Smart Grid, Smart City: Shaping Australia s Energy Future. Executive Report

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1 Smart Grid, Smart City: Shaping Australia s Energy Future Executive Report July 2014

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3 ABOUT THE AUTHORS In March 2013, a consortium of Australian-based consultancy firms was commissioned to utilise the Smart Grid, Smart City trial results and learnings to develop an integrated cost benefit assessment for smart grid technologies in a national context. The AEFI consulting consortium included: Arup Energeia Frontier Economics Institute for Sustainable Futures (University of Technology Sydney) WRITING AND PROJECT MANAGEMENT TEAM Arup Project Director Richard Sharp, Project Manager Ranelle Cliff ACKNOWLEDGEMENTS AEFI would like to thank Ausgrid and Australian Government staff for their detailed input in providing background information, Smart Grid, Smart City trial data and feedback on different elements of the cost benefit assessment and final report. This report was prepared by Arup in connection with the Smart Grid, Smart City Program in It takes into account our client's particular instructions, requirements and priorities at the time. This report is based on specific assumptions which have been outlined in a number of supporting technical documents published in conjunction with this report. No responsibility is taken by Arup to any third party including in relation to their use of the findings in this report and third parties are advised to undertake their own assessments as required to satisfy themselves as to the adequacy or otherwise of the contents on this report. Michelle Norris (lead writer), Ranelle Cliff, Richard Sharp, Samuel Koci, Hugh Gardner Energeia Melanie Koerner, Ezra Beeman, Geoff Erder Frontier Economics Andrew Harpham, James Allen Institute for Sustainable Futures Edward Langham, Jenni Downes National Cost Benefit Assessment: Executive Report ARUP 1

4 Executive Report Contents 1 Introduction The Smart Grid, Smart City Program Location of smart grid trial activities 10 2 The Smart Grid, Smart City Trials Common platforms work stream overview Grid applications work stream overview Customer applications work stream overview Distributed generation and distributed storage work stream overview Electric vehicles work stream overview 18 3 About the final series of reports from the Smart Grid, Smart City Program The national cost benefit assessment report Smart Grid, Smart City Information Clearing House 22 4 Approach to the cost benefit assessment 24 5 Stakeholder Engagement Rapid stakeholder engagement Stakeholder forum Stakeholder priorities 28 6 Customer interaction Smart Grid, Smart City retail and network trial survey results Background to the retail and network customer trials The Customer Research Survey scope of works Trial participant experience survey results Comparing trial participant responses to different feedback technologies and tariff products Financially vulnerable households Conclusions from Customer Research Survey Conclusions from Customer Research Survey 41 7 Introduction to the national integrated cost benefit assessment Introduction to national integrated cost benefit assessment Economic deployment of smart grid technologies Individual technology cost benefit assessments Medium integrated cost benefit assessment economic scenario results 48 2 National Cost Benefit Assessment: Executive Report ARUP

5 8 Key findings and recommendations for individual smart grid technologies and products Introduction Key findings and recommendations for Fault Detection, Isolation and Restoration (FDIR) technologies Key findings and recommendations for Active Volt-VAr Control (AVVC) technologies Key findings and recommendations for Substation and Feeder Monitoring (SFM) Observations on wide area measurement systems (WAMS) trials Key findings and recommendations for Smart Meter Infrastructure (stand-alone) Key findings and recommendations for dynamic tariffs and customer feedback technologies (plus SMI) Key findings and recommendations for Electric Vehicles (EVs) Key findings and recommendations for Distributed Generation (DG) and Distributed Storage (DS) Key findings and recommendations in relation to customer electricity bills 74 9 Transitioning industry and consumers to a smart grid future Electricity distribution networks Electricity consumers Transitioning to greater volumes of distributed generation Australia s grid emissions intensity Maximising the benefits and opportunities in transitioning to a smart grid in Australia Balancing financial, reliability and environmental benefits The case for cost reflective prices The case for in-grid smart grid technologies Varying economic conditions and national net benefits Prioritising the recommendations from the national integrated cost benefit assessment 86 Table of Acronyms 91 Glossary of terms 98 National Cost Benefit Assessment: Executive Report ARUP 3

6 Preface This is an independent report that has been prepared and developed following the successful completion of the Australian Government s $100 million Smart Grid, Smart City Program. This major government initiative was delivered by Ausgrid and its consortia partners for the purpose of supporting and informing the industry-led adoption of smart grid technologies in Australia. Australia s electricity network and retail operators, for the most part, are currently able to fulfil their obligations to provide reliable, safe and secure and relatively affordable electricity to all types of consumers. The continuing efficiency and resilience of the electricity system is fundamental to national productivity and economic growth. However, in recent times, the challenges facing the sector have increased in both scale and complexity. These challenges include changes in the trends of overall electricity demand and consumption (from highly positive growth to negative growth); a sharp increase in distributed generation (rooftop solar photovoltaic in particular); and changes to reliability standards, policies and regulatory frameworks. Consequently electricity network operators are under growing pressure to anticipate and deliver outcomes that challenge the capabilities of existing infrastructure systems. The reform agenda currently underway in Australia s energy sector is occurring in parallel with a global transformation in the way electricity is produced, transported and stored. In particular, over the past five years, Australians have seen major changes in the electricity sector. Network operators have invested billions of dollars in network refurbishment, while at the same time building additional network infrastructure late last decade to meet record demand for electricity during peak periods. More than 1 million Australians 1 have now embraced solar power by installing rooftop solar photovoltaic (PV) systems. The number of installed systems will continue to grow in both residential and commercial buildings. Wind power capacity has also grown rapidly, predominantly driven by the Renewable Energy Target (RET). In most states, residential customers have also experienced significant electricity price increases in response to network capital renewal programs. This has resulted in an increase in the number of households having difficulty in paying their electricity bills. As evidenced by these issues and others, the Australian energy sector will continue to face growing challenges in providing resilient and affordable electricity to consumers. Smart grid technologies have a role in addressing a number of these challenges. In 2009 the Australian Government recognised the importance of investing in commercial-scale trials of promising smart grid technologies, and as a result allocated funding in the order of $100 million 2 in the Smart Grid, Smart City Program. In total, around $490 million was invested in the Smart Grid, Smart City Program by all contributors. The Program, which ran from 2010 to , sought to determine whether there were benefits from the deployment of these technologies for Australia. 1 Climate Commission, The critical decade Australia s future solar energy, Unless otherwise specified, all dollar figures in this Report are quoted in AUD. 3 The Smart Grid, Smart City customer application trials were extended over the summer period, to enable additional data to be collected on residential customer behaviour and willingness to modify electricity usage. This allowed a greater amount of trial data to be used in the cost benefit assessment analysis 4 National Cost Benefit Assessment: Executive Report ARUP

7 The Smart Grid, Smart City Program was arguably one of the widest-ranging technology assessments of smart grid products in the world. It saw: The deployment and testing of several smart in-grid and customer-focussed technology groupings across the Ausgrid network and EnergyAustralia retail business in New South Wales Examined the impacts and benefits of additional distributed generation and distributed storage solutions Involved approximately 17,000 electricity customers in consumer-focussed trials examining how residential customers could contribute to peak demand management through behavioural changes The Smart Grid, Smart City Program focused on residential customers, as they represent the largest user group in Australia, and generally have more discretion over when and how much energy they use. Little was known before the Smart Grid, Smart City trials about how customers perceived, or how they might respond to, the opportunities that smart grid technologies offer. Most residential electricity customers in Australia are currently provided with limited information and very few incentives and tools to manage their domestic electricity use. A quarterly electricity bill is the main source of customer feedback, and this only shows the total amount of energy used during the previous three months, limiting the opportunities to systematically modify behaviour in order to save electricity and money. Based on the trials undertaken, this final Smart Grid, Smart City report, Shaping Australia s Energy Future: National Cost Benefit Assessment found the potential for a net economic benefit of up to $28 billion ($2014) over the next 20 years from the deployment of smart grid technologies in Australia. This report demonstrates that there are four key aspects to realising these benefits and improving consumer pricing outcomes: Technological development and deployment of enabling (smart grid) technologies The introduction of cost reflective electricity pricing including dynamic tariffs Consumer behaviour change with respect to electricity consumption (to better manage any future growth in peak demand) Energy market reform 4 (many aspects of which are already underway) Realising the potential benefits requires an integrated solution if any one aspect is not implemented, then the extent of net national economic benefits available will be reduced. A large proportion of the net benefits identified can be derived from the economic deployment of a number of in-grid technologies which improve operational efficiency, reduce capital investment (through better managing peak demand) and deliver improved reliability for consumers at a lower cost. There are vast differences across Australia s electricity grid, from highly populated suburban areas to sparsely populated rural areas, and different smart grid technologies are better suited in different circumstances. For those Australians living in suburban areas, there are significant potential benefits from certain in-grid technologies. Likewise, for less densely populated rural networks, there are alternative in-grid technologies which can assist in improving the reliability and cost of managing the grid. 4 The reforms relevant to this report are discussed in Appendix One and Part Three (Conclusions and Recommendations) in the main report. These are also discussed more briefly in Section 8 of this Executive Report National Cost Benefit Assessment: Executive Report ARUP 5

8 At present, commercially mature forms of distributed storage have limited availability and are not financially viable for most Australians. However, this cost benefit assessment indicated that from the early-tomid 2020 s, distributed storage could begin to be financially attractive for consumers and will grow in installed capacity over the period through to In the future, electricity networks in Australia will be expected to continue to provide sufficient capacity to deliver electricity and meet demand peaks. Analysis undertaken as part of the Smart Grid, Smart City Program has shown that it is possible to more effectively manage peak demand through consumer behavioural change and with the assistance of feedback technologies and dynamic tariffs. This analysis showed that with the appropriate pricing signals and behavioural changes it could be possible to improve electricity bill outcomes for consumers and increase the level of network asset utilisation compared to traditional approaches of additional network and generator capital investment. Changes in tariff structures (dynamic pricing signals), and the associated consumer behaviour change, will need to be carefully considered in conjunction with governments, consumer groups, network operators and retailers to ensure that the solutions developed has regard for all stakeholder perspectives. Some of this work is already underway with the Australian Energy Market Commission (AEMC) considering proposed rule changes from the Council of Australian Government (COAG) Energy Council. In addition the COAG Energy Council has a work program which is focussed on improving consumer demand side participation through time-varied electricity pricing. For Government, the findings of this report will need to be considered within the context of the existing energy market reform agenda and is intended to provide empirical data which supports future decision making and identifies where additional future investigations may be warranted. 6 National Cost Benefit Assessment: Executive Report ARUP

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10 1 Introduction Electricity grids have developed over time and in an environment where planning and managing the provision of reliable, safe and secure electricity supply was predicated on key assumptions. The implicit assumption of grid planners and managers has been that electricity will be generated at a few locations and distributed to many energy users, and that the behaviour of both generators and users can be predicted with a reasonable degree of confidence over time scales of hours, days and years. 5 These long-held assumptions are now being called into question, and in many parts of Australia, may no longer hold in the very near term. For the most part, networks across Australia are currently able to fulfil their obligations to provide reliable, safe and secure electricity to all types of consumers. This is largely due to the robust regulatory environment in which they operate. However, in recent times, the challenges of network planning, management and associated costs are increasing in scale and complexity. These challenges include changes in the trends of overall electricity demand and consumption (from highly positive growth to negative growth); a sharp increase in distributed generation (rooftop solar PV in particular); and changes to reliability standards, policies and regulatory frameworks. Consequently, electricity network operators are under growing pressure to anticipate and deliver outcomes that challenge the capabilities of existing infrastructure systems. This need for more advanced decision-making abilities for network operators is reasonably consistent throughout the world. As a consequence a range of innovative information and communication systems have been developed and are now driving an electricity grid modernisation often termed a smart grid. Standards Australia defines a smart grid as an electricity system incorporating electricity and communications networks, that can intelligently integrate the actions of parties connected to it. The implicit assumption in smart grids is that energy may be generated and used anywhere on the grid, the behaviour of both generators and users is much more variable and less predictable, and that both will continuously react to the other 6. Smart grid technologies offer the potential to better predict electricity supply and demand at specific locations in the grid, continuously monitor the condition of the grid and major assets, dynamically reconfigure the network and more efficiently utilise labour and materials. These technologies also provide the opportunity to interact with customers in order to actively manage demand on different parts of the network. However, the boundary between a conventional grid and a smart grid is not easily identified. 5 Standards Australia AS5711 Australian Standard: Smart Grid Vocabulary, 2013 ISBN Standards Australia AS5711 Australian Standard: Smart Grid Vocabulary, 2013 ISBN National Cost Benefit Assessment: Executive Report ARUP

11 There is no absolute level of capability or set of attributes which marks the transition of a specific electricity network from conventional to smart. Grids may become more smart over time as they acquire more of the transactional, operational and technical features defined in this Standard. In general, a smart grid is distinguished from a conventional grid by the deployment of enhanced information and communications systems, in order to manage equipment in a way that achieves outcomes remotely, automatically, more rapidly and more precisely 7. Modernising the grid using smart technologies will require additional capital investment. Determining the most economically efficient technologies and deployment opportunities for Australian conditions was a key driver of the Australian Government s investment in the Smart Grid, Smart City Program in The Smart Grid, Smart City Program In 2010, the Australian Government committed approximately $100 million in funding to the Ausgrid consortium which included: Ausgrid (one of the three New South Wales electricity distribution entities); IBM Australia; GE Energy Australia; Grid Net; CSIRO; TransGrid; EnergyAustralia; Landis+Gyr; Sydney Water; Hunter Water; the University of Newcastle; the University of Sydney; Lake Macquarie City Council and the City of Newcastle. Ausgrid and its trial partners provided additional funding resulting in total funding for the Smart Grid, Smart City Program of approximately $490 million in both cash and in-kind support. The Smart Grid, Smart City Program represents one of the largest commercial-scale trial deployments of smart grid infrastructure of its kind in the world. The objectives of the Smart Grid, Smart City Program were to: Deploy a demonstration and/or commercial scale rollout, as specified in the Guidelines, that informs a business case for key applications and technologies of a smart grid Build public and corporate awareness of the economic and environmental benefits of smart grids and obtain buy-in from industry and customers Gather robust information and data to inform broader industry adoption of smart grid applications across Australia Investigate synergies with other infrastructure (such as gas, water and the National Broadband Network) As part of awarding the funding, the Australian Government specified a range of activities, outcomes and data priorities for each of the trial work streams. These activities and data priorities were designed to answer a number of research questions. The Australian Government also specified a number of key datasets and results which it expected the Smart Grid, Smart City trials to produce. Each of these activities, outcomes and data priorities was specified in contractual obligations and have been reported against over the trial period. In essence, the Smart Grid, Smart City trials focused on producing results which could be used to determine whether individual or combinations of smart grid technologies could achieve economic benefits for Australian electricity consumers. 7 Standards Australia AS5711 Australian Standard: Smart Grid Vocabulary, 2013 ISBN National Cost Benefit Assessment: Executive Report ARUP 9

12 1.2 Location of smart grid trial activities The trial was largely focussed on the greater Newcastle and Sydney CBD areas with some additional areas selected to test specific smart grid applications on long rural network topologies. The selection of appropriate geographic locations for the trial was considered critical to producing reliable data that could be accurately extrapolated to assess the viability of a large scale smart grid roll-out in Australia. The greater Newcastle area was selected as one of the focal points for the trial due to its mix of regional and suburban characteristics that result in representative geography, climate, socioeconomic and demographic factors. The customer demographic and socioeconomic indicators in Newcastle closely reflect the demographic attributes of a typical Australian city. Newcastle s close relationship to the Australian average for customer demographics is widely accepted and has resulted in the city being used as a test market for products and services prior to their rollout across Australia in the past. The Smart Grid, Smart City trial locations (see Figure 1) were designed to provide a sound representation of the geographic, climate, customer demographic and electricity network characteristics of a number of regions throughout Australia. It was felt that this would produce nationally transferrable results. Importantly, the trial locations: Included a mix of both urban and regional areas Had demographic characteristics closely reflecting the national average in terms of household income, household occupancy, English proficiency, housing types, tenure types, energy sources and appliance stock. In addition, the trial locations contained sufficient variability in these characteristics to test their impact on measured outcomes Had similar climates to a large portion of the Australian population including both Climate Zones 5 and 6 8, in which per cent of Australia s population is located Demonstrated energy consumption patterns reflective of the Australian population, including both summer and winter peaks in energy demand Had sufficient variability in topographic and terrain characteristics to allow accurate testing of alternative technologies Demonstrated a range of different overhead and underground network configurations, both radial and meshed networks, and had rural, urban and CBD characteristics typical of Australian networks Contained several areas with high network utilisation making them good locations to demonstrate energy efficiency and demand management initiatives. Given the different network types captured by these varying geographic, socioeconomic, demographic and electricity network conditions, it was determined that these areas were broadly representative of a large portion of the Australian population. These are discussed further in Table 1. 8 The climate zones used for the purposes of the Smart Grid, Smart City Project were based on those produced by the Australian Building Codes Board, last published in December National Cost Benefit Assessment: Executive Report ARUP

13 Table 1 Geographic locations of the Smart Grid, Smart City trials Location Greater Newcastle area Sydney CBD Ku-Ring-Gai area Newington area Scone area Nelson Bay area Characteristic useful for the Smart Grid, Smart City trials The greater Newcastle area was selected as the focal point for the trial, due to its good mix of regional and suburban characteristics, representative geography, climate, socioeconomic and demographic factors of the broader Australian population. The customer demographics and socioeconomic indicators of the area closely reflect the demographics of a typical Australian city. Part of the City of Sydney Local Government Area (LGA), this area provided additional high density residential buildings and large scale co-generation. Situated on the north shore of Sydney, this area provided additional testing of high income demographics. The area also provided a high number of customers with swimming pools (approximately 36 per cent in some areas of the Local Government Area) for testing new products. Part of the Auburn LGA, this area provided a typical Western Sydney climate zone and suburban environment for broad testing. The suburb added a high multicultural population and contains the highest penetration of customer photovoltaic energy generation, assisting in the trial of renewable generation and storage applications. Part of the Upper Hunter LGA, this area provided additional rural characteristics and a more extreme climate zone. The area provided a rural network to perform end of feeder trials and much lower levels of internet use representative of more rural geographies. An area north of Newcastle in NSW, including two zone transformers with eight feeders exhibiting signs of moderate voltage constraint, supporting around 10,000 customers spread across 210 distribution transformers. This area is typical of older (brownfield) distribution zones with existing constraints which made it amenable to testing the potential benefits of grid application technologies. National Cost Benefit Assessment: Executive Report ARUP 11

14 Figure 1 Map of Smart Grid, Smart City Trial Locations 12 National Cost Benefit Assessment: Executive Report ARUP

15 2 The Smart Grid, Smart City Trials The aim of the Smart Grid, Smart City Program was to gather robust information about the costs and benefits of smart grids to help inform future decisions about smart grid technologies by government, electricity providers, technology suppliers and consumers across Australia. The trials involved the development, deployment, trial and analysis of smart grid infrastructure, products and solutions. For the purpose of the trials, the smart grid technologies and applications were categorised into work streams described in Table 2. A high level overview of the individual Smart Grid, Smart City work streams is provided in the following sections. A more detailed account of the timelines and deliverables, trial findings, conclusions, lessons learned and recommendations can be found in individual Technical Compendia or Part One of the main report. Table 2 Work streams for the Smart Grid, Smart City trial Name of work stream Supporting Information and Communication Technology Platforms (Common Platforms) Grid Applications Customer Applications Distributed Generation and Distributed Storage Electric Vehicles Description of work stream Investigated the feasibility of various high-speed, reliable and secure data communications network and associated IT systems which integrate with the electrical distribution network. It also examined interoperability with the National Broadband Network. Investigated the ability of grid-side monitoring and control technologies to reduce network operating costs and support the future planning and implementation of lower cost networks. Focused on residential electricity consumption, reliability, customer behaviour and responses to feedback technologies and pricing models. It also included an electric vehicle trial and investigations into the interoperability of electricity metering with gas and water metering. Investigated the feasibility and potential benefits of distributed generation and distributed storage within electricity grids. Investigated the potential impact of wide-scale uptake of electric vehicles in Australia on the electricity distribution network. National Cost Benefit Assessment: Executive Report ARUP 13

16 2.1 Common platforms work stream overview Unlike the rest of the Smart Grid, Smart City trials, which evaluated specific smart grid technologies, the purpose of this work stream was to provide an evaluation of how successfully these trials were able to leverage the common platform developed as part of the Smart Grid, Smart City Program. In addition this work stream sought to identify any learnings that could inform the design and implementation of a smart grid common platform for other network businesses. The project aimed to evaluate the requirements for a smart grid common information and communication technology (ICT) platform in the following areas: The effectiveness of current standards and the degree to which they permit interoperability of the wide variety of systems and devices making up the smart grid The data security and information privacy implications of the common platform The processing, management, correlation and storage of large amounts of data available from the smart grid The data centres, disaster recovery, backup, and monitoring systems necessary to support the common platform In addition, this study assessed the potential for the National Broadband Network (NBN), which was being rolled out in Australia at the time of the trial, to provide communication services to field-based smart grid infrastructure. The smart grid common platform developed for the Smart Grid, Smart City Program consisted of a communications network providing connectivity between the various elements of the smart grid, together with supporting IT infrastructure. This is described in Figure 2. Figure 2 Smart grid common platform layers Advanced Automation Wide Area Control AVVC FDIR Dynamic Ratings Demand Response Pricing & Feedback Network State Viability & Actuation Capability Transmission Monitoring Substation Monitoring Distribution Monitoring Distribution Control Wind Area Measurement Smart Meter Infrastructure Common Platform IT Infrastructure Communications Infrastructure Security Architecture Operational Model Design Standards 14 National Cost Benefit Assessment: Executive Report ARUP

17 2.2 Grid applications work stream overview The Grid Application work stream included a combination of projects which trialled grid-facing smart technologies within Ausgrid s distribution network. The intent of the Grid Application trials was to deploy and integrate smart grid technologies (generally) with the existing infrastructure at various points on the electrical network. The Grid Application technology trials aimed to assess: How smart technologies could improve the reliability of the distribution network How smart technologies could improve the quality of service Which technologies had the potential to deliver the best results for different network densities and characteristics Whether smart grid monitoring and control technologies could reduce the cost of running an electrical network Whether integrating smart grid technologies and techniques had the potential to enable the design of a lower cost electrical network Table 3 provides an overview of the different smart grid technologies trialled in the grid applications work stream. Table 3 Grid Application Project smart grid technologies trialled Smart grid technology project Active Volt-VAr Control Fault Detection, Isolation and Restoration Substation and Feeder Monitoring Wide Area Measurement Abbreviation AVVC FDIR SFM WAM Description of smart grid technology Automated voltage regulating and reactive power controls to measure and maintain acceptable voltages and high power factor at all points in the distribution network under varying load conditions. Automation technologies used to quickly and precisely detect fault conditions, isolate faulty equipment and restore power to customers by operating remotely controlled switches. A collection of technologies which monitor the network state (voltage, current and frequency) and condition of assets within the electrical distribution network utilising a common ICT platform. Measurement devices capable of providing high speed, timesynchronised samples of network data, including voltage, current and frequency, called synchrophasors. Once deployed at strategic points on the transmission and distribution networks, incoming data from these devices can be used to accurately and dynamically measure the state of the power system from a wider-area perspective. National Cost Benefit Assessment: Executive Report ARUP 15

18 2.3 Customer applications work stream overview The Smart Grid, Smart City Customer Applications Program trialled different methods of interacting with customers purchasing electricity as part of the broader Smart Grid, Smart City Program. Customers play a major role in smart grids, however, little is known about how they might perceive or respond to the opportunities that smart grid technologies offer. The Customer Applications Program sought to understand whether providing residential consumers with smart grid devices and different pricing would enable customers to make informed choices and potentially better control their consumption of electricity over the long-term and/or during peak events. The Customer Applications trials tested: Whether consumer-focussed smart feedback devices and near real-time electricity consumption information could influence residential customer behaviour on how and when electricity is used and reduce consumer energy bills Whether integrating consumer-focussed smart feedback devices with different pricing strategies and near real-time electricity consumption information could influence residential customer behaviour on how and when electricity is used and reduce consumer energy bills Behavioural changes and responsiveness from different residential consumer demographic groups against each of the different combinations of smart feedback devices and / or pricing strategies. In particular, emphasis was placed on assessing the effect of interventions on vulnerable energy users Table 4 provides an overview of the different smart grid devices and pricing strategies trialled as part of the customer applications work stream. Table 4 Customer Applications Project smart grid devices and pricing strategies trialled Customer Applications trial Network trial Retail trial Smart water meter trial Smart meter infrastructure Description of trial elements Measured the effectiveness of smart meter based products without changing the customer s retailer or electricity retail tariffs. The network trial tested feedback technologies, financial incentives (rebates) and provided a lifestyle audit. Eight products were offered to customers either individually or as a bundle. The products consisting of an online portal, an in home display, appliance control and sub-metering devices, an interruptible load (air conditioning) control rebate, a dynamic peak rebate and a lifestyle audit. Measured the effectiveness of alternative electricity tariffs either as standalone products or bundled with smart feedback devices The retail trial tested smart meter based tariffs, feedback technologies and a rebate. In total, twelve products were offered to customers with each product including a tariff (dynamic peak pricing, seasonal time-of-use or top-up plan) or a rebate (interruptible load (air conditioning)) and optionally one or more feedback technologies (an online portal, an in home display or appliance control and sub-metering devices). Trialled the effectiveness of integrating smart water meters with smart electricity meters. The results of this trial have been provided in a separate report available on the Smart Grid, Smart City Information Clearing House which can be found at The network and retail trials were supported by the installation of smart meter infrastructure. 16 National Cost Benefit Assessment: Executive Report ARUP

19 2.3.1 Smart meter infrastructure To enable the Customer Applications trials smart meters were installed at residential customer premises. In addition smart meter infrastructure was also deployed. This infrastructure included: The various communications technologies required to transport data to and from the smart meter, the feedback technologies and the Ausgrid and EnergyAustralia back office systems The firmware that controlled how the smart meter interacted with the meter s communication module The Meter Management System (MMS) Back office operational systems at Ausgrid, EnergyAustralia and Sydney Water The customer acquisition application The smart meter infrastructure enabled the remote collection of residential electricity usage data, the storage and analysis of these data, and the delivery of these data to smart grid feedback devices in trial participant s homes. Smart meter infrastructure also provided the ability for off-peak scheduling for hot water systems. These capabilities aimed to provide the information and tools necessary to help consumers, Ausgrid and EnergyAustralia manage and reduce over electricity consumption and demand during peak periods for the network or wholesale market Trial participant surveys Retail and network trial participants were surveyed twice in the last year of the trial to ascertain their level of engagement and satisfaction with the trial feedback technology products and tariffs. 2.4 Distributed generation and distributed storage work stream overview The Smart Grid, Smart City Distributed Generation and Distributed Storage (DGDS) Project was initiated to provide critical data and information to help understand the implications of greater penetration of distributed storage integrated with distributed generation and other smart grid technologies. The Distributed Generation and Distributed Storage Project sought to: Understand the maturity and suitability of distributed generation and distributed storage devices Assess the impacts on the grid from increased penetration of distributed generation and distributed storage devices Understand the value distributed generation and distributed storage devices can potentially deliver for network operators and customers The program consisted of field trials, advanced modelling and simulation trial elements. The field trial results were used to validate the models and gain insights into the commercial-scale deployment of these technologies. The advanced modelling and field simulations provided additional analytical tools for different penetrations of distributed generation and distributed storage devices which are not commercially and physically possible in a field trial. Analysis undertaken for this report also sought to determine whether these technologies and pricing signals led to changes in behaviour around electricity consumption. These findings are discussed in Section 6 of this Executive Report. National Cost Benefit Assessment: Executive Report ARUP 17

20 2.5 Electric vehicles work stream overview The overall objective of the Smart Grid, Smart City EV Project was to understand the potential impact of wide-scale uptake of electric vehicles in Australia on the electricity distribution network. To date, the majority of studies in Australia have focussed on travel behaviour, driver perceptions, uptake rates and the impact of electric vehicles on the electricity network at a whole-of-system level (a number of these are described in the following sections). Many of these studies identified that the greatest potential impact is likely to be at the distribution level, but to date investigations into the magnitude of this impact tend to be generalised. In addition, existing studies did not link spatial analysis of electric vehicle uptake with localised feeder impacts. This study represented the first investigation in Australia which has investigated the sensitivity of distribution network to spatial variation in electric vehicle uptake. The Smart Grid, Smart City EV Project was informed by four distinct trial components: charging infrastructure deployment; road trials; uptake and behaviour modelling; and grid impact modelling. Twenty Mitsubishi imiev electric vehicles were used in the trials which included business trialling at Ausgrid and separate fleet and home trials. 18 National Cost Benefit Assessment: Executive Report ARUP

21 3 About the final series of reports from the Smart Grid, Smart City Program Significant effort was invested in the original design of the Smart Grid, Smart City Program to endeavour to meet the key objectives and priorities of the Australian Government and its stakeholders. It was the intention that the Smart Grid, Smart City trial elements produce meaningful data that could be extrapolated in a national context and utilised by industry and other interested stakeholders. With this in mind, the Australian Government specified a range of activities, outcomes and data priorities for each of the program / trial work streams. The activities and data priorities were designed to prove (or challenge) a number of trial hypotheses (assumptions). The hypotheses were focussed on determining whether different smart grid technologies could achieve an economic or other benefit for Australian electricity consumers. In March 2013, a consortium of Australian-based consultancy firms was commissioned to utilise the Smart Grid, Smart City trial results and learnings to develop an integrated cost benefit assessment for smart grid technologies in a national context. The AEFI consulting consortium included: Arup Energeia Frontier Economics Institute for Sustainable Futures (University of Technology Sydney) Australian Government energy policies, programs and its strategic intent for the energy sector and energy consumers Stakeholder priorities and expectations including those identified during the stakeholder engagement processes completed as part of AEFI s assessment of the Smart Grid, Smart City Program In addition, a clear expectation of the Smart Grid, Smart City Program was that there would be significant effort focussed on presenting the results of the trial for different audiences. To this end, there are several levels of reporting being delivered as part of completion of the program: The National Cost Benefit Assessment Report (for which this is the Executive Summary) which provides stakeholders with an independent assessment of the potential integrated national cost benefit assessment using (predominantly) data produced by the Smart Grid, Smart City trials to determine the potential national net benefits of deploying economically efficient smart grid devices, customer feedback technologies and dynamic (cost reflective) electricity tariffs. The integrated methodology used to develop the analysis and costings within this report ensures that there is no double counting of benefits provided by two or more technologies and any under or overestimation of the value proposition achieved from technology interdependencies is minimised. While undertaking an integrated financial and economic assessment and developing conclusions and recommendations, AEFI considered the broad requirements of the program, including: The key questions and assumptions that the Australian Government was seeking to validate, or challenge Existing energy market reforms under investigation or in progress The Technical Compendia prepared by Ausgrid and partners that provide a detailed overview of the results for each of the work streams. These documents are technically complex and aimed at an audience that is familiar with energy sector terminology and technology. The intended audience includes network operators, energy retailers, technology providers, universities, regulators, governments and energy sector personnel. In addition these documents are intended to have global reach and contribute to the global knowledge base of smart grids and associated technologies. National Cost Benefit Assessment: Executive Report ARUP 19

22 The Modelling Inputs Compendium is also part of this suite of technical documents. This compendium provides detailed information as to where data and information generated from the Smart Grid, Smart City trials have been used either as direct inputs or to validate and inform the modelling inputs to the national cost benefit assessment. The Modelling Inputs Compendium also provides a series of stand alone cost benefit assessments for individual smart grid technologies which could be applied in the instance that only one device or technology (or a series of discrete technologies or devices which do not have any interaction) is deployed in the Australian context. These stand alone cost benefit assessments represent a less sophisticated approach than the integrated cost benefit assessment, but remain a valid estimate of costs and benefits under some circumstances. Supporting documentation prepared by Ausgrid, AEFI and partners that provides the detailed information and data upon which the Technical Compendiums are based. An Information Clearing House (ICH) that provides the communication mechanism for the data, analytic tools and results from the Smart Grid, Smart City Program and will be maintained until 30 September This site can be found at The breadth of the subject areas investigated as part of the Smart Grid, Smart City Program is shown in Figure 3. Figure 3 Structured reporting and access to information for the Smart Grid, Smart City trial National Cost Benefit Assessment Report Part One Smart Grid, Smart City trials Part Two The business case for smart grids in Australia Part Three Conclusions and recommendations Technical Compendia Substation and Feeder Monitoring Grid Applications Fault Detection Isolation and Restoration Active Volt VAr Control Wide Area Measurement Distributed Generation and Storage Applications Customer Applications Electric Vehicles Common Platform Study Smart Meter Infrastructure Modeling Inputs Compendium Supporting Documents 20 National Cost Benefit Assessment: Executive Report ARUP

23 3.1 The national cost benefit assessment report This is the final report to the Australian Government for the Smart Grid, Smart City Program and differs from previous progress reports. Importantly, it is an independent assessment that provides the analysis and discussion necessary to form: The business case (potential net economic benefit) associated with a future implementation of individual smart grid technologies, compared to a business as usual approach using the results of the integrated assessment 9 The business case (potential net economic benefit) associated with a future implementation of an optimised group of smart grid technologies (an integrated assessment), compared to a business as usual approach The business case (potential net economic benefit) for smart grid technologies for electricity networks and electricity generators (on a state-by-state 10 basis) The description of how the costs and benefits accrue to electricity customers and the potential impact on retail electricity prices for a smart grid scenario compared with a business as usual approach. This report is broken into a number of sections including: Executive Report (this report) A standalone synopsis of the main report which provides a full summary of the Smart Grid, Smart City Program, the key trial findings, conclusions and recommendations Part One An overview and the high level findings of the individual technology and customer trials Part Two A cost benefit assessment for the deployment of a national smart grid across Australia Part Three A discussion on the potential benefits, barriers and opportunities to implement a smart grid in Australia including the independent conclusions and recommendations from this assessment Appendix One An overview of Australia s energy sector including the policy, regulatory and investment drivers Appendix Two The cost benefit assessment methodology that AEFI used to complete the cost benefit assessment Appendix Three Tables of results for each of the three macroeconomic scenarios and for each Australian state Appendix Four Customer electricity bill impacts 9 Reporting the analysis in this way prevents double counting of benefits which can occur if assessments for different technologies are completed individually 10 State assessment has been limited to Western Australia, South Australia, Queensland, New South Wales, Tasmania and Victoria. National Cost Benefit Assessment: Executive Report ARUP 21

24 3.2 Smart Grid, Smart City Information Clearing House The Smart Grid, Smart City Information Clearing House (ICH) is a web portal designed to make reports and data from each of the Smart Grid, Smart City projects readily available to registered parties including electricity industry members, governments, individual researchers, suppliers and members of the public. The Smart Grid, Smart City ICH provides registered users with a user-driven online data selection, visualisation and download facilities. The intent is that registered users will be able to download and use the Smart Grid, Smart City data and research to further their own knowledge and research and in so doing contribute to the global knowledge base of smart grids and associated technologies. In addition users will be able to access a public version of the model used by AEFI in the cost benefit assessment. Registration to the Smart Grid, Smart City ICH is free and available to all members of the community and can be accessed at: 22 National Cost Benefit Assessment: Executive Report ARUP

25 Context Australia s energy market and the Smart Grid, Smart City Program The Smart Grid, Smart City Program was intended to provide an understanding and, where possible, quantify the costs and benefits of a range of smart grid technologies and products such as dynamic tariffs, in-home displays and web portals. At the time the Smart Grid, Smart City Program was instigated, Australia had been in a period of yearon-year growth, and in some cases rapid growth, in both electricity consumption and peak demand. Of particular importance, during this period, peak demand growth outstripped consumption growth by a significant amount in some states in Australia. This, combined with the need to replace a significant amount of existing electrical assets which were around 50 years old, resulted in an unprecedented upswing in network investment around Australia. The economy was also in a high growth period, driven by a mining boom and strong demand for Australian raw and processed products both domestically and overseas. However, over the past four years, the trend of rapid demand growth and high investment has been replaced by a period of lower total demand for gridsourced electricity and lower growth in total system peak demand. This situation has meant that there are parts of electricity distribution networks where there is excess capacity and similarly in the generation sector, several large baseload power stations have been temporarily or permanently withdrawn from service as a direct result of excess capacity. The reduction in total system demand is a result of a number of drivers including the global financial crisis, reduced manufacturing presence in Australia, improvements in the energy efficiency standards for appliances and buildings, and consumers responding to the increase in electricity prices by modifying behaviour. In addition, over the past few years the deployment of rooftop solar PV systems in Australia has outstripped all government and industry projections. This trend was driven by sharply increasing electricity prices, strong cost reductions in the price of solar PV systems and generous state government feed-in-tariffs (most of which have now been withdrawn). The Smart Grid, Smart City trials were underway during this unprecedented period of change in the electricity sector and now, amid projections of an economic recovery and a return to a period of low electricity demand growth in the near future, it is timely to consider whether smart grid technologies and products have a role in managing future demand growth and price increases. National Cost Benefit Assessment: Executive Report ARUP 23

26 4 Approach to the cost benefit assessment The business case assessment is an economic evaluation of the technologies and products trialled in the Smart Grid, Smart City Program. The economic assessment sought to determine: Which technologies, customer feedback products and dynamic tariffs, deployed in which combination, over what timeframe could maximise national net economic benefit How these benefits are transferred within the electricity system to impact the price of electricity and customer bills Eight different groups of smart grid technologies, products and tariffs were assessed 11 including: Fault Detection, Isolation and Restoration (FDIR) technologies Substation and Feeder Monitoring (SFM) technologies Dynamic tariffs which included combinations of: Voluntary adoption of dynamic tariffs with feedback technologies for some customers Mandatory adoption of dynamic tariffs for customers installing distributed generation and distributed storage technologies Inclining block tariffs for the remaining customers Provision of a smart meter infrastructure for customers on dynamic tariffs Smart Meter Infrastructure (SMI) Electric Vehicles (EVs) Distributed Generation (DG) Distributed Storage (DS) Active Volt-VAr Control (AVVC) technologies 11 All data inputs and the relevant sources for these inputs are described in the Modelling Inputs Compendium which can be sourced from the Smart Grid, Smart City Information Clearing House 24 National Cost Benefit Assessment: Executive Report ARUP

27 A model was developed which allowed the impact of the interactions between customer behaviour and different smart grid and traditional technologies to be quantified. This model sought to replicate the interactions and behaviours within and between different stakeholders in the electricity industry in both the BAU and smart grid cases. These stakeholders include customers, network operators, electricity retailers and electricity generators. This model is known as the integrated benefits model and is illustrated in Figure 4. Figure 4 Integrated benefits model Electricty price and tariff structure Technology costs (Customer applications, Distributed generation and distrubited storage) Retail Model Capital costs Customer Load Profile 1 Customer Load Profile 2 Customer Load Profile i Customer Model Customer Load Profile 1 Customer Load Profile 2 Customer Load Profile i Diversity Model (Grid applications, Distributed generation and distrubuted storage Network Load Model Network Model Network benefits System Load Profile Retail benefits Generation (Market) Model Generation benefits Environmental benefits National Cost Benefit Assessment: Executive Report ARUP 25

28 The integrated benefits model was developed for the purpose of assessing the net economic benefit of smart grid technologies. The model was used to assess both individual technologies and an integrated smart grid deployment which includes a combination of technologies. The integrated benefits model was run for both a business as usual (BAU) and smart grid case at five points in time 2014, 2019, 2024, 2029 and The model was also run separately for five states 12. Due to their relatively low numbers, Northern Territory customers were assigned to the Queensland network and ACT customers to the NSW analysis. The model was also run for three macro-economic scenarios (low, medium and high) to understand the sensitivity of the results to macroeconomic factors. The business case assessment did not provide a financial assessment or business model for individual stakeholders. In fact, for non-grid technologies, the assessment is deliberately agnostic in terms of which market stakeholder would bear the costs or accrue the benefits of smart grid technologies. There is still significant work to be done to understand the right business model for deployment of a number of products to ensure that the full value can be captured. The scope of the business case assessment is limited to the electricity system. However, when combined with the Customer Research Survey results this assessment provides a broader perspective of the economic and societal opportunities and challenges for deploying smart grid technologies and dynamic tariffs in Australia. The technologies and retail products assessed were limited to those trialled as part of the Smart Grid, Smart City Program. The results of the cost benefit assessment are complex, given the number of smart grid technologies, products and tariffs that were considered throughout the analysis. In addition, state-based results have also been presented within the report. It is therefore recommended that the results presented in this report be read in conjunction with the full methodology contained in Appendix Two and complete results presented in Part Two of the full report. 12 Refer to Appendix Two of the main report which provides a detailed description of the methodology, and Appendix Three which provides the State by State results 26 National Cost Benefit Assessment: Executive Report ARUP

29 5 Stakeholder Engagement Throughout the analysis and reporting stages of the Smart Grid, Smart City cost benefit assessment, a range of stakeholder engagement activities were undertaken. The broad objectives of stakeholder engagement were to ensure: Stakeholders understood the scope and objectives of the cost benefit assessment and reporting phase of the Smart Grid, Smart City Program Stakeholder priorities for the cost benefit assessment and reporting phase of the Smart Grid, Smart City Program were understood and addressed to the extent practicable Stakeholders had an opportunity to validate or provide alternative data and information to inform the cost benefit assessment modelling process Identification of other ongoing studies and programs within the electricity sector which could inform or be informed by the analysis and reporting phase of the Smart Grid, Smart City Program. 5.1 Rapid stakeholder engagement At the commencement of the analysis and reporting phase (i.e. in 2013), a rapid stakeholder engagement process was undertaken to identify stakeholder priorities. This took the form of web-based and phone-based group and individual interviews. This initial rapid stage was required to quickly identify stakeholders expectations for reporting and modelling outcomes. Once identified, stakeholders expectations were used to inform the technical models structure, as far as practicable. The rapid engagement phase targeted stakeholders who had already had some involvement with the Smart Grid, Smart City Program. This allowed a deeper level of engagement across fewer stakeholders than would have otherwise been achieved with stakeholders with limited or no understanding of the program. National Cost Benefit Assessment: Executive Report ARUP 27

30 5.2 Stakeholder forum Following the rapid engagement process, a stakeholder forum was held on 12 June 2013 with a broader range of stakeholders many of whom had not been previously involved in the program. The aim of the forum was to: Present a summary of the results of the first phase of engagement by stakeholder group, and offer opportunity for discussion, update or comment Offer the opportunity for diverse stakeholder groups to hear the competing interests in smart grid outcomes, to place their own views in perspective To offer broader participation than the initial rapid stakeholder interview phase 5.3 Stakeholder priorities In total, a list of 38 stakeholder priorities was identified over the first two stages of stakeholder engagement. Some of the priorities were not able to be addressed as they were not directly related to the business case assessment or the Smart Grid, Smart City Program, but related to broader energy market and consumer issues. A description of the stakeholder priorities and an indication of where these priorities have been reported on within the various Smart Grid, Smart City reports, supporting documents and supporting data sets is provided in Section 2.3 in Part Two of the main report. It should be noted that the degree to which these issues are discussed varies across each of the documents (including the Technical Compendia, Customer Research Report and the National Cost Benefit Assessment Report), supporting documents and data sets. Whilst the majority of stakeholder priorities have been investigated and reported in at least one of the trials (Technical Compendia), other Smart Grid, Smart City reports, or the cost benefit modelling, there were a small number of priorities which have not been comprehensively investigated. These priorities were not in the original scope (or only partially within the scope) of the Smart Grid, Smart City Program or cost benefit assessment. In some cases it has been noted that these issues are the subject of a recommendation in this report (refer to Part Three) for further investigations beyond this project. 28 National Cost Benefit Assessment: Executive Report ARUP

31 6 Customer interaction Smart Grid, Smart City retail and network trial survey results 6.1 Background to the retail and network customer trials As described in Part One of this report and within the Customer Applications Technical Compendium, there were two key trials completed as part of the Smart Grid, Smart City Customer Applications Program: The retail trial tested smart meter based tariffs, feedback technologies and a rebate. In total, twelve products were offered to customers with each product including a tariff (dynamic peak pricing, seasonal time-of-use or top-up plan) or a rebate (interruptible load (air conditioning)) and optionally one or more feedback technologies (an online portal, an in home display or appliance control and submetering devices). A Network Trial which measured the effectiveness of smart meter based products without changing the customer s retailer or electricity retail tariffs. The network trial tested feedback technologies, financial incentives (rebates) and a lifestyle audit. Eight products were offered to customers either individually or as a bundle. The products consisted of an online portal, an in home display, appliance control and sub-metering devices, an interruptible load (air conditioning) control rebate, a dynamic peak rebate and a lifestyle audit. A Retail Trial which measured the effectiveness of alternative electricity tariffs either as standalone products or bundled with feedback technologies. As part of investigating the outcomes of the Customer Applications network and retail trials, a Customer Research Survey was commissioned. The key findings and conclusions from this work are summarised in the following section, with the full Customer Research Report available from the Information Clearing House at The impact of the Customer network and retail trial findings on the integrated costs benefit assessment is discussed in Section 6.6 of this Executive Report. National Cost Benefit Assessment: Executive Report ARUP 29

32 6.2 The Customer Research Survey scope of works The primary purpose of the Customer Research Survey was to: Obtain household profiling data to enable a more accurate depiction of household demographics and energy profiles, and Analyse the customer experience of Smart Grid, Smart City trial participants with the smart grid technology and tariff products they were trialling Data collected from the household profiling and customer experience was used to: Analyse the efficacy of different smart grid products in delivering real world benefits to customers Understand customer perceptions of trialled smart grid products Undertake a granular analysis of the customer experience that included consideration of how relevant socio-demographic factors influence customer experience of smart grid products Analyse the perceived effects of smart grid products on customers ability to control and manage their consumption Over the two deployment periods in 2013 and 2014, a total of 3,215 trial participant responses were obtained. In addition, 241 control group responses were also received in All Smart Grid, Smart City network and trial products were well represented in these survey responses, with between 22 per cent and 53 per cent of participants who trialled a product undertaking the survey. Two customer research surveys were conducted approximately six months apart. Both surveys were offered to over participants in the Smart Grid, Smart City Customer Applications Program. From the 8,000 participants, more than 1,700 participants responded to the initial customer research survey, while almost 2,500 participants responded to the second survey which included almost 1000 respondents from the initial survey. Data collected from both surveys was pooled to create a sample of 3,215 responses. For participants who answered both surveys, only their latest responses were included. 13 For additional information on which of the different trial participant groups were included in the analysis presented in the Customer Research Survey Report findings, refer to the full report available on the Information Clearing House. Examine how the product experiences of vulnerable groups differ from the broader population Compare survey respondents own perceptions of their trial experiences and bill savings with data on total energy savings, peak demand savings and bill savings 13 To streamline the longer survey for repeat respondents, some of the profiling and energy perspective questions were not asked of these respondents in the 2014 survey. Instead their answers were drawn from their responses to the 2013 survey 30 National Cost Benefit Assessment: Executive Report ARUP

33 6.3 Trial participant experience survey results The following sections provide an overview of some of the key findings from the customer survey focussed on the customer experience in trialling the different combinations of customer feedback technologies and dynamic tariff products within the Smart Grid, Smart City Customer Applications Program Feedback technologies level of engagement The Customer Applications Program trialled three types of feedback devices including: A home energy monitor (also known as an in-home display ), showing basic live energy consumption and cost data An online portal, which showed more detailed information but required computer access An online portal paired with a Home Area Network (HAN). The HAN included smart plugs that enabled tracking and remote control of individual appliances There were diverse results from the respondents when they were asked how often they used their feedback technologies, with the data suggesting a clear advantage of the home energy monitors for capturing user engagement. This was likely due to the lower entry barriers, as the in-home display was in view within the home and did not require a dedicated login. On average user engagement with energy data reduced slightly over time, due to both positive (user learning) and negative (apathy) factors (Figure 5). A key finding was that 83 per cent of trial participants reported that the use of their customer feedback technology and/or tariff product had resulted in them taking some action to reduce or change the way they consumed electricity. Three-quarters of respondents reported that the quantity of information provided by the feedback technologies was about right, while almost onequarter would have preferred more information. Almost no respondents felt that they were given too much information. Further, the more information provided to customers (through the Portal and the Portal+HAN), the greater the likelihood that they reported that they wanted more. Figure 5 Trial participant frequency of usage of feedback technology Monitor (n=1264) 31% 13% 5% 19% 11% 21% Portal (n=673) 8% 11% 7% 31% 22% 21% Portal+HAN (n=239) 7% 12% 13% 27% 23% 19% 0% 20% 40% 60% 80% 100% Daily 2-3 times per week Weekly Every now and then Once / twice Never National Cost Benefit Assessment: Executive Report ARUP 31

34 6.3.2 Trial participant response to peak event products Some trial products involved discrete peak events where customers were encouraged through significantly higher prices or rebates for reduced demand to reduce consumption for a period of up to four hours (this product is further described in Part One of the main report). These customers were sent SMS notifications 24 hours and 2 hours in advance of the event to request their participation. A key finding from this survey question was that a very high proportion of respondents (87 per cent) reported participating in a peak event and two-thirds reporting that this flowed on to a lasting change in their behaviour outside of the peak event period. Continued interest in peak event participation was high, with 80 per cent of respondents stating that they maintained or increased their level of interest in participating in peak events over time. The incentivebased Dynamic Peak Rebate performed slightly better than the tariff-based Dynamic Peak Pricing on all three measures. When asked, 40 per cent of respondents said they would participate in the peak event by reducing their heating/air-conditioning use regardless of how extreme the temperature was in order to save money. The remaining 60 per cent indicated they would use their heating/air-conditioning less on moderate temperature days but would pay more to heat/ cool their house on extreme temperature days. This suggests that customer participation during extreme weather conditions may not be as substantial as days when peak events are run on moderately hot or cold days. Figure 6 shows the differences in survey responses to this question categorised separately by network and retail trial participants 14. A slightly higher proportion of Dynamic Peak Pricing respondents indicated they would reduce their heating/ cooling on extreme temperature days compared to Peak Rebate respondents, tentatively suggesting that the penalty of higher prices may be slightly more effective that the incentive of higher rebates on extreme hot or cold days. Refer to the Customer Applications Technical Compendium for analysis of observed savings during trial peak events. 15 Figure 6 Proportion of trial households who indicated that they would respond to a peak event no matter how extreme the temperature 50% 40% 30% 40% 35% 43% 37% 30% 41% 20% 10% 0 Summer (n=744) Winter (n=100) Overall Network Retail 14 The summer in the region where the trial was conducted was mild in comparison to other years with no prolonged periods of temperature above 35 C 15 Data can also be found at the Smart Grid, Smart City Information Clearing House: 32 National Cost Benefit Assessment: Executive Report ARUP

35 6.3.3 Trial participant electricity awareness and control Participants rated how the use of their product had impacted on their awareness, energy literacy and control over electricity consumption bills. Overall the trial was found to have had a very positive effect on awareness of electricity use, which translated to almost 70 per cent of respondents saying that their ability to reduce electricity bills had improved Trial participant behaviour change Of all survey respondents 83 per cent of respondents reported that the use of their product had resulted in their taking some action, with two-thirds reporting reducing their usage, 58 per cent reporting changing the time of day that they used electricity, and one quarter of trial participants making one or more appliance efficiency upgrades. For two-thirds of respondents the behaviour changes reported had some effect on their daily routine, but only 5 per cent reported them as having substantially affected their daily routines (Figure 7). Participants were also asked about the changes they were still making at the time of the survey, which was between 6 and 18 months after starting to use their product (Figure 8). A key conclusion was that the results suggested that trial respondents changes in behaviour was relatively persistent, with half of respondents reporting that they were still implementing all of their changed behaviours and over 85 per cent still implementing half or more of the changes. These findings were despite the finding that engagement with energy data reduced over time for half of respondent households. In addition, consistent, statistically significant differences of self-reported behaviour change were found according to product type, pricing/incentive type and feedback technology type with the following products encouraging the greatest behaviour changes: Products combining pricing/incentives with a feedback technology Peak event products Trial participants using monitors Figure 7 Trial participants reporting magnitude of changes to daily routine Figure 8 Proportion of participants reporting behaviour changes after 6-18 months 29% 5% 8% 6% 16% 50% 66% 20% Substantial change to routine All More than half About half Some change to routine No change to routine Less than half None National Cost Benefit Assessment: Executive Report ARUP 33

36 6.3.5 Trial product satisfaction Overall the majority of trial respondents were positive about the product they had trialled, with one quarter of participants very satisfied and a further 45 per cent satisfied. The key findings were that: The two peak rebate products had the most satisfied customers All trial products in the top half ( very satisfied or satisfied responses) involved a pricing/incentive On average product satisfaction tended to stay relatively stable or improve over time 6.4 Comparing trial participant responses to different feedback technologies and tariff products The following section summarises the key findings of the Customer Research Survey analysis which evaluated trial participant responses to different feedback technologies and tariff products Response of trial participants to different trial products To inform discussion on the potential for new dynamic tariffs and/or feedback technologies, analysis was undertaken to compare the responses of trial participants within the product groupings which included: Pricing or incentive tariff products only Feedback technologies only Combinations of pricing/incentive structures with feedback technologies Based on the analysis of trial respondents to the survey, the following conclusions were made: Frequency of engagement Pricing/incentive and feedback technology combinations were superior for encouraging trial participants to engage with their electricity use on a more regular basis Perception of financial savings - Having a dedicated tariff structure or rebate to incentivise behaviour change resulted in trial participants reporting greater savings Impact on awareness and ability to reduce bills - All products increased trial participants awareness of electricity use and control over electricity bills, but combination products show the strongest result Product satisfaction Using a feedback technology alone resulted in lower trial participant satisfaction than if the product included a tariff or incentive 34 National Cost Benefit Assessment: Executive Report ARUP

37 Overall it was concluded that whilst informing trial participants had benefits, and offering a tariff or financial incentive to promote time shifting of electricity helps to save customers money, doing both optimises customer outcomes across a range of indicators Comparing tariff and incentive structures To inform discussion on the most effective approach to structuring consumer tariffs and incentives to achieve positive customer outcomes, results from trial participants who responded to the survey was evaluated with the following products compared: Peak Rebate (network dynamic peak event incentive payments) PriceSmart (dynamic peak pricing) SeasonSmart (seasonal time of use pricing) BudgetSmart (pre-payment plan) Based on the analysis of trial respondents to the survey, the following conclusions were made: Frequency of engagement - Trial respondents with peak event products, both incentive-based (Peak Rebate) and tariff-based (PriceSmart) engaged more frequently with their feedback devices than trial participants with the other tariff types A key finding was that while BudgetSmart was clearly not favoured on most indicators, its satisfaction and likelihood to recommend ratings were unexpectedly high. This may indicate that the unique feature of this product the more deliberate and constant engagement with actual accrued electricity bill costs was popular with some customers Comparing feedback technologies The high visibility of home energy monitors (inhome displays) resulted in strong trial respondent engagement, which had positive flow-on effects in terms of awareness and the ability to reduce bills. The online portal was generally much less successful in both of these aspects, as the barriers to entry (having to turn a computer on and log-in) were higher. However, when the portal was combined with the HAN, the additional functionality seemed to generate stronger customer benefits. Further, despite not achieving a high frequency of engagement, the HAN was shown to be most successful in delivering an increased ability to reduce trial participant electricity bills. Perception of financial savings - Trial respondents with peak event products reported the largest savings, with the Peak Rebate being the strongest performer. This may be because Peak Rebate savings were provided separately on a credit card when earned rather than applied to the quarterly electricity bill Product satisfaction and likelihood to recommend - The results suggest survey respondents preferred peak event products to time-of-use pricing products, but that providing a rebate may resonate better with customers than applying a penalty (higher) tariff National Cost Benefit Assessment: Executive Report ARUP 35

38 6.5 Financially vulnerable households The following trial respondents were categorised as experiencing financial vulnerability 16 for the purposes of this analysis: Households with combined income in the lowest income bracket ( $41,600 p.a.) Households that rent with government assistance Households that occupy public housing Financially vulnerable households were more likely than other trial participants to think that they could shift a larger proportion of their electricity use outside of peak times, with almost 60 per cent suggesting they could shift all but one or two appliances, compared to 53 per cent of other trial respondent households (Figure 9). These results suggest that greater financial vulnerability increases a consumer s willingness to shift electricity load. At the same time, vulnerable households in the survey also rated the behaviour changes they made as easier (less disruptive), than other households in the survey. This is an important finding in the context of developing products that enable financially vulnerable households to be better off in an incentive-based pricing environment. Figure 9 Trial respondent s ability to shift major appliance use, by financial vulnerability Financially Vulnerable (n=501) 18% 41% 33% 7% Others (n= % 40% 35% 12% 0% 20% 40% 60% 80% 100% Able to shift all Unable to shift 1-2 Unable to shift 3-5 Unable to shift Consideration was given to including those who indicated that they had felt unable to pay their energy bill within the last 12 months in this category, however there was a large proportion of people reporting themselves unable to pay who were not in the three groups included in this composite variable. Therefore, as this was a subjective measure it was decided that unable to pay could indicate lifestyle choices or other circumstances rather than ongoing financial vulnerability. Importantly, further analysis (comparisons) between financially vulnerable and unable to pay groups showed similar results. 36 National Cost Benefit Assessment: Executive Report ARUP

39 A key finding relating to the empowerment of trial participants ability to reduce their electricity bills, was that financially vulnerable households were statistically more likely to report their ability to reduce their bills had increased a lot (Figure 10). In addition, financially vulnerable trial households were commonly more satisfied than other trial households with their product and were more likely to recommend their product to a friend. This suggests that trial households with a greater desire for control over their bills (through necessity) were more likely to obtain and appreciate the benefits offered by the trialled products Elderly and pensioner households Elderly households 17 demonstrated somewhat less perceived energy bill vulnerability than others (i.e. they were less likely than others to have felt unable to pay an energy bill within the last year). The difference was less observable for pensioner households (i.e. pensioner households were closer to general average) but still statistically significant. Thus it appears that among trial participants, low-income households that were not exclusively made up of older household members, have a higher incidence of bill vulnerability (Figure 11). Figure 10 Impact of trial on ability of trial participants to reduce electricity use, by financial vulnerability Financially Vulnerable (n=474) 31% 38% 27% 3% Others (n= % 45% 29% 2% 0% 20% 40% 60% 80% 100% Increased a lot Increased a little No impact Decrease a little Decreased a lot Figure 11 Inability to pay energy bills in the past year, by age vulnerability Elderly Households (n=414) 7% 93% Pensioner Households (n=192) 11% 89% Non-elderly Households (n=2822) 18% 45% 0% 20% 40% 60% 80% 100% Have felt unable to pay bill Have NOT felt unable to pay bill 17 Elderly households were considered to be those who had no members under the age of 70, or only one person aged in the bracket 55 69, and the remainder aged 70 or over. Elderly households, if they fell into the lowest income bracket, were termed pensioner households for the purposes of this analysis. Thus pensioners are a subset of elderly households. National Cost Benefit Assessment: Executive Report ARUP 37

40 Figure 12 Frequency of usage of feedback technology, by presence of young children Financially Vulnerable (n=501) 18% 41% 33% 7% Others (n= % 40% 35% 12% 0% 20% 40% 60% 80% 100% Able to shift all Unable to shift 1-2 Unable to shift 3-5 Unable to shift 6-8 Elderly and pensioner trial households were no different to other trial households in how often they engaged with feedback technology, but they increased or maintained their level of use of the technology over time more than other households. Pensioner households were not statistically different from other trial households in their reported time shifting behaviour during the trial, but showed slightly lower peak event participation. This suggests that the older the household, the less likely it was to engage strongly with the product, obtain the benefits and derive satisfaction, but having a lower income offsets some of this age effect, bringing responses back towards the average Households with children A higher proportion of trial households with children reported difficulty in paying their energy bills at some time within the past year compared to households with no children. The results for households with children were as high as the results for the financially vulnerable group. This suggests that despite higher incomes, a larger family size and higher electricity use of this group produces a similar level of bill pressure. A key finding was that the presence of children, and particularly young children as shown in Figure 12, was associated with a higher engagement of trial participants with feedback technologies. Those trial participant households with young children tended to engage well with the technologies, driven by a desire for increased control of bills (and potentially because this group comprises a younger, more technology savvy age group). 38 National Cost Benefit Assessment: Executive Report ARUP

41 The analysis showed exceptionally clear positive behaviour change outcomes. For trial households with children there was no difference in reported reductions in electricity usage during the trial compared to all survey respondents. However, households with children more often reported shifting their time of electricity use during the trial, as shown in Figure 13. Despite a willingness to shift their electricity use, this did not translate to higher than average participation in peak events Top (high) energy users Relative to other respondents, the top 10 and 20 per cent of trial electricity users have a stronger than average desire for control over their electricity bill, and a lower incidence of not being able to pay their electricity bills in the past 12 months. This suggests that this group represents a less vulnerable group from a policy perspective, but may present the utilities with opportunities for large demand reductions. No statistically significant difference was found in self-reported reductions in energy usage during the trial for the top 20 per cent of electricity users, however top users more often reported shifting their time of energy use in the trial. This translated to higher perceived financial savings, with double the proportion of highest energy users estimating saving over $45 per bill compared to other households. Product trends, when analysed for the top 20 per cent of users, revealed that, as with all respondents, pricing/incentive structures (particularly peak event pricing/rebates) were the primary driver of peak and energy savings for large energy users. Feedback information on its own was shown to be of less use. Figure 13 Self-reported change in time of day of electricity use, by presence of children in the trial household Households with any children (n=508) 63% 37% Households with no children (n=1212) 56% 44% 0% 20% 40% 60% 80% 100% Reported shifting appliance use Reported shifting appliance use National Cost Benefit Assessment: Executive Report ARUP 39

42 6.6 Conclusions from Customer Research Survey The customer research survey successfully obtained customer perspectives from almost half of all households participating in the Smart Grid, Smart City Customer Applications trial. Overall, a high level of satisfaction with the trialled products was found, with customers generally obtaining higher levels of engagement and benefit from products when a pricing/incentive structure was combined with a feedback technology, particularly home energy monitors (in-home displays). The most popular trial products tended to be those involving discrete peak events, but the BudgetSmart products which focussed on regular proactive customer engagement with a customer s account, were also successful. Analysis showed large variations in the experiences of different trial participants with the same product, which suggests that there will not be one product that suits all customers in a real world (commercial) product offering. Diversity in product offerings is likely to be required to allow customers to choose the products they think best suit their needs. Analysis also found that financially vulnerable households and households with children had greater than average engagement with the trialled products and were able to obtain financial benefits and satisfaction from their use. These results suggest that trialled smart grid products, particularly dynamic pricing, were viewed by financially vulnerable households as an opportunity to achieve bill savings, as opposed to a financial threat. The comparison of actual electricity savings with customer perceptions of their savings confirmed that self-reported customer behaviour changes do correlate with actual delivered savings, and showed that trial participants were reasonably able to estimate the savings their products were delivering. However, those receiving rebates tended to overestimate the value of their bill savings, while those on dynamic tariff structures tended to underestimate the bill savings their products delivered. More frequent billing cycles and savings estimation features may help dynamic tariff customers more accurately understand their savings, while caution should be exercised when asking customers directly how much they saved, as this may be influenced by the product type or design. 40 National Cost Benefit Assessment: Executive Report ARUP

43 6.7 Conclusions from Customer Research Survey The customer research survey successfully obtained customer perspectives from almost half of all households participating in the Smart Grid, Smart City Customer Applications trial. Overall, a high level of satisfaction with the trialled products was found, with customers generally obtaining higher levels of engagement and benefit from products when a pricing/incentive structure was combined with a feedback technology, particularly home energy monitors (in-home displays). The most popular trial products tended to be those involving discrete peak events, but the BudgetSmart products which focussed on regular proactive customer engagement with a customer s account, were also successful. Analysis showed large variations in the experiences of different trial participants with the same product, which suggests that there will not be one product that suits all customers in a real world (commercial) product offering. Diversity in product offerings is likely to be required to allow customers to choose the products they think best suit their needs. Analysis also found that financially vulnerable households and households with children had greater than average engagement with the trialled products and were able to obtain financial benefits and satisfaction from their use. These results suggest that trialled smart grid products, particularly dynamic pricing, were viewed by financially vulnerable households as an opportunity to achieve bill savings, as opposed to a financial threat. The comparison of actual electricity savings with customer perceptions of their savings confirmed that self-reported customer behaviour changes do correlate with actual delivered savings, and showed that trial participants were reasonably able to estimate the savings their products were delivering. However, those receiving rebates tended to overestimate the value of their bill savings, while those on dynamic tariff structures tended to underestimate the bill savings their products delivered. More frequent billing cycles and savings estimation features may help dynamic tariff customers more accurately understand their savings, while caution should be exercised when asking customers directly how much they saved, as this may be influenced by the product type or design. National Cost Benefit Assessment: Executive Report ARUP 41

44 7 Introduction to the national integrated cost benefit assessment 7.1 Introduction to national integrated cost benefit assessment This section of the report presents the integrated cost benefit assessment results for the medium scenario. The integrated cost benefit assessment includes the costs and benefits of the integrated smart grid case, as well as individual technologies and products. The cost benefit assessment is presented in terms of a number of performance measures commonly used by the electricity sector: Year in which each of the smart grid technologies, products and dynamic tariffs could be economically deployed for different network topologies across either BAU or smart grid cases Net difference in electricity grid-sourced consumption (and total consumption) growth and peak demand growth Differences in the profile of customer demand for grid-sourced electricity and network asset utilisation Differences in the required network capital investment and operational expenditure in Australia Changes in network reliability Differences in electricity generator costs and benefits and greenhouse gas emissions intensity Consideration of macroeconomic trends Clearly, the costs and benefits of smart grid technology, and the implications of the deployment of smart grid technology, will depend on future conditions and outcomes in the power sector and the economy as a whole. The business case assessment (national cost benefit assessment) was considered under three macroeconomic scenarios (termed economic scenarios ) reflecting three different potential future states of the world. The three macroeconomic scenarios were used to test the sensitivity of the modelling outcomes to the feasible range of future states of the world, which are specified as distinct sets of internally consistent demographic, economic, technological and energy pricing conditions. The key features of the three economic scenarios are as follows: Medium scenario macroeconomic and demographic trends over the 30 year forecast period are closest to expected outcomes or conventional wisdom, which also represent a central case Low scenario macroeconomic trends over the 30 year forecast period reflect less favourable conditions for the Australian economy, with lower economic growth. Demographic trends over the 30 year forecast period reflect slower population growth High scenario macroeconomic trends over the 30 year forecast period reflect more favourable conditions for the Australian economy, with higher economic growth. Demographic trends over the 30 year forecast period reflect faster population growth A full description of these macroeconomic scenarios and the process under which they were developed has been described in Appendix Two of the National Cost Benefit Assessment Report. Unless otherwise stated, the results presented in this Executive Report represent the national outcomes for the medium economic scenario. Detailed tables showing the integrated net cost benefit assessment results for all states under each economic scenario has been provided in Appendix Three 18 of the main report. 42 National Cost Benefit Assessment: Executive Report ARUP 18 For stakeholders who have an interest in understanding the specific result areas for individual states and the NEM, these data are also able to be extracted from the model published as part of this project. This model is available at

45 7.2 Economic deployment of smart grid technologies Table 4 shows the results of the preliminary cost benefit analysis which determined in which year (if any) each of the Smart Grid, Smart City smart grid technologies, products and tariffs were expected to show a positive net present value (NPV). This process was completed for each macroeconomic scenario (low, medium and high) and for four different network topologies. The results presented in this table should be interpreted in the following way: Red cells indicate that the smart grid option returns a negative NPV for any economic scenario (high, medium or low) and therefore has no economic business case compared to BAU Orange cells indicate that the smart grid option returns a positive NPV for some economic scenarios (high, medium or low) and therefore may have a business case compared to BAU Green cells indicate that the smart grid option has a positive NPV under all economic scenarios (high, medium and low) and therefore is likely to have a business case compared to BAU Where deployment was shown to be economic under one or more scenarios, the year in which deployment becomes economically viable is shown within the cell. National Cost Benefit Assessment: Executive Report ARUP 43

46 Table 5 Technology deployment results for BAU and smart grid cases across different Australian network types Technology Business as Smart grid scope Network Type usual (BAU) Scope CBD Urban Short Rural Long Rural Fault Detection, No FDIR Retrofit of automated Isolation and Restoration (FDIR) technology HV field switches with monitoring Active Volt-Var Control (AVVC) No AVVC technology Retrofit of automated capacitors or voltage regulators Substation No automated Retrofit HV feeder and and Feeder Monitoring (SFM) SFM technology distribution transformer monitoring Stand-alone Spinning disc Retrofit of smart meters to metering to all all existing customers (also customers (except known as a full deployment Victoria) approach) Dynamic Spinning disc Voluntary adoption of tariffs plus metering dynamic tariffs by some Smart Meter Infrastructure feedback technologies Electric vehicle charging Inclining block tariffs for all customers No feedback technology EV adoption with unconstrained charging Spinning disc metering customers Provision of a smart meter Provision of an in home display Inclining block tariffs for remaining customers EV adoption with dynamic tariffs and controlled charging Provision of a smart meter Distributed Voluntary DG Voluntary DG adoption by generation adoption by some some customers customers Size and configuration optimised for inclining block Size and configuration optimised for dynamic tariffs Provision of a smart meter tariff 44 National Cost Benefit Assessment: Executive Report ARUP

47 Technology Business as Smart grid scope Network Type usual (BAU) Scope CBD Urban Short Rural Long Rural Distributed Voluntary DG Voluntary DG adoption by Smart Meter Infrastructure storage adoption by some customers Size and configuration optimised for inclining block tariff some customers Size and configuration optimised for dynamic tariffs Provision of a smart meter No In some circumstances Yes Smart Grid option returns a negative NPV for all macroeconomic scenarios (high, medium and low) in $2014 for the assessment period through to The year nominated refers to the medium scenario. Smart Grid option returns a positive NPV for some macroeconomic scenarios (high, medium and low) in $2014 for the assessment period through to The year nominated refers to the medium scenario. Smart Grid option returns a positive NPV for all macroeconomic scenarios (high, medium and low) in $2014 for the assessment period through to The year nominated refers to the medium scenario. National Cost Benefit Assessment: Executive Report ARUP 45

48 7.3 Individual technology cost benefit assessments The following sections examine the business case for each of the individual technologies including smart grid applications, customer applications, distributed generation and distributed storage solutions and electric vehicle smart charging. Figure 14, Figure 15 and Figure 16 provide a summary of the national net present costs and benefits for individual smart grid technologies and products for each network type (under the low, medium and high economic scenarios). These results show that the national integrated net benefit from the economic deployment of smart grid technologies, including customer feedback technologies and dynamic tariffs varies from around $9.5 billion over 20 years for the low economic scenario, through to $27 billion under the medium economic scenario and almost $28.5 billion under the high economic scenario. As these figures and the subsequent discussion shows, the costs and benefits of smart grid technologies vary by state, by network topology and by customer type. For the network types and states modelled, these differences are quantified as part of the cost benefit assessment and are discussed in Part Two and Appendix Three of this report. This means that individual stakeholders will need to consider the full findings of the modelling to determine whether, based on local circumstances, there is a positive business case for deployment of individual smart grid technologies and customer feedback technologies. The following figures, termed waterfall diagrams, show the costs of different smart grid technology deployments (on the right side) and the benefits achieved because of this investment (on the left side). Figure 14 National gross costs and benefits and total net benefit by technology and network type (low scenario) Net Present Value ($M 2014 Real) 20,000 15,000 10,000 5, , , (893) (125) (1,578) (115) (2,542) (144) (5,438) 9,525 SFM FOIR AVVC Dynamic Tariffs SMI EV Charging DG & DS SFM FOIR AVVC Dynamic Tariffs SMI EV Charging DG & DS SMI Enabled SMI Enabled Costs Total Australia Net Present Value CBD Urban SR LR 46 National Cost Benefit Assessment: Executive Report ARUP

49 Figure 15 National gross costs and benefits and total net benefit by technology and network type (medium scenario) 30,000 15,235 27,183 Net Present Value (SM 2014 Real) 25,000 20,000 15,000 10,000 5, , SFM FOIR 855 AVVC 3,635 DYNAMIC TARIFFS 796 SMI SMI Enabled 354 EV CHARGING (4,981) (164) (1,334) DG & DS SFM FOIR (99) AVVC (2,514) DYNAMIC TARIFFS (333) SMI SMI Enabled (265) EV CHARGING DG & DS Costs Total Australia Net Present Value CBD Urban SR LR Figure 16 National gross costs and benefits and total net benefit by technology and network type (high scenario) 30,000 19,880 28,435 Net Present Value ($M 2014 Real) 25,000 20,000 15,000 10,000 5, SFM 15,797 FOIR 638 AVVC 3,264 DYNAMIC TARIFFS 931 SMI SMI Enabled 470 EV CHARGING (8,354) (108) (1,106) DG & DS SFM FOIR (84) AVVC (2,529) (344) DYNAMIC TARIFFS SMI SMI Enabled (265) EV CHARGING DG & DS Australia Net Present Value Costs Total CBD Urban SR LR Under all three economic scenarios FDIR shows consistently high results. Implementation of dynamic tariffs and AVVC also showed positive net economic benefits under all three scenarios. The individual technology cases shown in the waterfall diagrams under a medium economic scenario are described further in the following sections. National Cost Benefit Assessment: Executive Report ARUP 47

50 7.4 Medium integrated cost benefit assessment economic scenario results The greatest potential economic benefit shown by the modelling of the economic deployment of smart grid technologies, customer feedback technologies and dynamic tariffs comes from FDIR technologies which account for approximately 53 per cent of the total net benefits under the medium scenario, mostly as a result of improved customer reliability. The medium economic scenario waterfall diagram (Figure 15) shows a potential $15.2 billion in avoided costs from the deployment of distributed generation and storage. This represents the avoided customer investment in distributed generation under the smart grid case as a result of the introduction of dynamic tariffs which provide price signals to consumers to encourage more economically efficient investment. In turn this economic signal results in lower investment in distributed generation under the smart grid case compared to BAU. The reduced investment in distributed generation under the smart grid case means that there is a need for increased volumes of centralised generation in order to meet consumer electricity consumption and peak demand requirements. This results in increased centralised generation costs (such as additional fuel and other operational costs) which are shown as a negative benefit of $5 billion in the medium scenario (Figure 15). The introduction of dynamic tariffs drives the net benefit result for distributed generation and storage investment as well as the direct net benefits from customer responses to the tariffs themselves. Dynamic tariffs therefore account for 42 per cent of the total net benefits, with approximately 90 per cent of these benefits resulting from more efficient customer distributed generation and storage investment decisions. These benefits are discussed in greater detail under each of the technology sections in this part of the report. In addition the smart grid technology costs and benefits by technology for the all macroeconomic scenarios are presented in Appendix Three of this report. As part of the integrated net cost benefit assessment, benefits were assigned to a number of benefit categories including peak demand, grid consumption, network operation and maintenance, reliability and billing, metering and customer services. Table 5 shows the relative contribution of each of the individual technologies to the smart grid cost benefit assessment for the period 2014 to 2034 by benefit category. These results show that 95 per cent of the gross benefits are as a result of improved reliability, with billing metering and customer services benefits the next major category of benefits. There are relatively few network operation and maintenance benefits nationally in the deployment of smart grid technologies. Analysis also showed a net cost in terms of grid consumption. This is driven by additional investment in centralised generation that is required under the smart grid case because consumers invest more efficiently in distributed generation compared with BAU. These investment decisions are discussed at length in Part Two of the main report. 48 National Cost Benefit Assessment: Executive Report ARUP

51 Table 6 Smart grid technology costs and benefits, by technology and benefit type (medium scenario) Tech Smart grid Gross Benefits ($M 2014) Net costs (capex and opex) ($M 2014) Peak Demand Grid consumption Network operation and maintenance Reliability Billing, metering and customer service Total Benefits ($M 2014) FDIR 1, (4) (15,741) (15,745) (14,411) AVVC 99 (846) (9) (855) (756) SFM (22) (230) (252) (88) Smart Meter Infrastructure Standalone (796) (796) (463) Dynamic tariffs 2,514 (1,798) (121) (1,717) (3,635) (1,121) Electric vehicle 265 (360) 6 (360) (89) charging DG/DS (15,235) 2,772 2, ,981 (10,254) Total integrated (10,527) (232) 1,882 (26) (15,971) (2,309) (16,656) (27,183) Figures in ( ) represent a positive net present value i.e. a benefit whilst figures outside of the ( ) represent a cost or a negative net present value National Cost Benefit Assessment: Executive Report ARUP 49

52 In addition to analysis of the costs and benefits by benefit category, assessment was also separated by network topology. Table 6 shows the relative contribution by network types over the period 2014 to These results clearly show that the majority of benefits from the economic deployment of smart grid technologies, products and dynamic tariffs accrue within urban networks. This is particularly the case with strong benefits shown from the introduction of dynamic tariffs which results in reduced (and more economically efficient) investment in distributed generation in urban networks. FDIR benefits are evenly split between urban and short rural networks, with relatively few benefits in long rural networks due to the small number of customers on this network type. The net benefit on CBD networks is relatively small due to the existing investment in these networks particularly in terms of reliability. Table 7 Smart grid technology costs and benefits, by technology and network type (medium scenario) Tech Smart Gross Benefits ($M 2014) Net grid Benefits costs ($M 2014) (capex and opex) ($M 2014) CBD Urban Short Rural Long Rural Total FDIR 1,334 - (7,899) (7,847) - (15,745) (14,411) AVVC 99 - (609) (205) (41) (855) (756) SFM 164 (9) - - (243) (252) (88) Smart Meter Infrastructure Stand- alone 333 (4) (418) (299) (75) (796) (463) Dynamic tariffs 2,514 (33) (2,307) (1,130) (165) (3,635) (1,121) Electric vehicle 265 (13) (205) (120) (15) (354) (89) charging DG/DS (15,235) 725 1,983 1, ,981 (10,254) Total integrated (10,527) 666 (9,455) (7,952) 85 (16,656) (27,183) Figures in ( ) represent a positive net present value i.e. a benefit whilst figures outside of the ( ) represent a cost or a negative net present value 50 National Cost Benefit Assessment: Executive Report ARUP

53 8 Key findings and recommendations for individual smart grid technologies and products 8.1 Introduction A detailed summary of the key findings and recommendations for each different smart grid technology, for customer feedback technology and for dynamic tariffs is presented in the following sections. Additional detail on each of these technologies, with findings, observations, conclusions and recommendations, can be found in the relevant technology-specific areas sections of the main report. In addition, detailed tables of results for the low and high economic scenarios for each state and network topology are provided in Appendix Three of the main report. 8.2 Key findings and recommendations for Fault Detection, Isolation and Restoration (FDIR) technologies Currently many grid operators in Australia generally become aware of a fault on their overhead HV network through a feeder circuit breaker tripping, which sends an alarm to the control room. This, in conjunction with customer calls and feeder patrols, allows field staff to restore overhead connections via manual switching. FDIR technologies use advanced Distribution Management System (DMS) software and remotely controllable switches with in-built fault monitoring sensors to optimise the process of restoring power to customers after the occurrence of a fault i.e. FDIR technologies enable the remote discovery of a fault, the location of that fault and remote power restoration. FDIR technologies have the potential to improve a distribution business fault detection and response capabilities including the discovery of a fault, approximating its location, isolating the equipment responsible, restoring power to non-faulted sections, and deploying resources to restore power to the affected areas. FDIR technologies can reduce the duration of outages to customers on unaffected network sections, automatically switch the network and implement sophisticated switching schemes. These characteristics can generate the following benefits: Avoided network capital expenditure Avoided network fault management operational expenditure Avoided customer cost of outages National Cost Benefit Assessment: Executive Report ARUP 51

54 Figure 17 National gross costs and benefits and net benefit of FDIR deployment, medium scenario 20,500 Present Value ($Million) 15,500 10,500 5,500 15, ,310 14, ,500 Search costs VCR FDIR Opex FDIR Capex FDIR Net Benefit Benefits Costs Figure 17 shows the benefits, costs and net benefit of a financially unconstrained national deployment of FDIR technologies for the medium scenario. An unconstrained deployment of FDIR technologies has the potential to deliver the largest economic benefit of any individual technology or product trialled during the Smart Grid, Smart City Program. The net benefit of FDIR technology deployment was estimated to be around $14.41 billion, in present value terms, in Australia through to 2034, with more than 99 per cent of benefits relating to improvements in customer reliability. The remainder, approximately $4 million, is attributable to reduced fault finding costs which represent a minor operational saving nationally for distribution network operators. Recommendation Distribution network businesses should consider where FDIR technologies could provide the best opportunities for improvements to SAIDI in urban and short rural networks, or deliver current SAIDI requirements at a lower cost, and target the deployment of these technologies to achieve optimal reliability outcomes. Modelling showed all of these benefits will accrue within urban and short rural networks. FDIR was found to be cost prohibitive for CBD feeders mainly due to the existing high reliability within CBD areas. 52 National Cost Benefit Assessment: Executive Report ARUP

55 The FDIR benefit of $14.41 billion is found from the national cost benefit assessment was derived from the monetised value of customer reliability described in AEMO s National Value of Customer Reliability Report (2012), which was in turn derived from Victorian surveys conducted in These AEMO values are used to derive the modelling results shown in Figure 17. Improving reliability, that is, increasing the total time that electricity supply to all or any customers within a network is available, has an economic value known as the value of customer reliability. This is based on a customer s estimated economic loss due to a loss of electricity supply and their willingness to pay to avoid an outage. The value any individual customer places on reliability depends on their vulnerability to outages. This will differ by customer type. Some business customers will experience significant productivity losses as a result of even very short outages, while for other customers, several minutes without electricity is unlikely to have any impact on productivity or quality of life. Recommendations There will be significant capital investment required to deploy FDIR technologies nationally. Given the strong potential for national net economic benefits suggested by this assessment, AEMO s 2012 value of customer reliability and its methodology used to calculate these values should be updated. When an updated series of figures for the value of customer reliability are available, the business case for deploying FDIR technologies nationally in urban and short rural networks should be re-evaluated. The Smart Grid, Smart City Customer Application network and retail trials did not assess consumers willingness to accept lower levels of reliability (i.e. accept a greater number and / or longer outages) in exchange for lower prices. This may be an area of additional research that the AEMC or AEMO could undertake in determining the value of customer reliability. At the time this report was published there were no agreed industry-wide values for customer reliability. AEMO is also currently conducting a national VCR review, which is due to be completed in September As part of the review, AEMO will develop regional-specific VCRs which can effectively be applied for use in revenue regulation, planning and operational purposes in the NEM. Despite this uncertainty, even if the VCR values were reduced significantly, it is highly likely that investment in FDIR technologies will still show a significant national net benefit for short rural and urban networks in Australia. National Cost Benefit Assessment: Executive Report ARUP 53

56 The AER also has an existing incentive framework for networks to invest in technologies to improve reliability under its distribution Service Target Performance Incentive Scheme (STPIS scheme). The STPIS is designed to encourage distribution businesses to maintain or improve service performance for both supply reliability and service performance. The STPIS sets targets for the average duration (SAIDI) and frequency (SAIFI) of outages for each electricity distribution business (as well as other service performance targets). The scheme provides financial bonuses and penalties of up to a cap of 5 per cent of revenue to network businesses that meet or fail to meet performance targets, as well as a guaranteed service level (GSL) component under which customers are paid directly if performance falls below specified threshold levels. With the current incentive cap and the fixed fiveyear incentive window, STPIS could constrain the deployment of FDIR. The upper limit of the incentive is generally 5 per cent of annual network revenue for each year of the five year regulatory period 19. Although this is lower than the step change in customer reliability delivered by FDIR, it may still be sufficient to encourage at-risk investment. While the STPIS value is capped at a level significantly lower than the customer value of reliability provided by FDIR estimated in this study, it has been sufficient to incentivise investment in deployment FDIR for some networks. For example, SP AusNet has relied on the STPIS to implement a distributed automation system. However, network operators may consider proposing higher revenue caps to fund more wide scale deployment of smart grid technology including FDIR. Recommendations In light of the potential gap between network benefits which could be achieved by FDIR technologies and the cap on incentives under the current distribution Service Target Performance Incentive Scheme (STPIS), the AER should investigate whether the current scheme is an economically efficient means of delivery the potential net economic benefits of these technologies highlighted by this assessment. Investment by network businesses will also be determined by differing reliability standards in each state and the relative proportions of networks which have low reliability indicators. FDIR is only as valuable as the reliability improvement it delivers, which means that a targeted deployment on a network s worst performing feeders would be expected to deliver the greatest benefits, with diminishing returns as reliability improves. As a result, care should be taken when applying the outcomes from this trial to the wider network reliability indicators, as the reliability improvements for FDIR will be area-specific. In addition to the AER s STPIS, individual states apply their own reliability standards 20. These standards differ by jurisdiction and are generally either (or a combination of): Deterministic, requiring a certain level of redundancy in specific parts of the network (usually expressed as N-x requirements), or Probabilistic, requiring that investments take place only if the benefits from doing so (based on VCR) exceed the costs 19 Within the current STPIS framework network operators can request to up to 10 per cent revenue at risk (with rollout in year one) but most network businesses choose not to accept the greater level of revenue risk 20 Noting that the COAG Energy Council has asked the AEMC to investigate opportunities to standardise reliability standards across NEM states 54 National Cost Benefit Assessment: Executive Report ARUP

57 Historically most jurisdictions have had some form of deterministic reliability standard. In many of these states there has been discussion as to the contribution of deterministic reliability standards to higher distribution network capital investment and increased network electricity tariffs for consumers. Most states have, or are in the process of moving towards probabilistic reliability standards. FDIR technologies have the potential to assist network businesses to achieve minimum standards at lower costs. However, it is plausible that deterministic standards may be a barrier to FDIR technologies where the comparable reliability benefits afforded by FDIR are not considered in the assessment. The high benefit to cost ratio of FDIR technologies implies that FDIR may represent a more economic alternative to traditional approaches used to increase customer reliability. This suggests that deploying FDIR technologies may provide an opportunity to raise reliability standards in some parts of the electricity network without having a significant impact on customer electricity prices. National Cost Benefit Assessment: Executive Report ARUP 55

58 8.3 Key findings and recommendations for Active Volt-VAr Control (AVVC) technologies AVVC technologies apply automated voltage regulating and reactive power controls to measure and maintain acceptable voltages and high power factor at all points in the HV distribution network under varying load conditions. Reducing system losses by minimising real and reactive power flow in the network through voltage control and the control of reactive sources Improving power quality through improved voltage profiles Reducing energy consumption through conservation voltage reduction technology Given this functionality, AVVC technology is best placed in strategic locations where there are power factor, capacity or voltage constraints in a HV network. AVVC field trials included automated management of power factor, conservation voltage reduction and peak demand reduction and demonstrated the technical feasibility of each technology application in an Australian distribution network environment. The role for AVVC technologies in the smart grid includes the potential for: Deferring capital expenditure (network and new generator capacity) by improving the utilisation of existing assets through minimising reactive power in the network and peak shaving at times of maximum load Figure 18 shows the benefits, costs and net benefit of a financially unconstrained national deployment of AVVC technologies for the medium macroeconomic scenario. Analysis of AVVC technology showed the potential for net benefits of $756 million in present value terms, under the medium scenario for Australia through to 2034, with the majority of these benefits attributable to urban and short rural networks. Approximately five per cent of benefits also were shown in long rural networks, although only in some states. Figure 18 National gross costs and benefits and net benefit of AVVC deployment, medium scenario 1, Present Value ($Million) Avoided Line Losses Peak Benefits Capex Opex Benefits Costs AVVC Net Benefitsd 56 National Cost Benefit Assessment: Executive Report ARUP

59 The strongest economic benefits were seen in urban and short rural networks in New South Wales and Victoria, followed by Queensland, with lower levels of benefits seen for other states in Australia. Other key findings from the cost benefit assessment of AVVC which included the Smart Grid, Smart City trial results are summarised below: Automated capacitor banks and voltage regulators (both types of AVVC technologies) could be economically deployed on high voltage networks within urban and short rural networks from 2019 and on long rural feeders from Deployment of AVVC devices within CBD networks was found not to be economically viable under any of the macroeconomic scenarios The greatest financial benefits from AVVC are likely to be achieved in a distribution network s worst capacity or voltage constrained areas AVVC-style control could be a key enabler to derive benefits and manage some of the network costs from distributed generation (e.g. from higher rooftop solar PV penetration). The benefits of AVVC technologies are likely to increase with higher levels of distributed generation In Australia there appears to be a net benefit business case for the more rapid deployment of AVVC technologies. This business case could be marginally improved if distribution network operators were able to adequately quantify other market benefits which accrue other parts of the market. As an example, benefits from the reduction in line losses due to a future deployment of AVVC devices will be split (or shared) between network operators and retailers. In the case of AVVC devices, the benefits which accrue to line losses are relatively minor ($9 million in gross benefits) compared to the improved power factor benefits ($846 million in gross benefits). AVVC may have a greater role in managing power quality in network areas where there are significant volumes of grid-connected rooftop solar PV installations. As the amount of distributed generation increases in Australia over the coming decades, AVVC technologies are likely to have a growing role in distribution networks. The Smart Grid, Smart City AVVC field trials also demonstrated that the technology is effective in managing the voltage profile in the distribution network. High penetration of rooftop solar PV was shown to result in voltage rise near the inverter connection point. If voltage rises above the preset upper voltage limit (253 V) the inverter will trip, resulting in solar spillage. AVVC can be used to better control the voltage profile and hence avoid solar spillage, meaning that strategic deployment of these technologies has the potential to avoid power quality rectification costs. Recommendation Network operators should investigate the potential benefits which could be achieved from the deployment of AVVC technologies in areas of their networks where there are power factor, capacity or voltage constraints. This may include a comparison of the existing costs to remedy power factor, capacity or voltage constraints and the alternative costs of deploying AVVC in these locations. Across the high, medium and low economic scenarios, modelling suggested that there was very little difference in the location and magnitude of the net benefits, implying that under any scenario, there were likely to be net benefits from AVVC deployment. AVVC was shown to have a strong business case for urban and short rural networks and in some locations long rural networks. As with many smart grid technologies, the need for enabling ICT infrastructure (a common platform) to enable communication with devices is also a consideration. Network businesses will need to determine whether their existing SCADA or other systems are compatible with the AVVC devices. National Cost Benefit Assessment: Executive Report ARUP 57

60 8.4 Key findings and recommendations for Substation and Feeder Monitoring (SFM) SFM technologies use a collection of monitoring devices to measure current, voltage, power factor and a range of environmental and technical conditions including partial discharges, dissolved gases and thermal conditions in order to monitor the network state and condition of assets within the distribution network and to predict faults before they occur. SFM technologies can improve utilisation of existing network assets, reduce network fault search time, avoid unscheduled maintenance, avoid certain manual inspection tasks and extend asset life by identifying and rectifying potential problems before they occur. Due to the high cost of monitoring equipment and the need for dedicated communications links, on-line asset condition monitoring has traditionally been limited to a small number of high-value network assets in the zone substations. Performance monitoring of transmission lines, feeders, distribution transformers and other assets outside the substation has typically been carried out through scheduled inspections and tests. Network performance monitoring technologies include earth fault indicators, line fault indicators, and substation metering. The benefits of network monitoring technologies include avoiding the costs of load survey and power quality surveys as well as providing automated fault detection which reduces both outage time and fault finding labour costs. For both network performance and asset condition monitoring, individual components can either be integrated within new asset purchases or deployed as an aftermarket retrofit for existing equipment. SFM technology potentially offers various benefits including providing information to help manage outages and optimise maintenance by helping to avoid outages and lower maintenance and inspection costs. Figure 19 shows the results of the assessment including the gross benefits and costs and net benefit of a national deployment of SFM for network monitoring technologies under the medium macroeconomic scenario. Figure 19 National gross costs and benefits and net benefit from SFM (network monitoring) technologies (medium scenario) Present Value ($Million) Search costs VCR Load Surveys PQ Surveys Load Surveys Opex SFM Net Benefit Benefits Costs 58 National Cost Benefit Assessment: Executive Report ARUP

61 The results showed a national net benefit of $88 million for an investment of $163 million attributable to SFM network monitoring technologies. This includes $230 million from improved reliability benefits to customers, based on the value of customer reliability (discussed previously in the FDIR technology results). In addition there are also operational savings from avoided load and power quality surveys, which contribute to a further $21 million in benefits in present value terms. Network monitoring capabilities are available from both FDIR and SFM technologies. The modelling showed a better business case for FDIR compared to SFM in most network types due to the additional reliability benefits of FDIR. The exception to this is in CBD networks where because of existing high levels of reliability SFM becomes a cheaper option. Recommendation As with FDIR technologies, there is a significant capital investment required to deploy SFM network monitoring technologies nationally relative to the benefits. Before this investment occurs, AEMO s 2012 value of customer reliability and the methodology used to calculate these values should be updated. When an updated series of figures for the value of customer reliability are available, network operators should investigate whether SFM network monitoring devices could be cost effective in CBD and long rural networks. Notwithstanding, network businesses in Australia have already been deploying lower cost SFM technologies including earth fault indicators, line fault indicators and substation metering in preference to FDIR. This may have been influenced by underinvestment in FDIR technologies because of existing regulatory investment limitations of STPIS (refer to the previous FDIR recommendations). Recommendation Further investigations should be undertaken by network operators to determine whether FDIR technologies could deliver higher net benefit network monitoring in place of lower cost SFM technologies 8.5 Observations on wide area measurement systems (WAMS) trials Wide Area Management Systems (WAMS) are currently used by transmission and distribution network companies around the world as part of the monitoring, measurement and control of the complex behaviour exhibited by large power networks. In its present form, WAM may be used as a standalone system that complements the grid s conventional supervisory control and data acquisition (SCADA) system. As a complementary system, WAM can enhance the operator s real-time situational awareness that is necessary for safe and reliable grid operation. WAM technologies (also referred to as synchrophasors) are protection relays capable of providing high speed, time-synchronised measurements of the electrical network, including voltage, current and frequency. Once deployed at strategic points on the transmission and distribution networks, these devices generate data that can be used to provide an accurate view of the health of the larger grid. It should be noted that WAM technologies were not included in the national cost benefit assessment. The inherent complexity of estimating its benefits and the current lack of benchmarking data made available in the industry makes it virtually impossible to quantify the benefits. This gap is a key learning from the project and highlights the importance of further studies within the industry to generate key benchmarks to inform the business case for such technologies. National Cost Benefit Assessment: Executive Report ARUP 59

62 The inherent complexity of benefits and the lack of benchmarking data currently available in the industry made it impossible to quantify the benefit for the cost benefit analysis. This gap in cost data is a key learning from the Smart Grid, Smart City WAM Project and highlights the importance of further studies within the industry to generate key benchmarks to inform future business cases. The WAM field trials demonstrated the following (unquantified) benefits which could potentially assist in managing the risks of wide area outages and reducing network capital expenditure: Assessing baseline power system performance which assists in network planning and assessing efficiencies in the grid Using synchrophasor data to increase visibility of the sub transmission network performance and to identify appropriate locations for phasor measurement unit (PMU) installation Using synchrophasor data to obtain accurate and current information with respect to the state of the network at all levels to assist in forecasting Improving the reliability of power measurement data The value of these benefits was not able to be quantified as each of these elements are highly dependent on the effectiveness of existing network analytics, engineering practices and operational conditions. This is highly sensitive network business data for which there exists no publicly accessible benchmarking data. 8.6 Key findings and recommendations for Smart Meter Infrastructure (stand-alone) Two different deployment value propositions for the deployment of smart meter infrastructure were modelled as part of the national cost benefit assessment. The first, termed stand-alone is a full deployment approach to rolling out smart meters in Australia. Under the stand-alone or full deployment approach, it assumes that smart meters can be economically deployed based on the financial savings of including remote meter reading, remote connections and disconnections and other benefits such as savings on manual load and power quality surveys. A full deployment is similar to the mandated deployment of smart meter infrastructure currently underway in Victoria. In addition to the stand-alone or full deployment approach to, assumptions were made about a customer-led rollout of smart meter infrastructure. For the purposes of this modelling, a customer-led smart meter rollout occurs either when customers voluntarily uptake a dynamic tariff or when customers take up either distributed generation or distributed storage technologies. The result of the cost benefit assessment of a customer-led deployment of smart meter infrastructure is discussed in the following section. The trajectory of each of the different smart meter infrastructure deployment approaches is described in Figure 20. Smart meters provide the enabling infrastructure required for smart grids. In a stand-alone capacity, smart meter infrastructure provides: The capability to remotely collect 30-minute (interval) data on the electricity usage of customers Power quality data to monitor networks e.g. voltage and current 60 National Cost Benefit Assessment: Executive Report ARUP

63 Smart meter infrastructure also enables: The introduction of dynamic tariffs, allowing cost reflective price signals to be sent to electricity consumers Remote delivery of off-peak scheduling for hot water systems (replacing the existing ripple control systems) Remote control of household appliances such as cycling of air-conditioning (DRED) for the purpose of managing electricity demand during peak events under the smart grid case Communications and metering for electric vehicle smart charging Under the smart meter infrastructure (stand-alone) business case, the assessment included the costs and benefits of avoided meter reading; avoided power quality surveys; avoided costs for customer connections and disconnections; and avoided load surveys. The expected change in smart meter penetration in Australia over time has been shown in Figure 20. This figure shows the gradual increase in the number of smart meters in Australia under the smart grid medium scenario. It shows that in 2014 approximately two thirds of all customer meters have the traditional spinning disc electricity meters with the majority of smart meters being located in Victoria due to their mandated deployment. In the early years of the modelling (from 2014), the number of smart meters deployed under the standalone or full deployment approach is expected to be very small because the relatively high capital cost of the smart meter infrastructure means that the avoided costs from its deployment are insufficient to outweigh the costs. In the first instance, smart meters are deployed economically predominantly in long rural networks because the costs of manual meter reading, connections and disconnections are higher than in more densely populated areas. However, over time with the reduction in smart meter capital costs, the number of meters increases, particularly in urban and short rural networks which serve the majority of Australian customers. Figure 20 Smart meter penetration under the smart grid case (medium macroeconomic scenario) National Cost Benefit Assessment: Executive Report ARUP 61

64 The pink shaded area of the chart shows the impact of the smart grid medium case assumptions including customers taking up distributed generation and distributed storage devices and voluntarily adopting dynamic tariffs. For the purposes of this report, this has been termed a customer led rollout of smart meter infrastructure. As the customer led deployment increases over time, the unit cost of a manual meter read also increases due to the increased travel distance between spinning disc meters. In turn this further enhances the business case for smart meter infrastructure deployment in the later years and by 2029 modelling showed that smart meters can be economically deployed to all electricity customers. The orange shaded area of the chart shows the growing number of smart meters which are deployed under the medium economic smart grid case where it is economically sensible to do so. This has been termed a full deployment of smart meters for the purposes of this report. In summary, the cost benefit assessment found that currently, for most network types in Australia, the costs of deploying smart meter infrastructure outweighed the financial benefits. The exception in some states and under some economic scenarios, is long rural and CBD feeders. This is because the avoided billing, metering and customer service costs for long rural networks are higher than for urban and short rural networks. This means that the higher avoided costs for long rural networks are sufficient to offset the capital and deployment costs of smart meters. However, over time, as metering capital costs reduce, this value proposition changes, particularly from around In order to maximise the benefits from smart meter deployment, it will be important to ensure that there are mandatory minimum standards established, where cost effective, to maximise use of associated smart metering services by all participants and to reduce unnecessary meter churn. The AEMC is currently considering a rule change with respect to the expansion of competition in metering and related services. As part of that process, AEMC has indicated that a minimum functional specification for smart meters should be developed and adopted by individual jurisdictions. Advice is currently being prepared by AEMO to the COAG Energy Council on minimum smart meter functionality reflecting the Power of Choice principles, and the development of a shared market protocol (common communication standards using B2B as the baseline). In order to realise the smart meter benefits identified in the national cost benefit assessment modelling, it will be important that any minimum smart meter functionality and shared market protocol enables cost effective access to data for network operators, retailers or third-party providers of smart metering services. Recommendation The COAG Energy Council should ensure that the minimum guidelines for smart meter functionality currently being developed by AEMO is sufficiently contemporised to enable network operators, retailers and third-party providers of smart metering services to cost effectively access relevant data in order to derive the full benefits of smart meters. 62 National Cost Benefit Assessment: Executive Report ARUP

65 8.7 Key findings and recommendations for dynamic tariffs and customer feedback technologies (plus SMI) The cost benefit assessment to deploy dynamic tariffs and customer feedback technologies (plus SMI) relies on the same assumptions on SMI costs and benefits as described by the stand-alone or full deployment business case. In addition, it assumes that the uptake of smart meters in conjunction with dynamic tariffs and customer feedback technologies will also drive the realisation of additional national economic benefits. This type of rollout is referred to as customer led deployment and was discussed in the previous section of this Executive Report (with the trajectory of the rollout shown in Figure 20). Unlike the stand-alone deployment of smart meter infrastructure there is an economic business case now (in 2014) across all network topologies for deployment of smart meter infrastructure in conjunction with: A customer voluntary take up of a dynamic tariff with customer feedback technologies, or The installation of distributed generation, distributed storage, electric vehicle smart charging and DRED control products (modelling for the national cost benefit assessment assumed it was compulsory for customers to take up dynamic tariffs when these devices were installed) Dynamic tariffs (which consist of a combination of a network capacity tariff, retail critical peak pricing, or direct load control tariffs) combined with customer feedback technologies (and SMI), incentivises customers to behave in a way that either assists retailers to manage electricity market price risk and/ or assists network operators to reduce future capital investment caused by unmanaged growth in peak demand. These behaviours and market outcomes also have the potential to lower future electricity price increases for customers in Australia. The cost benefit assessment modelling assumed a steady growth in the number of customers adopting a range of dynamic tariffs and prepayment plans based on the adoption rates observed in the Smart Grid, Smart City Customer Application network and retail trials for the selected products and feedback technologies. Detailed information on these assumptions and inputs is available from the Modelling Inputs Technical Compendium which is available on the Smart Grid, Smart City Information Clearing House at Under the modelled smart grid case, electricity consumers who choose to adopt distributed generation and distributed storage products were assumed to be required to adopt dynamic tariffs. Figure 21 shows the assessment of the gross benefits and costs and net benefit of a national deployment of dynamic tariffs and customer feedback technologies under the medium macroeconomic scenario. National Cost Benefit Assessment: Executive Report ARUP 63

66 Figure 21 SMI and dynamic tariff and customer feedback technologies gross costs and benefits and net benefit under the medium scenario 4,500 Present Value ($millions 2014 Real) 4,000 3,500 3,000 2,500 2,000 1,500 1,000 1, ,514 1, Network CAPEX GEN OPEX GEN OPEX SMI benefits SG CAPEX Total Benefits Cost Modelling indicated that under the medium economic scenario, the gross benefits for deployment of dynamic tariffs and customer feedback technologies (with SMI) were more than $3.64 billion for the period through to In order to achieve these benefits, a significant upfront investment of around $2.5 billion is required, mostly in the form of smart meter infrastructure. This results in a net benefit of more than $1.12 billion in present value terms from the deployment of dynamic tariffs and products in Australia through to Given these results, there is a strong economic business case for the immediate deployment of dynamic tariffs in conjunction with customer feedback technologies and smart meters in Australia. Based on this modelling it is also clear that: If dynamic tariffs are voluntary, not all customers will adopt the offer. For some customers dynamic tariffs will result in higher electricity bills compared to BAU. These findings are discussed further in Section 8.10 of this Executive Report Without dynamic tariffs (cost reflective pricing) customers will be presented with a strong financial incentive to install larger distributed generation systems. The consequence of this will be higher network tariffs for all customers, which will further increase forward electricity prices. In addition the cross subsidies which flow to customers who install distributed generation and distributed storage systems from those who do not, has been modelled to grow significantly through to 2034 under BAU in the absence of dynamic tariffs 64 National Cost Benefit Assessment: Executive Report ARUP

67 If inclining block tariffs (or flat tariffs) are maintained in Australia modelling showed that it will be unlikely that distributed storage will be deployed by consumers due to a lack of financial incentives though to 2034 (the modelling period). Conversely, the introduction of dynamic tariffs was likely to see distributed storage installed from 2024 under the medium economic scenario. This is further discussed in Section 8.9 of this Executive Report Notwithstanding the strong economic business case for the introduction of more cost reflective electricity pricing (dynamic tariffs), it has been acknowledged that some jurisdictions may find this challenging. The Customer Research Survey found that overall there was a high level of satisfaction with the Smart Grid, Smart City Customer Application network and retail trialled products, with customers generally reporting higher levels of engagement and benefit from products where a dynamic pricing/incentive structure was combined with a feedback technology. In particular, customers interacted more with the home energy monitors (in-home displays) relative to online home energy data. The most popular trial products were those involving discrete peak events with either a rebate or price incentive. BudgetSmart products which focussed on customers remaining in credit on their electricity bills were also popular with participants. In order to achieve widespread deployment of dynamic tariffs, there is a significant body of policy and rule-making process work to be completed. Some of this work is already underway including: The AEMC is currently considering a rule change proposal from SCER (now the COAG Energy Council) related to the way that distribution network prices are set and structured. 22 Among other things, SCER proposed that the pricing principles for distribution prices should be amended to include a requirement for distribution prices to be based on the long run marginal cost (LRMC) of providing network services (rather than the current requirement to take into account LRMC). SCER noted that the proposed changes should seek to reflect that network costs are largely driven by meeting peak demand requirements, so that where prices reflect the costs of meeting peak demand over time consumers will be able to respond efficiently in ways that help to minimise costs over time The COAG Energy Council s Demand Side Participation (DSP) Program includes a work stream to deliver market settings that allow for jurisdictions to provide consumers with the option to move to time-varying pricing The Customer Research Survey also showed that financially vulnerable customers, including pensioners, derived more benefit and satisfaction from trialled products than to their counterpart households 21. This suggests it will be important to develop and market products which will assist those who may have trouble in paying their electricity bills to better manage their costs. 21 This is discussed further in the Customer Research Survey which can be found on the Smart Grid, Smart City Information Clearing House 22 Network-Pricing-Arrangements# National Cost Benefit Assessment: Executive Report ARUP 65

68 These processes have the potential to ensure that dynamic tariffs are widely available to customers and it is clear that some jurisdictions are more progressed than others in regard to this allowing flexible pricing. However, given the substantial benefits suggested by the Smart Grid, Smart City national cost benefit assessment for dynamic tariffs deployed with smart meter infrastructure, AEFI consider that it is important to monitor the extent to which dynamic tariffs are available and are adopted, and to consider a stronger policy response in the event that dynamic tariffs are not widely adopted. This could include a requirement that a standard dynamic tariff is available to small customers in each state. Given the existing energy market reforms underway and the findings of the Smart Grid, Smart City national cost benefit assessment for dynamic tariffs deployed with smart meter infrastructure, the following recommendations have been made: Recommendations Given the strong business case for deployment of dynamic tariffs and customer feedback technologies (with smart meters), state governments should allow for flexible pricing to be available to small customers in each state. The AER should undertake continued assessment of the take up of voluntary dynamic tariffs in Australia and report these rates as part of its reporting on the performance of energy retailers and distributors. The COAG Energy Council should assess the benefits of a stronger policy mechanism to deploy dynamic tariffs with smart meters if the voluntary take up of dynamic tariffs proves insufficient to realise the potential benefits. The outcomes of the national cost benefit assessment demonstrate that care needs to be taken in the design of dynamic tariffs. Under the low scenario, the benefits of distributed generation and storage appear to be over signalled by the seasonal time of use tariff applied in the smart grid case, such that the incremental network and generation benefits realised by additional distributed generation and storage capacity did not offset the incremental customer investment. Despite this finding, the seasonal time of use tariff structure has the potential to be more cost reflective than the current default inclining block tariff (IBT) structure. The magnitude of the price signal will require careful consideration in development of future tariffs with either a peak or capacity based component to ensure that the value of customer demand response during peak times is cost reflective. The AEMC is currently undertaking a consultation process as part of its Distribution Network Pricing Arrangements Rule Change which has suggested that each charging parameter within the network tariff should be based on LRMC of providing the services. AEFI notes that the results of the Smart Grid, Smart City national cost benefit assessment is supportive of SCER s rule change proposal that tariffs should be cost reflective. Increasing demand side participation from the introduction of dynamic tariffs makes future load forecasting more complex and will require network businesses to modify their existing load forecasting models. A consequence of this is that network businesses may benefit from moving to probabilistic network planning in order to capture the effects of critical peak pricing and increased distributed generation in their planning processes. 66 National Cost Benefit Assessment: Executive Report ARUP

69 As well as developing appropriate pricing elements within dynamic tariffs, network operators and retailers should have regard to the findings of the Smart Grid, Smart City Customer Applications retail and network trials which suggested: The need to offer more regular billing cycles and / or provide tangible information for customers on their savings from engagement such as bill estimation That potential benefits and costs should be clearly and simply communicated to customers That dynamic tariff products should be paired with feedback technologies to deliver greater customer savings Electricity network operators and retailers should note from the Customer Research Survey that some groups (like the elderly) may require additional assistance in setting up and engaging with the dynamic tariffs and customer feedback products. Recommendation The COAG Energy Council should ensure that the existing customer protection measures in the National Energy Retail Rules are sufficient to ensure all consumers, particularly vulnerable consumers, are afforded appropriate protections when new dynamic pricing mechanisms are introduced. For jurisdictions that have not adopted the National Energy Retail Law, state governments should determine whether existing consumer protection mechanisms are sufficient prior to the introduction of dynamic pricing mechanisms. 8.8 Key findings and recommendations for Electric Vehicles (EVs) Whilst electric vehicle numbers are currently very low in Australia, they are expected to grow steadily over the next 20 years. Vehicle numbers are then expected to grow more rapidly once price parity with conventional internal combustion engine vehicles is reached in the late 2020 s. Given these projections, numbers of electric vehicles in Australia are expected to grow more rapidly beyond the assessment period of this modelling (2034). As the number of electric vehicles in Australia increases, so too will the charging load on local distribution networks (both total consumption and peak demand). If not managed carefully, electric vehicle charging load has the potential to increase peak demand, requiring additional network capital investment, which will contribute to higher consumer electricity bills. The impact will be greatest on areas of the network where there is less diversity in demand profiles. It is important to note that the electric vehicle business case presented in this report assesses the benefits of smart charging of electric vehicles rather than the benefits of the vehicles themselves. That is, the number of electric vehicles in Australia is assumed to be the same under both BAU and smart grid cases, but the charging behaviour is different. Under BAU, electric vehicle charging is uncontrolled, whilst the smart grid case assumed smart charging which uses two-way communication between the network and the charging point and includes direct load control of vehicle demand. Compared to BAU, this has the effect of reducing peak demand growth whilst increasing network asset utilisation (or load factor). National Cost Benefit Assessment: Executive Report ARUP 67

70 The Smart Grid Smart City electric vehicle field trial tested the performance of first generation production vehicles across a range of driving conditions and using six fast charging charge points. It also trialled 40 domestic charge points which were not configured for smart charging. Instead, the Smart Grid Smart City trials focussed on the relative merits of time-of-use charging tariffs for electric vehicles. To broaden the outcomes of the EV Project, advanced modelling using the PS+EDGE platform was undertaken by Ausgrid. The modelling investigated various charging schemes including time of use tariffs and smart charging through direct load control and two way communications with the network operations centre. The modelling showed that time of use tariffs were likely to introduce new peaks in the low voltage network, at the time of the off peak rate, by However, smart charging resulted in increased utilisation and no increase in network peak demand caused by electric vehicle smart charging over the assessment period which ended in Uncontrolled electric vehicle charging leads to an increase in the evening peak demand as many people plug-in the vehicles at around the same time when they arrive home. Smart charging can minimise the increase in peak demand from electric vehicle charging, which can reduce and /or defer generator capital and operational expenditure and network capital expenditure. Figure 22 shows the resulting benefits, costs and total net benefit of a national deployment of electric vehicle smart charging for the medium macroeconomic scenario. Figure 22 Electric vehicle charging gross costs and benefits and total net benefit (medium scenario) ($Million) Benefits Gen CAPEX Benefits Network CAPEX Costs SG CAPEX Costs Generation OPEX Total 68 National Cost Benefit Assessment: Executive Report ARUP

71 Based on the Smart Grid, Smart City EV Trial modelling, the net benefit of smart charging for electric vehicles is estimated to be $89 million in present value terms in Australia through to 2034, under the medium economic scenario. Under the smart grid (smart charging) scenario, electric vehicles make a minimal contribution to peak demand on the network because EV demand is able to be controlled and shifted outside the peak period. Electric vehicle smart charging also leads to an improved distribution network load factor (a key metric of network performance) and this contributes to the $89 million net benefit from smart charging under the smart grid case. The results of the modelling show that the greatest impact of deploying electric vehicle smart charging infrastructure is in urban networks and short rural networks where electric vehicle uptake is likely to be highest. The benefits of smart charging during the assessment period are significant and would likely be even greater in the subsequent decade where greater growth in electric vehicle numbers is expected in Australia. Time of use pricing offers one solution to the electric vehicle charging problem. However, time of use pricing may not be sufficient in its own right and may create new localised peaks at high electric vehicle uptake rates. The electric vehicle charging solution therefore must not only shift the time of charging but increase the diversity of the charging load. Based on the results of modelling undertaken for the Smart Grid, Smart City Program, there appear to be several viable options to achieve improved diversity of electric vehicle charging including direct load control or smart charging. The modelling showed that there is a strong business case for the use of smart charging (either directly or via critical price tariff). Recommendation Standards Australia should incorporate demand response capabilities within the Australian Standard AS for electric vehicle charging to ensure electric vehicle charging points installed today will be compatible with managed charging schemes in the future. National Cost Benefit Assessment: Executive Report ARUP 69

72 8.9 Key findings and recommendations for Distributed Generation (DG) and Distributed Storage (DS) Distributed generation The following distributed generation technologies were trialled as part of the Smart Grid, Smart City Program: Rooftop solar PV leveraging existing installations in the suburb of Newington 2.4 kw small wind turbine 1.5 kw solid oxide fuel cell Associated monitoring and control technologies and systems Distributed generation has an impact on customer load profiles for those who adopt these technologies. On a system level, distributed generation has the potential at certain penetration rates to reduce peak demand and mains energy consumption, which can generate benefits including avoided new generator capacity capital expenditure, avoided generator operational expenditure and avoided new network capacity capital expenditure. However, at more granular levels in the network, for example at a feeder level, high levels of distributed generation have the capacity to create challenges in voltage regulation and system stability. These impacts depend upon a number of factors including the number, size and type of distributed generation devices and the network topology for example long rural networks may not be as robust in managing a similar proportions of solar compared with urban networks. This was discussed further in Part Two of this report. Analysis has clearly shown that both the volume and system size of future rooftop solar PV deployment in Australia is sensitive to a number of financial factors including solar PV system costs, the level of feed-in tariffs and the retail pricing structures for electricity sourced from the grid (electricity tariffs). As shown by Figure 23 under both smart grid and BAU cases, modelling indicated there will be continuing growth in both the number of residential solar PV systems deployed in Australia as well as the size of the systems installed. In addition, modelling has shown a strong growth in rooftop solar PV systems on commercial buildings, which are similar in both size and number under both smart grid and BAU cases. For commercial customers, CHP (fuel cells) will also become economic and see some deployment in areas with gas connection. The inclining block tariff represents a form of cross subsidy present in the electricity market. This tariff requires electricity consumers to pay for the use of the network based on total energy consumption rather than the maximum capacity of the network required to meet their peak demand. This type of tariff benefits solar PV owners and any other customer who significantly decreases electricity consumption without necessarily decreasing peak demand. Results from the cost benefit assessment showed that maintaining the existing flat or inclining block retail tariffs in Australia will continue to incentivise the installation of larger solar PV systems in the future, as customers seek to further reduce their consumption of grid-sourced electricity. Unfortunately, this does not necessary reduce peak demand. By contrast, under the smart grid case, the number of consumers investing in rooftop solar PV continues to grow, but the size of the systems are smaller because the cross subsidy through the existing tariff structures is reduced (refer to the discussion in the customer bill impacts in Section 8.10). 70 National Cost Benefit Assessment: Executive Report ARUP

73 Figure 23 National gross costs and benefits and total net benefit from deployment of dynamic tariffs with distributed generation and distributed storage (medium macroeconomic scenario) 35,000 30,000 25,000 NPV ($M 2013 Real) 20,000 15,000 10,000 15, , ,005 10,254 5,000 0 DG & DS CAPEX SMI OPEX Network CAPEX Gen CAPEX SMI OPEX GEN OPEX Total Benefits Costs Similarly, modelling showed that commercial customers with dynamic tariffs were likely to install a similar amount of solar (of a similar system size) as under an inclining block tariff, but in addition install distributed storage and CHP (fuel cells). These changes saw impacts in annual electricity bills for the period through to 2034 for residential and business customers both with and without distributed generation and storage (discussed in the customer bill impact section). Recommendation In light of the projected growth in rooftop solar PV for both residential and business customers in Australia, the COAG Energy Council should direct the AEMC to consult with stakeholders to identify the least cost approach to managing high levels of rooftop solar PV penetration in Australia. National Cost Benefit Assessment: Executive Report ARUP 71

74 The Smart Grid, Smart City trial investigations also showed that smart inverters (also termed STATCOMs when referring to low voltage regulation) had the potential to provide voltage regulation services for network operators. However, rooftop solar PV owners are not currently financially incentivised to install smart inverters. Smart inverters have the potential for undertaking voltage regulation if these inverters were set up on distributed generation and storage systems (particularly rooftop solar PV) to only export onto the grid when the voltage was low. Additionally if there was distributed storage capacity on site, smart inverters could be used to import electricity from the grid when voltage was high (also assisting with voltage regulation). The challenge with existing financial incentives (feedin-tariffs) is that rooftop solar PV inverters are setup for exporting electricity and there may need to be alternative incentives introduced (e.g. for regulation of power quality) to encourage system owners to install smart inverters and offer voltage regulation services. Recommendation If smart inverters can be shown to be cost effective in delivering voltage control and power quality benefits, consideration should be given to increasing the minimum standards for existing inverters in Australia. In this way some of the costs of network remediation caused by increasing numbers of rooftop solar PV could be better managed. This work should involve network operators, standards bodies and industry peak bodies. Investigations around smart inverters are likely to require both embedded network trials and financial assessments in order to determine the business case for this technology Distributed storage The Smart Grid, Smart City Distributed Storage trial used a 5kW/10kWh zinc-bromide flow battery technology with a remotely controllable battery management system including a grid-tie inverter. At the time of the field trial, the zinc-bromide flow battery was new on the market and the only approved grid-connected storage device available (excluding older lead acid technologies). The zincbromide flow battery has a full depth of charge advantage over lead acid batteries which means a smaller unit (kw) could be deployed. Grid battery storage was not successfully implemented in the field trials due to a number of challenges which are discussed in the Distributed Generation and Distributed Storage (DGDS) Technical Compendium. As a result, the specific storage technology used in the trial was not used for the national business case assessment. Instead, lead acid technology was used in the modelling, because it has been demonstrated in an Australian context and because greater operational and financial data was available. Distributed storage has the potential to contribute to the management of growth in system peak demand and has implications for future electricity bill increases. Modelling showed that despite anticipated price reductions in distributed storage devices, without changes to retail electricity pricing structures (i.e. under BAU) there will be no deployment of storage through to 2034 in Australia. Modelling clearly shows that the existing tariff structures effectively discourage the uptake of battery storage technologies. 72 National Cost Benefit Assessment: Executive Report ARUP

75 For commercial customers under the BAU case, price signals encourage investment in relatively large rooftop solar PV and CHP systems. The systems will likely export to the grid during times of low demand, incentivised by a volume based inclining block tariff. In contrast to residential customers, the size of the solar PV systems deployed was not significantly different under either a BAU or smart grid case. This suggests that solar PV for commercial customers is likely to be a financially viable solution in the future regardless of scenario, given the anticipated further reduction in solar PV panel costs. In summary, under the smart grid case, dynamic pricing (network capacity charge in combination with a retail critical peak price) drives the deployment of smaller rooftop solar PV systems (around 3 GW less) and CHP (around 1.8 GW less) in the NEM by 2034 compared to BAU. This however, is balanced by the deployment of around 3.5 GW of storage capacity. Under both BAU and smart grid cases, there is growing adoption of solar PV generation by both residential and commercial electricity consumers. The field trial and modelling showed that the effectiveness of rooftop solar PV systems in reducing summer peak demand is limited, mainly due to misalignment of the timing of rooftop solar PV system output and peak network demand. Advanced modelling of high PV penetration scenarios found that PV reduced feeder peak load on average by 3 per cent. It was also found that the hottest days were not necessarily the sunniest, with later afternoon clouds reducing the amount of available solar radiation on some days. In the case of the field trial for small wind turbines, generation profiles were highly variable and intermittent and did not necessarily match customer energy usage or network peak load profiles. The generation profiles had minimal impact on reducing summer peak demand in the Gundy trial area on the focus days studied. The trials also indicated that the customer and network value of this technology is on average likely to be low and generally less than a comparably sized PV system. While the fuel cell technology trialled had some capability to reduce network peak load, the more efficient operating mode was continuous operation (constant output at the rated capacity of 1.5kW) reducing network load at all times. The results from the trial indicated that the potential customer value of this technology was highest for customers with a higher than average electricity consumption and the ability to better utilise the heat which is generated as a by-product. Modelling suggested that the introduction of dynamic tariffs (critical peak pricing) in conjunction with network capacity tariffs (i.e. the smart grid case) would give rise to a different configuration of combined distributed generation and storage devices at customer premises. The Smart Grid, Smart City trials indicated that there is potential for distributed storage to export into the grid during peak events and that export during these times could provide a cost effective alternative to centralised generation from peaking plants. Currently, exports during peak events from distributed generation or storage devices are not efficiently valued. At present, any export during these events is valued at the feed-in-tariff rate, based on the weighted average cost of wholesale electricity during solar PV export hours, rather than the higher value of generation at peak times. National Cost Benefit Assessment: Executive Report ARUP 73

76 Notwithstanding, there are no existing regulatory barriers to retailers offering a dynamic feed-in-tariff which increases during peak events to better reflect retailer costs. This does not occur at present and was not considered in the modelling exercise. However, it is foreseeable that once distributed storage technology becomes more broadly available, retailers would implement such a tariff which would further incentivise distributed storage uptake beyond what has been modelled. Even with such a dynamic feed in tariff, there remain barriers for network businesses to provide price signals to customers as to value of export from distributed storage during network peak events. Such a price signal could potentially take the form of a one off incentive payment or network rebate during events. This would essentially function as a demand response mechanism (similar to the dynamic peak rebate product trialled), but would reward customers for not just offsetting their own demand but for achieving negative net demand in peak times. Recommendation The COAG Energy Council should, in conjunction with the AEMC, develop a market mechanism which more efficiently values export from distributed energy resources (distributed generation and distributed storage) during market and network peak events. In this way customers may be financially incentivised to export electricity from distributed generation and distributed storage devices in response to market signals. For non-nem states, state and territory governments should consider the most appropriate organisation to undertake a similar review Key findings and recommendations in relation to customer electricity bills Analysis for the cost benefit assessment showed a net increase in real $2014 electricity prices over time for both the smart grid and BAU cases for the period through to Analysis showed a higher wholesale cost of energy in the smart grid case due to the additional centralised generation capacity required to make up for the reduced decentralised generation. By 2034 the wholesale component of the retail price component is 8 per cent higher under the smart grid case compared to BAU. However, network prices under the smart grid case were shown to be significantly lower than the BAU case by 2034 the network price component is 13 per cent higher under BAU compared to the smart grid case. This outcome was mostly driven by the decreased network utilisation because of a lack of incentives under BAU for storage and the effect of unmitigated electric vehicle charging resulting in a higher network cost per unit of electricity. This recommendation is broadly similar to a recommendation stemming from the Power of Choice review and which is currently being considered by the COAG Energy Council officials group. 74 National Cost Benefit Assessment: Executive Report ARUP

77 Residential customer bill impacts Appendix Four of this report presents the full results for 20 customer segments in each state, for each assessment period and each macroeconomic scenario. The results discussed below are for an average customer (as defined in the business case methodology in Appendix Two) in 2034 under the medium economic scenario. Annual residential customer bills were assessed under the smart grid case and BAU case for passive customers (residential customers who choose not to adopt a dynamic price tariff or do not adopt distributed generation or storage and remain on inclining block tariffs), and distributed generation and storage customers (residential customers who adopt distributed generation and/or storage along with dynamic tariffs). The differences between passive residential customers and distributed generation and storage customers under both BAU and the smart grid cases are shown in Figure 24. This analysis clearly shows the breakdown in cost elements in a future residential bill under BAU and smart grid. There are a number of key differences between these cases: The passive customer under smart grid case is $156 per annum better off than the BAU passive customer Business customer bill impacts Annual business customer bills were assessed under the smart grid case and BAU case for passive customers (business customers who do not adopt distributed generation or storage and remain on inclining block tariffs), and distributed generation and storage customers (business customers who adopt distributed generation and/or storage along with a critical peak pricing and time-of-use tariff). The difference between the BAU and smart grid case in average annual bills in 2034 for the average business customer type is shown in Figure 25. This analysis clearly shows the breakdown in cost elements in a future business customer bill under BAU and smart grid. There are a number of key differences between these cases: The passive business customer under smart grid case is $2,018 per annum better off than the BAU passive business customer The cost of the distributed generation and distributed storage cross subsidy under the BAU case at $9,251 per year for passive customers, or more than three times higher than for smart grid passive customers The annualised customer investment cost in distributed generation and distributed storage is higher under BAU, reflecting the over incentivisation for larger systems caused by the inclining block tariff Under the BAU case there is a significantly higher number of passive customers than under the smart grid case The cost of the distributed generation and distributed storage cross subsidy is almost nine times higher under the BAU case at $420 per year than for the smart grid case at $47 per year The annualised customer investment component in distributed generation and distributed storage is higher under BAU, reflecting the over incentivisation for larger systems caused by the inclining block tariff Given the findings for residential and business customer bills, it is clear that under a smart grid case, passive customers (who do not adopt distributed generation or storage nor change their behaviour) are better off compared to passive customers under the BAU case. National Cost Benefit Assessment: Executive Report ARUP 75

78 Figure 24 Impact on average annual residential customer bills in 2034 (medium scenario) 3,000 2,500 $156 $2,159 $420 Annual Bill Impact ($) 2,000 1,500 1,000 $1,712 $244 $47 $2,003 $332 $1, SG Bill Customer with DG/DS Cost of DG/DS Cross Subsidy SG SG Passive SG Benefits BAU Passive Customer Cross Subsidy BAU Cost of DG/DS BAU with DG/DS Average Bill - SG Average Bill - BAU Figure 25 Impact on average annual business customer bills in 2034 (medium scenario) 18,000 16,000 $2,108 $15,292 $9,251 14,000 $3,083 $13,184 Annual Bill Impact ($) 12,000 10,000 8,000 6,000 $8,390 $1,711 $2,620 4,000 $3,421 2,000 0 SG Bill Customer with DG/DS Cost of DG/DS Cross Subsidy SG SG Passive SG Benefits BAU Passive Customer Cross Subsidy BAU Cost of DG/DS BAU with DG/DS Average Bill - SG Average Bill - BAU 76 National Cost Benefit Assessment: Executive Report ARUP

79 Importantly, although customers who take up distributed generation and storage are subsidised by passive customers in both BAU and smart grid cases, for residential customers this cross subsidisation is more than nine times higher under BAU compared to the smart grid case. For commercial customers, those who are passive in the BAU scenario incur a cross subsidy which is more than three times higher than under the smart grid case. This cross subsidy is significant for business customers where the uptake of distributed rooftop solar PV is projected to be a major area of growth over the modelling period. Overall, passive residential customers, who do not change behaviour or make any investment decision, receive an annual saving in the order of $156 per annum by 2034 under the smart grid case compared to the BAU case. Passive business customers, who do not change behaviour or make any investment decision, receive an annual saving in the order of $2,000 per annum by 2034 under the smart grid case compared to BAU. Recommendations In order to avoid a significant future cross subsidy for passive customers modelled under a business as usual approach, jurisdictions should consider mandating the uptake of dynamic tariffs for customer initiated meter upgrades, which would include when customers adopt distributed generation and distributed storage. To protect financially vulnerable customers, the COAG Energy Council should agree an appropriate policy response which provides a safety net for those who are unable to make behavioural or tariff changes. It is foreseeable that if changes which over incentivise the adoption of distributed generation are not addressed, the level of economically inefficient cross subsidies between different customer groups may intensify. This cross subsidy is significant for business customers where the uptake of distributed rooftop solar PV is projected to be a major area of growth over the modelling period. The COAG Energy Council as part of the demand side participation reform program are considering how to transition consumers to more cost reflective and flexible pricing. National Cost Benefit Assessment: Executive Report ARUP 77

80 9 Transitioning industry and consumers to a smart grid future The Smart Grid, Smart City Program and its trials were wide-reaching, and the recommendations in previous sections of this report call for considerable work to embed some of the conclusions into existing regulatory frameworks, NEM Rule Changes and further electricity market development (both NEM and non-nem states). In addition to the recommendations pertaining to smart grid in-grid and customer feedback technologies and dynamic tariffs, there is a need to develop frameworks which will provide both industry and electricity consumers with appropriate information and education about these new technologies and tariffs. It will then require time to change existing work practices and consumption behaviours which may have been entrenched for a number of decades. This will require continued collaboration between the Australian, state and territory governments, peak industry bodies, network operators, retailers, policy makers, market operators and vendors in order to progressively move towards embedding smart grid thinking in policy deliberations and decision-making. 9.1 Electricity distribution networks Existing network resilience and technology maturity Australian network operators are generally starting from a strong position with a relatively robust, resilient and reliable grid. This is due, in part, to significant recent investment in replacing aged infrastructure and the requirement for network operators to meet high customer reliability targets set by jurisdictions. This strong position brings both challenges and opportunities for distribution network operators in deciding when and where to deploy smart grid technologies. While some smart grid technologies are relatively mature, others continue to see rapid development in technology functionality and pricing. This means that network operators need to remain well informed through the monitoring and evaluation of these technologies within the Australian context to ensure that the most cost-effective combinations are chosen. To support the transition to deploying smart grid technologies, the development of supporting common (ICT) platforms and interoperability standards will also be critical in Australia. Without these standards, which will allow for both existing and newer technologies to be integrated via common platforms, the economics for widespread deployment are likely to be unattractive in the foreseeable future. This report has made a number of recommendations relating to common platforms and standards. In addition, some situations where smart grid technologies are integrated into new assets, but are not enabled in distribution networks in Australia, must be understood and remedied. This may require work between the peak industry bodies and network operators to share educational information and to improve understanding about smart grid technologies, and how they can be deployed in the most efficient manner. 78 National Cost Benefit Assessment: Executive Report ARUP

81 9.1.2 Balancing the risks and opportunities from new smart grid capital investment None of the benefits that were suggested by the Smart Grid, Smart City integrated net cost benefit modelling are cost or risk free. Network businesses are capital and asset-intensive and subject to rigorous AER planning and investment rules as regulated monopolies. Further, moving forward, consumers will play an increasingly engaged and active role in the energy sector, through continued investment and deployment of distributed storage and distributed generation devices, electric vehicles, and through active demand side participation with network operators, retailers and third party operators. This participation will be enabled by smart grid technologies and devices. As previously discussed, many smart grid technologies and platforms are relatively new or are evolving in terms of both functionality and price. This could be perceived by network operators as making the economic case for trialling and deploying smart grid technologies in Australian networks more challenging. In addition, within the current environment of very slow growth in demand, and generally decreasing per capita consumption, network owners may be less inclined to seek regulatory approval to spend additional capital on evolving technologies (despite the potential longerterm benefits) given the perceived short-term impact on consumer pricing. Regulatory resets for network businesses also only occur once every five years and network businesses will generally wait for their regulatory reset to put forward a business case for additional capital investment (for example, for smart grid devices). Within the current regulatory phase the AER is considering all NEM distribution network operators regulatory proposals during 2014 and The timing of the release of this report means that either: There may be very limited (or no) additional deployment of network-centric smart grid devices for NEM distribution network companies until their regulatory reset period, or Network owners could choose to invest in smart grid technologies at their own financial risk For non-nem jurisdictions (Western Australia and the Northern Territory), the organisations responsible for network regulation may be faced with similar challenges. Should there be no mechanism for investment in economically efficient smart grid technologies during the next regulatory period and the Australian economy recovers, with growth in peak demand, then some of the national economic benefits shown by the Smart Grid, Smart City cost benefit assessment may not be realised in the foreseeable future. Because of these factors, there may be a need to balance the risk and reward for Australian distribution network operators seeking to innovate within a regulated environment. The AER (or similar organisations in non-nem states) have a role in providing targeted R&D funding to enable network operators to assess where in-grid smart grid technologies could deliver the greatest economic benefit for Australian consumers. National Cost Benefit Assessment: Executive Report ARUP 79

82 Although network operators, not regulators, are responsible for innovation, there is still an opportunity to consider the most effective mechanism to encourage the trialling of potentially economically efficient smart grid technologies within a highly regulated environment. Recommendation As part of the review of the Demand Management and Embedded Generation Connection Incentive Scheme (DMEGCIS), the AEMC and AER should facilitate the location-specific trialling of smart grid technologies by network businesses. In developing the criteria for a reformed DMEGCIS, the AEMC and the AER should consider the findings from the Smart Grid, Smart City trials and this national cost benefit assessment, to target those grid technologies which demonstrate the greatest potential for benefits. Further, given the current regulatory cycle for NEM distribution network companies, the AER should consider an in-cycle review, expansion and release of an updated DMEGCIS. This could mean that network operators have the opportunity to trial smart grid technologies during the next regulatory cycle. Recommendation The Northern Territory and Western Australian state governments should consider the most appropriate mechanism to enable their distribution network operators to trial smart grid technologies within an appropriately incentivised mechanism within their regulatory investment framework People - industry understanding, education and change Given the potential for strong consumer benefits from the deployment of some technologies and the potential for new network solutions, there is a need for industry leadership to facilitate improved sharing of information about smart grid technologies across the entire industry workforce and community. There will be a need for individual network businesses and the industry as a whole, to develop and implement new standard operating procedures. Training programs will also be required so that network engineers have adequate knowledge of how to effectively deploy and integrate new smart grid technologies. This information should also be shared with the AER and the broader sector where possible. Recommendations Industry peak bodies and Smart Grid Australia should consider the most effective ways to improve information sharing and knowledge transfer pertaining to smart grid technologies and their application in the Australian context. To ensure that smart grid technologies are cost effectively deployed and utilised, network businesses should develop new standard operating procedures for the optimal deployment and safe operation of smart grid devices and systems in the network. There will be a need for ongoing assessment to determine whether the current energy market structure, regulatory frameworks and business models provide the appropriate incentives for consumers and energy market participants to support the economically efficient deployment of smart grid technologies and products. 80 National Cost Benefit Assessment: Executive Report ARUP

83 9.2 Electricity consumers Electricity tariff structures, especially for residential consumers who are billed for the volume of electricity consumed, have essentially been unchanged for many years. However, following publication of the Power of Choice report by the AEMC and the adoption of its recommendations by the then Standing Council on Energy and Resources, there have been a number of reviews relating to improving consumer participation in the electricity market and rule changes which will provide a mechanism for the introduction of more cost reflective electricity network tariffs. However, in order to fully realise the potential benefits suggested by the Smart Grid, Smart City Customer Application network and retail trials and the cost benefit assessment modelling there are a number of challenges around consumer understanding and education which need to be overcome. The outcomes of the Smart Grid, Smart City Customer Research Survey which sought to ascertain consumer engagement, behaviour changes, electricity bill savings and consumer feedback on the trial products provides valuable learnings for future deployment of dynamic tariffs in Australia. Given that the majority of electricity customers in Australia may not currently have an understanding of dynamic tariffs, there is a requirement for comprehensive education strategy to improve the understanding for all customers and maximise their opportunity to make bill savings. The Power of Choice review report also recognised the importance of an education strategy for consumers. The COAG Energy Council is currently considering the most appropriate strategy to improve consumer understanding of the benefits of market participation, dynamic tariffs and demand side participation. Although dynamic tariff structures are commonplace in many of the developed nations, there has been considerable reluctance by a range of stakeholders to introduce such changes in Australia. However, the pace at which consumers have adopted rooftop solar PV and more energy efficient appliances should be an indication that general consumer awareness of electricity consumption is improving and that consumers are sensitive to electricity price increases. National Cost Benefit Assessment: Executive Report ARUP 81

84 9.3 Transitioning to greater volumes of distributed generation The traditional electricity system which saw the dispatch of electricity from large centralised generators transported (in one direction) over sometimes large distances to consumers is rapidly changing. The continuing uptake of rooftop solar PV and the potential for economic storage solutions (given cost effective pricing) means that distribution networks are becoming a far more dynamic and responsive system. Smart grid technologies offer the potential to better predict electricity supply and demand at specific locations in the grid, continuously monitor the condition of the grid and major assets, to dynamically reconfigure the network and more efficiently utilise labour and materials. These technologies also provide the opportunity to interact with customers in order to actively manage demand on different parts of the network. A key feature of modern electricity networks in Australia is a growing volume of distributed generation, in particular, rooftop solar PV, the benefits and challenges of which has been extensively discussed throughout this report. There has been significant conjecture as to whether smart grid technologies will be able to better manage larger volumes of distributed generation in the future. The findings of the national net cost benefit assessment based on the trial findings of the Smart Grid, Smart City Program have suggested that a smart grid can manage larger volumes of distributed generation at a lower cost per connection (or per kw). The current electricity network in Australia, in general terms, is able to manage up to about 40 per cent of residential premises with rooftop solar PV within an urban network. For short rural and long rural networks, depending on the individual feeder characteristics, this limit may be lower. Modelling undertaken by Ausgrid for the Distributed Generation and Distributed Storage trials suggested that distributed generation will begin to be systematically constrained-off the network once penetration reaches 40 per cent. Under the current approach it was assumed that network operators manage network augmentation due to rooftop solar PV by reconductoring and distribution transformer replacements, or by upgrading existing power quality management secondary systems (e.g. tap changers, placement of field devices etc.). Assumptions used in the smart grid case of the net cost benefit assessment included several possible approaches to managing rooftop solar PV including: The introduction of cost reflective tariffs (including a network capacity tariff) which means that consumers deploy economically efficient solar PV system sizes Deployment of AVVC technologies which can be used to dynamically integrate distributed and centralised electricity in the distribution network The use of distributed storage (potentially in conjunction with AVVC technologies), improving power factor and reducing line losses by keeping the generation in the local low voltage network Results suggested that under a smart grid case, depending on where costs were allocated, a smart grid could potentially enable 100 per cent of capacity. This modelling requires additional field investigations to determine grid and cost impacts as well as the least cost approach to managing high levels of rooftop solar PV penetration in Australia. 82 National Cost Benefit Assessment: Executive Report ARUP

85 9.4 Australia s grid emissions intensity Whilst the net cost benefit assessment modelling suggested there are positive economic benefits from the deployment of smart grid technologies, analysis showed that with an economically efficient deployment of smart grid technologies there was an increase in the emissions intensity of grid sourced electricity under a smart grid compared to BAU. This means that whilst a smart grid solution is potentially more economically efficient than BAU, there is a trade off with a slightly higher emissions intensity result of around 3.4 per cent under the medium economic scenario. The actual outcome will be influenced by the average emissions intensity of grid-sourced electricity in different parts of Australia and by future rooftop solar PV capital costs (i.e. if rooftop solar PV system costs reduce at a greater rate than assumed for the purposes of this modelling, it is likely that there will be a greater uptake by consumers) and average system sizes. National Cost Benefit Assessment: Executive Report ARUP 83

86 10 Maximising the benefits and opportunities in transitioning to a smart grid in Australia 10.1 Balancing financial, reliability and environmental benefits The Smart Grid, Smart City national cost benefit assessment suggests that there is a clear positive business case for deploying a number of smart grid technologies and pricing products in some parts of the grid in different states of Australia. The economics for these technologies and pricing products vary by technology, by network type, and to some degree, by the rate of economic growth present in Australia at the time The case for cost reflective prices What is clear from the modelled smart grid case is that the introduction of smart meters, in conjunction with dynamic tariffs provides a stronger ability for electricity customers to participate in the energy market as well as an improved opportunity to manage the future growth of electricity peak demand in Australia. As well as moderating peak demand growth, the introduction of smart meter infrastructure with dynamic tariffs has the ability to reduce (in real terms) future electricity bills for many consumers, including those passive consumers who choose not to make behavioural changes, adopt dynamic tariffs or deploy distributed generation and storage devices. This is true for both residential and business consumers 23. Based on the modelling, it is also clear that this economic benefit is likely to increase with higher economic growth in Australia. This means that if the Australian economy returns to a higher period of growth, the efficient deployment of smart grid technologies has the potential to deliver greater economic benefits. Modelling suggested that introducing mandatory dynamic tariffs for some electricity consumers could also deliver more equitable bill outcomes by reducing cross-subsidies between consumers who choose to invest in distributed generation (or indeed any technology or behaviour which reduces consumption without necessarily reducing peak demand) and those who do not. Modelling with the introduction of dynamic tariffs suggests that distributed storage devices would be deployed from 2024 when the technology becomes economic. This suggests that if consumers are appropriately incentivised, they could draw electricity from their local storage devices during peak demand or pricing periods. Under the BAU case, the over-incentivisation of distributed generation investment due to inclining block tariffs and the lack of financial incentives for distributed storage means that these devices are unlikely to be economically deployed unless dynamic tariffs are introduced. 23 Based on the average consumer demand profiles modelled. This is discussed in Appendix Two of this report ( methodology) 84 National Cost Benefit Assessment: Executive Report ARUP

87 10.3 The case for in-grid smart grid technologies There are several in-grid smart grid technologies that based on Smart Grid, Smart City trials and cost benefit analysis, showed a positive net benefit. FDIR showed the strongest net benefit of all technologies, given the strong correlation between technology deployment and improved consumer reliability outcomes. These strong net financial benefit results flow from AEMO s estimated value of customer reliability. As previously noted, given the importance of the value of customer reliability in determining this economic benefit, these values should be updated before reassessing the business case for FDIR (and SFM) technologies. There were also benefits demonstrated by AVVC technologies and to a lesser extent SFM technologies, albeit at lower levels compared to those achieved by FDIR, smart metering and dynamic tariffs. The combination of technologies deployed and network topology has also been shown to be important in determining the magnitude of the net benefits achieved. This means that the Australian Government, network owners and the AER (or AERequivalent organisation in non-nem states) need to carefully review where the greatest financial returns are possible, and deploy the appropriate technologies in these locations. Many of the smart grid technologies showed the greatest financial return in urban and short rural feeders, but there are also some potential strong benefits for CBD and long rural networks with specific technologies in some locations Varying economic conditions and national net benefits International research and other information found as part of this Smart Grid, Smart City Program is that individual smart grid technologies are already being deployed by different network operators across Australia. Further, there are both Rule Changes and policy developments underway which will potentially change the way that consumers participate in Australia s electricity markets. Given these factors it will be important for governments and industry to monitor key indicators within the electricity sector (such as new investment, growth in peak demand and network utilisation), the cost of smart grid technologies and consumer sentiment to determine the optimal time to deploy different smart grid options. In general the cost benefit assessment showed that the national benefits from the deployment of smart grid technologies increased with improving macroeconomic conditions. Recommendation Given the potential for a significant national net benefit from the deployment of a smart grid in Australia, the COAG Energy Council should ensure that the energy sector policy frameworks, including regulatory settings (in both NEM and non-nem states), support investment in net beneficial combinations of smart grid technologies and tariff structures. National Cost Benefit Assessment: Executive Report ARUP 85

88 11 Prioritising the recommendations from the national integrated cost benefit assessment Table 7 provides a summary list of the 23 recommendations within the National Cost Benefit Assessment report which are based on analysis of the findings of the Smart Grid, Smart City trials. These recommendations have been grouped under five primary categories shown in Figure 26. In addition to these five categories, the recommendations list includes a category in which further investigations will be required. Figure 26 Recommendation categories Cost reflective Pricing for consumers Need for interoperability standards Existing COAG Energy Council market reform program Jurisdictional government and industry leadership Innovation in technology and product deployment Consumer education and industry training 86 National Cost Benefit Assessment: Executive Report ARUP

89 Table 8 Summary list of recommendations Recommendation Category Jurisdictional government and industry leadership Recommendation Recommendation 1 Given the potential for a significant national net benefit from the deployment of a smart grid in Australia, the COAG Energy Council should ensure that the energy sector policy frameworks, including regulatory settings (in both NEM and non-nem states), support investment in net beneficial combinations of smart grid technologies and tariff structures. Recommendation 2 Given the strong business case for deployment of dynamic tariffs and customer feedback technologies (with smart meters), state governments should allow for flexible pricing to be available to small customers in each state. Recommendation 3 The COAG Energy Council should ensure that the existing customer protection measures in the National Energy Retail Rules are sufficient to ensure all consumers, particularly vulnerable consumers, are afforded appropriate protections when new dynamic pricing mechanisms are introduced. For jurisdictions that have not adopted the National Energy Retail Law, state governments should determine whether existing consumer protection mechanisms are sufficient prior to the introduction of dynamic pricing mechanisms. Recommendation 4 Cost reflective pricing for consumers To protect financially vulnerable customers, the COAG Energy Council should agree an appropriate policy response which provides a safety net for those who are unable to make behavioural or tariff changes. Recommendation 5 The COAG Energy Council should assess the benefits of a stronger policy mechanism to deploy dynamic tariffs with smart meters if the voluntary take up of dynamic tariffs proves insufficient to realise the potential benefits. Recommendation 6 The AER should undertake continued assessment of the take up of voluntary dynamic tariffs in Australia and report these rates as part of its reporting on the performance of energy retailers and distributors. Recommendation 7 The COAG Energy Council should, in conjunction with the AEMC, develop a market mechanism which more efficiently values export from distributed energy resources (distributed generation and distributed storage) during market and network peak events. In this way customers may be financially incentivised to export electricity from distributed generation and distributed storage devices in response to market signals. For non-nem states, state and territory governments should consider the most appropriate organisation to undertake a similar review. National Cost Benefit Assessment: Executive Report ARUP 87

90 Recommendation Category Cost reflective pricing for consumers Innovation in technology and product deployment Recommendation Recommendation 8 In order to avoid a significant future cross subsidy for passive customers modelled under a business as usual approach, jurisdictions should consider mandating the uptake of dynamic tariffs for customer initiated meter upgrades, which would be applied when customers adopt distributed generation and distributed storage. Recommendation 9 As part of the review of the Demand Management and Embedded Generation Connection Incentive Scheme (DMEGCIS), the AEMC and AER should facilitate the location-specific trialling of smart grid technologies by network businesses. Recommendation 10 The Northern Territory and Western Australian governments should consider the most appropriate mechanism to enable their distribution network operators to trial smart grid technologies within an appropriately incentivised mechanism within their regulatory investment framework. Recommendation 11 In light of the projected growth in rooftop solar PV for both residential and business customers in Australia, the COAG Energy Council should direct the AEMC to consult with stakeholders to identify the least cost approach to managing high levels of rooftop solar PV penetration in Australia. Recommendation 12 In light of the potential gap between network benefits which could be achieved by FDIR technologies and the cap on incentives under the current distribution Service Target Performance Incentive Scheme (STPIS), the AER should investigate whether the current scheme is an economically efficient means of delivery the potential net economic benefits of these technologies highlighted by this assessment. Recommendation 13 Distribution network businesses should consider where FDIR technologies could provide the best opportunities for improvements to SAIDI in urban and short rural networks, or deliver current SAIDI requirements at a lower cost, and target the deployment of these technologies to achieve optimal reliability outcomes. Recommendation 14 Further investigations should be undertaken by network operators to determine whether FDIR technologies could deliver higher net benefit network monitoring in place of lower cost SFM technologies Recommendation 15 Network operators should investigate the potential benefits which could be achieved from the deployment of AVVC technologies in areas of their networks where there are power factor, capacity or voltage constraints. This may include a comparison of the existing costs to remedy power factor, capacity or voltage constraints and the alternative costs of deploying AVVC in these locations. 88 National Cost Benefit Assessment: Executive Report ARUP

91 Recommendation Category Need for interoperability standards Consumer education and industry training Further investigations Recommendation Recommendation 16 The COAG Energy Council should ensure that the minimum guidelines for smart meter functionality currently being developed by AEMO is sufficiently contemporised to enable network operators, retailers and third-party providers of smart metering services to cost effectively access relevant data in order to derive the full benefits of smart meters Recommendation 17 Standards Australia should incorporate demand response capabilities within the Australian Standard AS for electric vehicle charging to ensure electric vehicle charging points installed today will be compatible with managed charging schemes in the future. Recommendation 18 To ensure that smart grid technologies are cost effectively deployed and utilised, network businesses should develop new standard operating procedures for the optimal deployment and safe operation of smart grid devices and systems in the network. Recommendation 19 Industry peak bodies and Smart Grid Australia should consider the most effective ways to improve information sharing and knowledge transfer pertaining to smart grid technologies and their application in the Australian context. Recommendation 20 The Smart Grid, Smart City Customer Application network and retail trials did not assess consumers willingness to accept lower levels of reliability (i.e. accept a greater number and / or longer outages) in exchange for lower prices. This may be an area of additional research that the AEMC or AEMO could undertake in determining the value of customer reliability. Recommendation 21 If smart inverters can be shown to be cost effective in delivering voltage control and power quality benefits, consideration should be given to increasing the minimum standards for existing inverters in Australia. In this way some of the costs of network remediation caused by increasing numbers of rooftop solar PV could be better managed. This work should involve network operators, standards bodies and industry peak bodies. Recommendation 22 There will be significant capital investment required to deploy FDIR technologies nationally. Given the strong potential for national net economic benefits suggested by this assessment, AEMO s 2012 value of customer reliability and its methodology used to calculate these values should be updated. When an updated series of figures for the value of customer reliability are available, the business case for deploying FDIR technologies nationally in urban and short rural networks should be re-evaluated. National Cost Benefit Assessment: Executive Report ARUP 89

92 Recommendation Category Further investigations Recommendation Recommendation 23 As with FDIR technologies, there is a significant capital investment required to deploy SFM network monitoring technologies nationally relative to the benefits. Before this investment occurs, AEMO s 2012 value of customer reliability and the methodology used to calculate these values should be updated. When an updated series of figures for the value of customer reliability are available, network operators should investigate whether SFM network monitoring devices could be cost effective in CBD and long rural networks. 90 National Cost Benefit Assessment: Executive Report ARUP

93 Table of Acronyms Abbreviation Term 3G/ 4G Third Generation/ Fourth Generation (mobile communications technology) AC ACMA ACT ADMD AEFI AEMC AEMO AER AMI Alternating Current Australian Communications and Media Authority Australian Capital Territory After Diversity Maximum Demand Arup, Energeia, Frontier Economics, and Institute for Sustainable Futures Consortium Australian Energy Market Commission Australian Energy Market Operator Australian Energy Regulator Advanced Metering Infrastructure ARRA American Recovery and Reinvestment Act 2009 ATO AUD AVVC BAU BEV BIPV BREE CBD CA CAA CAIDI CAIFI CAPEX CBA CBD CCGT CHP CIS COAG COAGEG CO2 CO2-e CPP CPUC CRM Activity Target Outcomes Australian Dollar Active Volt-VAr Control Business As Usual Battery Electric Vehicle Building Integrated Photovoltaics Bureau of Resource and Energy Economics Central Business District Customer Applications Customer Acquisition Application Customer Average Interruption Duration Index Customer Average Interruption Frequency Index Capital Expense Cost Benefit Analysis Central Business District Combined Cycle Gas Turbine Combined Heat and Power Customer Information System Council of Australian Governments Council of Australian Governments Energy Council Carbon Dioxide Carbon Dioxide Equivalents Critical Peak Pricing California Public Utilities Commission Customer Relationship Management National Cost Benefit Assessment: Executive Report ARUP 91

94 Abbreviation CSIRO CVR DC DC 0C DER DERMS DFA DG DLC DM&C DMEGCIS DMS DNMS DNSP DOE DOI DP DPP DPR DRED DRET DS DSP DSM DSR DTS ECA EEIS EGS EMS ENA EPRI ERA ERM ESAA Term Commonwealth Scientific and Industrial Research Organisation Conservation Voltage Reduction Direct Current Distribution Centre Degrees Celsius Distributed Energy Resources Distributed Energy Resource Management System Distribution Feeder Automation Distributed Generation Direct Load Control Distribution Monitoring and Control Demand Management and Embedded Generation Connection Incentive Scheme Distribution Management System Distribution Network Management System Distribution Network Service Provider Department of Energy (United States) Department of Industry Data Priorities Dynamic Peak Pricing Dynamic Peak Rebate Demand Response Enabling Device (former) Department of Resources, Energy and Tourism Distributed Storage Demand Side Participation Demand Side Management Demand Side Response Distributed Temperature Sensing Energy Consumers Australia South Australia Energy Efficiency Improvement Scheme Enhanced Geothermal System Energy Management System Energy Networks Association Electric Power Research Institute Economic Regulation Authority Energy Resource Management Energy Supply Association of Australia 92 National Cost Benefit Assessment: Executive Report ARUP

95 Abbreviation ESB ESS EU EV EVSE FAN FAR FBT FDIR FiT FP7 FTTN FTTP/ FTTH GA GDP GPS GreenPower GSL GST GW GWh HAN HEMS HEV HV HWLC Hz IBT ICE ICH ICT IEA IEC IFI IGCC (black coal) IHD Term Enterprise Service Bus New South Wales Energy Savings Scheme European Union Electric Vehicle Electric Vehicle Supply Equipment Field Area Network Field Area Router Feedback technology Fault Detection, Isolation and Restoration Feed In Tariff 7th Framework Programme Fibre to the Node Fibre-To-The-Premises/ Fibre-To-The-Home Grid Applications Gross Domestic Product Global Positioning System GreenPower Guaranteed Service Level Goods and Services Tax Gigawatt Gigawatt Hours Home Area Network Home Energy Management System Hybrid Electric Vehicle High Voltage Hot Water Load Control Hertz Inclining Block Tariff Internal Combustion Engine Information Clearing House Information & Communication Technology International Energy Agency International Electrotechnical Commission Innovation Funding Incentive Integrated Gasification Combined Cycle Black Coal In Home Display National Cost Benefit Assessment: Executive Report ARUP 93

96 Abbreviation IMO IP IPART IVVC km KPI kv kw kwh LAN LGA LGCs LNG LRMC MAIDI MAIFI Mbps MIC MMP MMR MMS MPLS ms-1 Mt MVA MW NA NBN NEL NEM NER NERR NGGI NGR NIST NMI Term Independent Market Operator Internet Protocol Independent Pricing and Regulation Tribunal Integrated Volt-VAr Control Kilometre Key Performance Indicator Kilovolt Kilowatt Kilowatt Hour Local Area Network Local Government Area Large-scale Generation Certificates Liquefied Natural Gas Long Run Marginal Cost Momentary Average Interruption Duration Index Momentary Average Interruption Frequency Index Megabits per second Modelling Inputs Compendium Monitoring and Measurement Plan Monitoring and Measurement Report Meter Management System Multiprotocol Label Switching Meter Per Second Millions of tonnes Millivolt ampre Megawatt Not Applicable National Broadband Network National Electricity Law National Electricity Market National Electricity Rules National Energy Retail Rules National Greenhouse Gas Inventory National Gas Rules National Institute of Standards and Technology National Metering Identifier 94 National Cost Benefit Assessment: Executive Report ARUP

97 Abbreviation NPV NSMP NSW NTD NTNDP NWIS OCGT OECD OEM OPEX PF PHEV PINC Plt PMU PNM PNNL PP PQ PS+EDGE Pst PV QCA R&D REC RET (LRET & SRET) RIT-D RTM RTP RTU SAIDI SAIFI SC (coal) SCADA SCER Term Net Present Value National Smart Metering Program New South Wales Network Termination Device National Transmission Network Development Plan North West Interconnected Systems Open Cycle Gas Turbine Organisation for Economic Co-operation and Development Original Equipment Manufacturer Operating Expense Power Factor Plug in Hybrid Electric Vehicles Platform for Intelligent Network Communications Long Term flicker susceptibility Phasor Measurement Unit Power Network Model Pacific Northwest National Laboratory Policy Priority Power Quality Production System + Extended Data Grid Environment Short Term flicker susceptibility Photovoltaics Queensland Competition Authority Research and Development Renewable Energy Certificate Renewable Energy Target Regulatory Investment Test for Distribution Requirement Traceability Matrix Real Time Pricing Remote Telemetry unit System Average Interruption Duration Index System Average Interruption Frequency Index Supercritical Black Coal/ Supercritical Brown Coal Supervisory Control and Data Acquisition Standing Council on Energy and Resources National Cost Benefit Assessment: Executive Report ARUP 95

98 Abbreviation SFM SFM SGA SGI SGSC SMI SMS SP SRMC STATCOM STC STEM STPIS SUV SWIS TOU/ STOU THD TSO TWh UK UMTS USA USC (coal) USD V V2G VAr VCR VEET WA WAC WAM WAMPAC WAN WEC Term Substation Feeder Monitoring Substation and Feeder Monitoring Smart Grid Australia Smart Grid Initiative Smart Grid, Smart City Smart Metering Infrastructure Short Message Service Stakeholder Priority Short Run Marginal Cost Static VAr Compensation Small-Scale Technology Certificate Short Term Energy Market Service Target Performance Incentive Scheme Suburban (or sport) Utility Vehicle South West Interconnected Systems Time of Use/ Seasonal Time of Use Total Harmonic Distortion Transmission System Operators Terrawatt Hours United Kingdom Universal Mobile Telecommunications System United States of America Ultra-supercritical Black Coal/ Ultra-supercritical Brown Coal United States Dollar Volt Vehicle-to-Grid Volt-Ampere reactive Value of Customer Reliability Victoria Energy Efficiency Target Western Australia Wide Area Control Wide Area Measurement Wide Area Monitoring, Protection And Control Wide Area Network Wholesale Energy Costs 96 National Cost Benefit Assessment: Executive Report ARUP

99 Abbreviation WEM WiMAX WMS WTA WTP xdsl ZigBee Term Wholesale Energy Market Worldwide Interoperability for Microwave Access Work Management System Willingness to Accept Willingness to Pay Digital Subscriber Line Standards based protocol for the network and application layer for wireless network applications National Cost Benefit Assessment: Executive Report ARUP 97

100 Glossary of terms Abbreviation Term Description Third Generation/ 3G telecommunication networks support services that provide an information transfer rate of at least 200 kbit/s. 3G/ 4G Fourth Generation 4G telecommunications networks are the successor to 3G (mobile communications standards. A 4G system provides mobile ultra-broadband technology) Internet access, for example to laptops with USB wireless modems, to smartphones, and to other mobile devices. AC Alternating Current A form of electrical current where the flow of electrical charge reverses periodically. An Australian government statutory authority within the Department of Broadband, Communications and the ACMA Digital Economy (Australia) (DBCDE) portfolio. The ACMA Australian is tasked with ensuring most elements of Australia's media Communications and and communications legislation, related regulations, Media Authority and numerous derived standards and codes of practice operate effectively and efficiently, and in the public interest. ACT The ACT is a territory in the south east of Australia, Australian Capital enclaved within New South Wales. It is the smallest selfgoverning internal territory in Australia. Territory The maximum probable demand in a defined electricity system, taking into account the diversity in individual ADMD After Diversity Maximum consumer electricity consumption patterns. The maximum Demand demand from each consumer will not occur at the same time, and so the coincident maximum peak demand is less than the sum of each consumer's peak demand. Arup, Energeia, Frontier AEFI Economics, and Institute The Project Team undertaking the Smart Grid Smart City for Sustainable Futures Analysis and Reporting Project. Consortium The Australian Energy Market Commission (AEMC) was set up by the Council of Australian Governments through the Ministerial Council on Energy in The AEMC has AEMC two roles in relation to national energy markets - as rule Australian Energy Market maker and as a provider of advice to Ministers on how Commission best to develop energy markets over time. The AEMC actively considers market development when it considers rule change proposals, policy advice and energy market reviews. The Australian national energy market operator and AEMO Australian Energy Market planner. AEMO plays an important role in supporting the Operator industry to deliver a more integrated, secure, and cost effective national energy supply. 98 National Cost Benefit Assessment: Executive Report ARUP

101 Abbreviation Term Description AER The Australian Energy Regulator (AER) is Australia s Australian Energy national energy market regulator and an independent Regulator statutory authority. The meters, communications systems, data collection AMI and management systems and business arrangements Advanced Metering necessary to support smart metering and the contractual Infrastructure and billing arrangements that rely on smart metering. Also known as smart meter infrastructure (SMI). The ARRA 2009, commonly referred to as the Stimulus or the Recovery Act, was an economic stimulus package enacted by the 111th United States Congress in February 2009 and signed into law on February 17, 2009, by ARRA American Recovery and President Barack Obama. The Act included direct Reinvestment Act 2009 spending in infrastructure, education, health, and energy, federal tax incentives, and expansion of unemployment benefits and other social welfare provisions. The approximate cost of the economic stimulus package was estimated to be $787 billion at the time of passage. ATO Activity Target Outcomes A set of outcomes defining the activities the Australian Government expects to be undertaken by Ausgrid to deliver the Smart Grid, Smart City trial results and data and prove or disprove the hypotheses. AUD Australian Dollar Unit of currency in Australia. AVVC Active Volt-VAr Control A smart grid technology which uses equipment to measure and actively control Volt and VAr conditions across a network to minimise electrical losses, manage demand and reduce energy consumption. AVVC was a Smart Grid, Smart City - Grid Applications Project. BAU Business As Usual The normal execution of standard functional operations within an organisation - which forms a baseline comparator for projects or programs which might introduce change. BEV Battery Electric Vehicle A vehicle that is powered by electric motors, using electricity stored in batteries. BIPV Photovoltaic materials that are used to replace Building Integrated conventional building materials in parts of the building Photovoltaics envelope such as the roof, skylights or facades. BREE Bureau of Resource and BREE is part of the Australian Government Department of Energy Economics Industry and operates as an economic research unit. CBD Central Business District The CBD is the commercial and often geographic heart of a city. National Cost Benefit Assessment: Executive Report ARUP 99

102 Abbreviation Term Description CA Customer Applications The component of Smart Grid, Smart City project that focused on smart meter based applications that could impact customer behaviour. CAA An ipad and web application designed and built for the Customer Acquisition SGSC Customer Application Program to support the Application acquisition of customers to the relevant trials. A commonly used reliability indicator by electric power CAIDI utilities. The sum of the duration of each sustained Customer Average customer interruption (in minutes), divided by the total Interruption Duration number of sustained customer interruptions (SAIDI Index divided by SAIFI). CAIDI excludes momentary interruptions (one minute or less duration). A commonly used reliability indicator by electric power CAIFI Customer Average Interruption Frequency Index utilities indicating the number of customers affected out of the whole customer base. It is calculated as the total number of customer interruptions, divided by the total number of customers who had at least one interruption. CAPEX Capital Expense Expense incurred when a business buys a new asset or adds to the value of an existing asset. CBA Cost Benefit Analysis A systematic process for calculating and comparing benefits and costs of a project. CBD Central Business District The commercial and often geographic heart of a city. An assembly of gas turbines working together from the same heat source to produce electricity. The exhaust heat of one turbine is used as the heat source for another, CCGT increasing the system's overall efficiency. CCGT plant Combined Cycle Gas capture heat from the exhaust of the gas turbine in a heat Turbine recovery steam generator (HRSG) to produce steam to drive a steam turbine. The capture of waste heat improves the efficiency of the plant, meaning that CCGT use less fuel and produce less carbon emissions than OCGT plant. Cogeneration or combined heat and power (CHP) is the CHP Combined heat and use of a heat engine or power station to simultaneously power generate electricity and useful heat. CHP is also known as a fuel cell. An IT system to manage information related to customers CIS including name, address and interactions. The CIS Customer Information developed for the SGSC Program included a customer System relationship management (CRM) system and a customer acquisition application (CAA). 100 National Cost Benefit Assessment: Executive Report ARUP

103 Abbreviation Term Description The Council of Australian Governments (COAG) is the COAG peak intergovernmental forum in Australia. The role of Council of Australian COAG is to promote policy reforms that are of national Governments significance, or which need coordinated action by all Australian governments. The Council of Australian Governments Energy Council is responsible for pursuing priority issues of national COAGEC Council of Australian Governments Energy Council significance in the energy and resources sectors. It provides the leadership and sets the investigative (reform) agenda throughout Australia. This body was formerly referred to as SCER, Standing Council on Energy and Resources CO2 Carbon Dioxide A naturally occurring chemical compound, and an important greenhouse gas. Carbon dioxide is released through the burning of carbon-based fuels to produce energy (as well as many other natural and anthropogenic processes), and so the reduction of carbon dioxide emissions is a key focus for the energy industry. A measure used to describe how much global warming CO2-e Carbon Dioxide a given type and amount of greenhouse gas may cause, Equivalents using the functionally equivalent amount or concentration of carbon dioxide (CO2) as the reference. CPP Critical Peak Pricing A type of electricity tariff in which very high 'critical peak' prices are assessed for certain hours of certain days where electricity demand is expected to be extremely high (often limited to per year). Prices during critical peaks are significantly higher than the standard rate. Peak time rebates can be used in which customers can get credit for load reduction during critical peaks, but no penalty for increased load. CPUC California Public Utilities A regulatory agency for privately owned public utilities Commission within the State of California. CRM An IT system to store all interactions with a customer. For Customer Relationship the SGSC Program, the CRM was a component of the Management customer information system (CIS). CSIRO Commonwealth Scientific and Industrial Research Organisation Australia's national science and research agency. National Cost Benefit Assessment: Executive Report ARUP 101

104 Abbreviation Term Description The terms consumer and customer have been used throughout the report. The term customer is used when it refers to a person or class of persons generally Consumer / Consumer / customer prescribed by the National Electricity Rules. The customer term consumer is used when the report is generally describing persons who consume electricity, rather than a specific type of customer. Reducing voltage can cause a reduction in power CVR consumed by loads such as households. This can be Conservation Voltage applied on according to a strategy to achieve network Reduction benefits such as delaying the need to construct additional network capacity. DC Direct Current A form of electrical current where the flow of charge is in one direction only. DC Distribution Centre Also known as distribution substations or pole top transformers. 0C Degrees Celsius Celsius, also known as centigrade, is a scale and unit of measurement for temperature. DER DERMS DFA DG DLC DM&C Distributed Energy Resources Distributed Energy Resource Management System Distribution Feeder Automation Distributed Generation Direct Load Control Distribution Monitoring and Control Energy generation (e.g. photovoltaics, fuel cells, wind turbines, generator sets) and storage devices (e.g.: batteries) distributed throughout a distribution network, normally at customer premises but also connected to network operator's low voltage plant. An integrated management system for the control of distributed energy resources with capabilities for dispatch, shutdown, startup and varying input/output. Automatic isolation and reconfiguration of distribution feeders using sensors, controls, switches and communication systems. Distributed generation, also called on-site generation, dispersed generation, embedded generation, decentralized generation, decentralized energy or distributed energy, generates electricity from many small energy sources. Direct load control allows a third party such as a network operator or retailer to have remote access to different customer appliances such as hot water systems, swimming pools, air conditioners (refer to DRED definition) and controllable electric vehicle load. Internal project to deploy RTUs in distribution centres to monitor and control the electricity distribution network. 102 National Cost Benefit Assessment: Executive Report ARUP

105 Abbreviation Term Description DMEGCIS An incentive scheme developed by the AER in order to Demand Management provide funding for DNSPs to implement efficient non and Embedded network alternatives or to manage the expected demand Generation Connection for standard control services in some other way or to Incentive Scheme efficiently connect embedded generators DMS A system which enables network operators to monitor and Distribution Management control in near real time information about the electricity System distribution network. DNMS A system which enables network operators to access Distribution Network near real time information about the electricity distribution Management System network and to control/switch the network remotely. DNSP A business that manages the distribution of electricity Distribution Network through the "poles and wires" network. In NSW, DNSPs Service Provider also own and manage metering infrastructure. DOE The United States DOE is a government department Department of Energy whose mission is to advance energy technology and (United States) promote related innovation in the United States. DOI Department of Industry On 18 September 2013 the Australian Government's Department of Industry portfolio was established. The department includes portfolio areas of energy, resources, science and skills. DP Data Priorities A set of priorities defining, at a high level, the results and/ or benefits the Australian Government expects from each Smart Grid, Smart City application trial. DPP Dynamic Peak Pricing Dynamic pricing is often considered an essential part of demand reduction programs. There are several forms of dynamic pricing including Critical Peak Pricing and Real Time Pricing (refer to definitions in this Glossary). DPR Dynamic Peak Rebate Within the Smart Grid, Smart City trials some customers participated in the trialling of a rebate for reducing electricity use during nominated peak events. DRED A device that enables the remote control of customer Demand Response appliances by a DNSP in response to electricity pricing Enabling Device signals. The (former) Department of Resources, Energy and DRET Tourism provided advice and policy support to the (former) Department of Australian Government regarding Australia's resources, Resources, Energy and energy and tourism sectors. The energy functions of this Tourism department are now the responsibility of the Department of Industry. DS Distributed Storage Storage of electric energy in a decentralised manner such as batteries in many households. National Cost Benefit Assessment: Executive Report ARUP 103

106 Abbreviation Term Description DSP refers to the ability of energy consumers to make decisions regarding the quantity and timing of their DSP Demand Side energy consumption that reflect their value of the supply Participation and delivery of electricity. These decisions include both short-run decisions in response to specific events, and longer-run investment decisions about energy efficiency. DSM refers to the modification of consumer demand DSM for energy through various methods such as financial Demand Side incentives and education. DSM aims to encourage Management consumers to use less energy during peak times, or shift the time of energy use to off-peak times. DSR Demand Side Response A reduction, shift or flattening of energy demand profile occurring through activities undertaken at the point of consumption. DTS Devices which measure temperatures by means of optical Distributed Temperature fibres functioning as linear sensors. Allows high accuracy Sensing of temperature determination over longer distances. The establishment of ECA is a commitment by the COAG Energy Council by no later than 1 January The role of ECA will be to promote the long term interests of consumers of energy with respect to the price, quality, ECA Energy Consumers safety, reliability and security of supply of energy services Australia by providing and enabling strong, coordinated, collegiate evidence based consumer advocacy on national energy market matters of strategic importance or material consequence for energy consumers, in particular for residential and small business customers. EEIS The South Australian scheme which aims to assist South Australia Energy households and businesses to reduce electricity Efficiency Improvement consumption and electricity costs, by creating financial Scheme incentives to invest in energy savings activities. EGS Geothermal EGS power stations, also known as hot dry Enhanced Geothermal rock (HDR) power stations, use heat from the earth s crust System to raise steam and generate electricity. EMS A system of computer-aided tools used by network Energy Management operators to monitor, control and optimise the System performance of an electricity network. The peak national body for Australia s energy networks which provide the vital link between gas and electricity ENA Energy Networks producers and consumers. ENA represents gas Association distribution and electricity network businesses on economic, technical and safety regulation and national energy policy issues. 104 National Cost Benefit Assessment: Executive Report ARUP

107 Abbreviation Term Description EPRI Electric Power Research An institute that conducts research on issues related to Institute the electric power industry in the USA. The ERA in Western Australia is responsible for regulating third party access to electricity infrastructure and ERA Economic Regulation administers licenses for the electricity sector. One of the Authority ERA s primary functions is to observe the behaviour of the WEM in the SWIS to ensure that it is meeting its market objectives. The component of Smart Grid, Smart City project that ERM Energy Resource focuses on distributed energy generation, storage and Management management. This project within the trials was renamed DGDS Project. ESAA Energy Supply The peak industry body representing the stationary Association of Australia energy sector in Australia. ESB Enterprise Service Bus A software architecture model used for designing and implementing the interaction and communication between mutually interacting software applications. The New South Wales scheme which aims to assist ESS New South Wales Energy households and businesses to reduce electricity Savings Scheme consumption and electricity costs, by creating financial incentives to invest in energy savings activities. EU European Union An economic and political union of 28 member states located primarily in Europe. EV Electric Vehicle A vehicle that uses one or more electric or traction motors for propulsion. There are various kinds of EV's which differ in the way their batteries are charged including Hybrid Electric Vehicles (HEV), Plug in Hybrid Electric Vehicle (PHEVs), and Battery Electric Vehicle (BEV). Refer to the respective acronyms in the glossary for full definitions. EVSE Electric Vehicle Supply Infrastructure that supplies electric energy for the Equipment recharging of plug-in electric vehicles. FAN Field Area Network A network enabling communications for the distribution network. FAR Field Area Router Multi-service communication platforms built to use in Field Area Networks. FBT Feedback technology A group of smart grid technologies and a Smart Grid, Smart City - Customer Applications project focusing on evaluating the potential for Smart Meters and other technologies to provide consumers with better quality information that will have a measurable impact on total energy consumption and/or peak demand. National Cost Benefit Assessment: Executive Report ARUP 105

108 Abbreviation Term Description A group of smart grid technologies and a Smart Grid, Smart City - Grid Applications project focusing on capability of an electricity network to discover the FDIR occurrence of a fault, detect the location of that fault, Fault Detection, Isolation isolate the equipment responsible for that fault and then and Restoration deploy resources in a manner that will restore power to as much of the affected area as possible, usually with the assistance of advanced algorithms and remotely controllable switches. FiT Feed In Tariff A policy mechanism designed to accelerate uptake of distributed energy technologies whereby contracts are formed with distributed energy generators (e.g. customers with PV) for excess energy fed into the grid. FP7 The 7th European Union Framework Programme for 7th Framework Research and Technological Development, covering the Programme period 2007 to FTTN Fibre to the Node A form of fiber-optic communication delivery, in which an optical fiber is run to a cabinet serving a neighborhood FTTP/ FTTH A generic term for any communication infrastructure Fibre-To-The-Premises/ which uses fibre-optic cable extending all the way to Fibre-To-The-Home homes and commercial premises. GA Grid Applications A component of the SGSC Program involving a combination of grid side projects trialing smart technologies within Ausgrid's distribution network. Included Active Volt-VAr Control (AVVC), Fault Detection, Isolation and Restoration (FDIR), Substation Feeder Monitoring (SFM) and Wide Area Measurement (WAM). GDP Gross Domestic Product An economic indicator reflecting the strength of a nation's economy. GDP is defined as the market value of all officially recognised goods and services produced within a country within a specified time period. 106 National Cost Benefit Assessment: Executive Report ARUP

109 Abbreviation Term Description GPS Global Positioning System GPS is a system of earth-orbiting satellites, transmitting signals continuously towards the earth, that enables the position of a receiving device on or near the earth's surface to be accurately estimated from the difference in arrival times of the signals. GreenPower GreenPower GreenPower is a government accredited voluntary program that enables Australian energy retailers to purchase renewable energy on behalf of their customers. The participating renewable energy generators generate electricity from sources which produce no net greenhouse gas emissions. GSL Guaranteed Service Level A set performance level under the Service Target Performance Incentive Scheme (STPIS), below which consumers must be compensated. GST Goods and Services Tax Goods and services tax (GST) is a broad-based tax of 10 per cent on most goods, services and other items sold or consumed in Australia. GW Gigawatt Unit of power equal to one thousand million watts. GWh Gigawatt Hours Unit of power equal to one thousand million watt hours or 1000 megawatt hours. HAN Home Area Network A communications network within a customer's dwelling that supports smart meter based feedback technologies, water/gas meters, etc. An appliance control and sub metering system operated within a customer's dwelling. It provides real time HEMS electricity consumption information of appliances via Home Energy smart plugs and wireless connectivity to a router. A Management System HEMS system can provide information to the customer or electricity provider via the Internet (i.e. it does not rely on a smart meter). HEV Hybrid Electric Vehicle A vehicle that is powered by a combination of an internal combustion engine and an electric motor. HV High Voltage Electrical energy at high voltage. HWLC Hot Water Load Control The management of the time of day which power is supplied to domestic hot water systems. Hz Hertz The SI unit fo frequency, equal to one cycle per second. IBT Inclining Block Tariff A type of electricity tariff in which electricity prices are divided in to blocks, based on consumption. Electricity prices charged to the consumer are increased when their overall consumption for the charging period exceeds defined threshold (block) levels. Customers are therefore charged in increasing price increments with increasing consumption. National Cost Benefit Assessment: Executive Report ARUP 107

110 Abbreviation Term Description ICE An engine that his powered by the combustion of a fuel Internal Combustion with an oxidiser. The majority of private vehicles have Engine ICEs. A purpose built web platform designed by Ausgrid to provide the communication mechanism to share the ICH results of the trials after the Smart Grid, Smart City team Information Clearing has been disbanded. There is both an Ausgrid internal House edition as well as a public edition accessed by a web portal The public edition can be found at smartgridsmartcity.com.au/. ICT Information & Technologies that provide access to information through Communication telecommunications. Technology An intergovernmental autonomous organisation which works to ensure reliable, affordable and clean energy IEA International Energy for its 28 member countries and beyond. The IEA's four Agency main areas of focus are: energy security, economic development, environmental awareness, and engagement worldwide. IEC A non-profit, non-governmental international standards International organization that prepares and publishes International Electrotechnical Standards for all electrical, electronic and related Commission technologies. A scheme implemented by the UK government as a IFI mechanism to encourage distribution network operators to Innovation Funding invest in appropriate research and development activities Incentive that focus on the technical aspects of network design, operation and maintenance. IGCC power stations use a gasifier to convert coal to IGCC (black coal) Integrated Gasification Combined Cycle Black Coal syngas, which is then used to power a combined cycle turbine. One of the advantages of IGCC plant is that the technology can readily be used to reduce carbon emissions. IHD In Home Display Devices which display smart meter data (such as electricity demand, consumption and real time pricing information) in the home, providing information to enable consumers to change behaviour. The IMO in Western Australia is an industry-funded IMO Independent Market organisation whose role is to operate and develop the Operator WEM and the Gas Information Services Project (GISP) in Western Australia. IP Internet Protocol The method or protocol by which data is sent from one computer to another on the Internet. 108 National Cost Benefit Assessment: Executive Report ARUP

111 Abbreviation Term Description IPART The independent regulator that determines the maximum Independent Pricing and prices that can be charged for certain retail energy, water Regulation Tribunal and transport services in New South Wales. Control algorithms which gain inputs from multiple Volt- IVVC VAr measurement and control points across the network Integrated Volt-VAr in order to implement control functions (for example, Control to minimise electrical losses, to manage demand or to reduce energy consumption). km Kilometre Unit of measurement (distance) equivalent to one thousand metres. A performance indicator or key performance indicator. KPI KPI is industry jargon for a type of performance measurement. Key Performance KPIs are commonly used by an organisation to evaluate Indicator its success or the success of a particular activity in which it is engaged. kv Kilovolt A unit of electromotive force, equal to one thousand volts. kw Kilowatt Unit of energy equal to one thousand watts. kwh Kilowatt Hour A unit of energy equal to one thousand watt hours. LAN LGA LGCs LNG LRMC MAIDI MAIFI Mbps Local Area Network Local Government Area Large-scale Generation Certificates Liquefied Natural Gas Long Run Marginal Cost Momentary Average Interruption Duration Index Momentary Average Interruption Frequency Index Megabits per second A computer network that links devices within a building or group of adjacent buildings, generally within a radius of less than 1 km. Administrative area that local government holds responsibility for. Large-scale Generation Certificates (LGCs) is an electronic form of currency created by eligible large-scale renewable energy installations sized 100kw or more. Natural gas that has been converted to liquid form for ease of storage or transport. The change in the long-run total cost of producing a good or service resulting from a change in the quantity of output produced. A commonly used reliability indicator by electric power utilities to indicate the average duration of momentary interruptions that a customer would experience during a given period. A commonly used reliability indicator by electric power utilities to indicate the average number of momentary interruptions that a customer would experience during a given period. Megabits per second refers to the data transfer speeds as measured in megabits. This term is commonly used in communications and data technology to demonstrate the speed a which a transfer takes place. National Cost Benefit Assessment: Executive Report ARUP 109

112 Abbreviation Term Description An SGSC document that demonstrates where data and MIC information generated from the Smart Grid, Smart City Modelling Inputs trials have been used either as direct inputs or to validate Compendium and inform the modelling inputs of the national cost benefit assessment. MMP Monitoring and Plan issued by Ausgrid to the Australian Government Measurement Plan outlining the proposed approach to delivering the MMR. Progress reports issued by Ausgrid to the Australian MMR Monitoring and Government after the completion of each six month period Measurement Report in accordance with Item 4 of Schedule 2 in the SGSC Funding Agreement. An IT system that allows a DNSP to remotely manage MMS each smart meter's lifecycle, firmware and security and Meter Management facilitates meter configuration and remote meter reading System of the customer's electricity consumption and any distributed generation. MPLS Multiprotocol Label A standards-approved technology for speeding up Switching network traffic flow and making it easier to manage. ms-1 Meter Per Second Meter per second is an SI derived unit of both speed (scalar) and velocity (vector quantity which specifies both magnitude and a specific direction), defined by distance in meters divided by time in seconds. Mt Millions of tonnes Millions of tonnes (in the context of millions of tonnes of carbon dioxide equivalents Mt CO2-e) MVA Millivolt ampre Milli volt is one thousandth of a volt and milli amp is one thousandth of an amp. MW Megawatt Unit of energy equal to one million watts. NA Not Applicable Abbreviation for not applicable. NBN NEL NEM NER National Broadband Network National Electricity Law National Electricity Market National Electricity Rules The national wholesale-only, open-access data network under development in Australia. Fibre broadband connections are sold to retail service providers, who then sell Internet access and other services to consumers. The framework outlining how the regulatory systems operate within the National Electricity Market. The NEM is a wholesale exchange for electricity for the Commonwealth adjacent areas and those States and Territories that are electrically connected - Queensland, NSW, ACT, Victoria, South Australia and Tasmania. The NER govern the operation of the National Electricity Market (NEM). The Rules have the force of law, and are made under the National Electricity Law (NEL). 110 National Cost Benefit Assessment: Executive Report ARUP

113 Abbreviation Term Description The NERR are primarily focused on the sale and supply of NERR energy to small retail customers, and provide the detailed National Energy Retail content of the consumer protection measures and Rules model contracts that govern the relationships between consumers, retailers and distributors. The compilation of Australia s emissions data, undertaken NGGI centrally by the Department of Climate Change and National Greenhouse Gas Energy Efficiency. The NGGI conforms to international Inventory guidelines adopted by the United Nations Framework Convention on Climate Change. NGR National Gas Rules The NGR govern the operation of the National Gas Market. The Rules have the force of law, and are made under the National Gas Law. NIST National Institute of Standards and Technology The USA National Institute of Standards and Technology has a goal to promote domestic innovation and competitiveness by advancing measurement science, standards, and technology in ways that enhance economic security and improve quality of life. NMI NPV NSMP NSW NTD NTNDP NWIS National Metering Identifier Net Present Value National Smart Metering Program New South Wales Network Termination Device National Transmission Network Development Plan North West Interconnected Systems A unique identifier for each connection point within the National Electricity Market. The value of a future investment or sum of money in present day currency, discounted to reflect inflation and potential investment returns. In June 2008 the then Ministerial Council on Energy confirmed the need to engage industry stakeholders to support the development of a consistent national framework for smart metering in the National Electricity Market. The Australian Energy Market Operator is managing secretariat and contractor arrangements to support this process. The most populated state in Australia. The state in which the Smart Grid, Smart City trials were conducted. A device that connects the customer's data or telephone equipment to a carrier's line that comes into a building or an office. A strategic report developed by AEMO aiming to provide the energy industry with a comprehensive information source to enable dialogue and support the development of nationally efficient transmission planning. NWIS is a separate energy market located on the North West coast of Australia. The grid is physically separated from the other grids located around the country. National Cost Benefit Assessment: Executive Report ARUP 111

114 Abbreviation Term Description OCGT Open Cycle Gas Turbine A form of internal combustion engine that uses gas as a fuel. OCGT power stations consist of a gas turbine. OECD Organisation for Economic Co-operation and Development The OECD is an international economic organisation dedicated to world trade and economic progress. The OECD provides a forum in which governments can work together to share experiences and seek solutions to common problems. An original equipment manufacturer manufactures products or components that are purchased by another OEM Original Equipment company and retailed under that purchasing company's Manufacturer brand name. When referring to automotive parts, OEM designates a replacement part made by the manufacturer of the original part. OPEX Operating Expense Ongoing expense incurred by a business as part of the normal operation and maintenance of an asset. PF Power Factor The power factor of an AC electrical power system is defined as the ratio of the real power flowing to the load to the apparent power in the circuit and is a dimensionless number between 0 and 1. Usually, the higher the number, the more efficient the system. A hybrid vehicle which utilizes rechargeable batteries, or PHEV Plug in Hybrid Electric another energy storage device, that can be restored to full Vehicles charge by connecting a plug to an external electric power source (usually a normal electric wall socket). PINC Platform for Intelligent Network Communications A high-speed fibre-optic telecommunications platform. Lamp flicker occurs when the intensity of the light from a lamp varies due to changes in the magnitude of the supply voltage. This changing intensity can create annoyance to the human eye. The perceptibility of flicker Plt Long term flicker is quantified using a measure called the short-term flicker susceptibility index, Pst, which is normalised to 1.0 to represent the conventional threshold of irritability. The measurement period for Pst is 10 minutes. A derived long-term flicker index, Plt, is the averaged value of Pst over a 2 hour interval (ie 12 x Pst contiguous measurements). PMU Phasor Measurement Unit A phasor measurement unit is a device which measures the electrical waves on an electricity grid, using a common time source for synchronisation. The measurements, also referred to as synchrophasors, are defined in the IEEE C standard. 112 National Cost Benefit Assessment: Executive Report ARUP

115 Abbreviation Term Description PNM Power Network Model The PNM is the Master Data Manager for the electrical network and topology in Ausgrid. The PNM data model is aligned with the standard IEC common information model. PNNL PNNL is is one of the USA s Department of Energy Pacific Northwest National Laboratories, managed by the Department of National Laboratory Energy's Office of Science. PP Policy Priority A set of strategic priorities for energy and energy market development in Australia as identified by the Australian Government s Energy White Paper 2012, and other relevant publications from the AEMC, AER and the Productivity Commission. PQ Power Quality The fitness of electrical power to consumer device. Power quality is defined in terms of continuity of service, variation in voltage magnitude, transient voltages and currents, and harmonic content in the wave forms for AC power. PS+EDGE Production System + Extended Data Grid Environment A method of feeding the production control system as deployed in the Smart Grid, Smart City trials with additional data to test a wider range of scenarios. Lamp flicker occurs when the intensity of the light from a lamp varies due to changes in the magnitude of the supply voltage. This changing intensity can create Pst Short term flicker annoyance to the human eye. The perceptibility of flicker susceptibility is quantified using a measure called the short-term flicker index, Pst, which is normalised to 1.0 to represent the conventional threshold of irritability. The measurement period for Pst is 10 minutes. PV Photovoltaics A method of generating electrical power by converting solar radiation into direct current electricity using semiconductors that exhibit the photovoltaic effect. An independent Statutory Authority regulating competition in Queensland. The QCA seeks to provide a recognised QCA Queensland Competition avenue whereby both government and third parties Authority can rely on an independent, objective appraisal of the issues subject to its review. The QCA regulates retail and distribution electricity prices in Queensland. R&D Research and technology/product development activities Research and carried out by business, government and research Development organisations. REC A tradable commodity attached to eligible installations of Renewable Energy renewable energy systems (including solar panels, solar Certificate water heaters and heat pumps). National Cost Benefit Assessment: Executive Report ARUP 113

116 Abbreviation Term Description The Australian Government's renewable energy target. The RET operates as two parts. The Large-scale Renewable Energy Target (LRET) and Small-scale RET (LRET & Renewable Energy Target (SRET). The LRET encourages Renewable Energy Target SRET) the deployment of large-scale renewable energy projects such as wind farms, while the SRET supports the installation of small-scale systems, including solar panels and solar water heaters. RIT-D The RIT-D establishes consistent, clear and efficient Regulatory Investment planning processes for distribution network investments in Test for Distribution the national electricity market. A matrix developed by AEFI to provide a transparent RTM record of the approach undertaken in utilising data Requirement Traceability obtained through literature review, trials and modelling, Matrix to address the key government and industry stakeholder objectives for the Smart Grid, Smart City Project. RTP Real Time Pricing A form of dynamic pricing where the consumer price reflects the retail price of electricity. RTU Remote Telemetry Unit An electronic device that interfaces physical network infrastructure to a distribution control system or SCADA system by transmitting telemetry data. SAIDI System Average Interruption Duration Index A commonly used reliability indicator by electric power utilities to indicate the average outage duration for each customer served. SAIFI System Average Interruption Frequency Index A commonly used reliability indicator by electric power utilities to indicate the average number of interruptions that a customer would experience. Supercritical pulverised coal steam turbines have boilers SC (coal) that operate at higher temperatures and pressures than Supercritical Black Coal/ older subcritical pulverised coal steam turbines. This Supercritical Brown Coal improves the efficiency of these turbines, reducing both fuel use and carbon emissions. SCADA A computerised control system which uses remote Supervisory Control and monitoring and control devices as well as computerised Data Acquisition algorithms, to monitor and control industrial equipment. The Council of Australian Governments' (COAG) Standing Council on Energy and Resources is responsible for SCER pursuing priority issues of national significance in the Standing Council on energy and resources sectors. It provides the leadership Energy and Resources and sets the investigative (reform) agenda throughout Australia. This has now been replaced by the COAG Energy Council. 114 National Cost Benefit Assessment: Executive Report ARUP

117 Abbreviation Term Description A group of smart grid technologies and a Smart Grid, Smart City - Grid Applications project investigating how SFM Substation Feeder communications between substations and back-end Monitoring information technology systems can act as a strategic enabler for the deployment of different monitoring technologies, at a reduced incremental cost. A group of smart grid technologies and a Smart Grid, SFM Substation and Feeder Smart City - Grid Applications Project focusing on Monitoring advanced asset utility asset monitoring in substations and feeder locations. SGA Smart Grid Australia Smart Grid Australia is a non-profit alliance dedicated to an enhanced, modernised electric system. SGI Smart Grid Initiative The section within the Department of Industry responsible for the management of the SGSC Program. SGSC Smart Grid, Smart City A Federal government initiative aiming to demonstrate the societal and economic benefits of smart grids and assist with the identification of barriers to a broader industry adoption across Australia. The meters, communications systems, data collection SMI and management systems and business arrangements Smart Metering necessary to support smart metering and the contractual Infrastructure and billing arrangements that rely on smart metering. Also known as advanced meter infrastructure (AMI). SMS Short Message Service A text messaging service component of phone, web, or mobile communication systems, using standardized communications protocols that allow the exchange of short text messages between fixed line or mobile phone devices. SP Stakeholder Priority A set of priorities defining the results and/or benefits Industry Stakeholders and the public expect from each Smart Grid, Smart City application trial, as identified through stakeholder engagement. SPARK - SPARK is a proprietary model of generator bidding which determines dispatch of generation plant and wholesale electricity prices. For the purpose of the integrated benefits assessment model, SPARK is used to determine wholesale electricity prices for a large number of representative half-hourly demand points in each year. SRMC Short Run Marginal Cost The change in short run total cost for an extremely small change in output. STATCOM Static VAr Compensation Electrical devices which provide fast acting reactive power on high-voltage electricity transmission networks. National Cost Benefit Assessment: Executive Report ARUP 115

118 Abbreviation Term Description STC A tradable commodity attached to eligible installations of Small-Scale Technology small-scale renewable energy systems (including solar Certificate panels, solar water heaters and heat pumps). STEM Short Term Energy Market The STEM in WA is a daily forward market which allows market participants to trade around their bilateral contract position. STEM clearing prices and volumes are published on a daily basis by the Independent Market Operator (IMO). STPIS An incentive scheme administered by the Australian Service Target Energy Regulator to encourage distributors to improve Performance Incentive and maintain service performance for both reliability and Scheme performance. SUV A sport utility vehicle or suburban utility vehicle (SUV) is Suburban (or sport) Utility a vehicle similar to a station wagon or estate car, usually Vehicle equipped with four-wheel drive for on- or off-road ability. SWIS is a separate energy market located on the South SWIS South West West coast of Australia. The grid is physically separated Interconnected Systems from the other grids located around the country. It is the second largest within Australia. A type of electricity tariff in which customers pay different prices at different times of the day. Electricity consumed TOU/ STOU at peak times is charged at a higher rate, and electricity Time of Use/ Seasonal consumed at off-peak times is charged at a lower rate Time of Use than a 'standard' rate. The price schedules is fixed and predefined based on season, day of week and time of day. THD Total Harmonic Distortion A measure of the distortion or deviation from the sinusoidal (electrical) waveform. In electrical power business, a transmission system operator (TSO) is an operator that transmits electrical TSO power from generation plants over the electrical grid to Transmission System regional or local electricity distribution operators. In the Operators European Union, the European Commission formally defines a TSO in Article 10 of the Electricity and Gas Directives of TWh Terrawatt Hours One TWh is equal to one million MWh or one billion kwh (109). UMTS Universal Mobile A 3G networking standard used throughout much of the Telecommunications world as an upgrade to the earlier GSM mobile networks. System 116 National Cost Benefit Assessment: Executive Report ARUP

119 Abbreviation Term Description USC (coal) Ultra-supercritical Black Coal/ Ultra-supercritical Brown Coal Ultra-supercritical pulverised coal steam turbines have boilers that operate at higher temperatures and pressures than both supercritical and subcritical pulverised coal steam turbines. This improves efficiency, reducing both fuel use and carbon emissions. USD United States Dollar Unit of currency in the USA. V Volt The SI (International System of Units) unit of electromotive force the different of electrical potential between two points of a conductor carrying a constant current of one ampere, when the power dissipated between these points is equial to one watt. V2G Vehicle-to-Grid V2G refers to technologies in which plug-in electric vehicles can be used to deliver electricity into the grid, or adjust charging rates in response to grid signals, with the objective of reducing energy demand at peak times. VAr Volt-Ampere reactive A unit of reactive power. The value that electricity consumers place on avoiding service interruptions. The cost of an outage of a given duration to individual electricity consumers varies widely between agricultural, residential, industrial and commercial customers based on their location and other VCR characteristics. These costs depend on the extent to Value of Customer which the typical consumer s activities rely on electricity Reliability and their ability to postpone these activities without cost. Outage costs may either consist of expenses that arise directly as a result of the outage, or else consist of foregone benefits as a result of the outage. There may also be social disruption costs that spread beyond the direct consequences and location of an individual outage. The Victorian scheme which aims to assist households and businesses to reduce electricity consumption and VEET electricity costs, by creating financial incentives to invest Victoria Energy Efficiency in energy savings activities. A recent review of the VEET Target scheme (May 2014) announced that the current scheme will operate under a reduced target of 2.0 million tonnes of GHG emissions savings for WA Western Australia Western Australia is a state occupying the entire western third of Australia. WAC Wide Area Control An extension of Wide Area Measurement (WAM) systems which enable a transmission system to automatically detect issues with transmission system stability and perform remedial actions in an automated manner. National Cost Benefit Assessment: Executive Report ARUP 117

120 Abbreviation Term Description WAM Wide Area Measurement A group of smart grid technologies and a Smart Grid, Smart City - Grid Applications project that uses PMUs to monitor high voltage network stability and associated parameters. A WAM system uses multiple PMU data streams to increase visibility of network conditions. WAMPAC A system which is designed to detect abnormal network Wide Area Monitoring, conditions and take measures to preserve system Protection and Control integrity. WAN Wide Area Network A computer network that links devices across a broad area using private or public communication network transports. WEC Wholesale Energy Costs The WEC is the cost that a retailer would face in purchasing electricity from the wholesale market to supply to its small retail customers (including both residential and small business customers). WEM Wholesale Energy Market The Western Australian WEM operates in the SWIS and aims to facilitate greater competition and private investment and allow generators and wholesale purchasers of electricity (such as retailers) greater flexibility as to how, and whith whom, they sell or procure electricity. WHIRLYGIG WHIRLYGIG is a proprietary long-term investment model which determines the least-cost mix of existing generation plant and new generation plant to meet system demand. For the purpose of the integrated benefits assessment model, WHIRLYGIG is used to determine investment in new generation assets over the entire modelling period. WiMAX Worldwide Interoperability A wireless communications standard providing highspeed data rates. for Microwave Access WTA Willingness to Accept A customer's willingness to accept is a variable used in describing the Value of Customer Reliability. It describes the willingness of the customer to accept more outages to in return receive lower costs. WTP Willingness to Pay A customer's willingness to pay is a variable used in describing the VCR. It describes the willing ness of the customer to pay more to receive less outages. xdsl Digital Subscriber Line A term referring to all types of digital subscriber line communications technologies, the two main categories being asymmetric digital subscriber line (ADSL) and symmetric digital subscriber line (SDSL). ZigBee Standards based protocol for the network and application layer for wireless network applications. 118 National Cost Benefit Assessment: Executive Report ARUP

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