EMBEDDED GENERATION CONNECTION INCENTIVES FOR DISTRIBUTION NETWORK OPERATORS
Report Number: K/EL/00286/REP
URN 02/1148
Contractor
Ilex Energy Consulting
Prepared by Peter Williams Stephen Andrews
The work described in this report was carried out under contract as part of the DTI Sustainable Energy Programmes. The views and judgements expressed in this report are those of the contractor and do not necessarily reflect those of the DTI.
First Published 2002
© Crown copyright 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. REVIEW OF THE EXISTING OBLIGATIONS ON DISTRIBUTION NETWORK OPERATORS 1
2. REVIEW OF DNO PRACTICE 9
3. INTRODUCTION OF THE UTILITIES ACT 2000 21
4. DNO INCENTIVES - PROBLEMS AND PROSPECTS 36
ANNEX A: DNO QUESTIONNAIRE 60 [This page is intentionally blank] INTRODUCTION
This is a final report on the work undertaken by ILEX on the ‘Connection Incentives for Distribution Network Operators’ project - 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 ETSU1. This final report incorporates the content of the interim report which was submitted in February 2002.
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) has become 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).
Recent Government targets for renewable and CHP generation2 will have a material impact on the distribution businesses since most of this small generation 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 ETSU3, has commissioned a number of projects associated with the connection of embedded generation through its Renewable Energy Programme.
It is recognised that the commercial and regulatory implications for the newly licensed Distribution Network Operators (DNOs) of connecting increasing
1 Agreement/contract ref. K/EL/00286/00/00. 2 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. 3 The Energy Technology Support Unit - now renamed Future Energy Solutions.
i numbers of embedded generation needs to be afforded full and careful consideration as the industry moves forward. This project addresses the issue of DNOs’ incentives for the connection of embedded generation.
Final report content Section 1 reviews the obligations on the Public Electricity Suppliers (PESs) relating to connection incentives for connection of embedded generation in the period between privatisation in 1990 and the introduction of the Utilities Act 2000
Section 2 examines current DNO practices associated with the connection of embedded generation including their interpretation of the various statutory and regulatory obligations. Business organisation and the processes and policies adopted by some of the DNOs, is also explored. This is based on consultation with three DNOs.
Section 3 looks at the changes introduced by the Utilities Act 2000 - in particular, the new obligations placed on the DNOs and how these might affect the connection of embedded generation. The requirements of the new Electricity Distribution Standard Licence conditions are also explored and these are compared and contrasted with the obligations which previous existed under the Electricity Act 1989. The final part of Section 3 reviews the overall impact which the Utilities Act 2000 has had on the policies and practice adopted by DNOs in respect to the connection of embedded generation - together with the costs and penalties of non-compliance.
Section 4 reviews the current regulatory treatment of the DNOs and explores the issues and opportunities associated with the creation of an effective incentive regime for the connection of embedded generation. The section concludes with ideas of how an incentive framework might look and work in practice and also looks at the means by which any new incentive framework might be could be governed.
ii 1. REVIEW OF THE EXISTING OBLIGATIONS ON DISTRIBUTION NETWORK OPERATORS
1.1 There are a number of legal and licence obligations which must be considered before the concept of new, or further, DNO incentives for connecting embedded generation can be explored. Compliance with these statutory duties and regulatory requirements are non-negotiable and therefore represent the foundations upon which any incentive regime is built.
1.2 This section reviews the statutory, regulatory and licence obligations placed upon electricity distributors in England and Wales which are relevant to facilitating and encouraging the connection of small scale, embedded, generation.
1.3 The section goes on to briefly review any European Directives which are likely to have an impact on the connection of Embedded Generation and also highlights the relevant aspects of UK competition law.
1.4 The Utilities Act 2000 amends the Electricity Act 1989 and also introduces some important new obligations which are particularly relevant to the connection of embedded generation. The impact of the Utilities Act 2000 and an assessment of how the introduction of new obligations have affected current DNO practice, and may modify future DNO behaviour, is addressed section 3 of this report.
The Electricity Act 1989
1.5 The Electricity Act 1989 underpins the governance and structure of the post- privatised electricity industry. It introduced the concept of Public Electricity Suppliers (PESs) and established the framework within which parties could connect to, and use, the distribution networks.
Background 1.6 The Electricity Act 1989 (“the 1989 Act”) received royal assent on 27 July 1989 and applied to England, Wales and Scotland. In essence, the 1989 Act provided for the: • re-structuring of the electricity supply industry and the transfer from public to private ownership; • establishment of a new regulatory regime under the direction of the Director General of Electricity Supply; and • issue of licences for the generation, transmission or supply of electricity.
1.7 The 1989 Act introduced the requirement on those who wished to generate, transmit or publicly supply electricity to do so under licence. The Act prohibited anybody from carrying out any of these activities unless licensed or exempted from the requirement to be licensed. The 1989 Act empowered the Director General of Electricity Supply (DGES) to grant licences.
1 Public Electricity Suppliers (PESs) 1.8 At privatisation of the industry in 1990 the old Area Electricity Boards became Regional Electricity Companies (RECs). These RECs, by virtue of the licensing regime, all became Public Electricity Suppliers (PESs) and were awarded appropriate licences by the then DGES. Each REC was required to fulfil specific obligations associated with its authorised area4 as laid down in each of the PES licences.
1.9 The term “supply” of electricity was drafted to mean the provision of electricity to customer premises and included the distribution of electricity through ownership and operation of the local lines and cables and well as the wholesale purchase and sale of electricity to final customers. Those wanting to carry out this function were required, by the 1989 Act, to obtain a licence to do so as Public Electricity Suppliers (PESs).
1.10 The 1989 Electricity Act also introduced the concept of the second tier supplier whereby those participants in possession of an appropriate licence could compete with the incumbent suppliers, i.e. the local RECs, to supply electricity to eligible customers. Competition in electricity supply was introduced in three stages following privatisation. Firstly, in 1990, the largest customers, those over 1MW, were able to choose their supplier. In 1994 this threshold reduced to include all customers whose demand exceeded 100kW and by 19995 , all customers were able to select their supplier on a competitive basis.
1.11 Consequently, since privatisation, the RECs have been required to calculate and publish charges for third party access to their distribution networks together with a statement on the basis for such charges6. The publication of network access prices, on a transparent and verifiable basis, was seen as being an essential element in the process of introducing a liberalised market for buying and selling (the supply) of electricity.
Sections of the 1989 Act 1.12 The 1989 Act laid down a number of duties, both general, and specific, associated with connection to and use of, the distribution system. In many cases, there is no explicit mention of the connection of generation, with the majority of the legislation aimed at the (majority) demand customers. The relevant Sections of the 1989 Act are reviewed below.
4 The authorised area aligns with the geographical boundaries previously associated with the Electricity Boards, pre-privatisation. 5 The target date for full competition in electricity supply was originally April 1998 but this was subsequently delayed with some customers not being able to choose their supplier until 1999. 6 Condition 8 of the Public Electricity Supply Licence required licensees to publish details of Distribution Use of System (DUoS) charges.
2 1.13 The 1989 Act lays down a single general duty for PESs “...to develop and maintain an efficient, co-ordinated and economical system of electricity supply”7.
1.14 It is to be expected that this general duty should have been taken into consideration by the PESs when considering their policy and in dealing with applications for the connection and operation of embedded generation (in common with other, demand, connections).
Duty to supply on request 1.15 The 1989 Act placed a duty on PESs to provide, upon request, and following receipt of the required information, a supply of electricity to a customer’s premises8. ‘Supply’, in this context, refers also to the provision of the required connection assets.
1.16 There is a further requirement under this duty for the PES to respond to the request for supply by providing proposed tariff details and also advising of the costs associated with constructing the physical connection to the system.
1.17 This section of the 1989 Act makes no explicit mention of the connection of generation. All references to charges and tariffs are in the context of the PES selling energy with no suggestion for the treatment of export electricity.
Recovery of expenditure 1.18 The 1989 Act empowers the PES to recover from the customer “... any expenses reasonably incurred” in providing the connection assets9. The recovery of costs is, however, associated with the provision of a “supply” an d would not, therefore, seem to, necessarily, provide for costs associated with connection of embedded generation.
The power to require security 1.19 This section of the 1989 Act10 enables the PES to insist upon security for payment of all moneys owed for both delivery of energy and connection. Again, this is aimed at demand customers and makes no specific mention or provision for connection of generation.
Functions with respect to competition 1.20 Section 43 of the 1989 Act places a duty on the DGES to discharge the Directorial responsibilities in relation to competition as laid out in the Fair Trading Act 1973 (“the 1973 Act”). The 1989 Act states that the functions of the ‘Director’ in the 1973 Act shall be transferred to the DGES so as to be exercisable concurrently with the Director General of Fair Trading.
7 The Electricity Act 1989, Section 9(1). 8 ibid. Section 16(1). 9 ibid. Section 19(1). 10 ibid. Section 20.
3 1.21 The 1989 Act also placed a duty on the DGES to assist the Monopolies & Mergers Commission11 in carrying out any investigations and to submit the necessary information and provide appropriate assistance as appropriate.
1.22 Consequently, these pieces of legislation provided electricity customers with some measure of protection against abuse of monopoly power. As providers of a monopoly network service, the PESs were required to operate within the bounds of these various statutory provisions.
1.23 After reviewing the various sections of the 1989 Act, it is clear that it contains little or no statutory provision specifically associated with the connection and operation of embedded generation. The only explicit mention of generation associated with the PESs is obligation for the purchase of electricity from non fossil fuel sources. This is of no direct relevance to the connection of embedded generation nor to the obligations or incentives on DNOs for so doing.
Public Electricity Supply (PES) Licences 1.24 Following privatisation, the functions of local distribution and supply were licensed as a dual activity with separate licences 12 being issued to third party participants, or to PESs, who wished to supply electricity to customers outside of their franchise area.
1.25 The PESs licences defined the way in which customers could expect to be treated in terms of obtaining a connection to the distribution network and receiving energy.
Governance 1.26 The licences were the vehicle by which many of the statutory obligations in the 1989 Act were discharged. Following privatisation, the licences were issued by the DGES on behalf of the then Secretary of State for Energy. They set out specific requirements and represented the conditions under which the DGES authorised those to operate as public electricicty suppliers.
1.27 Licences were subject to approval by the DGES and were amended to take account of periodic regulatory price control reviews. Revisions to the licences were made only after statutory consultation13 with the licensee.
1.28 The PES licences contained a number of Conditions associated with connection to the distribution network. In common with the 1989 Act, the licences contained little or no requirements associated specifically with the connection of embedded generation. The Conditions associated with network connections are listed below.
11 Later to become the Competition Commission by virtue of the Competition Act 2000. 12 The Second Tier Supply licences. 13 The Electricity Act 1989, Section 11.
4 Basis of charges for use of the distribution system and the requirement to offer standard terms for connection 1.29 Condition 8 of the PES licence placed an obligation on the PES to publish charges for connection to the network and also to set out the basis for such charges. Condition 8 referred to connections at a generic level and made no specific reference to the connection of embedded generation.
Basis of charges for ‘top-up’ and ‘standby ’ supplies of electricity 1.30 It was a condition of the PES licence that companies would offer terms for top- up14 and standby15 supplies or sales of electricity with their own authorised areas. Although a supply business responsibility, this was a key condition associated with the operation of embedded generation. The requirements still stand as part of the new supply licence conditions.
Reinforcement costs 1.31 The PES licence also set down principles associated with the recovery of reinforcement costs. Condition 8B16 prescribed that no charge should normally be made for reinforcement of the existing distribution system if the new or increased load requirement did not exceed 25% of the existing network capacity. In addition, charges should not normally be levied on the customers for reinforcement work carried out at more than one voltage level above the voltage of connection.
1.32 These conditions did not appear in the original licences and were introduced as part of the 1994 price control review.
1.33 Whilst these two principles were aimed at demand connections, the principle has important connotations for the costs associated with the connection of embedded generation.
Distribution system planning standard and quality of services 1.34 Condition 9 of the PES licence addresses planning standards and the design of the system for the purpose of ensuring security of supply. It prescribes Engineering Recommendation P2/5 as being the minimum standard to which PESs should plan their distribution networks.
14 Where an exempt supplier’s metered input to the system was insufficient to meet the total of the exempt supplier’s customer demand, the local PES was required to provide ‘top- up’ energy. 15 Some customers, having their own on-site generation, may only require a supply of electricity at times when their own facility is unavailable. The provision of this back-up supply service is know as ‘standby’. 16 Paragraph 5.
5 The Distribution Code 1.35 Condition 11 of the licence required all PESs to prepare, and at all times have in force and implement, a Distribution Code (DC). This covers all material technical aspects relating to the connection to, and use of, the distribution network.
1.36 Condition 11 also states that the DC should be designed so as to .facilitate competition in the generation and supply of electricity”. This is not provided for in the 1989 Act and is the only mention of the facilitation of competition in generation, at a distribution voltage level, before the introduction of the Utilities Act 2000.
1.37 The DC provides much technical information associated with the connection of embedded generation.
Restrictions on own generation capacity 1.38 Condition 6 of the original PES licence placed restrictions on the PES with regard to owning generation. Any generation businesses must have been held separately or through a wholly-owned subsidiary of the licensee. In addition, the licence restricted PES interest in generation to a total capacity figure which was related to each PES’s total customer demand. 17 The extent of ownership of generation may become an important issue in the context of incentives for the connection of embedded generation and is discussed further in later sections of this report.
1.39 In general, the PES licences contain few obligations of direct relevance to the connection of embedded generation. Nevertheless, some of the principles adopted for demand could have been extended to specifically encompass embedded generation. Section 4 of this report reviews how the Utilities Act 2000 has changed the licence obligations placed on the distribution business.
European Directives
1.40 European Community (EC) law is based on an independent legal system which takes precedence over national legal provisions. EU law is composed of three different types of legislation: • primary legislation such as the Treaties; • secondary legislation - Regulations, Directives and Decisions; and • case law which includes judgements of the various European Courts.
1.41 There are a number of pieces of secondary legislation that affect monopoly network operators and which may, therefore, have some indirect relevance to the connection of embedded generation.
1.42 Regulations are binding in all EU member states without the need for any national implementing legislation. Directives bind EU member states to objectives to be
Sumtotal of all own-generation plus any other accountable generation interest - determined on the basis of declared net capacity.
6 achieved within a certain time limit - but leaves individual nations to implement the required national legislation.
The Electricity Directive18 1.43 Article 11(1) refers to ‘distribution system operators’ (DSO) and states that the DSO "... shall maintain a secure, reliable and efficient electricity distribution system" with due regard for the environment”. This is similar to the provisions in the 1989 Act but with additional environmental responsibilities.
1.44 Note 2 of Article 3 of the Directive, states that the DSO should give priority to renewable generators, energy from waste plants and CHP schemes when ‘dispatching ’ generation. In the UK, distribution system operators are not responsible for dispatching generation as part of their distribution duties. However, the way in which a distributor operates its network, and the commercial and contractual relationships it has both with embedded generators and with the transmission system operator, may have a material impact on the connection and operation of embedded generation.
1.45 Article 18 states that Member states shall take the necessary measures to ensure that ‘independent producers’ can negotiate with the DSO for access to the system on the basis of commercial agreement. An independent producer in this context includes independent embedded generators. This is already achieved in England and Wales through ‘use of system agreements ’ and ‘connection agreements ’.
The Renewables Directive19 1.46 Article 7 of the Renewables Directive deals with grid system issues. Note 1 states that all member states shall take the necessary measures to ensure that DSOs guarantee the distribution of electricity produced from renewable energy sources within their licence areas. It also suggests that distribution system operators might make provisions for priority access to the monopoly network.
1.47 These provisions in Article 7 could, therefore, mean that the DNOs in England and Wales ought not to curtail the output from, or restrict the connection capacity associated with, renewable embedded generators. It is for debate whether this could be interpreted as meaning that Distribution network constraints should be managed by limiting the flows of non-renewable energy as opposed to that associated with renewable sources. This may become more of an issue at high penetration levels of embedded generation.
1.48 Article 7 goes on to require the publication of "... obj ective, transparent and non- discriminatory...” rules for third party access to the system. It also requires DSOs to provide any embedded generator wishing to connect with ".a comprehensive and detailed estimate of the costs associated with the connection.”
18 Directive 96/92/EC of the European Parliament and of the Council of 19 December 1996 concerning common rules for the internal market in electricity. 19 Directive 2001/77/EC of the European Parliament and of the Council of 27 September 2001 on the promotion of electricity produced from renewable energy sources in the internal electricity market.
7 1.49 Unlike the 1989 Act, some of the European Directives make explicit mention of embedded, or independent, generation. Some of the requirements are already enshrined within Uk statute. Other requirements have been implemented through the Utilities Act 2000.
8 2. REVIEW OF DNO PRACTICE
Introduction 2.1 This section provides an insight into the way in which embedded generators were dealt with by the DNOs in the period between privatisation and the introduction of the Utilities Act 2000 - the 1990s. It examines DNO policy, process and rationale associated with the application, design and construction of embedded generation connections.
2.2 Three DNOs were selected whose practice was believed to provide a reasonable representation of the range of DNO behaviour. Telephone interviews were undertaken with appropriate DNO staff in order to ascertain past and present practice and to discuss regulatory and statutory obligations with regard to the connection of generation to the distribution network.
2.3 A questionnaire was prepared in advance and sent out to the interviewees. This provided a structure to the discussions and acted as a useful aid memoir during the phone interview. A blank copy of the questionnaire is provided in Annex A.
2.4 Other public domain information such as the companies’ licence condition 4 statements 20 and the standard licence conditions were collated and reviewed in support of the exercise.
2.5 All of the information gathered has been treated as confidential and the three DNOs identities remain anonymous throughout this report. All results and comments have been compiled in un-attributable format.
Existing statutory and regulatory obligations onDNOs 2.6 We first reviewed how the DNOs had interpreted the statutory and regulatory obligations placed on them in 1990, at the time of privatisation, in the context of connecting embedded generation.
2.7 As discussed in section 2, the Electricity Act 1989 and the PESs licences required them, in carrying out distribution connection works, not to discriminate between connectees and, in setting charges for use of the system, not to “restrict, distort or prevent competition in the generation or supply of electricity”.
2.8 With the DNOs we surveyed we explored how their companies interpreted the statutory and regulatory obligations and how these were implemented in terms of policy and practice.
Electricity Distribution Licence condition 4 requires the distribution companies to publish a statement of charges for use of the distribution system and also a statement of connection charges. This was previously provided for under Condition 8 of the PES licence.
9 2.9 From our telephone discussion with the three DNOs it was clear that, in general, they were confident that their behaviour and practice during the pre-Utilities Act 2000 period fulfilled the statutory obligations. Although, interestingly, all three DNOs interviewed expressed some uncertainly as to how, exactly, the statutory wording was interpreted within their own company. One DNO suggested that there was some uncertainty as to the expectations of other parties with regard to restriction, distortion or prevention of competition in generation or supply. This was believed to be an important factor in the way in which the DNOs are likely to interpret legislation.
2.10 One of the DNOs made reference to customers having right of recourse to the Regulator where they believed that DNO obligations were not being met or that they were being otherwise unfairly treated. The regulator’s power to formally determine was seen by the DNOs as being an important part of the statutory and regulatory process.
2.11 One of the DNOs adopted the same ‘full-cost’ connection charging approach for industrial and commercial (I&C) customers as for embedded generation. The DNO believed that this demonstrated non-discrimination between participants and non-distortion of competition through the setting of prices - as required by the 1989 Act. The DNO we spoke to was also of the opinion that this full cost recovery approach aligned with the right for PESs to recover all the ‘reasonable costs’ of connection. This DNO’s charging policy differed from the other two and will be described in more detail later in this section.
2.12 All three of the DNOs we surveyed had a high level of awareness of the statutory duty to “...develop and maintain an efficient, co-ordinated and economical system of electricity supply - as required by the 1989 Act21. However, interpretation of the terms ‘co-ordinated’ and ‘economical’ was not straightforward. One DNO interpreted ‘economical’ as meaning the lowest overall cost to participants - connectees and users of the network.
2.13 The PES licence obligation not to discriminate between “.persons, class or classes of persons.”22 was also familiar to the three company representatives. Interpretation of the further obligation in Condition 8 of the PES licence “.not to restrict, distort or prevent competition in generation or supply of electricity”22 was familiar to all DNOs but its interpretation in the context of the distribution business seemed to be less clear.
Potential ‘inhibitors’ to the connection of embedded generation 2.14 As part of our research, we explored areas of the pre-Utilities Act legislative and regulatory framework which may have discouraged or restricted the connection of embedded generation.
2.15 The 1989 Act’s provision to allow PESs to recover all reasonable costs associated with making a connection, although difficult to disagree with on any rational
21 The Electricity Act 1989, section 9(1) 22 Condition 8 of the Public Electricity Supply Licence.
10 economic basis, was also recognised as a potential inhibitor of embedded generation connection. This was particularly the case in PESs where capital allowance23 was applied for new, or enhanced, load connections, but not for generator connections.
2.16 Whilst the concept of generators paying full-cost for their connections does not restrict or prevent competition per se, it is for debate whether or not applying different charging rules to both demand takers and generation constitutes discrimination between classes of persons.
2.17 The long established planning standard, Engineering Recommendation P2/5 (P2/5), was enshrined in the PES licences as a licence condition24 . The contribution of embedded generation to distribution network security, as an alternative to the distribution assets, was not, and is not, properly recognised by P2/5 25
2.18 The PES licence 26 set out principles to be applied in respect of the extent to which consequential system reinforcement charges could be levied on a new connectee. If the new, or increased, load did not exceed 25% of the existing capacity (at the relevant points of the system) then costs associated with reinforcing the network would not be included in the connection charge but would be recovered through a general reinforcement charge smeared across all customers through supplier use of system charges. Similarly, connection charges will not normally take account of any work to reinforce the system at more than one voltage level above the voltage of connection.
2.19 Discussions with the three DNOs confirmed that this principle of recovering some of the ‘deep ’27 connection costs from the general customer base, via Distribution Use of System Charges (DUoS)28 charges, was not extended to embedded generator connections.
23 Also know as ‘tariff support’ 24 In the standard licence conditions, prior to partitioning in advance of the separation of distribution and supply licences, Engineering Recommendation P2/5 was incorporated in licence Condition 9 - “Distribution system planning standard and quality of service”. 25 This was cited by all three DNOs as being an inhibitor to the increasing numbers of embedded generation. The treatment of embedded generation in respect to network security has been recognised for some time as being an issue and was debated in some detail as part of the work carried out by the Embedded Generation Working Group (EGWG). These network security issues are now being taken forward by UMIST under a separate New and Renewable Energy Programme project. 26 As amended and clarified following the 1994 Distribution Price Control Review. 27 ‘Deep’ implies further from the customer connection, and higher up the voltage levels, than ‘shallow’ which is local to the connection. 28 DUoS charges are those levied by DNOs on suppliers for using the distribution network to transport electricity from the exit point on the transmission system to the supplier’s retail customers. Suppliers are able to recover these costs from their customers as part of their energy charges.
11 2.20 In general, it was acknowledged by the DNOs that the differences in the connection charge applied to generation and demand was a possible source of discouragement for prospective embedded generators.
2.21 One of the DNOs we consulted did not apply capital allowances when calculating connection charges for industrial and commercial demand connections. This facilitates comparisons to be made between generator and demand connection costs since it removes the charge distortion which capital allowances can often introduce. It was recognised that this may highlight the fact that generators pay all upstream costs whereas demand connection costs are limited by the ‘25% demand rule’ or the ‘voltage level above’ rule.
2.22 The differences in the approaches towards connection charging for both demand and generation was recognised by one of the PESs in particular, as being a possible source of discouragement for prospective embedded generators
PES practice and approach to the connection of embedded generation 2.23 From our discussions with the DNOs it was clear that under the existing framework, the attitude of the PESs towards the connection of embedded generation, was very much one of ‘tolerance’. Embedded generators were not sought-out or pro-actively encouraged and the PES approach was very much one of ‘accommodation’. PESs discharged their obligations to process connections and dealt with applications from embedded generator developers alongside those from demand customers.
Organisational structure 2.24 All of the DNOs to whom we spoke had, at some stage during the pre-Utilities Act period, supported and operated a dedicated connections facility of some form or another. The extent to which these internal connections functions were autonomous varied between PESs and also varied over the time. Corporate strategy of the day was seen to be a major driver in this respect.
2.25 One DNO, which operated one of the more autonomous connection businesses, was of the opinion that as PES connections income fell outside of the regulatory price cap, an increase in the number of connected embedded generators might be commercially attractive. It was acknowledged, however, that the extent to which this represented an incentive would depend upon the financial significance of the internal connections business in the ‘group’, or corporate, context.
2.26 One DNO explained how the connection of embedded generation often required staff with enhanced skills when compared to those involved in routine connection of demand customers.
2.27 Some DNOs were of the opinion that this segregation delivered to embedded generators a connections service of higher quality than that for demand connection customers.
2.28 One DNO interviewed saw this enhancement to staff capability as being an important ‘ spin-off benefit to an increase in the number of embedded generators.
12 This comment was made in the context of the autonomous connection business and it was acknowledged that this might well not be the corporate view.
Internal business processes 2.29 The statutory and regulatory drivers for connections affected the PES businesses in a number of ways. Most importantly it defined the process and practices within the various internal business units. As part of our research, we explored this area with our three, representative, DNOs.
2.30 All DNOs we spoke to recovered the costs of connection design from the prospective connectee and all operated some form of tiered process for dealing with connection applications for generation. All DNOs were prepared to commit a limited amount of ‘free-time’ at the outset in considering the generator requirements.
2.31 This was seen to be a good way of identifying key issues at an early stage without the need for significant commitment. The extent to which this was formalised differed between companies and upon the nature of the DNOs relationship with the prospective generation developer. One DNO operated a free “one hour quick look service”, whilst another operated a free initial response, within one week of application, which would often be via telephone. Subsequent feasibilities studies and detailed design work would be charged for.
2.32 One DNO described how an ‘application fee’ was charged. This provided for either an examination of how the embedded generator might be accommodated onto the network (assessment only) or a full study including design work (assessment plus design). This was seen to facilitate competition in connection work since it gave the developer the choice of procuring a third party connection design. In the case where the DNO carries out the design work, the generator owns the design and can then use it for procuring connection construction works on a competitive basis. This approach was adopted for both generation and demand connection applications.
2.33 The approach concerning the timing of the recovery of study and design costs varied between companies, as did the consistency with which generators were treated compared with demand customers. One DNO charged for all connection design work ‘up-front’ - the same as for industrial and commercial demand customers. Another DNO insisted that generators should pay design and other study costs in advance, although in this DNO area, housing developments, for example, were not required to pay design costs up-front.29
2.34 Designing for demand was, therefore, seen to present a lower risk in terms of recovery of design costs than a scheme for an embedded generation developer which may never come tofruition due to a number of potential development
Once a plot of land has been ‘ear-marked ’ for housing development it is highly unlikely that it will not, at some stage, go ahead - even if under a different developer. Local planning regulations usually mean that an electrical design carried out for one housing developer is likely to be largely appropriate for a subsequent developer who will, inevitably, emerge in the event of the initial development not progressing.
13 difficulties. The large number of renewable generator connection applications associated with the various Non-Fossil Fuel Obligation calls were specifically mentioned in this regard.
Table 1 - Summary of process and charges for dealing with connection applications DNO A DNO B DNO C Demand connections Up-front charges for No Yes No connection design? Embedded generation Free initial assessment Yes Yes Yes Up-front charges for Yes Yes Yes feasibility study? Up-front charges for full Yes Yes Yes design? Timescales for design and connection offer for EG30 Maximum31 12 weeks 12 weeks 12 weeks DNO internal target 12 weeks/4 12 weeks/4 6-8 weeks weeks32 weeks33
2.35 One of the DNOs we surveyed said that in circumstances where the need for more specialist network equipment34 would mean a long project lead time, it would offer to move the commercial boundary so as to pass responsibility and control for the procurement of these items to the embedded generation developer.
2.36 It was acknowledged, however, that although this may provide the developer with the opportunity to source items of equipment more quickly, this approach would result in a loss of the DNOs purchasing strength, plus any economies of scale, and may therefore result in a higher overall cost to the connectee.
30 Turn-around times for detailed designs are from the time when the developer has provided the DNO with all required information. 31 Public Electricity Supply (PES) Licence, Condition 8B, part 89(b). 32 12 weeks for complex 11kV, 33kV and 132kV embedded generation schemes and 4 weeks for straightforward 11kV schemes. 33 Following an initial response, the target was to produce a feasibility study within 1 month and a fully costed design within 3 months. 34 The DNOs confirmed that some items of electrical equipment required for connection have relatively long delivery times. This is especially true for connection at higher system voltages where kit is usually more specialist and is often manufactured to order and in very low production volumes.
14 Co-ordination of applications for connection 2.37 There may be situations where the co-ordination of new and enhanced connections may give rise to mutual benefits to both prospective connectees and the DNO. Treating generation and demand in isolation may, in some circumstances, result in the failure to capture commercial benefits which may otherwise arise.
2.38 Whilst technical co-ordination of connection work may realise some cost efficiency benefits, and be more intuitive to the DNOs, it may be that the full financial benefits of co-ordinating demand and generation is only achievable with a more dynamic distribution system with the appropriate reform of commercial cost allocation and pricing policies.
2.39 Discussions with the DNOs highlighted a number of particular difficulties with this co-ordination philosophy. One of the DNOs surveyed explained that there were often differing levels of urgency associated with completing generation and demand connections due, principally, to differing project time-cycles. Another DNO cited varying levels of confidence associated with the project’s progression as being a difficultly.
2.40 It was the DNOs’ view that many embedded generation projects fail to progress beyond the feasibility stage (as already observed, this was particularly the case for many NFFO projects). Conversely, most applications for demand connection, especially those associated with domestic housing developments, are, in the DNOs’ view, expected to come to fruition.
2.41 One of the DNOs particularly mentioned confidentiality issues as a source of further complication. New connections are often associated with commercial ventures and have an element of commercial sensitivity. This can hamper and restrict opportunities to co-ordinate new connections for mutual commercial gain.
2.42 All of these asymmetries were seen as by the DNOs as potential difficulties when attempting to co-coordinate connection applications.
2.43 Despite the acknowledged difficulties, one DNO did say that attempts were made to ‘broker’ some level of connection co-ordination but only where it was thought by the DNO to be of clear benefit to the parties involved and where it was practicable within the realms of required connection timescales and confidentiality issues.
2.44 When questioned about the advantage to the DNO in co-ordinating connections in this way, the benefits of delivering a higher level of customer service and of maximising the limited DNO resource were cited as being the principal drivers. It was acknowledged by the DNO in question that the existing regulatory framework meant that there was no direct financial benefit or explicit commercial incentive to be gained from this approach.
2.45 The same DNO described how technical and commercial terms offered to prospective demand connectees usually remained valid for a period of 28 days. On occasions, and usually at the request of the customer, this offer period is increased to three months - although this tends to be for the larger projects. The
15 DNO was not aware of any obligations or licence conditions with regard to the period of time for which an offer must remain valid.
2.46 The DNO is obliged to honour the terms of the connection offer for the offer validity period. If a firm commitment is not forthcoming within the offer period, the demand developer will be notified in writing that the offer is no longer valid. Any spare capacity which would have been used by the new connectee is then ‘released ’ and may be used to cater for other interested parties.
2.47 Formally, the process for the connection of generation is similar to that for demand connections. However, the DNO acknowledged that additional project complexities and the associated detailed technical clarification meetings - together with the an increased level of developer sensitivity - often meant that, informally, the prospective generator may be afforded more focussed DNO attention.
2.48 Forexample, if, during a generator connection offer validity period, the DNO were to receive another, separate, application for the connection of a generator, then the first-comer’ would often be made aware of this by the DNO. Particularly where there might be an opportunity for both generators to benefit from a coordinated approach. The DNO said that generators were often given more information about local network conditions at the project outset, than demand customers. The perception that generators are more sensitive to connection charges - through the payment of ‘deep ’ connection costs - may explain the need for this more attentive approach.
2.49 The DNO representative could not recall an instance where simultaneous requests for generation and demand customers had affected one another. The DNO suggested that the reason for this might be a function of its local conditions; Most generation requests to date have been for developments in rural, or semi-rural, locations or industrial complexes - whereas most commercial developments have been in urban or city centre locations.
2.50 The other two DNOs treated each connection application, be it for load or for embedded generation, as a stand-alone project. Allocation of system capacity and the consequential impact on connections charges was carried out on first-come- first-served basis.
2.51 One of the DNOs identified the new licence obligation on DNOs to produce a long term development plan 35 as being helpful in coordination of connections by providing prospective connectees with transparent and accessible information on network development issues.
Connection charging practice 2.52 All DNOs confirmed that the specification of all equipment, materials, processes and procedures were the same regardless of whether they were for a demand or a generator connection. The DNOs confirmed that the underlying costs and costing
35 Standard Licence Condition 25.
16 mechanisms, upon which charges were based, were identical for both demand connections and demand connections.
2.53 In common with national practice, none of the DNOs applied capital allowance to the charges for connection of embedded generation. Since generators do not pay charges for use of the distribution system, the net present value of future revenue is zero and generators are required to pay the full, ‘deep ’ cost of connection.
2.54 The fact that allowed regulatory distribution revenue is specified in terms of the ‘number of kWh distributed’36 was mentioned by one DNO, in particular, as being a disincentive to connect embedded generation. Changing this was seen by one of the DNOs as being essential in the quest to encourage the connection of more embedded generation.
2.55 Table 2 summarises the approach each of the DNOs had pre-Utilities Act 2000, towards the provision of a capital allowance for new connections.
Table 2 - Summary policy on tariff support (capital allowances) Connection type Tariff support applied DNO A DNO B DNO C Domestic Yes Yes Yes Commercial and Industrial No Yes Yes Embedded generation No No No
2.56 Under this charging approach, the cost of all assets associated with the connection of the generator is recovered, from the embedded generator, by the DNO, through the up-front connection charge. These connection assets do not enter the regulated asset base and do not, therefore, attract any further financial return.
2.57 This treatment of embedded generation connection assets has been the ‘normal’ DNO practice since vesting as a direct result of the regulatory framework.
First and second comers - subsequent benefits and costs 2.58 The issue of timing of network connections, and the consequences on connection charges of being the first, or second connectee, was explored as part of the DNO survey. This is recognised as being an important contributor to the total cost of connection.
2.59 It has been recognised for some time that it is not equitable for the last connectee, whose additional demand triggers a major reinforcement requirement, to have to meet the all of the network reinforcement costs. To this extent, DNOs have been required, for some time, to protect demand connectees against the prospect of
36 From the Grid Supply Points (GSPs)
17 having to face large reinforcement costs to the benefit of subsequent connectees. To date, this protection only been afforded to domestic customers.
2.60 DNOs are required37 to record and retain details, for a period of five years, of connection works where domestic customers have been required to pay additional charges associated with network reinforcement. Where a subsequent domestic connectee stands to benefit from any original reinforcement work, at the cost of the first connectee, then the second connectee is asked to contribute to the cost of the original works. This contribution is collected by the DNO from the ‘ second- comer’ and passed back to the ‘first-comer’ - in accordance with a defined set of cost reallocation rules
2.61 All three DNOs surveyed confirmed that this policy was not extended to the connection of industrial and commercial demand customers, nor was it applied to connections for embedded generation. Generators who were required, therefore, to pay for all ‘deep ’ reinforcement costs at the time of connection could not expect to recover any proportion of those costs from a subsequent connectee who may benefit from the works associated with the original connection. This would apply whether the second party was another embedded generator or a demand customer.
Use of, and charges for, existing surplus capacity 2.62 To a lesser or greater extent, surplus capacity will always occur on the distribution network. The margin of surplus will depend upon several factors including local demand conditions, equipment ratings and the effect of planned system security measures. Under-utilisation of DNO assets is a cost which must be recovered and which can be the result of a one or more of the following. • ‘Lumpy’ capacity increases. Network capacity is discontinuous due to the discrete nature of lines, cables and switchgear. • Migration of load. Customers are connected and disconnected from the network frequently. Some customers disappear entirely whilst others move to another part of the distribution system. This movement of load, without the corresponding adjustment to the capacity of the network, gives rise to surplus capacity. • System security. A limited amount of redundancy is planned, and built into the network, in order to provide for unscheduled outages, such as faults, and also to comply with distribution system security requirements.
2.63 To date, as a direct result of the regulatory mechanisms, this cost of surplus capacity has been recovered from demand takers through a combination of capacity charges focussed on individual connectees and via distribution capacity charges smeared across all customers.
2.64 Whilst industrial or commercial customers are made to pay for a proportion of this spare capacity - typically through monthly capacity charges - the mechanism
37 The Electricity (Connection Charges) Regulations 1990, SI 1990 No 527.
18 through which a connecting embedded generator pays for ‘taking-up’ any surplus capacity on the system is less clear. This issue was taken up with the three DNOs.
2.65 In two of the three DNOs, a value was not attached to the use of any existing surplus capacity and newly connecting embedded generators were only charged according to the actual, tangible, costs associated with making the connection.
2.66 Unlike demand-takers, since generators do not pay DUoS, there exists no mechanism to facilitate the recovery of any general reinforcement costs which may be more difficult to attributable to individual users and which it might be more appropriate to smear across a customer group. It is for this reason that the 25% reinforcement rule and the ‘voltage above’ rule are not applied directly to the connection of embedded generators. Two of the three of the DNOs we spoke to adopted this methodology.
2.67 One of the DNOs described an approach, adopted by them for a small number of schemes in the early 1990s, which attempted to attach a value to spare capacity and to recover costs from the embedded generator for using this spare capacity. Where existing capacity had been used to provide a generator with a design export capacity, an excess export capacity DUoS charge was levied on any difference between export and import maximum demand requirements.
2.68 The charge was applied at half the rate of demand DUoS and levied on the supplier purchasing the export energy who would pass the charge on to the generator. This method was applied only where the existing local network arrangements meant that generator connection costs would be minimal.
2.69 Although the three DNOs confirmed that the ‘second-comer’ rule was not extended to industrial and commercial customers, it was acknowledged that a charge for use of the surplus capacity was made to the connectee through a DUoS capacity charge. It was accepted, therefore, that where embedded generators were not required to pay DUoS on export electricity, any newly connecting generator would be able to take advantage of existing, surplus, network capacity free of charge.
Charges for Operations, Repair and Maintenance (O, R and M) 2.70 These are the costs incurred in keeping the distribution system in proper working order. O, R and M costs can be accounted for either as capital expenditure or as revenue expenditure - depending on the period over which the associated benefits are delivered to the asset owner38. There will always be an O, R and M liability associated with all connection assets and these costs needs to be appropriately allocated and recovered from participants.
Revenue or ‘expensed ’ costs are those associated with the consumption of a resource whilst obtaining business revenue. The benefit obtained from revenue expenditure is required to have occurred within the same accounting period - unlike capital, or investment, costs where the benefit obtained is spread over a number of years. Examples of revenue costs are those associated with: staff wages; monitoring and controlling the distribution system; vehicle fuel costs and routine equipment maintenance costs. In the DNOs, this type of costs is often called operational expenditure or ‘opex’.
19 2.71 In most DNOs, DUoS charges provide for O, R and M of the assets included in the regulatory asset base39. These costs are, therefore, recovered by all demand takers through charges for use of the distribution system levied on suppliers by the DNOs.
2.72 We explored the policies associated with recovery of O, R and M with the three DNOs. All three of the DNOs we consulted added an amount to the connection costs charged to embedded generator to reflect the on-going O, R and M liability. This policy of capitalising the lifetime costs seems to be the most common approach amongst the all DNOs.
Competition in connections 2.73 Some of the DNOs seemed to promote the concept of ‘competition in connections’ more than others. One DNO offered prospective connectees a clear choice between non-contestable works only and non-contestable plus detailed design, whilst others seemed to be less proactive in promoting the competitive connection approach.
DNO attitudes towards the prospect of increasing levels of embedded generation. 2.74 The three DNOs we surveyed all held strong views as to the potential impact on their business of increasing levels of embedded generation - although these tended to be dominated by technical challenges. All three DNOs citied increased system fault levels and management of system voltage as being the most pertinent technical considerations.
2.75 Some of the DNOs appeared to be more aware of the commercial and regulatory issues than others. All were au fait with the present regulatory treatment of embedded generation and of the lack of consistency between the treatment of demand and embedded generation in terms of charges for connection and for use of the distribution system.
2.76 All three DNO were aware of the recent work carried-out by the Embedded Generation Working Group (EGWG) and familiar with the group’s findings and recommendations. In fact, one of the DNO representatives we spoke to was a member of the original EGWG.
2.77 One of the DNOs we spoke to was particularly pro-active in the development of commercial and contractual arrangements for the connection and use of embedded generation as a service provider to the distribution network. Some of the ideas and thoughts emerging from these discussions are explored further in section 4 .
The regulatory asset base (RAB) or regulatory asset value (RAV) is the total value attributed, by the regulator (Ofgem), to the monopoly distribution assets (lines, cables, switchgear, transformers etc.). It is on this RAB value that DNOs are allowed to make a ‘reasonable rate of return’ (presently 6.5%) and which forms the basis of the charges levied on supplier demand for use of the distribution network.
20 3. INTRODUCTION OF THE UTILITIES ACT 2000
3.1 Compliance with statutory duties is a minimum requirement for the Distribution Network Operators (DNOs) and any new incentive regime needs to be developed with due regard to these legal responsibilities. The Utilities Act 2000 came into force in July 2000 and amends the Electricity Act 1989. It introduces a number of new obligations which are of relevance to the connection of embedded generation.
3.2 This section firstly reviews the major changes introduced by the Utilities Act 2000 (“the 2000 Act”) - the main provisions. The work then goes on to review the sections of the new Act which are of significance to DNOs and, particularly, any which may be pertinent to, or have the potential to impact upon, the connection of embedded generation. The requirements of the new Electricity Distribution Standard Licence conditions will also be explored. This part of the work focuses on the areas of change with respect to the obligations under the Electricity Act 1989 and the old Public Electricity Supply (PES) licences.
3.3 The final part of the section reviews the impact which the Utilities Act has had, not only on the DNOs, but also, on the embedded generators. The potential costs and penalties associated with failing to comply with the various statutory requirements are also explored.
The Utilities Act 2000
3.4 The Utilities Act 200040 builds on the basic, post-privatisation electricity industry framework established in the Electricity Act 1989. The 2000 Act established a number of important new concepts and re-defined the framework within which the electricity industry operates.
Background 3.5 The Utilities Act 2000 received Royal Assent on 28 July 2000. It amends the Electricity Act 1989 (and the Gas Act 1986) and its introduction made a number of substantial changes to the way in which the electricity industry in Great Britain is organised and regulated. The 2000 Act introduces the following important provisions and changes: • creation of the Gas and Electricity Markets Authority (GEMA); - replaces the functions of the Director General of Electricity Supply (DGES); - governs Ofgem; and - determines strategy and decides on major policy. • Imposes a primary objective on the Authority to protect the interests of customers.
40 Utilities Act 2000, Chapter 27.
21 • The separation of electricity supply and distribution - including separate licences. • An obligation for a proportion of electricity to be generated from renewable 41 sources . • Establishes the Gas and Electricity Consumer’s Council (GECC); and • Empowers the ‘Authority’ (GEMA) to impose fines for breach of licence.
3.6 Not all of these changes and new provisions are of direct relevance to the licensed distributors (the DNOs). The following paragraphs highlight the sections of the 2000 Act which are relevant to DNOs or to the connection of embedded generation.
Sections of the 2000 Act relevant to DNOs 3.7 The 2000 Act comprises six main parts. These include: • a description of the new regulatory arrangements (establishment of GEMA and GECC, transfer of functions and property to the new Authority etc); • objectives of regulation of gas and electricity (duties under the 1989 Act, health and safety etc); • functions of the GECC; • amendment of the Gas Act 1986; and • amendment of the Electricity Act 1989.
3.8 There is an additional section covering ‘Miscellaneous and Supplementary’ issues.
3.9 It is, however, the part on Amendments to the Electricity Act which is of most interest to the distribution licensees - in particular, the ‘Duties of electrical distributors’42 .
3.10 The majority of the duties are similar to those imposed on the PESs by the Electricity Act 1989 - although some are new and many are now specific to the DNOs.
General duties of electricity distributors 3.11 The 2000 Act retains the general duty of electricity distributors “...to develop and maintain an efficient, co-ordinated and economical system of electricity distribution”43 . This represented the only general duty for the PESs under the
41 The Renewables Obligation Order was laid before Parliament in February 2002, approved by the Lords on 28 March 2002 and can into force on 1 April 2002. In the first year of the obligation order (2002/2003), suppliers are obliged to purchase 3% of electricity from renewable sources - increasing gradually to 10.4% by 2010/2011. 42 Utilities Act 2000, Part IV, ‘Duties of electricity distributors 43 The Utilities Act 2000, Section 50(1)a.
22 1989 Act44 although this was previously associated with the ‘supply’45 of electricity - commensurate with the function of the PESs.
3.12 The 2000 Act introduces a second, new, general duty on electricity distributors “.to facilitate competition in the supply and generation of electricity.” This duty recognises the distribution business as a monopoly service provider and does, in fact, mirror the general duty placed on operators of transmission systems by the Electricity Act 198946 .
3.13 The Utilities Act does not provide any further thought on how this second general duty is likely to be discharged nor does it suggest the sort of DNO actions, or inactions, which might give rise to a breach of this duty (i.e. to facilitate competition in the supply and generation of electricity).
Duty to connect on request 3.14 The 2000 Act places a duty on the DNOs to make a connection between the licensee ’s electricity distribution network and a customers premises for the purpose of enabling electricity to be conveyed to and from the premises47. The request for a connection may come from: • the owner or occupier of the premises requiring the connection; or • an authorised supplier acting with the consent of the owner or occupier of the premises.
3.15 The difference from the original 1989 Act is that it is now recognised that this request for a connection may come from a licensed supplier acting on behalf of the prospective connectee. This is in keeping with the ‘supplier-hub48’ principle adopted by the industry as part of the final stage of supply de-regulation in 1998/99.
3.16 The 2000 Act also requires a distribution licensee to provide a connection with another licensed distribution system where required to do so for the purpose of enabling electricity to flow from one distribution network to another49.
44 The Electricity Act 1989, Section 9(1). 45 The term supply was drafted to mean both the ownership and operation of the local lines and cables (distribution) as well as the wholesale purchase and sale of electricity to final customers. 46 The Electricity Act 1989, Section 9(2)b. 47 The Utilities Act 2000, Section 44 - amends Sections 16 and 17 of the Electricity Act 1989. 48 The supplier hub principle leads to the licensed suppliers operating at the contractual and commercial ‘centre ’ of the industry. The suppliers ‘buy-in’ the necessary services - such as metering operations, meter reading, distribution services etc. - by contracting with suitable service provider agents. End customers deal directly with the suppliers. The industry effectively revolves around the licensed suppliers. 49 The Utilities Act 2000, Section 44(16)b - amends Sections 16 and 17 of the Electricity Act 1989.
23 3.17 Although this section of the 2000 Act still makes no specific mention of the connection of generation, by changing the subject of the duties from supply to connection this would now seem to include the connection of embedded generation. References to providing the connection for enabling electricity to be conveyed “.to or from the premises” reinforces the inclusion of embedded generation.
Power to recover expenditure 3.18 The right to recover from the customer all reasonable expenses incurred in making the connection remains. However, the 2000 Act establishes the distributor duties by amending the 1989 Act by substituting the terms “public electricity supplier”, “supplier” and “supply of electricity” with the terms “electricity distributor”, “distributor” and “connection”.
3.19 The reference to ‘connection’ rather than to ‘supply’ would now seem to provide for the recovery of costs associated with both demand connections and generator connections.
Exemptions from the duty to connect 3.20 The 2000 Act clarifies the conditions under which a DNO may not be required to make a connection to the system50 . The 2000 Act states these conditions as being: • where the DNO is prevented from doing so by circumstances beyond its control; • in circumstances where doing so might involve a breach of regulations; or • where it is not reasonable in all the circumstances for them to do so.
Procedure for requiring aconnection 3.21 The requirement for the distributor to be provided with all of the required information, prior to making the connection offer, still exists51 . Any additional information, which the DNO may require in order to make the connection, must be requested from the person requiring the connection as soon as practicable52 .
3.22 Once all necessary information has been received, the DNO is required to notify the person requiring the connection: • the extent to which the proposals are acceptable to the DNO - together with any counter proposals; • the charges for making the connection; and • details of any other terms or securities.
50 ibid. Section 44(17). 51 The prospective connectee must provide the DNO with details of the premises requiring connection, the date by which the connection is required and the maximum power capability required from the connection - together with any other information as the DNO may reasonably request. 52 The Utilities Act 2000, Section 44 (4).
24 3.23 The contractual arrangements associated with the connection of domestic connections changed as a result of the 2000 Act. Previously, a connection agreement - that between the connectee and the DNO - was required, and was procured by the supplier on behalf of the DNO. The connection agreement was, effectively, an addendum to the supply agreement, and was secured by the supplier at the time of securing the supply agreement. Nevertheless, the connection agreement was a separate document to the supply agreement with different counter parties.
3.24 The 2000 Act provided for domestic connection agreement terms to be included as mandatory terms within the supply agreement. The use of system agreement - that between the licensed suppliers and the DNOs - now makes provision for this arrangement.
3.25 The connection agreement arrangements for all non-domestic customers remains unchanged with customers having separate supply and connection agreements. This ‘triangle ’ of arrangements is explained further in section 4 of this report53 .
The power to require security 3.26 This provision entitles the DNO to insist upon security for payments associated with providing and installing the connection equipment. This was included in the existing 1989 Act but is now amended by the 2000 Act54 to deal specifically with connection to the distribution system.
3.27 If the prospective connectee fails to provide security, and the DNO considers it to be necessary, then the DNO has the right to refuse to provide the connection equipment. In the case when the connection has already been made the DNO has the right to disconnect the premises from the distribution system.
3.28 Before a premises can be disconnected, the 2000 Act requires the DNO to give to the occupier or owner of the premises not less than seven working days notice of the intention to disconnect.
3.29 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.
Special agreements for connection 3.30 Under the 1989 Act, provision of a supply for more than 10MW, required the public electricity supplier (PES) and the person requiring a supply to enter into a bespoke agreement. All other customers were free to enter into such special agreements with the PESs should they wish. The alternative was to receive a supply of electricity under standard tariff terms - in accordance with the standard provisions in the 1989 Act.
53 The contractual relationships are illustrated in section 4 , Figure 2. 54 Section 20 of the Electricity Act 1989 as amended by the Utilities Act 2000, Section 47.
25 3.31 The 2000 Act continues in this vein by permitting any person requiring a connection to enter into a special connection agreement. In such case, provided the connection agreement is effective, the rights and liabilities of the DNO and the connectee shall be as arising under the connection agreement and not those provided by the sections of the 2000 Act associated with the provision of a connection 55 .
Distribution licences 3.32 One of the most important changes brought about by the Utilities Act is the division of distribution and supply functions and the introduction of separate licences. The 2000 Act amends the 1989 Act so as to differentiate between supply and distribution functions and to make it an offence for any person to distribute56 electricity unless authorised to do so by licence or by exemption.
3.33 All of the previously licensed Public Electricity Suppliers (PESs), were granted distribution licenses to operate the distribution systems in the geographic areas previously covered by the PES licenses. Over recent years, there has been some merger and acquisition activity in the distribution business sector, although the number of licensed distribution areas has remained unchanged 57.
3.34 The distribution licence defines the operating framework within which the DNOs must deliver their licensed distribution service. It also sets out the way in which distribution customers, be they suppliers or connectees, can expect to be treated in pursuit of these licensed activities. The overall objective of the licensee has not changed from the PES licence - notwithstanding, of course, the fact that the distribution licence is now only concerned with the distribution function.
3.35 Prior to the Utilities Act 2000 coming into force, the conditions of the existing PES licenses were partitioned into supply conditions, distribution conditions and those conditions which were common to both activities. This facilitated the introduction of the separate licences.
55 The Electricity Act 1989, sections 16 to 21 as amended by section 44 of the Utilities Act 2000. 56 Section 28(3)a of the Utilities Act 2000 Act introduces the definition of distribute as being “distribute, in relation to electricity, means distribute by means of the distribution system, that is to say, a system which consists (wholly or mainly) of low voltage lines and electrical plant and is used for conveying electricity to any premises or to any other distribution system ” 57 Merger and Acquisition activity has meant that some companies, or corporate entities, hold 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.
26 Prohibition from holding both a distribution and a supply licence 3.36 An important consequence of the separation of distribution and supply is that the 2000 Act prohibits the same legal person holding both a supply licence and a distribution licenc e58.
3.37 Regional electricity companies who previously held Public Electricity Supply (PES) licences - and who have decided to retain both a distribution and a supply business - have, therefore, been required to establish separate legal entities for distribution and supply businesses.
The introduction of standard licence conditions 3.38 The new distribution licences are based on a set of standard licence conditions. This approach differs from the old PES licenses which, although developed on a common basis, the licence conditions were individually agreed on a bilateral basis between Ofgem and each PES. This meant that any changes to licence conditions had to be made within each individual licence - even though the change may be identical.
3.39 Under the new standard licence condition arrangements, any change or modification to the core conditions can be made collectively. A voting process is used, with specified majority thresholds, to decide whether or not a change or modification may go ahead.
Governance 3.40 The standard distribution licence conditions, as in the case of the previous PES licence conditions, provide the vehicle by which many of the obligations contained within the Utilities Act 2000 are fulfilled. Distribution Licences are still granted and issued by Ofgem but contained within them will be the standard conditions, as determined by the appropriate Secretary of State59.
3.41 The PES licences contained Conditions associated specifically with connection to the distribution network. These now form part of the standard distribution licence conditions. Although there is no explicit mention of connection of embedded generation, the licence conditions relating to connection do not exclude connections for generation.
Basis of charges for Use of System and Connection toSystem (Condition 4) 3.42 The requirement for the licensee to prepare, and make readily available, details associated with charging for connection and for use of the system, remains in the new distribution licences. This obligation is now set out in Condition 4 of the licence 60 and is commonly known as the ‘Condition 4 statement ’. It was previously provided by Condition 8 of the old PES licence.
58 Section 6(2) of the Electricity Act 1989 as amended by section 30 of the Utilities Act 2000. 59 Currently the Secretary of State for Trade and Industry. 60 Electricity Distribution Standard Licence Condition 4.
27 3.43 The information which the DNOs are required to publish as part of this licence condition are as follows: • a statement setting out the basis upon which charges will be made for use of the licensee ’s distribution network; and • a statement setting out the basis upon which charges will be made for connections to the licensee ’s distribution system.
3.44 Condition 4 of the distribution licence clearly sets out what the two charging statements are expected toinclude. Apart from charges for the distribution of electricity under use of system, the first of the two statements above should also provide detail of distribution loss adjustment factors61, a description of the methodology for setting available capacity charges and a schedule of charges for accounting and administration 62.
3.45 The licence is also clear about what the connection statement must detail - this includes a schedule listing of items of significant cost together with their indicative costs.
3.46 Since, at present, embedded generators are not charged for use of the distribution system, the use of system statement is concerned mainly with the treatment of demand.
3.47 Most DNO connection statements do, however, make some mention of connection charges for embedded generation and usually state that they are based on the full costs incurred by the DNO in making the connection. The items of equipment needed to connect a generator are likely to be of similar specification to those for a demand connection and sothe schedule of items of significant cost is likely to be as relevant to embedded generation as to demand.
3.48 The old PES licenses Condition 8 did make reference to the costs associated with connection “at entry or exit points”. Entry points are those associated with connecting generators and this terminology is retained in the new standard distribution licence conditions63.
3.49 A detailed discussion of the charging statements and the methodology and principles adopted by the DNOs for connection and use of the system is beyond the scope of this project on incentives64 .
61 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 losses incurred in physically transporting energy through the distribution system to end users. 62 Electricity Distribution Standard Licence Condition 4, Part 2. 63 Electricity Distribution Standard Licence Condition 4, Part 2(e). 64 A more detailed review of the charging methodology and principles associated with connection to, and use of, the distribution system been undertaken by ILEX as part of a separate project under the DTI’s New and Renewable Energy Programme - ‘Distribution
28 ‘Top-up’ and ‘standby ’ supplies of electricity 3.50 As a ‘supply’ business function, this no longer forms a part of the distribution licences. This obligation to provide top and standby supplies still remains but is now part of the new supply licence conditions.
Reinforcement costs 3.51 With regard to the allocation of reinforcement costs to connectees, both the ‘25% demand rule’ and the ‘voltage level above’ rule, are retained in the new distribution licences 65 . However, this licence rule is still laid down in the context of ‘load’ requirements and does not include upstream reinforcement costs associated with embedded generation.
3.52 With embedded generation paying the full, ‘deep ’ costs of connection, the application of these two reinforcement rules to the connection of generation would be likely to have significant effect.
Planning and quality of service 3.53 The requirement for distribution businesses to plan their distribution networks in accordance with Engineering Recommendation P2/5 is retained in the new distribution licences 66 .
3.54 It has been recognised for some time that P2/5 does not properly recognise the contribution which embedded generation can make to network security. The new licence Condition 5 makes reference to the existing ER P2/5 document and does not, therefore, redress this situation67.
The Distribution Code 3.55 The new standard distribution licence continues to require DNOs to “prepare and at all times have in force and implement ” a distribution code68. This continues to cover all material technical aspects relating to connection to, and use of, the distribution system.
3.56 As in the old PES licences, the standard distribution licence conditions still require the Distribution Code to be designed so as to facilitate competition in the
Network Connection: Charging Principles and Options’ (Agreement/contract ref. K/EL/00283/00/00). 65 Electricity Distribution Standard Licence Condition 4B, ‘Requirement to Offer Terms for Use of System and Connection’, Section 5(c)(i) and (ii). Note that these conditions were introduced into the old PES licences as part of the 1994 price control review. 66 Electricity Distribution Standard Licence Condition 5. 67 The treatment of embedded generation in respect to network security was debated in some detail as part of the work carried out by the Embedded Generation Working Group (EGWG). These network security issues are now being taken forward by UMIST under a separate DTI New and Renewable Energy Programme project. (Ref. K/EL/00287/00/0). 68 Electricity Distribution Standard Licence Condition 9.
29 generation and supply of electricity. This aligns with the new general duty on DNOs introduced in the 2000 Act.
3.57 A single Distribution Code Review Panel (DCRP) of Great Britain (GBDCRP) has recently been formed comprising members of both the England and Wales DCRP and the DCRP for Scotland. The GBDCRP are now working towards the development of a single Distribution Code for Great Britain through merger of the two Distribution Codes of England and Wales and Scotland.
BSC and NETA implementation 3.58 The electricity distribution standard licence introduced a new Condition associated with the Balancing and Settlement Code (BSC) and the implementation of NETA69. The Condition requires DNOs to be a party to the BSC Framework Agreemen t and to comply with the BSC.
Change coordination for NETA and for the Utilities Act 2000 3.59 Condition 1170 and Condition 1271 of the distribution licence requires also that DNOs cooperate in coordinating changes of the core industry framework documents, as necessary, in pursuant of the provisions of NETA and the Utilities Act 2000. Examples of such documents and agreements are the Connection and use of System Code (CUSC), the Master Registration Agreement (MRA), Grid Code and the Distribution Code.
3.60 The Licence condition also required DNOs to comply with the implementation scheme for the New Electricity Trading Arrangements (NETA)72.
Changes arising from the introduction of the new Distribution licences 3.61 The new standard distribution licence Conditions are based, largely, on the Conditions contained within the old PES licences which were relevant to distribution. Prior to the Utilities Act 2000 coming into force, the PES licence conditions were partitioned into those relevant to the distribution function, those relevant to the supply business function and those, more general conditions, which were relevant to both businesses. This assisted in the development of, and formed the basis of, the standard distribution licence conditions.
3.62 Apart from references to NETA, the Utilities Act 2000, and the new references to the “Authority” (rather than the “Director”), there is no significant difference between the conditions of the old PES licences relevant to distribution and those which make up the new distribution standard licence conditions.
69 ibid. Condition 10. 70 Electricity Distribution Standard Licence Condition 11. 71 ibid. Condition 12. 72 NETA ‘went live ’ on 27 March 2001.
30 Impact of the 2000 Act on the DNOs
3.63 During the conference call interviews we undertook as part of the work we asked the DNOs about the Utilities Act 2000. In particular, how it has affected DNO policy and practice.
Interpretation of the new general duty 3.64 We were particularly interested in the DNO interpretation of the new general duty to “facilitate competition in the supply and generation of electricity” placed on them thought the introduction of the 2000 Act.
3.65 We asked three DNOs “how, as a DNO, do you feel that you can facilitate competition in generation”.
3.66 The most commonly held view was that this new duty required DNOs to adopt a consistent approach to the treatment of embedded generation. The DNOs we spoke to were of the opinion that this new duty meant that each embedded generation developer should be afforded the same degree of DNO attention with respect to applications for connection.
3.67 One of the DNOs questioned whether to “facilitate competition in supply and generation” implied that a consistent approach should be adopted, by the DNO, to the treatment of generation and supplier demand or, whether such consistency should be adopted just between generators or just between suppliers. After further discussion it was acknowledged, however, that the facilitation of competition between supply and demand may not be realistic given the current differences in the way generators and demand are treated by the DNOs - particularly in respect of connection.
Transmission connected generation 3.68 The reference to generation in general, rather than specifically to embedded generation, provoked one of the DNOs to question whether the new general duty refers to the facilitation of competition between embedded generators or between embedded generators and other, transmission connected, generation. The DNO was unclear as to how the competitiveness of transmission connected generators could be materially affected by its actions and/or behaviour.
Interaction with existing ‘general duty ’ 3.69 One DNO suggested that if the term ‘economical’ was interpreted as meaning low cost, then there may be some conflict between the two general duties placed on distributors courtesy of the 2000 Act - to “...develop and maintain an efficient, co-ordinated and economical system of electricity distribution.” and that to facilitate competition in generation. The rationale being that higher levels of embedded generator penetration would be likely tolead to higher network costs and hence higher customer costs - at least in the short to medium term.
Provision of information 3.70 One of the DNOs we consulted thought that facilitation of competition in generation could be achieved by improving the extent to which network
31 information is made available to embedded generators. It was thought that the recently developed standard licence Condition 25 would be of significant benefit in this respect. The same DNO was also of the opinion that encouraging local authority planners to provide more information about planning restrictions might further assist developers.
3.71 Forexample, the feasibility of developing an embedded generation scheme for network reinforcement may be significantly influenced by the planning constraints associated with the construction of new overhead lines. This particular DNO talked about the local authority providing a “passive facilitation” role.
The cost of non-compliance DNO penalties 3.72 Under the provisions of the 2000 Act, the Authority73 is empowered to levy fines on licence holders for non-compliance74. Penalties can be applied where the authority is satisfied that a licence holder has contravened or is contravening any “relevant condition or requirement”75.
3.73 The Gas Act already contained provisions which enabled the previous Director General to impose financial penalties on companies that breached, and continued to breech, a relevant requirement. The 2000 Act now extends this provision to electricity but with the additional proviso that, unlike the Gas Act, a fine can still be imposed even if the breach has been corrected.
3.74 The penalty on the DNO for breach of a relevant requirement can be up to 10% of the DNO’s turnover - where the definition of turnover is specified in a statutory instrument made by the Secretary of State. The penalty must be ‘reasonable in all circumstances of the case’. Also, the 2000 Act makes clear that the Authority shall not impose a fine where it believes that it is more appropriate to proceed under the Competition Act 2000.
3.75 Before a penalty is imposed, the 2000 Act requires the Authority to provide the licensee (DNO) with details of the amount to be fined, the condition, requirement or standard in question and the acts or omissions leading to the contravention. The DNO has a right of objection to any fines and the Authority must notify the licensee of the time within which any objection of representation must be made.
Overall impact of the Utilities Act 2000 3.76 In general, there seemed to be a degree of uncertainty with regard to what the new statutory duty to facilitate competition in supply and generation actually meant in practice. None of the DNOs we consulted were able to give a clear account of
73 The Gas and Electricity Markets Authority (GEMA). 74 The Utilities Act 2000, Section 59 (27A) - amends section 27 of the Electricity Act 1989. 75 “Relevant requirements” are licence conditions, standards of performance or obligations imposed by certain sections of the Act itself.
32 how the introduction of the Utilities Act had affected policies or practices - other to confirm that little change had taken place.
3.77 All three DNO we interviewed confirmed that their internal policies and procedures had not changed as a result of the introduction of the 2000 Act. This was reinforced by one of DNOs claiming that the introduction of the Utilities Act meant ‘business as usual’.
3.78 Furthermore, it is interesting to note that the duty to facilitate competition in generation (and supply) has been a requirement of the design of the Distribution Code, in the old PES licence, for a number of years. On this basis, one might not have expected DNO practice to change significantly as a result of the introduction of the Utilities Act 2000.
3.79 The treatment of embedded generation by the DNOs - in terms of both policy and practice has not changed as a result of the introduction of the Utilities Act 2000.
Impact on embedded generation 3.80 The changes brought about by the introduction of the 2000 Act which are of direct relevance to the connection of embedded generation are: • the additional general duty on licensed distributors to facilitate competition in the supply and generation of electricity; and • the establishment of duties specific to the distribution function and the change of reference from supply to connection throughout the sections on DNO duties.
3.81 The Utilities Act 2000 formalises the separation between distribution and supply and establishes a number of new duties specifically for electricity distributors. Most of these are lifted, directly, from the old PES licences but with the important difference that all of the previous references to the provision of supply have all been changed to the provision of connections.
3.82 The new legislation isolates the ownership and operation of the ‘wires’ business from the sale of energy and identifies the principal DNO activities as being connection and use of system. The 2000 Act does not differentiate between network connections for generation and network connections for demand. To this extent, the 2000 Act ought to promote consistency in the treatment of generation and demand.
3.83 The Utilities Act does not, however, define the way in which distribution allowed revenues are determined and does not stipulate how DNOs ought to treat, or charge for, the connection of embedded generation.
3.84 The new duty to facilitate competition in generation would not seem to be specifically aimed at embedded generation. Furthermore, from the DNOs we interviewed, the purpose of this new duty, and the expectations arising from it, would seem to be somewhat unclear.
33 3.85 None of the DNOs we spoke to had made any changes to their embedded generation connection and charging policy as a result of either the new provisions of the Utilities Act or the new electricity distribution standard licence conditions.
3.86 Some of the DNOs are now beginning to think more carefully about the policies and practices they adopt for the connection of generation - both in terms of using generation for the provision of network services and also in terms of charging embedded generators for connection and use of the distribution system.
3.87 There is no evidence to suggest that this increased interest in embedded generation, by the DNOs, is as a result of any new statutory obligations or licence conditions.
3.88 Government targets for renewable and CHP76 generation has stimulated national industry interest in the connection of embedded generation. If these targets are to be met then a significant amount of generation capacity will need to be connected to distribution networks over the coming years. Some believe that it is this ‘inevitability’ of increased penetration levels of embedded generation which is driving and encouraging DNOs interest.
3.89 This would seem to reinforce the need for the development of an incentive framework to actively encourage DNO to connect embedded generation. The next section explores how this might be introduced.
Government targets are for 10% of electricity to be supplied to be from renewable sources and for an increase in installed CHP generation to 10GW - both by 2010.
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35 4. DNO INCENTIVES - PROBLEMS AND PROSPECTS
4.1 This section firstly describes, and reviews, the way in which the present regulatory framework deals with the connection of embedded generation. The different polices and procedures of the DNOs are taken into account when examining the impact of the present regulatory regime.
4.2 The work goes on to consider, for a typical DNO, the balance between business income and business costs associated with the connection and ongoing operation of embedded generation. In the light of this, the work explores alternatives to the present regulatory arrangements and examines the extent to which revised regulatory arrangements can provide genuine and sustainable incentives for DNOs.
Current regulatory treatment of the DNO businesses
4.3 This first part of the section reviews the regulatory treatment of the DNO businesses in England and Wales in order to identify the commercial drivers and explore opportunities for incentivisation.
4.4 Since privatisation, distribution businesses have operated under an asset-based regulated price control regime whereby income for use of the distribution system is ‘capped ’ in accordance with a prescribed number of business attributes -such as number of kWh distributed and the number of connected customers.
4.5 The present regulatory arrangements are designed for a network system which is dominated by connected demand and where electricity flows from the point of connection to the transmission system to the point of connection of customer load. Whilst the present regulatory regime does, to a limited extent, accommodate embedded generation, it is now recognised by the industry77 that current arrangements will be insufficient if Government targets for CHP and renewable generation are to be met.
4.6 Before any new incentive regime can be considered it is necessary to understand the way in which the DNO revenues are generated, in particular, the regulatory framework and commercial processes which drive the business. It is also necessary to appreciate how the various charges and payments flow between the main participants.
Regulated business revenue 4.7 In common with many other commercial operations, the profit generated by the distribution business is what remains once the costs of the business have been accounted for. In general terms, profit equals revenue minus costs.
Embedded Generation Working Group (EGWG) report, Chapter 3, Section 4 (and Annex 4) - ‘charging principles ’ DTI/Ofgem, January 2001.
36 4.8 In electricity distribution, however, the business income is largely fixed by the regulatory price control mechanism. Once the regulator, Ofgem, has determined the level of income which each DNO should be allowed to earn, a price control formula is used to describe this revenue allowance in terms of a number of basic cost drivers - such as kWh distributed, electrical losses and the number of connected customers. The allowed revenue is collected from the users of the network.
4.9 Since Vesting, the price controls have been set such that DNO revenues are directly related to the retail price index (RPI). To date, the allowed revenues have reduced in relation to the RPI by a percentage factor defined as “X”. Since privatisation in 1990, this percentage has been negative such that DNO revenues have been cut, in real terms, year on year, according to this RPI-X price control formula. It has been usual for the “X” figure to be set for the duration of the price control period - typically 5 years.
4.10 For the current price control, all distribution businesses regulated revenues are required to reduce each year by RPI-3%78.
4.11 The consequence of this is that the principal means of increasing, or maintaining profits, is to increase efficiencies and reduce costs79. This is shown pictorially in Figure 1. This form of regulation is sometimes referred to as ‘incentive regulation’.
78 Review of Public Electricity Suppliers 1998 to 2000, Distribution Price Control Review, Final Proposals, December 1999. 79 There is some opportunity for DNOs to increase regulated revenues but, under the present regime, this is limited.
37 Figure 1 - Regulation of distribution businesses
Distribution revenue
RPI-X Profit
efficiencies Business costs
Sources of licence distribution business income 4.12 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.
4.13 Forall DNOs, charges for use of the distribution system represent the vast majority of the business income80. 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 known as Distribution Use of System (DUoS) charges.
4.14 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. Fora domestic customer, distribution charges typically represent 25% of the total electricity bill81.
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. Source: Ofgem web-site - http://www.ofgem.gov.uk/customers/bills electricitv.htm
38 4.15 Figure 2 shows the contractual relationships between the principal participants and also the flow of cash to the distribution businesses - for both connection and use of system.
Figure 2 - Contractual relationships and cash flows
CUSTOMER
(use of system) (connection)
Supply Connection Agreement Agreement
SUPPLIER Use of System DISTRIBUTOR Agreement
£€$ (use of system)
4.16 The business of making the physical connection to the network is the responsibility of the DNO82 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 connection83.
4.17 The service performance and business revenues associated with the DNO’s licensed business are regulated. The business structure and regulatory treatment of the DNOs is an important consideration when contemplating any new incentive mechanisms.
Calculation of DNO regulated revenues 4.18 The Regulator, after consultation with each of the distribution businesses, sets the maximum revenue which the DNOs are allowed to recover from customers. This,
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. The connection agreement arrangements for domestic customers are different as a result of the Utilities Act 2000. These are explained in section 3 (paragraph 3.23).
39 so called ‘price control’ is set, and usually runs for, a period of five years84. This allowed revenue is based upon the regulator’s view of: • 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 amount of money needed to run the distribution business (operational expenditure - Opex); • the worth of the existing network assets (the so-called Regulatory Asset Base, or RAB, value) plus an amount for depreciation; 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).
4.19 In simple terms, the annual allowed revenue is determined by the sum of: • the capital return on the regulated asset base (appropriately adjusted for depreciation and investment); • an amount to run the business; and • an allowance for depreciation.
4.20 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.
Additional revenue drivers 4.21 Once the regulator has arrived at the permitted levels of capex and opex, the revenue, which the DNO can earn, is described in terms of the maximum average charge per unit (kWh) distributed. The allowed revenue expression includes of number of ‘tariff baskets’ in recognition of a number of individual customer groups.
4.22 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.
4.23 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 losses - calculated on a ten year rolling average basis. In addition, DNOs are
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.
40 allowed to retain approximately half85 of any additional revenue earned as a result of increasing the number of units distributed.
Capital expenditure (capex) 4.24 This is the amount of money needed to invest in the distribution network in order to maintain the required service levels and to comply with the relevant environmental and safety obligations and responsibilities.
4.25 The regulatory framework recognises the importance of continued capital investment in the distribution system. Expenditure on the network gives rise to a significant proportion of distribution business revenue. By definition 86, and as a result of the physical nature of distribution systems, the benefit derived from expenditure on network assets will be delivered over the long term - typically 40 years.
4.26 As a consequence, the annual allowed revenue does not, specifically, include an amount directly for the purchase of network assets, but provides, instead, for a market rate of return such as to attract the necessary levels of investment from the marketplace87.
4.27 From a regulatory perspective capex is usually divided into load-related expenditure (LRE) and non-load related expenditure (NLRE).
4.28 LRE is money spent by the DNO on customer driven work - such as new business connection costs and also reinforcement work which may be the result of general load growth. It is recognised that the need for this sort of capital investment is not fully within the control of the DNO.
4.29 NLRE mainly represents the money spent on the replacement of time expired assets. As lines, cables and transformers reach the end of their useful life they
85 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. 86 A capital cost is the cost of a resource whose consumption is associated with generating revenue in more than one accounting period. Any cost which results in financial benefit beyond the accounting period in which the costs were incurred, is considered to be a capital cost. 87 A detailed discussion on accounting practices and cost of capital is beyond the scope of this report. However, a useful discussion on the financial issues associated with the regulation of distribution businesses can be found in the Offer consultation paper: ‘Reviews of Public Electricity Suppliers 1998 to 2000, Distribution Price Control Review, May 1999’.
41 will usually require replacement 88. Asset replacement accounts for a large proportion of allowed capital expenditure89
Operational expenditure (opex) 4.30 This is the amount of money which is required to run the business on a day-to-day basis. It covers costs such as: • maintenance of equipment and repairs to damaged and faulty cables and lines; • office rent, energy bills and employee wages; and • NGC connection (exit) charges and distribution system business rates.
4.31 Whereas capital investments are expected to be of benefit to the business for many years into the future, and are treated as such in the regulatory accounts, operational expenditure gives rise to benefit in the short term - within the accounting period that the cost is incurred. Opex is sometimes referred to as revenue costs.
4.32 In the past, Ofgem has used a benchmarking process to compare the operational expenditure across all of the distribution businesses in England and Wales and to arrive at what it believes to be the cost of running an efficient distribution business.
The regulatory asset base (RAB) 4.33 This regulatory asset base (RAB), or regulatory asset value (RAV) as it is sometimes known, is the worth of the existing network assets. If the DNOs are to secure access to funds on commercially attractive terms then the RAB must be capable of delivering a market return on invested capital. The level of return must reflect market expectation and must be commensurate with the risks.
4.34 Initially, the RAB was set on the basis of the market value of each of the Public Electricity Supply (PES) businesses at close of trading on the day of flotation - appropriately adjusted for subsequent shareholder instalments 90.
4.35 Fora medium sized PES, the initial RAB value was typically, of the order of, £500m. This asset value was adjusted at subsequent distribution price control reviews to account for new capital expenditure, depreciation and for changes in the cost of capital.
88 Rationalisation of network voltage levels, system reconfiguration and technical advancement in equipment design and materials - means that assets are not always replaced on a like-for-like basis. 89 To date, the total NLRE in GB has generally been greater than LRE. In 1999, Ofgem’s proposals for total NLRE in England, Wales and Scotland was £3.34bn and for LRE was £2.51bn (source: Review of Public Electricity Suppliers 1998 to 2000, Distribution Price Control Review, Final Proposals, December 1999). 90 Further adjustments were made for the divestment of the PES interest in National Grid plc and also for any non-distribution capital.
42 The cost of capital debate 4.36 This represents the level of return required by the financial markets in order to attract investment into the distribution business. Capital is obtained either from both bank loans (debt capital) or from shareholder investment (equity capital). The cost of capital is usually calculated as a weighted average cost of these two sources and is known as the weighted average cost of capital (WACC).
4.37 Distribution companies will usually strive to develop a company financing structure which delivers the optimum WACC.
Depreciation 4.38 The reduction in the value of the network assets due to wear and tear91 is a cost which will be faced by any asset-owning business. This cost must be provided for in the regulatory allowances so that it can be appropriately recovered.
4.39 The present regulatory treatment allows for the DNOs to recover depreciation from network users and so it is included in DUoS charges. Depreciation comprises a significant part of the DNOs’ allowed revenues.
4.40 Since Vesting, capital expenditure has generally exceeded depreciation and so the value of the DNOs asset base has steady increased. At some stage in the future, the amount of capital expended on the network is likely not to exceed depreciation and the asset value will stabilize.
Costs of connecting embedded generation
4.41 Connection of embedded generation to distribution networks will, in virtually every case, give rise to additional costs. In some cases, negative costs may accrue as a result of the generator having a positive impact on the network - but these are likely to occur over varying timescales and are also likely to be rather more difficult to quantify.
4.42 This part of the section looks at the DNO costs, and the impact on regulatory revenues, which may result from the connection of embedded generation.
DNO cost perspective 4.43 Embedded generation drives DNO costs both in terms of new network assets, and in the operation of new and existing assets - capital and operational costs.
Capital costs 4.44 The DNOs might have to replace otherwise adequate existing infrastructure to cope with increased fault levels, or to control voltage regulation. These costs relate to both system infrastructure - such as switchgear, cables and lines - and also to control and IT systems.
In the case of distribution businesses, deprecation may also provide for technical obsolescence.
43 4.45 It should be noted however, that the present ‘deep ’ connection policy for connection of embedded generation means that it is the generation developer who is required to make the capital outlay associated with reinforcement costs.
4.46 Consequently, under the present regulatory regime, the value of any assets installed to accommodate embedded generation does not enter the DNO’s regulatory asset base (RAB) and the DNO does not, therefore, earn a return on this capital expenditure. This is one of the main reasons why the present arrangements do not provide the DNOs with an incentive to connect embedded generation .
Operational costs 4.47 Maintenance costs are likely to be affected by the connection of embedded generation. These may increase as a result of connecting generation but may also, in some circumstances, be reduced.
4.48 A significant operational challenge, and potential additional DNO cost source, is, however, likely to come from the management and service of a new customer base - the generator connectees. This must be done without affecting services to existing demand customers and, potentially, from within an operational regime of increasing intervention from real-time system management.
DNO revenue perspective 4.49 From the DNO perspective no allowance has been made in the current price control for any additional costs which may arise from any new capital, or operational, requirements associated with the connection of increased levels of embedded generation.
4.50 The present regulatory arrangement means that, in general, DNOs will prefer to invest capital rather then incur operational costs. Capital expenditure is treated as an investment and the regulatory regime allows DNOs to earn a reasonable rate of return on ‘approved’ levels. Any capital expenditure above agreed levels may, or may not, continue to attract a return for the lifetime of the asset. This will depend upon whether the regulator considers that the money has been spent in the interest of the customer or whether it is simply a function of capital inefficiencies on the part of the DNO.
4.51 Under the present RPI-X regulatory regime the strongest driver on DNOs is to spend nothing and still achieve necessary outputs. Provided agreed outputs are met (and are expected to be met in the future), a capital under-spend is classed as an efficiency gain and, to date, companies have been allowed to keep the benefit. This comprises a return on the capital saving together with depreciation until the end of the regulatory period - this is 2% years on average for a five-year review period.
This issue of ‘deep ’ versus ‘shallow’ connection charges is examined in more detail by ILEX as part of a separate project under the DTI’s New and Renewable Energy Programme - ‘Distribution Network Connection: Charging Principles and Options’ (Agreement/contract ref. K/EL/00283/00/00).
44 4.52 Of course, as the capex investment creeps closer to the regulatory allowance, the “efficiency” margin is eroded, further strengthening DNOs’ disinclination to invest.
4.53 If capex investment greater than the regulatory allowance is made, then the DNO is not allowed income to support the investment and it is for debate with Ofgem as to whether this investment will be allowed for the purposes of calculating allowed income at the next review.
4.54 Operational costs (opex) are allowed - based on the opex of the “efficient ” companies. Any variation in opex from the regulatory assumptions at the price review flows directly to the bottom line.
The characteristics of an incentive framework
4.55 In this part of the section we examine the potential attributes of an incentive framework and explore the ways in which such a regime might work in practice.
Defining an incentive 4.56 Before a successful incentive framework can be designed and implemented, it is important to try to define what is meant by an incentive in the context of the regulated distribution network operators (DNOs). In particular, it becomes necessary to differentiate between financial penalties and financial incentives - in terms their commercial impact and potential consequences.
Incentives versus penalties 4.57 In general, incentives can be defined as instruments which change behaviour. Traditionally both incentives (‘carrot’) and penalties (‘stick’) are seen as incentives, though their properties may be very different.
4.58 Where a particular outcome can be defined precisely, rewards or penalties can have the same effect since, in either case, failure tomeet a target leads to a negative impact on business income. Where there is seen to be some ‘global’ merit in exceeding a given output target level, then the rewards approach may be more successful, since varying levels of achievement can be matched by a corresponding scale of payment levels.
4.59 For the DNOs, the structure of incentives already recognise the distinction between penalties and incentives. Forexample, under the present regime of ‘Guaranteed Standards ’, failure to meet particular service levels can lead to compensation payments to individual customers or to the risk of DNOs being fined under the Utilities Act for failure to meet defined ‘Overall Standards 93’.
Guaranteed Standards relate to service levels that must be met in each individual case. If the DNO fails to provide the level of service required, it must make a payment to the affected customer. Overall standards cover areas of service where it is not appropriate to give individual guarantees, but where consumers in general have a right to expect DNOs
45 4.60 More recently, Ofgem’s ‘Information and Incentives Project’ (IIP) has introduced graduated penalties for failing to meet customer service targets for 2002-2005 in respect of network performance and response to customers. The IIP also offers the prospect of a reward for out-performing service targets for 2004/5. This is capped at 2% of revenue, reflecting concerns that customers’ have not explicitly indicated a desire to pay more for a higher quality of supply.
4.61 This issue of the value placed on the performance of the distribution network, by its users, is an important consideration when attempting to define an incentive framework. It is important to align any incentives with relevant objectives.
4.62 In many business performance frameworks, penalties are likely to a part to play. Forexample, a penalty regime is likely to be particularly successfully where it is used to prevent ‘undesirable’ events - such as reductions in service quality or individual instances of poor customer service.
Cost recovery 4.63 It is also evident that pass-through of costs represents neither an incentive nor a penalty. Fora licence holder the right of cost recovery is often directly associated with licence, or other statutory, obligations. In this way the licence holder continues to be able to finance its functions once the new duty is taken on.
4.64 Whilst this ‘cost recovery’ approach may be appropriate where a new obligation can be clearly specified, it provides no incentive for the licensee to deliver any particular quantity of the new output - nor to deliver output at efficient levels of cost.
4.65 Any new activity could be funded using the existing regulatory approach of allowing a fair rate of return on approved capital expenditure and a permitted efficient level of operational costs. The cost of capital applied would need to be commensurate with the risks associated with financing any new activity. Having the right to earn this return on additional investment would allow the licensee to continue to fund its operations. However, it does not create a stream of surplus profit that might further encourage licence holders to proactively seek out more business.
4.66 In the context of embedded generation ‘cost pass-through’ may, therefore, only be an appropriate regulatory response where any new obligations can be precisely defined. If there is a desire to create an environment in which DNOs will also seek out further opportunities, then it might be appropriate to offer additional rewards. These could either be short term - relating to initial investment decisions, or enduring - such as to reward the subsequent operation of any new assets.
to deliver predetermined, minimum levels of service. (Ref. ‘Guaranteed and overall standards of performance - Final proposals, Ofgem, January 2001).
46 DNO opportunities for increased returns 4.67 In the current environment there are a number of ways in which DNOs can earn returns that differ from those assumed in the setting of the price control. They can be summarised as follows:
Cost out-performance 4.68 Where the company delivers the outputs required for less cost than assumed there will be increased levels of return and an associated increase in short term profit. In the longer term customers may also benefit from a downward adjustment to the regulatory asset base (RAB) to reflect capital expenditure (capex) savings or from lower cost estimates for the next regulatory price control review.
Increases in the capital base 4.69 Increased returns can result from additional investment which was not anticipated as part of the regulatory price control review and which results directly from customer requirements. This can lead to either additional up-front revenue from connection charges or to a larger increase in the RAB, on which future returns can be made.
Diversification and development of unregulated businesses 4.70 There may be opportunities to build on skills or requirements of the core business to offer services to a wider market, and thus to develop new income streams not directly subject to regulation. In the past, a number of DNOs exploited their telephony skills in this way and created separate subsidiaries offering telecoms services to a wider customer base.
Reduction in network losses 4.71 The price control includes an adjustment factor that rewards reductions in losses against a 10-yearhistorical average. Companies can therefore benefit for ten years from any changes in network components or configuration that lead to a sustained improvement in losses.
Increased units distributed 4.72 The present price control formula includes an increased revenue driver where the DNO can keep approximately half of any additional revenue collected from users as a result of distributing more kWh than planned. This was discussed in paragraph 4.23 .
Improvement in service quality 4.73 Ofgem’s Information and Incentives Project (IIP)94 has introduced the prospect of additional income where performance, against key measures of service, exceeds target. Output service measures include Customer Minutes Lost (CML), the number of customer interruptions (CI) and also telephone response standards. For
94 The IIP framework came into force in April 2002.
47 the period to 2005, the additional revenue opportunity is capped at a one-off benefit of 2% of annual regulated revenue.
4.74 In all of the areas above it is important to note that the opportunities to earn additional returns are not without risk - it is therefore feasible for returns to be reduced. Targets costs may prove too challenging, new investment may be limited by poor performance of the regional economy, diversification can fail and improvements in network losses or service quality may cost more to achieve than is available in rewards from price control adjustments.
4.75 In each case companies must choose whether the risks involved are justified by the returns expected. Similar judgements will have to be made in responding to the challenges associated with a growth in embedded generation.
Challenges associated with DNO Incentives for embedded generation
4.76 Although it is possible to examine and, to some extent, define the characteristics which may be required from a successful incentive framework, there are still a number of important issues which are likely to require careful consideration. This part of the section reviews some of the key issues.
Volume Uncertainty 4.77 Setting cost targets for DNOs will become much more difficult if the nature of work to be undertaken on the network becomes less certain. Out-performance has, in the past, mainly been achieved by delivering the required outputs more cheaply. This becomes much harder to establish if the levels of output required can not be predicted in advance. DNOs could find they have ‘overspent’ allowances because far more work needed to be done than was originally anticipated.
Impact Uncertainty 4.78 The range of embedded generation technologies and sizes is wide and varied. The impact which they have on the distribution network will depend on the type and concentration of new generation. For example, widely dispersed domestic generation95 will be very different in how it affects the local distribution network than, say, a small number of large wind farms. Some large offshore wind installations may even be connected to the transmission system and may, therefore, have minimal impact on the distribution networks.
4.79 The positioning of generation, especially in remote areas, will also have a critical effect on capital and operating costs. With such uncertainty it may become more difficult to rely on traditional incentives to drive the changes that are likely to be needed and to encourage the DNO businesses to plan and take the appropriate actions.
95 This may be domestic combined heat and power (DCHP) installations.
48 Benefits and payments 4.80 Whilst many of the costs associated with embedded generation may fall on the DNO, there will be a range of possible beneficiaries. The DNO may gain if the generator provides support to its existing network and local consumers may benefit from the local economic enhancement achieved by the new project. There may also be wider benefits to society since low-carbon technologies may replace existing fossil-fuelled generation.
4.81 If the DNO is to be offered incentives to support and encourage embedded generation, then the money has to come from somewhere. Within the present price control framework this revenue can only come from parties connected to, or using, the DNO’s system (via the licensed supplier). This would seem to prevent a customer located outside of the DNO’s licence region from being able to generate, or contribute to, regulatory rewards for the DNO.
4.82 Areas with substantial renewable resource could therefore face increased DUoS charges to support wider public policy objectives. For this reason, it may not be possible to rely solely on price control incentives to deliver the scale of changes needed in DNO behaviour if Government targets are to be met.
Generators can be both customers and/or service providers 4.83 For the DNO there is a fundamental question as to how to treat an embedded generator. An embedded generator might be considered just another customer wishing to make use of a range of network services or, alternatively, as a service provider - able to contribute positively to the DNO’s wider directives and responsibilities.
4.84 The answer may well be a combination of the two. This adds to the challenge for the DNO, which must construct suitable commercial arrangements to reflect this dual relationship, and ensure that services provided by the network are charged for, whilst services provided to the network, by the generator, are fairly remunerated.
4.85 The flow of funds between the embedded generator and the DNO may well define, at any one time, whether the generator is behaving as a DNO customer or as a DNO service provider.
Timescales 4.86 Not all parties involved in the delivery of embedded generation will have the same time horizons. For the DNO, the likelihood is that new network assets will have a potential life in excess of 40 years, whilst price controls have traditionally provided certainty for only 5 years. Many generation projects may involve assets with operational lives of 15 years, though where technological progress is rapid, business planning may be done over shorter periods.
4.87 Government carbon policies and plans could extend over many decades, but are themselves subject to the shorter duration political timetables. It may be difficult to balance the need for sufficient rewards to reflect the risks in the medium term, without making the short-term price effects unacceptable.
49 4.88 The answer may lie in creating a stronger sense of certainty around at least some elements of future price control settlements.
Incentive mechanisms
4.89 In this part of the section we review the incentive framework employed by the UK gas networks operator, Transco. An approach previously considered by Ofreg, the Northern Ireland regulator, is also briefly described.
Transco’s price control and incentives to invest 4.90 Transco, the monopoly UK gas pipeline owner and operator is subject to a price control that is governed by economic regulator Ofgem. The aims of the price control with regard to investment are to provide a framework within which Transco can invest efficiently to meet market demand for its services. The main investment service, which is to be incentivised, is the provision and maintenance of network capacity.
4.91 Capacity is required by gas shippers in order to enter gas into the National Transmission System (NTS) (entry capacity) and to off-take gas from it for supply to end users (exit capacity). Historically Transco has been accused of under investment in the NTS that has resulted in insufficient capacity at entry and exit to meet demand.
4.92 From April 2002, Transco has been subject to a new price control mechanism. This provides Transco with separate price controls for the NTS, the Local Distribution Zones (LDZs) and its metering business. At the NTS level the price control has also been split further between the Transmission Asset Owner (TO) role and the System Operator (SO) role96.
Entrycapacity incentives 4.93 The main function of the Transmission Asset Owner, in terms of the price control, will be to deliver pipeline capacity services to the System Operator. These services will include both maintenance of existing pipelines and investment in new infrastructure. The TO will receive signals from the SO to invest in new pipeline capacity through the auction of entry capacity and the contracting of interruptible exit capacity.
4.94 Under the price control mechanism, a series of output measures (OMs) for entry capacity are defined. The OMs indicate a level of capacity that Transco should sell under long-term auctions, up to 13 years forward. Transco receives a rate of return (6.5%) on capacity up to the OM.
4.95 Transco is incentivised, through the SO function, to make more capacity available over and above the OM level if there is a genuine market demand for it. The signal to invest is revealed by Transco being able to sell the additional capacity
As at May 2002, Ofgem is still in the process of making the necessary licence changes to formally implement these new arrangements.
50 via the auction at a price above a defined unit cost allowance. If Transco sell capacity above the OM level at a unit price higher than the unit cost allowance then it earns a higher rate of return on this capacity. The rate of return is related to the price achieved at auction and can be up to 12.25%.
4.96 However, Transco is not obliged to build this new capacity and can take a commercial risk that market demand will be less than indicated through the price auction. It is able to keep the proceeds of the sale of this capacity as incentive revenue and it must balance the risk against the purchase of capacity back from shippers should the need arise, i.e. if shipper gas deliveries are higher than Transco can physically accept into the NTS.
4.97 Transco is also incentivised to make less capacity available than the OM level where there is an absence of market demand by being able to defer investment and keep the capital expenditure (Capex) which it has been allowed under the price control.
4.98 Transco is also able to invest speculatively on the basis that market demand may increase by the time investment has been made, usually two-to-three years. Under this mechanism Transco would build new capacity without first having sold it to shippers via the price auction. If the anticipated market demand does not emerge and Transco fails to sell this capacity then it receives a reduced rate of return (5.25%) for this portion of capacity.
Exit capacity incentives 4.99 At present, Transco sells exit capacity at administered prices based on long-run marginal costs. It manages the supply of new exit capacity by insisting that some new and existing loads are interruptible. For large loads Transco has a generic contract called a Network Exit Agreement (NExA) that governs off-take rates and notice periods for amendments to nominated flows.
4.100 It has been proposed by Ofgem that under the new price control, all capacity is deemed to be firm and that all the NexA provisions are cancelled. Ofgem is concerned that Transco has over-contracted for interruptible capacity and placed artificial limits on sites’ off-takes through the NExAs.
4.101 Instead, Transco will be incentivised to secure only the interruption and off-take restrictions that it really requires for the safe and efficient operation of the NTS. Transco will be given a target amount of money with which to secure interruption and off-take rights. Transco will contract directly with the end-users.
4.102 If Transco cannot secure the rights that it requires at the right price then it will receive a clear signal that investment in new capacity is required.
4.103 If Transco is able to secure the rights it requires for less than the target level then it keeps some of the revenue as incentive payments. If Transco fails to beat the target then it faces some of the additional costs. The incentive revenue or costs are shared with shippers and Transco is subject to a cap and collar to limit their exposure.
51 An incentive based on kWh distributed 4.104 A approach which was recently considered by Ofreg97, as part of its distribution price control consultation to encourage the distribution business to connect more embedded generation, was an incentive framework based upon units (kWh) distributed.
4.105 The consultation paper 98 describes how, historically, the transmission and distribution networks have been required to carry the same number of units (kWh) - since virtually all power came from central, transmission connected, generation.
4.106 The connection of increasing numbers of embedded generators does, however, mean that it is possible for the distribution network to carry a higher number of units, in aggregate, than the transmission network99.
4.107 The consultation sought views on the extent to which the Northern Ireland distribution business shouldbe incentivised to carry more units (kWh) than the transmission network - thereby promoting the connection of embedded generation.
4.108 Following the recent review of Northern Ireland Electricity distribution charges100 it does not, however, appear that this idea will be implemented at this stage.
Potential solutions for DNOs and embedded generators
4.109 This part of the section discusses how some of the ideas already explored, or parts of those ideas, could be used to incenti vise DNOs to connect more embedded generation.
Requirements of an incentive regime 4.110 There is a wide range of possible measures that could be adopted to try to hasten the development of embedded generation within a low carbon future. Incentives can take the form of either rewards for performance or penalties for non performance. As we have discussed above, for a penalty based regime to be effective it would be necessary for the required outputs to be specified in considerable detail, and for regular monitoring and reporting, to be practical.
The Office for the Regulation of Electricity & Gas. Regulates the electricity and gas markets in Northern Ireland. 'Greening Transmission and Distribution', a consultation paper by the Director General of Electricity Supply for Northern Ireland, June 2001. (Ref. http://ofreg.nics.gov.uk/papers/Greening%20T&D.pdf) Suitable adjustments would need to be made to account for the units consumed by the small number of customers connected to the transmission network and for network losses. Transmission and Distribution price control review - initial proposals for Northern Ireland Electricity, Ofreg, March 2002 (Ref. http://ofreg.nics.gov.uk/papers/T%20&%20D%20paper%20march%2002.pdf)
52 4.111 Given the uncertainty around many aspects of the debate on embedded generation, a prescriptive approach to the performance of distribution networks with embedded generation may prove not to be the most appropriate way forward. This would require the regulator to take on a more active role in the detailed planning of network redevelopment. It is far from obvious that this would be an appropriate, or advantageous, industry development.
4.112 Consequently, the next part of the section focuses on the components of a reward based scheme which would be intended to offer the prospect of additional returns for DNO’s that successfully rise to the challenge of contributing to delivery of the Government’s environmental objectives
A possible ‘reward-based’ incentive scheme 4.113 The scheme is likely to have several components that need to be addressed separately.
Modified Infrastructure 4.114 Companies need to be encouraged to identify parts of their network where available renewable resources can not be accessed without infrastructure modifications. This could give rise to ‘speculative reinforcement’ plans that would make final connection of new generation projects more likely101.
4.115 DNOs might be expected to develop plans that will satisfy Government guidelines, in this case, by opening access to particular resources, perhaps highlighted in Premium Power Zones - as proposed in Ofgem’s recent consultation paper102.
4.116 The attraction to the DNOs would be the opportunity to add new assets to the regulated asset base, and use their design and construction skills to out-perform the cost estimates behind the original project approval.
Use of the Network 4.117 Once the network is capable of absorbing output from local generation it becomes important that DNOs encourage the use of the capacity that exists. For this purpose, a new charging framework should be introduced which is capable of recognising the location of embedded generation - particularly its proximity to local demand and any locational benefits which may accrue.
4.118 Charges ought to be made for use of the system by both generators and demand. It is for debate whether charges for use of the distribution system ought to be levied directly on generators or on the suppliers who purchase from the embedded generators. The later option has some attractions since it is capable of working
101 There is history, in the water industry, of investment made in response to (European) Government Directives which follows this approach. 102 Distributed generation: price controls, incentives and connection charging - further discussion, recommendations and future action, March 2002, 26/02.
53 within the present ‘supplier-hub’ trading arrangements and ensures the DNOs retain a limited number of counter parties.
4.119 A framework of entry and exit charges, where the existing grid supply points would be treated as network entry points - along with embedded generators - might be an appropriate approach103.
4.120 It should be recognised that regardless of cash flows through the industry, the charges to end demand customers are not likely to change - notwithstanding market forces and competition.
4.121 From a regulatory perspective, under this type of entry-exit charging regime, ‘allowed income’ may need to be increased sothat suppliers can be properly incentivised to ‘take’ electricity from embedded generation and DNOs can gain from the more intense usage of their networks. Without a new component of allowed income, generator charges would simply reduce supplier charges and the DNO would stand to gain nothing.
4.122 It might be possible to establish new allowed income on the basis of additional costs, and risks, incurred from more active system management. However simply providing for recovery of new costs is not, in itself, an incentive. What may be needed is an additional reward to incentivise the DNOs to take the initiative.
4.123 There needs to be some premium attached to kWh (or kW of peak demand) satisfied by embedded generation rather than by grid connected power stations. Such schemes can have the added benefit of supplementing the incentive to reduce losses, which also has wider environmental benefits.
Active Management 4.124 The third component of an incentive package could be to reward for active management of the network. This can be built around the same principles as the NGC system Operator Scheme.
4.125 The idea would be to agree a target cost for providing network management services, including the competitive procurement of some services from local generators, and to allow sharing of benefits as the company learns to perform the functions more cheaply.
A ‘three-pronged’ approach to DNO incentives 4.126 Such an approach is likely to provide opportunities for the DNOs to gain at each of the three stages in the network transformation process: • Investment;
A detailed review of the charging methodology and principles associated with connection to, and use of,the distribution system been undertaken by ILEX as part of a separate project under the DTI’s New and Renewable Energy Programme - ‘Distribution Network Connection: Charging Principles and Options’ (Agreement/contract ref. K/EL/00283/00/00).
54 • Network usage; • System management.
4.127 There remain questions over who should provide these extra sources of income. It was the view of one of the DNOs we consulted that to allocate all costs to the generators risks ‘choking off the demand that is intended to be encouraged. Furthermore, they believed that such an approach could only be used if it was clear that the system of Renewable Obligation Certificates (ROCs) was generating sufficient revenue to allow generators to pay without damaging the prospects for new projects.
4.128 Any alternative would be likely to need Government support, as well as that of Ofgem, since it would undoubtedly raise questions over regional pricing differentials and over who the ultimate beneficiaries would be.
DNO business structure 4.129 In order to recognise the differences in business risk associated with various DNO activities, and to support the investments proposals suggested above, it might be appropriate to review the basic internal structure of the distribution businesses. It may also be beneficial to segregate the DNO business activities into the three areas set out below.
Core licence activity 4.130 The core businesses activity is likely to be well specified in terms of what is required of the licensee. It may be fairly straightforward to determine the DNO performance in this area through measurement of compliance with the licence conditions and duties. The relative certainty of activity in the core business is likely to mean relatively low business risk with a commensurate rate of return.
4.131 It might be appropriate that the core business activity is managed through a system of financial penalties - since its expected output can be well defined.
Output target activity 4.132 There are likely to be a number of DNO activities which are associated with meeting or enhancing output performance measures - as set by Ofgem. These may be over and above the core licence duties and conditions but may nevertheless constitute an important business activity and give rise to significant business costs.
4.133 As an example, this might include the business activity associated with achieving network performance measures - such as customer minutes lost targets or customer interruption standards. Whilst some of the basic performance standards may fall within the core activity, there may be some benefit in separately categorising some of the costs associated with meeting some additional targets, or those associated with exceeding existing targets - where there is perceived to be some customer benefit.
4.134 This type of activity is most likely to lend itself to the application of an incentive regime. This may simply be an increase in the financial return which the DNO is
55 able to earn on capital expenditure associated with this type of output target based activity. This might apply to speculative capital investment associated with the connection of higher levels of embedded generation.
Market-driven commercial activity 4.135 This type of DNO costs may arise out of ‘non-core’ activities or may be directly associated with the performance of the network but be considered as a relatively high-risk investment. An example of this is the telecom business ventures which some of the DNOs recently embarked upon. DNOs are likely to be allowed to earn enhanced returns on this activity - although this may need to be supported by a clear commercial market need.
4.136 Alternatively, this type of activity might be applicable to highly speculative investment in network assets for the connection of embedded generation.
4.137 These three business activities are illustrated in Figure 3 below.
Figure 3 - Segregation of DNO activities
MARKET DRIVEN COMMERCIAL ACTIVITY
OUTPUT TARGET ACTIVITY
CORE LICENCE ACTIVITY
Governance
4.138 As has been set out in this report the incentives for DNOs to connect embedded generation span several areas. The purpose of this part of the section is to describe current governance arrangements associated with the creation and setting
56 of incentives and to comment on their appropriateness and interaction with other governance arrangements which impact on embedded generation.
4.139 The electricity industry, and specifically monopoly networks are regulated by Ofgem. Ofgem’s brief is to regulate areas of the gas and electricity industries where competition is not effective by setting price controls and standards to ensure customers get value for money and a reliable service.
4.140 Ofgem is governed by the Gas and Electricity Markets Authority (GEMA) and its powers are provided under the Gas Act 1986, The Electricity Act 1989 and more recently the Utilities Act 2000. Sections 10 and 14 of the Act insert sections 4AB and 3B into the Electricity Act 1989 and the Gas Act 1986 respectively. These sections require the Secretary of State to issue guidance to the Gas and Electricity Markets Authority on the Government's social and environmental policies, so that the Authority can make an appropriate contribution to the attainment of these policies. The Authority is obliged to have regard to the guidance. The same sections impose a requirement on the Secretary of State to consult the Authority and others before he issues the guidance.
4.141 GEMA determines strategy and decides on major policy issues. It is made up of non-executive and executive members, including a number of Ofgem directors. It may regulate its own procedures and as such has adopted rules to achieve this. In its last annual report GEMA referred to the issues surrounding embedded generation and outlined a work programme to take these forward. In doing so it recognised the influence of the work of Government created Embedded Generation Working Group (EGWG) and anticipated the formation of the Distributed Generation Coordination Group (DGCG) which is jointly chaired by the DTI and Ofgem.
4.142 It can therefore be seen that at a high level, there are already a number of influences on the setting and execution of policies which would effect embedded generation.
4.143 Ofgem is considering the issue of embedded generation under its social and environmental action plan, which it also receives specific direction on from Government and under the Utilities Act 2000. Clearly, this is only part of the story and there is also a coordination activity within Ofgem to ensure that embedded generation is specifically considered under the all important 2005 Distribution Price Review. During this year Ofgem is conducting a consultation exercise with the DNOs to establish the incentive measures which might be considered as part of the review.
4.144 Alongside this work and ahead of the price review, Ofgem is consulting on a number of other issues raised by the EGWG and highlighted for Ofgem action. Ofgem is also working with the Technical Steering Group (TSG) which has been established under the DGCG with a brief to deliver various workstream objectives associated with embedded generation. Members of the DGCG are represented in this activity as sponsors of the workstreams, and they report in turn to the joint chair of the group who will advise the Minister of progress.
57 4.145 There are also other bodies which have influence and interests in the fate of embedded generation and its ability to be accommodated in the networks. There has been a Royal Commission report on Climate Change which recommended action by Government to ensure networks could accommodate the expected growth in renewable embedded generation and more recently the Performance Innovation Unit (PIU) of the Cabinet Office has identified actions to which Government is considering its response.
4.146 Inevitably many of these organisations will create tensions for Regulators in delivering their primary duties to protect the customer. Ofgem has identified that it would look to Ministers and other government bodies with direct environmental responsibilities to take the lead where action would have significant financial implications for customers or for the companies that Ofgem regulates.
4.147 The timescale for change within the electricity industry associated with embedded generation is particularly challenging. On the one hand the Regulator has to balance devising charges and incentives to encourage the efficient use of the distribution network, against the backdrop of short run and long run decisions.
4.148 In the short run there is a question of how to allocate existing resources efficiently, whereas in the long run there is a question of ensuring investment is made efficiently. A regulated electricity network which naturally evolves, or where demand has limited growth is one thing, but one where there is an active Government target to seamlessly install generation up to a third of existing (transmission system connected) capacity in the distribution system by 2010 is altogether different.
4.149 Within this period there will be two price reviews, and probably an enhanced incentives project, but with no potential guidance between reviews. It is against this backdrop that Distribution Network Operators will be seeking to anticipate the regulated environment, in advance of capacity actually being connected.
4.150 Given the asset lives of the network, the statutory Governmental guidance given to GEMA in these circumstances, will also have to span several terms of Government. This presents challenges for a Regulator that presently has promotion and protection of the customer at its heart. Increasingly other values will no doubt have to be reflected. The recently published cross departmental consultation on Energy Policy seeks views on a proposed redefinition of DTI’s energy policy objective sothat it might become:
“the pursuit of secure and competitively priced means of meeting our energy needs, subject to the achievement of an environmentally sustainable energy system
4.151 It remains to be seen what new Governance arrangements flow from such a bold statement and how they effect embedded generation and access to the networks.
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59 ANNEX A: DNO QUESTIONNAIRE
The following questionnaire was sent out to the three participating DNOs in advance of conference calls.
CONNECTION INCENTIVES FOR DISTRIBUTION NETWORK OPERATORS (TASKS A, B AND C)
Introduction This brief note sets out the areas, which ILEX would like to further explore with the three DNOs who have kindly agreed to assist with the UU/ILEX project on embedded generation connection incentives for DNOs.
Although we would have liked to meet up face-to-face to discuss some of these issues, the work has to be delivered within a tight budget which does not provide for off-site meetings for this part of the project. We hope that this prompt sheet/questionnaire, and a follow-up phone call, will enable us to gather sufficient information to give the report the required DNO input and balance.
Part of the work will explore future options for appropriate incentive mechanisms for DNOs to connect embedded generation. The intention is to share these deliberations with the DNO community. This is likely to be arranged through United Utilities who are collaborating on the project.
All of the information gathered will be treated as confidential and will not be used for purposes other than the ETSU work without the express permission of the parties involved. All contributors’ identities will remain anonymous and an unattributable summary of results will be compiled for disclosure to United Utilities and for general ETSU publication.
These questions are designed to understand the behaviour of DNOs, given the historical incentives provided by licence and statute as well as commercial considerations.
60 Questions and points for discussion
It would be useful if the following issues could be considered in advance of our telephone call.
Existing statutory and regulatory obligations onDNOs (pre-Utilities Act 2000) a) The Electricity Act 1989 and the PESs licences required PESs, in carrying out distribution connection works, not to discriminate between “classes of persons” and, in setting charges for use of system, not to “restrict, distort or prevent competition in the generation or supply of electricity”.
i) How were these requirements interpreted in your company in the context of providing connections for embedded generation (EG)?
ii) Do you believe there were any aspects of the statutory and regulatory obligations (pre-Utilities Act) which restricted or discouraged embedded generation?
iii) What was the company’s approach to accommodating generators onto the network? Under what circumstances would a generator connection
61 be discouraged? To what extent did your company promote the connection of embedded generation connections?
iv) Were there any specific policies or procedures in place to ensure that charges levied on generation (full, ‘deep ’, connection costs) were consistent with those for demand customers (connection + DUoS)?
v) Were your company incentivised, either internally or externally, to connect embedded generation? If so, how and why.
62 Embedded Generation Connection process b) We would like to explore the various internal processes and policies associated with the way in which your company deals with applications from embedded generators (EGs) to connect to your distribution network. i) In the past, were EG connection applications given equal priority to those from load customers? If not, why?
ii) How is the situation of simultaneous applications for both EG and demand co-ordinated? What about more than one generator application? How are second-comers treated?
iii) Were charges levied for preliminary studies for connection of embedded generators? Are developers for speculative demand charged for feasibility/initial studies (e.g. housing developers)?
iv) What timescales were involved in the connection process?
63 v) In arriving at a charge for connecting generation, how does your company account for: - existing surplus system capacity; - system betterment; - O&M - are these rates the same as for demand?
64 Introduction of the Utilities Act 2000 c) The Utilities Act 2000 places a new statutory obligation (general duty) on Distribution Licence holders to facilitate competition in supply and generation of electricity. We would be interested to hear how the answers to the questions in section a) parts iii, iv and v; and section b) above, have changed as a result of this? i) How were these new requirements interpreted in your company in the context of providing connections for embedded generation (EG)? Were there any policy or procedural changes?
ii) How far do you feel that this new obligation will go towards incentivising DNOs to connect more embedded generation? How, as a DNO, do you feel that you can “facilitate competition in generation”.
Incentives for connecting embedded generation d) We would welcome your thoughts on commercial and financial incentives for DNOs to connect EG.
65 i) How does your company view the connection of increased levels of EG in terms of its impact, or potential impact, on business performance? What does your company see as the potential commercial and regulatory consequences?
ii) Has your company previously identified any particular commercial and/or financial benefits, or opportunities, associated with connecting EGs? How has this changed with the introduction of the Utilities Act 2000 and the new Distribution licences?
iii) Should the Government targets for increased levels of embedded generation be met through market mechanisms or through a centrally administered support mechanism?
iv) What do you believe would be the most equitable (to all parties) and effective way of incentivising DNOs to connect more EG?
66 Although not directly relevant to the specific tasks (Tasks A, B & C) in the project. We would also welcome your views on the following:
Use of Embedded Generation as distribution network service provider? e) Traditionally, embedded generation has been connected for the purpose of commercial generation of energy - i.e., as a network customer. i) What do you believe are the short, medium and long-term prospects of DNOs using EG for the provision of network services (voltage control, security (P2/5), availability, demand control etc) and deferral of capex (reinforcement)?
ii) Do you actively seek-out embedded generation solutions to network problems?
iii) Do you ever enter into, or consider entering into, commercial contracts with EG for such services?
67 iv) Do you consider it possible for EGs to compete with distribution assets (and demand customers), on a ‘level playing-field ’ for the provision of network services?
68