Review of Bord Gáis Éireann’s Natural Gas Supply Tariffs and

the Structure of Distribution Use of System Tariffs

A Consultation Paper

CER/04/182 10 May 2004

Contents Executive Summary.......................................................................................................................i 1. Introduction .......................................................................................................................... 1

1.1. Background ............................................................................................................................................ 1 1.2. The Commission’s 2002 and 2003 Tariff Reviews .......................................................................... 1 1.3. Aim, Scope, and Approach to the 2004 Gas Tariff Review........................................................... 2 1.4. About this Paper ................................................................................................................................... 3 1.5. Submission of Comments on this Paper........................................................................................... 4

2. Core Principles...................................................................................................................... 6 2.1. Introduction ........................................................................................................................................... 6 2.2. Protecting Consumers .......................................................................................................................... 6

2.2.1. Transmission and distribution ................................................................................................... 6 2.2.2. Regulating Supply Activities....................................................................................................... 6 2.2.3. Cross Subsidisation...................................................................................................................... 7

2.3. Cost Reflectivity .................................................................................................................................... 7 2.3.1. Introduction.................................................................................................................................. 7 2.3.2. Competitive Disadvantage.......................................................................................................... 7 2.3.3. Financial Viability and Economic Pricing................................................................................ 7 2.3.4. Social Issues and Cost Reflectivity ............................................................................................ 7

2.4. Promoting the Utilisation of the Gas Networks.............................................................................. 8 2.5. Promoting Competition ....................................................................................................................... 8 2.6. All-Island Market .................................................................................................................................. 9 2.7. EU Legislation ....................................................................................................................................... 9 2.8. Environmental Policies ...................................................................................................................... 10

3. Tariff Design Principles.......................................................................................................11 3.1. Introduction ......................................................................................................................................... 11 3.2. Basis for Setting Prices ....................................................................................................................... 11 3.3. Estimation of Marginal Costs ........................................................................................................... 12

3.3.1. Distribution Network Costs..................................................................................................... 12 3.3.2. Peak Gas Costs........................................................................................................................... 13 3.3.3. Commodity (kWh) Costs.......................................................................................................... 14 3.3.4. Customer Related Costs............................................................................................................ 14

3.4. Customer Characteristics and Relationship with Costs ................................................................ 15 3.5. Determining Tariff Categories .......................................................................................................... 16 3.6. Structuring the Tariffs ........................................................................................................................ 16

3.6.1. Connection Charges .................................................................................................................. 17 3.6.2. Fixed Customer Related (Supply) Charges ............................................................................ 17 3.6.3. Demand Charges - for Customers with Daily Metering...................................................... 17 3.6.4. Demand Charges - for Customers with Non-Daily Metering ............................................ 18 3.6.5. Commodity Charges.................................................................................................................. 18 3.6.6. Seasonal Charges........................................................................................................................ 18 3.6.7. Interruptible Tariffs ................................................................................................................... 19

3.7. Adjustments to Meet Financial and Other Criteria ....................................................................... 19 4. International Tariffs............................................................................................................ 20

4.1. Introduction ......................................................................................................................................... 20 4.2. Points of Interest for the Current Review ...................................................................................... 20

5. Distribution Use of System Tariff....................................................................................... 22 5.1. Introduction ......................................................................................................................................... 22 5.2. The 2002/3 Tariff Structure.............................................................................................................. 22

5.2.1. Statistical Approach................................................................................................................... 23 5.2.2. Customer Categorisation .......................................................................................................... 23 5.2.3. Grouping of Network Assets................................................................................................... 23 5.2.4. Revenue Recovery Requirement of each Network Asset Group ...................................... 24 5.2.5. Allocation of Costs across Customer Categories.................................................................. 24

5.2.6. Deriving Customer Unit Capacity and Commodity Charges ............................................. 25 5.2.7. Summary - 2002/3 Tariff characteristics................................................................................ 26

5.3. 2003/4 Tariff calculations and structure ......................................................................................... 27 5.3.1. Merging a ‘Connection’ Approach with a ‘Statistical’ Approach ....................................... 27 5.3.2. Determination of Bord Gáis Distribution’s Allowed Revenues ........................................ 28 5.3.3. Impact of Roll-out of Daily Metering for I/C on Estimates of Market Capacities ........ 28 5.3.4. Summary - 2003/4 Tariff Characteristics............................................................................... 29 5.3.5. Additional Issues with Current Distribution Tariff Structure ............................................ 29

5.4. Issues for Future Distribution Tariff Structure.............................................................................. 29 5.4.1. Introduction................................................................................................................................ 29 5.4.2. Connection Policy...................................................................................................................... 30 5.4.3. Form of Use-of-System Prices................................................................................................. 32 5.4.4. Use-of-System - Capacity:Commodity Split .......................................................................... 33 5.4.5. Customer Differentiation ......................................................................................................... 33 5.4.6. Categories of Customer ............................................................................................................ 34 5.4.7. The Form of Charges ................................................................................................................ 35 5.4.8. Distribution Competition ......................................................................................................... 35

6. Natural Gas Supply Tariffs ................................................................................................. 37 6.1. Introduction ......................................................................................................................................... 37 6.2. Franchise Supply Tariffs .................................................................................................................... 37

6.2.1. The Current Franchise Supply Tariffs .................................................................................... 37 6.2.2. Issues with Current Franchise Supply Tariffs ....................................................................... 42 6.2.3. Future Supply tariff structure................................................................................................... 45

6.3. The Eligible market............................................................................................................................. 50 6.3.1. Current Eligible Market Pricing............................................................................................... 50 6.3.2. Eligible Market Pricing - Issues for Consideration............................................................... 51

7. Supply Revenue Formula.................................................................................................... 55 7.1. Introduction ......................................................................................................................................... 55 7.2. Form of Regulation............................................................................................................................. 55 7.3. Revenue Control Formula for Electricity Supply .......................................................................... 56 7.4. Controllable Costs............................................................................................................................... 57

8. Conclusion .......................................................................................................................... 58 Appendix 1: Marginal Cost Formula ......................................................................................... 59 Appendix 2: Calculation of ESB PES Annual Allowable Revenue.............................................61 Appendix 3: International Tariffs .............................................................................................. 66 Appendix 4: Summary of Issues .................................................................................................81 Appendix 5: Glossary of Terms ................................................................................................. 84

Executive Summary

The Commission for Energy Regulation (“the Commission”) is overseeing the liberalisation of the Irish natural gas and electricity markets, which is proceeding on a phased basis with a view to full market opening in 2005.

In accordance with the Gas (Interim) (Regulation) Act 2002 the Commission is charged with approving the form and basis of charges to be applied for the use of the transmission and distribution systems and the nature and amount of charges applied to final customers for the supply of natural gas. Where necessary the Commission may give directions to Bord Gáis Éireann in respect of the basis for such charges.

The current Bord Gáis Energy Supply (‘BGS’) tariffs for the franchise market were introduced gradually over the years and prior to the arrival of market liberalisation. Given its monopoly position, creating competition within the gas market was not a consideration in developing these particular tariffs. Due to developments in the introduction of competition into the market, the Commission now considers that the time is right for a complete review of both the franchise tariffs and the Regulated Tariff Formula (“RTF”). Similarly, there is a requirement to reassess, and if necessary revise, the current distribution tariff structures, given their interim nature when introduced in 2002 and in light of more recent developments.

The purpose of this consultation paper is to inform customers, market participants, and other interested parties about the Commission’s approach to reviewing Irish Natural Gas Supply and Distribution tariffs, and to set out a number of issues for consultation in relation to the current and future structure of gas tariffs.

In the paper the Commission sets out the core economic, financial, social, and regulatory principles underlying its approach to reviewing existing tariff structures. We explain the conflicts that can arise between these different obligations and the impact this can have on tariff design.

We explain the relevant economic theory of tariff design and draw on the experience of tariff design in other countries. We also examine the current distribution and supply tariff structures and highlight a number of issues for consultation that will be considered by the Commission during its review. In particular we highlight the issue of rising wholesale gas prices and the impact this will have in driving up gas supply tariffs. Finally, we set out for consultation our proposed approach to regulating the revenues of BGS.

This first consultation paper brings to a close Phase I of the Commission’s review of gas tariffs. In Phase II we will investigate the costs associated with the distribution and supply of gas to consumers and how these are allocated to different categories of customer. On the basis of this analysis we will consider the appropriateness of the current tariff structures (and customer categories), bearing in mind the core principles discussed in this document, and make proposals to introduce either entirely new tariff structures, amendments to current tariff structures, or both. Before making these proposals the Commission will assess the impact of these changes on different categories of customer.

In the meantime the Commission looks forward to receiving comments on this consultation paper by 2 June 2004.

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1. Introduction

1.1. Background

The Commission for Energy Regulation (“the Commission”) is overseeing the liberalisation of the Irish natural gas and electricity markets, which is proceeding on a phased basis with a view to full market opening in 2005. The liberalisation timetable is been driven by a number of legislative developments at a national and European level.

Since the introduction of the Gas (Interim) (Regulation) Act in 2002, and in the context of market liberalisation throughout the EU, the Irish natural gas market has undergone a number of important structural and regulatory developments to further encourage and facilitate competition within the marketplace.

Under this Act, the Commission is charged with approving the form and basis of charges to be applied for the use of the transmission and distribution systems and the nature and amount of charges applied to final customers for the supply of natural gas. Where necessary the Commission may give directions to Bord Gáis Éireann in respect of the basis for such charges.

The current Bord Gáis Energy Supply (‘BGS’) tariffs for the franchise market1 were introduced gradually over the years and prior to the arrival of market liberalisation. Given its monopoly position, creating competition within the gas market was not a consideration in developing these particular tariffs2.

The existing supply tariff arrangements relate to both the franchise market, where a suite of published tariffs sets prices for customers using below 5.3 GWh per annum (181,000 therms), and the RTF market for customers using between 5.3 and 264 GWh per annum (181,000 and 9m therms3), where prices are subject to a formula proposed by BGS and approved by the Commission in 2003.

On 1 July 2004, the eligibility threshold will fall further to incorporate all industrial and commercial customers4. It is anticipated that in 2005 the market will be fully open to all customers including domestic users.

Due to developments in the introduction of competition into the market, the Commission now considers that the time is right for a complete review of both the franchise tariffs and the Regulated Tariff Formula (“RTF”). Similarly, there is a requirement to reassess, and if necessary revise, the current distribution tariff structures, given their interim nature when introduced in 2002 and in light of more recent developments.

It is expected that the outcome of the review will be implemented from 1 October 2004. The current tariff arrangements have been extended until such time as this review has been completed.

1.2. The Commission’s 2002 and 2003 Tariff Reviews

Tariffs for the use of the distribution system were introduced and approved by the Commission for the first time in October 2002. Since then the Commission has completed a review of Bord Gáis’ revenue entitlement for the use of the distribution pipelines up to 2007. BGÉ was directed to inflate the 2002/3 tariff charges to ensure the 2003/4 recovery would meet allowable revenue requirements. This approach did not address the need to adjust “relative costs” among the various customer categories. The review did not include an assessment of the Distribution tariff structure.

In 2003, the Commission undertook the first review of Bord Gáis’ supply tariffs in both the competitive and non-competitive markets. Prior to this, natural gas supply tariffs in Ireland had effectively remained unchanged since the mid 1990s, although some additional tariffs were introduced 1 The ‘franchise market’ consists of all customers who are not eligible to change supplier and are therefore supplied by BGÉ.

2 BGÉ would have considered the competitive position of natural gas versus competing fuels such as oil.

3 For clarity, throughout the document ‘m’ refers to ‘million’.

4 In accordance with the Commission Direction 04/130 newly eligible customers on 1 July will continue to be priced on the appropriate franchise tariff until further notice. The further market opening in July is pursuant to Directive 2003/55 EC.

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during that period. Rising gas prices coupled with inflationary effects meant that, in general, gas tariffs lagged the underlying costs of serving natural gas customers. Section 6.2.2 discusses how increasing wholesale gas prices have exerted an upward pressure on supply tariffs.

On completion of its 2003 review, the Commission approved a 9.1% increase in supply tariffs for gas delivered to the non-competitive (or franchise) market. This increase was introduced largely to recover previously incurred heavy infrastructure investment and also to reflect the steep rise in the cost of gas on the commodity markets that had occurred over the past few years, particularly in 2000/1. The Commission was in a position to limit this increase due to the effect of favourable wholesale gas prices that Bord Gáis had availed of by entering into beneficial long-term gas contracts.

Following the 2003 review, Bord Gáis’ supply activities in the competitive market were monitored for the first time. The Commission directed Bord Gáis to introduce a Regulated Tariff Formula for the purpose of pricing gas supplied to eligible customers. The intention of this tariff formula was to ensure that all such customers would be offered a single, transparent market related tariff from Bord Gáis, thereby facilitating the procurement and comparison of competing quotes from new entrant gas suppliers.

1.3. Aim, Scope, and Approach to the 2004 Gas Tariff Review

Against this background, the Commission has decided to undertake a review of the distribution and supply tariff structures. The general aim of this review is to develop tariff structures that will not only encourage efficiency in the use of the gas distribution network but which will also promote competition and fairness in the various customer categories, while setting charges that are as cost-reflective as possible, and that do not discriminate unfairly between different customers. Section 2 explains the various economic, financial, social, and regulatory principles that the Commission must take into account in meeting this general aim.

The project scope is generally limited to: (1) the development of a Supply Control Revenue Formula, a reconciliation of the BGS outturn revenue for the period 2003/4, and setting BGS’ revenue for 2004/5; (2) a review of Natural Gas Supply Tariff Structures including a review of the Application and Structure of the RTF; and (3) review of Distribution Use of System Tariff Structures. Included within the scope is: (a) a review of current methodologies used by Bord Gáis’ Distribution and Supply business units in allocating its costs to each customer category, (b) a review of customer categories and whether/how these should be redefined, (c) a review of the number of tariffs and components within each tariff and whether these should be altered.

The project scope does not extend to a review of Transmission tariff structures or to the Transmission and Distribution revenue formulae both which have been fixed for the four-year period ending 30 September 2007. The Commission and its consultants (a consortium including Economic Consulting Associates, Petroleum Development Consultants, and Enercomm International) will broadly take the following approach to the project:

Phase I – Contextual Review

1. Identify the key economic, financial, social, regulatory, and other principles that need to be considered in revising current tariff structures and in developing a revenue control formula for BGS;

2. Research the structure and background to the existing tariffs and identify issues for potential further investigation in Phase II;

3. Conduct a review of distribution and supply tariffs in a sample of different countries highlighting any points of interest for Ireland;

4. From 2) and 3) above develop some high level tariff options for further investigation in Phase II;

5. Issue a consultation paper (early May 2004) capturing the work undertaken at steps 1) to 4) seeking feedback from market participants, customers, and other interested parties on the current tariffs and inviting representations on the future structure of tariffs.

6. Issue a response paper (early June 2004) summarising responses received to the public consultation process.

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Phase II - Quantitative Analysis

1. Review cost structures of BGÉ Distribution5 and Supply; 2. Review of cost allocation methodologies used to allocate costs to different customer categories

within BGÉ Distribution and Supply business units; 3. Review BGS revenue and develop revenue control formula; 4. Develop Distribution and Supply Tariff designs; 5. Conduct customer (billing) impact analysis; 6. Release second consultation paper (July 2004) setting out the Commission’s proposed decision

on the final distribution and supply tariff structures and the BGS Revenue Control formula; 7. Issue Commission’s final Direction to BGÉ (August 2004) on Distribution and Supply tariffs

and Supply revenue, to include responses to comments received during the Phase II consultation process.

BGÉ will begin to implement the Commission’s August 2004 Direction from 1 October. At this stage it is not possible to anticipate what degree of change to tariff structures this Direction might introduce. However, the Commission will give careful consideration to the timing and process of transitioning from old to new tariff regimes, and would expect to give an indication about such transitioning in August 2004.

1.4. About this Paper

The purpose of this paper is to inform customers, market participants, and other interested parties about the Commission’s approach to reviewing Irish Natural Gas Supply and Distribution tariffs, and to set out a number of issues for consultation in relation to the current and future structure of gas tariffs. (Please refer to Section 1.5 for details of how to respond this paper.)

Tariff design is a complex subject. For the benefit of the less informed reader we have tried to minimise this complexity by placing as much technical information as possible in the appendices. It is not essential to read these appendices in order to fully understand the key points raised in the paper.

Section 2 sets out the Core Principles underlying our approach and explains the choices that must be made in trying to address the inherent contradictions that exist between some of these economic, social, financial, and regulatory principles. Section 3 explains the key economic principles underlying tariff design. Section 4 summarises observations from a review and comparison of international gas tariffs. This section looks at supply and distribution tariffs in other countries and identifies potentially suitable options worthy of further investigation in the Irish context.

Section 5 firstly reviews the current Distribution tariff structures and secondly identifies some of the issues that the Commission will examine when considering future tariff structures. Section 6 contains a review of the current Supply tariff structures, including the RTF, and sets out some of the issues that will be investigated further during the analytical phase of the review. Section 7 concentrates on the proposed mechanism to be used for regulatory control of BGS’ Revenue.

There are a number of appendices attached to the main paper. Appendix 1 presents the marginal cost formula used in our proposed approach to tariff design. Appendix 2 sets out the calculation of allowable revenues for ESB PES. Appendix 3 gives details of tariffs in other countries. Appendix 4 summarises the issues raised in this document, while Appendix 5 provides a glossary of terms.

5 Note, this review of BGÉ Distribution (BGD) cost structures, does not focus on the allowed revenues of BGD (which have already been set and are outside the scope of this review), but rather to help determine the best way to allocate those costs to various network users.

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The following table is offered as a guide to readers to assist in navigating around the document.

Section Title Suggested readership

2 Core Principles All

3 Tariff Design Principles Only those requiring an understanding of the economics behind tariff design.

4 International Tariffs All

5 Distribution Tariffs See 5.2 and 5.3 below.

5.2 The 2002/3 Tariff Structure

For those interested in the 2002/3 distribution tariffs.

5.3 2003/4 Tariff Calculation and Structure

For those interested in the 2003/4 distribution tariffs.

5.4 Issues for the Future Distribution Tariff Structure

All

6 Natural Gas Supply Tariffs See 6.2 and 6.3 below.

6.2 Franchise Supply Tariffs All (in particular for those interested in how wholesale gas prices have exerted an upward pressure on supply tariffs. Readers with an understanding of current franchise supply tariffs can skip section 6.2.1).

6.3 The Eligible Market All (though those with an understanding of current supply tariffs in the eligible market can skip section 6.3.1).

7 Supply Revenue Formula Those interested in the regulatory control of revenue BGS will recover through its tariffs.

In the paper a large number of issues are raised for consultation. These are separately numbered and highlighted in text boxes for ease of reference. Additionally we have summarised all of these issues in Appendix 4 to further assist the reader. A Glossary of Terms is provided in Appendix 5.

1.5. Submission of Comments on this Paper

During the review the Commission will issue consultation papers on its website (www.cer.ie), inviting comments from interested parties. This is the first of such papers and the Commission would encourage anyone with an interest in gas tariffs to respond to the specific issues raised and to make any other relevant points on issues not identified in the paper.

Comments should be sent, preferably in electronic format to Elaine Wallace at the Commission by 5pm on 2 June 2004. Contact details are as follows:

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Elaine Wallace

Commission for Energy Regulation

Plaza House

Belgard Road

Tallaght

Dublin 24

Tel: 00353 (01) 4000800

Fax: 00353 (01) 4000850

Email: ewallace@cer.ie

The Commission intends to make all comments public. However, any information submitted in confidence and not for publication should be clearly marked as such.

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2. Core Principles

2.1. Introduction

In carrying out its functions the Commission is required to act in a manner that: 6

• does not discriminate unfairly between holders of licences, consents and Bord Gáis Éireann, and

• protects the interests of final customers.

The Commission is also required to have regard to the need to:

• promote competition in the supply of natural gas, • secure that licence holders are capable of financing the undertaking of the activities which they

are licensed to undertake, • promote the use of renewable, sustainable or alternative forms of energy,

secure that there is sufficient capacity in the natural gas system to enable re•

expectations of demand to be met, and secure the continuity, security and qualit

asonable

• y of supplies of natural gas,

Add o the duty to:

advantaged and the elderly.

How e making policy

2.2. Protecting Consumers

iti nally, without prejudicing its duties listed above, the Commission has

• take account of the protection of the environment, • take account of the needs of rural customers, the dis

ev r, there are often conflicts between these different obligations. Therefore in decisions the Commission must carefully weigh up theses objectives and strike an appropriate balance between them. The remainder of this section explains the Core Principles underlying the tariff review and highlights some of the key influences on tariff design.

2.2.1. Transmission and distribution

ution systems are, inescapably, natural monopolies within a Natural gas transmission and distribgeographical area. The Commission has a duty to protect natural gas consumers from potential monopoly practices that might otherwise lead to high prices and excess profits. However, it is also in the interests of customers that sufficient investment is made in the network to ensure the continuity and security of supply of natural gas and this requires the Commission to establish a framework that ensures that licensees will be financially viable and capable of financing necessary investments. There is therefore a balance to be found between ensuring an appropriate level of security of supply on the one hand, and regulatory control of monopoly profits to within normal levels on the other hand. The Commission’s aim, through the regulatory framework, is to set costs at a level that is consistent with a profitable but efficient and secure gas industry.

2.2.2. Regulating Supply Activities

The wholesale market for buying of natural gas from up-stream producers and the selling of natural gas

to end consumers (supply activities) are not natural monopoly activities. The retail market for natural gas has gradually been opened to competition and will be opened to full retail competition starting in 2005 thus allowing every natural gas consumer the right to choose a supplier of natural gas. Initially, however, the choice of supplier will be limited. At present there are three suppliers active in the market, including Bord Gáis Supply (BGS), but BGS will continue to be dominant in some segments of the market for the immediate future. In the interest of consumers the Commission will therefore continue to regulate the revenues earned by BGS and natural gas tariffs charged by BGS until such time as the Commission deems the market to be sufficiently competitive.

6 Electricity Regulation Act, 1999, Section 9, as amended by the Gas (Interim) Regulation Act of 2002.

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2.2.3. Cross Subsidisation

The Commission’s duties include the protection of customers and this is interpreted to include the protection of any one group of consumers from subsidising any other group of customers. For this reason, and for other reasons discussed below, tariffs should be cost reflective. But this leads to conflicts between the Commission’s obligations, on the one hand, to protect customers and to be non-discriminatory between holders of licenses, with its obligation to take account of the needs of rural customers, the disadvantaged and the elderly on the other hand.

2.3. Cost Reflectivity

2.3.1. Introduction

Cost reflectivity essentially means that prices are set at a level that would be achieved if there were a perfectly competitive market7. In such a market, prices would be set at levels that:

• match the marginal costs8 of supplying customers9, and • represent the most efficient level of costs attainable using the technology available10.

The method of calculating marginal costs by customer type is described in Section 3. Here we note some of the conflicts that arise.

2.3.2. Competitive Disadvantage

Subject to its other duties, the Commission will generally seek to ensure that prices are cost reflective. This is partly to protect consumers from cross-subsidising other consumers but cost reflectivity is also important in the context of a competitive market. If the Commission were to require BGS to maintain tariffs that subsidise one group of consumers at the expense of others, this would give BGS a competitive disadvantage relative to other suppliers who are not burdened with this obligation. This would lead to ‘cherry picking’ by independent suppliers. Similarly, subsidised customers would face lower prices from BGS and therefore would be unlikely to attract competing offers.

2.3.3. Financial Viability and Economic Pricing

Economic principles would lead to high prices at times of capacity shortage, and low prices at times of surplus; but economic principles do not consider the need for financial viability of licensees. Surplus capacity in the transmission network, for example, would mean low economic prices. However, surplus capacity on the transmission network would generally require high prices in order to ensure financial viability. This leads to conflicts between the economic pricing principle that prices should reflect marginal cost, and the need for financial viability.

Consistent with its statutory obligations, the Commission proposes that economic principles (e.g., marginal cost) be used to design the structure of the tariffs while financial principles (e.g., recovering allowed costs) be used to determine the revenue control formulae.

2.3.4. Social Issues and Cost Reflectivity

Cost reflective pricing typically means the introduction of fixed supply charges to cover the customer related costs (metering, billing, account management, etc.) with variable charges relating to network capacity and usage, and commodity costs. This means that small users, including typically the elderly and disadvantaged, would pay higher overall charges (when measured per kWh of gas consumed) than larger users.

7 A perfectly competitive market is one in which there are no barriers to entry and exit by firms, and in which all costs are variable (so that they adjust as volumes and customer numbers change). In a competitive market, if a firm’s prices were to deviate from the efficient marginal cost level, then competitors would be able to undercut that firm and capture the consumer concerned. Competitive pressures force prices to return to the efficient marginal cost level.

8 The marginal cost is the change in costs associated with supplying one additional unit of a good or service to the consumer concerned.

9 This is known as ‘allocative’ efficiency.

10 This is known as ‘productive’ efficiency.

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Cost reflective pricing also typically means that consumers in more remote areas would pay more than consumers in areas of dense load, such as Dublin, where the costs are lower.

The Commission has an obligation to take account of the needs of rural customers, the disadvantaged and the elderly provided that this does not prejudice its other obligations in relation to discrimination among holders of, and applicants for, licences. The protection of rural customers, the elderly and the disadvantaged could be accomplished in ways that do not compromise other obligations, but would add a degree of complexity to the regulatory process; these options include:

• The creation of a Public Service Obligation (PSO) that compensates licensees for subsidising supplies to certain groups of customer (e.g., rural, elderly, disadvantaged). The PSO would be financed from a levy on sales to final customers. All suppliers would be subject to the same levy.

• An obligation on all suppliers to maintain a mix of rural, elderly and disadvantaged customers.

The former is complex, would require approval of the European Commission and would increase the cost of regulation and the regulatory burden on licensees. It would be difficult to impose the latter option on small new entrant suppliers or even on existing independent suppliers without deterring competition. Neither option is ideal.

The Commission will review the likely impact of moves toward cost reflective pricing on rural, elderly and disadvantaged consumers and will then consider whether the options outlined above or any alternative options are necessary and, if so, whether they can be introduced in a simple, low cost way.

2.4. Promoting the Utilisation of the Gas Networks

The gas system as developed is capable of having new customers connected. The distribution network in many cases is capable of supplying far greater consumption levels with minimal additional investments. In this situation, the additional network costs to supply a new customer are, in some cases, close to zero. Each new connection allows the total cost of the network to be spread over more customers, thus reducing the average cost for all customers.

However, there is a cost associated with connecting new users to the system. It would be inefficient to connect new users to the system if the amount those users will contribute to the system as a whole is less than the costs to connect them. Thus, the Commission must find a balance between adding new connections to the system and the costs of doing so.

Companies in competitive markets provide incentives to attract new consumers with offers of free appliance installation or introductory offers. BGD may have an incentive to provide such offers on its own initiative, without intervention by the Commission, provided that attracting new consumers leads to increased profits.

In promoting utilisation of the network the price sensitivity of customers will need to be taken into account. Where small changes in price lead some customer groups to switch to other fuels, this would impact on the prices charged to remaining customers and could potentially lead to a vicious cycle of rising prices and falling demand. Marginal cost pricing principles that are discussed in Section 3 are helpful in addressing this issue.

While the Commission has no specific duty to encourage greater utilisation of the network, we recognise that this will lead to lower average prices for all consumers. Therefore the Commission considers that the encouragement of the improved and efficient utilisation of the network is part of its duty to protect customers and will consider whether any measures to encourage utilisation of the network are required.

2.5. Promoting Competition

The Commission also has a duty to promote competition. Higher prices by BGS will encourage new entrants which will drive down prices in the longer term, but at the expense of higher prices in the short term. There is therefore a conflict between the objectives of protecting customers in the long-term, by promoting competition, and protecting customers in the short-term.

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Moving BGS prices to market reflective levels in the short-term will encourage competitors to BGS which will lead to greater competition and lower prices in the longer term11; the encouragement of competition is therefore both an obligation in its own right and also part of the Commission’s responsibility to protect customers. However, there is a potential conflict in the short-term between market reflective prices to encourage competition and the need to protect customers.

The Commission is also aware that within two years most gas customers could face significant tariff increases as a consequence of the ending of BGS’ low price gas contracts. The Commission will therefore wish to mitigate the tariff increases to the extent possible, and will consider a possible transition path from the existing tariffs to cost reflective tariffs, taking account of the impacts on consumers in the short term and competition in the longer term.

2.6. All-Island Market

One of the key goals of the Commission is to create a functioning, competitive all-island energy market. An all-island market would deliver a more efficient and effective energy market for the final customer in comparison with maintaining the current arrangement of two separate energy markets on the island of Ireland.

The Commission is part of an All-island Joint Steering Group (JSG), set up in July 2003, to oversee co-operation on the development of an all-island energy market. The group comprises representatives from the Commission, the Northern Ireland Authority for Energy Regulation (NIAER), the Department of Communications, Marine and Natural Resources and the Department for Enterprise, Trade and Investment of Northern Ireland. The key priority areas for the JSG include the creation of an efficient all-island gas network.

The potential for an all island network is enhanced given the future construction of the South North pipeline. The Commission, in conjunction with the NIAER, is currently undertaking a study that aims to identify potential transmission tariff arrangements for an all-island gas market, and identify the costs and benefits of gas transmission tariff harmonisation.

In embarking on the current review of distribution and supply tariff structures in Ireland, the Commission is mindful of the work being undertaken by the JSG. When examining different tariff options, where relevant, we will consider the impact these might have on the potential for greater integration of the two markets.

2.7. EU Legislation

On 26 June 2003, the European Parliament and the Council adopted Directive 2003/55/EC concerning common rules for the internal market in natural gas and repealing Directive 98/30/EC. While Directive 98/30/EC, the first Internal Market Directive, took the first relatively tentative steps towards the creation of the internal market for gas, the second Directive aims to provide the necessary structural changes in the regulatory framework to tackle remaining barriers to the completion of the internal market.

To help develop a more competitive market in natural gas and expedite the process of liberalisation in each member state, this Directive, which will be implemented by 1 July 200412, sets out a number of provisions to tackle the issue of market dominance and ensure a level playing field for existing and potential market entrants. Central to achieving this goal are provisions that ensure that the nature of network access is non-discriminatory and equally that the associated network tariffs are fair and transparent. At the same time national regulatory authorities in each member state must ensure that adequate safeguards are put in place specifically for vulnerable customers and customers connected to the gas network in remote areas.

The key principles embodied in the EU Directive are reflected in our approach to this review, namely, customer protection, network viability and investment incentives, fair and non-discriminatory tariffs, cost-reflectivity and regard for the environment. Each of these are discussed in more detail elsewhere

11 This could also, eventually, remove the need for regulation of supply tariffs.

12 2003/55/EC Article 33

9

in this section of the paper. In carrying out the Gas Tariff Review the Commission will have regard to each of the principles and obligations set out under of the Directive and, in particular, their implications for the design of both the supply and distribution use of system tariff structures.

2.8. Environmental Policies

As mentioned above, the Commission has a duty to take account of protection of the environment13. However, this duty must not prejudice the Commission’s duty to, among other things, protect the interests of final customers. For example, Combined Heat and Power production14 (CHP) is generally seen as a more environmentally friendly way of producing electricity. However, if the Commission were to encourage the use of CHP through adjustments to tariffs, it may negatively impact on other gas users (e.g., through cross-subsidy), creating a conflict with the Commission’s duty to protect the interests of final customers. The Commission must therefore find an appropriate balance on these issues.

Natural gas is seen as an ‘environmentally friendly’ fossil fuel, in that for the equivalent amount of energy it emits less carbon dioxide than other fossil fuels. From an environmental perspective therefore, it may make sense for the Commission to decrease the price of gas so customers use it in preference to other more polluting fuels (such as coal and peat). However, such a policy may, if gas is cheaper, encourage reckless use of energy that would damage the environment. Once again, the Commission must use its judgement on this issue.

Issue No. 1 – Core Principles

The Commission invites comment in relation to the Core Principles mentioned above.

13 See Section 9(5) of the Electricity Regulation Act, 1999.

14 Combined Heat and Power production is where electricity is generated (generally with natural gas), and the heat generated from the process (which would normally be discharged as ‘waste’) is utilised, maybe for space heating or an industrial process. This process is a much more efficient use of energy than conventional electricity generation (as less of the energy in the heat is wasted).

10

3. Tariff Design Principles

3.1. Introduction

Section 3 describes some basic tariff design principles that are used in the subsequent discussion of distribution and supply tariffs in Sections 5 and 6. This Section may be omitted by those with an understanding of the basics of tariff design or those more interested in the recommendations.

Section 3.2 discusses the basis for tariff design and, specifically, the choice between marginal cost and average historic cost pricing.

Section 3.3 describes how marginal costs are estimated in network industries.

Section 3.4 shows how customer (load) characteristics are related to costs on the gas supply chain.

Sections 3.5 and 3.6 describe how marginal costs are used to decide on customer categories and various components of the tariffs.

Section 3.7 describes how tariffs calculated using marginal cost can be adjusted to recover the revenues allowed to gas companies.

3.2. Basis for Setting Prices

Tariffs serve two main functions:

• they collect revenues for the utility, and • they provide signals to customers about the cost of the resource consumed, and help

consumers decide their level and pattern of gas use.

Both are important. The first is essential in order to allow BGS and BGD to cover its costs. The second is also important because the value of natural gas is too high to allow it to be unmetered and charged on the basis of an annual lump sum. Tariff design is concerned primarily with the second of these two tariff functions - to signal to customers the costs of resources. This is referred to as cost reflectivity.

• Costs used in tariff design can be approached in two different ways: • average historical cost, or • marginal cost.

These costs are reflected in tariff design by allocating ‘revenue recovery’ among consumers, and detailing the form that charges should take (seasonality, demand charges, etc) in order to reflect costs.

15

The average historical cost approach allocates responsibility for financial costs to specific uses or to specific consumer groups. These financial costs include operating costs, depreciation costs and the cost of capital.16 Costs are allocated among consumer groups or uses (demand, commodity) according to the share of the cost that is attributed to that consumer group or use. For example, accounting data will provide fixed investment and operating costs of distribution networks and these can be divided between capacity and commodity; with data on usage of the network by different consumer groups it is then possible to determine the cost responsibility of those different consumer groups.

While average historical cost pricing looks backward at historic financial costs, marginal cost pricing ignores all historic costs and only looks forward to future investments. The marginal cost pricing approach is consistent with economic efficiency and with the way that markets operate. Marginal costs are calculated as the change in costs that result from a unit increase in demand or consumption.

The starkest difference between marginal cost pricing and average cost pricing occurs where there is excess capacity: with average cost pricing, prices would be high, but with marginal cost pricing, prices

15 Revenue recovery relates to the way in which the regulated firm recovers allowable revenues approved by the regulator from tariffs and other charges.

16 Note, there are a number of different accounting methods for valuing assets and determining depreciation.

11

would be low because changes in demand can be accommodated without the need for additional investment.

With marginal cost pricing the revenues recovered from consumers will, in almost all cases, not match the allowed revenues of a regulated utility. Where the existing network has excess capacity then average costs17, which determine allowed revenues, will be above marginal costs. The converse applies where the existing network is capacity-constrained. For this reason, it is necessary to adjust marginal cost based tariffs such that the revenue matches the allowed revenue. The revenues from the two approaches - average historic cost and marginal cost - will therefore be the same, though the structure of tariffs will certainly be different. The Commission proposes to adopt a marginal cost pricing approach in the development of tariff structures for BGD and BGS because such tariff structures reflect economic costs and can be adjusted to meet allowable revenue targets. Tariffs based on average cost do not reflect economic costs. Marginal cost based structures provide a good starting point from which adjustments can be made to reflect other objectives - financial viability, competition and social - as discussed earlier.

Issue No. 2 – Marginal Cost Pricing

The Commission invites comments on the adoption of the Marginal Cost approach to tariff development.

The methodology is described in the following sub-sections. In summary, the steps in marginal cost pricing include:

• Estimation of the changes in costs that result from a marginal change in peak demand, or marginal change in consumption of a kWh of gas, or the addition of a new consumer to the network or a new account for a supplier.

• Identification of consumer characteristics (e.g., size of their peak demand) and how these relate to marginal costs.

• Grouping together of those consumers that have similar marginal cost characteristics. • Structuring tariffs to consumer groups in such a way that they reflect costs, but having regard

to the likely response of customers to the ensuing price signals. • Estimation of the total revenues that would be generated from strict marginal cost prices and

adjustment of the tariffs to ensure that the revenues will be sufficient to satisfy financial targets for an efficient utility. Adjustments may also be made at this stage to reflect social or other concerns.

3.3. Estimation of Marginal Costs

Marginal costs include:

•

• Transmission network costs,18 costs related to peak demand (maximum kWh/day):

, and

3.3. Distribution Network Costs

• Distribution network costs, • gas procurement costs, • commodity (kWh) costs• customer-related costs.

1.

Because investments in network industries tend to be lumpy, as shown in Figure 1, marginal costs in such industries are generally calculated using Long-Run Marginal Cost (LRMC)19.

17 Historic costs, including the cost of the assets (depreciation on the assets and cost of capital).

18 This is not within the scope of this review. See paper CER/03/172.

12

Figure 1 Long-run marginal cost

0

20

40

60

80

100

2005 2010 2015 2020GW

h/da

y, E

uro,

cen

ts m

ax./k

Wh/

120day

Investment cost

Capacity

Demand

LRMC

LRMC represents the change in fixed operating costs and capital costs required to meet a sustained increase in demand. LRMC for transmission and distribution is calculated using long-run average incremental costs (LRAIC); the formula is given in Appendix 1.

gas will have flowed. This approach

luded in the investment costs but are not related to demand

ment plans

Marginal distribution capacity costs must also reflect shrinkage - the loss, whether real or due to metmeters. re gas, typically 1% to 2% more, in order to cover this shrinkage.

LRAIC calculations can be applied separately to medium pressure and low pressure networks. If the network is differentiated by pressure, the costs of the distribution network would be allocated between consumers based on the pressure tier at which they are supplied. Consumers would pay the costs of the tier of connection plus each higher tier through which theimplicitly assumes that gas has entered the distribution network at the highest pressure tier and flows through all higher tiers before reaching the consumer.

Such an approach is simple and intuitive but, because of the dictates of network design, supply pressure may not be a good indicator of cost. It is appropriate to use pressure as a cost factor if there is a strong relationship between pressure and cost, but this relationship does not always hold in the gas sector. This is discussed further in Section 5.4.5.

There are various practical issues in the calculation of LRAICs for distribution. For example:

• demand growth may be only one of a number of factors driving the investment; • renewals investments20 may be inc

growth; • demand growth can be unpredictable and prudent utilities will typically develop the assets over

time to match the expected near-term growth in demand so that long-term investmay not be available.

ering errors or fraud, of gas between entry to the distribution network and flow through customers’ To supply the peak kWh/day of gas to customers, the supplier must purchase slightly mo

3.3.2. Peak Gas Costs

The marginal cost of gas itself is related to the cost of the marginal unit of gas on each day of the year. Where there is an international market, as in the UK, and where the marginal unit of gas in the

19 Short-run marginal cost (SRMC) is a better representation of the actual economic cost of meeting a demand increase at each point in time, but is volatile because of lumpy investments, and therefore requires frequent recalculation and results in unstable consumer tariffs.

20 The replacement of assets at the end of their economic lives, or for safety reasons, e.g., replacing old cast iron pipes.

13

Republic is purchased from that market, the prices on the international (spot) markets should generally

customers, it will normally wish to mirror these in either

ere are large storage volumes then the marginal cost at

o customers and reflected in tariffs is discussed later in

determine marginal costs of procurement.21

A supplier may enter into contracts for gas rather than procure all of its gas on the spot market, but it does so in order to match its sales contracts with its own gas purchase contracts. If, for example, it has fixed price year-ahead contracts with somelong-term (multi-year) contracts or futures contracts. However, a supplier will not normally expect to be able to predict future gas prices better than the market. For this reason, the incremental gas to meet demand should be considered to be from the UK market and not from these contracts. Spot prices rather than contract prices should therefore determine marginal costs.

Bord Gáis has several long-term contracts at relatively attractive prices (that are due to expire on a phased basis through to 2006). In general, contracts that are below market prices are treated as windfalls but they do not affect marginal costs.

Without storage, the marginal cost of gas on peak days would be related to the market spot price on peak days on, for example, the International Petroleum Exchange (IPE). Storage complicates the calculation of peak gas procurement costs. If thpeak would be the cost of off-peak gas plus the cost of storage, including the capital costs, and the shrinkage gas (including the losses of energy resulting from injecting gas, compressing it and then releasing it). In general, however, the costs of storage will be reflected in the UK spot market prices and, unless Ireland has attractive large scale storage options, the marginal cost of gas procured to meet demand at times of peak demand will typically be related to the UK spot market prices, and these prices already incorporate the costs of storage.

As with marginal distribution costs, for each kWh metered at customers premises, suppliers must procure slightly more gas to cover shrinkage. This also needs to be reflected in the marginal costs of peak gas. The way that this cost is attributed tthis Section.

3.3.3. Commodity (kWh) Costs

Marginal commodity costs are the costs resulting from an additional kWh metered at the customer’s premises. This comprises two components:

and

lated to international market prices (for example, in Irel , d to derive market prices). Network (commodity) costs are prin a gas around the network. This

• the cost of procured gas,• any network operating costs associated with an additional kWh.

The cost of procured gas, as discussed above, is reand the IPE market is often usecip lly the energy and operating costs of compressors to pump the

tends to be minimal. Commodity costs also include the cost of shrinkage - the difference between the amount of gas entering the network and the amount passing through customers’ meters.

3.3.4. Customer Related Costs

Customer-related costs are recurring costs that are incurred for each additional gas customer and that are independent of the amount of gas consumed. These costs include:

• meter reading, • billing, • revenue collection, • account management (enquiries, complaint handling, notification of gas leaks).

For Gas Card customers, the customer-related costs include the costs of providing facilities for selling and topping up the cards but they exclude the cost of meter reading and billing.

21 Provided there is no constraint on pipeline capacity to access that market.

14

3.4. Customer Characteristics and Relationship with Costs

The most important customer characteristic that affects cost (the cost driver) is the demand profile. The demand profile of a customer category can be described by three factors:

• swing, • coincidence factor, and • diversity factor.

These are illustrated in Figure 2 which shows a notional annual gas demand profile for the system and a group of customers. ‘Swing’ describes the relationship between consumption on the day of maximum demand (B) and the average daily consumption over the year (C). (See Appendix 1 for a mathematical definition.)

Figure 2 Customer profiles

02468

101214161820

Season

Dem

and

Total demand

Demand of customer group

BA C

In Figure 2, swing is represented by B divided by C. It indicates the relationship between average consumption and peak consumption but does not indicate whether demand coincides with overall peak demand on the network (and therefore affects the need for network capacity) or occurs at off-peak times (and therefore does not contribute to the need for network capacity). The ‘network’ in this context can be a distribution network or a transmission network and the ‘system’ peak can refer to the peak for the entire network or to parts of the network. The relationship between peak demand for a consumer group and demand at time of system peak is the coincidence factor: This is illustrated in Figure 2 as the ratio A divided by B.

The coincidence factor can take a value between zero and one. A factor of one or close to one indicates that the consumer group tends to peak at the same time as the system. A low coincidence factor indicates that the consumer group tends to have low consumption at times when the system is facing its greatest constraints. Where, for example, the peak demand on the network is driven by residential winter heating consumption then the residential sector will tend to have a high swing parameter and a coincidence factor of one.

Similar to the coincidence factor, the diversity factor reflects the fact that peak demands for individual consumers are unlikely to occur at exactly the same time. For example, commercial consumers’ peak demands may all occur in the winter but their peak is unlikely to occur exactly on the same day. The diversity factor is the ratio of the peak demand for the customer group to the sum of the individual peak demands of the group members.

A high diversity suggests that individuals’ peaks all tend to occur at the same time. A low diversity factor suggests they are spread out over a longer period. The peak demand by residential consumers will typically occur on the coldest day of the year and, unless there is some variation in temperatures in different parts of the country, the diversity factor for residential consumers will tend to be close to one.

15

The three factors - swing (or load factor), coincidence factor and diversity factor - are used to identify how a customer’s consumption impacts on costs of supply. The swing calculation is explained as follows.

Firstly, the peak demand of large customers is directly metered (or estimated based on historical meter readings). However, adjustments need to be made to this demand or, equivalently, to the marginal costs associated with that customer. Firstly, because the peak demand of a group of customers might not coincide with the system peak demand, the contribution to the overall system peak is estimated as the peak demand multiplied by the coincidence factor - this gives the coincident peak demand. However, the coincidence factor is normally estimated for the group as a whole, so that this coincidence factor adjustment is appropriate for the group rather than to an individual consumer. This leads to a second adjustment. The peak demands of individual customers in a group do not normally all occur on the same day. So, when calculating the contribution that an individual customer makes to the system peak, the coincident peak demand must be multiplied by the diversity factor - this gives the after diversity coincident peak demand. The marginal cost associated with the individual customer’s metered peak demand is then calculated:

• by multiplying the after diversity coincident peak demand by the demand-related marginal cost (ie., the general, demand-related, marginal cost as described above),

or, directly equivalent:

• by multiplying the metered peak demand by a customer specific marginal-cost that has been calculated as the general demand-related marginal cost multiplied by the coincidence factor and diversity factor for the customer group.

Secondly, for customers without daily metering, consumption is only measured as kWh per month or per year but no recordings are available of actual peak-day consumption. However, the swing factor (load factor) is used to relate the customer’s metered kWh consumption over the month or year to an estimate of peak demand (maximum kWh/day). Once this estimate is available of peak demand (for the customer), the same adjustments are made as for a daily-metered customer as described above - with coincidence factors and diversity factors - and a customer specific marginal cost per maximum kWh/day may be calculated.

The above marginal costs may be charged to the customers in a number of different ways. They may, for example, be charged as a fixed (site) charge, or spread over kWh charges or, for daily metered customers, charged according to actual peak demand in the month/season/year or according to a forecast of peak demand based on historical readings of the customer’s peak demands. This is discussed below.

3.5. Determining Tariff Categories

Complex metering (daily load metering) is able to identify consumer characteristics (load profiles) without the need for classification of customers into groups. It is only small consumers, for whom complex metering is not cost effective, that it is necessary to group consumers into tariff categories. Consumers with similar marginal cost characteristics should generally be grouped together but account should be taken of the administrative costs of identifying separate consumer groups and of ensuring that customers do not ‘cheat’ by registering as one type to gain from lower tariffs in that group.

There is no hard-and-fast rule for determining when the marginal costs of one group of customers are sufficiently ‘different’ from the costs of another group to warrant the creation of a separate group. This requires judgement.

Where it is desirable to introduce social pricing policies it may be necessary to deviate from the principle that tariff groups be differentiated according to marginal cost; with social pricing policies, other criterion might be used to group consumers together.

3.6. Structuring the Tariffs

Natural gas tariffs may be structured with combinations of the following components or features:

• connection charges,

16

• fixed customer related (supply) charges, • demand charges, • commodity charges, • seasonality in either or both of the demand charges or commodity charges, • discounts for interruptible customers.

Each of these is discussed in turn below.

3.6.1. Connection Charges

Connection charges are the fees demanded by BGD to connect a new customer to the network. These fees cover the cost of the service connection and the meter. This is covered by Commission Decision on Gas Distribution Connection Policy of 7 August 2003 (CER/03/190) and is not the subject of this Review.

3.6.2. Fixed Customer Related (Supply) Charges

Fixed charges are those that are paid monthly, bi-monthly, quarterly or annually, irrespective of a consumer’s gas consumption or peak demand. In the context of marginal cost pricing, fixed customer charges relate to the costs that vary primarily with customer numbers, such as meter reading, billing, part of the costs of call centres and account management in general. Capacity costs may also, in some instances, be recovered through a fixed charge but this is not so common because it does not provide incentives to reduce usage at peak times. It is also possible to recover customer related costs through a commodity charge (possibly through a declining block tariff), or a capacity (demand) charge, but these are less cost reflective.

The starting point for marginal-cost based tariffs is that a fixed charge should recover fixed, customer-related costs but in this Review we will deviate from this principle if it is necessary to do so to balance the objectives set out in Section 2 such as cost reflectivity and protecting the elderly or disadvantaged.

3.6.3. Demand Charges - for Customers with Daily Metering

Demand charges should reflect the costs that vary with changes in peak demand, including network capacity and the costs of procuring gas at peak times. For customers with daily metering, it is possible to charge on the basis of metered demand. The charges may be levied either on the basis of actual peak demand in the billing period or on the basis of a forecast of peak demand that is estimated from the previous year’s metered peak consumption.

The former gives customers an immediate incentive to restrain their demand in the current billing period while the latter approach gives weaker immediate incentives because a high demand in the current billing period will not feed through into higher charges until next year (or later depending on how historical metered data is used to forecast maximum demand).

Metered demand, for the purpose of estimating demand charges, can be based on the maximum demand on a single day or on the average of several days of high demand. The former gives strong incentives to avoid ‘spikes’ but once a peak has been reached, the customer has no incentive to restrain demand at other times - providing that demand is kept below the level of the spike. Averaging the highest few days of peak demands gives customers continuing incentives to restrain demand, but less incentive to avoid spikes. Tariffs are generally an imperfect reflection of actual system costs and both approaches have advantages and disadvantages; the choice between them is therefore necessarily based on judgement.

Another option is to charge for demand on the basis of a rolling 12-month maximum demand. Demand charges in, say, the current month would be one twelfth of the maximum demand on the highest demand in this month and the previous 11 months. This approach is useful for systems with little seasonal variation in demand or costs, but less useful in Ireland where demand and costs are very clearly seasonal.

A demand charge may also be charged to customers on the basis of contracted capacity combined with penalty rates for those customers who substantially exceed the contracted capacity (and possibly discounts for those who do not use their contracted capacity). This structure often mirrors the structure of the utility’s own costs and, from this viewpoint, is therefore attractive to the utility and from an economic viewpoint. On the other hand, it does require the customer to accurately forecast

17

his own demand and, because the utility has a portfolio of customers, the utility is usually better positioned to forecast aggregate demand than individual customers.

There are a number of sub-options relating to demand charges for customers with daily metering,

discussed below), tible’ contracts.

3.6. D

which are discussed later in this sub-section:

• demand charges that vary by season (• rebates on demand charges for customers with ‘interrup

4. emand Charges - for Customers with Non-Daily Metering

Tariffs should be designed to reflect marginal costs, but high metering costs (relative to the potential

n the maximum capacity of the customers supply, or ing block

With the first of these, the customer would have small number of stepped options for maximum

either daily metering nor peak flow capacity constraints are worthwhile, the

benefits of metering) mean that for some customers only kWh metering is worthwhile. These are non-daily metered customers. For these customers, demand-related costs could be charged on the basis of a fixed (monthly, bi-monthly, quarterly or annual) charge but this is not reflective of marginal costs. Better options, though imperfect, are:

• capacity charges that depend o• recovery of demand-related costs through the commodity charge, possibly in a declin

tariff.

supply capacity and would be charged according to the chosen maximum flow capacity (of the regulator/meter). A customer wishing to have a high peak volume of gas would be charged for a larger capacity supply and the corresponding regulator/meter. The charges would approximate to the demand-related costs.

Alternatively, where ncapacity charges must be rolled into, and charged with, the commodity charges.

3.6.5. Commodity Charges

The marginal costs associated with an extra kWh of consumption should be charged as a commodity

and-related costs through a demand charge,

charge (c/kWh). These costs are dominated by the (non-demand related) procurement costs of gas though they also include a small amount of network costs that are associated with each kWh of gas flowing through the network. Such costs tend to vary directly with a consumer’s gas consumption implying that a simple kWh charge is most cost reflective.

However, because it is not always possible to recover demthe commodity charge may also include capacity costs. There may then be an argument for block tariffs. Increasing/declining block tariffs are ‘second best’ tariff structures that are introduced because of various other constraints. A declining block might be introduced, for example, in order to recover the fixed, customer related costs or the demand-related costs through the first block or initial blocks of a commodity charge. The more cost reflective option would be to cover fixed costs through the fixed charge and the marginal kWh costs through the commodity charge.

3.6.6. Seasonal Charges

Commodity charges or demand charges may vary by season to reflect seasonal variations in marginal

e

ustomers are

costs (capacity constraints and variations in gas procurement costs). Spot prices on the UK market vary significantly by season and this could be reflected in the associated commodity charges. Demand-related costs vary even more significantly by season and may be zero, or close to zero, in the summer.

Seasonal tariffs are relatively easy to implement since there are no special metering requirements. Thmore significant impact is on the utility’s billing system which will need some adaptation.

Another issue, in considering the introduction of seasonal tariffs, relates to whether clikely to respond by changing their patterns of consumption. If customers ignore the signals coming from a seasonal tariff and continue to behave as before, the tariff does no harm but, on the other hand, it does no good. If the introduction of a seasonal tariff costs money to implement but has no impact, then it should be avoided.

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3.6.7. Interruptible Tariffs

Some customers are able to interrupt consumption when requested to do so by the utility when the utility is facing capacity constraints. This flexibility allows the utility to build less network capacity and to contract for less gas. It can therefore save significant costs. Cost reflective tariffs will include an interruptible tariff option with a discount for those customers willing and able to interrupt gas supply either for a maximum number of days per year or for any number of days per year. The latter option can mean that demand-related charges are fully discounted. More generally, the demand-related charges are discounted with the discount varying depending on the maximum number of days of interruption in the contracts.

3.7. Adjustments to Meet Financial and Other Criteria

Adjustments will need to be made to prices derived from marginal costs to reconcile them with revenue that is allowed under the price control formulae. While there are a variety of means for making such adjustments, all have in common the result that prices deviate to a greater or lesser extent from marginal costs.

The main theoretical basis for adjusting prices to cover allowed revenues is based on second-best pricing theory: Ramsey or Pareto pricing. This suggests that if it is necessary for prices to deviate from marginal cost then the best way to do this is to target customer groups or that part of consumption that is least responsive to price22.

Consumers that are unresponsive to price are typically those for whom natural gas is an insignificant component of their overall costs, such as commercial customers. However, the Commission needs to consider its duties in relation to the protection of customers and also of ensuring a level playing field between licensees, including BGS23.

The first block of consumption by a consumer may also be less price responsive. This might argue for a declining block tariff. The advantage is that it would not necessarily lead to cross subsidies between consumers. This would, however, be very similar in effect to an increase in the fixed customer-related charge. The Commission will consider the option of declining block tariffs.

22 Whose demand is inelastic.

23 If pricing policies are not applied carefully, they might unfairly encourage consumers to join independent suppliers, leaving BGS with only the subsidised groups.

19

4. International Tariffs

4.1. Introduction

The purpose of this section is to compare the tariff structures currently in place in Ireland with those in other countries. From this comparison we identify possible new structures that may be worthy of further investigation as part of the on-going tariff review.

Brief summaries of tariff structures for distribution and supply in other countries and some background information on the gas markets in these countries is provided in Appendix 3. The countries used for comparison were:

• the United Kingdom; • the state of Victoria in Australia; • the United States; • France and Denmark; and • Canada.

This provides natural gas tariffs from a representative selection of countries from three continents all of which have, like Ireland, liberalised their natural gas markets. We have reviewed supply and/or distribution prices of a few gas distribution and supply companies within each country. In this review we have focused, in particular, on:

• customer categories, • fixed charges versus variable (commodity or demand) charges,

4.2. Points of Interest for the Current Review

e supply tariff structures are:

harges, n in the

• n for small consumers. The UK gives residential consumers the w

.

• ed charges often adopt declining block tariffs for small users. However,

• Australia defines

l

• ys, simpler than those in Ireland. The US

• here competition is strong, suppliers do not generally provide published tariffs

• usually calculated for the tariff period on the basis of the peak demand in the previous period.

• declining and increasing block tariffs, • seasonal charges.

The k y points of interest for Ireland from international

• All tariffs have variants of the same general ingredients - fixed and variable ccommodity and demand charges, seasonal charges, blocks - but there is wide variatiouse of these ingredients. Fixed charges are commooption of a fixed charge but, if customers choose a tariff without a fixed charge or with a lofixed charge, they pay higher rates. Some suppliers do not have fixed charges for small users but, instead, have a declining block tariff where the first block is designed to cover fixed costsFixed charges are often discarded for larger users because the fixed charge is small relative to the total gas costs. Suppliers without fixthe two US suppliers have increasing block charges for residential customers but declining block tariffs for non-residential. Unusually, but not irrationally, Victoria in Australia has a three block tariff with an increasing block followed by declining block. Suppliers in Canada and Australia have seasonal charges. One supplier inthree seasons, but generally there are peak and off-peak seasons. Australia applies seasonal charges to residential and non-residential customers while British Columbia offers residentiacustomers a single tariff covering the whole year. Residential tariff categories are often, but not alwasuppliers in particular offer a wide range of tariffs to residential customers (and to other consumers). In countries wfor very large customers. The US suppliers and British Columbia do publish such tariffs. Tariffs for large customers generally include a demand or capacity charge. The charge is

20

The y

• untries tend to offer tariffs that

here

•

•

• ith smaller franchise areas generally offer a postalised tariff in their area (Denmark, lly large areas often have

ke points of interest from distribution tariff structures are:

The North American utilities (US and Canada) offer transportation tariffs in the same categories as their supply tariffs while utilities in other codifferentiate largely by customer size.

• No examples were found of distribution tariff structures similar to those in the UK and Ireland (i.e., with an equation that can be used to calculate the tariff). Generally, the utilities offer a relatively small number of size categories, with the exception of Denmark where tare eight size categories. Some utilities include demand/capacity charges as well as commodity charges (UK, France, Australia) while others include only commodity charges (Denmark, US, Canada). Unusually, daily metered customers in Victoria, Australia have only demand charges (no commodity charges). Only France was found to offer a distance related tariff option. Utilities wUK, France, US) but those distributors operating in geographicageographically differentiated tariffs (Victoria, British Columbia).

21

5. Distribution Use of System Tariff

5.1. Introduction

The purpose of this section is to explain the structure of the current distribution tariffs and to highlight both existing structural issues and additional issues that will be considered by the Commission in assessing the need to revise the current distribution tariff structures.

Shortly after taking responsibility for regulation of the natural gas industry under the Gas (Interim) (Regulation) Act, 2002 the Commission set out to establish the basis upon which charges should be imposed for the use of the distribution system. To this end, a distribution use of system tariff structure was developed and implemented for the period 1 October 2002 to 30 September 2003 (“2002/3 Tariff Structure”).

In setting the tariffs for the 2003/4 gas-year24, the 2002/3 tariff levels were inflated largely to reflect inflation and the need to recover revenue from connection specific capacities and volumes (i.e. exclusion of transmission connected customers as a result of the adoption of a ‘connection’ approach) which on aggregate are less than the original ‘statistical’ capacities and volumes. However, the underlying structure of the 2002/3 tariff was retained. The 2003/4 distribution tariffs were implemented on 1 October 2003 and remain in place until the 30 September 2004.

This section begins by setting out the principles and methodology employed in the development of the 2002/3 tariff structure, as detailed under subsection 5.2 below. This tariff was put in place as an interim tariff pending a full structural review in the following 12-month period. Subsection 5.3 details the adjustments made to the 2002/3 tariffs culminating in the current 2003/4 distribution tariffs. This subsection also highlights particular issues and anomalies with the current tariffs as a result of the above adjustments. Namely, the adoption of a connection based approach, the associated implications of recovering the allowed revenue for 2003/4 based on connection-specific capacities and the application of market capacity estimates for 2003/4 tariffs that were based on limited historical data. Finally, subsection 5.4 presents further issues with the current distribution model relating to the use of incorrect asset utilisation estimates and the resulting impact on allocation of costs among particular customer categories.

5.2. The 2002/3 Tariff Structure

The distribution tariff design was based on an average cost approach. In order to determine the cost associated with transporting gas to customers the tariff was based on two aspects of a customer’s gas consumption:

• distribution network asset utilisation • annual consumption load profile (volumes and peak day values)

To this end, the distribution mains were separated into medium and low pressure tiers, and the network services25 and meters were identified as specific to Industrial and Commercial (‘I/C’) and residential users. In addition, aspects of a customer’s consumption profile, such as annual volume and peak day values, which each separately (and in different ways) contribute to the capital and operational cost of the system, were applied to the tariff design. This approach, termed the ‘statistical’ approach (which is explained in more detail below), aimed to achieve the most equitable appropriation of the relevant costs to gas customers. It aimed to ensure a customer is levied charges based on specific use of the network, with charges reflecting the cost of servicing demand to that customer.

In addition to the approach outlined above, a postalised method of charging was adopted. In the context of the Irish network, where two major urban centres represent 80% of the customer base, it was reasoned that consumers located outside of those urban centres would be strongly penalised by any location-based tariff. In addition, applying a location based tariff to the Irish system was thought to be

24 A gas year runs for 12 months from the 1 October to the following 30 September.

25 The term ‘services’ refers to service pipes. These pipes connect a particular premises/site to the distribution low or medium pressure mains.

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impractical, requiring the system to track all flows through the system to the meter point, and subsequently requiring application of an onerous set of tariffs for each individual meter point. Thus, a postalised approach was reasoned to be the most transparent, simple and equitable methods of the charging available.

5.2.1. Statistical Approach

The 2002/3 distribution tariff structure was developed on the tenet that all customers below a certain consumption threshold (annual volume of <5m therms or 146, 535MWh) should pay a distribution tariff regardless of whether they were connected to the distribution system (termed the “statistical approach”). The rationale behind this approach can be summarised as follows:

• Avoided disparate charges being applied to similar sized customers receiving the same gas delivery service

• Mitigated the propensity for un-economic bypass which would see customers seeking transmission connections where distribution connections represent the most economic solution from a system perspective

• Ensured a lower level of charge would be applied to the larger industrial customers than would have been the case if only distribution connected customers were levied with a distribution tariff.

5.2.2. Customer Categorisation

The 2002/3 tariff structure allocated distribution network asset and operating costs across 11 distinct customer categories, grouped by annual consumption volumes, ranging from residential to the largest industrial customers (consuming up to 5m therms or 146, 535 MWh of natural gas per annum).

Table 1 – Customer Categories

Customer Categories

(annual consumption volumes)

1 Residential 7 <10,257 MWh

2 <73.25 MWh 8 <14,653 MWh

3 <732.67 MWh 9 <29,307 MWh

4 <2051 MWh 10 <73,267 MWh

5 <2,930 MWh 11 <146,535 MWh

6 <7,327 MWh

5.2.3. Grouping of Network Assets The distribution network assets and costs were broken down into four principle sectors for allocation among customer categories, namely: Medium Pressure Mains (MP), Low Pressure Mains (LP), Residential Service26 and Meters and Industrial/Commercial Services and Meters.

26 The term ‘services’ refers to service pipes. These pipes connect a particular premises/site to the distribution low or medium pressure mains.

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Table 2 - Grouping of Network Assets

MP Assets LP Assets Residential

Specific Assets I/C

Specific Assets

Description Medium Pressure Mains (P/E mains)

Low Pressure Mains (P/E and some cast iron mains, majority of mains installed presently)

Residential Meters and Services (identifiable in the BGÉ RAB)

Industrial and Commercial Customer Meters and Services (identifiable in the BGÉ RAB)

Customer Allocation

The entire market

Statistical percentage27 of LP connections in each category

All residential customers

All I/C customers

Revenue Allocation

Cost allocated across market capacities and volumes

Cost allocated across statistical % of market capacities and volumes

Cost allocated across residential capacities and volumes

Costs allocated across industrial and commercial capacities and volumes

5.2.4. Revenue Recovery Requirement of each Network Asset Group

The distribution tariffs are intended to recover use of system revenue in respect of the following:

• All projected operating and maintenance and other non-capital costs incurred in operating and maintaining the distribution network

• A return on network capital investment (historic and projected) • Capital depreciation

The opening and closing asset values, opex, capex, appropriate rate of return and depreciated values for each of the four network asset categories were utilised to determine net present revenue amounts for each component part of the network assets28. Applying the a revenue formula resulted in four separate ‘blocks’ of revenue, associated with each asset group (MP, LP, I/C & Res), to be recovered through the distribution tariffs.

5.2.5. Allocation of Costs across Customer Categories

The network asset revenue ‘blocks’ were recovered from the 11 customer categories based on their respective asset utilisation and capacity and commodity elements of annual consumption.

Determining MP and LP asset utilisation (of each customer category) was based on a statistical analysis of customer connections to the MP or LP mains. This involved calculating the percentage of each customer group (as a % of the market) connected to the MP and LP distribution network assets.

A capacity/commodity split was also applied to revenue recovery. This split defines the portion of the total revenue that is recoverable through the capacity (peak day value) and volume components of a customer’s annual consumption profile. A 80/20 capacity/commodity split was applied to the 2002/3 tariff structure. In general, the vast majority of network operating costs are associated with the fixed element of the network business, infrastructure installation, operation and maintenance of the mains and services. Therefore, a large capacity charge reflects the costs of this fixed element of network.

27 Statistical percentage refers to the method calculating the percentage of each customer group (as a % of the market) connected to the LP distribution network assets.

28 For the period 1 October 2002 to 30 September 2003.

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.2.6. Deriving Customer Unit Capacity and Commodity Charges

methodology was used to determine

gy Steps:

5

Using the revenue calculations for each asset group, the following a unit capacity and commodity charge for each customer category (that reflects the cost of serving that category):

Methodolo

d above, separate revenue recovery requirements were determined for each asset

specific assets/services

2. Dividing the revenue by the relevant capacity and volume values (customer category aggregate value) produced four capacity and commodity charges for MP, LP, Res and I/C (meters and

3. among the various customer groupings for each asset type.

total

market customers, and derived applicable unit

This me s across th ustomers of a similar size (at the

1. As mentionegroup using the revenue formula:

• MP mains • LP mains • Residential• I/C specific assets/services

services) assets. Application of these asset charges by the customer category capacity and volumes in turn allocated revenue

4. Adding the revenues for each of the asset groups in each customer category produced the revenue recoverable among customer groups.

5. Dividing the total revenue recoverable amount by the market capacities and volumes for each group then spread the average costs among all capacity and commodity charges for the customer categories.

thod produced 11 discrete capacity and commodity charges. To apply each of these chargee market would have introduced price differences between c

threshold between customer category bands). Therefore, to produce a tariff that avoids discrete price differences between customer categories, a continuous function was derived to represent the distribution tariff for all customer categories except those in the 0 – 73 MWh range. Residential customers were subject to a flat charge for both capacity and commodity29.

Developing continuous functions for >73 – 146,535 MWh range

The 11 discrete capacity and commodity charges derived from thaverage peak day volume (in MWh) for each of the selected ba

e method above were plotted against nds. For example, for the capacity

graph, the average PDV for a particular category was obtained by dividing the total PDV for the category by the number of customers in that category. The average PDV was then used as the x co-ordinate, and the capacity charge was used as the y co-ordinate. This is illustrated in the following graph:

29 Variation in peak day and annual volume values between customers in this range are marginal and therefore these customers are considered to have similar load profiles. Customers of similar load profiles were reasoned to impose similar costs on the system and thus were subject to the same flat charges.

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Figure 3 - 2002/3 Distribution Tariffs Model Capacity Charges

Capacity Charges (>73 - 14,653 MWh)

y = -2.942Ln(x) + 101.21

0.0020.0040.0060.0080.00

100.00120.00140.00

0.00 20.00 40.00 60.00 80.00

Avg PDV (MWh)

Cap

acity

Cha

rge

(c/p

k da

y kw

h)

Source: 2002/2003 Interim Distribution Tariff Model (as published on BGÉ’s website)

A selection of data points was obtained in this way, one for each of the categories. The best-fit regression curve was then selected to represent the model charges. The ‘best-fit’ was achieved by separating the customer range into two separate bands [>73 – 14,653 MWh] and [>14,653 – 146,535 MWh]. In both cases natural logarithmic curves best represented the data points. The same exercise was performed for the commodity charges, producing a set of four continuous functions to define the distribution tariffs.

These capacity and commodity formulae, for individual Peak Day Values (PDV) measured in MWh, results in a unit capacity charge measured in c/pk day kWh, and a unit commodity charge measured in c/kWh respectively. Customers can derive a specific capacity and commodity charge by inserting their site peak day volume (annual capacity) into the relevant equation shown below:

Table 3 - 2002/3 Distribution Charges

Volume Range Capacity Charge (c/pk day kWh)

0-73 MWh 114.33

>73 – 14,653 MWh 101.21-2.942Ln(PDV[MWh])30

>14,653 – 146,535 MWh 252.86-36.285Ln(PDV[MWh])

Volume Range Commodity Charge (c/kWh)

0-73 MWh 0.243

>73 – 14,653 MWh 0.1942 – 0.0188Ln(PDV[MWh])

>14,653 – 146,535 MWh 0.2264 – 0.0297Ln(PDV[MWh])

5.2.7. Summary - 2002/3 Tariff characteristics • 80/20 Capacity/Commodity split • 11 customer categories allocated share of 4 asset groups • Asset allocation based on statistical analysis of MP/LP asset utilisation

30 Note – Ln (PDV [MWh]) denotes the natural logarithm of the Peak Day Volume (Maximum Daily Quantity) measured in MWh.

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• Operating costs allocated across the market by capacity and volume use • Statistical market capacities and volumes utilised

5.3. 2003/4 Tariff calculations and structure

During 2003, a number of developments impacted the distribution tariffs to be implemented for the gas year 2003/4, i.e. the current distribution tariffs. Namely, a ‘connection’ approach was adopted and merged with the ‘statistical’ approach used in the 2002/3 tariff design. This had the effect of excluding transmission-connected customers consuming less than 146 GWh threshold, developed under the statistical approach, from paying distribution tariffs. In addition, the level of allowed revenues that BGD are permitted to recover over the period of 1 Oct 2003 to 30 Sep 2007 was determined by the Commission. Finally, the roll-out of daily metering for I/C customers revealed that for some customers the estimates of market capacities on which the 2002/3 tariffs were based deviated (in some cases substantially) from those originally estimated. Each of these issues is discussed in more detail below.

5.3.1. Merging a ‘Connection’ Approach with a ‘Statistical’ Approach

On 26 November 2002, the Commission issued a letter directing BGÉ not to apply the ‘statistical tariff’ to transmission-connected customers. The 2002/3 tariff was determined based on the assumption that all gas customers consuming 146 GWh or less would contribute to the tariffs. Excluding the transmission-connected customers ensured that the unit charges determined under the 2002/3 methodology would be insufficient to guarantee expected revenue recovery in accordance with the tariff projections.

Recalculation of the tariff based on the original statistical approach and excluding the transmission-connected customers would have resulted in substantive increases (100% in some cases) in distribution tariffs for customers in the higher consumption volume bands. This is because the revenue associated with these higher consumption bands had to be recovered from a smaller number of customers. For this reason, and as an interim measure, it was decided to simply inflate the 2002/3 tariff charges across the market to recover the allowable revenue in 2003/4.

Thus, on the face of it the current tariff structure is not cost reflective, as certain revenue must now be recovered from a smaller number of larger distribution connected sites. The effect of introducing this statistical approach was effectively absorbed across the market and not applied to relevant customer groupings.

The current review will not only address the incompatibility of applying a connection based method of charging to an underlying tariff structure that was developed under the statistical approach but will also consider the merits of a connection approach itself. To this end, this subsection identifies the following potential outcomes that flow from a decision to retain a ‘connection’ approach:

• Disparate charges can apply to similar sized customers receiving the same gas delivery service depending on whether they are transmission or distribution connected,

• Increases the propensity of customers seeking transmission connections where distribution connections represent the most economic solution from a system perspective,

• While transmission-connected customers consuming <146 GWhr/year are not charged for assets they do not use (i.e. the distribution system), a higher level of charge is applied to the larger remaining distribution-connected industrial customers than would be the case if the transmission-connected customers under the threshold were not exempt from a distribution charge.

Issue No. 3 – Connection or Statistical Approach

The Commission invites comment on the connection approach versus the statistical approach for the charging of distribution tariffs to customers at the border between the distribution and transmission systems and the impact of each on the distribution tariff.

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5.3.2. Determination of Bord Gáis Distribution’s Allowed Revenues

On 7 August 2003, the Commission determined and published the allowable revenues associated with the gas distribution tariffs for the period 1 October 2003 to 30 September 2007. This Direction31 indicated the level of allowable revenue to be recovered through the distribution tariffs for the four-year period. This review did not, however, include a tariff structural review. As a result, BGÉ were directed to inflate the 2002/3 tariff charges to ensure 2003/4 recovery would meet allowable revenue requirements. This approach did not address the need to adjust “relative costs” among the various customer categories, but simply inflated the previous tariff, in order to achieve allowable revenues in the 2003/4 gas year.

5.3.3. Impact of Roll-out of Daily Metering for I/C on Estimates of Market Capacities

The 2002/3 distribution tariffs were based on estimates of market capacity. Since the tariffs were published on 1 October 2002, the roll-out of a daily metering programme to industrial sites had commenced. In an effort to obtain the most accurate market capacity and volume projections for the 2003/4 tariffs, load profile data from this ongoing programme was used in setting the capacity and volume projections for the 2003/4 tariffs. In addition market capacity estimates (generally for the lower consumption bands (i.e. non-daily metered)) were also drawn from the initial finding of the FAR group32. These new capacity and volume estimates were incorporated into the 2003/4 tariffs and implemented on 1 October 200333.

Note, it was found that the capacities determined for individual sites from the daily meters deviated slightly from the original estimates. However, in some cases, this resulted in substantive year on year increases to certain sites. To avoid extreme price variations the Commission directed BGÉ to cap the resultant tariff charge increases to 6% in 2003/4, the applicable shortfall being recoverable in the following gas year.

Subsequent to the implementation of the 2003/4 tariffs, capacity values for some customers have been found to vary with current capacity determinations performed using current data and methodologies. This is due to the following reasons. First, capacities and volumes used in the 2003/4 tariffs were set at a time when the daily metering programme was still being completed, and access to substantive historical information was limited. Secondly, the capacities were derived before the outcome of the FAR process. Subsequent to September 2003 (when the estimates used in the current tariffs were set) a capacity determination methodology (developed under the FAR) for non-daily metered customers was further refined and as result produces, in some cases, different capacity estimates than those determined using the initial findings.

Thus, although the current distribution model was updated with revised capacity information in September 2003, culminating in the current tariffs, these estimates, for some customers, have subsequently been found to vary with those determined under current methodologies and data. These disparities will be addressed in the current review.

31 See CER/03/188 Commission’s Decision on Distribution Use of System Revenue Requirement and Tariff Structure 1 October 2003 – 30 September 2007.

32 FAR group – The Forecasting Allocation and Reconciliation group. The objective of this group is to develop a methodology for determining Irish gas market capacities for non-daily metered customers.

33 It is important to note, however, that these capacities and volumes were set at a time when the daily metering programme was still being completed, and access to substantive historical information was limited. In addition, the capacities were derived before the outcome of the FAR process.

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Table 4 – 2003/4 Distribution Charges

Volume Range Capacity Charge (c/pk day kWh)

0-73 MWh 120.733

>73 – 14,653 MWh 106.878-3.107Ln(PDV[MWh])

>14,653 – 120,000 MWh 267.021-38.317Ln(PDV[MWh])

>120,000 MWh 31.055

Volume Range Commodity Charge (c/kWh)

0-73 MWh 0.257

>73 – 14,653 MWh 0.2051 – 0.0199Ln(PDV[MWh])

>14,653 – 120,000 MWh 0.2391 – 0.0314Ln(PDV[MWh])

>120,000 MWh 0.045936

5.3.4. Summary - 2003/4 Tariff Characteristics • 2002/3 tariff inflated by 5.6% largely to reflect inflation and the need to recover revenue from

connection specific capacities and volumes (i.e. exclusion of transmission connected customers) which on aggregate are less than the original ‘statistical’ capacities and volumes.

• Unit charges based on new market capacities and volumes (per initial findings of both the FAR group and the roll out of the daily metering programme to I/C sites)

5.3.5. Additional Issues with Current Distribution Tariff Structure

Analysis of MP and LP asset utilisation

In addition to the issues identified above BGD has recently completed an analysis of the MP/LP asset utilisation of each customer category. The analysis incorporated a database search of customer connection details, and a correlation with GIS34 information, which contains network pressure tier information. The analysis supported the original estimations of the residential utilisation of LP assets (61.2%), however, indicated a higher than expected utilisation of LP assets among I/C customers (80% versus circa 32% originally estimated). The effect of distinguishing between MP/LP asset utilisation will now be to “weight” higher unit charges on I/C customers than was previously the case.

Thus, the current distribution tariffs are based on asset utilisation estimates that have been subsequently found to be inaccurate and therefore the current cost allocation among customer sectors is incorrect.

Fair allocation of costs

The Commission is concerned that the costs of the different tiers in the distribution system are identified properly, and allocated correctly to the appropriate customer category, including opex.

5.4. Issues for Future Distribution Tariff Structure

5.4.1. Introduction

Distribution tariffs recover the costs of connecting customers to the distribution network (through connection charges) and the installation, operation and maintenance of that network (through connection and use-of-system (UoS) charges). The following Section discusses issues relating to:

• connection charging policy,

34 GIS – Geographical Information System

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• the form of use-of-system charges, • the split of capacity costs between commodity and capacity, • differentiation of charges depending on pressure of supply, • categories of customer.

5.4.2. Connection Policy

The policy under which charges for new connections to the gas network are determined was published as the Commission Decision on Gas Distribution Connection Policy of 7 August 2003 (CER/03/190). In this Decision, the Commission adopted the principle that the level and structure of charges for new gas connections should provide incentives - or at least minimise disincentives - for customers to connect to the network. This reflects the expectation that added gas demand tends to exert downward pressure in the long run on the Distribution Use of System (DUoS) component of tariffs for all customers by allowing distribution network capacity to be more highly utilised and its fixed costs to be spread across more customers.

Under the Decision, all DUoS payments made by a customer after connection are deemed to be ‘paying off’ the portion of the cost of connection that exceeds any up-front charge levied on the customer for their new gas connection.

The Decision specifies that generally the up-front customer contribution to the connection charge be set equal to the connection cost (including capex and opex) to BGD minus the Net Present Value (NPV) of the stream of DUoS payments for a specified number of years.

The methods by which connection costs are calculated by BGD for each group of customers is shown in Table 5, along with an indication of the current charges.

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Table 5 Summary of Connection Charges

Existing premises New developments

NPV calculation

Residential Small I&C (>73 000 kWh /y) service pipe only

New residential developments

New build I&C: requiring mains & service pipe

Cost basis for the policy in the Commission decision

Average cost of a 15m connection

Attributable distribution network cost of serving the load, consistent with the Transmission Connection Policy: this is known as “deep charging”

Actual cost of new connections including new distribution assets required to connect the new development to the existing gas network

Actual cost of new connections

Revenue basis for the policy in the Commission decision

Assumed DUoS revenues based on averages calculated across all similar customers

Assumed DUoS revenues based on average calculated across all similar customers

Assumed DUoS revenues based on averages calculated across all similar customers

100% up-front charge for distribution connection CapEx

Period and calculation

10 year NPV must break even

7 year NPV 20 year NPV must break even

0 year NPV

Annual revenues to be included in the economic calculation

Full DUoS tariff for an average consumption of 16 000kWh

For >73 000 kWh /y estimated annual consumption

Full DUoS tariff assuming 16 000 kWh /unit /y for developments of >3 houses; 13 000 kWh /unit /y for developments of >4 apartments

None

Costs to be included

Average OpEx and CapEx only for a new 15m connection to existing gas network

Attributable CapEx and OpEx required to meet the customer’s load profile

Actual cost of connecting the development to the existing network

CapEx required to supply the customer as determined by BGÉ

Costs allowed to be included in the Distribution RAB

Costs of connection minus up-front customer connection payment

75% of the cost of connection

Costs of connection minus up-front developer contribution

None

Resulting connection charges (as of March 2004)

€220.26 + 13.5% VAT = €250 for up to 15m plus €65/m over 15m + 13.5% VAT = €73.78

The greater of 25% of the cost of connection and the difference between

Minimum €150 + 13.5% VAT = €170.25 per unit

100% of the capital costs required to supply the customer

To be paid by Customer Customer Developer Customer

The effect of the distribution connection charging policy in the residential sector is that other customers partly cross-subsidise new connections to both existing individual households and to new housing developments. New gas customers in existing houses effectively do not contribute DUoS revenues towards the distribution system upstream of their own connection for 10 years. New gas customers in new housing developments effectively do not contribute DUoS revenues towards the distribution system upstream of the point that their new housing development was connected to the gas network for 20 years.

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5.4.3. Form of Use-of-System Prices

Use-of-system charges recover those network costs that are not recovered from connection charges, including the costs of those parts of the network that cannot be attributed to individual users through connection charges, the costs of capacity added to meet future demand increments, and the costs of the operation and maintenance of common network assets. Options for use-of-system charges are discussed below.

Postage-stamp

A postage-stamp charge does not vary with the location of a consumer (although it may vary by factors such as customer size or load profile). Such charges are simple to calculate and administer. They also offer a means of cross-subsidising rural consumers located away from the main network. This may be important in meeting social objectives.

Postage-stamp charges do lead to prices deviating from costs, with those customers located close to the transmission network cross-subsidising those located at a distance. In taking decisions on where to locate, therefore, consumers do not take full account of the costs they impose on the network, and as a result may increase costs for other network users (who will have to pay for costs that exceed the average level).

Zonal

Zonal tariffs policies recognise that the costs of supplying consumers may be very different between zones. However, this can lead to increased charges for newly-established zones where a few consumers become liable for the entire costs of the network (assuming this is built with significant excess capacity in expectation of future demand growth) in that zone. These zones are also likely to be more remote from the existing network and will typically be those with higher costs. Zonal pricing could therefore act as a barrier to the expansion of the gas market, and is not desirable for this reason.

The Commission will, in future, consider the possibility of offering licences to independent gas distribution companies in areas that have not previously been gasified. If this were to happen the independent distribution companies would require full cost recovery in these areas, unlike BGS who is able to cross-subsidize between lower cost distribution zones in Dublin and their other, more remote, zones. This would mean that independent distribution companies would necessarily charge higher prices than BGD outside of Dublin. Distribution costs represent only approximately one third of gas prices to end users so that the impact on end users will be less significant.

Other

Full locational pricing relates the UoS charges applied to consumers to the point at which they are connected to the network - for example, through entry-exit or point-to-point charging. Such charges are complex to calculate and administer, can change significantly over time as system flows change, and are generally impractical where a network connects large numbers of small users. For these reasons, the Commission does not propose to consider such prices further.

Initial proposal

Though the Commission recognises that it is undesirable that BGD should be allowed to charge lower prices outside Dublin than prices charged by independent distribution companies, the Commission believes that the benefits of uniform pricing by BGD outweigh the disadvantages. The Commission’s initial proposal is therefore that UoS charges by BGD should be set on a postage-stamp basis, undifferentiated geographically.

Issue No. 4 – Commission’s Proposal on uniform distribution tariff pricing

The Commission invites comment on its proposal to set distribution tariffs on a uniform pricing basis.

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5.4.4. Use-of-System - Capacity:Commodity Split

The costs of the distribution network can be divided into:

• those associated with capacity to meet peak demand on the network, and • those associated with the volumes transported through the network.

For customers with daily load metering, the first of these is generally recovered through a capacity charge related to peak demand (maximum kWh/day) and the latter are generally recovered through commodity charges irrespective of the time at which this demand occurs. For customers with daily load metering it is important to differentiate between the capacity and commodity component of costs.

For customers without daily load metering, the capacity costs may be charged as either a fixed (site) charge, a declining block commodity tariff, or the capacity cost may be charged as a simple commodity charge. Even if capacity costs are incorporated in the commodity charges it is still important to split capacity and commodity related costs before calculating the simple commodity charge.

The network is designed to meet the peak demand so that, according to marginal cost principles, all of the marginal capacity costs should be associated with peak demand. However, to the extent that smaller customers tend also to be those with high swing factors, there may be a social argument in favour of implementing this principle less strictly.

In its most recent decision on this issue (CER/03/188), the Commission required BGD to continue to apply a 80:20 split between capacity and commodity charges. By way of comparison, NationalGridTransco applies a 50:50 split in its LDZ charges. There is, however, no rationale for this split.

Over the coming months, the Commission will identify the capacity and commodity related costs and will consider the implications of splitting network costs into capacity and commodity; it will then propose an allocation.

Issue No. 5 – Capacity/commodity split

The Commission invites comment on the capacity/commodity split used in the current Distribution Tariff structure.

5.4.5. Customer Differentiation

The distribution network is made up of different pressure tiers. In general, larger consumers will connect to the higher pressure tiers, thereby avoiding lower tiers, and the connection pressure might therefore provide information about the cost that a consumer imposes on the gas network. However, there is no simple rule governing the tier of connection with, in many cases, similar consumers being connected to differing tiers depending on the local network geography. The relationship between pressure and cost is not, therefore, simple.

The Commission directed that, from November 2002, BGD should cease using the “statistical approach” to distribution charging. Under this approach, distribution charges were applied to all customers with an annual consumption of less than 146,535 MWh, irrespective of whether these customers were actually connected to the transmission or the distribution system. Distribution charges are now to be applied only to those customers physically connected to the distribution system.

The same “statistical approach” could also be taken to differentiation of distribution connected customers connected at MP and LP. In categorising distribution network-connected consumers for the purposes of setting UoS charges, three main approaches can be adopted:

• no differentiation, i.e., treat all consumers as belonging to a single category, • differentiate by the pressure tier at which the consumer is connected, • differentiate by consumer size.

The choice depends on whether differentiation provides useful information about costs.

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No differentiation

Under this approach the same UoS charges would apply to all consumers, irrespective of their size or point of connection to the distribution network. This approach is simple to implement. It would be appropriate if a network is developed in a range of areas with differing conditions requiring different network designs. In such circumstances, there would be no simple relationship between cost and pressure/diameter and in some instances, in low density zones, higher pressure/larger size pipes might actually signal that the customer is causing higher costs.

Differentiate by pressure/pipe size

Under this approach customers could face different UoS charges depending on either the pressure or size of pipe (or both) to which they are connected. Differentiation by pressure/pipe size would be appropriate where load patterns are relatively uniform across the country and a relatively uniform design is adopted by BGD. In these circumstances the pattern would be clear whereby the larger customers would be connected at higher tiers and would avoid the costs of the lower tiers of the network. The pressure or pipe diameter would then provide valuable signals about the cost that customers impose on the network.

Differentiate by customer size

Under this approach customers could face different UoS charges depending upon their size. Differentiation by customer size is equivalent to the “statistical approach” for allocating distribution costs between customers according to size. There is generally a correlation between customer size and the tier at which it is supplied. The question is whether the pipe size or supply pressure provide additional information (about costs to the network) that is not already contained in the information about customer size. In other words, do we need to differentiate by pressure/pipe diameter as well as customer size?

A large customer in a dense industrial zone will cause lower costs to BGD than a smaller customer in the same zone. Similarly, a large customer in an area of low load density will cause lower costs to BGD than a small customer in the same zone. But a small customer in a dense zone may cause equal or lower costs than a large customer in a low density zone. This suggests that size is useful indicator of cost, but is not perfect.

One disadvantage of differentiating only by customer size is that it will then be more difficult to create a charging structure that will allow independent distributors (discussed in Section 5.4.8) to develop LP networks that would be supplied through the upper tiers of the BGD network.

Initial proposal

The Commission’s initial proposal is that marginal capacity costs of distribution should be considered to be independent of distribution pressure. The Commission proposes to investigate further the relationship between a customer’s supply pressure/pipe size and network costs.

Issue No. 6 – Customer Differentiation

The Commission invites comments on the options for customer differentiation on the distribution system.

5.4.6. Categories of Customer

BGD’s customers are effectively classified by size with lower charges35 for larger consumers. However, the primary factor (for non daily-metered customers) in determining tariffs is the customer load profile or ‘effective swing’. Since there is an empirical relationship in gas data between ‘effective swing’ and customer size, the Commission believes that it is reasonable to continue to categorise distribution charges according to customer size.

35 The charges calculated from equations that depend on customer size.

34

5.4.7. The Form of Charges

The UK has customer charges and, until recently, Denmark had customer charges, but BGD does not. In the UK, the charges relate to the meter reading cycle. Without meter reading costs, BGD’s fixed, customer related costs, would be relatively low and a separate fixed customer charge would likely to be relatively insignificant.

Issue No. 7 – Fixed Charges

The Commission will consider the possible introduction of a fixed customer related charge for distribution. Comments are invited upon this.

With regard to capacity charges, the main issue concerns ex ante or ex post peak daily values. For non daily-metered consumers there is clearly no option other than to base charges on estimated peak demands. For daily-metered customers, there is an option to use ex ante (peak demands estimated from past metered data) or ex post (metered peak demands during the year in question). The use of ex ante quantities for capacity pricing is common practice among utilities since it gives the distributor assured revenues to cover network costs that do not vary with throughput. Nevertheless, it gives fewer incentives to customers to minimise peak day volumes and can lead to arbitrary estimation of peak demand for any firm that is facing year-to-year changes in its consumption.

The Commission wishes to review the basis for charging capacity for distribution customers and invites comments on the present capacity charging policy of BGD.

Issue No. 8 Distribution Capacity Charges

The Commission invites comment on whether distribution capacity charges should be based on forecasts derived from historical meter readings or on actual meter readings.

5.4.8. Distribution Competition

BGÉ does not hold a legal monopoly on gas distribution (or transmission) in Ireland. Other parties may, subject to gaining the necessary regulatory consents , install distribution networks. These ‘Independent Gas Transporters’ (“IGTs”) would charge a tariff for use of their networks. Though there are no IGTs at present, it is appropriate that a regulatory framework is developed in order to provide regulatory certainty to parties hoping to become an IGT. Below are three options by which IGTs could charge tariffs.

Under the first option IGTs would charge the same tariff as BGD (a ‘national tariff’). The assets/operations of all Distributors (BGD and IGTs) would be considered together in the determination of a total allowable revenue and tariffs would be set nationally. All tariffs recovered would be put into a central fund, which would then be distributed to the different Distributors based upon their share of the assets/operations.

This approach would require a common connection policy, and common policies for determining investments in the network.

A second option would be to allow IGTs to charge no more than the BGD tariff (a ‘benchmark tariff’). BGD would offer different tariffs for use of different levels of its system. For example, the first part of the tariff would be for use of the medium pressure distribution spine, while the second part of the tariff would be for the final connection/distribution zone. So if an IGT connects to BGD’s medium pressure spine network it could charge the users connected to its network the full tariff, but must pay BGD a tariff for use of its medium pressure spine network.

A third option would allow distribution tariffs to vary by location (‘locational charging’). IGTs would be able to charge higher distribution tariffs to take gas to areas that would otherwise be uneconomic.

35

Issue No. 9 – Distribution Competition

The Commission invites comment on the options for distribution tariff structures in the presence of distribution competition.

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6. Natural Gas Supply Tariffs

6.1. Introduction

The purpose of Section 6 is to explain the structures of the current supply tariffs, including the RTF, and to draw attention to some of the issues potentially requiring further consideration in the analytical phase of the gas tariff review.

This section is divided into two broad areas. Section 6.2 describes the current natural gas supply tariffs in the non-eligible (‘franchise’) market, highlighting issues with the current structures and discussing issues relevant to the future design of supply tariffs. Section 6.3 follows the same format for the eligible market, focusing particularly on the RTF.

Over the years BGS has introduced tariffs for supplying natural gas on a gradual basis, resulting in a suite of natural gas tariff prices that are applied in both the domestic and Industrial/Commercial markets. Larger users were often supplied ‘off tariff’ – with non-standard prices negotiated between BGS and the customer, often with reference to the price of competing fuels.

In the first quarter of 2003, the Commission conducted a review of BGS’s tariffs for both the eligible and franchise markets. This review set the level of the franchise tariffs for 2003/4 and also introduced a new tariff - the Regulated Tariff Formula (RTF) - for certain eligible customers. The market (for the purposes of supply tariffs) is now split as follows:

• The Franchise Market, consisting of customers currently paying Industrial and Commercial tariffs or Residential tariffs;

• The Eligible Market, consisting of the Large End User Market, the RTF Market, and the Gas Fired Generation Market.

The tariff arrangements for each will be dealt in turn below, along with a discussion of some issues surrounding the current supply tariffs.

6.2. Franchise Supply Tariffs

6.2.1. The Current Franchise Supply Tariffs

The franchise market consists of all gas users that use less than 5.3 GWh per annum (excluding those that use gas for the purposes of electricity generation). The market is split into two sections: industrial and commercial (I/C), and residential.

Industrial & Commercial Tariffs

In July 2004, pursuant to Directive 2003/55/EC, all I/C customers will be eligible to change supplier. At the moment I/C customers consuming up to 5.3 GWh per annum are not eligible to choose their supplier. The tariff structures for this section of the market will remain unchanged, pending the implementation of any changes arising from the gas tariff review.36

The current suite of I/C tariffs were introduced in 1992 to harmonise I/C natural gas prices across the old Towns Gas Utility areas of Cork, Dublin, Limerick, Clonmel, and Waterford. These tariff rates were set in the context of a favourable contract gas position to compete with and displace alternative fuels in the market. The tariffs operated in parallel with Gas Oil and Heavy Fuel Oil indexed contracts for larger customers. There are three different I/C tariffs: I/C Blocked Rate tariff, Demand and Commodity 1, and Demand and Commodity 2. These are described below.

I/C BLOCKED RATE TARIFF

The I/C blocked rate is the price paid by the majority of I/C customers (approximately 13,000). The price varies by usage level every 2 months (or monthly depending on customers billing cycle – monthly

36 See the Commission paper CER/04/130 for the Direction extending the current tariff arrangements until the implementation of any changes arising from this tariff review.

37

bill cycle customers are priced based on half the consumption bands listed below – e.g., Band 1 is 0-3000 kWh). That is, the consumption band customers’ fall into (and hence the prices they pay) depends on their consumption in every two-month period (or every month). Customers are charged the unit rates for all consumption bands that they consume. For example, if a customer consumes 16,000 kWh in a two-month period, it will be charged (the supply charge, plus) 3.072 c/kWh for the first 6,000 kWh, 2.836 c/kWh for the next 8,999 kWh (that is, from 6,001 to 15,000 kWh), and 2.599 c/kWh for the last 999 kWh (that is, from 15,001 to 16,000 kWh).

I/C Blocked Rate Tariff Supply Charge37 €83.14 pa Applied monthly & bi-monthly Band 1 (0-6,000 kWh) 3.072 c/kWh Band 2 (6,001-15,000 kWh) 2.836 c/kWh Band 3 (15,001-30,000 kWh) 2.599 c/kWh Band 4 (30,001+ kWh) 2.364 c/kWh

Banding is applied on a monthly & bi-monthly basis

Prices exclude VAT

According to BGS, the I/C blocked rate is the most appropriate tariff for I/C customers consuming below approximately 350,000 kWh per annum.

DEMAND & COMMODITY 1 TARIFF

The Demand and Commodity 1 tariff (D&C1) has a fixed annual supply charge element applied monthly and a flat commodity charge per unit. Approximately 850 customers are supplied on D&C1.

Demand & Commodity 1 Supply Charge €1662.35 pa applied monthly Meter Charge €83.14 pa applied monthly Commodity rate 2.080 c/kWh Prices exclude VAT

According to BGS, the D&C1 tariff is the most appropriate tariff for I/C customers consuming between 350,000 and 2,300,000 kWh per annum.

DEMAND & COMMODITY 2 TARIFF

The Demand and Commodity 2 tariff (D&C2) is similar to D&C1 but has a higher annual supply charge and a lower commodity unit rate. Approximately 1,300 customers are supplied on D&C2. Typically the D&C2 tariff applies to single site customers consuming up to approximately 5.3 GWh per annum but it applies also to many smaller sites with group affiliations.

Demand & Commodity 2 Supply Charge €4987.03 pa applied monthly Meter Charge €83.14 pa applied monthly Commodity Charge 1.937 c/kWh Prices exclude VAT

According to BGS, the D&C2 tariff is the most appropriate tariff for single site I/C customers consuming between 2,300,000 to 5,300,000 kWh per annum. Above this level the RTF applies.

37 Note, the ‘Supply Charge’ is a fixed charge.

38

Figure 4 - Industrial and Commercial Tariff Profiles

1.50

2.00

2.50

3.00

3.50

4.00

73,000 1,073,000 2,073,000 3,073,000 4,073,000 5,073,000

Annual Consumption (kWh)

Cos

t of

Gas

(c/k

Wh)

I/C BlockedD&C1D&C2

The graph above shows the cost of gas (in c/kWh) for each of the I/C tariffs. It clearly shows the most appropriate rate for different levels of consumption.

Residential Tariffs

There are six current residential tariffs (the Standard Rate Tariff, Gas Card Tariff, Golden Years Rate, Supersaver Rate, Economy Rate, and Reducing Rate), and two recently discontinued tariffs (the Double Up Discount Rate, and Coin/Concession Tariff). There are approximately 435,000 residential customers. Customers can switch between tariffs, subject to the minimum take requirements of some tariffs.

STANDARD RATE TARIFF

The domestic Standard Rate tariff is the most recent domestic gas rate, used by the majority of residential customers (approximately 280,000). It was launched by BGS in January 1996 as the default tariff for all new central heating customers. The purpose of the domestic standard rate was to provide a price structure that reflected an estimate of the cost structure in emerging transportation charges in the form of a high standing charge and a flat commodity rate.

Standard Rate Profile Supply Charge €162.54 pa applied bi monthly Commodity Charge 2.155 c/kWh Prices exclude VAT

According to BGS, the Standard Rate is designed for central heating users and its cost is closely aligned to that of Supersaver for the typical central heating user.

GAS CARD TARIFF

The Gas Card tariff is a pre-payment metering system, meaning customers pay for gas before they use it (much like pay-as-you-go mobile phone users). It was first introduced in 1994 and is used by approximately 17,000 customers. The rationale for this type of tariff is to make gas available to

39

customers who might prefer, for budgeting reasons, to pay in advance rather then receive bi-monthly bills. This tariff is the targeted at the local authority rented housing sector.

Gas Card Rate Profile Supply Charge €59.74 pa applied daily Commodity Charge 2.836 c/kWh Prices exclude VAT

The Gas Card tariff is not universally available. Gas card meters are located in clusters close to retail outlets that have the necessary facilities to provide credit.

GOLDEN YEARS RATE

The Golden Years tariff was introduced in the early 1990’s. It is applicable to senior citizens only and is used by approximately 3,000 customers. It offers the same unit charge as the economy rate but requires no minimum usage.

Golden Years Rate Profile Supply Charge None Minimum Take None Commodity Charge 3.734 c/kWh Prices exclude VAT

Customers on this tariff typically are using it in conjunction with a social welfare energy allowance. According to BGS, it is the most appropriate tariff for small to medium consumption elderly customers.

SUPERSAVER RATE

This tariff was introduced circa 1986 as part of a program of harmonising tariff rates across the utility areas of Cork, Dublin, Limerick, Clonmel, and Waterford. It requires a minimum annual commitment to pay for 16,000 kWh but offers a flat rate for each unit of consumption. The tariff was the basis of central heating changeover promotions from the late 1980’s to mid 1990’s and is used by approximately 100,000 customers.

Super Saver Rate Profile Supply Charge None Minimum Take38 16000 kWh pa Commodity Charge 2.836 c/kWh Prices exclude VAT

According to BGS, the Supersaver Rate is the most appropriate tariff for customers with medium to high annual usage.

ECONOMY RATE

The Economy Rate tariff is similar in structure to the supersaver rate. It requires a lower minimum annual usage of 8,750 kWh but has a higher commodity rate. It is used by approximately 9,000 customers.

38 Customers on this tariff must pay for a minimum of 16,000 kWh of gas each year, even if they consume less than this amount.

40

Economy Rate Profile Supply Charge None Minimum Take39 8750 kWh pa Commodity Charge 3.734 c/kWh Prices exclude VAT

According to BGS, the Economy Rate is the most appropriate tariff for smaller gas users consuming between 7,618 and 10,295 kWh per annum.

REDUCING RATE TARIFF

The Reducing Rate tariff is a traditional gas pricing structure from the Towns Gas industry that pre-dates the emergence of the Natural Gas industry in the early 1980’s. It was relaunched in 1988 as part of a harmonised tariff structure across the old Town Gas utility areas of Cork, Dublin, Limerick, Clonmel, and Waterford. It’s design allows customers with varying consumption to use a tariff with an effective ‘volume discount’ built in as consumption increases. It is used by approximately 25,000 customers.

Reducing Rate Profile Supply Charge €30.15 pa applied bi-monthly Band 1 (0-585 kWh) 5.673 c/kWh Band 2 (586-1170 kWh) 4.253 c/kWh Band 3 (1171+ kWh) 3.007 c/kWh

Banding is applied on a bi-monthly basis

Prices exclude VAT

According to BGS, the Reducing Rate is the most appropriate tariff for lower consumption customers. It is the default tariff for cooking only customers.

DEMAND UP DISCOUNT RATE

The Double Up Discount tariff was withdrawn from the market at the end of 2002 as part of a rationalisation of pricing structures. It was originally aimed at low to medium consumption usage but the reducing rate provided better value at this level of consumption. The tariff had a minimum annual usage level of 5,850 kWh and a flat commodity charge of 5.001 cents per kWh.

COIN/CONCESSION TARIFF

The Coin/Concession tariff was also withdrawn from the market at the end of 2002. The number of customers on this type of tariff had dwindled over to the years to a mere handful. The changeover to the Euro in 2002 was the main factor in the final elimination of this tariff as the dated meters were not suitable for conversion to new coins. The Gas Card tariff is the modern equivalent to the old coin rate tariffs.

The graph below shows the cost of gas (in c/kWh) for each of the residential tariffs at different consumption levels. It clearly shows the most economical rate for different users.40 The (generally) higher cost of gas in lower consumption levels would tend to reflect the cost to the system of low consumption users. A large proportion of the costs of serving residential customers are fixed. Regardless of how much gas a household uses, it still has one meter, a service pipe (the dedicated pipe from the gas main running down the street to the house), has its meter read, and is billed (all of these costs do not vary with consumption). So for a low consumption user these costs to the system are

39 Customers on this tariff must pay for a minimum of 8,750 kWh of gas each year, even if they consume less than this amount.

40 To put the graph in context, the average annual consumption for households is approximately 16,400 kWh. The vast majority of residential users consume in the range of 7,500 kWh per annum to 30,000 kWh per annum. Households that use gas for cooking only would tend to have annual consumptions much lower than the average.

41

spread over a lower level of consumption, and hence the per unit cost of gas is higher. This reasoning explains the general shape of the curves below (i.e., exhibiting a decreasing cost of gas as consumption increases).

Figure 5 - Residential Tariff Profiles41

.2.2. Issues with Current Franchise Supply Tariffs

2

3

4

5

6

7

8

9

10

500 3000 5500 8000 10500 13000 15500 18000 20500 23000 25500 28000 30500 33000

Annual Consumption (kWh)

Cos

t of

Gas

(c/k

Wh)

Standard RateGas Card RateGolden Years RateSuper Saver RateEconomy RateReducing Rate (indicative)

6

t franchise supply tariffs. This section highlights

es

Section 6.2.1 described the structure of the currensome of the Commission’s observations on these tariffs that will be the subject of further consideration in Phase II of its Gas tariff Review. Section 6.2.3 deals with issues relevant to the future design of supply tariffs.

Tariff Anomali

for residential tariffs shows the variation among the tariffs. It shows, for example,

Golden Years Rate, there is not a clear cost rationale for the

The graph above that the Golden Years Rate is considerably cheaper than other tariffs at annual consumption levels below approximately 4000 kWh. Also, it shows that the Economy Rate tariff is more expensive than other tariffs at all consumption levels42.

Aside from the Gas Card Rate and the variation among the tariffs43. The Standard Rate tariff, for example, is more expensive than the Super Saver Rate in the consumption range between approximately 13,500 kWh and 23,000 kWh per annum. However, there is no apparent reason why consumers in this range on the Super Saver Rate would impose any lower costs on BGS than those on the Standard Rate tariff. Similarly, the Economy Rate is

41 Note, the ‘Reducing Rate’ tariff in the graph is merely indicative, assuming a totally flat consumption profile over the year.

42 However, at some consumption levels the Economy Rate may be the best option for certain customers who cannot avail of the Gas Card Rate or the Golden Years Rate.

43 The Gas Card tariff would be expected to vary from other tariffs because customers using it would cause BGS to incur different costs from users on other tariffs. For example, the use of gas card meters imposes higher meter installation costs but no meter reads costs. Also gas card users do not receive credit. The Golden Years Rate would differ from other tariffs for social reasons.

42

cheaper than the Standard Rate over a narrow band. If there is no cost difference in providing the same service to customers on different tariffs, then the current tariffs may not be cost reflective. This could potentially impede the development of competition when customers in this sector of the market become eligible to choose their supplier.

Some tariffs only offer the cheapest rate over a narrow range of consumption. The Economy Rate for

s implies that the Gas Card Rate imposes low fixed costs on the

rs at discounts to the published

example, as can be seen on the graph above for residential tariffs, only offers the lowest rate for customers who use between approximately 7,500 kWh and 10,000kWh.44 The band is narrow to the extent that customers may move outside the ‘optimal band’ in any given year merely due to the weather being colder or warmer than normal.

The graph above for residential tariffsystem (due to its low cost at low consumption levels). This may not, in fact, be the case, as gas card meters are more expensive to install than standard residential meters.

An issue with the D&C2 tariffs is that BGS supply some custometariffs45. Thus, for example, BGS might supply someone at the D&C2 tariff rate discounted by 20%. Alternatively, the supply charge may not be levied. The customers supplied under such arrangements need to be transitioned to the relevant tariffs. Such transition may present additional issues in terms of customer impact.

Issue No. 10 – Tariff Anomalies and Issues

The Commission invites comment on the apparent anomalies within and between the different tariffs and other franchise tariff issues.

he Market Cost of GasT

ffs do not reflect the market cost of gas - that is, they do not reflect the costs

reflective’ level include:

nd) having

• er,

The current franchise tarithat a new supplier would face if they were to enter the market. In its submission to the Commission in 2002 BGS estimated that a 27% tariff increase was necessary in 2002/3 to bring the tariff levels in line with the full market cost of serving the franchise market. In March 2003 the Commission approved a 9.1% increase in BGS’s tariffs. However there is still a significant gap between the market cost of gas for the franchise market and the cost of gas reflected in the current franchise tariffs. This has the effect of placing an upward pressure on gas prices.

Reasons that the franchise tariffs are below the ‘market cost

• The cost of gas in the UK market (the reference market for gas prices in Irelaincreased significantly in recent years (see Figure 6 below), while tariffs have not; and BGS, through locking into long-term contracts to buy gas when market prices were lowbeing able to access gas at a cost that is lower than the market cost (i.e., BGS’s weighted average cost of gas (WACOG) is lower than market cost).

44 That is, for customers that cannot avail of the Gas Card Rate or the Golden Years Rate.

45 BGS has not offered these discounts to customers subsequent to April 2003. However, BGS have honoured contracts entered into with customers prior to that date.

43

Figure 6 - Historic UK Gas Prices: 1999-2004

hus, there is a distinction between ‘market cost reflective’ and ‘cost reflective’ tariffs. As BGS’s

4.00

8.00

12.00

16.00

20.00

24.00

28.00

32.00

Jan-99 Jul-99 Jan-00 Jul-00 Jan-01 Jul-01 Jan-02 Jul-02 Jan-03 Jul-03 Jan-04

Ster

ling

p/Th

IPE INDEX

TWACOG is lower than market cost, cost reflective tariffs would be set at a lower level than market cost reflective tariffs. However, the long-term contracts from which BGS derives it WACOG benefit will expire in 2006 and BGS will need to replace those contracts with new ones (at market cost). Thus, over time, BGS’s costs will approach market costs, and the distinction between market costs and BGS costs will be less significant. This distinction is not an issue for RTF customers as the formula already reflects the market price of gas (see Section 6.3.1 below).

Premiums associated with long-term gas contract

In the period of April 2003 - March 2004, BGS’s contract portfolio was expected to achieve a saving of

ion, size, swing and take-or-pay

ition BGS will face risks associated with the potential

a market such as the IPE and BGS would not be wise to expose itself and its customers to long-term contracts to the same

€41 million (the ‘WACOG benefit’) relative to spot prices on the IPE market46. The majority of this (€39m) was allocated to the franchise market. These beneficial medium term gas contracts included in BGS’s portfolio will expire on a phased basis between now and 2006.

BGS purchases gas under a portfolio of contracts of varying duratarrangements. This portfolio includes spot purchases. BGS in turn has a number of contracts, of varying duration, to supply customers, often at prices that are fixed in advance. BGS chooses to contract for gas rather than purchase all its requirements on the spot market in order to limit its contract exposure with its own customers. Contracts are a hedge and should generally be more costly, on a long-term average, than spot purchases.

With the introduction of full retail competmismatch between the length of its gas purchase contracts and the length of its contracts with final consumers. Large-scale switching by consumers away from BGS could leave it with large quantities of stranded contracts. The extent of this risk depends on the proportion of consumers who can be expected to switch away from BGS as retail competition develops, and how the resulting quantities compare with the quantities of gas purchased by BGS under long-term contracts.

BGS’s contracts cannot be expected, in the long-term on average, to outperform

46 The outturn benefit is expected to be even higher as market prices have risen since the 2003 BGS revenue review.

44

extent that it has in the past. This is because BGS is exposed to greater risk of loosing customers and its allowed revenue would need to be recovered from a smaller customer base, thereby exerting an upward pressure on tariffs. For this reason, in the longer term, the Commission takes the view that47 gas tariff structures should be related to prices on markets, such as the IPE, rather than contract prices.

Issue No. 11 – Market Reflective Tariffs

The Commission invites comment on its proposal that gas tariffs should reflect market prices for gas.

Weighted Average Cost of Gas (WACOG)

long term contracts entered into as the supplier to the ost of gas (WACOG) is lower than the current market cost

non market-reflective prices

ould be set at market reflective levels, and BGS would receive a

s to compete with BGS, and BGS would receive ‘windfall’ profits because they would be

As mentioned above, due to favourable franchise market, BGS’s weighted average cof gas. As the contracts from which the WACOG benefit derives were entered into by BGS as franchise supplier for the benefit of the gas market, the Commission believes that this benefit should remain either with the existing franchise market or the market in general.

There are different ways in which the WACOG benefit can be dealt with. The first way is to set BGS’s tariffs at levels that reflect their WACOG. Thus, tariffs would remain atinitially, and then increase as BGS’s WACOG benefit disappears (as the long term contracts expire over time through to 2006). Eventually the tariffs would reach market reflective levels. This option would keep prices lower in the short term, to the benefit of consumers. However, it would delay the arrival of competition in the market.

A second way to deal with the WACOG benefit would be to ‘recycle’ the WACOG benefit into transmission tariffs. BGS’s tariffs wwindfall (due to their WACOG being lower than market prices). This windfall would be transferred from BGS to BGÉ Transmission, and would be deducted from the revenue to be collected by the transmission tariffs. The transmission tariffs would therefore decrease, to the benefit of all consumers48. Under this option, consumers would receive the advantage of the WACOG benefit49 and, because BGS’s prices would be set at market reflective levels, competition in the market would not be delayed.

A third option is to set tariffs at market reflective prices but not ‘recycle’ the benefit. This would allow new entrantselling gas at market prices, but buying it at a much lower price (due to the WACOG benefit). As stated above, the Commission believes that the WACOG benefit should stay with the market. As this option does not meet this requirement it is not recommended for further consideration.

Issue No. 12 – The WACOG benefit

The the manner in which the WACOG benefit is dealt Commission invites comment on with.

.2.3. Future Supply tariff structure6

Introduction

Supply tariffsdistribution co

recover the costs of the purchase and sale of gas itself, including transmission and sts (including metering costs), as well as the costs of customer account acquisition and

management. 47 The Commission’s view is contingent upon there remaining surplus capacity in the interconnector pipelines with the UK.

48 The WACOG ‘discount’ applied to the transmission tariffs would have to be spread over a number of years to avoid undue fluctuation in the transmission tariff.

49 Though the distribution of the WACOG benefit would be spread more evenly to all consumers, rather than focussed on the franchise market as at present. Alternatively, the WACOG benefit could be ‘recycled’ through the distribution tariffs, focussing the WACOG benefit on smaller users of gas.

45

In developing its proposals for supply tariffs the Commission is concerned with the supply tariffs that will be established following the introduction of full retail competition in 2005.

The main drivers of supply costs are:

s associated with each consumer.

The s ate Commission con ta cost drivers are considered in t S

lock tariffs.

Imp

• the use made by the consumer of the transmission and distribution networks, • the quantity and profile of gas purchased to supply the consumer, • the account management cost

fir t of these is considered in Section 5 on distribution charges and in the separsul tions and decisions on transmission charges. The second and thirdhis ection, which deals with the following issues:

• the impact of swing on costs; • customer categories; • customer related charges; • capacity charges; • declining/increasing b

act of swing

Apart from volumes consumed, the most important factor determining the cost that a customer imposes on BGS, is the peakiness of demand - or ‘swing’ or ‘load factor’. Swing is the ratio of the gas consumed on the day of highest annual demand, to the annual average daily demand50. This is

ically in Figure 7.

be used to help reduce peak gas purchases, but storage itself has

illustrated schemat

The gas delivery system must be designed to cope with the maximum flow in any one day; the most efficient delivery profile is therefore a constant flow of gas each day of the year - with no swing. As swing increases, the delivery system must be expanded to cope with the peak demand, but remains unutilised at other times. Storage cancosts.

Figure 7 – Schematic illustration of Swing

Time of Year

Daily

Gas

Dem

and

Annual Peak

Annual Average

Swing = Annual Peak / Annual Average

The swing parameter can be calculated for any gas demand profile, e.g., all gas demand in Ireland, for a group or class of customers, or for an individual customer. Because peak demands do not all occur 50 Where the annual average daily demand is simply the annual consumption divided by 365 - the number of days in a year. Swing is expressed in percentage terms as the ratio of peak demand to average demand. For example: a purely flat demand profile has 100% swing; where the ratio of peak demand to average demand is 1.5, the swing factor is 150%.

46

simultaneously, generally th and profile, the smoother will be the shape. For example, swing for an individufor all residential customers combined.

Swing for residential and commercial customers is driven primarily by space heating in winter and the higher energy requirements at that time of year for end uses such as hot water and higher ambient losses51. Swing for industrial customers will reflect the way each industry (or each individual factory) uses gas in its production processes (continuous or batch processes) and the work schedule of the factory (5- or 7-day work weeks, shut-downs for annual holidays or maintenance) and any seasonality in production.

The swing parameters are used to identify the components of cost - procurement, transmission and distribution - for each group of customers. The principle in each case is fundamentally the same though the calculation may be presented differently.

For transmission and distribution, swing is used to calculate the peak MWh/day per customer and this is then multiplied by the appropriate transmission or distribution use-of-system charge in terms of € per peak MWh/day. In 2002/3 for example, the transmission use-of-system charge was €685 per peak day MWh and the average residential customer was forecast to contribute 0.141 MWh on the peak day.

For transmission, distribution and procurement, because peak demand does not occur simultaneously, it is necessary to adjust for the diversity or portfolio effect of the group of customers. This diversity/portfolio factor is incorporated in the estimates of peak day demand (for transmission and distribution) and in the cost of swing (for procurement52).

e larger the group of customers included in a demal residential customer will be higher than swing

Swing is calculated on the basis of an average winter temperature but, when booking transmission capacity, BGS must allow for the possibility of below average temperatures. This is calculated for temperatures that are expected to occur once in every 50 years. The adjustment to the swing parameters reflects the temperature sensitivity of demand in each customer category53.

Table 6 – Swing by Customer Type

Customer Type Annual Consumption (MWh) Annual Swing*

Very Large > 1,500,000 115%

Large >260,000 but < 1,500, 000 125%

Medium >57,500 but < 260,000 137%

Small > 5,500 but < 57,500 151%

Franchise All consumption <5,500 MWh 243%

* Annual Swings provided are for illustrative purposes only as swings per customer type will change as a portfolio and/or customer behaviour changes.

Annual swing is the peak to average ratio across a twelve-month period and the cost of swing for different customer types, shown in Table 6, is calculated relative to the price of annual flat gas.

51 Volumes of hot water consumed are similar in winter and summer but water needs to be raised from a colder starting

ulated as the cost of procuring the total volume of gas for the franchise market. This therefore

temperature. Losses of heat from buildings are high in winter because the differences between the outside and inside temperatures are greatest.

52 The cost of swing is calcalready incorporates the portfolio impact of the groups of consumers.

53 This is calculated by BGS using regression analysis.

47

A large proportion of the cost of swing is therefore related to the months of the year in which demand occurs. For example, for small temperature sensitive customers, most gas demand occurs in the winter

onths when prices are on average significantly higher than the annual price of gas. For procurement urposes therefore, due to the high variability of demand across the twelve-month period and the high

volatility of monthly gas price ing can be determined using twelve distinct monthly periods. That is,

for each m of gas, and th provide n a month

of gas can be (especially for winter gas), the cost of swing is continually changing.

mp

s versus the annual price, the cost of swthe cost of supplying a customer group can be related to the

expected demand for flexibility withi

onth, the relevant monthly price.

e cost of swing to

As the price very volatile

Issue No. 13 – Impact of Swing

The Commission welco pact of swing on gas ta ctures. mes comments on the im riff stru

Customer categories

t different needs. In the residential sector, for example, the tariff categories clude the Standard Rate, the Supersaver Rate, and the Golden Years Rate, etc.

stomer

are likely to be different costs for each sub-category. This implies that if BGS’s residential tariff does not distinguish size then there will be some cross-subsidy among residential customers.

Swing parameters will be used to estimate influe

Section 6.2.1 describes the customer categories currently in use by BGS and that have evolved over a number of years to meein

The main reason for choosing customer categories should be related to cost reflectivity: a tariff category should be introduced if consumers in that group cause BGS significantly higher or lower costs than other consumer groups (social factors are the other main reason for choosing cucategories). Tariff categories are not necessary for daily metered customers because the metering automatically reflects any important differences among consumers in the costs that they impose. The discussion below is therefore concentrated on non daily-metered customers.

The main factor leading to higher costs among consumer groups is ‘swing’ - as discussed above. BGS’s data shown in Table 6 shows that the franchise sector has a swing of 243% while ‘Small’ customers have a swing of 151%. There is therefore an unambiguous justification for distinguishing between the tariffs for these two categories.

There are also likely to be differences within the categories shown above. For example, within the franchise sector, small residential customers may have different swing to large residential customers. Thus, there

the cost differences among customer groups and these will nce the Commission’s decisions over the choice of tariff categories.

Issue No. 14 – Tariff Categories

The Commission invites comments on the nature of any changes that might be required to gas tariff categories.

Fixed (customer related) charges

Fixed charges are used to recover the account management costs associated with each consumer. These costs include billing, meter reading, call centres and some other costs (and should not be confused with capacity related costs). In terms of ‘marginal cost’ they should be calculated by considering how the above annual costs would change if, say, BGS were to have another 1,000 customers . 54

Fixed customer related charges are largely invariant with consumer size, and therefore represent a larger proportion of their total bill for smaller consumers.

,000 to give the marginal cost per customer. 54 The total change in costs would then be divided by 1

48

Supply charges are a feature of most of the gas tariffs in the franchise sector in Ireland with the exception of the Golden Years Rate. These supply charges are, generally, a combination of customer related costs and capacity related costs (discussed below). Some of the residential tariff categories have minimum-take components in the tariff that can, in some cases, be used to reflect fixed customer costs.

As part of this on-going Review, the Commission will consider the level of fixed customer costs and whether the tariffs should be revised to reflect these costs.

Issue No. 15 – Fixed Charges

The Commission invites comments in relation to the fixed customer-related components of gas tariff structures.

Demand Metering

urrently, there are no franchise customers facing demand charges (price per peak-day kWh). Instead, and distribution and the costs of procuring gas at peak times are

and metering should be adjusted.

Cthe capacity costs of transmissionreflected non-transparently in fixed annual supply charges and in commodity charges. This gives no incentives to customers to reduce their winter peak demand (i.e., to reduce swing). On the other hand, the introduction of demand metering would be expensive for small consumers and the potential savings may not warrant the additional costs.

A balance has to be made between the cost of metering and the desire for cost reflectivity. As part of the Review, the Commission will consider whether BGS has achieved the right balance at the present time or whether the customer size threshold for dem

Issue No. 16 – Threshold for Demand metering

The Commission invites comments in relation to the level of volume/type of customer for which demand metering should be implemented in the market.

Declining/increasing blocks

A ‘de n are lower ed at 3.0c/ 00 kWh might be charged at 2.8c/kWh. An ‘increasing block’ tariff is one

which the prices increase as consumption increases. Declining or increasing blocks are not generally troduced for reasons of cost reflectivity.

e sometimes introduced instead of a fixed (customer) charge; the first block is set at

charges and no metered demand charges; the declining

bsidised by the consumption of higher income consumers in the higher blocks. There are no increasing block gas tariffs

The ether these uring revenue security. The Commission will also review the tariffs for residential consumers and will consider the option of a low initial block. The Commission must also, however, consider the possible distortions that could arise from this policy in terms of competing fuels (heating oil, solid fuels, LPG).

clining block’ tariff is one in which the price per kWh for higher ‘blocks’ of consumptio than in the lower or earlier blocks. For example, the first 6,000 kWh might be chargkWh while the next 9,0

inin

Declining blocks ara higher price in order to cover the fixed customer related costs. However, it is more cost reflective to have a properly cost reflective customer charge combined with variable charges. Arguably, declining blocks may also be introduced in order to cover fixed capacity related costs that cannot be recovered through a metered demand charge. The higher initial blocks guarantees the Licensee greater revenues to cover fixed, capacity related costs, if demand is low. BGS’s I/C tariffs for example incorporate declining blocks, relatively low fixed (supply)block tariff in this situation is designed to recover fixed capacity costs.

Increasing block tariffs are typically introduced for social reasons. Low income and elderly consumers will typically consume most of their gas within the initial block and will be su

at the present time in Ireland.

Commission will review BGS’s declining block tariffs in the I/C groups and consider wh are the best approach to providing cost reflectivity and ass

49

Issue No. 17 – Supply Tariffs – Increasing/Declining Blocks

The Commission invites comments regarding the block component of current gas tariff structures and views on possible alternatives.

6.3. The Eligible market

6.3.1. Current Eligible Market Pricing

The eligible market consists of all gas users that are eligible to choose from whom they take their gas supply – i.e., all users that consume above 5.3 GWh per annum (181,000 therms), or use gas for the purposes of electricity generation. The eligible market is split into the large end user market, the gas fired generation market and the RTF market.

The Large End User Market

Upon the implementation of the RTF, it was decided that the upper threshold of the RTF should be 264 GWh per annum (9m therms), as competition was thought to be well established in that market. Thus, for users consuming above this threshold there are no regulated tariffs.

The RTF Market

The RTF55 applies to eligible customers who consume between 5.3 and 264 GWh per annum (181,000 and 9m therms) and are not supplied by an independent (i.e., non-BGS) supplier. The objective of the RTF is to provide a transparent market-price reflective mechanism for the pricing of customers, creating a clear target for competing suppliers. The regulated nature of the RTF allows BGS, the supplier to the franchise market, to also operate in the eligible market.

The RTF is based upon the following formula:

P = [(IPE Index + Tuk +Psw) * EUR/GBP] + Tti +Tdi + Si + Fixed Charges

here:

The price of gas for the customer

ternational Petroleum Exchange price index at the NBP

m

W

P =

IPE Index = The Inin the UK

Tuk = UK transportation charges

Psw = Swing Premiu

EUR/GBP = The Euro Sterling exchange rate

Tti = Transportation charges for the Irish Interconnectors and on-shore Ireland Transmission System

Tdi = Transportation charges for the Irish Distribution System

Si = Shrinkage charges on the Irish System

Fixed Charges = A fixed charge to cover BGS operating costs and margin

55 Introduced by papers CER/03/078 and CER/03/079, and amended by CER/04/111.

50

The formu ur in supplying monthly variable price contract; and 3, 6, 9, and 12 month fixed price contracts. All products are based

formula above. Under the monthly variable price contract (of one year duration), the price mer is charged each month (m) is the average of the previous month’s (m-1) daily forward market prices

for month m56. T e customrise) during the contract period, the price the customer receives will also fall (or rise).

Under ontract, t re the contract is entered into the term of the contract before the contract is signed.

la is designed to clearly identify the different elements of cost that a supplier would inca customer. A number of different products are available under the RTF: a 12 month

upon thethe custo

hus, th er is exposed to variations in the market. If the market prices fall (or

the fixed price c. Thus, the prices for each month are fixed and known for

he prices the customer is charged for each month are set shortly befo

Issue No. 18 – The Regulated Tariff Formula

The invites comment as to the appropriateness of the RTF and whether Commission th natives there are any alter at could be used to replace it.

The Gas Fired Generation Market

Some g that consume be s to generate electricity57. These customers have the choice of an RTF contract, the relevant franchise tariff (outline ve), or supply by an

6.3.2. E g - I

as users low 5.3 GWh per annum are eligible because they use ga

d abo independent supplier.

ligible Market Pricin ssues for Consideration

Scuection 6.2.3 identified a number of issues relevant to the future structure of supply tariff design in the rrent franchise market. Many of those issues are also relevant in the context of eligible market

pricing, particularly in the RTF market. There are a number of additional issues regarding the current tariff arrangements that are highlighted below.

Cost reflectivity

The lack of market cost reflectivity in the current franchise tariffs causes issues at the border between the franchise tariffs and the RTF. As outlined above, the RTF reflects market prices. Thus, customers just below the RTF threshold of 5.3 GWh are able to avail of favourable franchise tariffs (D&C2 tariff), while users just above the threshold face market reflective prices. This discontinuity may raise perverse incentives for gas users, and produces a potentially inequitable situation where similar sized users are charged very different tariffs.

Issue No. 19 – Border between Franchise Tariffs and RTF

The Commission invites comments on the discontinuity between current D&C2 franchise tariff and the RTF.

RTF thresholds

An issue with the RTF is the range of customers to which the RTF currently applies. Currently, as outlined above, the RTF applies to BGS customers who consume between 5.3 and 264 GWh per annum (181,000 and 9m therms). Potentially, both the upper or lower thresholds could be increased or decreased.

The lower threshold of the RTF (5.3 GWh) is currently set at the same level as the eligibility threshold.

That is, all customers that are on an RTF tariff are eligible to change supplier. Additionally, all users

56 For example, a customer’s price for May will be determined by averaging the May forward market settlement prices for every day up to the second last business day in April.

57 See Section 10A of the Gas Act, 1976, as amended by Section 14 of the Gas (Interim) (Regulation) Act, 2002.

51

above the threshold have daily metering equipment58. The RTF, through use of the daily usage information ‘customises’ tariffs for customers. If the lower RTF threshold were to be increased, it

liers the ability to ‘cherry pick’ the better load profile customers, to the detriment of r a ‘customised’ tariff to customers, undercutting

ectricity). If the franchise supplier is also able to operate in the competitive market, there is a da be undercut in the comp its position as franchise supplier. The g the ability to leverage its position as franchise supplier. Having an upper threshold for the RTF means that BGS is able to supply some very large customers in an unregulated manner. Potentially, BGS could

verage its position in the franchise market to compete unfairly in this sector. The Commission could or example, by raising the upper threshold of the RTF, so that more of BGS’ activity e sector is regulated under the RTF.

would give suppBGS (as independent suppliers would be able to offeBGS’s ‘averaged’ tariffs calculated based upon the good and poorer load profile customers). To decrease the lower threshold of the RTF would add complexity to smaller consumers of gas. The Commission would therefore propose not to change the lower threshold of the RTF.

The upper threshold of the RTF is set at 264 GWh. Part of the rationale of introducing the RTF was to allow BGS, the supplier to the franchise market, to also operate in competitive market without setting up an independent business (such as ESBIE in el

nger that other suppliers will etitive market by the franchise supplier, who is able to leverage

RTF allows BGS to operate in the competitive market in only a regulated way, decreasin

lerespond to this, fin the competitiv

Issue No. 20 –RTF thresholds

The Commission invites comments on the current positioning of the RTF in the eligible market.

Capacity charges

All RTF customers currently pay explicit capacity charges, though the charges are billed as monthly fixed charges. The transmission charges for winter-peaking RTF customers are based on the average of the five highest metered demand days . Summer peaking customers additionally pay a charge of 50% of the transmission tariff for their summer peak consumption .

The transmission and distribution capacity charging policy may not re

59

60

flect diversity among customers.

ds as the basis for capacity charges for winter

• ission tariff) for summer peaking customers, • d

The sum of customer demands calculated using the approach in the RTF formula is likely to exceed the peak demand of the RTF customers combined. This implies that BGS would have scope to recover more than its transmission and distribution costs (associated with these customers) through the capacity charges in the RTF tariff. This diversity in the RTF formula is recognised to some extent through the charging for transmission capacity: customers are charged for the average of their five peak days (rather than for the peak day), and summer peakers only pay 50% of their summer peaking capacity.

The Commission will review the capacity charges in the RTF formula and will welcome comments on and consider in particular:

• the use of the average five winter peak demanpeaking customers, the charges (50% of the transmthe appropriate adjustments in the transmission and distribution charges for customer loadiversity.

Daily metering equipment allows BGÉ to read customers’ meters on a daily basis, rather than a residential meter, for

example, which is only read periodically. BGÉ is able to gather more accurate information about the usage of customers by virtue of these daily reads.

59 f the

e five peak days in the summer, but only to the extent that that is greater than the winter peak.

58

Where sufficient data from daily meter readings is not available, capacities are estimated on the basis of calculations oDistribution Transporter.

60 That is, the average of th

52

Issue No. 21 – Capacity Charges for RTF customers

The Commission invites comments on the nature of capacity charging for RTF customers.

Swing

As discussed above in Section 6.2.3, apart from volumes consumed, the most important factor determining the cost that a customer imposes on BGS, is the peakiness of demand, or swing.

In the RTF formula there is a term for a swing premium . This term has the affect of increasing the price of g

61

as, so the higher the swing premium, the higher the price for the customer under the RTF.

The o ot reflect the actual cost of swing for RTF customers.

The swing premium is calculated as a charge of 0.15p Sterling per 10% of within month swing62, to a maximum of 1.0p Sterling. This price is set as a constant and does not vary, even if the cost of swing in the market changes.

C mmission is concerned that the current calculation of the swing premium in the RTF may n

I sue No. 22 – Swing Charges for RTF customerss

The Commission invites comments on the calculation of swing in the RTF.

Other terms and conditions

The total ‘pack y also have the overall attractiveness of the offer. For example, customers could be paying the

me price for gas supply, but one might have to pay its bills one month after the gas was supplied, hile the other might pay its bills three months after gas was supplied. Even though the customers

same price, one arrangement is more attractive to the customer than the other.

d above),

current structure63 of the RTF focuses on prices. However, price is only one aspect of theage’ a customer receives when it is being supplied with natural gas. Other facets of gas supplan affect on

sawface the

There are many facets of RTF gas supply that the current RTF Directions64 are silent upon, but that affect the attractiveness of the RTF offering. These include credit terms (mentioneresponsibility to nominate65, and liability for imbalance and overrun charges66.

As mentioned above, the purpose of the RTF is to regulate BGS’s behaviour in the competitive market. If the RTF Directions are silent on the matters above there may be uncertainty in the market regarding the application of the RTF.

Issue No. 23 – Terms and conditions of the RTF

The Commission proposes that the RTF Direction be reissued in a more comprehensive form, so the RTF will apply to all appropriate aspects of gas supply. Comments are welcomed on the aspects of gas supply that should be regulated under the RTF, and the manner in which they should be regulated.

79.

62 The charge for monthly swing relates to the maximum daily volume for a particular month, compared to the average daily volume for that month.

63 The current structure of the RTF is set out in papers CER/03/078, CER/03/079, and CER/04/111.

Transporte

66 arged under the transportation arrangements. Imbalance charges are incurred when a

it has booked.

61 See Appendix One of CER/03/0

64 See papers CER/03/078, CER/03/079, and CER/04/111.

65 Under transportation arrangements a customer’s shipper must nominate the quantities it expects to consume to the r.

Imbalance and overrun charges are chconsumer uses a different quantity of gas to that it nominated, while overrun charges are incurred when a consumer uses more gas in a day than capacity

53

Default tariff

The current RTF Directions do not clearly set a ‘default contract’. A default contract and price would apply to customers who, despite the best efforts of BGS and/or independent suppliers, have not signed a contract for supply of gas before the supply period commences. In preference to disconnecting the customer, the Commission will set a ‘default contract’ to apply to such customers.

A default contract should not be unduly onerous on customers, nor should it tie them to BGS for longer than necessary.

The Commission proposes that the default contract be an open-ended variable contract, with an option for termination upon one months notice.

Issue No. 24 – Default RTF

The Commission proposes that the default contract be an open-ended variable contract, with an option for termination upon one months notice.

54

7. Supply Revenue Formula

7.1. Introduction

In 2005 it is expected that the gas market will be fully open to competition67. Thereafter, all customers will be eligible to choose their supplier. However, there will still be a need for the Commission to regulate the level, as well as the structure, of tariffs charged by BGS for at least some customers and until such time as competition is fully established in that sector of the market. Given that, as supplier to any sectors in which competition is not fully established, BGS may be able to leverage its position in those sectors to its advantage in competitive sectors, the Commission must give consideration to regulating all of the activities of BGS. Such regulation may be required to ensure that it is not possible - and not perceived to be possible - for BGS to abuse its dominant position in any sector of the market.

The remainder of this section discusses the regulation of BGS’ supply revenue.

7.2. Form of Regulation

In setting allowed revenues, the Commission needs to strike a balance between:

• protecting the interests of consumers under the published tariff, by not allowing BGS to earn revenues exceeding those of an efficient business, and

• promoting the development of competition in the market.

There are five general methods of price regulation that might be considered for BGS:

• cost plus • price cap • revenue cap • simple performance incentive regulation • sliding scale regulation

Cost plus regulation on determining the allowed revenue in a given period as the approved

ive years (the ‘control period’).

ee adjustment components:

) in the traditional UK model)

Transmission and Distribution costs

The P f

cap regulation, the revenue rather than the price is capped for a period of time

is based costs plus an allowed profit, where the allowed profit is determined with reference to an approved margin or profit (e.g., rate of return). BGS’ allowed revenues are currently calculated in this way. This approach is relatively simple but gives BGS no incentive to be efficient.

Price-cap regulation caps the price for a period of time, typically for fThe intent of this approach is to give incentives to BGS to reduce costs and, at the same time, to reveal information to the Commission about the potential to reduce costs and improve efficiency, which can be used in setting future price controls.

Typically, the price cap formulae has thr

• price or cost inflation adjustment (the retail price index (RPI• an adjustment factor (X) – to promote cost efficiencies • pass-through share of costs (Y) – e.g., commodity costs,

R I-X+Y formula first used extensively in the UK is probably the most well-known example othis approach.

With revenue (typically five years). Except for differences in sales volume risk, in other respects price-cap and revenue-cap regulation are virtually identical. The periodic (e.g., 5-yearly) review establishes the total revenue that is allowed in each year of the control (e.g., each of the five years). Then, at the start of each year of the control period, the allowed unit price (c/kWh) for the following year is calculated as the allowed revenue divided by the forecast volume (kWh).

67 The precise date for full market opening will be decided by the Government.

55

With performance incentive regulation, the company is rewarded for good performance through profit increases, but the incentives are limited to a small number of cost areas. The term ‘performance regulation’ used in the regulatory literature includes quality performance measures as well as cost performance such as shrinkage but we are using the term here to refer to individual indicators of cost performance rather than, for example, indicators of reliability or response to customer complaints. This form of regulation is a simple variant of cost plus regulation in which some of the parameters used in the annual price review are predetermined by the regulator. For example, the bill collection efficiency (days receivables)might be pre-determined rather than actual.

The basic approach of sliding scale regulation or profit sharing, is that a benchmark profit should be determined for the company with excess profits being paid back to customers (e.g.: through a tariff reduction in a following year). The aim of this approach is to share the benefit of good performance between the company’s shareholders and the consumer, while still providing the company with efficiency incentives. However, the incentives are less powerful than with price-cap or revenue-cap regulation, under which all the surplus profits are retained by the utility for the duration of the control period.

A related form of regulation employs dividend sharing. With this type of regulation, a utility is required to pay out its entire profit each year partly in dividends and partly as a rebate or tariff adjustment to customers, the latter computed as a fraction by which the dividend exceeds the normal dividend. This is similar to profit sharing except that consumers receive a discount on their gas bill at the end of the year.

Sliding scale, profit sharing and dividend sharing forms of regulation are not common today. This is partly related to the difficulties in measuring profit and partly because this form of regulation is less effective at encouraging efficiency.

7.3. Revenue Control Formula for Electricity Supply

The gas supply business is fundamentally similar to the electricity supply business. Both buy transmission and distribution transportation services and while the electricity supplier buys from generators, the gas supplier buys from gas producers. The similarities between the two imply that regulatory precedents in the electricity sector are relevant to the gas sector.

The revenue control formulae for electricity supply (Public Electricity Supply or PES) is a revenue cap, as described in Section 7.2 above, but indexed in part to customer numbers and GWh sales. In this formula there is full pass through of transmission and distribution costs and of electricity procurement costs and PES is allowed revenues to cover its own costs that are calculated from base year (year 2000) costs indexed to:

• wage inflation, • the consumer price index, • customer numbers, and • GWh sales.

Costs are divided into payroll (50%) and non-payroll (50%) and each of these is further subdivided into fixed and variable components in the proportion 25% fixed and 75% variable. Wage inflation is applied to the payroll related costs and the consumer price index is applied to the non-payroll costs. The fixed costs are indexed only to the inflation parameters (wage inflation or consumer price index) while the variable costs are indexed to both customer numbers and the inflation parameters (wage inflation or consumer price index).

An X-factor of 2 is included in the PES formula for each year of the control period. This implies that PES is expected to reduce its controllable costs by 2% per year on average, relative to inflation (ie., if inflation is 5% then the PES’s costs are expected to increase by only 3%).

The PES was allowed a margin of 1.3% of turnover in the base year. This was then indexed in subsequent years of the control period to the consumer price index and to GWh sales. No X factor was applied to the allowed margin.

Allowed revenues and tariffs for any year t (t-1 is the ‘current’ year and t is the following year) are calculated on the basis of forecasts of inflation, customer numbers and GWh sales that are made in

56

year t-1and then when actual data becomes available on actual inflation, customer numbers and GWh sales68, there is an adjustment to compensate PES for the previous year’s over or under-recovery of revenues.

The PES revenue control formula is reproduced mathematically in Appendix 2.

7.4. Controllable Costs

The Commission wishes to prounder its control but to allow no

vide BGS management with incentives to reduce those costs that are n-controllable costs to be fully passed through in the tariff.

extent by

•

ng

cash collection

nditures (IT) rental

The largest of these are billing & cash collection, labour and transaction processing - in that order. These three account for over half of BGS’ own costs. All of the above costs are ‘controllable’ in the sense defined above and could be incentivised through a suitable revenue control formulae. However,

A controllable cost is a cost that the company can reduce by good management practice, or can allow to increase by poor management practice. It is a cost that is not influenced to any greatoutside circumstances or events. Controllable costs can be indexed in the revenue control formulae. The major components of BGS’s own operating costs are listed below:

• labour call centre and associated contractors

• marketi• transaction processing • billing and • administration • regulation • facilities • capital expe• property

these costs only represent a small share of costs to final customers (2-3% for larger customers but 9% for residential customers). This is similar to the electricity supply business where PES’ own costs average 4% of end user prices. While controlling these costs will be helpful, this cannot be expected to lead to dramatic improvements in end-user prices.

Nevertheless, the Commission is keen to explore options that would encourage BGS to reduce the cost of the gas it procures and would welcome comments on this issue.

Issue No. 25 – BGS’ Revenue Control

With regard to BGS’ own operating costs, the Commission’s initial proposal is to introduce a revenue control formulae broadly similar to that adopted for PES in the electricity sector.

68 This does not become available until year t+1.

57

8. Conclusion

The primary objective of gas market liberalisation is to give gas consumers access to secure and reliable gas supplies at competitive and reasonable prices. In the context of market liberalisation, the purpose of the Gas Tariff Review is to develop distribution and supply tariff structures that will not only encourage efficiency in the use of the gas distribution network but which will also promote competition and fairness in the various customer categories, while setting charges that are as cost-reflective as possible, and that do not discriminate unfairly between different customers.

In this consultation paper we have set out to inform customers, market participants and other interested parties about the potential consequences of market liberalisation for the current BGÉ distribution and supply tariffs. Our preliminary investigation of these tariffs has identified a range of tariff issues and tariff options requiring further consideration and analysis in the next phase of the review. In particular, we highlighted the upward pressure on supply tariffs being exerted by rising wholesale gas prices.

The consultation process is not restricted to the issues and options identified in this paper. Respondents are encouraged to contact the Commission on any matter that might have a bearing on the future structure of BGÉ distribution and supply tariffs, and the supply revenue control formula for BGS.

In the next phase of the review the Commission will investigate the costs associated with the distribution and supply of gas to consumers and how these are allocated to different categories of customer. On the basis of this analysis we will consider the appropriateness of the current tariff structures, bearing in mind the Core Principles discussed in this document, and make proposals to introduce either entirely new tariff structures, amendments to current tariff structures, or both. Before making these proposals the Commission will assess the impact of these changes on different categories of customer.

The Commission will publish its response to comments made to this consultation paper at the beginning of June. In July we will issue our proposals in relation to future distribution and supply tariff structures.

58

Appendix 1: Marginal Cost Formula

The formula for Long-Run Average Incremental Cost (LRAIC) is shown below:

( )

( )∑

∑

=

=

+

∆+

= T

ii

i

T

ii

i

rM

rI

LRAIC

1

1

1

1

where:

iI = investment cost in year i

T = planning horizon

M∆ = change in maximum kWh/day relative to previous year r = discount rate

Swing is defined as the ratio of consumption on the day of maximum demand and the average daily consumption over the year:

100

365

%365

1

max xkWh

kWhSd

⎟⎟⎠

⎞⎜⎜⎝

⎛=

∑

Where:

S% = swing, expressed in percent

kWhmax = peak kWh gas consumption for the consumer group

kWhd = kWh gas consumption on day d for the consumer group

The relationship between peak demand for a consumer group and demand at time of system peak is the coincidence factor:

100%max

xkWhkWhCF SP=

Where:

CF% = Coincidence factor, expressed as a percent

kWhSP = kWh demand of the customer group on the day of system peak demand

The diversity factor is the ratio of the peak demand for the customer group to the sum of the individual peak demands of the group members:

100%max

max xkWh

kWhDF i∑=

Where:

DF% = Diversity factor, expressed as a percent

ikWhmax = maximum kWh demand of customer i

A residential or other small customer may face a fixed monthly customer-related charge and a commodity charge that combines commodity costs with capacity-related costs, as follows (the Hopkinson Rate):

mcmc

r CS

xDFxCFMP +

⎟⎟⎟⎟⎟⎟

⎠

⎞

⎜⎜⎜⎜⎜⎜

⎝

⎛

⎟⎠⎞

⎜⎝⎛

=

100%

365%%

Where:

Pr = price, expressed as c/kWh

60

Appendix 2: Calculation of ESB PES Annual Allowable Revenue

The following Appendix is extracted from the Commission’s Decision CER/02/24, December 2002.

Total Allowed Revenue:

In the base year of 2000 the allowed revenue is calculated as:

)**][]([ 0000

002000 GWhMmberscustomernumberscustomernu

PvNPPvPPfNPPfPR +

+++=

PES’s total allowed revenue in Euro (€) millions for a given year, where t ≠ 2000, will be estimated in midyear t-1 for January to December of the following year t according to the following formula:

Estimated Allowed Revenue

PES Base Year Allowed Revenue will be indexed in successive years according to the following formula:

21211

11

11t

)*)1(*(

)*)]1(*)1(*([

)]1(*)1(*[ER

−−−−−

−−

−−

++++++

−++−++

−++−+=

tttttt

tt

tt

KrfKrfKDIKDIGWHCPIM

umbersEcustomernXCPIumbersEcustomern

PvNPXWI

umbersEcustomernPvP

XCPIPfNPXWIPfP

Revised Forecast Allowed Revenue

PES Revised Forecast Allowed Revenue will provide a better estimate of inflation, quantities sold and customer numbers. It will be used in the calculation of the initial k factor that will be applied to the allowed revenue of year t+1. The Revised Forecast Allowed Revenue will be calculated in May of year t according to the following formula:

21211

11

11

)*)1(*(

)*)]1(*)1(*([

)]1(*)1(*[

−−−−−

−−

−−

++++++

−++−++

−++−+=

tttttt

tt

ttt

KrfKrfKDIKDIRFGWHRFCPIM

numbersRFcustomerXRFCPImberscustomernu

PvNPXRFWI

mberscustomernuPvP

XRFCPIPfNPXRFWIPfPRFR

Forecast Actual Revenue

PES Forecast Actual Revenue will provide an estimate of the revenue that PES will earn using the revised forecast of customer numbers and GWh. better estimate of inflation, quantities sold and customer numbers. It will be used as part of the calculation of the initial k factor that will be applied to the allowed revenue of year t+1. The Forecast Actual Revenue will be calculated in May of year t according to the following formula:

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21211

11

11

)*)1(*(

)*)]1(*)1(*([

)]1(*)1(*[

−−−−−

−−

−−

++++++

−++−++

−++−+=

tttttt

tt

ttt

KrfKrfKDIKDIRFGWHCPIM

numbersRFcustomerXCPImberscustomernu

PvNPXWI

mberscustomernuPvP

XCPIPfNPXWIPfPCR

Actual Allowed Revenue

PES Actual Allowed Revenue will take account of actual inflation rates, quantities sold and customer numbers, providing the total amount of revenue that PES should have earned. It will be used in the calculation of the secondary k factor, which will be applied to the allowed revenue of year t+2. The Actual Allowed Revenue will be calculated in May of year t+1 according to the following formula:

21211

11

11

)*)1(*(

*)])1(*[)]1(*([

)]1(*)1(*[

−−−−−

−−

−−

++++++

−++−++

−++−+=

tttttt

tt

ttt

KrfKrfKDIKDIAGWHACPIM

umbersAcustomernXACPImberscustomernu

PvNPXAWImberscustomernu

PvPXACPIPfNPXAWIPfPAR

Actual Revenue Earned

PES Actual Revenue Earned will use the actual inflation rates, quantities sold and customer numbers for the year to calculate the total revenue that PES should have earned. It will be used in the calculation of the secondary k factor, which will be included in the allowed revenue of year t+2. The Actual Allowed Revenue will be calculated in May of year t+1 according to the following formula:

2121

11

11

)*)1(*1(

)*)]1(*)1(*([

)]1(*)1(*[

−−−−

−−

−−

+++++−+

−++−++

−++−+=

ttttt

tt

ttt

KrfKrfKDIKDIAGWHCPIMt

umbersAcustomernXCPImberscustomernu

PvNPXWI

mberscustomernuPvP

XCPIPfNPXWIPfPACR

K Factors

Revised revenue forecast k factor

Initial k factor

)1(*)(1 ICRRFRKRF ttt +−=−

The k factor above represents the difference between the revised forecast of PES allowed revenue and the forecast of what will be earned. This calculation will occur in May of year t and will be accordingly recovered/rebated in year t+1 with interest.

Secondary k factor

)1(*)1(*))(( 2112 −−−− ++−−= tttttt IIKRFACRARKRF

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This secondary k factor represents the difference between what was earned and what should have been earned less the amount previously recovered. This calculation will occur in May of year t+1 and will be accordingly recovered/rebated in year t+2 with interest.

Pass-through costs k factor

The pass-through costs k factor will correct for differences between the estimated and actual amounts of PES’ pass-through costs. The pass-through costs are separately regulated upstream costs and include DUoS and TUoS charges and purchases of electricity. The initial k factor will correct for differences in the estimate and revised estimate of these pass-through costs. This calculation will occur in May of year t and will be accordingly recovered/rebated in year t+1 with interest.

The secondary k factor will correct for the difference between the actual costs and the revised estimate of pass-through costs, less the amount previously recovered. This calculation will occur in May of year t+1 and will be accordingly recovered/rebated in year t+2 with interest.

Revenue Earned k factor

A third k factor will be included in the tariffs from 2003 to correct for changes in revenue earned due to variations in volumes sold. This k factor will incentivise PES to forecast the GWh and customer turnover correctly. This will impose upon PES a similar type of risk that an independent supply company faces. The Revenue Earned k factor is different from the prior k factors as the values on which PES is being incentivised arise from the tariff calculations, rather than the PES Allowed Revenue figures.

The penalty will operate in two stages. The first stage compares the original estimate of total revenue earned and the AUP for year t to the revised forecast for year t, will operate to a band of +/-4% of the original estimate. For example, the original estimate for 2003 is made on August 2002 and the revised forecast for 2003 is made in May 2003. The second stage, which operates to a band of +/-2%, compares the actual revenue earned with the revised forecast. This process will take place for the year 2003 in May 2004.

The Commission has agreed that a non-exhaustive list of ‘exceptional reasons’ will be assessed when implementing this penalty. These factors will be taken into account when assessing the level of variance between estimated and revised forecast and revised forecast and actual out turn (Appendix 5).

The penalty should be in proportion to the amount that PES can sustain, given its allowed revenues. The Commission has determined that the penalty should not exceed a maximum of €250,000 in any one year.

The mechanism for calculating this penalty, set out below takes into account changes in average unit price and sales volumes.

∆ AUPt-1 = (AUPt-1 * Qt) - (AUPt * Qt) ∆ AUPt-2 = ((AUPt-2 * Qt) - (AUPt-1 * Qt)) - ∆ AUPt-1

∆ Qt-1 = │(AUPt * Qt-1) - (AUPt * Qt)│ ∆ Qt-2 = │((AUPt * Qt-2) - (AUPt * Qt-1))│ The k factor will be applied to the sum of the revenue variance. ∆ TRev t-1 = ∆ Qt-1 + ∆ AUPt-1

∆ TRev t-2 = ∆ Qt-2 + ∆ AUPt-2

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Where the ∆ TRev t-1 is greater than 4% of the estimated total revenue earned, the penalty will apply to that percentage of the revenue earned greater than 4%. Interest on this amount plus a 2% penalty will be rebated in the following year.

Where the ∆ TRev t-2 is greater than 2% of the revised forecast total revenue earned, the penalty will apply to that percentage of the revenue earned greater than 2%. Interest on this amount plus a 2% penalty will be rebated in the following year.

ER Is the estimated total PES revenue allowed.

RFR Is the revised forecast of the total revenue that should have been earned, given revised forecasted values for CPI, WI, PES Customer numbers and GWh sales.

CR Is the cash revenue that is expected to be earned, given the revised forecast of customer numbers and GWh sales and the existing charges already built into the tariff.

AR Is the actual total allowed revenue that should be earned, given actual values for customer numbers, GWh sales, and allowed wage and actual CPI.

AUP Average Unit Price. This is calculated as the total revenue that PES will earn / total sales volumes.

ACR Is the cash revenue earned given the actual customer numbers and GWh sales, and the existing charges already built into the tariff.

PfP Is the fixed cost payroll related expenditure.

PfNP Is the fixed cost non-payroll related expenditure.

PvP Is the variable cost payroll related expenditure.

PvNP Is the variable cost non payroll related expenditure.

WI Is the wage inflator, PPF until 2003. If a new government agreement is not reached post 2003, CPI will be used.

CPI Is the average annual rate as published by the Central Statistics Office.

KDIt-1 Is any revenue allowed to be recovered in year t deferred from the previous year, adjusted for inflation and interest.

KDIt-2 Is any deferred revenue that should have been collected in year t-2 compared to the estimate used when calculating the value of KDIt-1, adjusted for inflation and interest.

KRFt-1 Is the difference between the revised forecast of allowed revenues and the estimated revenues that will be earned, with interest.

KRFt-2 Is the difference between the actual allowed revenue that should have been earned and the revenues that were earned, adjusting for the previous K factor based on the revised forecasts, with interest.

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GWh GigaWatt hours - Quantity of Electricity Sales

TR Total Revenue

E Estimated

Q Quantity

M Margin expressed as a value per GWh

RF Revised Forecast

A Actual

X Efficiency factor

It-1 Is the annual-average-three-month Euribor rate less the European Harmonized Index of Consumer Prices (HICP) plus Irish CPI based on the most recent published information at the relevant time.

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Appendix 3: International Tariffs

United Kingdom

The United Kingdom is significant because the markets is connected with Ireland. As the Marathon Kinsale Head field has moved into production decline as it approaches the end of its life, Ireland now receives a significant proportion of its gas via an interconnector with Scotland. Therefore, upstream gas prices on the International Petroleum Exchange (IPE) in London affect downstream prices and tariffs in Ireland. Furthermore, the UK implemented retail competition for gas some years ago. That experience may hold useful lessons for Ireland as it opens up its gas market to competition.

Scotland has about 5 million people, compared with about 4 million in Ireland, so the scale of the gas market in Scotland is comparable to that in Ireland in terms of population. Scottish gas retailers can operate in England and Wales and vice versa. The market is open to foreign-owned gas retailers. This is relevant to Ireland, where at least one European retailer (RWE) is seeking to establish a presence in the market. UK-based gas retailers might also be expected to be interested in extending their businesses to Ireland.

Ownership

The UK gas industry was at the forefront of the wave of privatisation liberalisation sweeping the world and is now totally privately owned. Transco is the main network operator and is segregated into its transmission and local distribution zones. There also a number of retail marketing companies.

Structure

In 1997 British Gas de-merged vertically to create Centrica and BG group. Centrica was the incumbent gas supplier and BG held Transco (integrated transmission and distribution business). Furthermore BG split its network assets off into Lattice and retained for itself the unregulated activities of storage, exploration and production.

The market is liberalised with full retail competition and has a number of active independent suppliers. Residential as well as large consumers are able to choose their own gas supplier.

Tariff formulae

With the wide scale privatisation of the utility industries in the UK in the late 1980s and early 1990s, the regulators universally introduced RPI – X tariff regulation. At this time this was an innovative approach that was designed to encourage efficiency and avoid the automatic pass through of costs (or, alternatively, invasive regulation) that was seen to be the problem with traditional rate-base rate of return regulation.

Residential Gas prices/tariffs

For review, we have selected tariffs for Seeboard Energy, British/Scottish Gas and Scottish Power. Interestingly, all have introduced declining block tariffs and most have a fixed charge that is specified per day. The fixed charge varies significantly between different suppliers.

Seeboard energy

Seeboard has two types of charge for domestic consumers. One is based on pre-payment and the other is standard with no pre-payment. The pre-payment tariff has is a declining block. The standard tariff has a similar structure with a declining block, but no fixed charge; the unit charges are also a little higher with the standard tariff.

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Pre-payment tariff

Fixed charge 4.2p/day

0 - 1,143 kWh 2.23 p/kWh

> 1,143 kWh 1.65p/kWh

Standard tariff

Fixed charge None

0 - 1,143 kWh 2.42 p/kWh

> 1,143 kWh 1.52p/kWh

British/Scottish Gas

British and Scottish gas has a very similar pricing structure to Seeboard, albeit with an additional block. It has no fixed charges. Discounts69 are available for consumers who sign-up to the Direct Debit scheme and to those customers who take both gas and electricity from the same supplier.

Fixed charge None

0 - 1,143 kWh 2.96p/kWh

1,143 - 73,268 kWh 1.67p/kWh

> 73,268 kWh 1.64p/kWh

Scottish Power

Scottish Power provides three distinct tariff schedules for household consumers; a tariff with a standing charge, a tariff without a standing charge and a capped price gas tariff:

Standing charge option

Fixed charge 10.49p/day

All units 1.433 p/kWh

No standing charge option

Fixed charge None

0 - 1,143 kWh 2.270p/kWh

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0.66p/kWh on the 1st block, 0.07p/kWh on 2nd block and 0.09p/kWh on the 3rd.

67

> 1,143 kWh 1.433p/kWh

Capped price gas (capped until 2007)

Fixed charge None (note: a standing charge options is also available)

0 - 1,143 kWh 2.664p/kWh

> 1,143 kWh 1.433p/kWh

The tariff option with a standing charge of 10.49p per day, on a monthly direct debit option offers an energy charge rate of 1.433 p/kWh. Without the standing charge, Scottish Power will charge its customers 2.27p/kWh for each quarter for the first 1,143 kWh and 1.433 p/kWh on any energy consumption above that.

The capped tariff category fixes the cost of gas up until 31 March 2007. For the capped option without a standing charge, for example, the tariff is 2.664 p/kWh for the first 1,143 kWh each quarter and 1.433 p/kWh thereafter.

Summary of UK residential tariff structures

The structure of residential gas tariffs in the UK is summarised in Table 1. The tariffs all have declining blocks and most suppliers offer the choice of a fixed charge with lower prices per kWh or no fixed charge (or a reduced fixed charge) and higher prices per kWh.

UK distribution tariffs

Distribution in UK is owned and operated by Transco (now National Grid Transco) and is divided into Local Distribution Zones (LDZs). The structure of the distribution use-of-system tariffs for the LDZs is very similar to that currently in use by BGD in the Republic, with charges dependent primarily on customer size as measured by annual volumes. Transco’s standard charges, starting on 1 April 2004, are shown below.

Transco distribution use-of-system tariffs

Bands

kWh/year

Capacity

(p/peak day kWh per day)

Commodity

(p/kWh)

0 - 73,200 0.0481 0.1284

73,200 - 732,000 0.0446 0.1188

> 732,000 0.2115 x SOQ -0.1806 0.7369 x SOQ-0.2121

Subject to a minimum rate of: 0.0048 0.0112

Minimum reached at SOQ of: 1,181,616,389 kWh 382,022,999 kWh

SOQ = supply point offtake quantity. Schedule valid from 1 April 2004.

The more complex formulae, based on supply point offtake quantity occurs at a slightly higher level (732 MWh) in the Transco tariffs than in the BGD tariff (73 MWh) - but otherwise the structure of the two tariffs are very similar.

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The LDZ networks in UK are, however, larger than BGD’s network. The LDZ’s are a network of pipes including the local transmission system operating generally at pressures up to 38 bar, and the distribution system operating in three pressure tiers: intermediate (2 to 7 bar), medium (75 mbar to 2 bar) and low (below 75 mbar).

Transco offers a slightly lower price to large customers, in the size band above 732,000 kWh who are connected to system exit points. There is also another tariff (LDZ optional tariff) for large loads close to the national transmission system and who might otherwise have an incentive to seek to connect direct to the transmission network.

The capacity charges are based on ex ante offtake quantities rather than ex post metered peak demands. The offtake quantities are adjusted downwards for customers with interruptible loads.

All customers are charged a fixed customer charge in addition to the use-of-system charges shown above. The customer charges are levied in different ways depending on the size of the customer, as shown in the Table below. Customers consuming less than 73,200 kWh per year pay only a commodity charge. Those consuming between 73,200 and 732,000 kWh per year pay a fixed charge in p/day, which is slightly higher for consumers with monthly meter reading, plus a capacity charge based on supply point capacity. Those with consumption above 732,000 kWh per year pay a charge that is based on a formula similar in form to that for the use-of-system tariff.

Transco customer charges

Bands

kWh/year

0 - 73,200 Commodity only: 0.1430p/kWh

Fixed charge (non-monthly)

Fixed charge (monthly)

Capacity (p/peak day kWh per day)

73,200 - 732,000 15.0713p/day 16.0476p/day 0.0017

> 732,000 0.2115 x SOQ -0.1806

0.7369 x SOQ-0.2121

0.0366 x SOQ 0.2100

SOQ = supply point offtake quantity. Schedule valid from 1 April 2004.

Victoria, Australia

The natural gas sector in the state of Victoria in Australia bears a number of similarities to the gas industry in Ireland. The population of Victoria (about 4.7 million) is comparable to Ireland’s. Just as Ireland’s Marathon discovered the Kinsale Head field in the 1970s, enabling natural gas to displace town gas, gas (and oil) fields were discovered offshore in Bass Strait by resources major BHP in the 1960s. These resources were developed via a partnership with the international oil major Esso (Exxon corporation), enabling natural gas to replace town gas. The gas was sold to the State Government-owned Gas & Fuel Corporation (G&FC) under long-term take-or-pay contracts: similar in principle to Marathon’s long-term contracts to the State-owned Bord Gáis in Ireland.

The natural gas transmission and distribution network was developed over the subsequent decades by the G&FC, extending supply beyond the capital city (Melbourne) to include population centres throughout the state. This has some similarities to Bord Gáis’ development of the gas network in Ireland.

Just as output from Ireland’s Kinsale Head field is now declining and the original long-term contracts will expire in 2005, so the Bass Strait gas fields are now coming towards the end of their production life, and the original take-or-pay gas contracts are reaching the end of their terms. Ireland’s gas network

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is now interconnected with the UK via Scotland. Similarly, Victoria’s gas network has recently been interconnected with the neighbouring state of NSW, providing access to wider gas reserves and increasing security of supply.

In the late 1990s the Victorian State Government separated the G&FC into a gas transmission company and three retail and distribution companies, each with one-third of the distribution pipes network and one-third of the customers. The pipes and retail customers were allocated to the companies such that no company owned both the physical connection and the retail account for the same customer. Similarly, each customer had one company providing its connection and another company serving its retail account. The three network and retail gas companies were then sold via three sequential trade sales. Each of the existing electricity retailers were provided with gas retail licenses and, as with electricity, new entrants were allowed to apply for retail licenses. The market was opened up to competition in tranches beginning with the largest customers. The experiences here are dissimilar: apart from the step-wise opening of the gas market to retail competition, Ireland has not opted to separate and divest Bord Gáis Éireann.

Ownership

Victoria’s gas industry is privately owned. Private companies are the only operators at the four stages (production, transmission, distribution and retail). The main players are the BHP Billiton/ESSO consortium at the production stage, GPU Gasnet at the transmission stage, three distributors (TXU Networks, Envestra, and Multinet) and three formerly franchised suppliers (TXU Retail, Origin Energy, and AGL Victoria) plus a handful of independent suppliers.

Structure

The distribution industry was split up in July 1997 into three distribution entities, from the original monopoly operator Gas and Fuel Corporation. These three distribution entities have been privately owned companies since early 1999. Each distributor owns distribution pipelines in its area and control its own gas retailer. The distributors’ areas do not completely overlap with the retailers’ areas.

The gas market has been progressively opened to competition, starting in October 1999 and culminating in households and small businesses becoming able to choose between gas retailers in October 2002. Before market opening, customers had to buy from the franchised retailer in their area (TXU Retail, Origin Energy, or AGL Victoria). By June 2003, 5% of customers had transferred to a new gas retailer.

Regulation

The Essential Services Commission (ESC) is the utility regulator in Victoria. As well as gas, ESC covers electricity, water, ports, grain handling, rail freight and parts of the insurance industry. ESC took over from the Office of the Regulator-General Victoria in January 2002.

ESC sets prices for the gas distribution companies, using a variety of methods including RPI-X incentive-based regulation and compliance with pricing principles. ESC also establishes codes of conduct for operators in order to ensure minimum standards of service. Financial incentives are given to operators to meet performance targets. ESC is responsible for market rules in its regulated industries.

The state of Victoria in Australia has full retail competition in gas supply and, following the opening of the market, residential and small business customers who remained with their existing retailer without signing a new contract were under a ‘deemed’ contract on published prices and terms. Currently, all local gas retailers are required to publish their deemed and standing offers (including tariffs) in the Victoria Government Gazette.

The tariffs of the three gas suppliers in the State of Victoria are explained below. These tariffs apply to standing offer contracts and deemed contracts; some customers negotiate with their supplier, resulting in negotiated contracts with different tariff structures and rates.

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Origin Energy

Origin Energy applies seasonal charging with a peak and an off-peak period: the peak period is 1 June to 30 September inclusive and the off-peak period is 1 October to 31 May inclusive. Prices given include sales tax.

Residential tariffs are shown in the Table below. The Domestic General tariff imposes a supply charge plus a charge per unit of gas used in three blocks (increasing then declining in peak periods; declining in off-peak periods). The Multiple Residential tariff imposes charges for meter/regulator capacity up to 50 m3/hr and over 50 m3/hr, plus a charge per unit of gas used (the same for all quantities). The Residential Bulk Hot Water Master Meter tariff imposes charges for meter/regulator capacity up to 50 m3/hr and over 50 m3/hr, plus a charge per unit of gas used (the same for all quantities). The Bulk Supply to Flats for Water Storage Heating tariff imposes charges for meter/regulator capacity up to 50m3/hr and over 50m3/hr, plus a charge per unit of gas used (the same for all quantities), plus a charge per litre of water used (the same for all quantities).

Origin Energy residential tariffs

Domestic General Peak Off-peak

Supply charge A$19.33 A$19.33

First 4,000 MJ 0.9640 c/MJ 0.9640 c/MJ

Next 8,000 MJ 1.0550 c/MJ 0.9400 c/MJ

Over 12,000 MJ 0.9220 c/MJ 0.8700 c/MJ

Multiple Residential All periods

Capacity up to 50 m3/hr A$34.04

Capacity over 50 m3/hr A$115.60

All gas consumption 1.1510 Ac/MJ

Residential Bulk Hot Water All periods

Capacity up to 50 m3/hr A$34.04

Capacity over 50 m3/hr A$115.60

All gas consumption 1.1510 c/MJ

Bulk Supply to Flats for Water Storage Heating

All periods

Capacity up to 50 m3/hr A$34.04

Capacity over 50 m3/hr A$115.60

All gas consumption 1.2480 c/MJ

All hot water consumption 0.6387 c/litre

Note: A$1.6 = 1 Euro. 3.6 MJ = 1 kWh.

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The Commercial / Industrial tariff imposes charges for meter/regulator capacity up to 100m3/hr and between 100.1 and 850m3/hr, plus a charge per unit of gas used in three declining blocks as shown in the following Table.

Origin Energy commercial/industrial tariffs

Charge Peak Off-peak

Capacity up to 100 m3/hr A$26.14 A$26.14

Capacity between 100.1 and 850 m3/hr A$54.92 A$54.92

First 12,000 MJ 0.9170 c/MJ 0.8710 c/MJ

Next 74,000 MJ 0.9170 c/MJ 0.8710 c/MJ

Over 86,000 MJ 0.6690 c/MJ 0.6360 c/MJ

Note: A$1.6 = 1 Euro. 3.6 MJ = 1 kWh.

AGL Victoria and TXU Retail

The tariffs for AGL Victoria and TXU Retail are set in similar categories to those of Origin Energy. The block and fixed charge structure is also similar, with the exception of AGL Victoria where the Domestic General tariff is in two blocks (up to 3,500Mj and over 3,500MJ) rather than three. The tariffs are similar to those of Origin Energy.

TXU Distribution Tariffs

TXU has three distribution use-of-system tariff categories: V, D and M.

Tariff V is for users who use less than 10,000 GJ/year or with a maximum demand of 10 GJ per hour. Tariff V is further divided into residential and non-residential users. Tariff D is for users who exceed the volume or demand limits for Tariff V. Tariff M is for customers who choose the Tariff V category but then exceed the volume or demand limits. The tariffs are differentiated by area (central and west).

The schedule for Tariff V users in the central area are shown below. These have a fixed charge and a declining block variable charge per GJ. There is also some seasonal variation in the charges. Non-domestic users pay a lower tariff.

TXU distribution tariffs small users (central area)

Domestic

Fixed charge (A$/day) 0.0771

Peak charge (A$/GJ) Off-peak charge (A$/GJ)

0 - 0.1 GJ/day 5.9196 4.8636

>0.1 - 0.2 GJ/day 4.1991 3.1427

>0.2 - 1.4 GJ/day 2.5933 1.9045

>1.4 GJ/day 0.9712 0.7142

72

Non-domestic

Fixed charge (A$/day) 0.0771

Peak charge (A$/GJ) Off-peak charge (A$/GJ)

0 – 0.1 GJ/day 5.4972 5.2860

>0.1 - 0.2 GJ/day 3.7765 3.5652

>0.2 - 1.4 GJ/day 2.3178 2.1800

>1.4 GJ/day 0.8684 0.8170

Valid from 1 January 2004 A$1.6 = 1 Euro. 1 GJ = 1,000 MJ. 3.6 MJ = 1 kWh.

The tariff for large customers in Tariff D is shown below. Tariff D customers must have daily metering and agree to pay a demand charge of a minimum of 1.15 GJ/hour. This tariff has no fixed charge and has only a capacity charge with three declining blocks (no commodity charge).

TXU distribution tariffs, large users

Annual maximum demand (maximum GJ/hour)

A$/(maximum GJ/hour)

0 - 10 889.14

>10 - 50 606.89

>50 321.35

Valid from 1 January 2004 A$1.6 = 1 Euro. 1 GJ = 1,000 MJ. 3.6 MJ = 1 kWh.

The other distribution companies in Victoria have broadly similar distribution tariff structures though some have tariffs that differentiate three seasons (instead of two by TXU) while others do not (yet) have Tariff M.

Victoria Summary

The three suppliers in Victoria have similar tariffs. All residential tariff categories have fixed charges but there is a mixture of increasing and declining blocks. The general domestic tariff, for example, has a declining block during the off-peak and an increasing block, followed by declining block, in the peak season. The other categories of residential consumer have a constant commodity charge that does not vary with season or consumption, but they also face capacity charges based on regulator capacity at the meter. Commercial and residential consumers have capacity charges but no fixed charges and a declining block commodity charge.

The distribution tariffs are interesting. These have seasonal components and, for large daily metered customers, a demand-only charge.

United States

The parallels between the gas industry in the United States and in Ireland are not so striking. Nevertheless, the United States is the largest gas market in the world and some selected examples from

73

the US are included below. Historically, gas in the US has been provided by investor-owned utilities: local private monopolies regulated at the state level. As is the case for the energy utilities sectors generally, the US is moving to a gas market model involving retail competition and regulation of the pipes business.

Ownership

The US has a long history of regulated investor-owned utility service providers. A number of states are now moving away from the vertically integrated model and separating the distinct business units in the gas industry. As well as creating the separate network businesses, a key aspect of these reforms has been to encourage the marketing aspect of business at the retail level.

Structure

There are more than 150 (transmission) pipeline companies in the United States and over 1,200 natural gas distribution companies, with ownership of over 833,000 miles of distribution pipe. While many of these companies maintain monopoly status over their distribution region, many states are currently in the process of offering consumer choice options with respect to their natural gas distribution.

There are about 114 natural gas storage operators in the United States, with control over 415 underground storage facilities. These facilities have a storage capacity of 3,923 Bcf of natural gas, and an average daily deliverability of 78 Bcf per day.

With advent of open access both in inter- and intra-state pipelines, a number of marketing companies also exist in the US.

Regulation

Today, only pipelines and local distribution companies (LDCs) are price regulated while the prices at the wellhead and prices for supply are left to the market.

FERC has jurisdiction over inter-state infrastructure (electricity and natural gas transmission networks and oil pipelines) while the state-level Public Utility Commissions (PUCs) have jurisdiction over gas companies within their own state. The PUCs are almost universally multi-utility regulators that have responsibilities for a number of privately owned activities including transport, mail, telecommunications and in California, hot air balloons.

The regulatory regime in the US is based on a quasi-judicial legal system that, arguably, has discouraged innovation in the practice of regulation though not in theoretical innovation. For example, though the price cap regime became well known internationally through the RPI-X+Y regime introduced in the UK in the late 1980s, the concept had been discussed widely in the US for a number of years before this. The tariff regime in the US has, for many years, standardised toward the rate-base rate of return approach with some attempts at incentive regulation largely through disallowance of some costs.

We have selected two gas suppliers (from approximately 1,200 distributors) in the US for comparison.

Socalgas - Residential supply tariffs

Socalgas is the Southern California Gas Company. In the residential sector the tariff classes are:

• Individually metered

• Sub-metered (multi-family dwelling units and mobile home parks supplied through one meter and sub-metered to individual units)

• Small master metered (large multi-dwelling units, residential hotels and communal facilities such as swimming pools)

• Large master metered (customers who have averaged at least 100,000 therms of weather-normalised usage for the previous two calendar years.

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The residential tariff has an increasing block structure with no fixed charges. There is no significant difference in the tariff rates applied to the first three of the above classes but the tariff is substantially lower for the final class (Large Master metered).

Socalgas residential tariffs

Consumer category Blocks70 Price USc/therm

Baseline (<14 therms per month in summer and <51 therms per month in winter)

75.3 Residential Individually Metered, Residential Sub-Metered and Residential Small Master Metered

Non Base-line 93.6

Baseline (as above) 68.1 Residential Large Master Metered

Non Base-line 76.0

Note: 1 therm = 29.3071 kWh. 1.2 USc = 1 Euro c.

Pacific Gas and Electric Company (PGE)

PGE has a very similar tariff schedule to Socalgas with the following customer categories:

• Residential

• Small commercial

• Large commercial

• Compressed Natural Gas (CNG)

• Gas transportation charge for large users

In the residential classes, multi-family discounts are available as well as lower rates for low-income families. The residential rate schedules for PGE is an increasing block tariff, with no fixed charge. Non-residential customers face fixed customer charges and seasonal differentiation in tariffs.

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The blocks are defined in terms of therms per day. 14.4 therms = 420 kWh. 51.4 therms = 1,500 kWh.

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PGE gas supply tariffs Block

Residential USc/therm

Baseline (21 therms per month in summer and 73 therms per month in winter)71

71.6

Excess 92.7

Small commercial Fixed charge (USc/day)72 Summer/Winter

Summer (USc/therm)

Winter (USc/therm)

Baseline (< 4,000 therms/month)

34.3/34.8 66.3 72.4

Excess 43.9/44.4 57.7 61.8

Large commercial Fixed charge (USc/day) Summer/Winter

Summer (USc/therm)

Winter (USc/therm)

Baseline (< 4,000 therms/month)

4.96 64.0 70.1

Excess 55.4 59.4

Note: 1 therm = 29.3071 kWh. 1.2 USc = 1 Euro c.

US Summary

The US tariff structures are diverse. Socalgas and PGE both have increasing block structures. Neither have fixed charges for residential customers. PGE has seasonal charges for all customers but Socalgas does not. Neither have demand charges for the customer classes described above.

Denmark

Denmark sources its gas almost entirely from its offshore gas fields. The Danish state oil and gas company (DONG) continues to dominate the Danish gas market. It has taken over two of the five regional distribution companies completely and continues to have restrictive agreements with two others. The remaining company Naturgas Fyn has a joint venture with Statoil of Norway.

Unbundling has taken place in all companies. The market is 100% open and 17% of large industrial users have switched supplier. There are eight active licensed suppliers. DONG has 93% of the market.

The Danish Energy Regulatory Authority monitors prices and conditions for gas distribution.

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These are actually defined as therms per day. Note, 21 therms = 620 kWh and 73 therms = 2,140 kWh.

72 The fixed charge differs in summer and winter. Curiously, the fixed charge itself has a step increase to the higher of the

numbers if daily consumption is above 40 therms in summer and 145 therms in winter.

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Distribution Tariffs

Denmark (Danish Oil & Natural Gas - DONG) has adopted a postalised system for distribution tariffs - the same price irrespective of location. The tariffs are differentiated solely on the basis of customer size. The distribution commodity charges for the year commencing 1 October 2003 are shown in the Table below. DONG temporarily simplified these tariffs in the year 2003-04 by phasing out capacity charges expressed as DKK/kWh/hour/year, and permanently eliminating fixed customer charges (DKK/year). In the year starting 1 October 2003 the tariff continued to include a pressure related fee of øre0.1818/kWh for customers with burnertip pressures above 4 Bar. It appeared to have dropped charges for customers with burnertip pressures in the two ranges 1-4 Bar and below 1 Bar.

However, from 1 October 2004 DONG expects to reintroduce a capacity charge. The charge was temporarily eliminated in 2003-04 because it was felt that it gave an advantage to larger established gas suppliers (the market was fully opened on 1 January 2004) who are able to use customer diversity (pooling) to reduce their demand charges73. The elimination of the demand charges meant that no supplier can benefit from diversity (pooling) benefits. DONG intends that the capacity charge will be reintroduced in the two years 2004-05 and 2005-06 and that it will eventually be between 200 and 300 DKK per maximum m3 per hour, from October 1st 2005.

DONG distribution tariffs

Size band (per year) øre/kWh

0 - 66,000 kWh 8.6364

66,000 - 220,000 kWh 8.6364

220,000 - 825,000 kWh 8.0909

825,000 kWh - 1,650 MWh 4.6364

1,650 - 3,300 MWh 2.5909

3,300 - 110,000 MWh 1.9545

110,000 - 385,000 MWh 1.5273

> 385,000 MWh 1.4364

Note: there are approximately 7.5 øre to one Euro c. 1 MWh = 1,000 kWh.

The other two network companies - HNG and Naturgas Midt-Nord - have similar distribution tariffs.

France

The French state oil and gas company (Gaz de France) continues to dominate the gas market. Unbundling has taken place at the accounting level. 37% of the market is open to competition and 20%

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It is not completely clear how the market is arranged in Denmark such that suppliers can benefit, in relation to distribution charges, from pooling. Diversity (pooling) will only benefit suppliers that are geographically concentrated and that somehow take over some distribution functions. Payments by suppliers for distribution transport services for the suppliers’ customers should be based on peak capacity required by individual customers - rather than the peak capacity required by those customers as a group. Diversity should be reflected in the tariff (ie., lower tariffs) rather than in the suppliers’ aggregate peak demand estimates.

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of large industrial customers have switched suppliers. There are around 24 gas distribution companies. The Commission de Régulation de L’Éenergie (CRE) is responsible for setting tariffs.

Distribution Tariffs

The section below summarises distribution tariffs for customers of:

• Gaz de France

• Gaz de Bordeaux

• Gaz de Strasbourg

There are four tariff classes for the standard network distribution tariffs, T1, T2, T3 and T4. These tariff classes differ in the combination of fixed charge and energy charge applicable. T4 is slightly different in that it also has a capacity charge in addition to fixed charge and commodity charges.

A fifth type of tariff is the ‘distance-related’ tariff – TP. TP has a fixed charge, a capacity charge and a distance charge in € per metre (irrespective of the volumes) in a straight line from the point of delivery to the nearest transmission grid connection point. Moreover the distance related charge is subject to multiplication by a coefficient depending on the density of the population in the distribution area as follows:

• Coefficient of 1 if there is less than 400 inhabitants per km2

• Coefficient of 1.75 if there is more than 400 inhabitants per km2 but less than 4000 inhabitants per km2

• Coefficient of 3 if there is greater than 4000 inhabitants per km2

Gaz de France

Standard tariff

Fixed charge (€/year) Annual capacity charge (€/Max. MWh/day)

Commodity charge (€/MWh)

T1 30 21.43

T2 120 6.32

T3 690 4.42

T4 14, 115 180 0.62

Distance-related tariff

Fixed charge (€/year) Annual capacity charge (€/Max. MWh/day)

Distance charge €/metre

TP 32,400 90 60

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Gaz de Bordeaux

The tariff structure for Gaz de Bordeaux is similar to that of Gaz de France but the tariffs differ.

Standard tariff

Fixed charge (€/year) Annual capacity charge (€/Max. MWh/day)

Commodity charge (€/MWh)

T1 45 34.55

T2 207 7.40

T3 729 5.66

T4 15,930 270 0.92

Distance-related tariff

Fixed charge (€/year) Annual capacity charge (€/Max. MWh/day)

Distance charge €/metre

TP 32,000 70 60

The tariff for other distributors (Gaz de Strasbourg, Régie Municipale de Colmar, Gaz Elictricité de Grenoble, Regié Municipale de Dreux, etc) all follow the same structure though the tariffs for each are different.

Canada - British Columbia (Terasen Gas)

Though relatively small by international standards, Terasen Gas is Canada’s third largest gas utility; it provides gas to over 860,000 customers in British Columbia. British Columbia has wholesale competition and will be allow competition for small commercial customers from November 2004.

Terasen Gas has a large number of end-use tariff classes including:

• residential

• small commercial

• large commercial

• seasonal

• general firm

• natural gas vehicle

• general interruptible

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For each of these end-use categories there is an additional transportation (transmission and distribution) charge.

We note that the Terasen Gas’s residential tariff has a fixed monthly charge plus a simple charge per GJ that is built up, as in the US, from ‘commodity related charges’ plus a ‘delivery margin’ equal to a transportation charge. However, here we focus on the ‘general firm’ and ‘general interruptible tariffs’.

The General Firm Service) is for large volume customers with annual consumption of 5,000 GJ or more. These customers are ‘eligible’ in the European sense but Terasen offers them a bundled rate comprising commodity and transportation combined. The rate structure includes a fixed monthly charge, a monthly demand charge based on peak demand volume, and variable charges per GJ of gas consumed. This peak demand volume is set once a year and is based on a maximum hourly quantity set out in the annual contract. It is calculated from actual consumption in the previous year as 1.25 times the higher of:

• the customer’s highest daily consumption in any month during the winter months, or,

• a half of the customer’s highest daily consumption in any summer month.

Terasen Gas is not obliged to provide more gas than the contracted peak demand volume (though may do so without, apparently, penalties to the customer). The rate schedule is shown below.

Terasen Gas Tariffs for Large Users

General Firm Service (Bundled Charges)

Fixed charge (C$/month) 532

Demand charge (C$/max. GJ/day per month) 13.312

Delivery charge (C$/GJ) (transmission/distribution) 0.539

Gas cost recovery charge (C$/GJ) (gas commodity cost) 6.751

General Interruptible Service

Fixed charge (C$/month) 799

Delivery charge (C$/GJ) (transportation) 0.899

Commodity charge - fixed price option (C$/GJ) 6.751

Charge for unauthorised overrun gas - first 5% overrun Daily spot price of gas

Charge for unauthorised overrun gas - above 5% overrun The greater of 1.5 x daily spot price or C$20/GJ.

Notes: There is some variation in the gas recovery cost in three different areas. There are 1.61 C$ per Euro. A GJ is 1,000 MJ and there are 3.6 MJ per kWh.

Terasen offers a published tariff called the General Interruptible Tariff. The tariff is described as a bundled service as it combines transportation and commodity charges (as for the other tariffs). There is no size criteria for this tariff. The tariff, shown in the above Table, avoids a demand charge but, instead, allows Terasen Gas to interrupt the customer whenever it reasonably considers that it does not have the capacity to provide gas. There is an alternative to the fixed price option in which Terasen passes the cost of the gas in full to the customer through the Commodity charge in the above schedule - Terasen then covers its costs through the other charges in the schedule.

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Appendix 4: Summary of Issues The following Appendix lists all the issues highlighted throughout the paper. The Commission invites comment on each of these issues. Please refer to the issue number when providing feedback.

Issue #

Issue Description Location

(page #)

1

Issue No. 1 – Core Principles

The Commission invites comment in relation to the Core Principles mentioned above.

Section 2

p. 10

2

Issue No. 2 – Marginal Cost Pricing

The Commission invites comments on the adoption of the Marginal Cost approach to tariff development.

Section 3

p. 12

3

Issue No. 3 – Connection or Statistical Approach

The Commission invites comment on the connection approach versus the statistical approach for the charging of distribution tariffs to customers at the border between the distribution and transmission systems and the impact of each on the distribution tariff.

Section 5.3.1

p. 27

4

Issue No. 4 – Commission’s Proposal on uniform distribution tariff pricing

The Commission invites comment on its proposal to set distribution tariffs on a uniform pricing basis.

Section 5.4.3

p. 32

5

Issue No. 5 – Capacity/commodity split

The Commission invites comment on the capacity/commodity split used in the current Distribution Tariff structure.

Section 5.4.4

p. 33

6

Issue No. 6 – Customer Differentiation

The Commission invites comments on the options for customer differentiation on the distribution system.

Section 5.4.4

p. 34

7

Issue No. 7 – Fixed Charges

The Commission will consider the possible introduction of a fixed customer related charge for distribution. Comments are invited upon this.

Section 5.4.7

p. 35

8

Issue No. 8 Distribution Capacity Charges

The Commission invites comment on whether distribution capacity charges should be based on forecasts derived from historical meter readings or on actual meter readings.

Section 5.4.7

p. 35

9

Issue No. 9 – Distribution Competition

The Commission invites comment on the options for distribution tariff structures in the presence of distribution competition.

Section 5.4.8

p. 36

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10

Issue No. 10 – Tariff Anomalies and Issues

The Commission invites comment on the apparent anomalies within and between the different tariffs and other franchise tariff issues.

Section 6.2.2

p. 43

11

Issue No. 11 – Market Reflective Tariffs

The Commission invites comment on its proposal that gas tariffs should reflect market prices for gas.

Section 6.2.2

p. 45

12

Issue No. 12 – The WACOG benefit

The Commission invites comment on the manner in which the WACOG benefit is dealt with.

Section 6.2.2

p. 45

13

Issue No. 13 – Impact of Swing

The Commission welcomes comments on the impact of swing on gas tariff structures.

Section 6.2.3

p. 48

14

Issue No. 14 – Tariff Categories

The Commission invites comments on the nature of any changes that might be required to gas tariff categories.

Section 6.2.3

p. 48

15

Issue No. 15 – Fixed Charges

The Commission invites comments in relation to the fixed customer-related components of gas tariff structures.

Section 6.2.3

p. 49

16

Issue No. 16 – Threshold for Demand metering

The Commission invites comments in relation to the level of volume/type of customer for which demand metering should be implemented in the market.

Section 6.2.3

p. 49

17

Issue No. 17 – Supply Tariffs – Increasing/Declining Blocks

The Commission invites comments regarding the block component of current gas tariff structures and views on possible alternatives.

Section 6.2.3

p. 50

18

Issue No. 18 – The Regulated Tariff Formula

The Commission invites comment as to the appropriateness of the RTF and whether there are any alternatives that could be used to replace it.

Section 6.3.1

p. 51

19

Issue No. 19 – Border between Franchise Tariffs and RTF

The Commission invites comments on the discontinuity between current D&C2 franchise tariff and the RTF.

Section 6.3.1

p. 51

20

Issue No. 20 –RTF thresholds

The Commission invites comments on the current positioning of the RTF in the eligible market.

Section 6.3.1

p. 52

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21

Issue No. 21 – Capacity Charges for RTF customers

The Commission invites comments on the nature of capacity charging for RTF customers.

Section 6.3.1

p. 53

22

Issue No. 22 – Swing Charges for RTF customers

The Commission invites comments on the calculation of swing in the RTF.

Section 6.3.1

p. 53

23

Issue No. 23 – Terms and conditions of the RTF

The Commission proposes that the RTF Direction be reissued in a more comprehensive form, so the RTF will apply to all appropriate aspects of gas supply. Comments are welcomed on the aspects of gas supply that should be regulated under the RTF, and the manner in which they should be regulated.

Section 6.3.1

p. 53

24

Issue No. 24 – Default RTF

The Commission proposes that the default contract be an open-ended variable contract, with an option for termination upon one months notice.

Section 6.3.1

p. 54

25

Issue No. 25 – BGS’ Revenue Control

With regard to BGS’ own operating costs, the Commission’s initial proposal is to introduce a revenue control formulae broadly similar to that adopted for PES in the electricity sector.

Section 7.4

p. 57

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Appendix 5: Glossary of Terms

BGÉ Bord Gáis Éireann

BGD BGÉ Distribution (the business unit of BGÉ responsible for distributing gas through medium and low pressure pipes)

BGS Bord Gáis Energy Supply (the business unit of BGÉ responsible for supplying gas to customers)

CAPEX Capital expenditure

Coincidence Factor This term describes the relationship between peak demand for a consumer group and demand at time of system peak.

Commodity Charges Charges calculated per unit of gas used.

Cost Allocation Methodologies Methods of allocating costs among customers or groups of customers.

Daily load metering Metering of a customer’s gas consumption on a daily basis.

DCMNR Department of Communications, Marine and Natural Resources

Deep Connections Connection charges requiring connecting consumers to pay for the full costs their connection imposes on the network.

Demand Charges Charges that reflect the cost of consuming gas at times of system peak.

Diversity Factor The ratio of the peak demand for a customer group to the sum of the individual peak demands of the group members.

DUoS Charges Distribution Use of System charges, i.e., the tariffs paid for use of a distribution network

Eligibility threshold The threshold, measured in annual consumption of gas, at which a gas consumer becomes eligible to choose its gas supplier.

Fixed Customer Related Charges Fixed charges are those that are paid monthly, bi-monthly, quarterly or annually, irrespective of a consumer’s gas consumption or peak demand.

Franchise market The franchise market consists of all customers who are not eligible to change supplier and are therefore supplied by BGÉ. Also referred to as the ‘non-eligible’

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or ‘non-competitive’ market.

Gas (Interim) (Regulation) Act, 2002

The Gas (Interim) (Regulation) Act, 2002, established the Commission for Electricity Regulation as the Irish natural gas regulator under the name of the Commission for Energy Regulation. It gave the CER the necessary powers to license and regulate the transmission, distribution, storage and supply of natural gas and issue Orders in relation to the supply, transmission, distribution and sale of gas.

This Act also marked the second phase of the opening of the Irish gas market so that customers whose annual consumption exceeded 2 mscm of natural gas were eligible to obtain a natural gas supply from a licensed Shipper/Supplier other than BGÉ.

The Gas (Interim) (Regulation) Act, 2002, amends two previous Gas Acts, the 1976 Gas Act and the Gas (Amendment) Act, 1987.

GWh Gigawatt hour. A measurement of energy equivalent to 1,000,000 kWh.

I/C customers Industrial and Commercial customers

Interruptible tariffs Tariffs that are based on an interruptible supply of gas.

kWh Kilowatt hour. A measurement of energy.

LDZ Local Distribution Zone. Distribution in UK is owned and operated by Transco (now National Grid Transco) and is divided into Local Distribution Zones.

mcm Million cubic metres – a measure of a quantity of gas.

MWh Megawatt hour. A measurement of energy equivalent to 1,000 kWh.

Natural Monopoly A natural monopoly refers to a situation where a single company tends to become the only supplier of a product or service over time because the nature of that product or service makes a single supplier more efficient than multiple, competing ones. For example, it is inefficient, to have several pipelines going in the same direction. It is more efficient to build and operate a single (larger diameter) pipeline.

OPEX Operating expenditure

Overrun gas Overrun charges are charged under the transportation arrangements and are incurred when a consumer uses more gas in a day than capacity it has booked.

Peak Day Value Value of maximum daily quantity of gas consumed during a 12 month period.

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Postage-stamp charge See ‘postalised method’ below.

Postalised method The method of charging gas consumers a use of system tariff that is not based on location, i.e. where a consumer is connected to the gas network.

Regulated Tariff Formula (“RTF”) The RTF is a regulated tariff offered by BGS to a certain sector of the eligible market. The regulated nature of the RTF allows BGS, the supplier to the franchise market, to also operate in the eligible market. It applies to eligible customers who consume between 5.3 and 264 GWh per annum (181,000 and 9m therms) and are not supplied by an independent (i.e., non-BGS) Supplier.

Renewals Investments The replacement of assets at the end of their economic lives, or for safety reasons, e.g., replacing old cast iron pipes.

RPI – X tariff regulation. A form of price regulation used for public utilities. RPI refers to retail price index (a cost inflation adjustment) and X refers to an adjustment factor (to promote cost efficiencies).

Seasonal charges Charges that vary depending on what season gas is consumed.

Shallow Connections Connection charges requiring connecting consumers to pay for only the direct costs of connecting to the network (and not any reinforcements).

Shrinkage The loss, whether real or due to metering errors or fraud, of gas between entry to a pipeline network and flow through customers’ meters.

Statistical Approach This refers to an approach adopted in the development of the 2002/3 distribution tariff. Under this approach all customers below a certain consumption threshold (annual volume of <5m therms or 146,535MWh) pay a distribution tariff regardless of whether they were connected to the distribution or transmission system.

Supply Control Revenue Formula A supply control revenue formula is used to determine the revenue that can be recovered by a supply business. It is applied as a way of incentivising the management to reduce those costs that are under its control.

Swing Swing describes the relationship between consumption on the day of maximum demand and the average daily consumption over the year.

Therm

An imperial unit of energy. Largely replaced by the metric equivalent: the kilowatt hour (kWh). One therm equals 29.3071 kWh.

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Unbundling This term generally refers to the separation of vertically integrated activities (e.g. transmission, distribution and supply), of a utility firm.

Up-stream Producers Producers of natural gas from (up-stream) gas fields.

UoS Charges Use of System charges, i.e., the tariffs paid for use of a network

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