cost-benefit analysis (cba) for a national gas …gas smart metering cost-benefit analysis...

Gas Smart Metering Cost-Benefit Analysis CER/11/180c

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Cost-Benefit Analysis (CBA) for a National Gas Smart

Metering Rollout in Ireland

DOCUMENT TYPE:

Information Paper

REFERENCE:

CER11180c

DATE PUBLISHED:

11th October 2011

The Commission for Energy Regulation, The Exchange, Belgard Square North, Tallaght, Dublin 24. www.cer.ie


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CER – Information Page Abstract: This cost-benefit analysis (CBA) delivers the findings of a robust economic assessment of the long-term costs and benefits to the market and the individual consumer (residential and small businesses) of a national gas smart metering rollout in Ireland.

Target Audience: This paper is for the attention of members of the public, the energy industry, energy consumers and all interested parties. For further information on this Information Paper, please contact Gary Martin ([email protected]) at the CER. Related Documents: Smart Metering Information Paper 5 – CER/11/180 – 11 Oct 2011

- Gas Smart Metering Customer Behaviour Trial (CBT) Findings Report – CER/11/180a – 11th October 2011

- Dual Fuel Smart Metering Technology Trial Findings Report – CER/11/180b – 11th October 2011

Smart Metering Information Paper 4 – CER/11/080 – 16 May 2011 - Electricity Smart Metering Customer Behaviour Trials (CBT) Findings

Report – CER/11/080a – 16th May 2011 - Electricity Smart Metering Technology Trial Findings Report –

CER/11/080b – 16th May 2011 - Electricity Smart Metering Cost-Benefit Analysis (CBA) Report –

CER/11/080c – 16th May 2011 Smart Metering Consultation Papers and Responses:

- Responses to Consultation Paper 2 – CER/11/033 – 18th February 2011 - Consultation Paper 2 – CER/10/197 – 11th November 2010 - Responses to Consultation Paper 1 CER/10/161 – 9th September 2010 - Consultation Paper 1 – CER/10/082 – 11th June 2010


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Executive Summary

i. Introduction The CER has worked with industry stakeholders to produce a detailed cost-benefit analysis (CBA) on a number of options for the national rollout of smart meters in the Irish gas market. This follows on from the electricity smart metering CBA published by the CER in May 2011 (CER/11/080c). A fundamental assumption of the gas CBA is that a national gas smart metering rollout leverages the infrastructure that would be put in place for electricity smart metering, hence only costs incremental to those already included in the electricity CBA are included in the gas CBA. The gas CBA delivers a robust economic assessment of the long-term costs and benefits to the market and the individual consumer (i.e. all gas customers in the G4 meter category, which includes all residential customers and some non-residential customers, mainly small businesses) of a national gas smart metering rollout. The analysis indicates that the rollout of smart metering has the potential to provide a positive net benefit to the Irish gas market and consumers. The publication of this report is a major milestone in the CER’s Smart Metering Project, and a key deliverable in the completion of Phase 1, which focused on delivering electricity and gas smart metering trials and cost-benefit analyses. The findings from the CBA will provide a rich source of information which will be used to inform energy policy decisions in Ireland relating to smart metering enabled initiatives such as more detailed and frequent billing, in-home displays, innovative tariffs and prepayment metering.


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ii. Background to the CBA Smart meters are the next generation of meters, which can replace existing electro-mechanical and diaphragm meters and offer a range of benefits for both the individual electricity and gas consumer and for the electricity and gas systems in general. The implementation of a smart metering system encompasses more than just metering. It is essentially a hybrid technology consisting of three high level layers; physical meters and associated devices, communications layer covering data transport and communications network management, IT systems which manage the data, applications, and services. At the core of a smart metering system is a more sophisticated digital metering unit. It records customers’ actual use of electricity/gas over short intervals (e.g. every 30 minutes). These meters are connected by a communications system to the network company / meter data collector providing the operator with automated, up-to-date information on the amounts of electricity/gas used by customers. From a technical perspective, access to this information provides opportunities to reduce network operation costs, including reduced costs of visiting customer premises to manually read the meter and carrying out any necessary connections and disconnections. There are also savings due to reductions in technical losses and theft. The data collected from smart meters can also be used by electricity and gas suppliers, subject to data protection requirements, to deliver useful information to their customers regarding their electricity and gas consumption and costs. In particular, the installation of smart metering will allow electricity suppliers to create innovative pricing arrangements that can be offered to customers to support the efficient use of electricity, such as time-of-use electricity tariffs. This is where the price of electricity varies at different times of the day to reflect the changes in the costs of producing electricity. This will allow customers to manage their consumption of electricity in line with price movements and demand patterns. Smart meters can facilitate improving energy efficiency by empowering consumers with more detailed, accurate, and timely information regarding their energy consumption and costs, thus helping consumers reduce any unnecessary energy usage and shift any discretionary electricity usage away from peak consumption times. The benefits of smart metering are recognised internationally and there are a number of key EU legislative instruments promoting smart metering to ensure that customers are properly informed of actual energy consumption and costs frequently enough to enable them to regulate their energy consumption. In particular the 3rd Package requires that Member States shall ensure the implementation of intelligent metering systems that shall assist the active participation of consumers in the electricity and gas supply markets. The


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implementation of those metering systems may be subject to an economic assessment of all the long-term costs and benefits to the market and the individual consumer or which form of intelligent metering is economically reasonable and cost-effective and which timeframe is feasible for their distribution. While much work is underway at a European level in the development of technical standards and guidelines of good practice, the status of smart metering for electricity and gas in Europe is still diverse and changing at a rapid pace. In March 2007 the Commission for Energy Regulation (CER) issued a Demand Side Management and Smart Metering Consultation Paper (CER/07/038)1 in which the case for providing domestic and small business customers with time of use (ToU) electricity prices and smart metering arrangements was made. This was followed in November 2007 with the publication by the CER of an information paper, Smart Metering - The Next Step in Implementation (CER/07/198)2, which outlined a proposed framework in which the future scope of smart metering arrangements can be established. Following on from the conclusions reached in the smart metering information paper CER/07/198 the CER established the Smart Metering Project Phase 1 in late 2007 with the objective of setting up and running smart metering trials and assessing their costs and benefits, which will inform decisions relating to the full rollout of an optimally designed universal National Smart Metering Plan. In order to draw on the experience and expertise of the electricity and gas market a Steering Group and a Working Group was established by the CER for the Smart Metering Project Phase 1. Both groups are chaired by the CER and consist of representatives from the Department of Communications, Energy and Natural Resources (DCENR), Sustainable Energy Authority of Ireland (SEAI), the Northern Ireland Authority for Utility Regulation (NIAUR) and Irish Gas and Electricity Industry Participants. The Economic and Social Research Institute (ESRI) was engaged by the CER to partner delivery of the electricity cost-benefit analysis and to peer review the gas cost-benefit analysis. Frontier Economics was engaged to work with the CER to deliver the gas cost-benefit analysis. This gas CBA is another key deliverable of Phase 1 of the CER Smart Metering Project. It draws information from the following key Phase 1 deliverables which are published alongside it:

Gas Customer Behaviour Trials (CBT) Findings Report (CER/11/180a) The gas customer behaviour trial is among the largest and most statistically robust smart metering behavioural trials conducted

1 www.cer.ie/en/electricity-retail-market-current-consultations.aspx?article=01b6318d-3876-4630-8bb5-f54fb368be16 2 www.cer.ie/en/electricity-retail-market-current-consultations.aspx?article=01b6318d-3876-4630-8bb5-f54fb368be16


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internationally to date and thus provides a wealth of insightful information on the impact of smart metering enabled initiatives on gas consumers. The gas CBT looked at the measureable reduction in customer demand achievable through the use of smart meters in combination with a number of information stimuli (i.e. detailed billing on a bi-monthly and monthly frequency, in-home displays) and a variable tariff.

Dual Fuel Technology Trial Findings Report (CER/11/180b) The dual fuel technology trial examined the general concept of gas smart metering leveraging the electricity smart metering communications infrastructure. This trial enabled Bord Gáis Networks and ESB Networks to attain a better understanding of the requirements and risks that would be associated with a dual fuel (i.e. electricity and gas) national smart metering rollout.

Figure 1: Smart Metering Project Phase 1 – Participants and Deliverables

Customer Behaviour Trials Findings Reports

Electricity: CER/11/080a

Gas: CER/11/180a

Technology Trials Findings Reports

Electricity: CER/11/080b

Dual Fuel : CER/11/180b

Cost-Benefit Analyses Reports

Electricity: CER/11/080c

Gas : CER/11/180c


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These reports on gas smart metering follow similar reports on electricity smart metering which were published by the CER in May 2011 (CER/11/080). The electricity smart metering customer behaviour trial and cost-benefit analysis findings were positive, indicating that consumers respond positively to smart metering related demand side management (DSM) measures and that a strongly positive net benefit for Irish electricity market and consumers is likely to be achieved from proceeding with a national electricity smart metering rollout. This combined suite of electricity and gas smart metering findings reports, the publication of which mark the culmination of the ‘exploratory’ Phase 1 of the Smart Metering Project, is intended to inform the Commission for Energy Regulation (CER), the Department of Communications, Energy and Natural Resources (DCENR), and stakeholders of the possible merits of providing smart electricity and gas meters to residential and SME customers in Ireland. In addition, the CBAs should help cast light on the relative attractiveness of various design options for implementation of smart metering and the main sources of risk associated with a national rollout.


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iii. Approach to the Gas CBA For the purposes of compiling the gas CBA, Bord Gáis Networks, ESB Networks and gas suppliers currently active in the Irish market were requested by the CER to provide smart metering related costs and benefits in accordance with the national smart metering high level design and implementation assumptions, which had been developed by the CER via the Smart Metering Project industry forums and a public consultation process. The CER reviewed and validated the submitted costs and benefits, including a review by a contracted independent third party, Frontier Economics. Some sources of costs and benefits are more amenable to quantification than others, so the analysis is divided between “quantifiable” and “qualitative” sources of costs and benefits. To place some structure on the analysis of the quantifiable elements, costs and benefits are also divided into rough categories by source: networks, suppliers/shippers, and consumers. The validated network and supplier related costs and benefits were then inputted into a CBA model developed by Frontier Economics and peer reviewed by the ESRI. Results from the gas customer behaviour trial (CER/11/180a) were also inputted into this CBA model in order to derive the usage-related benefits and some of the network-related benefits. The cost-benefit analysis assesses the broad societal costs and benefits of implementing smart metering rather than the private costs and benefits to any given subset of affected parties. The Gas CBT Findings Report (CER/11/180a) does illustrate some distributional effects arising from a move to smart metering related initiatives for gas. There may also be distributional effects along the value chain, for example transfers of welfare between suppliers and customers, but to economise on the time required for this analysis such effects have not been modelled. The CER identified 8 high level smart metering national rollout options. The overall attractiveness of each option is identified for the quantifiable costs and benefits by computing the net present value (NPV) of the project in 2011, taking into account predicted cash flows from 2011-2032. The gas CBA analysis varies according to the different meter deployment and energy savings scenario assumptions, and the underlying counter-factual “business as usual” scenario. A scenario based approach has been used to assess the impact of the different assumptions, based on: Two separate meter deployment scenarios, i.e. “fast” and “phased” meter-

deployment scenarios:

Fast rollout: in this case all smart meters would be installed in four-years, 2015 to 2018; and


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Phased (or ‘slow’) rollout: in this case, smart meters would be installed only when traditional non-smart meters would have to be replaced, thus completing the full rollout only in 2030; (although the retro-fitting of the smart-ready meters already installed at the start of the rollout would take place over an accelerated four-year period, 2015 to 2018);

Four separate energy saving scenarios depending on the type of customer informational stimuli deployed in a national rollout (based on Gas Customer Behaviour Trial Findings – CER/11/180a). Informational dimensions are frequency (bi-monthly or monthly) and detailed content (energy statement) of billing used with smart metering, whether an in-home display (IHD) device is deployed or not and whether a variable tariff is added. Table 1 below summarises the options analysed.

Table 1: List of Options Analysed in CBA Option Code.

Energy Saving

Scenario

Meter Rollout

Scenario 1F Bimonthly ES Fast 1S Bimonthly ES Phased 2F Monthly ES Fast 2S Monthly ES Phased 3F Bimonthly ES + IHD Fast 3S Bimonthly ES + IHD Phased 4F Bimonthly ES + IHD + Variable Tariff Fast 4S Bimonthly ES + IHD + Variable Tariff Phased

ES=Energy Statement; IHD = In-home Display

A fundamental assumption of the gas CBA is that a national gas smart metering rollout leverages the electricity smart metering infrastructure. The gas smart metering high-level design assumptions that underpin the gas CBA are predicated on this assumption: The electricity meter will act as the utility communication-hub for the home; The gas meter will communicate with this communication-hub on the

electricity meter; The electricity meter communication-hub will forward the gas data via the

electricity smart metering wide area network (WAN) communications system to the electricity smart metering meter data management system (MDMS) at the required intervals;

The electricity smart metering MDMS will in turn send the gas related data to the gas smart metering MDMS and then onwards to the customer information system (CIS) for validation and processing in accordance with the required gas market processes.

If a dual fuel in-home display (IHD) is part of the smart metering rollout solution then the electricity meter communication-hub will also forward the gas data to the IHD.


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Figure 2 below illustrates the high level design assumptions for a dual fuel national smart metering rollout, highlighting the specific components of the electricity smart metering infrastructure that a gas smart metering is assumed to leverage. The costs of the national rollout of the electricity smart metering infrastructure have already been included in the electricity smart metering CBA (CER/11/080c) and therefore these costs are not double-counted in the gas CBA model, which captures only the incremental costs to be borne by the electricity smart metering rollout as a result of facilitating gas smart metering i.e. the additional incremental electricity smart metering communication and meter data management system (MDMS) costs. The CER wishes to emphasise that the regulatory treatment of costs and their attribution to various segments of the industry in this CBA are without prejudice to any findings that may be made in the context of future price control measures or other regulatory actions. Figure 2: High-level system architecture overview

1MAM = Meter Asset Management (MAM) system, i.e. the BGN MAXIMO system 2CIS = Customer Information System (CIS), i.e. currently the BGN Integrated Utility System (IUS) 3OMS = Operational Meter System

In Home Display

Local Area Networks

Electricity Smart Meter

Gas Smart Meter

Head End Data

Collector 1

Head End Data

Collector 2

Head End Data

Collector n

Meter Data Management

System


System

GIS MAM OMS

BGN Managed Systems

CIS

Gas Shippers

End Customers

B2B Integration

Customer Premises

Wide Area Networks

B2B Integration

Industry Portal

A2A Integration

Market Systems

A2A Integration

Meter Data Collection

ESBN Responsible for provision

BGN Responsible for provision

Joint Responsibility for provision


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iv. Key Findings of the CBA Overall Results from Quantifiable Analysis The estimated total NPVs for the 8 national gas smart metering rollout options (Table 2 and Figure 3 below) analysed in the quantitative CBA are generally positive, often substantially so, for options including an IHD (options 3 and 4), and generally negative or marginal for options not including an IHD (options 1 and 2), with the exception of option 1F. The NPVs are generally more favourable for energy saving scenarios based on the fast rollout scenario compared to the phased rollout scenario. The energy saving scenario with the strongest NPVs, especially for the fast rollout scenario, is the combination of energy statement with IHD and variable tariff (Option 4F and 4S). If these results were borne out in an actual deployment of gas smart metering, leveraging an electricity smart metering infrastructure, the project would bring about net benefits for Ireland in comparison with the base case (counterfactual) scenario for the ‘with IHD’ options (3 and 4), especially if a fast rollout approach is taken (options 3F and 4F), and also the ‘without IHD’ option 1F. Table 2: Total NPV by option

Energy saving scenario Meter rollout

scenario Option code

Total incremental NPV (EUR)

Bimonthly ES Fast 1F 15,663,848 Bimonthly ES Phased 1S -1,612,759

Monthly ES Fast 2F 938,003 Monthly ES Phased 2S -13,870,616

Bimonthly ES + IHD Fast 3F 33,323,837 Bimonthly ES + IHD Phased 3S 12,101,010

Bimonthly ES + IHD + VT Fast 4F 59,879,967 Bimonthly ES + IHD + VT Phased 4S 33,991,380

ES=Energy Statement; IHD = In-home Display; VT = Variable Tariff


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Figure 3: Total NPV (€m) by options

Summary of NPV Breakdown by Component Figure 4 below depicts the distributional breakdown by component of the total NPV for the fast rollout options. Figure 4: Fast Rollout Options - NPV (€m) Breakdown by Component


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The same distributional trend is broadly reflected in the phased rollout options also. The Networks component is generally strongly negative in all options (ranging from -€58m to -€64m for fast scenarios and from -€61m to -€67m for phased scenarios) and Customer component being strongly positive (ranging from -€77m to -€122m for fast scenarios and from -€63m to -€100m for phased scenarios). The Supplier/Shipper component remains mainly marginal (circa -€1m) for most options, except for the smart metering monthly billing options which are strongly negative (-€33m to -€38m). Sensitivity Analyses

11 sensitivity tests were conducted on the gas CBA model. Important sources of variation in estimated NPVs arose from assumptions about the price of gas and the discount rate used (Table 3 below). The NPVs are also moderately sensitive to increases in the cost of smart meters and supplier IT systems costs. Generally the ‘with IHD’ options, which generally have the strongest NPVs of all options, proved very sensitive to a change in the assumption regarding the persistence of the IHD energy saving impact post-2020 (Table 4 below). They are also sensitive to a lesser but not insignificant extent to a change in the assumption regarding sharing of the IHD device costs. The other sensitivity tests all improved the NPVs across all options from minor to moderate extents. Table 3: Discount Rate that would turn each option’s NPV to zero Energy saving scenario

Meter rollout scenario

Option code

Discount rate cut-off value

Bimthly ES Fast 1F 5.8% Bimthly ES Phased 1S 3.8%

Monthly ES Fast 2F 4.1% Monthly ES Phased 2S 1.9%

Bimthly ES + IHD Fast 3F 7.4% Bimthly ES + IHD Phased 3S 5.6%

Bimthly ES + IHD + VT Fast 4F 9.8% Bimthly ES + IHD + VT Phased 4S 8.1%



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Table 4: Sensitivity 8: IHD effect wanes after 2020 Base case Sensitivity 8

Energy saving scenario

Meter rollout

scenario

Option code

NPV NPV Difference

TRUE

Bimthly ES + IHD Fast 3F 33,323,837 13,531,982 -19,791,855 Bimthly ES + IHD Phased 3S 12,101,010

-5,433,405 -17,534,415

Bimthly ES + IHD + VT Fast 4F 59,879,967 20,296,257 -39,583,710 Bimthly ES + IHD + VT Phased 4S 33,991,380 -1,077,451 -35,068,831

ES=Energy Statement; IHD = In-home Display; VT = Variable Tariff Societal Benefits from reduced emissions of greenhouse gases The reduction in gas usage will result in societal benefit for Ireland in the form of abated carbon dioxide (CO2) emissions from less gas being burnt. The value of this carbon abatement is included as part of the calculation of the consumer usage-related reduction using the carbon tax as a proxy for the value of carbon. The amounts of carbon abated for each of the CBA scenarios is calculated using the CO2 emissions intensity factor for natural gas of 0.190kg of CO2 per kWh. Figure 5 below shows the total CO2 savings, across the entire CBA period, for each gas smart metering national rollout option analysed in the CBA. Figure 5: Total CO2 savings by option (tCO2)


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iv. Next Steps The rollout of smart metering represents a major national infrastructure project and the publication of this report is one of the defining milestones in its delivery. Given the scale of investment required to deliver smart metering, a thorough and robust analysis is required to substantiate any rollout decision. This CBA, which concludes the potential for a positive net benefit for gas consumers, will facilitate the further development of the Smart Metering Project. The next steps for the project are outlined in the Smart Metering Information Paper 5 (CER/11/180) which accompanies this CBA report. The CER appreciates the significant contribution of all stakeholders that have been involved in compiling this CBA and the other reports and looks forward to their ongoing involvement in the next steps for the Smart Metering Project.


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Table of Contents Executive Summary .............................................................................................. 3

i. Introduction ..................................................................................................... 3 ii. Background to the CBA .................................................................................. 4 iii. Approach to the Gas CBA ............................................................................. 8 iv. Key Findings of the CBA ............................................................................. 11 iv. Next Steps................................................................................................... 15

List of Figures ..................................................................................................... 19 List of Tables ....................................................................................................... 20 1.0 Introduction ................................................................................................... 21

1.1 The Commission for Energy Regulation .................................................... 21 1.2 Purpose of This Paper ............................................................................... 21 1.3 Acknowledgements .................................................................................... 22 1.4 Approach to Analysis ................................................................................. 23 1.5 Background Information ......................................................................... 25

1.5.1 What is Smart Metering? ..................................................................... 25 1.5.2 EU Legislation ..................................................................................... 27 1.5.3 EU Initiatives ....................................................................................... 30 1.5.4 Smart Metering Rollout Status in Europe ............................................ 31 1.5.5 Smart Metering Progress in Ireland ..................................................... 32 1.5.5.1 Government Policy and Legislation .................................................. 32 1.5.5.2 CER Smart Metering Project ............................................................ 33

1.6 Structure of This Paper .............................................................................. 37 1.7 Commenting on This Paper ....................................................................... 38

2.0 Overview of Quantifiable Gas CBA Structure ................................................ 39 2.1 Introduction ................................................................................................ 39 2.2 High-level Design and Functional Requirement Assumptions ................... 42

2.2.1 High-level Design Assumptions ........................................................... 42 2.2.2 Functional Requirements Assumptions ............................................... 44 2.2.3 PPM Meter Solution............................................................................. 46 2.2.4 Remote Re-enablement of the Meter .................................................. 47

2.3 Gas CBA Options ...................................................................................... 48 2.4 Gas CBA Scope and Calculation Assumptions.......................................... 49

2.4.1 Scope of the Gas CBA ........................................................................ 49 2.4.2 Key Calculation Assumptions .............................................................. 49

2.5 Structure of Remaining Document ............................................................. 50 3.0 Quantifiable Costs and Benefits for Networks ............................................... 51

3.1 Introduction ................................................................................................ 51 3.2 Networks Related Costs ............................................................................ 53

3.2.1 Meter Capital Costs ............................................................................. 54 3.2.2 Smart Communication Module Failures ............................................... 59 3.2.3 Smart Metering IT Systems Costs ....................................................... 60 3.2.4 Electricity Smart Metering Interface Incremental Costs ....................... 66

3.3 Network Related Benefits .......................................................................... 70 3.3.1 Meter Reading Benefits ....................................................................... 71


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3.3.2 Siteworks Savings ............................................................................... 73 3.3.3 Meter Exchanges................................................................................. 74 3.3.4 Prepayment – Meter Exchange and Operations Savings .................... 76 3.3.5 Fuel Gas Savings ................................................................................ 79 3.3.6 Revenue Protection - Theft of Gas ...................................................... 80 3.3.7 System Reinforcement ........................................................................ 81

4.0 Quantifiable Costs and Benefits for Suppliers ............................................... 82 4.1 Introduction ................................................................................................ 82 4.2 Retail Enquiries and Complaints ................................................................ 85

4.2.1 Option 1 (Bi-monthly Billing) ............................................................ 85 4.2.2 Option 2 (Monthly Billing) ................................................................ 85

4.3 Customer Education and Awareness Campaign ....................................... 86 4.3.1 Option 1 (Bi-monthly Billing) and Option 2 (Monthly Billing) ............ 86

4.4 Bill Printing Costs ....................................................................................... 87 4.4.1 Option 1 (Bi-monthly Billing) ............................................................ 87 4.4.2 Option 2 (Monthly Billing) ................................................................ 87 4.4.3 Colour Printing Set-up Costs ........................................................... 87

4.5 Debt Management Benefits ....................................................................... 88 4.5.1 Option 1 (Bi-monthly Billing) and Option 2 (Monthly Billing) ............ 88 4.5.2 Working Capital ............................................................................... 88

4.6 Staff Training Costs ................................................................................... 89 4.7 IT Systems Costs ....................................................................................... 90

4.7.1 IT Systems CAPEX for Option 1 (Bi-monthly Billing) and Option 2 (Monthly Billing) ............................................................................................ 90 4.7.2 IT Systems OPEX for Option 1 (Bi-monthly Billing) and Option 2 (Monthly Billing) ............................................................................................ 91 4.7.3 Web Portal....................................................................................... 91

4.8 Payment Transactions Costs ..................................................................... 92 4.8.1 Option 1 (Bi-monthly Billing) ............................................................ 92 4.8.2 Option 2 (Monthly Billing) ................................................................ 92

4.9 Supplier Switching Related Benefits .......................................................... 93 4.9.1 Option 1 (Bi-monthly Billing) and Option 2 (Monthly Billing) ............ 93

4.10 Hedging Benefits ..................................................................................... 94 4.11 Prepayment Benefits ............................................................................... 95

5.0 Quantifiable Costs and Benefits for Consumers ........................................... 96 5.1 Introduction ................................................................................................ 96 5.2 Residential usage-related benefits ............................................................. 97

5.2.1 Gas Cost ............................................................................................. 98 5.2.2 Average Quantity ............................................................................... 101

5.3 Societal Benefits ...................................................................................... 104 5.4 Non-usage related costs and benefits ..................................................... 105

5.5.1 Reduction in complaints .................................................................... 106 5.5.2 Elimination of “dial-a-read” calls ........................................................ 106 5.5.3 Familiarisation cost of smart metering ............................................... 107

6.0 Results of Quantifiable Cost-Benefit Analysis ............................................. 108 6.1 Introduction .............................................................................................. 108


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6.2 Options and CBA Parameters.................................................................. 109 6.2.1 Options tested in the CBA ................................................................. 109 6.2.2 High level parameter assumptions used in the CBA.......................... 109

6.3 Total NPV by Option ................................................................................ 111 6.4 NPV Components by Option .................................................................... 113

6.4.1 Network Component .......................................................................... 113 6.4.2 Supplier Component .......................................................................... 115 6.4.3 Customer Component ....................................................................... 116 6.4.4 Societal Component .......................................................................... 118 6.4.5 Summary of NPV Breakdown by Component .................................... 119

6.5 Sensitivity Tests ....................................................................................... 121 6.5.1 Sensitivity Test 1: Shared IHD Cost .................................................. 122 6.5.2 Sensitivity Test 2: Meter Costs Increase ........................................... 123 6.5.3 Sensitivity Test 3: Programme Management Costs ........................... 124 6.5.4 Sensitivity Test 4: Supplier IT Systems Costs Increase ..................... 125 6.5.5 Sensitivity Test 5: Dual Fuel Licence Cost Discount.......................... 126 6.5.6 Sensitivity Test 6: Lower communication OPEX costs ...................... 127 6.5.7 Sensitivity Test 7: Energy Savings for Small Businesses .................. 128 6.5.8 Sensitivity Test 8: IHD benefit wanes from 2020 onwards ................. 129 6.5.9 Sensitivity Test 9: Gas Price Forecasts ............................................. 130 6.5.10 Sensitivity Test 10: Gas Price Consistent with Electricity CBA ........ 131 6.5.11 Sensitivity Test 11: Discount Rate ................................................... 132 6.5.12 Summary of Sensitivity Tests .......................................................... 135

6.6 Summary ................................................................................................. 136 7.0 Qualitative Costs and Benefits .................................................................... 137

7.1 Introduction .............................................................................................. 137 7.2 Potential for greater usage-related benefits ............................................. 137 7.3 Monthly Electronic Billing Costs for Suppliers .......................................... 137 7.4 Hedging Benefits for Suppliers ................................................................ 137 7.5 Customer Interface Costs and Benefits ................................................... 138 7.6 Competition-related Benefits.................................................................... 138 7.7 Consumer Investment Related Benefits .................................................. 138 7.8 Summary ................................................................................................. 139

8.0 Conclusions ................................................................................................ 140 8.1 Summary and Next Steps ........................................................................ 140

Appendix A – Glossary ..................................................................................... 141


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List of Figures Figure 1: Smart Metering Project Phase 1 – Participants and Deliverables .......... 6 Figure 2: High-level system architecture overview .............................................. 10 Figure 3: Total NPV (€m) by options ................................................................... 12 Figure 4: Fast Rollout Options - NPV (€m) Breakdown by Component .............. 12 Figure 5: Total CO2 savings by option (tCO2) .................................................... 14 Figure 6: Smart Metering Project Phase 1 – Participants and Gas Deliverables 22 Figure 7: General structure of a smart metering system ..................................... 26 Figure 8: Smart Metering Project Phase 1 – Overview of Participants ................ 34 Figure 9: Smart Metering Project Phase 1 – Governance Structure ................... 35 Figure 11: Overview of Gas CBA Structure......................................................... 41 Figure 12: High-level system architecture overview ............................................ 44 Figure 13: High-level overview of meter functional requirements ........................ 45 Figure 14: Overview of Programme Timetable (Fast Rollout) ............................. 64 Figure 15: Prepayment Penetration Rates Assumed - All Scenarios .................. 76 Figure 16: Total NPV (€m) by Option ................................................................ 112 Figure 17: Total CO2 Savings by Option (tCO2) ............................................... 118 Figure 19: Phased Rollout Options - (€m) Breakdown by Component .............. 119 Figure 20: Sensitivity of NPV to Real Discount Rate for Options 1F, 2F, 3F, 3S, 4F, 4S ............................................................................................................... 133


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List of Tables Table 1: List of Options Analysed in CBA ............................................................. 9 Table 2: Total NPV by option .............................................................................. 11 Table 3: Discount Rate that would turn each option’s NPV to zero ..................... 13 Table 4: Sensitivity 8: IHD effect wanes after 2020 ............................................. 14 Table 5: Status of Smart Metering CBA Development in EU Member States ..... 31 Table 7: Meter Capital Costs - Fast Rollout Scenario ......................................... 54 Table 8: Meter Capital Costs - Phased Rollout Scenario .................................... 54 Table 9: Smart Meter Rollout Schedule - Fast Scenario ..................................... 55 Table 10: Gas Meter Population in 2011 ............................................................. 55 Table 11: Smart-communication module failure assumptions ............................. 59 Table 12: Smart metering IT systems - All Scenarios ......................................... 61 Table 13: Smart metering programme costs assumptions .................................. 65 Table 14: Summary of Costs for interface with electric meters ........................... 66 Table 15: Summary of Meter reading savings..................................................... 71 Table 16: Summary of Siteworks Savings........................................................... 73 Table 17: Failure rates ........................................................................................ 74 Table 18: Meter exchanges costs ....................................................................... 74 Table 19: Prepayment Churn Rate Assumptions ................................................ 77 Table 20: PPM operations savings assumptions ................................................ 78 Table 21: Fuel gas savings assumptions ............................................................ 79 Table 22: Supplier ('Gas shippers') - Costs and Benefits Overview .................... 83 Table 23: Gas CBT Results Overview ................................................................ 97 Table 25: ‘New builds’ Usage and Rate Assumptions ....................................... 103 Table 27: List of Options Analysed in CBA ....................................................... 109 Table 28: Total NPV by Option ......................................................................... 111 Table 29: NPV by Option for Network Component ............................................ 114 Table 30: NPV by Option for Supplier Component ............................................ 115 Table 31: Gas Customer Behaviour Trial Results ............................................. 116 Table 32: NPV by Option for Customer Component ......................................... 117 Table 33: Total CO2 Savings by Option (tCO2) ................................................ 118 Table 34: Summary of NPVs (€m) by Option .................................................... 120 Table 35: Results of Sensitivity Test 1 - Shared IHD Cost ................................ 122 Table 36: Results of Sensitivity Test 2 - Meter Costs Increase ......................... 123 Table 37: Results of Sensitivity Test 3 - Programme Management Costs ........ 124 Table 38: Results of Sensitivity Test 4 - Supplier IT Systems Costs Increase .. 125 Table 39: Results of Sensitivity Test 5 - Dual Fuel Licence Cost Discount ....... 126 Table 40: Results of Sensitivity Test 6 - Lower communication OPEX costs .... 127 Table 41: Results of Sensitivity Test 7 - Energy Savings for Small Businesses 128 Table 42: Results of Sensitivity Test 8 - IHD benefit wanes from 2020 ............. 129 Table 43: ICE Gas Futures Prices Used in Sensitivity Test 9 ........................... 130 Table 44: Results of Sensitivity Test 9 - Gas Price Forecasts........................... 130 Table 45: Results of Sensitivity 10 - Gas Price Consistent with Electricity CBA 131 Table 46: Discount Rate That Would Turn Each Option’s NPV to Zero ............ 132


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1.0 Introduction

1.1 The Commission for Energy Regulation The Commission for Energy Regulation (‘the CER’) is the independent body responsible for overseeing the regulation of Ireland's electricity and gas sectors. The CER was initially established and granted regulatory powers over the electricity market under the Electricity Regulation Act 1999. The enactment of the Gas (Interim) (Regulation) Act 2002 expanded the CER’s jurisdiction to include regulation of the natural gas market, while the Energy (Miscellaneous Provisions) Act 2006 granted the CER powers to regulate electrical contractors with respect to safety, to regulate natural gas undertakings involved in the transmission, distribution, storage, supply and shipping of gas and to regulate natural gas installers with respect to safety. The Electricity Regulation Amendment (SEM) Act 2007 outlined the CER’s functions in relation to the Single Electricity Market (SEM) for the island of Ireland. This market is regulated by the CER and the Northern Ireland Authority for Utility Regulation (NIAUR). The CER is working to ensure that consumers benefit from regulation and the introduction of competition in the energy sector.

1.2 Purpose of This Paper The purpose of this paper is to outline and describe in detail the results of the cost-benefit analysis (CBA) for a national rollout of gas smart metering in Ireland. The scope of the CBA covers all gas customers in the G4 meter category, which includes all residential customers and some non-residential customers. This gas CBA follows on from the electricity smart metering CBA published by the CER is May 2011 (CER/11/080c). A fundamental assumption of the gas CBA is that a national gas smart metering rollout leverages the infrastructure that would be put in place for electricity smart metering, hence only costs incremental to those already included in the electricity CBA are included in the gas CBA. This gas CBA delivers a robust economic assessment of the long-term costs and benefits (incremental to those already included in the electricity smart metering CBA) to the market and the individual consumer of a national gas smart metering rollout. This will inform decisions to be made regarding the rollout of smart metering in Ireland. The findings from the CBA provide a rich source of information which will be used to inform energy policy decisions in Ireland relating to smart metering enabled initiatives such as more detailed and frequent billing, in-home displays, innovative tariffs and prepayment metering. This CBA is a key deliverable of Phase 1 of the CER Smart Metering Project. It draws upon other key Phase 1 deliverables which are published alongside it i.e.


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the Gas Customer Behaviour Trial Findings Report (CER/11/180a) and the Dual Fuel Technology Trial Findings Report (CER/11/180b). It should be noted that, for the purposes of compiling the CBA, Bord Gáis Networks, ESB Networks and gas suppliers currently active in the Irish market were requested by the CER to provide smart metering related costs and benefits in accordance with the national smart metering high level design and implementation assumptions which had been developed by the CER via the Smart Metering Project industry forums and a public consultation process (refer to section 2.2 for further details). The CER reviewed and validated these costs and benefits, including an external review by Frontier Economics. Figure 6: Smart Metering Project Phase 1 – Participants and Gas Deliverables

1.3 Acknowledgements The Smart Metering Project is a collaborative project managed by the Commission for Energy Regulation (CER) with the support of multiple energy

Gas Customer Behaviour Trials Findings Report (CER/11/180a)

Dual Fuel Technology Trial Findings Report

(CER/11/180b)

Gas Cost-Benefit Analysis Report (CER/11/180c)


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industry stakeholders (Figure 6). The cost-benefit analysis for a national gas smart metering rollout in Ireland is a robust and detailed document which will inform future decisions relating to smart metering and associated energy policy in Ireland. The CER would like to acknowledge and commend the valuable contributions made by the following organisations involved in successfully developing the Irish gas smart metering cost-benefit analysis to such a high standard:

Bord Gáis Networks and ESB Networks provided the network operator related cost and benefit inputs to the CBA model.

Airtricity, Bord Gáis Energy, Phoenix Energy and Vayu provided the supplier/shipper related cost and benefit inputs to the CBA model.

Frontier Economics which was contracted to develop the CBA model and to assist the CER with a validation check on the network and supplier submitted costs and benefits. Frontier were partnered by Logica, which contributed to the review with their technical expertise in the areas of IT and communication equipment.

The Economic and Social Research Institute (ESRI) which performed a peer review of the CBA model.

Finally, the assumptions for the high level design and implementation of a national smart metering rollout that underpin this CBA were set after taking into account the feedback from responses received to the CER’s two consultations on the topic during 2010/11 (CER/10/082 and CER/10/197). The CER would like to thank all parties that contributed responses and attended the associated public consultation workshops.

1.4 Approach to Analysis This paper is intended to inform the CER, the Department of Communications, Energy and Natural Resources (DCENR), and stakeholders of the possible merits of providing smart gas meters to all Irish gas customers in the G4 meter category, which includes all residential customers and some non-residential customers. In addition, the analysis should help cast light on the relative attractiveness of various design options for implementation of smart meters and the main sources of risk associated with a rollout. Some sources of costs and benefits are more amenable to quantification than others, so the analysis is divided between “quantifiable” and “qualitative” sources of costs and benefits. To place some structure on the analysis of the quantifiable elements, costs and benefits are divided into rough categories by source: networks, suppliers/shippers and consumers. There are some points at which an activity allocated to one category influences costs or benefits arising in another category. Nevertheless, it is considered helpful to group the results in this way for the purpose of exposition. Where the allocation of costs and benefits among these


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categories overlap some decisions have been made to allocate those costs and benefits so as to prevent double counting. The cost-benefit analysis assesses the broad societal costs and benefits of implementing smart metering rather than the private costs and benefits to any given subset of affected parties. The Gas CBT Findings Report (CER/11/180a) does illustrate some distributional effects arising from a move to smart metering related initiatives for gas. There may also be distributional effects along the value chain, for example transfers of welfare between suppliers and customers, but to economise on the time required for this analysis it has not been attempted to model such effects. The overall attractiveness of each option is identified for the quantifiable costs and benefits by computing the net present value (NPV) of the project in 2011, taking into account predicted cash flows from 2011-2032. A fundamental assumption of the gas CBA is that a national gas smart metering rollout leverages the electricity smart metering infrastructure. The gas smart metering high-level design assumptions that underpin the gas CBA are predicated on this assumption: The electricity meter will act as the utility communication-hub for the home; The gas meter will communicate with this communication-hub on the

electricity meter;

The electricity meter communication-hub will forward the gas data via the electricity smart metering wide area network (WAN) communications system to the electricity smart metering meter data management system (MDMS) at the required intervals;

The electricity smart metering MDMS will in turn send the gas related data to the gas smart metering MDMS and onwards to the customer information system (CIS) for validation and processing in accordance with the required gas market processes.

If a dual fuel in-home display (IHD) is part of the smart metering rollout solution then the electricity meter communication-hub will also forward the gas data to the IHD.

The costs of the national rollout of the electricity smart metering infrastructure have already been included in the electricity smart metering CBA (CER/11/080c) and therefore these costs are not double-counted in the gas CBA model, which captures only the incremental costs to be borne by the electricity smart metering rollout as a result of facilitating gas smart metering i.e. the additional incremental electricity smart metering communication and meter data management system (MDMS) costs.


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The CER wishes to emphasise that the regulatory treatment of costs and their attribution to various segments of the industry in this CBA are without prejudice to any findings that may be made in the context of future price control measures or other regulatory actions.

1.5 Background Information 1.5.1 What is Smart Metering? “An intelligent metering system or ‘smart meter’ is an electronic device that can measure the consumption of energy, adding more information than a conventional meter, and can transmit data using a form of electronic communication. A key feature of a smart meter is the ability to provide bi-directional communication between the consumer and supplier/operator. It should also promote services that facilitate energy efficiency within the home. The move from old, isolated and static metering devices towards new smart/active devices is an important issue for competition in energy markets. The implementation of smart meters is an essential first step towards the implementation of smart grids.”3 It is important to note that ‘smart metering’ encompasses more than just the meter itself. Smart metering should be viewed as a system rather than a single device. It is essentially a hybrid technology consisting of three high level layers:

Physical meters and associated devices Communications layer covering data transport and communications

network management IT systems which manage the data, applications and services

The following diagram (Figure 7) illustrates the general structure of a smart metering system. Smart meters are the next generation of meters, which can replace existing electro-mechanical and diaphragm meters and offer a range of benefits for both the individual electricity and gas consumer and for the electricity and gas systems in general. The existing standard mechanical meter records the total amount of electricity/gas used over time. These meters are read manually and the information is sent to the network company and then used to calculate customer bills. If a meter reader does not have access to the customer’s meter, estimated

3 Commission staff working paper - interpretative note on directive 2009/72/EC concerning common rules for the internal market in electricity and directive 2009/73/EC concerning common rules for the internal market in natural gas - retail markets - 22 January 2010 (Pg 7) http://ec.europa.eu/energy/gas_electricity/interpretative_notes/doc/implementation_notes/2010_01_21_retail_markets.pdf


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consumption information (or a reading provided by the customer) is used to calculate the bill. If the estimated consumption is higher or lower than the actual meter read, this is corrected for when the meter is next read by the customer or the meter reader. Figure 7: General structure of a smart metering system (Source: Figure 6, ERGEG Status Review of Regulatory Aspects of Smart Metering4)

A smart meter is much more sophisticated. It records customers’ actual use of electricity/gas over short intervals (e.g. every 30 minutes). These meters are connected by a communications system to the network company / meter data collector providing the operator with automated, up-to-date information on the amounts of electricity/gas used by customers. Access to this information provides opportunities to reduce network operation costs, including reduced costs of visiting customer premises to manually read the meter and carrying out any necessary connections and disconnections. There are also savings due to reductions in technical losses and theft. The data collected from smart meters can be used by electricity and gas suppliers, subject to data protection requirements, to deliver useful information to their customers regarding their electricity and gas consumption and costs. In particular, the installation of smart metering will allow electricity suppliers to create innovative pricing arrangements that can be offered to customers to support the efficient use of electricity, such as time-of-use electricity tariffs. This is where the price of electricity varies at different times of the day to reflect the changes in the costs of producing electricity. This will allow customers to manage their consumption of electricity in line with price movements and demand patterns. Smart meters can facilitate improving energy efficiency by empowering consumers with more detailed, accurate and timely information regarding their energy consumption and costs, thus helping consumers reduce any unnecessary energy usage and shift any discretionary electricity usage away from peak consumption times. 4 Ref: E09-RMF-17-03 www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_ERGEG_PAPERS/Customers/Tab/E09-RMF-17-03_SmartMetering-SR_19-Oct-09.pdf


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1.5.2 EU Legislation There are a number of key EU legislative instruments promoting smart metering, which include: a) Third Legislative Package for Further Liberalisation of the Electricity

and Gas Markets 5 The 3rd Package contains provisions regarding intelligent metering systems, with the aim of better informing customers of their consumption and helping to increase awareness of energy consumption. The implementation of those metering systems may be subject to an economic assessment of all the long-term costs and benefits to the market and the individual consumer or of which form of intelligent metering is economically reasonable and cost-effective and which timeframe is feasible for their installation. The general principle is that consumers must have access to their consumption data. National Regulatory Authorities (NRAs) must ensure access to customer consumption data, and the existence of a nationwide harmonised format for consumption data and a process for suppliers and consumers to access the data must be defined. Intelligent metering systems are promoted twice in the Directives: first, with the aim to promote energy efficiency and demand side management measures; second, with the aim to ensure active participation of consumers in the market. Different provisions apply for electricity and for gas – details below. There are also a number of EU Interpretive Notes which cover smart metering published on these directives.

i) Electricity - Directive 2009/72/EC (Annex 1) 6 This directive states that: 1. (i) [Member States shall ensure that customers] are properly informed of

actual electricity consumption and costs frequently enough to enable them to regulate their electricity consumption’

2. ‘Member States shall ensure the implementation of intelligent metering

systems that shall assist the active participation of consumers in the electricity supply market. The implementation of those metering systems may be subject to an economic assessment of all the long-term costs and benefits to the market and the individual consumer or which form of intelligent metering is economically reasonable and cost-effective and which timeframe is feasible for their distribution.

5 http://ec.europa.eu/energy/gas_electricity/third_legislative_package_en.htm 6 http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32009L0072:EN:NOT


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Such assessment shall take place by 3 September 2012’. Subject to that assessment, Member States or any competent authority they designate shall prepare a timetable with a target of up to 10 years for the implementation of intelligent metering systems. Where rollout of smart meters is assessed positively, at least 80 % of consumers shall be equipped with intelligent metering systems by 2020.

An EU Retail Markets Interpretive Note7 on Electricity Directive 2009/72/EC highlights a European Commission Declaration8 which clarifies that:

“It is understood that in the case no economic assessment of the long-term costs and benefits is made, at least 80% of all consumers have to be equipped with intelligent metering systems by 2020.”

ii) Gas - Directive 2009/73/EC (Annex 1)9 This directive states that: 1. (i) [Member States shall ensure that customers] are properly informed of

actual gas consumption and costs frequently enough to enable them to regulate their own gas consumption.

2. Member States shall ensure the implementation of intelligent metering systems that shall assist the active participation of consumers in the gas supply market. The implementation of those metering systems may be subject to an economic assessment of all the long-term costs and benefits to the market and the individual consumer or which form of intelligent metering is economically reasonable and cost-effective and which timeframe is feasible for their distribution. Such assessment shall take place by 3 September 2012. Subject to that assessment, Member States or any competent authority they designate, shall prepare a timetable for the implementation of intelligent metering systems.

b) Proposed Energy Efficiency Directive10 7 Commission staff working paper - interpretative note on directive 2009/72/EC concerning common rules for the internal market in electricity and directive 2009/73/EC concerning common rules for the internal market in natural gas - retail markets - 22 January 2010 http://ec.europa.eu/energy/gas_electricity/interpretative_notes/doc/implementation_notes/2010_0 1_21_retail_markets.pdf 8Council document 10814/09 ADD 1 REV 1 http://register.consilium.europa.eu/pdf/en/09/st10/st10814-ad01re03.en09.pdf 9 http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32009L0073:EN:NOT


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On 22 June 2011 the European Commission adopted a proposal for an Energy Efficiency Directive to establish a common framework for the promotion of energy efficiency across the EU, ensure the achievement of the Union's target of 20% primary energy savings by 2020 and pave the way towards the realisation of further energy efficiency beyond that date. The Directive on Energy Efficiency will amend and subsequently repeal the Cogeneration Directive (2004/8/EC, CHP Directive) and the Energy Services Directive (2006/32/EC, ESD)11. Given the assessment that the Union is unlikely to achieve its energy efficiency target of 20% primary energy savings by 2020 based on the current policy mix, the Commission is proposing to take a much firmer line with Member States. While there are no binding targets in the draft there are a number of binding measures The European Commission’s proposal for a Directive on Energy Efficiency (COM(2011)370) has direct implications for the activities of regulators, who have to ensure that customer interests are always taken into account and that competition is not distorted. The Energy Efficiency Directive is covers a range of areas including; Energy Efficiency Obligation Schemes (Article 6), Metering and informative billing (Article 8), Promotion of efficiency in heating and cooling (Article 10) and Energy Transmission and Distribution (Article 12). c) Directive 2005/89/EC – Security of Supply12 This Directive specifies that member states may encourage “the adoption of real-time demand management technologies, such as advanced metering systems” to maintain balance between electricity demand and supply. d) Directive 2004/22/EC - Measuring Instruments13 The Directive 2004/22/EC of the European Parliament and of the Council of 31 March 2004 on measuring instruments (MID) establishes the requirements that measurement devices and systems have to satisfy before being put on the market and/or put into use. Each measuring instrument must meet the essential requirements (laid down in Annex I of the Directive) and in the relevant instrument-specific Annex.

10 EC Proposal for new Energy Efficiency Directive http://ec.europa.eu/energy/efficiency/eed/eed_en.htm 11 Article 13 of DIRECTIVE 2006/32/EC OF THE EUROPEAN PARLIAMENT AND OF THE COUNCIL of 5 April 2006 on energy end-use efficiency and energy services and repealing Council Directive 93/76/EEC http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2006:114:0064:0064:en:pdf 12 Article 5 (2.d.) of DIRECTIVE 2005/89/EC OF THE EUROPEAN PARLIAMENT AND OF THE COUNCIL of 18 January 2006 concerning measures to safeguard security of electricity supply and infrastructure investment www.energy.eu/directives/l_03320060204en00220027.pdf 13 DIRECTIVE 2004/22/EC OF THE EUROPEAN PARLIAMENT AND OF THE COUNCIL of 31 March 2004 on measuring instruments http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2004:135:0001:0080:EN:PDF


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1.5.3 EU Initiatives There are currently a number of EU coordinated smart metering initiatives underway which include:

On 8th February 2011 ERGEG (European Regulators Group for Electricity and Gas) published its final Guidelines of Good Practice (GGP) on Regulatory Aspects of Smart Metering for Electricity and Gas (E10-RMF-23-03)14. These final recommendations aim to provide guidance regarding the European Commission’s 3rd Energy Package provisions on the installation of intelligent metering systems for electricity and gas, focusing on customer services, rollout of smart meters, cost-benefit analysis and data security and integrity.

European Standards Organisations are progressing Mandate M/44115 for the development of an open architecture for utility meters involving communication protocols and functionalities enabling interoperability. The Mandate has the general objective to highlight or to harmonise European standards that will enable interoperability of utility meters (water, gas, electricity, heat), which can then improve the means by which customers’ awareness of actual consumption can be raised in order to allow timely adaptation to their demands. According to Mandate M/441, the implementation of this provision requires the definition of new functionalities for smart meters – in addition to those in the Measuring Instruments Directive (MID)16, and as stated by the European Commission in the Mandate M/441.

The Open Meter Project17 began in January 2009 with the main objective

to specify a comprehensive set of open and public standards for advanced metering infrastructure (AMI), supporting electricity, gas, water and heat metering. This project concluded in June 2011 and the deliverables are published on www.openmeter.com.

In January 2010 a Task Force on Smart Grids18 was launched whose

mission is to advise the European Commission on policy and regulatory directions at European level and to coordinate the first steps towards the implementation of smart grids under the provision of the 3rd Package.

14ERGEG final Guidelines of Good Practice (GGP) on Regulatory Aspects of Smart Metering for Electricity and Gas (E10-RMF-23-03) http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_CONSULT/CLOSED%20PUBLIC%20CONSULTATIONS/CUSTOMERS/Smart%20metering/CD/E10-RMF-29-05_GGP_SM_8-Feb-2011.pdf 15 Mandate M/441 http://www.openmeter.com/documents/m441en.pdf 16 Directive 2004/22/EC of the European Parliament and of the Council of 31 March 2004 on measuring instruments http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32004L0022:en:NOT 17 Open Meter Project http://www.openmeter.com/ 18 Smart Grids Task Force http://ec.europa.eu/energy/gas_electricity/smartgrids/taskforce_en.htm


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1.5.4 Smart Metering Rollout Status in Europe The status of smart metering for electricity and gas in Europe is diverse and changing at a rapid pace. The last publicly available official report on the status of each country is the ERGEG Summary of Member State experiences on cost benefit analysis (CBA) of smart meters published 2nd February 201119 but this document focuses on smart metering cost-benefit analysis (CBA) development rather than specific meter rollout status. Table 5 below is an excerpt from this report and it indicates that, out of the 24 member states that responded to the ERGEG survey, as of 1st January 2011 eleven had completed an electricity CBA and six had completed a gas CBA. Table 5: Status of Smart Metering CBA Development in EU Member States (Source: Page 2, ERGEG Summary of Member State experiences on cost benefit analysis (CBA) of smart meters published 2nd February 2011)

19 Summary of Member State experiences on cost benefit analysis (CBA) of smart meters 2 February 2011 http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_CONSULT/CLOSED%20PUBLIC%20CONSULTATIONS/CUSTOMERS/Smart%20metering/CD/C11-RMC-44-03_CBA%20SM_2-Feb-2011.pdf


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The ERGEG Status review on regulatory aspects of smart metering report, published October 200920 is still the last publicly available official report on the status of each country regarding trials and rollouts of smart metering. Because of the fast pace of development in the area of smart metering it should be noted that the national situations which are reflected in the status review may no longer provide a complete and accurate picture of the national situations.

Generally in electricity only two countries have undertaken a large scale meter installation programme for customers - these early adopters are Italy and Sweden with full rollouts. In addition, some other countries have decided to undertake a large scale rollout of smart electricity meters, such as Britain, Norway, Finland and most recently France. Other countries are considering rollout plans with some undertaking smart metering trials to inform their decisions.

In gas, there are fewer uptakes of smart meters, with Italy and Britain having planned rollouts, while a small number of countries are discussing the possibility.

The ERGEG Status review on regulatory aspects of smart metering report also found that the most important policy objectives for supporting and encouraging a rollout of smart meters in both electricity and gas are energy efficiency, peak load management and more frequent meter readings.

1.5.5 Smart Metering Progress in Ireland

1.5.5.1 Government Policy and Legislation

The National Smart Metering Plan in Ireland is a key Government priority in the context of enabling the development of a Smart Grid, facilitating more efficient use of energy and underpinning smart and sustainable economic growth. The importance of Smart Metering within the Government’s energy policy, and indeed within its wider economic strategy, reflects the fact that, at EU level, Smart Metering is seen as a critical tool in managing energy demand in the interests of consumers and businesses. In December 2009, the Energy Services Directive (Directive 2006/32/EC) was transposed into Irish law under the European Communities (Energy End Use Efficiency and Energy Services) Regulations 2009, Statutory Instrument No. 542 of 200921. These Regulations also amend the Electricity Regulation Act 1999

20 E09-RMF-17-03 ERGEG Status review on regulatory aspects of smart metering as of May 2009 www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_ERGEG_PAPERS/Customers/Tab/E09-RMF-17-03_SmartMetering-SR_19-Oct-09.pdf 21 www.attorneygeneral.ie/esi/2009/B27331.pdf


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to allow the Commission for Energy Regulation (CER) to place requirements on energy undertakings in relation to informative billing.

“(5) The Commission may, by direction under subsection (1), require an energy undertaking to do any or all of the following— (a) provide bills to its final customers, based on actual energy use, at such frequency as may be specified by the Commission to enable those customers to regulate their own energy consumption in a timely manner,...”

In May 2009 the first National Energy Efficiency Action Plan (NEEAP)22 was adopted in line with EU requirements. The first NEEAP set out the key targets to be met in order to achieve our 2020 commitments, including Action 33:

“We will encourage more energy efficient behaviour by householders through the introduction of smart meters”.

The second NEEAP, due to be published in October 2011, will reiterate the importance of smart metering as a key tool for realising long term energy demand management objectives.

1.5.5.2 CER Smart Metering Project

In March 2007 the Commission for Energy Regulation (CER) issued a Demand Side Management and Smart Metering Consultation Paper (CER/07/038)23 in which the case for providing domestic and small business customers with time-of-day electricity prices and smart metering arrangements was made. This was followed in November 2007 with the publication by the CER of an information paper, Smart Metering - The Next Step in Implementation (CER/07/198)24, which outlined a proposed framework in which the future scope of smart metering arrangements can be established. Following on from the conclusions reached in the smart metering information paper CER/07/198 the CER established the Smart Metering Project Phase 1 in late 2007 with the objective of setting up and running smart metering trials and assessing their costs and benefits, which will inform decisions relating to the full rollout of an optimally designed universal National Smart Metering Plan. In order to draw on the experience and expertise of the electricity and gas market a Steering Group and a Working Group was established by the CER for the 22 Chapter 07 – Residential Sector, Page 79 www.dcenr.gov.ie/Energy/Energy+Efficiency+and+Affordability+Division/National+Energy+Efficiency+Action+Plan.htm 23 www.cer.ie/en/electricity-retail-market-current-consultations.aspx?article=01b6318d-3876-4630-8bb5-f54fb368be16 24 www.cer.ie/en/electricity-retail-market-current-consultations.aspx?article=01b6318d-3876-4630-8bb5-f54fb368be16


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Smart Metering Project Phase 1. Both groups are chaired by the CER and consist of representatives from the Department of Communications, Energy and Natural Resources (DCENR), Sustainable Energy Authority of Ireland (SEAI), the Northern Ireland Authority for Utility Regulation (NIAUR) and Irish gas and electricity industry participants (Figure 8). Figure 8: Smart Metering Project Phase 1 – Overview of Participants

To achieve its objectives the Smart Metering Working Group was divided into four Work Streams each focusing on separate aspects of the Smart Metering Project Phase 1 (Figure 9 and Figure 10):

Networks: Technical design and rollout of smart metering infrastructure required for the technology trials and customer behavior trials. Lead: ESB Networks (electricity) and Bord Gáis Networks (gas).

Customer Behaviour: Mainly focusing on the design and implementation of all aspects of the customer behavioural trials, including participant selection, communications and analysis of results. Lead: Sustainable Energy Authority of Ireland (SEAI).

Tariffs: Mainly focusing on design of Tariffs for the customer behavior trials (time of use tariffs for electricity and a variable seasonal tariff for gas) and development of a Prepayment Trial. Lead: Electric Ireland.


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Billing / Data: Mainly focusing on data flows from the smart metering systems to Suppliers, for customer behaviour trial billing options, and statisticians, for analysis of results from the customer behavior trials. Lead: Bord Gáis Energy.

The CER was responsible for undertaking Smart Metering Cost-Benefit Analyses (CBAs) for national electricity and gas smart metering rollouts and worked with Frontier Economics and the Economic and Social Research Institute (ESRI) in this regard. As part of this work, the CER identified the information requirements for a CBA, the parties responsible for providing such information and coordinated the transfer of the required information to the ESRI (Electricity CBA) and Frontier Economics (Gas CBA) for their modelling. The CER also arranged for an external review of the supplier and network operator cost and benefits included in the CBAs, which was conducted by Frontier Economics for both the electricity and gas CBAs. A peer review of the gas CBA was conducted by the ESRI. Figure 9: Smart Metering Project Phase 1 – Governance Structure

The key deliverables of the Smart Metering Project Phase 1 are depicted below: Figure 10: Smart Metering Project Phase 1 – High-Level Work Breakdown Structure (WBS)

Smart Metering Steering Group

CER

Smart Metering Working Group

CER

Tariffs Work Stream

Billing–DataWork Stream

NetworksWork Stream

Customer Behaviour

Work Stream

Smart Metering Project

Procure & Start-Up

Technology Trials

Customer Behaviour

Trials

Residential SMEs

Prepayment Market Model

Micro Generation

AnalysisCost Benefit

Analysis


36

Overall, project progress has been very positive with all key milestones having been achieved. The main highlights to date have been the:

Completion of the electricity customer behaviour trials (CBT) for residential

and SME customers in December 2010 and completion of associated analysis and reporting in April 2011, the detailed report of which was published in May 2011 (CER/11/080a).

Completion of the electricity technology trials in September 2010, the detailed report of which was published in May 2011 (CER/11/080b).

Completion of the ‘smart prepayment’ trial in February 2011, the findings of which are included in the electricity CBT report (CER/11/080a).

Completion of the electricity cost-benefit analysis in April 2011, the detailed report of which was published in May 2011 (CER/11/080c).

Completion of the gas customer behaviour trials (CBT) for residential and SME customers in May 2011 and completion of associated analysis and reporting in September 2011, the detailed report of which is published alongside this CBA (CER/11/180a).

Completion of the dual fuel technology trials in May 2011, the detailed report of which is published alongside this CBA (CER/11/180b).

Completion of the gas cost-benefit analysis in September 2011, the subject of this report (CER/11/180c).

Further detailed information on the CER Smart Metering Project and its progress to date is available via the consultation papers and information papers that have been published on www.cer.ie. Smart Metering Information Paper 5 – CER/11/180 – 11th October 2011

- Gas Smart Metering Customer Behaviour Trial (CBT) Findings Report – CER/11/180a – 11th October 2011

- Dual Fuel Smart Metering Technology Trial Findings Report – CER/11/180b – 11th October 2011

Smart Metering Information Paper 4 – CER/11/080 – 16 May 2011 - Electricity Smart Metering Customer Behaviour Trials (CBT) Findings

Report – CER/11/080a – 16th May 2011 - Electricity Smart Metering Technology Trial Findings Report –

CER/11/080b – 16th May 2011 - Electricity Smart Metering Cost-Benefit Analysis (CBA) Report –

CER/11/080c – 16th May 2011 Smart Metering Consultation Papers and Responses:


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- Responses to Consultation Paper 2 – CER/11/033 – 18th February 2011 - Consultation Paper 2 – CER/10/197 – 11th November 2010 - Responses to Consultation Paper 1 CER/10/161 – 9th September 2010 - Consultation Paper 1 – CER/10/082 – 11th June 2010

Other Smart Metering Information Papers:

- Information Paper 3 - CER/09/186 - 7th December 2009 - Information Paper 2 - CER/09/118 - 31st July 2009 - Information Paper 1 - CER/09/024 - 6th February 2009

Other CER publications at this same Website location relating to smart metering which may be of interest are:

Approved Smart Metering CBTs Gas Tariff – published 1st April 2010 Approved Smart Metering CBTs Electricity Time of Use (TOU) Tariffs –

original published 2nd October 2009 and renewed 7th September 2010 Arrangements for Micro Generation Decision and Response to Comments

Received (CER/07/208) – 20th Nov 2007 Smart Metering - The Next Step in Implementation (CER/07/198) – 5th Nov

2007 Demand Side Management and Smart Metering Consultation Paper

(CER/07/038) - March 2007

1.6 Structure of This Paper This paper details the results of the cost-benefit analysis (CBA) for a national rollout of gas smart metering in Ireland. It is structured in the following manner:

Section 2.0 gives an overview of the structure of the quantifiable gas CBA.

Section 3.0 outlines the quantifiable costs and benefits included in the CBA for the gas network operator and the incremental costs for the electricity network operator.

Section 4.0 outlines the quantifiable costs and benefits included in the CBA for gas suppliers/shippers.

Section 5.0 outlines the quantifiable costs and benefits included in the CBA for customers.

Section 6.0 outlines the results of the cost-benefit analysis for quantifiable effects, including sensitivity test results.

Section 7.0 outlines other potential costs and benefits which were not included in the quantifiable effects but are described on a qualitative basis.

Section 8.0 outlines the conclusions and next steps.

Appendix A outlines a glossary and acronyms used in this paper.


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1.7 Commenting on This Paper This paper is provided as an information source on the results of the cost-benefit analysis (CBA) for a national rollout of gas smart metering in Ireland. Any queries or comments on its contents can be forwarded, preferably in electronic format, to:

Gary Martin Commission for Energy Regulation, The Exchange, Belgard Square North, Tallaght, Dublin 24. E-mail: [email protected]


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2.0 Overview of Quantifiable Gas CBA Structure

2.1 Introduction The introduction of gas smart metering would lead to incremental costs and benefits for the different market participants, i.e. for Bord Gáis Networks (BGN), ESB Networks (ESBN), gas shippers/suppliers and the end-customer. These incremental benefits and costs have been separately calculated for each market participant, and then combined to determine the overall “societal” benefit of a national gas smart metering rollout: Gas customers are assumed to receive additional benefits in the form of both

energy usage and non-usage savings, due to the greatly enhanced consumption data provided by smart metering:

The energy usage savings represent the estimated reduction in the customers final gas bill due to better energy management (arising from the enhanced consumption data), and have been provided from the results of the gas customer behavior trial (CBT) – the detailed findings report for which is available in CER/11/180a. All of the following CBT results used in the CBA are statistically significant against the trial control group at a 90% confidence level: o Savings of 2.2% were achieved by customers who received a detailed

Energy Statement with their bi-monthly bill, i.e. detailed informational and graphical analysis of their historical gas usage;

o Savings of 2.8% were achieved by customers who received a detailed Energy Statement in their monthly bill (i.e. the same detailed information more frequently);

o Savings of 2.9% were achieved by customers who received a detailed Energy Statement in their bi-monthly bill, plus an In-home display (IHD) device (i.e. half-hourly feedback on their gas usage); and

o Savings of 3.6% were achieved by customers who received a detailed Energy Statement in their bi-monthly bill, plus an In-home display (IHD) and a variable seasonal tariff;

The enhanced information should also generate customer time savings due to less complaints and avoided customer meter-reads (arising from the elimination of estimated bills etc); although there will also be additional time costs due to the extra time spent in understanding the enhanced information provided via energy statements and in-home displays, but these costs should be offset by the benefits.


40

BGN would incur additional costs in providing this enhanced information to both the gas shipper and the customers, which will be partially offset by savings from certain avoided activities:

The additional costs will include more expensive smart-meters, accelerated meter replacement programmes (MRPs), programme management costs and investments in new IT systems and associated business processes:

o A new central Meter Data Management System (MDMS) and web-based data-portal would be required to manage the huge increase in metering-data, plus all the alarms and events generated by smart-meters etc; and

o The existing market systems may need to be upgraded as well for smart metering, i.e. the Customer Information System (CIS), market-messaging etc;

Smart metering would also generate savings through the avoidance of certain activities, e.g. a large reduction in meter-reading, meter-lock/unlock and meter exchange activities, delayed system reinforcement, plus reduced fuel-gas requirements and theft of gas etc;

ESBN would also incur additional costs due to the assumption that gas smart

meters will leverage the electricity smart metering communications infrastructure. Although the cost of the wide area network (WAN) communications and home area network (HAN) are assumed to be already largely sunk in the electricity rollout, there will be some incremental costs associated with “back-hauling” the gas data over the WAN and storing it in the electricity MDMS. These incremental costs have been estimated by ESB Networks (ESBN), and included in the gas CBA.

Shippers/suppliers would also incur additional or incremental costs that may be offset by savings, in the form of reduced cost to serve for their customer base:

The reduction in the cost to serve arises from the assumed reduction in customer complaints and queries, enhanced debt-management and lower customer capture and switching costs; and

The additional costs will include additional bill printing costs (particularly in a monthly billing scenario) and investment in new IT systems and associated business process (however, these should only be incremental costs for existing dual-fuel energy suppliers).

Figure 11 below gives an overview of the main cost and benefit categories for different market participants as covered in the quantifiable CBA.


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Figure 11: Overview of Gas CBA Structure

Gas CBA

Network

Network

Costs

Smart Meters

COMM + WAN

IT systems

Network Savings

Meter-read

Siteworks

Lock/unlock

Meter-exchanges

Fuel-gas + theft

Shipper

Shipper

Savings

Reduced Complaints

Improved Debt Management

Improved Competition

Shipper

Costs

Bill Printing

Customer Awareness

Additional IT Systems

Customer

Usage

Energy Bill Savings

Bi-monthly Savings 2.2%

Monthly Savings 2.8%

BiM+IHD Savings 2.9%

BiM+IHD+VT Savings 3.6%

Customer

Non-usage

Reduced Complaints

Reduced dial a meter-read

Increased Learning Time


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2.2 High-level Design and Functional Requirement Assumptions In order to derive the network operator and shipper/supplier based costs and benefits associated with a national gas smart metering rollout a number of assumptions regarding the high level solution design and implementation approach were made. These assumptions were developed by the CER via the Smart Metering Project industry forums and finalised via a public consultation process which started in June 2010 and concluded in January 2011. The consultation papers and associated responses received are available on www.cer.ie :

Responses to Consultation Paper 2 – CER/11/033 – 18th February 2011 Consultation Paper 2 – CER/10/197 – 11th November 2010 Responses to Consultation Paper 1 CER/10/161 – 9th September 2010 Consultation Paper 1 – CER/10/082 – 11th June 2010

The final high level design and implementation assumptions that were used in this CBA are broadly the same as were laid out in the Consultation Paper 2 (CER/10/197). After taking into account the feedback received from respondents to this consultation the CER did not see any reason to change any of the assumptions underpinning the CBA outlined in the paper. CER/10/197 detailed the national smart metering rollout assumptions regarding:

Functionality and performance requirements. High level overview of system architecture (including meter,

communications layer and back-end IT systems). Implementation approach and timetable.

The following sub-sections give an overview of the key assumptions made in each of these areas that underpin the network operator and supplier costs and benefits in the CBA. Some of these high level assumptions have been elaborated, beyond the detail of what was outlined in consultation process, for the purposes of estimating cost and benefit values for the CBA. However, it should be noted that this is without prejudice to the requirements and technology choices that would have to be developed and made via a design and public procurement phase of any full rollout project.

2.2.1 High-level Design Assumptions The gas CBA is premised on the following high-level design assumptions and principles. The most important principle is that the gas smart metering rollout is assumed to be incremental to any electricity smart metering rollout (i.e. it will be part of a “dual-fuel” rollout): The electricity meter will act as the utility communication-hub for the home;


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The gas meter will communicate with the communication-hub using a Low Powered Radio (LPR), based on the ZIGBEE (2.4 GHz) protocol;

The electricity meter communication-hub will cache or temporarily store the gas data, and forward the data to both the IHD and the electricity meter data management system (MDMS) at the required intervals;

The electricity MDMS will in turn send the gas related data to the gas MDMS and then onwards to the customer information system (CIS) for validation and processing in accordance with the required market processes, which include:

Storing the hourly interval smart metering consumption data and summarising it into the required format for market processing purposes;

Volume conversion (to standard conditions) and energy conversion for billing purposes; and

Executing shipper requested services, e.g. reconfiguring meter from credit to PPM, remotely locking and unlocking the meter etc.

BGN will make the data available to shippers through the specified market-messaging systems. BGN will also separately make the data available to both gas shippers and customers through a web-based data-portal (in an agreed format). Although the data-portal will be separately managed by BGN, it has been assumed that it will be linked to the ESBN data-portal (so that the customer sees a “seamless” dual-fuel portal). The high-level system architecture is summarised in Figure 12. The gas smart-meter will communicate to the BGN back-office systems via the ESBN WAN. The BGN back-office systems will include: The BGN MDMS and market-facing CIS systems, which will manage and

process the smart metering data, alarms, events, firmware upgrades and shipper requested services;

Business to Business (B2B) interfaces between the BGN MDMS and both the ESBN MDMS system and web-based data-portal; and

Various internal Application to Application (A2A) interfaces between the BGN MDMS and other BGN systems, e.g. MAXIMO asset management, Geographical Information System (GIS), work-scheduling systems (e.g. “click-scheduler”) and market-messaging systems.


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Figure 12: High-level system architecture overview

1MAM = Meter Asset Management (MAM) system, i.e. the BGN MAXIMO system 2CIS = Customer Information System (CIS), i.e. currently the BGN Integrated Utility System (IUS) 3OMS = Operational Meter System

2.2.2 Functional Requirements Assumptions As discussed previously it is assumed that the electricity meter and communication-hub will simply cache or temporarily store the gas data, and that all of the gas related calculations will be carried out in the gas meter itself. This means that the gas meter will be required to: Record the actual volume of gas consumed in m3 and potentially the

Temperature Compensated (TC) volume as well (depending on the final specified smart metering functionality);

Perform an “indicative” energy conversion using a representative Gross Calorific Value (GCV) received from the BGN MDMS via the WAN;

Calculate the equivalent “interval” consumption data for the customer in both energy and monetary terms, for display on their IHD (i.e. to display their consumption in both kWh and € terms)

In Home Display

Local Area Networks

Electricity Smart Meter

Gas Smart Meter

Head End Data

Collector 1

Head End Data

Collector 2

Head End Data

Collector n


System


System

GIS MAM OMS

BGN Managed Systems

CIS

Gas Shippers

End Customers

B2B Integration

Customer Premises

Wide Area Networks

B2B Integration

Industry Portal

A2A Integration

Market Systems

A2A Integration

Meter Data Collection

ESBN Responsible for provision

BGN Responsible for provision

Joint Responsibility for provision


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It is assumed that the gas meter will calculate hourly interval data for the purposes of the CBA, i.e. that the IHD will display the customer’s hourly kWh gas consumption. It is further assumed that the meter will support both PPM functionality and remote operation of the integrated-valve (subject to safety requirements). Finally there is likely to be additional requirements in terms of data-storage etc. It is envisaged that the above functionality will be delivered through a base-meter and communications module (see Figure 13). The base-meter will perform the basic metrological measurement functions, and will also include an integrated-valve and a temperature-sensor (or equivalent device). In this architecture the communication module would include: The Low Power Radio (LPR) to communicate with the communication-hub in

customer’s home (i.e. in the electricity-meter);

The “intelligence” and processing-power to support the energy-conversion, interval-calculations, PPM functionality and data-storage requirements etc; and

The interface with the base-meter (which would contain the metrological measurement components).

Figure 13: High-level overview of meter functional requirements

Gas Meter

Base-meter

Volume Registers (m3)

Integrated Valve

Temperature Sensor

Communication Module

LPR Radio Intelligent Processing

Energy Conversion

Generate Interval data

PPM Functionality Data-storage

Alarm & event Management


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It should be noted that the above communications functionality could be delivered using an integrated or modular smart-meter design, with the final choice of technical architecture being determined by the outcome of the competitive tender-process. Due to the practical difficulty in providing a real-time GCV to the gas meter, it is assumed that the final energy conversion for billing purposes will be carried out in the BGN back-office market processing systems (and that the IHD will only display an indicative value): The GCV is currently calculated over a 24-hour period and is not available

until after the end of the gas-day and, therefore, it would not be available within the gas-day to do a real-time energy conversion at the gas meter; and

It will be more practical to resolve technical issues in a back-office system rather than on the meter itself (e.g. if there is no real-time GCV available due to a communication outage).

It is assumed that the interval data generated by the gas-meter will be cached by the communication-hub and only transmitted back to the BGN MDMS once per day (via the ESBN WAN system). It is further assumed that the ESBN WAN will be able to support on-demand meter-reading, remote disablement and re-enablement services, firmware upgrades and periodic broadcasting of the GCV value.

2.2.3 PPM Meter Solution It is assumed that the gas smart meter will be able to support both Pre-Payment Metering (PPM) and Pay As You Go (PAYG) metering services, and that the smart meter will continue to hold the “electronic purse” (i.e. the customer’s pre-paid credit balance will be stored on the meter). Smart metering will potentially open up new technological solutions for communicating the customer’s pre-paid credit balance to the electronic purse on the gas meter. Currently customers purchase credit at an approved retail outlet on their vending card, and then insert the card into the meter. The introduction of smart metering means that it will be both possible and practical to move away from the gas card technology and the associated Quantum back office, and communicate the customers pre-paid credit balance directly to the gas meter using the WAN infrastructure. This will have a number of major implications and advantages for the provision of PPM and PAYG services. In future there will be no physical distinction between a credit and a PPM meter, with any change of billing status being managed remotely by the smart metering infrastructure.


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The major advantage of this approach is that it will no longer be necessary to physically exchange a credit meter for a PPM meter (and vice-versa), when there is a change to the customer’s billing status. The following additional assumptions have been made for the gas CBA: That it will be possible to upgrade the more modern ultrasonic PPM meters to

a fully smart meter, by replacing the existing PPM module with a fully-smart communication module;

That the older token and smart card PPM meter population will be replaced by new smart meters; and

That the existing Quantum back office PPM infrastructure will be gradually phased out over the rollout period, and that all PPM meters will be migrated to a new smart PPM infrastructure by the end of the rollout period (i.e. by 2018).

The final form of the smart PPM solution will obviously need to be agreed by all of the relevant industry participants, including the gas shippers, suppliers, BGN and the CER. The above approach based on maintaining the electronic-purse on the meter will provide maximum rollout flexibility for BGN. If the industry adopts a “thinner” PPM model where the electronic purse is actually held in a shipper back-office system (and only disable and re-enable instructions are sent via the WAN system), then the PPM functionality on the meter is simply not used.

2.2.4 Remote Re-enablement of the Meter Although smart metering will make it technically possible to remotely re-enable the gas meter (i.e. to reopen the gas valve), it is still assumed that the customer will have to be present at the meter in order to restore gas supply for safety reasons. The customer will have to confirm that all gas appliances have been switched off by physically pressing a sequence of buttons on their meter (or at least on their IHD), before the integrated-valve will reopen and restore gas supply. The role of smart metering will be for the customer’s shipper to confirm that they are happy for the gas supply to be restored, by sending an instruction down through the WAN system. The smart-meter will not allow the customer to physically restore the gas supply, until it has received this instruction.


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2.3 Gas CBA Options The gas CBA analysis will vary according to the different meter deployment and energy savings assumptions, and the underlying counter-factual “business as usual” scenario. A scenario based approach has been used to assess the impact of the different assumptions, based on: Two separate meter deployment scenarios, i.e. “fast” and “phased” meter-

deployment scenarios:



Four separate energy saving scenarios depending on the type of customer stimuli deployed in a national rollout (based on Gas Customer Behaviour Trial Findings – CER/11/180a).

The structure of the gas CBA analysis is summarised in Table 6 which outlines the different combination of meter rollout and energy saving scenarios that make up the 8 national gas smart metering rollout options analysed in the quantifiable CBA model. The NPV of the costs and benefits for each category of ‘market participant’ are separately calculated, and then combined to derive a total NPV for each option. Table 6: Gas CBA Options No. Energy

Saving Scenario

Meter Rollout

Scenario

Network NPV

(€’000)

Shipper NPV

(€’000)

Customer NPV

(€’000)

Total Gas CBA

NPV (€’000)

1F Bimonthly ES Fast 1S Bimonthly ES Phased 2F Monthly ES Fast 2S Monthly ES Phased 3F Bimonthly ES + IHD Fast 3S Bimonthly ES + IHD Phased 4F Bimonthly ES + IHD

+ Variable Tariff Fast

4S Bimonthly ES + IHD

+ Variable Tariff Phased

(ES=Energy Statement; IHD = In-home Display)


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2.4 Gas CBA Scope and Calculation Assumptions

2.4.1 Scope of the Gas CBA The scope of the gas CBA covers all gas customers in the G4 meter category i.e. all residential customers and some non-residential customers (mainly small business e.g. dentists, hairdressers). The G4 metered non-residential customers (circa 2% of G4 meter customers) are included in the CBA for all impacts apart from customer usage-related benefits. This is because the gas CBT did not consider non-residential customers and therefore no statistically significant results are available to use for them. Larger SMEs, industrial or commercial gas customers that are in non-G4 gas meter categories are out of scope of this CBA. A small empirical study of approximately 50 of the larger non-daily metered SMEs (non-G4) was conducted alongside the residential gas customer behaviour trial. However this was a non-experimentally designed study and the findings are thus not statistically robust and therefore cannot be included in the CBA. These findings are available in the SME section of the Gas CBT report (CER/11/180a) published alongside this gas CBA report.

2.4.2 Key Calculation Assumptions As discussed above the costs and benefits of smart metering for each market participant will be calculated on a discounted cash-flow or net present value (NPV) basis. The NPV calculations will be based on the following high-level assumptions: The NPV calculation will be based on the cash-flows for the period from 2011

to 2032 inclusive;

It is assumed that any smart meter rollout will commence in 2015 (for both the fast and phased deployment scenarios), but programme rollout costs will commence earlier (from Q3 2011); and

The NPV of the cash-flows were calculated using a real discount rate of 4.0% (i.e. the same as used in the electricity CBA analysis25 with sensitivity tests being run to understand impact of higher discount rates).

25 ESRI recommendation as per Dunning (2007) and Public Expenditure and Reform (2011) Dunning, A., 2007, “Re: (i) Procedures for carrying out spot checks for compliance with the General Conditions of Department of Finance Sanction for Multi-Annual Capital Envelopes and (ii) Revision of Test Discount Rate for cost-benefit analysis and cost effectiveness analysis”, Letter, 15 May. www.finance.gov.ie/documents/publications/other/CApraisspotcheckguidance.pdf Department of Public Expenditure and Reform, 2011, Project Discount and Inflation Rates, Web Page, Accessed on 12 September 2011. http://per.gov.ie/project-discount-inflation-rates/


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As noted previously the CBA assessment is based on a simple NPV analysis of the “pure” cash-flow differential between the counter-factual and smart-meter scenarios. It does not take account of financial depreciation or meter write-down costs (e.g. associated with early retirement of G4 diaphragm meters in the fast rollout scenario).

2.5 Structure of Remaining Document The remainder of this document is structured into the following sections, which separately analyse the relevant cost and benefits for the different market participants: Networks Quantifiable costs and benefits; Shipper/Supplier Quantifiable costs and benefits; Customer Quantifiable costs and benefits;

Quantifiable CBA Results and Sensitivities Qualitative Analysis Conclusions and Next Steps


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3.0 Quantifiable Costs and Benefits for Networks

3.1 Introduction A key component of the cost-benefit analysis (CBA) of a national gas smart metering rollout is the distribution network operator related costs and benefits. Currently in Ireland Bord Gáis Networks is the sole entity responsible for owning and managing the gas distribution network and it is licensed and regulated by the CER. Part of Bord Gáis Network’s remit is the installation, maintenance and ownership of all gas metering assets. It is also responsible for the collection of data from the meters and meter operation. A move to smart metering would fundamentally change this part of Bord Gáis Network’s functions. Thus, for the purposes of compiling the CBA, Bord Gáis Networks was requested by the CER to provide smart metering related costs and benefits in accordance with the national smart metering high level design and implementation assumptions, which had been developed by the CER via the Smart Metering Project industry forums and a public consultation process. Refer to Section 2.2 for the high-level smart metering design and functional requirements assumptions that underpin the network costs and benefits. Also, as outlined in section 2.2, because it is assumed that gas smart metering leverages the electricity smart metering communications infrastructure, there would be an incremental cost impact on this infrastructure for facilitating gas smart metering data transfers. Thus ESB Networks was also requested by the CER to provide incremental costs for the electricity smart metering interface. The methodology used to derive the network operator costs and benefits required Bord Gáis Networks and ESB Networks to provide detailed submissions of its costs and benefits under ‘fast’ and ‘slow’ (phased) national smart metering rollout scenarios and also under one counterfactual scenario (i.e. non-smart metering business-as-usual scenario). These detailed submissions provided by Bord Gáis Networks and ESB Networks were reviewed and validated, via a number of iterations, by the CER and also by independent consultants Frontier Economics. The finalised network related costs and benefit included in the gas CBA model are outlined in the sub-sections that follow under the following headings:

Networks Related Costs: o Meter Capital Costs (Section 3.2.1) o Smart Communication Module Failures (Section 3.2.2) o Smart Metering IT Systems Costs (Section 3.2.3) o Electricity Smart Metering Interface (Section 3.2.4)


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Networks Related Benefits: o Meter Reading (section 3.3.1) o Siteworks Savings (section 3.3.2) o Meter Exchanges (section 3.3.3) o Prepayment - Meter Exchanges and Operations (section 3.3.4) o Fuel Gas Savings (section 3.3.5) o Revenue Protection - Theft of Gas (section 3.3.6) o System Reinforcement (section 3.3.7)


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3.2 Networks Related Costs This section outlines and describes the key network operator related cost elements included in the smart metering rollout scenarios of the CBA. These are broken down into the following broad categories:

Meter Capital Costs (Section 3.2.1): o Meter Purchase o Asset Life and Battery Replacement o Meter Installation

Smart Communication Module Failures (Section 3.2.2)

Smart Metering IT Systems Costs (Section 3.2.3):

o Meter Data Management System (MDMS) o Web-Based Data Portal o IT Deployment Support o Market Systems o Programme Management

Electricity Smart Metering Interface (Section 3.2.4):

o Incremental Capital Costs o Incremental Operational Costs

These cost assumptions were arrived at by the CER after comparing costs submitted by BGN and BGN with international benchmarks and information provided by Frontier Economics as part of their review. Some points to note from the Frontier review are outlined in the sub-sections that follow.


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3.2.1 Meter Capital Costs The meter purchase, installation and battery replacement cost assumptions are summarised in Tables 7 - 10 (below) for both the fast and phased smart meter rollout and counterfactual (base case) scenarios, and for both the installation of a fully-smart meter and retrofitting a communication module to a smart-ready and PPM meter. These cost assumptions are discussed in the sub-sections that follow. Table 7: Meter Capital Costs - Fast Rollout Scenario Meter Capital Costs (€/meter) - FAST SCENARIOS

Purchase Installation Battery change TOTAL

New traditional - Base case only 38.00 93.00 0.00 131.00 Traditional smart-ready credit meter 52.00 93.00 0.00 145.00 Traditional PPM meter 120.00 116.00 24.00 260.00 Fully smart meter - no IHD 87.00 83.50 18.00 188.50 Fully smart meter - with IHD 97.00 83.50 18.00 198.50 Retrofit E6V module - no IHD 35.00 38.32 24.00 97.32 Retrofit E6V module - with IHD 45.00 38.32 24.00 107.32 Retrofit PPM module - no IHD 35.00 52.41 0.00 87.41 Retrofit PPM module - with IHD 45.00 52.41 0.00 97.41

Table 8: Meter Capital Costs - Phased Rollout Scenario Meter Capital Costs (€/meter) - PHASED ROLLOUT SCENARIOS

Purchase Installation

Battery change TOTAL

New traditional - Base case only 38.00 93.00 0.00 131.00 Traditional smart-ready credit meter 52.00 93.00 0.00 145.00 Traditional PPM meter 120.00 116.00 24.00 260.00 Fully smart meter - no IHD 87.00 104.00 18.00 209.00 Fully smart meter - with IHD 97.00 104.00 18.00 219.00 Retrofit E6V module - no IHD 35.00 38.32 24.00 97.32 Retrofit E6V module - with IHD 45.00 38.32 24.00 107.32 Retrofit PPM module - no IHD 35.00 52.41 0.00 87.41 Retrofit PPM module - with IHD 45.00 52.41 0.00 97.41


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As outlined back in section 2.4 two separate meter deployment scenarios, i.e. “fast” and “phased” meter-deployment scenarios are analysed in the CBA:

Fast rollout: in this case all smart meters would be installed in four-years, 2015 to 2018 – Table 8 below outlines the deployment assumptions; and


Table 9: Smart Meter Rollout Schedule - Fast Scenario

2015 2016 2017 2018

Percentage deployed 20% 30% 30% 20% The CBA model also used the 2011 gas meter status population outlined in table 9 below as the basis for meter numbers. Table 10: Gas Meter Population in 2011

G4 Mechanicals

577,027 New traditional G4 (E6SR) 16,759 PPM G4 mechanical

10,016

PPM E6SR

23,944 Smart Meter

0

Meter Purchase Costs The ‘new traditional – base case only’ credit meter purchase cost assumption

is based on a traditional gas diaphragm meter continuing to be installed on a replacement basis in the counterfactual scenario.

o BG Networks indicated that, even in the absence of a planned smart meter rollout, its intention is to replace the traditional mechanical G4 meters with E6V meters, as this is a more reliable technology (for example, the meter keeps its accuracy over time, compared with a mechanical G4).

o On reviewing this assumption it was noted however that the use of this technology does not seem necessary in the counterfactual scenario, where smart meters are not going to be installed. In this case, therefore, a cheaper diaphragm meter is assumed.


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o The price of €38 assumed for a traditional diaphragm meter is broadly in line with international experience. For example, in the Netherlands a traditional gas meter was estimated to cost €30.

The ‘Traditional PPM meter’ purchase cost assumption is based on a Libra PPM meter that can be retrofitted with a communication module to become a smart meter. This type of meter includes a card reader, which accounts for most of the cost difference compared to the credit meter solution.

The smart metering solution assumed is based on the E6V smart-ready meter with an additional Zigbee communication module plugged in. The module is assumed to cost €45 for the ‘with IHD’ smart metering rollout scenarios and €35 in the absence of an IHD:

o The €45 ‘with IHD’ communication module is based on Zigbee technology and is expected to: (1) carry out the required calculations to convert gas consumed into kWh and apply the relevant tariff and (2) transmit this information to the electricity meter to be relayed to the WAN and to be displayed on the IHD (when available).

o It is assumed that the more expensive €45 communication module is needed only when an IHD is installed. In the other cases, a slightly cheaper communication module, at a cost of €35 is assumed to be used instead to reflect the fact it would not need to be capable of undertaking the tariff calculations (although it would be capable of firmware upgrades). It is noted that the choice of a cheaper technology will make any subsequent introduction of IHDs costly, as all communication modules would need to be replaced at that time.

It is assumed that there is no difference in meter purchase costs between the fast and phased rollout. This is because, while in the fast rollout BGN could benefit from bulk purchase discount, in the phased rollout it would benefit from the metering technology getting cheaper over time.

The retrofit solution is the same cost for both credit and PPM customers as it involves adding a communication module to an existing E6V meter (for credit customers) or a Libra PPM meter (for pre-payment customers).

Asset Life and Battery Replacement Costs There is considerable uncertainty regarding the life of ultrasonic meters as

they are a relatively new technology. The CBA model assumes a smart meter average asset life of 17 years. This is in line with the electricity CBA which has assumed an asset life of 15-20 years. The assumed E6V solution is modular and the ultrasonic meter component has a lower level of complexity than a fully integrated smart meter and therefore may be more durable. Moreover, the CBA captures the failure rate of the communication module separately.

The CBA model assumes that batteries will be replaced after 10 years (either of the meter becoming smart or, in the case of a PPM, when it is first installed). This is a conservative assumption as, based on analysis being undertaken as part of the British rollout, a battery should last up to 15 years


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providing the gas meter is not required to provide information to the IHD more than once every 15 minutes. However, it would probably make most operational sense to swap the battery at the mid-point of the life of the meter if it is not expected to last the full 20 years of the meter.

The CBA model assumes the following in relation to battery replacements for smart meters:

o The replacement activity itself will cost approximately €12, assuming it can be completed as part of a planned programme of work.

o The battery will cost approximately €6. o The replacement period is assumed to be 10-years for the current E6V

smart-ready meters and also for a new smart-meter. o The battery change cost for an E6V “upgraded” smart-meter would be

€24 every 10 years (as 2 x batteries are required, 1 for the base-meter and one for the smart-module).

o The battery change cost for a new smart-meter would be €18 every 10 years (as most new designs only require 1 x battery).

Meter Installation Costs The meter installation costs included in the CBA, for both the counterfactual

and the smart metering scenarios, exclude costs related to overheads and safety modifications.

The installation of a traditional diaphragm meter and a newer ultrasonic meter would generally cost the same. International literature reports installation costs for traditional gas meters of around €40 - €60. However, the CBA model recognises the need to reflect the actual costs that BGN incurs in the Irish market. At present, the contractor rate that BGN pays is about €93 per installation, which is therefore the assumed cost used in the CBA for installation of a traditional credit meter in the counterfactual scenario. The other installation costs are then calculated against this benchmark to try to ensure that the relativities between the different installation costs are consistent between the different scenarios.

The CBA model assumes higher installation costs for traditional PPM meters. In its impact assessment in Britain, DECC (Department of Energy and Climate Change) has assumed the installation cost for a traditional gas PPM meter to be about 25% higher than the installation cost for a credit meter. This provides an assumed installation cost of €116 per meter.

The CBA model assumes an installation cost for a fully smart meter of €83.50 in the fast rollout and €104 in the phased rollout – these values were derived as follows:

o A 10% increase was applied to the regulated meter installation cost of €93 to allow for increased installation time to install a smart meter. This gives a cost of €102.30.

o It is assumed that a 20% volume discount would be achievable in the fast rollout, making the cost of a smart meter install €81.80. However,


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in the phased rollout, this discount is unlikely to arise and so the cost would still be €102.30.

o Finally the installation cost assumption also includes an additional charge of €1.70 for revisit costs to resolve meter installation problems. This has been calculated by assuming that it will be necessary to revisit 3.5% of sites at a cost of €50.

o Looking at international comparisons for gas smart meter install costs, Austria used a range between €20-70, France €36, Belgium €54 and Britain €56. However, as noted above, the key issue for the CBA is to ensure the relative costs of installing smart and traditional meters are correct. Thus the CBA assumes values calculated from BGN’s current traditional meter installation cost.

The CBA model assumes that the smart metering solutions allow the retrofitting of the communication module to be carried out by relatively low-skilled labour, as the module can be added without taking the meter out of service. It is noted however that this assumption carries some risks as it is possible that a certain number of these installations may require more work.

The retrofitting of a PPM meter is essentially the same as the retrofitting of an E6V meter. However, the CBA model includes an extra allowance in the PPM retrofit cost for a proportion of older PPM meters which will require additional pipe work modifications required to accommodate the communication module.


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3.2.2 Smart Communication Module Failures These costs refer to communication module failures once smart meters have been installed. They are not costs associated with revisits during the installation process, as these costs are already included in the assumptions made in section 3.2.1 above, as well as in ESB Network’s electricity smart metering interface cost assumptions, section 3.2.4 below. Table 11 below gives an overview of the smart communications module failure costs assumptions included in the CBA model. Table 11: Smart-communication module failure assumptions

The CBA model assumes that each time the communication module fails this

will require a site visit and that the failure rate is 1%, which is in line with what has been assumed for the electricity CBA (which assumed the same communication technology i.e. Zigbee). This is in line with the Dutch CBA which assumed a failure rate of about 1%.

The CBA model has assumed that in 40% of cases it will be necessary to replace the communication module. This is in line with the Dutch CBA which assumed a replacement rate of between 20% and 50%.

The cost of a communication module for replacement is assumed to be consistent with the costs outlined for communication module purchases in section 3.2.1 above, i.e. €45 for ‘with IHD’ options and €35 for ‘without IHD’ options.

The CBA model assumes a cost of €60 for a site visit related to smart communication module failures. These visits would be undertaken on an ad-hoc basis, without the benefit of a field force already deployed and they would also require some additional time spent for problem diagnostics. Therefore the value used in this case is assumed to be higher than the assumption made for the installation of a fully smart meter and also for the retrofitting of smart-ready meters. However, the value is lower than the assumption made for the electricity CBA, as the technical solution (modular E6V meters) should allow a relatively less skilled-labour intensive replacement of the communication component.


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3.2.3 Smart Metering IT Systems Costs This section outlines the CBA assumptions on the incremental smart metering IT systems costs that Bord Gáis Networks (BGN) will need to bear to support the introduction of gas smart meters. It does not include the additional incremental communication and meter data management system (MDMS) costs that ESB Networks (ESBN) will need to bear to support the introduction of gas smart meters, which is addressed later in Section 3.2.4. The introduction of smart metering will obviously lead to a huge increase in the volume of gas metering data to be validated and processed by BGN for market-settlement purposes. It will also lead to new functional requirements including: Extracting the gas smart metering data from the ESBN head-end and MDMS

systems, and storing the smart metering interval data;

Validating the data and converting it into the required format for the market-processing systems (e.g. summarising the data into daily, monthly data-formats etc);

Processing, filtering and prioritising the alarm and event data, and forwarding it to asset management and work-order systems for follow-up actions (as required);

Executing shipper requests, e.g. remote disablement of meters, and re-enablement of “locked meters”, change of billing status (i.e. switch from credit to PPM);

Managing set-up and configuration data for the gas smart meter, e.g. deploying firmware upgrades, updating shipper tariff data as required etc; and

Ensuring that the gas meter database is kept up to date and fully synchronised with the corresponding ESBN electricity meter communication hub database (for device authentication, data protection and work-management purposes).

It will be necessary for BGN to purchase a separate MDMS system to manage all this additional functionality for gas meters, and to integrate it with both the ESBN MDMS system and the gas market systems using: B2B (business-to-business) interfaces between the ESBN and BGN MDMS

systems, and the BGN MDMS and the web-based data portal; and A2A (application-to-application) interfaces between the BGN MDMS and the

market facing CIS and market messaging systems, and between the BGN MDMS and asset management systems – i.e. MAXIMO and GIS etc.

It will also be necessary to implement a web-based data portal to allow customer access to the gas smart metering data. Finally it will be probably necessary to implement a new CIS system to replace the existing IUS legacy system, i.e. it


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would be more cost-effective to build a new system to deliver the smart meter functionality rather than upgrading an old legacy system. The detailed smart metering IT systems costs assumptions are outlined under the categories below in the followings sections:

MDMS Web-Based Data Portal IT Deployment Support Market Systems Programme Management

Table 12 below gives an overview of the smart metering IT systems costs assumptions included in the CBA model. Table 12: Smart metering IT systems - All Scenarios

Capital cost

Opex

Total licence costs

2.5 €/meter (one-off)

0.5 €/year/meter MDMS Licence fee

1.5 €/meter (one-off) 0.3 €/year/meter

Hardware and application support cost 8,560,000 € (one-off)

121,904 €/year

System implementation 4,000,000 € (one-off)

€/year System hardware

3,360,000 € (one-off)

€/year

A2A Interface

1,200,000 € (one-off)

€/year Other CIS OPEX (Application and hardware support) € (one-off)

0 €/year

Other MDMS OPEX (Application and hardware support)

€ (one-off)

121,904 €/year

Capital cost

Opex

Other costs

5,900,000 € (one-off)

277,142 €/year

Web-based data-portal 1,000,000 € (one-off)

80,000 €/year IT deployment support

1,000,000 € (one-off)

€/year

Market systems

3,900,000 € (one-off)

197,142 €/year


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Meter Data Management System (MDMS) Costs The CBA model assumes the following costs related to MDMS licence fees:

o CAPEX: €1.50 per gas meter. This assumption is based on the MDMS licence costs established through confidential discussion with clients and vendors for the electricity CBA.

o OPEX: €0.30 per gas meter per year. This value has been calculated as 20% of total licence fee (€1.50). It covers ongoing maintenance and support and has been determined through confidential discussions with clients and vendors for the electricity CBA.

The CBA model assumes a gas MDMS system implementation cost of €4m (CAPEX). This figure is within the range identified in the electricity CBA for the implementation of a MDMS of a similar scale (€3m - €6m). The cost incorporates MDMS vendor support, systems integrator costs and internal IT resources. Costs also include the interfaces to the ESB Networks MDMS, data portal and security.

The CBA model assumes the following costs related to MDMS system hardware costs:

o CAPEX: €3.36m, which includes system hardware costs and hardware refresh costs. Hardware costs can vary considerably depending on specification of resilience. The initial hardware investment included in this estimate (€1.86m) is in line with a the value assumed for the electricity CBA, scaled down to reflect the lower number of meters this system will have to support.

o OPEX: €2.56m (€121,904 per annum), which is at the lower end of the range established as part of the review of the inputs to the electricity CBA. This is due to two main reasons. First, the cost of hardware refresh in this case has been assumed to be part of the CAPEX. Second, in the case of gas smart meters, the MDMS acts mainly as a data repository, so it less mission critical: this reduces costs.

The CBA model assumes a cost of €1.2m (CAPEX) for the application-to-application (A2A) interface, which includes the customer interface system (CIS), market messaging systems and asset management systems, such as Maximo and GIS. When combining this cost assumption with the system implementation costs above, it is still within the range established as part of the electricity CBA.

Web-Based Data Portal Costs The CBA model assumes the following costs related to Web based data

portal costs: o CAPEX: €1m for the incremental costs for the Web portal which

assumes that it will be primarily a data-presentation portal and will not support more advanced functionality such as pre-registration of HAN devices etc. This is based on the cost assumed in the context of the electricity CBA and concurs with Web portal costs for similar solutions internationally, based on designing and implementing an “incremental”


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web portal, held on an existing system. The lower initial licence fee associated to the lower number of gas meters for which data is being made available is likely to be offset by the increased complexity of building a single user interface for both gas and electricity.

o OPEX: €80k per year (€1.44m total) for Web portal ongoing costs, which is comprised of €40,000 p.a. of licence costs (20% of the licence element of the total cost), €15,000 p.a. for hardware support and an €22,000 p.a. for an incremental 0.25 FTE (€88,000 p.a.) resource to support the portal’s Web user interface over the corporate IT support. Total amounts to €77,000 p.a., rounded up to €80,000 p.a. to capture some uncertainty surrounding the actual FTE time required.

IT Deployment Support Costs The CBA model assumes a cost of €1m (CAPEX) for IT support of meter

deployment: o This is intended to support the co-ordination of the deployment of gas

meters with electricity meters, as well as for managing the authentication of gas meters.

o The cost includes provision of handheld terminal for the meter installers to support provision of exchange of passwords and systems to support the exchange of passwords and electronic keys between ESBN and BGN. The cost of ruggedized handheld terminals is assumed to be €3,000 each as established in the electricity CBA. A refresh of the handheld technology halfway through the rollout period is assumed, to support business as usual smart meter installations. In total a cost of €0.65m is assumed. There will also be some system costs.

Market Systems Costs The CBA model assumes the following cost allowances for gas market

system changes, which would be required to deal with increased data volumes and to move to a near real-time access to the smart metering infrastructure. BGN have stated that its existing market systems will need replacing, but that the deployment of smart gas meters will bring forward by 2 years that upgrade activity and enhanced functionality. These costs are BGN’s estimate of the incremental costs associated with supporting the move to smart metering.

o CAPEX: €3.9m (€121,904 p.a.) which includes €1/meter initial licence cost for the incremental functionality in CIS to support smart gas meters and €3.3m for system implementation and hardware. These costs compared reasonably with international comparisons.

o OPEX: €4.14m (€197,142 p.a.) which includes application support and hardware support, and assumes annual licence costs of 20% of


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CAPEX, in line with the general commercial approach to costing licences assumed in the CBA.

Programme Management Costs The detailed design, procurement, implementation and rollout of smart-meters and new IT systems will require considerable project and programme management support. It is assumed that a project team will be established to manage the rollout (see Figure 14 below). The project will include a programme management team and various work-streams to manage the following phases of the rollout: Figure 14: Overview of Programme Timetable (Fast Rollout)

Project planning and product selection (assumed 18-months): Refining the

smart-meter business case, developing initial work-plan and schedule, defining requirements and target architecture solution, commencing procurement, technology and system integrator (SI) selection, and negotiating and signing off initial contracts;

Pre-deployment planning: Refining business case (assumed 18-months), work-plan and schedules, commencement of meter and WAN communication testing, finalising technology and SI selection, defining business and market design requirements, field testing of selected technologies, implementing MDMS and other IT solutions;

Deployment (assumed 4-years): Supporting the actual rollout, including full-scale implementation of IT infrastructure and meter rollouts;

Provision for €1.0m has also been made for market-process and Code Modifications, covering the legal drafting of Code Modifications and market assurance testing of the new IT systems.

Planning & Selection

Q4 2011 & 2012

Pre-Deployment Planning

2013 & 2014Deployment

2015 - 2018


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The gas CBA assumes that all of the programme management, planning and selection, pre-deployment and the full deployment costs will be capitalised and charged to the programme costs. Table 13 below details the smart metering programme costs assumptions included in the CBA model. Table 13: Smart metering programme costs assumptions


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3.2.4 Electricity Smart Metering Interface Incremental Costs A fundamental assumption of the gas CBA is that a national gas smart metering rollout leverages the electricity smart metering infrastructure. Section 2.2 provides further details on the gas smart metering high-level design and functional requirements assumptions. The costs of the electricity smart metering infrastructure have already been included in the electricity smart metering CBA (CER/11/080c) and thus are not double-counted in the gas CBA model, which captures only the incremental costs to be borne by the electricity smart metering rollout as a result of facilitating gas smart metering. The CER wishes to emphasise that the regulatory treatment of costs and their attribution to various segments of the industry in this CBA are without prejudice to any findings that may be made in the context of future price control measures or other regulatory actions. This section therefore outlines the CBA assumptions on the additional incremental electricity smart metering communication and meter data management system (MDMS) costs that ESB Networks (ESBN) will need to bear to support the introduction of gas smart meters i.e. costs above and beyond those not already included in the electricity smart metering CBA. These costs are divided into: Capital Costs (CAPEX):

o Electricity meter installation costs o Security and MDMS systems costs o Project and programme costs

Operational Costs (OPEX):

o Wide Area Network (WAN) costs o Additional IT costs o Management of gas related issues and processes o Meter failure costs

Table 14 below gives an overview of the electricity smart metering interface incremental costs assumptions used in the CBA other further details are outlined in the sub-sections that follow.

Table 14: Summary of Costs for interface with electric meters

CAPEX

Zigbee radio in meter

One-off costs

Cost of repeater and additional wiring if indoors 90 € (one-off per meter) Cost of repeater and additional wiring if in apartment block 90 € (one-off per meter)


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Other capex costs (Scenario independent) One-off

costs Costs if gas meter first, than e-meter 0 € (one-off per meter) Head end licence costs

1 € (one-off per meter)

MDMS licence costs

1.5 € (one-off per meter)

# meter independent costs of the programme (scenario independent)

Web portal costs

0 € (one-off total)

Incremental programme cost for co-ordination 1,000,000 € (one-off total) OPEX

Additional WAN costs

0.6 € p.a. per meter

IT costs

Licence support 350,000 total p.a.

Data storage

27,000 total p.a.

ESBN NOC costs PA 360,000 total p.a.

Faulty e-meter on gas meter 35,000 total p.a.

772,000

3.2.4.1 Capital Costs

Electricity meter installation costs The CBA model assumes:

o a cost of €90 for purchase and installation of repeaters if electricity meter is indoors or distant from gas meter.

o that a repeater may only be needed in the case of installations where the electricity meter is indoors or in apartments. Together, these two groups account for about 50% of total installations. It is assumed that 5% of these installations (i.e. 2.5% of the total installed based) will require repeaters.

The CBA assumes that gas smart meters will always be installed after the electricity meter, thus removing the need for ESBN to incur any costs relating to pairing the gas meter with the electricity meter.

Security and MDMS systems costs The CBA model assumes incremental head-end licence costs to support gas

meters of €1.00 per gas meter. o This licence cost is consistent with that used in the electricity CBA

and assumes that ESBN would have to pay a double licence for each


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dual fuel customer supported by its head-end. This is a conservative assumption, as it may be possible to negotiate commercial arrangements based on communication points rather than meters.

o Therefore, a sensitivity test (Test 5) is run assuming an incremental head-end licence cost of €0.75 per gas meter.

The CBA model assumes incremental MDMS licence costs to support gas meters of €1.50 per gas meter.

o Again, this licence cost is consistent with that used in the electricity CBA and assumes that ESBN would have to pay a double licence for each dual fuel customer supported by its MDMS. This is a conservative assumption, as it may be possible to obtain a discount for dual fuel customers.

o Therefore, a sensitivity test (Test 5) is run assuming an incremental MDMS licence cost of €1.00 per gas meter.

Project and programme costs The CBA model assumes an incremental cost of €1m for additional work

required by ESBN for design, procurement, selection and testing to accommodate gas smart metering requirements.

o ESBN has calculated this amount assuming an incremental 10% over its assumed programme costs for the electricity rollout. As the assumed programme costs in the electricity CBA ranged between €8m and €13m, ESBN’s estimate is consistent.

o ESBN has based this value on a high-level assessment of the additional activities that will be required.

3.2.4.2 Operational Costs

Wide Area Network (WAN) costs The CBA model assumes that gas smart meters will imply a 50% extra data

payload on the electricity smart metering wide area network (WAN) communications system. This is based on the assumption that:

o the electricity meter will be polled for consumption data once per day and that the gas data will be collected at the same time.

o the gas data to be collected per day will be: 24 Gas Profile Values, 3 Gas register Values, 1 Gas Event.

As gas meters will generate an extra 50% data payload, the CBA model assumes that communication costs will increase linearly resulting in an assumed incremental operational cost of €0.60 per gas meter.

o This is a very prudent assumption as it may be possible to accommodate the additional data payload within the data allowance that ESBN will purchase from data providers. Thus a sensitivity test is run that assumes no incremental costs (Test 6).


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Additional IT costs The CBA model assumes an additional IT licence support cost of €350k per

annum – this assumption is based on: o an extra 20% of ESBN’s assumed licence support cost per annum for

electricity smart metering - this is in line with licence assumptions throughout the CBA.

The CBA model assumes an additional data storage cost of €27k per annum – this assumption is based on:

o The electricity CBA assumed a cost of €0.70 per meter per annum for data storage. This assumption was based on the requirement to hold meter data for 12 months. For gas meters, the requirement is for ESBN to hold data for 30 days. Moreover, the data generated by the gas meter will be 50% of the data from the electricity meter. Therefore, the cost per meter should be €0.03. As by 2032 ESBN will need to support 891,746 gas smart meters, the annual storage cost then should be about €27,000.

Management of gas related issues and processes The CBA model assumes an additional cost of €360k per annum for

management of gas related issues and processes– this assumption is based on:

o an estimate of 1 FTE per 100,000 meters for an organisation of ESBN’s size which equates to an incremental 6 FTE to support gas meters, and assumes that these can be taken on within the existing business overheads. The incremental cost is based on a marginal salary cost of €60,000 per FTE.

Meter failure costs The CBA model assumes an additional cost of €35k per annum for incurring

extra installation costs (about €5) to pair failed electricity meters ESBN replaces to the gas meter. The assumed electricity meter failure rate (1%) is consistent with the value assumed in the electricity CBA.


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3.3 Network Related Benefits This section outlines and describes the key network operator related benefit elements included in the smart metering rollout scenarios of the CBA. These are broken down into the following broad categories:

Meter Reading (section 3.3.1) Siteworks Savings (section 3.3.2) Meter Exchanges (section 3.3.3) Prepayment - Meter Exchanges and Operations (section 3.3.4) Fuel Gas Savings (section 3.3.5) Revenue Protection - Theft of Gas (section 3.3.6) System Reinforcement (section 3.3.7)

These benefit assumptions were arrived at by the CER after comparing costs submitted by BGN with international benchmarks and information provided by Frontier Economics as part of their review. Some points to note from the Frontier review are outlined in the sections that follow.


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3.3.1 Meter Reading Benefits It is assumed that smart metering will lead to a very significant reduction on the current level of scheduled and non-scheduled manual meter-reading activities. The counter-factual scenario is based on the current meter-reading requirements specified in the Code of Operations and the associated Metering Data Services (MDS) Procedures26. Table 15 below summarises the benefit assumptions used in the CBA model relating to meter reading savings and some points to note follow the table. Table 15: Summary of Meter reading savings

Meter reading unit costs - ALL SCENARIOS

% of

meters Total cost

€/meter

Scheduled reads 1.02 Long-term no access (LTNA) 1.11% 10.99 Non-registered credit meters 0.77% 10.99 Non-vending PPM meter 4.25% 10.99 Special reads (e.g. change-of-shipper) 0.00% 39.50

Meter reading frequency Base case Smart meters

reads/year reads/year

Scheduled reads 4 0.5

Long-term no access (LTNA) 2 0

Non-registered credit meters 1 0

Non-vending PPM meters 1 0

Special reads (e.g. change-of-shipper)

Incremental meter operations costs - SMART METERING SCENARIOS

Number of FTEs required per 100,000 smart meters 1

Annual cost per FTE (€) 60,000

The assumed traditional meter reading costs are based on the costs that BGN

currently incurs for these types of reads. It is assumed that BGN would continue to incur these unit costs in the counterfactual scenario.

26 Meter Data Services Procedures, Version 3.0, December 2008. www.gaslink.ie/files/market_arrange/20090917031037_MeterDataServicesProceduresV3D.pdf


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It is noted that the assumed scheduled read cost for a traditional meter of €1.02 is lower than the assumptions made in other smart metering CBAs. For example, the British impact assessment assumed a cost of €7 per read, while the CBA in the Netherlands assumed a cost per read between €2 and €5. However, the Irish electricity CBA reports a total cost saving of about €8.4m per annum from avoided meter reads in a smart metering scenario. This implies a unit cost per manual read of about €0.70, which is not too dissimilar from the value assumed in the gas CBA.

The meter reading frequencies assumed in the CBA for the counterfactual scenario are as specified in the current Meter Data Service Procedures which is part of BGN’s Code of Operations.

The CBA model assumes that, even with smart meters, properties will still need to be visited once every two years for safety reasons. This assumption is consistent with what has been assumed for the electricity CBA. However, the CBA assumes that smart metering removes the need for network operators to carry out any other meter reads, especially those that are more skilled-labour intensive.

The read percentages for Long Term No Access, Non-Registering credit-meters and Non-Vending PPM-meters are based on the current annual average volume of ‘special’ reads that BGN carries out. The CBA model assumes that these percentages remain constant in the counterfactual scenario.

While the rollout of smart metering will lead to a very significant reduction in manual meter reading activities, it will also generate a huge increase in the volume of metering, alarms and events data. The CBA model therefore assumes that BGN will require a Meter Operations Team, with 1 FTE per 100,000 smart meters deployed. This assumption is consistent with that used for the electricity CBA and is based on a salary of €60,000 per FTE.


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3.3.2 Siteworks Savings Smart metering will support the remote disablement and re-enablement of the meter (subject to safety provisions – refer to section 2.4), therefore, it should no longer be necessary to physically visit the site when locking or unlocking the meter for a shipper. The assumed savings are based on the current published “BGN Network Operations Siteworks Charges” (January 2011)27. Table 16 below summarises the benefit assumptions used in the CBA model relating to siteworks savings and some points to note follow the table. Table 16: Summary of Siteworks Savings

Meter locks/unlocks

70.07 €/lock/unlock 1.51% (un)locks/year (% of credit meter population) Gas supply isolations

740.52 €/isolation 0.025% isolations/year (% of credit meter population)

These siteworks savings figures used in the CBA assume that it is possible to

carry out all locking and unlocking activities remotely once smart meters are installed and this would be facilitated by the implementation of a more rigorous protocol based on:

o more up-to-date vulnerable customers’ register; o introduction of remote communication requirements in advance of

locking (e.g. shipper sending the customer a text – or via the IHD – to warn them of the pending meter lock, giving them a chance to financially settle the bill, or warn of any vulnerable customer considerations).

The % number of siteworks activities per year, by type, have been estimated on the basis of current experienced volume of siteworks activities and regulatory assumptions.

27 BGN NETWORK OPERATIONS Siteworks Charging From January 2011 www.bordgais.ie/networks/media/Siteworks-Charging-20111.pdf


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3.3.3 Meter Exchanges Smart metering is expected to substantially reduce the number of meter exchanges. It is assumed that it will no longer be necessary to exchange the meter, when the customer switches from credit to PPM (and vice versa) - changes to billing status will instead be managed remotely through the MDMS. The overall number of like for like meter exchanges is also expected to reduce. This is primarily because PPM meters currently have a much higher in-service failure rate compared to credit-meters. This is primarily due to: Additional complexity of the PPM module and the potential for software errors

and bugs; Failure or corruption of the gas-card reading device etc.

Smart-PPM will remove the necessity to have a gas-card, which will obviously eliminate one potential source of failure. It is also assumed that it will be possible to remotely download firmware upgrades to smart-meters, which will allow software errors to be rectified without physically exchanging the meter. Remote fault diagnostics support can also be provided for smart-meters from the MDMS system, which should provide better support for field-staff. Table 17 and Table 18 below summarises the benefit assumptions used in the CBA model relating to meter exchange savings and some points to note follow the table. Table 17: Failure rates

Mechanical credit meters 0.5% of traditional meters Mechanical PPM meter

3.5% of traditional PPM meters

E6SR

0.5% of E6SR meters E6FS

0.5% of E6FS meters

Communication module 0.4%

Table 18: Meter exchanges costs Meter exchanges costs Total Purchase Installation Faults €/meter €/meter €/meter PPM to PPM exchange (EXMM) 236.00 120.00 116.00 Credit to credit exchange (EXMD) - Base case 131.00 38.00 93.00 Credit to credit exchange (EXMD) - SM scenarios (smart-ready) 145.00 52.00 93.00 Credit to credit exchange (EXMD) - SM scenarios (fully smart) 201.00 97.00 104.00


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The CBA model assumes the following in relation to meter failure rates: o Traditional diaphragm meters are very reliable and hence a low failure

rate of 0.5% is assumed, which is in line with international experience. o The smart meter failure rate of 0.5% is aligned with those used in the

international literature. For example in the French CBA, the same value has been used, while in the Dutch CBA, the assumed failure rate for smart meters ranges between 0.5% and 1%.

o As smart-ready meters are, in fact, equivalent to smart meters, the same assumed failure rate of 0.5% is used.

o The communication module failure rate and the associated costs are treated separately, refer to section 3.2.2.

o The higher assumed fault rate of 3.5% for the PPM meter for this smart meter is the due to the key interface unit, which is more prone to failure. This assumption is in line with international evidence.

The CBA model assumes the following in relation to meter exchange costs

relating to technical failures: o The purchase and installation costs assumed for the following

exchanges are the same as those outlined earlier for meter rollouts in section 3.2.1: Non-smart PPM for PPM exchange (EXMM) Non-smart Credit for credit exchange (EXMD)

o The Smart Credit for credit exchange (EXMD) meter purchase cost in this case would be the same as the purchase cost during the rollout. However, with regards to the installation cost, the volume discount assumed for the rollout will not apply in this case, as replacements will be done on a case-by-case basis. Therefore the installation cost assumed is that for the phased rollout.


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3.3.4 Prepayment – Meter Exchange and Operations Savings The gas CBA model assumes that the share of residential customers assumed to be on pre-payment tariffs will be as outlined in the Figure 15 below. This assumption is broadly in line with prepayment penetration assumptions used in the electricity CBA. This assumption on gas prepayment penetration applies to both the counterfactual (base case) scenario and all of the smart metering scenarios. The difference is that for new prepayment customers post-2015: The counterfactual scenario assumes that a visit by BGN is required to

replace the customer’s traditional credit meters with a traditional PPM meter. The smart metering scenarios assume that no visit or meter replacement is

required because, as outlined back in section 2.2.3, it is assumed that the gas smart-meter will be able to support both PPM and Pay As You Go (PAYG) metering services, and that the smart-meter will continue to hold the “electronic-purse” (i.e. the customer’s pre-paid credit-balance will be stored on the meter).

Figure 15: Prepayment Penetration Rates Assumed - All Scenarios

3.3.4.1 PPM Exchanges Table 19 below outlines the prepayment churn rate assumptions in the CBA model. These have an impact on the prepayment penetration rates depicted in Figure 15: Prepayment Penetration Rates Assumed - All ScenariosFigure 15 above. Table 19 also outlines the cost assumptions for prepayment exchanges.

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%


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Table 19: Prepayment Churn Rate Assumptions

Churn rate

2011 PPM to credit meter (% of PPM population) 0.0% Credit to PPM before 2015 2.50% Credit to PPM after 2015 in counterfactual 0.06%

Meter exchanges costs Total Purchase Installation Churn €/meter €/meter €/meter Credit to PPM exchange (EXEQ) 236.00 120.00 116.00

The model assumes the following in relation to credit to PPM exchanges

(EXEQ) for all scenarios pre-2015 (full rollout start) and the counterfactual scenario post-2015:

o Before the introduction of smart meters, the credit to PPM exchange would require replacing the existing credit meter with a smart-ready PPM meter. Therefore the same assumption is used for full meter rollout for the installation of a smart-ready PPM meter, for both meter purchase and meter installation (section 3.2.1).

o The annual number of EXEQ exchanges is assumed to be equal to 2.5% of the credit-meter population until end-2014 and 0.6% of the credit-meter population from 2015 onwards.

o In both of the smart rollout scenarios the EXEQ exchanges are assumed to fall away over time, as the new smart-meters will be able to function as either credit or PPM-meters, depending on the meter configuration (and further that it will be possible to re-configure the meter remotely as required).

The annual number of PPM back to Credit meter (EXRQ) exchanges is assumed to be 0% in order to be consistent with the electricity CBA prepayment assumptions. Thus no costs savings are included in the smart metering scenarios for these types of meter exchanges, which would incur costs in the counterfactual scenario if included.

3.3.4.2 PPM Operations The introduction of smart Pre-Payment Metering (PPM) will also lead to the eventual elimination of gas-cards. This will generate savings since it will no longer be necessary to purchase a gas-card and PPM brochure for each new PPM meter, or a replacement stock of PPM vending cards for retail outlets. The savings assumptions included in the CBA are summarised in the Table 20 below and some points to note follow the table.


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Table 20: PPM operations savings assumptions

PPM operations

Cost of PPM vending card

3.50 €/card Cost of PPM brochure

0.00 €/brochure

Replacement PPM vending cards

0.16 cards per PPM meter per annum The CBA model assumes the following in relation to PPM operations savings:

o €3.50 is the cost BGN currently incurs to provide a PPM vending card for each PPM meter it installs. It is assumed that BGN continues to incur these costs in the counterfactual (no smart meters) as well as in all smart metering scenarios in the period leading up to the start of the rollout, after which it represents a saving for the smart metering scenarios.

o Zero savings are included in the CBA model relating to provision of a PPM information brochure to new prepay customers (costs €0.50 per brochure). It is likely that, even when smart meters are installed, consumers being switched to PPM will need to receive additional information on how to purchase credit and use the device.


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3.3.5 Fuel Gas Savings Reductions in gas consumption for the residential customers resulting from the introduction of smart metering and related DSM initiatives would result in less fuel-gas being required to compress and heat gas in the gas system. Table 21 below summaries the fuel gas savings assumptions used in the CBA model. Table 21: Fuel gas savings assumptions Total gas used by transmission system 2.50% as % of domestic transmission throughput

Transmission fuel-gas usage as % 1.50% of transmission throughput

Distribution shrinkage as % of 1.00% transmission throughput

The fuel-gas savings used in the CBA model have been estimated using the following general assumptions: The reduction has been valued using the ICE gas-price for UK gas futures

(monthly). The level of fuel gas savings is varied in the CBA model according to the

energy saving scenario, based on the gas CBT results.


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3.3.6 Revenue Protection - Theft of Gas The theft of gas from the distribution system is relatively low at approximately 0.20% of distribution throughput. The theft of gas can continue after the meter has been locked by the shipper, i.e. the customer physically removes the meter-lock and restores their own gas supply. It is assumed that the introduction of gas smart metering will reduce this type of gas theft. The customer’s gas supply will be isolated by the integrated-valve inside the smart-meter. It will be more difficult for the customer to interfere with the integrated valve without damaging the smart–meter, and any attempt to do so will almost certainly result in a “tamper-alarm” being sent from the smart-meter. For the purposes of the gas CBA it has been assumed that the introduction of gas smart metering will reduce the level of theft by 30%. In the international literature, assumptions vary from GB (10%) to Portugal (50%) and up to Hungary (70%). The 30% assumption is consistent with the value used for the electricity CBA. The CBA model assumes that a 30% theft reduction will generate savings in avoided Unaccounted for Gas (UAG) purchases equivalent to 0.07% of the domestic annual gas throughput i.e. 0.20% × 30.00% = 0.07%. It is assumed that this saving will be achieved gradually over time, i.e. the level of savings will increase as more gas smart-meters are rolled in each scenario. These savings have been valued by assuming an average gas purchase price of £0.711075 per therm plus adjustments for Euro exchange rate, carbon-tax and VAT – refer to section 5 for further details.


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3.3.7 System Reinforcement The introduction of smart meters is expected to reduce the overall gas demand, thus reducing the level of growth of the distribution network. In turn, this may delay the investments in network reinforcement. The CBA model assumes that following a 3% reduction in overall demand, BGN should be able to save about €1.23 per meter per annum, a saving which is adapted proportionally to the actual demand reduction expected in each scenario. International comparisons are not particularly helpful in this instance as the savings depend very much on the characteristics of the networks, and especially on the current spare peak capacity available.


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4.0 Quantifiable Costs and Benefits for Suppliers

4.1 Introduction While the distribution network operator component of smart metering costs and benefits is substantial in Ireland, suppliers/shippers in the gas market will also have to incur costs and will receive benefits resulting from a national smart metering rollout. This section outlines these supplier related costs and benefits. The methodology used for deriving the supplier figures was slightly different to that used for the network operator’s costs and benefits. Supplier costs and benefit figures were provided as a delta on their current cost to serve models. Airtricity, Bord Gáis Energy and Phoenix Energy provided the supplier submissions that were used to derive the residential and small business (G4 meter type) incremental cost-to-serve figures used in the CBA. Vayu also provided a submission which was not directly applicable to this CBA as it related to larger industrial and commercial customers outside the G4 gas meter category. Each supplier was asked by the CER to provide their increment cost to serve costs and benefits for two different options:

Option 1: Bi-monthly billing with Energy Statement. This option assumes a national rollout of smart meters, while retaining the current bi-monthly billing frequency.

Option 2: Monthly billing with Energy Statement. This option assumes a national rollout of smart meters, while increasing billing frequency to monthly.

The detailed spreadsheets provided by the suppliers were reviewed and validated, via a number of iterations, by the CER and also by independent consultants Frontier Economics. The CER then agreed ‘blended’ cost to serve figures for each cost/benefit category that were included in the final CBA, which reflected the range of submissions from the different suppliers and Frontier Economic’s recommendations based on international experience. It should be noted that as with the network costs and benefits, for the purposes of compiling the CBA, suppliers were requested by the CER to provide smart metering related costs and benefits in accordance with the national smart metering high level design and implementation assumptions which had been developed by the CER via the Smart Metering Project industry forums and a public consultation process (refer to section 2.2 for further details).


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Supplier costs and benefits have been grouped into the following categories which are detailed in the sections that follow:

Retail enquiries and complaints benefits Customer education and awareness campaign costs Billing costs IT systems costs Debt management (and working capital) benefits Payment transactions costs Staff training costs Supplier switching related benefits Hedging benefits Prepayment benefit Other costs

Table 23 below gives an overview of the supplier/shipper related smart metering cost and benefit assumptions included in the CBA model. These assumptions were arrived at by the CER after comparing costs submitted by suppliers with international benchmarks and information provided by Frontier Economics as part of their review. Some points to note from the Frontier review are outlined in the sections that follow. Table 22: Supplier ('Gas shippers') - Costs and Benefits Overview

Supplier ('Gas shippers') - COSTS

One-off Annual

From 2015

€/meter installed

Total systems capex - Fast rollout 7.27 Total systems capex - Phased rollout 7.27

€/meter/year

Total systems opex (billing system) - Fast rollout 1.25 Total systems opex (billing system) - Phased rollout 1.25

Customer awareness campaign (one-off per customer) 1.00

Incremental bill printing costs - BI-MONTHLY (per cust./year) 0.10 Incremental bill printing costs - MONTHLY (per cust./year) 3.20

Incremental payment transaction costs - BI-MONTHLY (per cust./year) 0.00 Incremental payment transaction costs - MONTHLY (per cust./year) 1.55


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Supplier ('Gas shippers') - SAVINGS

Reduced customer complaints - BI-MONTHLY (per cust./year) 1.00 Reduced customer complaints - MONTHLY (per cust./year) 0.75

Debt management savings - BI-MONTHLY (per cust./year) 0.37 Debt management savings - MONTHLY (per cust./year) 0.37

Supplier switching benefits (per cust./year) 0.65


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4.2 Retail Enquiries and Complaints

4.2.1 Option 1 (Bi-monthly Billing) The CBA includes a reduction of €1.00 per annum per customer in the cost to serve figure for handling customer enquiries and complaints for the bi-monthly billing option. This reduction can mainly be attributed to the virtual elimination of estimated bills and associated queries and complaints. However it is recognised that the introduction of more detailed billing, and possibly also more complex tariffs, may initially result in an increase in the volumes and complexity of enquiry calls, but that this would likely not be sustained as customers soon adapt to the new tariffs and billing. This figure was settled on by the CER after taking into account a review by Frontier Economics of each of the three suppliers submitted retail enquiries and complaints figures for the bi-monthly billing Option 1 and information collated by Frontier Economics from international smart metering CBAs:

“The values submitted by two suppliers for the gas CBA are in line with those supplied for the electricity CBA. Only one supplier indicated that, following the installation of smart meters, costs will be higher than before. However, it is unclear whether the cost provided is completely incremental to the current cost level. Therefore, as there are no intrinsic reasons to expect gas customers to behave differently from electricity customers (in fact, they will all be dual fuel customers) we would recommend using the same assumption that was used for the electricity CBA.”

4.2.2 Option 2 (Monthly Billing) The CBA includes a reduction of €0.75 per annum per customer in the cost to serve figure for handling customer enquiries and complaints for the monthly billing option. However, the reduction for Option 2 is lower than Option 1 in order to take account of the incremental increase in call volumes that would result from the move from a bi-monthly billing cycle to a monthly billing cycle.


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4.3 Customer Education and Awareness Campaign

4.3.1 Option 1 (Bi-monthly Billing) and Option 2 (Monthly Billing) The CBA includes an incremental cost to serve figure of €1.00 per customer for smart metering education and awareness campaign costs during the rollout. This amounts to a total of €712k over the assumed four years of the smart meter rollout (2015-18), apportioned to each year as per the percentage meter installation rate assumptions for these years (20/30/30/20%), with no further incremental costs incurred thereafter. These figures were chosen by the CER after taking into account a review by Frontier Economics of each of the three suppliers submitted customer education and awareness campaign costs and information collated by Frontier Economics from international smart metering CBAs:

“For the electricity CBA, we assumed a cost of €1.11 per meter during the rollout period for a nation-wide communication campaign to be undertaken by the industry as a whole. We believe that such a communication will be required also for the gas rollout, however, some savings could be made from economies of scope. We note that this cost is intended to cover the information campaign for all gas customers.”


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4.4 Bill Printing Costs

4.4.1 Option 1 (Bi-monthly Billing) The CBA includes an incremental cost to serve figure of €0.10 per annum per customer for printing six additional colour pages to be included with each bi-monthly bill i.e. the energy usage statement, which will include additional gas consumption and cost information for customers (including average usage graphs, historic and peer comparison information, and hints and tips) based on the type of energy usage statement that was trialled in the gas customer behaviour trials (CER/11/180a). Note, that it has been assumed for the purposes of the quantitative CBA that all customers will receive their gas bills, including the energy usage statement, in paper format. The potential for future increased take-up of electronic billing (e-billing) has not been factored into these costs. The qualitative section of the CBA deals with the rationale behind this treatment of e-billing in more detail – refer to section 7).

4.4.2 Option 2 (Monthly Billing) The CBA includes an incremental cost to serve figure of €3.20 per annum per customer for printing six additional bills per annum and 12 additional colour pages for energy usage statements to be included with each monthly bill. These extra pages will include additional gas consumption and cost information for customers (including average usage graphs, historic and peer comparison information, and hints and tips) based on the type of energy usage statement that was trialled in the gas customer behaviour trials. This cost is derived from an extra €0.50 per additional bill printed (six) plus €0.20 for the twelve additional colour energy usage statements to be included in each of the monthly bills i.e. twice the bi-monthly cost detailed in Section 3.4.1 above). Note, that again it has been assumed for the purposes of the quantitative CBA that all customers will receive their gas bills, including the energy usage statement, in paper format. The potential for future increased take-up of electronic billing (e-billing) has not been factored into these costs. The qualitative section of the CBA deals with the rationale behind this treatment of e-billing in more detail – refer to section 7).

4.4.3 Colour Printing Set-up Costs In line with the assumption made for the electricity CBA no incremental costs for colour printing functionality are included in the gas CBA i.e. Billing system set-up costs for colour printing, additional to system CAPEX considered in section 4.7.


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4.5 Debt Management Benefits

4.5.1 Option 1 (Bi-monthly Billing) and Option 2 (Monthly Billing) The CBA includes a benefit of €0.37 per annum per customer from an improvement in debt management for both the bi-monthly and monthly billing options. This benefit can mainly be attributed to the improved accuracy and detailed content of billing information being received by customers, which should assist them in better managing their gas expenditure, and thus reduce debt issues arising and associated supplier costs for management and recovery of this debt. This figure was chosen by the CER after taking into account a review by Frontier Economics of each of the three suppliers submitted retail enquiries and complaints figures for the bi-monthly billing Option 1 and information collated by Frontier Economics from international smart metering CBAs:

“With regards to debt management benefits, the suppliers that have provided submission for both the electricity and gas CBA have indicated similar values in both cases. Therefore, for consistency with the electricity CBA and because it is unlikely that customers will behave differently depending on the fuel they use we suggest using the same assumption. This value was calculated as a straight average of the values submitted by suppliers for the electricity CBA.”

In relation to Option 2 (monthly billing):

“As we noted in the case of the electricity CBA, the increase in the dunning [billing] cycle will provide customers with additional information that may help them manage their consumption more effectively. The benefit of monthly billing should therefore be slightly higher than those assumed under Bi-monthly billing. However, in the presence of smart meters, this incremental impact is likely to be marginal. In the absence of more specific information we suggest using the same assumption used for Bi-monthly billing.”

4.5.2 Working Capital Working capital savings have been excluded from the CBA as they represent a transfer from consumers to suppliers rather than a net saving.


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4.6 Staff Training Costs The CBA includes zero incremental cost to serve figure for additional staff training costs for suppliers in the case of both options. This figure was chosen by the CER after taking into account a review by Frontier Economics of each of the three suppliers submitted incremental staff training costs for both options and information collated by Frontier Economics from international smart metering CBAs:

“We believe that smart meter staff training will be part of the standard training all staff receive, with no particular incremental cost incurred. Two suppliers did not identify any additional annual training cost and we suggest that no costs are assumed in the CBA, in line with the assumption made for the electricity CBA.”


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4.7 IT Systems Costs

4.7.1 IT Systems CAPEX for Option 1 (Bi-monthly Billing) and Option 2 (Monthly Billing) The CBA includes a cost of €7.27 per meter for the capital expenditure (CAPEX) required to invest in new, or upgrade existing, IT systems to handle the more granular consumption data flows to be processed for providing customers with more detailed consumption and cost information with their bills (the energy usage statement trialled in the gas customer behaviour trials was used by the suppliers as a guide for developing their costs), and possible also for more complex tariffs. A sensitivity test is also run in the CBA on the scenario where these system capital expenditure costs are higher i.e. €14.54 per meter. This range of figures was chosen by the CER after taking into account a review by Frontier Economics of each of the three suppliers’ submitted IT Systems capital costs and information collated by Frontier Economics from international smart metering CBAs:

“The customer numbers assumed by each supplier added-up to more than the total number of customers. This will lead to some duplication of costs, particularly around licensing costs. Further, suppliers do not appear to have taken adequate account of economies of scope that may be available between the gas and electricity smart meter rollouts. We also note that smaller suppliers should be able to sub-contract these activities to external provider, at a cost in line with that of larger dual-fuel suppliers. This business model is already in use in GB, where smaller suppliers purchase smart metering support services from third parties. When we scale the assumptions used in the electricity CBA to take account of lower incremental data volumes, numbers of meters and excluding the changes to the printing systems covered in electricity CBA, we get a range of costs between €7.27 - €14.54 per meter. This would include an MDM cost of between €1.2m and €1.5m for a large supplier.”

The IT System CAPEX assumption is the same for both Fast and Phased rollout scenarios. In a phased implementation of gas smart meters, there would be savings in terms of the profile of the system licence costs (driven by the meter volumes) and hardware costs to support the volumes of data. However the benefits are likely to be offset by incremental IT change costs in upgrading hardware at points in the phased deployment or to handle increased data. The CBA includes no incremental costs for suppliers relating to programme management costs.


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4.7.2 IT Systems OPEX for Option 1 (Bi-monthly Billing) and Option 2 (Monthly Billing) The CBA also includes an incremental supplier cost of €1.25 per meter per year for operational costs (OPEX) related to running and maintaining these new, or upgraded, IT Systems. Again, a sensitivity test is also run in the CBA on the scenario where these IT system operational expenditure costs are higher i.e. €2.00 per meter per year. This range of figures was chosen by the CER after taking into account a review by Frontier Economics of each of the three suppliers’ submitted IT Systems operational costs and information collated by Frontier Economics from international smart metering CBAs:

“We have identified a range of values for opex on a per-meter basis. As with the systems capex numbers above, we have taken into account the over-estimate in customer numbers assumed by suppliers in aggregate, estimated the economies of scope that could be achieved by dual fuel suppliers and assumed that smaller suppliers should be able to outsource smart metering support costs at a similar unit cost as incurred by larger dual-fuel suppliers. The range is based around different assumptions about the number of people assumed to be required to support the incremental gas rollout and around the cost of the MDM licence fee. We would not expect the unit opex to materially vary depending on the speed of the rollout.”

4.7.3 Web Portal As noted in the electricity CBA, any web portal functionality over and above the joint solution provided by ESBN and BGN (already included in the CBA) should be considered discretionary business expenditure and therefore excluded from the analysis for suppliers. Thus zero costs are included for suppliers in all the options for Web Portal.


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4.8 Payment Transactions Costs

4.8.1 Option 1 (Bi-monthly Billing) The CBA includes zero incremental cost to serve figure for additional transaction costs for suppliers in the case of bi-monthly billing as there would be no additional payment transaction costs.

4.8.2 Option 2 (Monthly Billing) The CBA includes an incremental cost to serve figure of €1.55 per annum per customer for additional transaction costs for suppliers in the case of monthly billing as the increase in billing frequency would imply an increase in payment transaction costs.


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4.9 Supplier Switching Related Benefits

4.9.1 Option 1 (Bi-monthly Billing) and Option 2 (Monthly Billing) The CBA includes a benefit of €0.65 per annum per customer from a reduction in supplier switching costs for the bi-monthly and monthly billing options. This benefit can mainly be attributed to the availability of automated actual account closure meter reads to suppliers replacing a current switching process where suppliers rely mainly on manual meter reads provided by customers. This figure was chosen by the CER after taking into account a review by Frontier Economics of each of the three suppliers submitted competition related benefit figures for the bi-monthly and monthly billing options and information collated by Frontier Economics from international smart metering CBAs:

“The electricity CBA includes a benefit of €0.65 per annum per residential customer from a reduction in supplier switching costs. This benefit originates from the availability of automated reads which would replace the current switching process where suppliers rely mainly on manual reads provided by customers. Given that these benefits would likely exist also in the case of gas meters, we would suggest using the same assumption used for the electricity CBA.”


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4.10 Hedging Benefits The CBA includes zero benefits from a reduction in hedging costs for suppliers. In their review Frontier Economics indicated that in other smart metering CBAs the reduction in hedging costs is often quoted as a potential benefit for suppliers, however, due to the uncertainty surrounding any estimate, these benefits are usually not quantified.

“With regards to ‘Hedging’ benefits, we believe that there may be some benefits associated with smart meters as they would provide additional information about consumption patterns and, therefore, could help suppliers carry out hedging operations more efficiently. However, the uncertainty surrounding any estimate would be large. Therefore, in line with the assumption made for the electricity CBA, we would suggest not including this benefit in the gas CBA.”

For these reasons, no robust figure for hedging benefits to suppliers can be included in the quantitative section of the CBA. It is mentioned in the qualitative section of the CBA as a potential supplier benefit (refer to section 7). It should be noted that any potential hedging benefits would not depend on bill frequency and hence there would be no difference between Option 1 and 2 if benefits could be quantified.


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4.11 Prepayment Benefits The CBA includes no incremental costs or benefits for suppliers relating to their cost to serve of prepayment customers. This is because an equal prepayment penetration rate of approximately 18% has been assumed in both the counterfactual and smart metering rollout scenarios. This is consistent with the electricity CBA prepayment assumptions. Refer to sections 2.2.3 and 3.3.4 for further details of the prepayment assumptions used in the gas CBA model.


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5.0 Quantifiable Costs and Benefits for Consumers

5.1 Introduction Gas customers are assumed to receive additional benefits in the form of both energy usage and non-usage savings, due to the greatly enhanced consumption information provided by smart metering:

The energy usage savings represent the estimated reduction in the customers final gas bill due to better energy management (arising from the enhanced consumption data), and have been provided from the results of the gas customer behavior trial (CBT) – the detailed findings report for which is available in CER/11/180a. All of the following CBT results used in the CBA are statistically significant against the trial control group at a 90% confidence level: o Savings of 2.2% were achieved by customers who received a detailed

Energy Statement with their bi-monthly bill, i.e. detailed informational and graphical analysis of their historical gas usage;

o Savings of 2.8% were achieved by customers who received a detailed Energy Statement in their monthly bill (i.e. the same detailed information more frequently);

o Savings of 2.9% were achieved by customers who received a detailed Energy Statement in their bi-monthly bill, plus an In-home display (IHD) device (i.e. half-hourly feedback on their gas usage); and

o Savings of 3.6% were achieved by customers who received a detailed Energy Statement in their bi-monthly bill, plus an In-home display (IHD) and a variable tariff;

The reduction in gas usage will result in societal benefit for Ireland in the form of abated carbon dioxide (CO2) emissions from less gas being consumed. The value of this carbon abatement is included as part of the calculation of the consumer usage-related reduction using the carbon tax as a proxy for the value of carbon.

The enhanced information should also generate customer time savings due to less complaints and avoided customer meter-reads (arising from the elimination of estimated bills etc); although there will also be additional time costs due to the extra time spent in understanding the enhanced information provided via energy statements and in-home displays.


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5.2 Residential usage-related benefits The gas customer behaviour trial concluded that the introduction of the tested smart metering enabled demand-side management (DSM) initiatives had a positive impact of gas customer behaviour in terms of assisting in the reduction of gas usage and associated costs – an average reduction of 2.9%. The results of the gas CBT are summarised in Table 24 below – for further information refer to the detailed gas CBT Findings Report (CER/11/180a) published alongside this CBA report. All of these gas CBT results have a high level of statistical robustness – they are all statistically significant against the CBT control group at a 90% confidence level – so they can confidently be used in the gas CBA to calculate a robust value for the consumer usage-related benefit associated with each of the national rollout scenarios for gas smart metering analysed in the CBA. Table 23: Gas CBT Results Overview

Energy saving scenario % Usage

Reduction

SM + Bi-monthly bills + Energy Statement 2.2% SM + Monthly bills + Energy Statement 2.8% SM + Bi-monthly bills + Energy Statement + In-Home Display 2.9% SM + Bi-monthly bills + Energy Statement + In-Home Display + Variable Tariff 3.6%

NB: All results are statistically significant against the CBT control group at a 90% confidence level In addition to the Gas CBT results another number of key inputs are required to calculate the monetary value of the consumer usage related benefit. These are the gas cost and the average quantity of residential gas consumption. The following formula is used to derive consumer usage related benefit for each CBA energy saving scenario: Consumer Benefit (€) =

Gas Cost (€) * Average Quantity (kWh) * CBT Reduction (%) where:

Gas Cost = (CP/CF * EX + CT) * (1 + VAT) o Gas Commodity Price (CP) o Energy Conversion Factor (CF) o Carbon Tax (CT) o Exchange Rate (EX) o Value Added Tax (VAT)


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Average Quantity of Consumption = AQCtl * WC * (1- (VP + SME)) o Gas CBT Control Group Average Annual Consumption (AQCtl) o Correction Factors:

- Weather Compensation Factor (WC) - Vacant Premises rate (VP) - G4 SMEs rate (SME)

These inputs to the consumer benefit calculation are described further in the sections that follow.

5.2.1 Gas Cost There are a number of key inputs that are used to calculate the cost of gas used in the CBA model. These inputs are described in the sub-sections below. The formula which is used to derive the gas cost based on these inputs is set out below and the inputs are described in the sub-sections that follow. Gas Cost = (CP/CF * EX + CT) * (1 + VAT) where

o Gas Commodity Price (CP) o Energy Conversion Factor (CF) o Carbon Tax (CT) o Exchange Rate (EX) o Value Added Tax (VAT)

Applying the above formula results in the following treatment of gas cost values in the CBA:

€0.034813 per kWh for 2011; €0.036902 per kWh for 2012 and 2013; €0.037957 per kWh constant value being used for 2014 through to the end

of the CBA period in 2032. Refer to Table 24 below for details of how these values are calculated. Given that the realisation of the usage-related benefits for consumers is related to the installation of the gas smart meters, usage related benefits therefore don’t start to kick in until the start of the rollout in 2015. Thus €0.037957 is the gas cost value used in the CBA. Note that since the whole CBA is done in real (inflation adjusted) terms, the carbon tax and fuel prices are assumed stable in real terms at their terminal values.


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Table 24: Gas Cost Calculations

2011 2012 2013 2014 2015

ICE gas commodity price 71.11 71.11 71.11 71.11 71.11 Energy conversion factor 29.31 29.31 29.31 29.31 29.31 Carbon Tax

0.277 0.461 0.461 0.554 0.554

£/€ exchange rate

1.15 1.15 1.15 1.15 1.15 VAT

13.50% 13.50% 13.50% 13.50% 13.50%

Gas cost

3.4813 3.6902 3.6902 3.7957 3.7957

5.2.1.1 Gas Commodity Price The first key input was the commodity price of gas which is assumed in the CBA to be a constant £0.711075 per therm for the period of the CBA. This price was the average of the settled monthly prices for October 2011 to September 2012 taken from the ICE UK Natural Gas Futures (Monthly) Exchange on 21st September 201128. Due to the volatile and unpredictable nature of gas commodity prices a number of sensitivities tests are run in the CBA which vary the commodity price of gas used:

The first sensitivity uses the ICE forecast gas prices instead of a single constant price. The forecasted prices used in this sensitivity test (Test 9) are based on the ICE UK Natural Gas Futures (Monthly) Exchange on 21st September 2011, using the average of the settled monthly prices for October 2011 to December 2017. The 2017 average price is assumed to be constant 2018 to 2032 in this sensitivity test.

The second sensitivity uses a lower single constant price of £0.51 per therm which is consistent with energy price assumptions that underpinned the electricity CBA (TEST 10).

Refer to section 6.5 for further details on these and other sensitivity tests. Consideration was also given to running an additional sensitivity test that would use a ‘bi-monthly weighted average gas price’ to reflect that the annual average reductions in consumption measured in the gas CBT are not linear throughout the whole year i.e. the volume of reductions differ between each bi-monthly period over which the CBT was run and the price of gas also differs in each of

28 Daily Volumes for ICE UK Natural Gas Futures (Monthly) https://www.theice.com/marketdata/reports/ReportCenter.shtml?reportId=10


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these corresponding bi-monthly periods too. Such a sensitivity test would use a gas commodity price that was based on the average ICE settled monthly price for each bimonthly period weighted to reflect the distribution of average consumption savings in each corresponding bi-monthly period from the gas CBT results i.e. instead of the average annual price. Again using the settled monthly prices for October 2011 to September 2012 taken from the ICE UK Natural Gas Futures (Monthly) Exchange on 21st September 2011, it was established that there is a negligible difference (0.6184%) between such a ‘bi-monthly weighted average gas price’ and the annual average gas price used in the model. Considering this small difference it was decided that it did not warrant an additional sensitivity test to be run.

5.2.1.2 Energy Conversion Factor (CF) The energy conversion factor for natural gas is a constant value of 1 therm equals to 29.307 kilowatt hours (kWh) for the period of the CBA.29

5.2.1.3 Carbon Tax (CT) The value of avoided carbon tax from a reduction in gas consumption by consumers is included as part of the consumer usage related benefits in the CBA. It is assumed for the CBA that the carbon tax reflects the value of carbon. Thus there is no additional value added to reflect carbon abatement. The carbon tax was originally set in the 2010 budget based on a price of €15 per tonne of carbon (€0.277 per kWh). It is due to be doubled to €30 during the period of the four-year National Recovery plan – increasing to €25 per tonne (€0.461 per kWh) in 2012 and 2013 and €30 per tonne (€0.554 per kWh) by 2014.30 These assumptions are reflected in the gas CBA. It is assumed in the CBA model that the constant €30 per tonne (€0.554 per kWh) carbon tax continues until the end of the CBA period in 2032.

5.2.1.4 Exchange Rate (EX) The exchange rate for converting the Pounds Sterling gas commodity price to Euro currency is assumed to be a constant £1=€1.15 for the entire CBA period. This is based on the average exchange rate for June to August 2011.

5.2.1.5 Value Added Tax (VAT) The value of avoided Value Added Tax (VAT) from a reduction in gas consumption by consumers is included as part of the consumer usage related benefits in the CBA. VAT is assumed to be a constant 13.5% for the period of the CBA.

29 Energy conversion factors: www.bordgais.ie/networks/index.jsp?p=311&n=143 30 Page 99, The National Recovery Plan 2011 – 2014 www.budget.gov.ie/The%20National%20Recovery%20Plan%202011-2014.pdf


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5.2.2 Average Quantity The average savings per meter is multiplied by the total number of smart meters in service in each year of the CBA to arrive at the total residential benefits for that year. The model deducts meters assumed to be in vacant dwellings (6%) or small businesses (2%) from this calculation, on the assumption that they will not give rise to energy savings from the introduction of smart metering related initiatives. The average annual residential gas consumption is assumed to be 13,600kWh for existing housing stock and 5,712kWh for new housing stock (‘new builds’) for the purposes of the gas CBA model. The savings in terms of gas usage reduction is then calculated for each of the energy saving scenarios using the gas CBT findings. The CBA model assumes that the change in gas usage induced by the introduction of the smart metering related initiatives persists for the duration of the analysis. In other words, for example, if residential customers reduce average demand by 3% compared to the CBT control group when they switch to smart metering, their demand is assumed to remain 3% lower than counterfactual demand for the remaining time covered by the study. The formula which is used to derive the gas cost based on these inputs is set out below and the inputs are described in the sub-sections that follow. Average Quantity of Consumption = AQCtl * WC * (1- (VP + SME)) where

o Gas CBT Control Group Average Annual Consumption (AQCtl) o Correction Factors:

- Weather Compensation Factor (WC) - Vacant Premises rate (VP) - G4 SMEs rate (SME)

5.2.2.1 Vacant Premises The CBA model assumes a constant vacant premises rate of 6% throughout the entire CBA period. This is calculated based on the 2006 census figures – refer to details below – which is consistent with the data source used for the electricity CBA vacant homes allowance (the electricity allowance was a higher 15% because it included holiday homes whereas the gas allowance is 6% to reflect the lack of vacant holiday homes in the predominantly urban gas consumer population). Thus the gas CBA model attributes no usage related benefits to these vacant homes and in effect reduces the consumer usage-related benefits in each of the scenarios by 6% to reflect empty gas connected premises.


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Calculation of the 6% vacant premises allowance is based on 2006 Census figures from the Central Statistics Office (CSO)31: “There were 266,000 vacant dwellings in 2006 representing 15 per cent of the total housing stock. Of these, 175,000 were houses, 42,000 were flats and 50,000 were classified as holiday homes.” Summary of gas CBA assumptions for vacant premises:

42k flats – assumed all gas consumers. 50k holiday homes – assumed none are gas consumers 175k houses – assumed one third of these are gas consumers. Gives total of 100k gas supplied vacant dwellings out of the total of 266k

vacant dwellings (15%) which equates to 5.64% rounded up to 6%.

5.2.2.2 Small Businesses The scope of the CBA model includes all gas consumers in the G4 meter category, which encompasses all residential customers and some small businesses. However, the results of the gas CBT apply to residential customers only, as small businesses were not included in this experimental trial, and therefore no usage reduction benefit is included in the CBA for small business customers in the G4 meter group. Small businesses account for approximately 2% of G4 meter customers, so the gas CBA model in effect reduces the consumer usage-related benefits in each of the scenarios by 2% to take account of small businesses. However, just because there are no available statistically robust results from the gas CBT applicable to small business customers does not mean, of course, that there would be no usage-related benefits from rolling out smart metering to such customers in practice. A sensitivity test is run which applies the residential consumer usage-related benefit measured in the CBT to these small business for each of the energy saving scenarios i.e. in effect it reverses the removal of the 2% outlined above (TEST 7).

5.2.2.3 Average Consumption The CBA model assumes a constant average annual consumption per residential gas customer of 13,600kWh from 2011 to 2032 for existing housing. This average is derived from using the average annual consumption of the gas CBT control group (during 1st June 2010 to 31st May 2011 trial test period) and applying a weather compensation factor to bring it into line with historic average residential annual consumption:

31 2006 Census of Population - Volume 6 - Housing , section on Vacant Dwellings www.cso.ie/newsevents/pr_census2006vol6.htm


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CBT Control group average consumption: 14,334kWh Weather compensation factor (provided by BGN): 8150 / 8590 = 0.9488 Corrected annual consumption: 14,334kWh * 0.9488 = 13,600kWh

For each of the four Energy Saving Scenarios in the CBA model the average annual consumption of 13,600kWh is multiplied by the CBT control group percentage reduction to ascertain the number of kWh units reduction per scenario. It should be noted that the CBA model does not take account of potential further reductions to the average annual residential gas consumption in the future resulting from potentially greater investment in energy efficiency measures in the existing housing stock as outlined in the National Energy Efficiency Action Plan (NEEAP). The NEEAP forecasts for energy reductions already take into account energy savings assumptions relating to the introduction of smart metering and thus, to avoid the risk of double counting, the NEEAP reductions have not been factored into the average consumption value used in the gas CBA.

5.2.2.4 New Builds The CBA model includes assumptions on the number of new gas connections over the period of the analysis. These assumptions are based on figures taken from the Joint Gas Capacity Statement 2011 (JGCS)32, which forecasts the number of new gas connections out to 2020, broken into ‘new build’ and existing housing connection numbers. The gas CBA model assumes that the figures for the 2019/20 year remain constant out until 2032. The JGCS indicates that the incremental annual residential gas demand from ‘new builds’ is forecast to substantially reduce to 5,700kWh due to enhanced building regulations. The gas CBA model takes this into account by applying a 58% (1- (5700/13,600)kWh) reduction to average consumption for ‘new builds’ with gas smart meters. Table 25 below gives the summary of the assumptions included in the CBA showing the assumed percentage of new gas connections that are assumed to be ‘new builds’ compliant with new energy efficient building regulations. Table 25: ‘New builds’ Usage and Rate Assumptions (Based on Joint Gas Capacity Statement 2011)

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

New connections 6,484 7,002 7,652 10,620 12,938 13,262 13,075 12,888 12,701 12,514 New-build compliant 9% 21% 35% 62% 69% 69% 69% 69% 68% 68% Energy savings 58% 58% 58% 58% 58% 58% 58% 58% 58% 58%

32 Joint Gas Capacity Statement 2011: Pg 39, Table3-11 for new connection figures; Pg 85 for ‘new build’ energy usage reduction assumption. www.cer.ie/en/gas-security-of-supply.aspx


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5.3 Societal Benefits The reduction in gas usage will result in societal benefit for Ireland in the form of abated carbon dioxide (CO2) emissions from less gas being burnt. The value of this carbon abatement is included as part of the calculation of the consumer usage-related reduction using the carbon tax as a proxy for the value of carbon.

The amounts of carbon abated for each of the CBA scenarios is presented as part of the CBA results for information and is calculated using the CO2 emissions intensity factor for natural gas of 0.190kg of CO2 per kWh33.

33 Carbon Trust CO2 conversion factors: www.carbontrust.co.uk/cut-carbon-reduce-costs/calculate/carbon-footprinting/pages/conversion-factors.aspx


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5.4 Non-usage related costs and benefits This sub-section outlines the treatment of non-usage related quantifiable benefits for residential consumers and small businesses in the CBA model. These include costs of learning and adapting to the new smart metering enabled initiatives (such as in-home displays and energy usage statements) and benefits of time saved due to better and more frequent provision of gas usage information (such as reducing the amount of time customers spend disputing and querying their gas-bill, and also to largely eliminate the need to phone or “dial-in” meter reads to either BGN or their gas shipper etc). The model assumes a value for each hour spent by residential consumers and small businesses on activities relating to management of gas use. It then compiles estimates for the extra time spent or saved on a range of activities related to the introduction or presence of smart metering initiatives, in comparison to the previous manual metering regime. Net time savings multiplied by the value of time is taken to be the net benefit from this source for each year. Average household value of time spent in non-paid work for use in assessing the value of increases or decreases in residential time use is taken to be half the average hourly wage: €15.68 per hour, and this same value is used for the small businesses covered in the scope of the CBA. Figures are assumed to remain constant in real terms. Table 26 below shows the assumptions used in the gas CBA model for non-usage related costs and benefits. Table 26: Non-usage Related Customer Cost and Benefit Assumptions

Consumer time savings 0.93 €/meter

Value of time

15.68 €/hour

Time savings from reduction in complaints 0.0083 hours

0.13 €/meter

Time saving for each billing meter read 0.1333 hours

Number of billing meter reads 25.92% % of customers with a smart meter

0.54 €/meter

Time saving for each change-of-supplier read 0.0833 hours

Number of changes of supplier in a year 20.00% % of customers with a smart meter

0.26 €/meter


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Consumer time losses

Incremental time needed to learn new usage statement 0.3400 hours (applicable to all scenarios)

5.33 €/meter

Incremental time needed to learn IHD usage 0.2217 hours (applicable to scenarios 3F, 3S, 4F and 4S)

3.48 €/meter

Incremental time needed to learn new tariff 0.0000 hours (applicable to scenarios 4F and 4S)

0.00 €/meter

5.5.1 Reduction in complaints The introduction of gas smart metering is assumed to lead to the virtual elimination of bills based estimated gas consumption, which in turn is assumed to reduce the number of customer billing complaints and queries. The value of this time-saving to the customer has been estimated as being approximately 0.0083 hours per year, or 30.00 seconds per year for each customer with a gas smart-meter. This is equivalent to €0.13 per year for each non-prepayment customer with a gas smart meter. Residential customers on prepayment are assumed not to receive this benefit, which is consistent with treatment of this benefit in the electricity CBA.

5.5.2 Elimination of “dial-a-read” calls Customers currently phone meter-reads to both BGN and their shipper primarily for both billing-query purposes (e.g. if they have missed the meter-reader, or if they wish to correct an estimated bill), or to complete a change of supplier (COS) process. It has been assumed that time savings achieved for each of these activities is approximately 8.00 minutes per billing meter-read, and 5.00 minutes for each COS meter-read. The total value of these time savings to the customer is, therefore, €2.09 per billing-query meter-read and €1.31 per COS meter-read. The total time-savings were estimated using the following assumptions:

That approximately 25.92% of customers will on average make one billing-query dial-a-read per annum (which is equivalent to approximately 150,000 dial-a-reads in 2011); and


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The churn in the competitive gas market will be approximately 20.00%, i.e. that approximately 20.00% of customer will on average change shipper during the year.

Residential customers on prepayment are assumed not to receive this benefit, which is consistent with treatment of this benefit in the electricity CBA.

5.5.3 Familiarisation cost of smart metering The gas CBA also assumes that there would be a time-penalty or cost to the customer, associated with familiarising themselves with smart metering, i.e. the additional time spent understanding the more detailed consumption data and IHD. These costs are calculated on an incremental basis to similar costs already included in the electricity CBA. Each consumer is assumed to spend some additional time in the year of implementation learning about gas smart metering, gas energy statement and in some cases additional gas functionality on their IHD. For residential customers, the gas CBT provides direct evidence on the time required for this from the post-trial survey. The average incremental time each customer with smart metering spends learning about new bills, in-home devices, etc. in the year of installation is assumed to be 0.3400 hours for bi-monthly and monthly bills, 0.2217 hours for an IHD and zero for the variable tariff. We also assume that small businesses spend the same amount of time on this activity, but we have no survey evidence to verify this assumption.


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6.0 Results of Quantifiable Cost-Benefit Analysis

6.1 Introduction In this section, we combine the estimates from the quantifiable sources of costs and benefits discussed earlier in this paper. The results are given as net present value (NPV) estimates for 8 national rollout options, plus 11 sensitivity tests that explore the effects of varying specific parameters of interest. The first sub-section briefly describes the options we have explored in the CBA and some of the enabling assumptions, and the second sub-section sets out the overall Net Present Value (NPV) estimates associated with each of these options. We then break these totals down by the sources identified earlier in this paper: network, suppliers/shippers, customers (usage-related and non-usage related). The third sub-section discusses a range of sensitivity tests and the final sub-section summarises the results. As indicated in the electricity smart metering CBA (CER/11/080c)), the NPV estimates shown in these smart metering CBAs are subject to uncertainty. Very small differences (say, of €1m) should be seen as well within the margin of error. However the total investment required for rolling out gas smart metering is lower than the investment assumed in the electricity rollout options, so smaller differences in estimated NPVs might be regarded as significant here compared to that analysis. The sensitivity analysis provided later in the section provides an indication of the uncertainty associated with a range of cost and benefit drivers.


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6.2 Options and CBA Parameters This sub-section describes the set of options tested in the CBA and outlines some of the higher-level assumptions made during the analysis.

6.2.1 Options tested in the CBA We chose a set of options for analysis based on combinations of meter rollout scenario (fast or phased) and energy saving scenario (four different informational stimuli combinations based on the gas CBT findings). Informational dimensions are frequency of billing used with smart metering (bi-monthly or monthly), whether an IHD is deployed or not and whether a variable tariff is added. Table 27 summarises the options tested. Table 27: List of Options Analysed in CBA

Option Code

Energy Saving

Scenario

Meter Rollout

Scenario 1F Bimonthly ES Fast 1S Bimonthly ES Phased 2F Monthly ES Fast 2S Monthly ES Phased 3F Bimonthly ES + IHD Fast 3S Bimonthly ES + IHD Phased 4F Bimonthly ES + IHD + Variable Tariff Fast 4S Bimonthly ES + IHD + Variable Tariff Phased

ES=Energy Statement; IHD = In-home Display All options are tested against a counterfactual (baseline) which assumes a continuation of the current ‘business as usual’ metering and billing processes i.e. traditional non-smart meters and bi-monthly billing cycles based on the current manual meter reading cycle.

6.2.2 High level parameter assumptions used in the CBA The CBA includes estimates of the net present value in 2011 of implementing smart metering for the 8 options defined above. Cash flows from 2011 through 2032 are taken into account, and we use a discount rate of 4% in real terms.34 As noted previously the CBA assessment is based on a simple NPV analysis of the “pure” cash-flow differential between the counter-factual and smart-meter

34 4% discount rate as per Dunning (2007) and Department of Public Expenditure and Reform (2011). Sensitivity tests are also carried out to understand the impact of higher discount rates on the NPVs and the discount rate that would be required to bring the NPV for each option to zero.


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scenarios. It does not take account of financial depreciation or meter write-down costs (e.g. associated with early retirement of G4 diaphragm meters in the fast rollout scenario). The model assumes that all G4 meter customers (i.e. all residential customers and some non-residential small business customers) are provided with smart meters over the course of the programme. For each rollout option we assume that all customers receive the relevant energy saving stimuli at the time of meter installation. For the two separate meter deployment scenarios, i.e. “fast” and “phased” meter-deployment scenarios, it is assumed that:



In both the counterfactual and smart metering rollout scenarios, we assume that there is a significant increase in the penetration of prepayment metering and billing for residential customers in comparison to the current level of penetration. The gas CBA is premised on a number of high-level design assumptions and principles. The most important principle is that a national gas smart metering rollout is assumed to be incremental to any electricity smart metering rollout (i.e. it will be part of a “dual-fuel” rollout) – refer back to section 2.2 for further details on this assumption. The costs of the national rollout of the electricity smart metering infrastructure have already been included in the electricity smart metering CBA (CER/11/080c) and therefore these costs are not double-counted in the gas CBA model, which captures only the incremental costs to be borne by the electricity smart metering rollout as a result of facilitating gas smart metering i.e. the additional incremental electricity smart metering communication and meter data management system (MDMS) costs. The CER wishes to emphasise that the regulatory treatment of costs and their attribution to various segments of the industry in this CBA are without prejudice to any findings that may be made in the context of future price control measures or other regulatory actions.


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6.3 Total NPV by Option The estimated total NPVs for the 8 options are generally positive, often substantially so, for options including an IHD (options 3 and 4), and generally negative or marginal for options not including an IHD (options 1 and 2), with the exception of option 1F. The NPVs are generally more favourable for energy saving scenarios based on the fast rollout scenario compared to the phased rollout scenario. Table 28 and Figure 16 display the total NPVs for all 8 options. If these results were borne out in an actual deployment of gas smart metering, leveraging an electricity smart metering infrastructure, the project would bring about net benefits for Ireland in comparison with the base case scenario for the ‘with IHD’ options (3 and 4), especially if a fast rollout approach is taken (options 3F and 4F). Table 28: Total NPV by Option



Total incremental NPV (EUR)

Bimonthly ES Fast 1F 15,663,848 Bimonthly ES Phased 1S -1,612,759

Monthly ES Fast 2F 938,003 Monthly ES Phased 2S -13,870,616

Bimonthly ES + IHD Fast 3F 33,323,837 Bimonthly ES + IHD Phased 3S 12,101,010

Bimonthly ES + IHD + VT Fast 4F 59,879,967 Bimonthly ES + IHD + VT Phased 4S 33,991,380

ES=Energy Statement; IHD = In-home Display; VT = Variable Tariff The fast rollout scenario generally compares more favourably against the phased rollout scenario for each of the energy saving scenarios, with the options based on fast rollouts being in the range of €14m to €26m relatively better in NPV terms than the options based on phased rollouts for the same energy saving scenario. This generally reflects that a fast rollout enables the benefits of smart metering to be realised up front for all customers and the network operator, including being able to avail of bulk rollout installation discounts which aren’t assumed to be available in the phased rollout scenario.


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Figure 16: Total NPV (€m) by Option

When comparing each of the energy saving scenarios the NPVs for the different options generally align with the trend from the gas CBT findings, apart from the monthly billing options, which have the lowest NPVs of all (€1m for fast rollout scenario and -€14m for the phased rollout scenario), reflecting that the incremental costs to suppliers of facilitating monthly billing more than outweighs the incremental benefit that receiving information on a monthly basis gives to customers. The options featuring an IHD are the best performers in terms of NPVs (€12m – €60m) with the options including the Variable tariff in combination with an IHD giving the most positive NPVs (€60m for a fast rollout and €34m for a phased rollout). This reflects that ‘with IHD’ options receive additional consumer usage-related benefits (as per their higher gas CBT results) but do not incur any additional costs for the IHD device because it is assumed that the IHD device already costed into the electricity smart metering CBA could act as a dual fuel IHD for gas customers with no incremental costs accruing.


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6.4 NPV Components by Option In this next sub-section, the total NPV for each option is broken down by the categories of costs and benefits discussed earlier in this paper .i.e. network, shipper/supplier and customer.

6.4.1 Network Component The network component of the NPV is always negative (Table 29). This reflects that, even when it is assumed that gas smart metering leverages an electricity smart metering infrastructure, the substantial investment in gas smart meters, installations, systems and project management outweighs the savings to be made in avoided cost elements such as manual meter reading and other savings. Generally there is not much variation in the NPVs for the network component between the different options, which range from -€58m to -€67m. However there are some slight variations which can mainly be attributed to the following reasons:

The options that include a phased rollout give rise to a slightly higher net cost than those with a fast rollout (generally in range of a €3m difference). This difference can mainly be attributed to the lack of bulk discount on installation costs in the phased rollout scenario.

The network component NPVs for the ‘with IHD’ options (-€61m to -€67m)

are generally slightly more negative than the comparable ‘without IHD’ options (-€58m to -€63m) mainly due to the fact that the smart metering communications module cost is assumed to be slightly more expensive (€45) in the ‘with IHD’ options, to cater for extra IHD-specific data processing functionality, than in the ‘without IHD’ options (€35).

Other slight variations between the network NPVs for the different options

can be attributed to the varying network related benefits that are linked to the energy saving scenario usage reduction results from the gas CBT i.e. system reinforcement and fuel gas savings.

As already mentioned earlier the network component does not include any additional cost for the provision of IHDs to customers in the ‘with IHD’ scenarios and hence there is no substantial difference in network NPVs between the ‘with IHD’ and ‘without IHD’ options. This is because it is assumed that the IHD already costed into the electricity smart metering CBA network component could act as a dual fuel IHD for gas customers with no incremental costs accruing.


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Table 29: NPV by Option for Network Component



Networks incremental NPV

(EUR)

Bimonthly ES Fast 1F -60,017,151 Bimonthly ES Phased 1S -62,871,328

Monthly ES Fast 2F -57,583,399 Monthly ES Phased 2S -60,859,343

Bimonthly ES + IHD Fast 3F -63,913,490 Bimonthly ES + IHD Phased 3S -66,695,753

Bimonthly ES + IHD + VT Fast 4F -61,074,113 Bimonthly ES + IHD + VT Phased 4S -64,348,438



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6.4.2 Supplier Component The supplier/shipper NPV component has less differentiation by option, and is also generally very marginally negative (shown in Table 30). This reflects that the additional CAPEX associated with improved billing systems and education of customers and the extra OPEX needed to run a more complex set of bills, and possibly tariffs, is roughly balanced by the savings from fewer complaints and queries, less costly management of bad debts and savings when customers are switching supplier. The exception to this trend is the monthly billing energy saving scenario which drives suppliers NPVs strongly negative for options 2F and 2S (-€33m to -€38m). This is because monthly billing leads to a large reduction in the NPV due to the need to print and post larger numbers of paper bills. For the other options, which retain a bi-monthly billing cycle, the only difference in NPVs is between the fast and phased rollouts for each energy saving scenario and this difference is negligible in CBA terms i.e. <€1m. Table 30: NPV by Option for Supplier Component


scenario

Option code

Shippers/Suppliers incremental NPV

(EUR)

Bimonthly ES Fast 1F -866,433 Bimonthly ES Phased 1S -1,485,835

Monthly ES Fast 2F -38,354,675 Monthly ES Phased 2S -32,506,865

Bimonthly ES + IHD Fast 3F -866,433 Bimonthly ES + IHD Phased 3S -1,485,835

Bimonthly ES + IHD + VT Fast 4F -866,433 Bimonthly ES + IHD + VT Phased 4S -1,485,835



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6.4.3 Customer Component A consistently large and positive source of benefits is the customer component of the CBA (Table 32), which is mostly comprised of the residential usage-related component (ranging from €61m to €122m positive NPVs). A very small amount of the customer component is attributed to non-usage related factors, as discussed in section 5, but these time related savings and costs generally cancel each other out resulting in a negligible net impact (< €2m) on the overall customer NPV figures. The substantial usage-related savings arise from a reduction in the variable element of the predicted average bills for residential customers i.e. the energy component – refer to section 5 for further details on how the usage-related benefits are calculated. The NPVs for the usage-related benefits correspond directly to the size of the percentage usage reduction measured for each of the energy saving scenarios as part of the gas CBT (Table 31). Hence option 4 gives the largest consumer component NPVs, followed by options 3 and 2, which are quite similar in NPV terms, with option 1 giving the relatively lowest NPVs. The fast rollout options give relatively better NPVs for each energy saving scenario when compared to the phased rollout options. Table 31: Gas Customer Behaviour Trial Results

Energy saving scenario % Usage

Reduction

1. SM + Bi-monthly bills + Energy Statement 2.2% 2. SM + Monthly bills + Energy Statement 2.8% 3. SM + Bi-monthly bills + Energy Statement + In-Home Display 2.9% 4. SM + Bi-monthly bills + Energy Statement + In-Home Display + Variable Tariff 3.6%

NB: All results are statistically significant against the CBT control group at a 90% confidence level The variation between the fast and phased rollout NPVs for each energy saving scenario can be attributed to earlier realisation of usage-related benefits in the fast scenario as consumers receive smart metering sooner than in the phased rollout scenario. The difference between the NPVs (ranges from only €14m to €22m) is perhaps not as great as would be expected but this is due to the fact that in the phased rollout scenario it is assumed that the retro-fitting of the smart-ready meters already installed at the start of the rollout would take place over an accelerated four-year period, 2015 to 2018 – thus by the end of 2018 there would be over 400k smart meters installed in the ‘slow’ rollout. The ‘without IHD’ options (1 and 2) derive a small positive NPV from non-usage related effects on customers, while the ‘with IHD’ options (3 and 4) derive a very


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small negative NPV. These results indicate that the costs and benefits associated with customer time use roughly balance: for the ‘without IHD’ options the savings on time making complaints and queries or reading meters for a variety of reasons are slightly greater than the costs associated with time spent learning about the new metering informational stimuli and charging arrangements (as reported in the CBT post-trial survey); and vice versa for the ‘with IHD’ options, where the extra time spent understanding the gas functionality on the IHD (as reported in the CBT post-trial survey) leads to the costs marginally outweighing the savings. Overall, as Table 32 below depicts, the total NPVs for the customer component are strongly positive across all options (ranging from €63m to €122m), reflecting the impact of the value of the usage-related savings measured in the gas CBT. Table 32: NPV by Option for Customer Component


scenario

Option code

Usage-related

consumers incremental NPV (EUR)

Non-usage related

consumers incremental NPV (EUR)

Total consumers

incremental NPV (EUR)

Bimonthly ES Fast 1F 74,538,364 2,009,068 76,547,433 Bimonthly ES Phased 1S 61,421,027 1,323,377 62,744,403

Monthly ES Fast 2F 94,867,009 2,009,068 96,876,077 Monthly ES Phased 2S 78,172,216 1,323,377 79,495,592

Bimonthly ES + IHD Fast 3F 98,255,117 -151,356 98,103,761 Bimonthly ES + IHD Phased 3S 80,964,081 -681,483 80,282,598

Bimonthly ES + IHD + VT Fast 4F 121,971,869 -151,356 121,820,513 Bimonthly ES + IHD + VT Phased 4S 100,507,135 -681,483 99,825,652



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6.4.4 Societal Component The reduction in gas usage will result in societal benefit for Ireland in the form of abated carbon dioxide (CO2) emissions from less gas being consumed. The value of this carbon abatement is included as part of the calculation of the consumer usage-related reduction using the carbon tax as a proxy for the value of carbon. The amount of carbon abated for each of the CBA scenarios is calculated using the CO2 emissions intensity factor for natural gas of 0.190kg of CO2 per kWh. Table 33 and Figure 17 show the total CO2 savings, across the CBA period, for each gas smart metering national rollout option. Table 33: Total CO2 Savings by Option (tCO2)


scenario Option

code Total CO2 savings

(tCO2)

Bimonthly ES Fast 1F

713,146 Bimonthly ES Phased 1S

607,486

Monthly ES Fast 2F

907,640 Monthly ES Phased 2S

773,164

Bimonthly ES + IHD Fast 3F

940,056 Bimonthly ES + IHD Phased 3S

800,777

Bimonthly ES + IHD + VT Fast 4F 1,166,966 Bimonthly ES + IHD + VT Phased 4S

994,068

ES=Energy Statement; IHD = In-home Display; VT = Variable Tariff Figure 17: Total CO2 Savings by Option (tCO2)


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6.4.5 Summary of NPV Breakdown by Component Figure 18 and Figure 19 below depict the distributional breakdown by component of the total NPV for the fast and phased rollout options respectively. The same distributional trend is broadly reflected throughout all the options with the Networks component strongly negative in all options (ranging from -€58m to -€64m for fast scenarios and from -€61m to -€67m for phased scenarios) and the Customer component being strongly positive (ranging from -€77m to -€122m for fast scenarios and from -€63m to -€100m for phased scenarios). The Supplier/Shipper component remains mainly marginal (circa -€1m) for most options, except for the smart metering monthly billing options which are strongly negative (-€33m to -€38m). Figure 18: Fast Rollout Options - NPV (€m) Breakdown by Component

Figure 19: Phased Rollout Options - (€m) Breakdown by Component


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Table 34 below depicts a summary of the NPVs for all gas smart metering national rollouts analysed in the quantifiable CBA including a breakdown by the component categories that make up the total NPV figures. Benefits are positive values and costs are negative values. Total CO2 savings are also shown for each option. Table 34: Summary of NPVs (€m) by Option


Meter rollout

scenario

Scenario code

Networks incremental NPV (EUR)

Shippers / Suppliers


Consumers incremental NPV (EUR)

Total


Total CO2 savings (tCO2)

Bimthly ES Fast 1F -60,017,151 -866,433 76,547,433 15,663,848

713,146

Bimthly ES Phased 1S -62,871,328 -1,485,835 62,744,403 -1,612,759

607,327

Monthly ES Fast 2F -57,583,399 -38,354,675 96,876,077 938,003

907,640 Monthly ES Phased 2S -60,859,343 -32,506,865 79,495,592 -13,870,616

772,961

Bimthly ES + IHD Fast 3F -63,913,490 -866,433 98,103,761 33,323,837 940,056 Bimthly ES + IHD Phased 3S -66,695,753 -1,485,835 80,282,598 12,101,010

800,567

Bimthly ES + IHD + VT Fast 4F -61,074,113 -866,433 121,820,513 59,879,967 1,166,966 Bimthly ES + IHD + VT Phased 4S -64,348,438 -1,485,835 99,825,652 33,991,380 993,807


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6.5 Sensitivity Tests This section reports the results of 11 sensitivity tests carried out on the NPV results discussed in section 6.4 above. These tests are listed below and described, along with their results, in the sub-sections that follow:

1. BGN to incur half of the cost of the IHD 2. Meter costs higher than expected 3. Programme management costs higher than expected 4. Suppliers IT costs higher than expected 5. Lower ESBN licence costs (dual-fuel discount) 6. Lower communication OPEX costs (gas data included in electricity data

allowance) 7. Residential-type' small businesses have same behavioural response as

residential customers 8. IHD benefit wanes from 2020 onwards (savings revert to bi-monthly scenario) 9. Gas price sensitivity (use ICE gas futures instead of current price) 10. Gas price sensitivity (use electricity CBA price instead of current price) 11. Discount rate sensitivity


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6.5.1 Sensitivity Test 1: Shared IHD Cost The main gas CBA model assumes that because gas smart metering leverages the electricity smart metering infrastructure already in place there is no incremental cost arising for providing gas customers with in-home displays (IHDs) i.e. the IHD already provided as part of an electricity smart metering rollout would be able to act as a dual fuel IHD for gas customers at no incremental cost to that already included in the electricity CBA. Therefore this first sensitivity test (results of which are shown in Table 35) changes this assumption to allocate half of the purchase cost of an in-home display for gas customers to BG Networks. This has the result of reducing the NPVs for the ‘with IHD’ options by €12m for the fast rollouts and €11m for the phased rollouts. However, the total NPVs for all of these ‘with IHD’ options still remain positive, although the NPV for option 3S becomes very marginally positive. Table 35: Results of Sensitivity Test 1 - Shared IHD Cost

Base case

Sensitivity 1


Meter rollout

scenario

Scenario code

NPV

NPV Difference

TRUE

Bimthly ES Fast 1F 15,663,848

Bimthly ES Phased 1S -1,612,759

Monthly ES Fast 2F 938,003

Monthly ES Phased 2S -13,870,616

Bimthly ES + IHD Fast 3F 33,323,837

20,908,400 -12,415,438

Bimthly ES + IHD Phased 3S 12,101,010

706,593 -11,394,417

Bimthly ES + IHD + VT Fast 4F 59,879,967

47,464,529 -12,415,438 Bimthly ES + IHD + VT Phased 4S 33,991,380

22,596,962 -11,394,417

It should be noted, however, that the changes assumed in this sensitivity test would have had a positive impact on the electricity CBA rollout options that included an IHD – their NPVs would be improved as the capital cost of purchasing an IHD would have been halved for roughly a third of electricity customers i.e. the gas consumer, or ‘dual fuel’, population. This sensitivity test therefore essentially results in a transfer of costs from the electricity CBA to the gas CBA and no net change in costs when both CBAs are considered together.


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6.5.2 Sensitivity Test 2: Meter Costs Increase The second sensitivity test (results of which are shown in Table 36) increases the smart meter purchase costs by 10%, reflecting that meter purchases are a variable cost which could prove to be higher than those estimated in the main model. This sensitivity has the result of reducing the NPVs for all options by circa €12m, which results in:

Options 1S and 2S, which already had negative NPVs becoming even more negative.

An additional option (2F) is also pushed into a negative NPV, meaning that 3 of the 8 options would now have negative NPVs.

Option 3S is also pushed down to a very marginally positive NPV. Options 1F, 3F, 4S and 4F remain positive although there NPVs have

reduced. Table 36: Results of Sensitivity Test 2 - Meter Costs Increase

Base case

Sensitivity 2


Meter rollout

scenario

Option code

NPV

NPV Difference

TRUE


4,189,396 -11,474,452


-13,002,337 -11,389,578


-10,536,449 -11,474,452


-25,260,194 -11,389,578


21,187,228 -12,136,609


103,730 -11,997,280



21,994,099 -11,997,280


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6.5.3 Sensitivity Test 3: Programme Management Costs The third sensitivity test (results of which are shown in Table 37) increases the smart metering programme management costs by 10%, therefore testing for a scenario where these costs are higher than has been assumed in the main model. This has the result of reducing the NPVs for all options by circa €2m, which results in:

Options 1S and 2S, which already had negative NPVs becoming slightly more negative.


Options 1F, 3F, 3S, 4S and 4F remain positive although there NPVs have been slightly reduced.

Table 37: Results of Sensitivity Test 3 - Programme Management Costs

Base case

Sensitivity 3


Meter rollout

scenario

Option code

NPV

NPV Difference

TRUE


13,966,376 -1,697,473


-3,310,232 -1,697,473


-759,469 -1,697,473


-15,568,088 -1,697,473


31,626,365 -1,697,473


10,403,537 -1,697,473



32,293,907 -1,697,473


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6.5.4 Sensitivity Test 4: Supplier IT Systems Costs Increase The fourth sensitivity test (results of which are shown in Table 38) increases the smart metering IT systems costs for suppliers to the upper end of the CAPEX and OPEX range identified as part of the cost review – refer back to section 4 for further details. Thus the CAPEX is increased from €7.27 to €14.54 per meter, and the OPEX is increased from €1.25 to €2.00 per meter per annum. This test reflects that IT systems costs are a variable cost which could prove to be higher than those costs estimated in the main model. This sensitivity has the result of reducing the NPVs for all options by circa €11m, which results in:



Option 3S is also pushed down to a marginally positive NPV. Options 1F, 3F, 4S and 4F remain positive although there NPVs have

reduced. Table 38: Results of Sensitivity Test 4 - Supplier IT Systems Costs Increase

Base case

Sensitivity 4


Meter rollout

scenario

Option code

NPV

NPV Difference

TRUE


4,507,530 -11,156,319 Bimthly ES Phased 1S -1,612,759

-11,724,833 -10,112,074


-10,218,315 -11,156,319


-23,982,690 -10,112,074


22,167,519 -11,156,319


1,988,936 -10,112,074



23,879,306 -10,112,074


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6.5.5 Sensitivity Test 5: Dual Fuel Licence Cost Discount The fifth sensitivity test (results of which are shown in Table 39 reduces the assumed incremental electricity smart metering head-end and MDMS licence costs to support gas meters. This is because, as outlined in section 3.2.4, it is believed that the costs used in the main model are based on conservative assumptions. This sensitivity reduces:

The incremental head-end licence costs to support gas meters from €1.00 to €0.75 per gas meter, to reflect that it may be possible to negotiate commercial arrangements based on communication points rather than meters; and

The incremental MDMS licence costs to support gas meters from €1.50 to €1.00 per gas meter, to reflect that it may be possible to obtain a discount for dual fuel customers.

This sensitivity has the result of slightly increasing the NPVs for all options by less than €1m, which makes no real change to the status of any of the options. Table 39: Results of Sensitivity Test 5 - Dual Fuel Licence Cost Discount

Base case

Sensitivity 5


Meter rollout scenari

o

Option code

NPV

NPV Difference

TRUE


16,491,544 827,696


-853,131 759,628


1,765,699 827,696


-13,110,988 759,628


34,151,533 827,696


12,860,638 759,628


60,707,663 827,696

Bimthly ES + IHD + VT Phased 4S 33,991,380

34,751,007 759,628


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6.5.6 Sensitivity Test 6: Lower communication OPEX costs The sixth sensitivity test (results of which are shown in Table 40) reduces to zero the assumed incremental electricity smart metering wide area network (WAN) communications operational costs to support gas meters. This is because, as outlined in section 3.2.4, the main CBA model assumes that as gas meters will generate an extra 50% data payload, the CBA model assumes that communication costs will increase linearly resulting in an assumed incremental operational cost of €0.60 per gas meter. This is a very prudent assumption as it may be possible to accommodate the additional data payload within the data allowance that ESBN will purchase from data providers. Therefore sensitivity test 6 reduces the assumed operational cost from €0.60 to €0.00 per gas meter, which has the result of increasing the NPVs for all options by circa €4m, which results in:

Turning option 1S from a marginally negative to a marginally positive NPV. Strengthens the positive NPV for option 2F which was previously very

marginally positive. The status of the other options remains broadly unchanged.

Table 40: Results of Sensitivity Test 6 - Lower communication OPEX costs

Base case

Sensitivity 6


Meter rollout

scenario

Option code

NPV

NPV Difference

TRUE


20,254,245 4,590,397


2,185,734 3,798,493


5,528,400 4,590,397


-10,072,122 3,798,493


37,914,234 4,590,397


15,899,504 3,798,493


64,470,364 4,590,397


37,789,873 3,798,493


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6.5.7 Sensitivity Test 7: Energy Savings for Small Businesses The seventh sensitivity test (results of which are shown in Table 41) assumes that the small businesses included in the CBA who receive gas smart metering (by virtue of being part of the G4 meter category used by residential customers) will also achieve the same gas usage-related reductions attributed to residential customers, based on the gas CBT results. Because the gas CBT did not include such small businesses in the scope of the trial the main CBA model attributes no usage-related benefits to the circa 2% of small business customers in the G4 meter category – refer to section 5 for further details. Therefore sensitivity test 7 increases the usage-related benefit across all the options by circa 2%, which has the result of increasing the NPVs for all options by circa €2m, which results in no significant change to the status of any of the options. Table 41: Results of Sensitivity Test 7 - Energy Savings for Small Businesses

Base case

Sensitivity 7


Meter rollout

scenario

Option code

NPV

NPV Difference

TRUE


17,226,041 1,562,193


-332,261 1,280,498


2,915,066 1,977,063


-12,248,257 1,622,359


35,325,955 2,002,118


13,739,430 1,638,420


62,366,100 2,486,133


36,028,638 2,037,258


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6.5.8 Sensitivity Test 8: IHD benefit wanes from 2020 onwards The eighth sensitivity test (results of which are shown in Table 42) allows for the possibility that the effect of having an IHD on residential demand does not persist after the IHD has gone. In the main model IHDs are assumed to be supported only during the rollout period and for one year thereafter (i.e. end-2019). No provision was made to refresh the IHD population later in the project. In the analysis of the ‘with IHD’ options, the assumption was made that the effect of having an IHD on residential demand (2.9% for option 3 and 3.6% for option 4, as measured by the gas CBT) persists for the life of the project. In effect, the stimulus has caused a step change in demand and the household never reverts to the baseline usage path. This sensitivity test relaxes this assumption, replacing the IHD effect with a bi-monthly billing only effect (2.2%, as measured by the gas CBT) for the ‘with IHD’ options from 2020 onwards. Therefore sensitivity test 8 decreases the usage-related benefit for the ‘with IHD’ options (options 3 and 4, in both phased and fast rollout scenarios) which has the result of significantly decreasing the NPVs for these options: by €18m and €20m for options 3F and 3S respectively; and by €40m and €35m for options 4F and 4S respectively, which results in:

Options 3S and 4S are both pushed into a negative NPV, meaning that 4 of the 8 options (all of the phased rollouts) would now have negative NPVs.

Options 3F and 4F remain positive although their NPVs have been substantially reduced.

Table 42: Results of Sensitivity Test 8 - IHD benefit wanes from 2020

Base case

Sensitivity 8


Meter rollout

scenario

Option code

NPV

NPV Difference

TRUE






13,531,982 -19,791,855


-5,433,405 -17,534,415



-1,077,451 -35,068,831


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6.5.9 Sensitivity Test 9: Gas Price Forecasts The ninth sensitivity test (results of which are shown in Table 44) assumes that the gas price used is based on the ICE gas futures instead of the current price. The main model assumes that the gas price is £0.711075 per therm which is held constant until 2032. This sensitivity assumes that the following prices based on the ICE gas futures are used (outlined in Table 43 below), the values for each year have been calculated as the average of the monthly futures, based on data published by ICE on 21st September 201135. It is assumed in this sensitivity that the 2017 price remains constant until 2032. Table 43: ICE Gas Futures Prices Used in Sensitivity Test 9

Year Price (STG p/therm)

2011 69.703 2012 71.115 2013 72.713 2014 73.558 2015 73.942 2016 74.980

2017-32 76.153 Because the futures gas prices are higher than the current constant price assumed in the main model, the effect of this sensitivity test is to increase the NPVs across all options by €4m to €7m, which results in:

Turning option 1S from a marginally negative to a marginally positive NPV. Strengthens the positive NPV for option 2F which was previously very

marginally positive. The status of the other options remains broadly unchanged.

Table 44: Results of Sensitivity Test 9 - Gas Price Forecasts

Base case

Sensitivity 9


Meter rollout

scenario

Option code

NPV

NPV Difference


20,275,585 4,611,737 Bimthly ES Phased 1S -1,612,759

2,197,209 3,809,968


6,765,757 5,827,753


-9,056,477 4,814,139


39,354,260 6,030,423


17,082,510 4,981,500


67,329,075 7,449,108 Bimthly ES + IHD + VT Phased 4S 33,991,380

40,144,412 6,153,033

35 Daily Volumes for ICE UK Natural Gas Futures (Monthly) https://www.theice.com/marketdata/reports/ReportCenter.shtml?reportId=10


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6.5.10 Sensitivity Test 10: Gas Price Consistent with Electricity CBA The tenth sensitivity test (results of which are shown in Table 45) assumes that the gas price used should be consistent with the gas price that underpinned the electricity CBA i.e. £0.51 per therm constant value instead of £0.711075 per therm constant value. Because the electricity CBA gas price is lower than the current constant price assumed in the main model, the effect of this sensitivity test is to substantially decrease the NPVs across all options by circa €15m to €30m, which results in:


Option 1F, 2F and 3S are also pushed down into negatives NPVs to various extents.

Options 3F, 4S and 4F remain positive although their NPVs have reduced substantially.

Table 45: Results of Sensitivity 10 - Gas Price Consistent with Electricity CBA

Base case

Sensitivity 10


Meter rollout

scenario

Option code

NPV

NPV Difference

TRUE


-3,019,435 -18,683,283 Bimthly ES Phased 1S -1,612,759

-17,014,816 -15,402,057


-22,671,619 -23,609,622


-33,332,070 -19,461,454


8,893,159 -24,430,678


-8,037,010 -20,138,020



9,117,397 -24,873,983

It should be noted that the ESRI suggested that a more correct treatment of the change in gas prices in the period between the electricity and gas CBA being conducted should be addressed by re-running the electricity CBA with the more up-to-date gas price of £0.711075 per therm. This would result in an increase in the NPVs for all rollout options tested in the electricity CBA, all other things remaining equal.


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6.5.11 Sensitivity Test 11: Discount Rate The final sensitivity test varies the real discount rate from its baseline value of 4% to show what the impact would be on total NPVs from changing the real discount rate for all 8 Options. Increases to the discount rate not surprisingly reduce the NPVs: in general, costs tend to come earlier than benefits. Table 46 below shows the discount rate that would be required to turn the NPVs of each of the options to zero.

As Options 1S and 2S are already negative at the baseline 4% discount rate, it would require the discount rate to fall to bring them up to an NPV of zero.

The other options are all positive at the baseline 4% discount rate. It would take the discount rate to rise to bring them back to an NPV of zero. A discount rate rise to up to 6% would turn the NPVs to zero for options 1F, 2F and 3S. As 2F has only a very marginally positive NPV it takes only a marginal rise of 0.1% in the discount rate to turn it to zero. Options 3F, 4F and 4S require a substantial rise in the discount rate (above 7%) before their NPVs turn zero. Figure 20 displays the discount rate sensitivities for each of these options graphically.

Table 46: Discount Rate That Would Turn Each Option’s NPV to Zero Energy saving scenario

Meter rollout scenario

Option code

Discount rate cut-off value

Bimthly ES Fast 1F 5.8%

Bimthly ES Phased 1S 3.8%

Monthly ES Fast 2F 4.1%

Monthly ES Phased 2S 1.9%

Bimthly ES + IHD Fast 3F 7.4%

Bimthly ES + IHD Phased 3S 5.6%

Bimthly ES + IHD + VT Fast 4F 9.8% Bimthly ES + IHD + VT Phased 4S 8.1%


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Figure 20: Sensitivity of NPV to Real Discount Rate for Options 1F, 2F, 3F, 3S, 4F, 4S

-20

-15

-10

-5

0

5

10

15

20

4% 5% 6% 7% 8%

NPV

(EU

Rm)

Bi-monthly ES - FAST (1F)

-25

-20

-15

-10

-5

0

5

4% 5% 6% 7% 8%

NPV

(EU

Rm)

Monthly ES - FAST (2F)

-10

0

10

20

30

40

4% 5% 6% 7% 8%

NPV

(EU

Rm)

Bi-monthly ES+ IHD - FAST (3F)


134

-15

-10

-5

0

5

10

15

4% 5% 6% 7% 8%

NPV

(EU

Rm)

Bi-monthly ES+ IHD - SLOW (3S)

0

10

20

30

40

50

60

70

4% 5% 6% 7% 8%

NPV

(EU

Rm)

Bi-monthly ES + IHD + VT - FAST (4F)

0

5

10

15

20

25

30

35

40

4% 5% 6% 7% 8%

NPV

(EU

Rm)

Bi-monthly ES + IHD + VT - SLOW (4S)


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6.5.12 Summary of Sensitivity Tests The sensitivity tests show that the NPVs for all the options in the gas CBA model are very sensitive to a number of key variables, in particular the price of gas (Tests 9 and 10) and the discount rate used (Test 11). Reductions in the price of gas and increases in the discount rate will tend to push more of the options into negative NPVs depending on the extent of the changes. The NPVs are also moderately sensitive to increases in the cost of smart meters (Test 2) and supplier IT systems (Test 3) and programme management costs (Test 4). Generally the ‘with IHD’ options have the strongest NPVs. However, these strong positive values proved very sensitive to a change in the assumption regarding the persistence of the IHD energy saving impact post-2020 (Test 8). They are also sensitive to a lesser extent to a change in the assumption regarding sharing of the IHD device costs (Test 1). The other sensitivity tests (Test 5, 6, 7 and 9) all improved the NPVs across all options from minor to moderate extents. Option 4, in particular the fast rollout scenario (4F), tends to remain positive across all the sensitivity tests.


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6.6 Summary The estimated total NPVs for the 8 national gas smart metering rollout options analysed in the quantitative CBA are generally positive, often substantially so, for options including an IHD (options 3 and 4), and generally negative or marginal for options not including an IHD (options 1 and 2), with the exception of option 1F. The NPVs are generally more favourable for energy saving scenarios based on the fast rollout scenario compared to the phased rollout scenario. If these results were borne out in an actual deployment of gas smart metering, leveraging an electricity smart metering infrastructure, the project would bring about net benefits for Ireland in comparison with the base case (counterfactual) scenario for the ‘with IHD’ options (3 and 4), especially if a fast rollout approach is taken (options 3F and 4F), and also the ‘without IHD’ option 1F. It should be noted when comparing the NPVs for the energy saving scenarios that, based on the gas CBT findings, although the usage reductions detected are each statistically significant against the control group, differences between treatment effects (energy saving scenarios) are not necessarily statistically significant. Important sources of variation in estimated NPVs arose from assumptions about the price of gas and the discount rate used. The NPVs are also moderately sensitive to increases in the cost of smart meters, supplier IT systems and programme management costs. Generally the ‘with IHD’ options, which generally have the strongest NPVs of all options, proved very sensitive to a change in the assumption regarding the persistence of the IHD energy saving impact post-2020. They are also sensitive to a lesser but not insignificant extent to a change in the assumption regarding sharing of the IHD device costs. The other sensitivity tests all improved the NPVs across all options from minor to moderate extents.


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7.0 Qualitative Costs and Benefits

7.1 Introduction In ensuring that a robust gas CBA was developed, a conservative approach was taken, which resulted in the inclusion of only robust data in the quantifiable costs and benefits. This led to a number of exclusions which are described below.

7.2 Potential for greater usage-related benefits There may be a potential for greater usage-related benefits to be realised from a national gas smart metering rollout than was included in the quantifiable CBA. A purist experimental approach was taken for the gas customer behaviour trials which prohibited any customer communications interventions during the active test period (1 June 2010 – 31 May 2011). Thus trial participants received an information pack at the end of May 2010 which informed them of their role in the trials (i.e. control group participant or test group participant including information about the informational stimulus they would be trialling). In a national rollout scenario it can be safely assumed that there would be a sustained high profile awareness and education campaign about smart metering and its associated energy efficiency initiatives. This may result in greater engagement from consumers and hence a greater reduction in both gas consumption than the levels detected in the experimental gas CBT.

7.3 Monthly Electronic Billing Costs for Suppliers For the monthly billing stimulus options included in the gas CBA a major factor in making this stimulus less attractive in NPV terms when compared with the other bi-monthly bill based stimuli is the supplier related costs of printing and posting six additional bills per year. It was assumed for CBA purposes that all customers would be receiving paper based monthly billing. However, in a national smart metering rollout scenario that includes a move to monthly billing cycle by suppliers it can be assumed that there would be a greater move by customers towards electronic billing (e-billing), as this type of billing becomes more acceptable and accessible to customers, and suppliers push it more. If e-billing penetration was greater in a future smart metering world then the incremental costs for suppliers associated with a move to monthly billing would be significantly less than those included in the CBA and the NPV for this stimulus would improve.

7.4 Hedging Benefits for Suppliers In many international smart metering CBAs the reduction in hedging costs is often quoted as a potential benefit for suppliers – associated with the provision from smart metering of additional information about consumption patterns which could help suppliers carry out their hedging operations more efficiently. However, due to uncertainty in quantifying this benefit it has not been included in the gas CBA, which


138

is in line with the assumption made for the electricity CBA. However it is safe to assume that some benefit will be attributed to suppliers and thus the supplier related benefits included in the gas CBA may be slightly underestimated.

7.5 Customer Interface Costs and Benefits There are some networks related benefits associated with an installation of smart meters that have been excluded from the CBA. These are associated with the resolution of certain customer interface issues that networks installers will encounter when installing smart meters that they can’t ‘walk away from’ even though it may not officially be the responsibility of BG Networks, such as safety related remedial works required in the home. While robust estimates could be put on the costs associated with this work it was not possible to put similarly robust estimates on the value of associated benefits that would derive from undertaking this work e.g. avoided injury and damage. Therefore no customer interface safety related costs or benefits have been included in the gas CBA, which is consistent with the electricity CBA treatment of such costs and benefits.

7.6 Competition-related Benefits The enhanced information on gas consumption provided to consumers via bills, in-home displays and other channels should result in consumers being better informed and more aware of their actual gas consumption and costs. This should enhance consumer ability to identify better tariff deals, switch suppliers and therefore drive prices down. In tandem with this enhanced consumer participation in the gas market, suppliers (existing and new) will be able to offer consumers an enhanced choice of products and services based on smart metering (subject to data protection requirements) e.g. a greater range of tariff offerings and new energy efficiency services that utilise smart metering information. Third party energy services companies will also be able to offer new energy efficiency services to consumers using the smart metering information (again, subject to data protection requirements). Overall, smart metering should enhance the operation of the competitive gas market by improving the consumer participation and choice, and encouraging suppliers’ (and others) to innovate. It is difficult to quantify these competition-related benefits and therefore they are not included in the CBA. The CBA does however include a quantifiable benefit for suppliers arising from a reduction in supplier switching costs - which can mainly be attributed to the availability of automated actual account closure meter reads to suppliers replacing a current switching process where suppliers rely mainly on manual meter reads provided by customers (section 4.9).

7.7 Consumer Investment Related Benefits Gas consumers might benefit from the increase in quantity and quality of usage information available from their smart meters by helping better inform their decisions


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relating to making energy efficient investments in their home e.g. timer control installation, boiler upgrade, adding or improving insulation. Potential investment related benefits could not be tested due to the duration and finite nature of the gas CBT.

7.8 Summary This section has described a number of potential costs and, mostly, benefits from a national rollout of gas smart metering that are very difficult to put a robust quantifiable estimate on and therefore have been excluded from the quantifiable CBA. Generally, these exclusions reflect the conservative approach taken to the CBA which tends towards a likely underestimation of the potential benefits from a national gas smart metering rollout.


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8.0 Conclusions

8.1 Summary and Next Steps The CER has worked with industry stakeholders to produce a detailed cost-benefit analysis (CBA) on a number of options for the national rollout of smart meters in the Irish gas market. This CBA delivers a robust economic assessment of the long-term costs and benefits to the market and the individual consumer of a national gas smart metering rollout that leverages the infrastructure required for a national electricity smart metering rollout. The analysis indicates that the rollout of gas smart metering has the potential to provide a positive net benefit the Irish gas market and consumers. The publication of this report is a major milestone in the CER’s Smart Metering project, and a key deliverable in the completion of Phase 1 (delivery of trials and CBAs for electricity and gas smart metering). The findings from the CBA will provide a rich source of information which will be used to inform energy policy decisions in Ireland relating to smart metering and related initiatives such more innovative tariffs, more detailed and frequent billing, in-home displays and prepayment metering. The rollout of smart metering represents a major national energy infrastructure project and the publication of this report is one of the defining milestones in its delivery. Given the scale of investment required to deliver smart metering, a thorough and robust analysis is required to substantiate any rollout decision. This gas smart metering CBA, which concludes that a positive net benefit is achievable for the Irish gas market and consumers, will, along with the positive results from the electricity smart metering CBA (CER/11/080c), facilitate the further development of the Smart Metering Project. The next steps for the project are outlined in the Smart Metering Information Paper 5 (CER/11/180) which accompanies this CBA report. The CER appreciates the significant contribution of all stakeholders that have been involved in compiling this CBA and the other reports and looks forward to their ongoing involvement in the next steps for the Smart Metering Project.


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Appendix A – Glossary A2A: Application-to-Application B2B: Business-to-Business BGN: Bord Gáis Networks CAPEX: Captial Expenditure CBA: Cost-benefit analysis CBT: Customer Behaviour Trial CER: Commission for Energy Regulation CIS: Customer Information System CO2 : Carbon Dioxide DCENR: Department of Communications, Energy and Natural Resources DSM: Demand Side Management ERGEG: European Regulators Group for Electricity and Gas ES: Energy Statement ESBN: ESB Networks ESRI: Economic and Social Research Institute EU: European Union FTE: Full-time Equivalent GGP: Guidelines for Good Practice GIS: Geographical Information System GVC: Gross Calorific Value HAN: Home Area Network IHD: In-Home Display JGCS: Joint Gas Capacity Statement kWh: Kilo Watt Hour LAN: Local Area Network LPR: Low Powered Radio MDMS: Meter Data Management System MRP: Meter Replacement Programme NEEAP: National Energy Efficiency Action Plan NIAUR: Northern Ireland Authority for Utility Regulation (NIAUR) NPV: Net Present Value NRA: National Regulatory Authority OPEX: Operation Expenditure PAYG: Pay As You Go PLC: Power Line Carrier PPM: Pre-Payment Metering RF: Radio Frequency SEAI: Sustainable Energy Authority of Ireland SME: Small-to-Medium Enterprises TC: Temperature Compensated TOU: Time of Use UAG: Unaccounted for Gas VAT: Value Added Tax VT: Variable Tariff WAN: Wide Area Network