supply to other connectees. In these cases, DG might expect to pay according to this additional cost which it may place on the DNO.

6.49 In time, and with appropriate recognition and commercial contracts, embedded generation may be able to compete directly to enhance network security and system availability.

6.50 Network security and availability of supply are likely to continue to be important distribution system attributes for all connectees - be they generators or load- takers. To date, security and availability have been focussed on demand customers - and the DNOs are set targets for the delivery of each of these output measures based on loss of load.

6.51 A connected embedded generator, wanting to export energy for sale, is also a distribution customer. It is for debate, but beyond the scope of this particular piece of work, whether the value of access to the distribution system is symmetrical across demand and generation connectees, or whether the value placed on supply security and/or availability is different for generators and demand customers.

Network security is a measure of the number of interruptions experienced per group of connected customers. In the UK, this is normally measured in the number of interruptions per 100 connected customers. Network availability is a measure of the firmness, or reliability, of the supply - this is often measured in customer-minutes lost (duration of interruption times the number of customers affected). In addition, Ofgem has recently introduced a new service standard associated with multiple interruptions. From April 2002, DNOs are targeted to ensure that a specified percentage of their customers do not receive more than five interruptions which last more than 3 minutes. For most DNOs this target percentage of customers is 98%. London has a target of 99% with NEDL, WPD and Scottish-hydro having a lower target of 96%.

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6.52 Much work has been carried out on the value which customers place on supply attributes such as availability and security109. Any future considerations will have to include the impact of embedded generators - particularly as numbers increase.

Commercial developments

6.53 Development of a commercial framework, which accommodates both demand and embedded generation on a fair and equitable basis, has been recognised by Ofgem as being an industry priority if embedded generation penetration levels are to rise to meet Government targets over the next 10 years and beyond110.

6.54 The present DNO practice of ‘commercially ignoring’ embedded generation after connection cannot continue if penetration levels are to continue to increase and Government targets met. The industry is now debating how charging principles might need to develop if generators are to be encouraged to connect and the contribution made by local generation is to be recognised and appropriately rewarded (or penalised) 111.

The value of locally produced energy

6.55 It has long been accepted that a kWh of energy produced locally (to the demand it supplies) has a higher value than a kWh of energy generated by transmission connected generation which may be located hundreds of miles away from the load. This is because by generating locally the costs associated with transportation of electricity is avoided. Despite this, present industry arrangements and distribution pricing practice do not recognise the costs or benefits accruing from connecting generation in close electrical proximity to demand.

6.56 As more generation connects to distribution networks and the system becomes more of an energy transport ‘mesh’ - connecting generation (of all sizes) with demand - then the basis for distribution charging may have to move away from one of network provision to one of true network use.

109

110

111

Professor Ron Allan at UMIST is a recognised world expert on reliability studies and has undertaken a significant amount of work, over many years, on ‘customer worth of supply’.

After consultation, Ofgem have decided that a wholesale review of distribution use of system charges can only take place as part of the next distribution price control review (ref. “Distributed generation: price controls, incentives and connection charging - Further discussion, recommendations and future action”, Ofgem, March 2002, 26/02).

A work stream to address commercial and charging issues was established in Feb 2002, under Ofgem’s responsibility, and as part of the Distributed Generation Technical Steering Group, to address the issues associated with charging generator for ‘use’ of the distribution network.

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Security of supplies

6.57 The security ‘safety net’ - traditionally provided by the grid connected distribution assets - is likely to change with embedded generation and active network management being used to complement the capabilities of the existing network to provide connectees with the level of security they require. Charges will begin to reflect the actual costs and benefits which individual demand and generators bestow on the system (and on its users) and also the level of security and availability - both required and provided.

Cost and complexity

6.58 A commercial pricing system which will address these new challenges - and one which has the potential to accommodate embedded generation - has the potential to be complex and expensive. However, once the base cost and price information has been derived, the level of complication could be reduced by grouping and averaging at the expensive of cost reflectivity.

Long-term investment signals

6.59 Any new commercial arrangements for use of the distribution network must consider the impact that any short term price signals will have on long term investment. Recovering the costs of existing network assets is also an important consideration.

6.60 For example, if the distribution network is to migrate from the ‘top-down’, unidirection, traditional, topology towards a multi-directional, highly interconnected ‘transmission style’ mesh, then the level of redundancy in the upstream assets may begin to increase.

6.61 If the basis for distribution charging were to change to reflect the actual use of system, and the cost of providing these upstream assets was recovered only from those using them, then the charge per unit (or kVA) for use of these assets may increase. This price signal might further encourage the connection of embedded generation at the lower voltage levels and for demand to locate nearer to generation.

6.62 The potential for stranded costs and, more importantly, who such costs should be attributed to, and recovered from, may become an important regulatory consideration.

6.63 In the long term, the DNO might be encouraged not to invest in the upstream assets. The security issues associated with a distribution network capital investment programme driven by commercial market forces would also have to carefully considered by the industry as a whole.

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7. POTENTIAL APPROACH TO A NEW ‘UNIVERSAL’PRICING REGIME

7.1 In this section we address the more challenging issue of the development of a distribution charging framework which can accommodate both demand and embedded generation. The work develops, at a conceptual level, some ideas of how such a DUoS charging framework might look and how it might work in practice.

7.2 Such a charging regime would aim to do more than just recover the balance of connection charges and would need to recognise the extent to which embedded generators (and demand) contribute, not only to distribution system costs, but also to system security, quality of supply and power quality.

7.3 The DUoS charging methodology suggested is based upon the concept of entry and exit charges. The underlying principles are illustrated with the aid of a simple example of connecting both generation and demand at 11kV in a simplified, but typical, distribution system. Realistic costs and other system factors are used to arrive at an example DUoS tariff.

7.4 Many of the ideas explored in this section are founded on concepts already being developed within in the industry - some of which were discussed with the DNOs who kindly contributed to the research.

The entry-exit charge concept

7.5 Charges are levied not only for electricity which leaves the distribution network - as at present for demand takers - but also for electricity which enters the distribution network. Under this arrangement, the grid supply point (GSP) - where electricity had traditionally entered the distribution system - becomes one of a number of entry points. Embedded generators are also acknowledged as network entry points and are treated on a consistent basis with the GSPs.

Maintain the supplier-hub principles

7.6 As was described in section 1, the present industry arrangements are for the supplier to deal with the end customer (demand) and for distribution use of system charges to be levied by the DNO onto the supplier. This is known as the ‘supplier-hub’ principle since the supplier sits at the centre of, and deals with, all other participants - including the DNO and the end customer. These supplier-hub principles were established during the final stages of supply de-regulation in 1998/99.

7.7 Any new DUoS charging framework based on the entry-exit methodology could continue to operate under the supplier-hub arrangements. Instead of the DNO charging the supplier DUoS only on the electricity taken off the system -the

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supplier would be charged DUoS both on entry to, and exit from, the distribution network.

7.8 An alternative arrangement, and one which was examined in section 4, is to levy the export charge on the generator. The likelihood is that this additional cost on embedded generators would be reflected in an increase in export prices.

Broad principles of the new DUoS tariff

7.9 Under this arrangement there would, of course, be a rebalancing of network costs such that, in general:

• entry (generation) charges should be lower in demand-rich zones but higher in areas with a deficit of demand;

• exit (demand) charges should be higher in demand-rich but lower where there is a surplus of generation; and

• exit charges are equal to, or lower than, the present demand charges;

7.10 Both entry and exit charges could be negative - that is, under certain circumstances, suppliers might be paid for taking generation, or for supplying demand.

7.11 Suppliers would be discouraged from:

• supplying exit points where there is:

- a deficit of generation; or- an existing surplus of demand

• buying from entry points where there is:

- already a surplus of generation; or- a deficit of demand.

7.12 The basic concept of supplier based entry-exit charging is shown in Figure 13.

7.13 Distribution system users might expect to pay lower use of system charges where local demand and local embedded generation is well balanced. If all suppliers were to balance their own positions at each level of the distribution network then local surpluses of generation and demand would be minimised and use of the distribution network would also be minimised.

7.14 Whilst it would be possible to establish entry and exit charges for each individual connection node, the complexities mean that this is unlikely to be economic and tariffs may well be set according to connection type (e.g. industrial, commercial, domestic) and a number of broad tariff zones. These may well be set according to voltage level of connection - as at present for demand.

7.15 Furthermore, it might be possible to set charges on monthly, weekly or even daily basis. Distribution charges could be set on a seasonal-time-of-day (STOD) basis

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to discourage use of the network at times of system peak - since this represents the principal cost driver for distribution networks. Again, the costs of designing and implementing such a system versus the benefits to the industry - would need to be carefully assessed.

Figure 13 - Introducing entry and exit charging

GRID

132kV

SUPPLIER PAYS iNTRY CHARGE

33kV

1 lkV <

DistributedGeneration

SUPPLIER PAYS EXIT CHARGE


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7.16 Figure 14 shows how the entry-exit point concept could be extended to recognise multiple points of entry through the connection of embedded generation to the distribution system. Each licensed supplier paying both entry or exit charges on the electricity bought and sold.

7.17 With reference to Figure 14, the suppliers would pay entry charges for all of the electricity it takes from generator sources (marked as green connection points in the diagram) and would pay exit charges for all electricity supplied via demand connections for which it was commercially liable.

7.18 Under this multiple entry-exit point scenario, suppliers would continue to pay for electricity taken from the grid - but the volume taken may be decline over time if suppliers choose to purchase energy from embedded generation. This may be the case if, due to their electrical location, embedded generators attract lower distribution (entry) charges than the grid.

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Figure 14 - Multiple entry points with embedded generation


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Potential tariff structures

7.19 There are a number of ways in which any new DUoS tariff, which incorporates embedded generation, could be structured. The present arrangements recognise that the cost of ‘local112’ assets are driven by power demand (kVA, MVA) whereas the costs associated with the remote assets have less correlation with connection demand requirements.

7.20 Under the present arrangements for demand, these ‘higher’ system costs are recovered through an energy utilisation, or unit volume, charge - typically levied on a p/kWh basis. This present charging concept was described in some detail in section 2.

7.21 This established approach to the recovery of distribution costs could be applied to the costing and pricing of distribution systems which including embedded generation.

7.22 In addition to the entry and exit charges, the new DUoS tariff could include an additional transportation charge to recover ‘higher system’ costs113.Alternatively, the entry and exit tariff could each comprise both demand based and unit-based element to recover appropriate network costs - similar to the present approach adopted for non-domestic demand charges.

Network costs

7.23 The majority of DNOs still use the Distribution Reinforcement Model (DRM) as the basis for calculating and allocating the costs associated with the provision of network capacity. This cost-based approach was described in some detail in section 2 of this report. To our knowledge, only one DNO has moved away from the cost-based DRM approach to one based on the regulatory price control formula114.

7.24 A DUoS charging methodology based on entry and exit charges could use the same cost basis as the present, demand-based, approach.

112

113

114

‘Local’ assets are defined as those being electrically close to the point of connection. Distribution assets at the voltage of connection are classed as ‘local’ whilst the 132kV network assets, when considering, say, a 11kV connection, would be classed as ‘remote’.

This was described as part of ‘Option 6’ in section 4 of the report.

This was DNO A whose approach was described in Section 3 of this report. (Ref. ‘The Structure of Electricity Distribution Charges - Initial Consultation Paper’, Ofgem, December 2000. Appendix, section 3.7.)

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Practical example of a new DUoS charging methodology

7.25 A very simple network connection example is used to illustrate how a DUoS tariff, which incorporates embedded generation, could be constructed using the existing DRM cost information.

Description of basic model

7.26 The basic model comprises a simple schematic representation showing the following voltage levels and transformation stages:

• 132kV;

• 132/33kV;

• 33kV;

• 33/11kV; and

• 11kV.

7.27 The examples consider connecting both generation and demand at the 11kV level and develops thoughts on how 11kV entry and exit charges might be determined under two basic scenarios:

• a demand-rich 11kV system; and

• a generation-rich 11kV system.

7.28 These are shown in Figure 15 and Figure 16 respectively.

7.29 Above the 11kV level, both test networks are identical - mostly comprising one or two blocks of demand at each of the higher voltage levels. The example considers the potential impact and costs imposed on the system of connecting at the 11kV level only. Costs may be both positive or negative (i.e. a perceived economic benefit).

7.30 Although a single existing generator is connected at the 132kV level, this is included for the purpose of modifying load flows and is not considered in the charge considerations.

7.31 Each single generator or demand block is assumed to export or import one unit. This gives rise to simple network load flows which can be used to assess the contribution of the various 11kV connections on the rest of the distribution system.

7.32 The extent of network loading is indicated in the two Case diagrams using red chevrons. Each chevron represents the load flow resulting from a single generator or demand block - and so the greater the number of chevrons the higher the loading on that particular part of the test network. Losses are not considered.

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Costs

7.33 Each of the five network levels have been populated with typical costs - as might be obtained from a DNO’s pricing model (DRM). Costs for both simultaneous maximum demand (diversified) and aggregate maximum demand (un-diversified) were obtained.

7.34 As for the present approach for calculating demand charges, aggregate maximum demand (AMD) was used as the basis for the costs at:

• voltage of connection;

• transformation to next level; and

• 20% voltage level above

7.35 simultaneous maximum demand (SMD) was used as the basis for calculating the costs:

• 80% voltage above; and

• all other upstream costs

Co-incidence factors

7.36 Typical co-incidence factors were used. These were, again, obtained from a DNO DRM. These were the co-incidence factors as ‘viewed’ from the 11kV connection level and represent the extent to which the connection’s maximum demand, or maximum generation export, coincides with the peak demands occurring at the higher system levels.

7.37 Since the costs of the 11kV assets will not depend upon the extent to which the individual connectee’s maximum requirements coincides with the local system demand, it is assumed that the coincidence factor at the 11kV level is unity (1.0).

Other assumptions

7.38 There were a number of assumptions made as part of this simple modelling exercise. These are as follows:

• a power factor of 0.95 was assumed when converting between £/kWh/month figures and p/kWh rates;

• demand was assumed to have a load factor of 30% at 11kV and 50% at all other voltage levels;

• generation was assumed to have a load factor of 95% (based on the assumption of a 5% forced outage rate);

• it was assumed that where the connectee was in the minority in terms of whether it was export or import (e.g. a generator in a demand-rich zone), then

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the contribution to the cost at the 33/11kV transformation level was deemed to be zero115;

• the benefit derived from connecting generation at the 11kV level in a demand- rich zone increases linearly from zero at the 33/11kV transformation level to minus 0.95 at the 132kV level116; and

• the model looks at the connection of one type of demand at one point of the system and does not consider the complexities which might occur with many more connection throughout the system.

Case 1 - Demand-rich 11kVsystem

7.39 Figure 15 shows Case 1 where the 11kV system is demand-rich. A generator having one unit of output is connected to the 11kV bars as shown.

7.40 As a direct result of the significant downward flow of power the 11kV generator reduces power flow in all parts of the network above its point of common coupling.

7.41 At each of the network sections, the red chevrons show the flow of power. It can be seen that in all parts of the network above 11kV, there would be one more red chevron if the generator connected to the 11kV bars was disconnected.

7.42 The table to the right of the diagram shows the contribution to the total DUoS charge made by each level of the network - according to the impact that the 11kV connected generator has at each point in the system. This is repeated for both a generator and for a demand connection at 11kV. The total 11kV DUoS charge is given at the bottom of the table and comprises both a £/kVA/month capacity charge together with a p/kWh unit charge.

Entry charges

7.43 In this case, whilst the supplier incurs a positive contribution to the total entry (generation) charge at the voltage of connection (of £0.41/kVA/month) - since here it is contributing to 11kV costs by virtue of its export connection - it is credited at 33kV due to its demand reduction effects.

7.44 In fact, in this case, the generator might expect to pay capacity charges of £0.36/kVA/month but to receive a credit of 0.11p/kWh on all energy exported -

115

116

This assumption is made on the basis that whilst the output mode of the connectee might well assist in reducing transformer loading, system security requirements mean that in practice the transformer must still be capable of supporting the demand (in the case of a demand-rich zone) and so no cost credit is given to the generator.

In practice, studies could be carried out to arrive at a more accurate assessment of the benefit obtained at the higher voltage levels - this linearisation is a first-order approximation.

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by virtue of its position and its tendency to reduce the costs associated with utilisation of the upstream assets.

Exit charges

7.45 Conversely, demand connected to the demand-rich 11kV system would continue to attract substantial charges for use of the entire system - similar to the present arrangements. The table shows that in our simple modelling exercise this would be £0.88/kVA/month together with a unit charge of 0.19p/kWh.

Grid entry charges

7.46 Supplying the surplus demand connected to the 11kV system would also require the supplier in question to pay entry charges for collecting the electricity from some other point on the system. The most expensive scenario, under case 1 would be for power to be collected at the grid and delivered to the demand-rich 11kV voltage level.

7.47 The generation surplus at the grid would give rise to relatively high entry charges - this would attract demand to connect near to the grid and encourage generation to connect at system levels where there was surplus demand.

7.48 The cheapest scenario would be for power to be collected in an area where generation is scarce and delivered to a zone where there is a surplus of generation.

7.49 For the practical reasons already discussed, price signals would need to be set, probably, on an annual basis - and so the locational signals may take sometime to ‘filter through’.

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Figure 15 - Case 1: DUoS charges for a demand ‘rich’ scenario

CASE 1 Capacity element Unit charge

Demand Gen Demand Gen

132k\

E

0X GRID

0.00 0.00 0.05 -0.05

*D ^ ^ Y

132k\33kV

' d iF

▼

1 El 0.00 0.00 0.08 -0.03

33kV0.04 -0.05 0.06 -0.03crrOB'

fff

aD

, t33kV,llkV

>

0 0.43 0.00 0.00 0.00

llkY

a a-

0.41 0.41 0.00 0.00][ □ 1$)EXIT ENTRY EXIT ENTRY

Total 1 lkV DUoS tariff charges

0.88f/kVA/month

0.36f/kVA/month

0.19p/kWh

-0.11p/kWh


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Figure 16 - Case 2: DUoS charges for a generation ‘rich’ scenario

Capacity element Unit chargeCASE 2Demand Demand

GRID

132kV

132kV/33kV

33kV

33kV/llkV

ENTRYEXIT EXITENTRY

0.95f/kVA/month

0.37f/kVA/month

Total 1 lkV DUoS tariff charges


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Case 2 — Generation-rich 11kVsystem

7.50 Figure 16 shows Case 2 where the 11kV system is generation-rich. This might be the sort of scenario which may begin to develop as renewable technology projects begin to ‘cluster’ at particular places on the distribution system117. A load having a requirement of one unit of import is connected to the 11kV bars as shown.

7.51 Being a generator rich zone the unit of demand is supplied by the adjacent generation. However, the dearth of demand mean that the generation is forced to export up the system - increasing costs at the lower voltage levels as it does so118.

Power flows

7.52 Since there is more demand than generation at the higher voltage levels this surplus export is soon diminished. In Figure 16 it can be seen that whilst the 33/11kV transformer (between points ‘A’ and ‘B’) is significantly loaded with export power119, this reduces to a single red chevron between points ‘B’ and ‘C’ due to the unit of demand connected to the system at position ‘B’.

7.53 The two units of demand connected to the 33kV system at position ‘C’ causes the power flow in the 132/33kV transformer (connected between points ‘D’ and ‘C’) to reverse and flow downwards from the grid in the traditional manner.

7.54 The contribution to the total costs (and hence the contribution to the 11kV tariffs ) are again given in on the right of the case two diagram. The change of power flow half way down the system introduces some interesting commercial conditions.

Costs

7.55 As in Case 1, charges are levied at the 11kV level at a £/kVA rate based on aggregate maximum demand (AMD). Again, no charge credit is given for the 11kV demand at this level - despite there being a surplus of generation - since connection of the unit of demand is unlikely to give rise to a cost saving.However, at the 33/11kV transformation level the demand connectee is deemed not to introduce additional costs since the transformer has to be sized to

117

118

119

This is likely to be a function of the renewable resource but could also result from planning consents or particular network attributes such as favourable voltage or fault level conditions.

This can happen on rural distribution feeders - particularly at night time when the local demand can reduce significantly leaving the local embedded generator with insufficient load to absorb its export locally. The consequential increased voltage levels can prohibit connection.

Although beyond the scope of this project on charging principles, it is appreciated that reverse power-flows can introduce material technical difficulties associated with the protection and control of lines, cables, transformers and switchgear.

9 1


accommodate the three units of generator export. The generator, however, is charged capacity charges here since:

• the asset costs are demand-driven; and

• the generator is deemed to contribute to the peak demand requirements of the transformer - based on a co-incident factor of 0.95120.

7.56 At the higher system levels, the power flow begins to reverse and the benefits between a generator and a demand, connected at 11kV, are reversed. The downward flow of power from the grid to the 33kV side of the 132/33kV transformer (points ‘E’ to ‘D’ to ‘C’ in the diagram) means that the 11kV demand (the effect of exit connections) begins to pay a positive p/kWh charge at these levels.

7.57 However, the additional demand connected at levels above 11kV (but below the 132kV and 132/33kV levels) means that the three generator units connected at 11kV are beneficial and attract charge credits at the top of the system.

Exit charges

7.58 The result is that, under this simple modelling, demand connected in an 11kV generation rich zone would pay a total of £0.37/kVA/month together with a unit charge of 0.07p/kWh.

Entry charges

7.59 Conversely, the 11kV generation, pays a capacity charge element of £0.95/kVA/month but still receives a credit of 0.02p/kWh for every unit exported in recognition of its contribution to load reduction at the higher system levels.

7.60 Table 6 provides a summary of the charges for both generation and demand in each of the two cases.

Based on the assumption that the generator has a forced outage rate of 5%. This means that the generator cost is slightly higher than the equivalent demand cost in Case 1 since this was based on a co-incident factor of 0.85.

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Table 6 - comparison of DUoS charges for Cases 1 and 2

11kV modelled DUoS charges

Demand (EXIT) Generation (ENTRY)

Case Capacity Unit Capacity Unit(£/kVA/month) (p/kWh) (£/kVA/month) (p/kWh)

Demand-rich (“A”) 0.88 0.19 0.36 -0.11

Gen rich (“B”) 0.37 0.07 0.95 -& 02

7.61 A table proving detail of the full analysis is given in Annex B.

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8. CONCLUSION

8.1 The application of charging principles associated with the connection of embedded generation to distribution networks can be a major factor in the commercial viability of small embedded generation schemes. This project examines the principles adopted by the Distribution Network Operators (DNOs) in setting charges for use of, and connection to, the distribution system.

8.2 It will necessarily include an examination of the treatment of demand connections and how this compares and contrasts with arrangements for the connection of embedded generation. The work focuses on the electricity distribution businesses of England and Wales.

8.3 After critically examining a number of alternative charging options, the work tests three options using cost and technical information obtained from a selection of real embedded generation connection schemes.

8.4 The work goes on to explore how a new Distribution Use of System (DUoS) charging framework might be developed to accommodate embedded generation. This would have to compliment any to change to the connection charging methodology. Typical distribution system costs, and other network characteristics, are used to illustrate the revised charging framework through use of a simple system model.

A new approach to charging

8.5 Changes to the present approach to charging for connection and use of the distribution system would seem inevitable if Government targets for increased levels of embedded generation are to be met. A revision to the charging arrangements for connection, together with a wholesale review of the DUoS charging methodology, will, almost certainly, be required.

Connection charges

8.6 The work in section 5 used real engineering schemes to evaluate the potential impact of three different connection charge policies.

8.7 It is no surprise that adoption of a shallow connection policy - where the developer pays only for the new assets installed for the sole use of the generator - gives rise to the lowest overall connection cost and would therefore be most attractive to embedded generation. This was shown to be the case for all projects we studied.

8.8 Whilst a entirely shallow connection charging policy may be attractive to the generator developers, it may be more appropriate to adopt a shallow-ish approach - where any upstream reinforcement costs are limited according to prescribed rules.

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8.9 Option 2 uses a policy based on this shallowish charging with simple generator DUoS to recover deep costs. For the majority of projects, this was shown to be the next favourable option for embedded generators.

8.10 In addition to the ‘25%’ and ‘voltage above’ rules applied to demand connections, the introduction of a similar 25% rule for the contribution to system fault levels might be appropriate for generators. The costs of upgrading switchgear, as a result of increased system fault levels, is often a major component of generator connection costs and can often prevent the scheme from progressing.

8.11 Option 3 involved a wholesale review of DUoS but applied such a ‘25% rule’ to switchgear replacements costs. The additional kWh-based ‘system’ charges under this option meant that it represented a higher overall cost to the generator than Option 2 - for the majority of projects.

8.12 Adopting a shallow-ish approach would reduce generator connection costs whilst maintaining some locational price signals in terms of connection location.

Suggested approach for a new methodology for use of system charging

8.13 It is recognised that whilst a shallower connection policy might be more attractive to generators, this would need to be complimented with a revised DUoS charging framework which was capable of reflecting the cost impact of generation. Furthermore, any new DUoS charging arrangements must recognise the interaction between supply and demand.

8.14 The need for changes to, or at least a full-scale review of, the basis for DUoS charges is recognised by the industry.

8.15 If the contribution from embedded generation is to be properly recognised then the present GSP-based DUoS arrangements must change. It is suggested that there is move towards an entry-exit regime whereby suppliers pay DUoS charges for both entry to, and exit from, the distribution network. The GSP would become just another entry point.

8.16 Under this approach, the ‘supplier-hub’ principles would be maintained - this would continue to limited the number of counter parties with which the DNO would need to contract for use of the system.

8.17 Entry and exit charges would be set so as to discourage suppliers from supplying exit points (demand) where there is either a deficit of generation or an existing surplus of demand, or from buying electricity from entry points where there is already a surplus of generation or a deficit of demand.

8.18 Under this regime, embedded generators might give rise to negative costs where they are expected to reduce network costs. Embedded generators connected at the lower voltage levels may be credited for their cost reduction impact at the ‘higher’ system levels.

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8.19 Since network costs at the local level, near to the connection point, are always likely to be positive, the net result, in such circumstances, may be a reduced overall DUoS charge - perhaps with a positive capacity charge but with a negative unit charge.

8.20 In our view, there would be a need for demand to be treated, conceptually, in the same way - although appropriate charge weightings might be applied in the ‘early days’ to support Government targets.

8.21 There would seem to be no reason why the existing DRM could not be used as the basis for the calculation and allocation of distribution system costs - these would still be required under this revised entry-exit charge approach. Significant changes would, however, need to be made to the existing models to reflect the new way in which DUoS tariffs would be compiled.

8.22 As the number of embedded generators increase, and new charging principles develop, it is likely that the distribution networks will become more akin to low voltage transmission systems. The GSP to LV power flow issues on distribution networks may provoke similar discussions to those associated with the north- south flow of power on the transmission systems. Zonal pricing of distribution networks may also evolve.

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ANNEX A: CONSULTATION WITH SELECTED DISTRIBUTION NETWORK OPERATORS - PROMPT QUESTIONS

The following questions were sent to the selected DNOs in advance of ourconference calls. This acted as an aid memoir and a basis for the discussion.

• Is the DUoS charging structure approach described in the Dec 2000 Ofgem consultation paper (ref: http://www.ofgem.gov.uk/docs/elecdistcharges.pdf ) still valid for your company?

• Has there been any variations or other recent changes?

• How has the DRM evolved over recent years?

• How often are the cost inputs reviewed? how do the yardstick outputs compare with allowed revenue?

• To what extent do the existing charging arrangements facilitate the connection of embedded generation?

• How should the impact of EGs on the distribution system be reflected in the charging principles? should there be a re-balancing of distribution costs between participants?

• Which of the charging options suggested by the Embedded Generation Working Group (EGWG) do you support?

- Option 1: status quo;- Option 2: shallow EG connection with all reinforcement costs being paid

by load customers;- Option 3: shallow EG connection with all reinforcement costs being

shared by all parties;- Option 4: shallowish EG connection with all reinforcement costs being

shared by all parties; or- Option 5: shallowish connection charge for smaller generators, site-

specific charges for larger generators.

• Do you agree with the likely impact on the various participants (DNO, EG, load customer, Ofgem?) suggested in the EGWG paper?

• How might this be incorporated into your current charging policy/approach?

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DISTRIBUTION NETWORK CONNECTION: CHARGING PRINCIPLES AND OPTIONS

ANNEX B: ILEX DUOS CHARGING ANALYSIS

The following table provides an insight into the costing analysis used to derive the DUoS charges for projects being connected at 11kV under Option 3.

Table 7 - ILEX DUoS charging analysis

Voltage Load factor Network costs Coincidence factor applicability applicabilityAMD SMD Demand Generation £/KVA/month p/kWh

kV Demand Generation £/kVA/month £/kW/yr p/kWh (Demand) p/kWh (gen) % % % %132 0.5 0.95 0.33 4.6 0.11 0.06 0.44 -0.95 0% 100%

132/33 0.5 0.95 0.43 5.8 0.13 0.07 0.58 -0.50 0% 100%33 0.5 0.95 0.32 4.4 0.10 0.05 0.70 -0.75 20% 80%

33/11 0.5 0.95 0.51 7.2 0.16 0.09 0.85 0.00 100% 0%11

Totals0.3 0.95 0.41 6.4 0.24 0.08 1.00 1.00 100% 0%

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DISTRIBUTION NETWORK CONNECTION: CHARGING