bhj by Ayse Kaya Firat

ESD.10 Introduction to Technology and Policy

Energy Group 1 - Term Project

Smart Metering in CA

date

12/10/08

Kevin J. Huang . Fiona Hughes . Ayse Kaya Firat . Oghenerume Christopher Kragha . Sebastian M. Protenhauer . Na Zhang

EXECUTIVE SUMMARY Since widespread electrification began in the early 20th century, electricity metering has made few significant advances. On-site electromechanical meters record the total electricity consumed, their value is read manually every month, and the customer is charged a flat per kilowatt rate. The advent of digital and wireless technology makes it possible to monitor electricity usage in real- or near real-time and to charge consumers based on the actual production cost of electricity. The general implementation of smart meters allows economic forces to optimize the electricity market, providing benefits to all stakeholders. However, the universal deployment of smart meters presents a formidable infrastructural challenge. The state of California has experienced rapid growth in electricity demand since the 1980s and has plans to use smart metering to slow the growing need for increased production capacity. In 2003 California established a schedule for smart metering implementation, but has been unable to achieve its goals. This report addresses three specific barriers that California must overcome to effectively implement smart metering. Charge to Committee 1. Centralization – California presently has three distinct regulatory agencies and additional municipal and county organizations which comprise a complex energyregulating framework in California. Should California adopt a more centralized regulatory structure or remain as it currently is? 2. Standardization – In the statewide deployment of smart metering, should all meters be technically standardized? What level of technical standardization, if any, should California smart meters adopt? 3. Competing Interests – Smart metering can provide a wide range of benefits, some of which favor consumers and others that favor suppliers. Should the interests of consumers be favored over those of electricity suppliers in the implementation of California smart metering? Methods We use three methods to generate recommendations for Californian smart metering: an effectiveness study of different smart meter technologies, a qualitative overview of cost benefit analyses performed on European smart metering systems, and a case study of the EU regulatory structure and that of two Member States, Italy and Ireland. Summary of Recommendations 1. Centralization • We recommend that California designate a “lead agency” for its smart metering project.

•

The California Public Utilities Commission is the most appropriate choice for this position because it is currently tasked with regulating the utilities and has wellestablished relations with them.

2. Standardization • We propose that California’s regulators require that suppliers meet or exceed technological standards for smart meters which are similar to those proposed by Southern California Edison. • The level of standardization needed for smart meter technology should be set by the regulatory authority according to the present and future structure of the electricity market. • Although all suppliers are using two-way communication, Californian regulatory agencies should emphasize the high value advantages arising from communication from customer to supplier. • Under all circumstances, smart meters should be equipped with a direct display capable of monitoring the instantaneous consumption in addition to an indirect feedback mechanism such as informative billing. 3. Competing Interests • We recommend that smart meter implementation policy should be focused on maximizing consumer benefits, especially during the initial roll-out phase, in order to foster long term behavioral changes. • For maximum benefits, direct and indirect feedback should always be combined and coupled to time-of-use pricing. • The consumer benefits of smart metering should also be emphasized to realize the high economic gain from these benefits. Additionally, they lead to larger societal benefits such as energy efficiency and environmental security.

Contents 1.Introduction and Background ........................................................................................................................................ 3 2.Why smart metering in CA? ............................................................................................................................................. 9

2.1. WHO'S WHO IN CALIFORNIA ELECTRICITY ........................................................... 11 2.1.1. GOVERNMENT AGENCIES .................................................................................... 11 2.1.2. FEDERAL AGENCIES .............................................................................................. 12 2.1.3. MAJOR INVESTOR-OWNED UTILITIES .............................................................. 13 2.2. DEMAND RESPONSE IN CALIFORNIA....................................................................... 14 2.2.1. DEMAND RESPONSE GOALS AND BUDGET ..................................................... 16 2.2.2. STATEWIDE PILOT PROGRAMS .......................................................................... 17 2.3. SMART METERING IN CALIFORNIA .......................................................................... 18 3.Technical Standardization of Smart Metering ....................................................................................................... 22

3.1. THE SMART METER ...................................................................................................... 23 3.2. THE CUSTOMER INTERFACE ...................................................................................... 25 3.3. THE PROVIDER INTERFACE ........................................................................................ 27 3.4. THE COMMUNICATIONS CHANNEL TO PROVIDER .............................................. 28 3.5. COMBINATIONS OF METHODS .................................................................................. 28 LESSONS LEARNED.............................................................................................................. 29 4.Cost Benefit Analysis ........................................................................................................................................................ 32

4.1. SMART METERING COSTS ........................................................................................... 33 4.2. CONSUMER BENEFITS .................................................................................................. 34 4.3. ELECTRICITY SUPPLIER BENEFITS........................................................................... 36 4.4. NETWORK AND METER OPERATOR BENEFITS...................................................... 38 4.5. BENEFITS OF SPECIFIC METER FUNCTIONALITY ................................................. 39 4.6. GENERAL, SYSTEM-WIDE BENEFITS........................................................................ 40 4.7. QUALITATIVE REVIEW OF COST-BENEFIT ANALYSES ....................................... 41 LESSONS LEARNED.............................................................................................................. 47 5.EU Case Studies: Italy and Ireland ............................................................................................................................. 50

5.1. EU SMART METER REGULATORY STRUCTURE .................................................... 51 5.2. RELEVANT EUROPEAN COMMISSION REGULATORY DIRECTIVES ................. 54 5.2.1. EC ELECTRICITY DIRECTIVE (2003/54/EC)........................................................ 54 5.2.2. EC METERING DIRECTIVE (2004/22/EC) ............................................................. 54 1

5.2.3. EC ENERGY SERVICES DIRECTIVE (2006/32/EC) ............................................. 55 5.3. CASE 1: SMART METERING IN ITALY....................................................................... 56 5.3.1. MAJOR POWER COMPANIES ................................................................................ 56 5.3.2. ITALIAN SMART METERING TECHNOLOGY & MARKET MODEL .............. 56 5.3.3. TYPES OF CONSUMERS ......................................................................................... 57 5.3.4. ITALIAN SMART METER REGULATORY STRUCTURE................................... 58 5.3.5. AEEG REGULATORY ORDER No. 235/07 ............................................................ 59 5.3.6. AEEG REGULATORY ORDER No. 348/07 ............................................................ 59 5.4. CASE 2: SMART METERING IN IRELAND ................................................................. 60 5.4.1. MAJOR POWER COMPANIES ................................................................................ 60 5.4.2. IRISH SMART METER DEVELOPMENTS AND MARKET MODEL ................. 60 5.4.3. TYPES OF CUSTOMERS ......................................................................................... 61 5.4.4. IRISH SMART METER REGULATORY STRUCTURE ........................................ 62 5.4.5. CER REGULATORY ORDER No. 04/064 ............................................................... 63 5.4.6. CER REGULATORY ORDER No. 07/085 ............................................................... 63 5.4.7. CER REGULATORY ORDER No. 07/198 ............................................................... 64 LESSONS LEARNED.............................................................................................................. 65 6.Education for Persistent Change: The Behavioral Importance of a Customer‐Oriented Approach 67

LESSONS LEARNED.............................................................................................................. 70 7.Recommendations and Conclusions .......................................................................................................................... 71 ACKNOWLEDGEMENTS ...................................................................................................................................................... 76 APPENDIX ................................................................................................................................................................................. 77 BIBLIOGRAPHY ...................................................................................................................................................................... 81

Section 1

Introduction and Background

Here at the beginning of the 21st century, domestic energy consumption is still measured in an almost arcane way in most households. The aggregate electricity usage of all appliances is measured by an electromechanical meter, which is manually read by service staff that makes a monthly visit to the household. The energy usage data – typically a single number per month – is processed manually by the utility 1 company, resulting in a monthly cumulative bill per household. This situation is displayed in Fig. 1.1.

Fig. 1.1: Situation “zero” – Electricity is measured in an aggregate manner and processed manually.

The current situation is highly undesirable for at least two reasons. First, consumers receive virtually no information about how they use electricity in real time. The cumulative number prohibits feedback on when consumption was high and where potential savings might arise. Second, the price of electricity generation and distribution is actually not constant over time. In fact, it may vary by an order of magnitude. A direct correlation between electricity price and actual consumption time has great benefits for both customers and suppliers. The advantages for customers are nicely captured by the following quotation by Kempton and Layne: ”Consider groceries in a hypothetical store totally without price markings, billed via a monthly statement like 'US$527 for 2362 food units in April'. How could grocery shoppers economize under such a billing regime?” [Kempton and Layne 1999] Suppliers, on the other hand, suffer from the fact that they cannot transfer the actual production costs of electricity to the market. Since the suppliers’ required production capacity is defined by their peak demand 2 , this results in redundant capacities during most of the day, as well as supply insecurities and even a risk of blackouts during peak loads. These risks, as well as the high marginal costs of production during peak hours, could be significantly reduced if consumers 1

We will use supplier, provider, and utility interchangeably. Peak Demand: Peak demand, peak load or on-peak are terms used in energy demand management describing a period in which electrical power is expected to be provided for a certain period at a significantly higher than average supply level. Peak demand fluctuations may occur on daily, monthly, seasonal and yearly cycles. 2

could be motivated to spread their daily energy consumption more evenly over the day, i.e. shift it away from peak hours. As a result of these potential energy savings, monetary savings, and energy security benefits, politicians alongside with suppliers and customers have increasingly engaged in demand response over the past years. 3 A large fraction of demand response options depend essentially on the correlation of electricity prices with time, for which current electromechanical electricity meters are not feasible. This has given rise to the introduction of a new generation of metering technology, so-called “smart meters.” “Smart meters” are a complex, multi-component system of measurement, communication, and display technologies, where the previous electromechanical meter is replaced by a digital metering device as illustrated in Fig. 1.2. The metering device measures the aggregate consumption of the household, but may also measure the consumption of single appliances. The smart meter is connected to a customer interface, which provides feedback to the consumer about his energy use with respect to its time-of-use (TOU). The smart meter is also attached to a supplier interface, through which the data is read out by the supplier. Alternatively, the supplier interface feeds data to the smart meter, including prices, warnings, or even signals to interrupt the electricity supply. This information exchange depends on the existence of dedicated communication channels between the household and the supplier, which may furthermore be mediated by a specialized data collection company or grid operator.

Fig. 1.2: Situation “one” – smart meters comprise a complex, multi-component system with feedback mechanisms to the customer and long-distance communication channels to the supplier

Demand Response: In electricity grids, demand response (DR) refers to dynamic demand mechanisms to manage customer consumption of electricity in response to supply conditions, for example, having electricity customers reduce their consumption at critical times or in response to market prices. Demand response is generally used to refer to mechanisms used to encourage consumers to reduce demand, thereby reducing the peak demand for electricity.

It is evident that these different technology components allow for very different smart meter variants and hence very different types of data. Especially for a large-scale implementation of smart meters, one thus needs to define a certain standard of minimum functional requirements if certain measurement and billing options shall be warranted. Furthermore, standardization is crucial to guarantee interoperability between end-users and different suppliers. It will turn out that the issue of standardization is of particular importance for California, where the customer faces three large and several smaller suppliers. In fact, California is an extremely interesting case study for energy research in many respects. It wasn’t long ago that the word California was virtually synonymous with energy crisis. Increased demand from hot weather, a lack of surplus power, plants undergoing repairs, and inadequate conservation led to rolling brownouts throughout the state. Today, the demand for electricity is still growing very fast, because of the increase in population (which has doubled since 1965) and tendencies toward larger houses and more and bigger appliances. Moreover, the population is moving to the inland areas of the state where the climate is more extreme than along the coast. As a result, peak demand is growing even faster than the overall electricity demand. To address increasing energy needs, California identified a sequence of key actions in Energy Action Plan II, and energy efficiency and demand response are identified as the state’s preferred means of meeting growing energy needs. To achieve its demand response goals, CA needs to install smart metering infrastructure throughout the state. In the summer of 2004, the California Public Utilities Commission (CPUC) ordered its investor-owned utilities to develop business cases for both full and partial deployment of smart metering. All of the utilities have filed proposals for the installation of smart meters. Some of these proposals are approved, while others are still pending. From the numerous political, technical, regulatory, and social barriers to large scale implementation of smart metering in California4 , we have identified three of the most important on which to focus our analysis. •

Should California adopt a more centralized regulatory structure or remain as it currently is? California presently has three distinct regulatory agencies and additional municipal and county organizations which comprise a complex energy-regulating framework in California. A number of them must regularly interact and work together. Would smart meter implementation be more effective or efficient if these authoritative bodies were more centralized?

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What level of technical standardization, if any, should California smart meters adopt? In the statewide deployment of smart metering, should all meters be technically standardized? If so, what minimum functional requirements should all meters adopt?

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Should the interests of consumers be favored over those of electricity suppliers in the implementation of California smart metering?

For a detailed description of these other various barriers to implementation not specifically addressed by our report, refer to Appendix A.

Customers and electricity suppliers have competing interests. For instance, customers prefer to save money on their energy bills while suppliers prefer to maintain the security and integrity of the electricity grid by shifting energy consumption from peak times to non-peak hours. Should California implement a smart metering technology that favors the interests of customers or suppliers? These particular issues were identified because they directly influence the specific smart metering technology that will be deployed throughout California as well as how such a roll out will be implemented. To answer these questions, we study previous smart metering experiences in the European Union. In particular, we assess the effectiveness of different smart metering technologies, analyze cost-benefit studies of smart metering deployment in Europe and study two especially relevant cases from Italy and Ireland. To address the issue of standardization, we introduce in detail the relevant technological components for smart meter systems. We will then refer to canonical effectiveness studies to evaluate the savings potential associated to single components, as well as particular combinations of these components. These findings will be supplemented by sustainability and customer acceptance studies in Chapter 6, which highlight the importance of adherence to specific implementation standards in order to the warrant persistent change of consumption behavior necessary for the success of smart metering. The technological arguments will have to be weighed against economic arguments to be discussed subsequently. To evaluate the economic feasibility of smart metering, we analyze the costs and benefits of the technology using various European studies. We present the primary costs of implementing smart metering on a large scale and the subsequent benefits of this deployment to various stakeholders in a smart metering system â&#x20AC;&#x201C; customers, electricity suppliers, network and meter operators, and society at large. The benefits afforded by smart metering are different for these different parties. For example, customers prefer to have smart meters which enable them to decrease energy consumption and subsequent energy costs, while electricity suppliers want a technology that will induce a shift in peak load energy usage and allow them to perform more of their services remotely. We further categorize these benefits according to the smart meter functionality or technology that enables them. Some benefits arise from one-way AMR-type functionality while others may only be realized via 2-way AMM features. Finally, we study various cost-benefit analyses to draw conclusions regarding why technical standardization is necessary in widespread smart metering deployment, what minimum functional requirements these smart meters should have, and whether the interests of customers should be favored over that of suppliers in smart metering implementation. We also derive recommendations based on a case study of the European Union and two member states, Ireland and Italy. We examine the progress these jurisdictions have made in implementing smart metering in light of their regulatory structure and the nature of their electricity market. The regulatory structure includes the number and size of government agencies regulating electricity and policies that have been adopted affecting the electricity market. The relevant aspects of the market structure include the level of regulation, whether services are bundled or 7

unbundled and the number of companies present in the market. Market regulation concerns how much control the government has over electricity prices, which companies can participate in the market and how much profit those companies can earn. The level of service bundling in a market describes how various electricity services are provided. In a bundled system, a single, vertically integrated company generates, transmits and distributes power. In an unbundled market, power companies compete in a wholesale electricity market while separate electricity supply companies compete to supply power to homes and businesses. Power transmission is typically maintained as a monopoly even in unbundled systems, but is managed by a company that does not participate in the power generation and electricity supply markets. We chose to examine Ireland and Italy because of the rapid progress both countries have made in smart meter deployment. Italy has nearly completed universal domestic smart meter installation while Ireland, similarly to California, is still in the pilot stages but has plans for universal installation.

Section 2

Why smart metering in CA?

We decided to analyze smart metering in CA because of the state’s fast-growing electricity demand and its commitment to energy efficiency and demand response. While little “progress” has yet been made in the widespread installation of smart or advanced meters and the use of more volatile pricing methods for residential customers, no state has taken more dramatic steps than those undertaken or planned in California. Population growth and electricity demand Today more than 37 million people (one in eight Americans) live in California. The state’s population has doubled since 1965, a growth rate faster than that of any other developed region in the world. The state Department of Finance expects California will add another 7 million people in the next dozen years, growing to more than 44 million by 2020 and moving toward 60 million residents by 2050.

Fig. 2.1: (Left) California’s actual and potential inland population increase [California Department of Finance] and (Right) Statewide Annual Electricity Consumption [California Energy Commission]

Demand for electricity is forecasted to grow fast because of the increase in population. Tendencies toward larger houses and more and bigger appliances will also increase expected growth in electricity demand (Figure 2.1, right). Moreover, the peak demand is growing even faster than the overall electricity demand, because the population is moving to the inland areas of the state, where the climate is more extreme than along the coast (Figure 2.1, left). This changes the pattern of energy use. In the summer, inland areas require more air conditioning than coastal areas, increasing peak demand more dramatically. With the pressure of the electricity crisis in 2001, heat storms of 2006 and increasing population growth in drier, hotter inland areas, CA is adopting aggressive efficiency and demand response goals. Achieving these goals is very important, because a significant disruption in the flow of electricity would bring the Californian economy to an abrupt standstill, costing hundreds of millions of dollars to the state as well as to individual commercial and personal enterprises. 10

Since 2003, California’s energy policy has defined a loading order of resource additions to meet the state’s growing electricity needs: first, energy efficiency and demand response; second, renewable energy and distributed generation; and third, clean fossil-fueled sources and infrastructure improvements. In this section, we will first give a brief description of the energy regulatory structure of the state and, then, explain the demand response goals of the state in general. Finally, we’ll focus on current smart metering infrastructure plans, minimum functionality requirements imposed by the government and the specifications of the smart meter being deployed by the utilities.

Fig. 2.2: The increase in peak demand per capita [California Energy Commission]

2.1. WHO'S WHO IN CALIFORNIA ELECTRICITY California’s electricity regulatory structure is very complex. There are four government agencies, three federal agencies and three major utility companies involved in advanced metering infrastructure decisions. 2.1.1. GOVERNMENT AGENCIES I. California State Senate - Committees: Energy, Utilities and Communication Natural Resources and Wildlife Formed by the California Legislature in 1998 to perform three functions: 1. To oversee the Independent System Operator and the Power Exchange; 2. To determine the composition and terms of service and to appoint the members of the governing boards of the Independent System Operator and the Power Exchange; 3. To serve as an appeal board for majority decisions of the Independent System Operator governing board. 11

II. California Energy Commission (CEC) Created in 1975, the California Energy Commission is the state's primary energy policy and planning agency. The Commission has five major responsibilities: 1. Forecasting future energy needs and keeping historical energy data; 2. Siting and licensing power plants; 3. Promoting energy efficiency through appliance and building standards; 4. Assisting energy research and development, supporting renewable energy, and working on energy industry emissions contributing to climate change; 5. Planning for and directing state response to energy emergencies. III. California Independent System Operator (California ISO) California Independent System Operator (California ISO) is charged with managing the flow of electricity along the long-distance, high-voltage power lines that make up the bulk of California's transmission system. The not-for-profit public-benefit corporation assumed the responsibility in March 1998, when California opened its energy markets to competition 5 and the state's investorowned utilities turned their private transmission power lines over to the California ISO to manage. IV. California Public Utilities Commission (CPUC) The CPUC regulates privately owned telecommunications, electric, natural gas, water, railroad, rail transit, and passenger transportation companies. The CPUC is responsible for assuring California utility customers have safe, reliable utility service at reasonable rates, protecting utility customers from fraud, and promoting the health of California's economy. 2.1.2. FEDERAL AGENCIES I. Federal Energy Regulatory Commission (FERC) FERC is an independent regulatory agency within the Department of Energy that regulates the transmission and sale for resale of natural gas in interstate commerce; regulates the transmission of oil by pipeline in interstate commerce; regulates the transmission and wholesale sale of electricity in interstate commerce; licenses and inspects private, municipal and state hydroelectric projects; oversees related environmental matters; and administers accounting and financial reporting regulations and conducts of jurisdictional companies. 5

In 1998, California became one of the first states in the US that restructured its electricity supply industry. It followed the British example of electricity market deregulation, which started in 1990 and had already achieved substantial cost reductions a few years after implementation. Before restructuring, each California utility provided its customers with generation, transmission, distribution, metering and billing of electricity. After restructuring, customers were allowed to choose their electric power supplier. Restricted transmission and distribution facilities were opened to all power generators on a fair and equitable basis and were overseen by a new organization, the Independent System Operator (ISO).

II. Energy Information Administration (EIA) The Energy Information Administration (EIA), created by Congress in 1977, is a statistical agency of the U.S. Department of Energy. Its mission is to provide policy-neutral data, forecasts, and analyses to promote sound policy making, efficient markets, and public understanding regarding energy and its interaction with the economy and the environment. 2.1.3. MAJOR INVESTOR-OWNED UTILITIES Three major utilities provide about 75 percent of all electricity consumed in California: investorowned Pacific Gas and Electric Company (PG&E), Southern California Edison (SCE), and San Diego Gas & Electric (SDG&E). The remaining 25 percent is provided by the publicly owned Los Angeles Department of Water and Power (LADWP) and Sacramento Municipal Utility District (SMUD); three smaller investor-owned utilities (Bear Valley, PacifiCorp, and Sierra-Pacific Power), and 24 municipal utility districts, three rural cooperatives, about 12 irrigation or water districts, and one state and one federal water agency. I. Pacific Gas and Electric Company Pacific Gas and Electric Company, incorporated in California in 1905, is one of the largest combination natural gas and electric utilities in the United States. Based in San Francisco, the company is a subsidiary of PG&E Corporation. There are approximately 20,000 employees who carry out Pacific Gas and Electric Company's primary businessâ&#x20AC;&#x201D;the transmission and delivery of energy. The company provides natural gas and electric service to approximately 15 million people throughout a 70,000-square-mile service area in northern and central California. As the other utilities in the state, PG&E is regulated by the California Public Utilities Commission. II. San Diego Gas & Electric San Diego Gas & Electric (SDG&E) is the utility that provides natural gas and electricity to San Diego County and southern Orange County in southwestern California. It is owned by Sempra Energy, a Fortune 500 energy services holding company that is based in San Diego. SDG&E is a regulated public utility that provides energy service to 3.3 million consumers through 1.3 million electric meters and more than 800,000 natural gas meters in San Diego and southern Orange counties. The utility's area spans 4,100 square miles. III. Southern California Edison 13

Southern California Edison (or SCE Corp), the largest subsidiary of Edison International, is the primary electricity supply company for much of Southern California. Unlike its sister IOUs (PG&E, SDG&E), SCE provides only electricity, not gas. Today, SCE provides daily electricity to 13 million people in 430 cities over an area of 50,000 square miles. They also supply power to commercial and industrial customers, including 5,000 large businesses and 280,000 small ones. However, the Los Angeles Department of Water and Power, SDG&E, Imperial Irrigation District and some smaller municipal utilities take substantial chunks out of its territory. The northern part of the state is generally served by the PG&E. 2.2. DEMAND RESPONSE IN CALIFORNIA A system-wide investment & commitment As California transforms its electric utility distribution network from a system using 1960s technology to modern, intelligent, integrated technologies, there is common agreement among California’s energy policy makers, utilities, independent system operator and other interested parties that demand response should be a key resource option. As early as 2001, California had already rolled-out interval meters for large customers with usage in excess of 200 kW and the placement of those customers on time-of-use tariffs. In 2002, when the investor owned utilities and the large publicly owned utilities were completing the installation of advanced, interval meters for large customers, the California Energy Commission and the California Public Utilities Commission (CPUC) initiated joint rulemaking proceedings on demand response, smart metering, and dynamic pricing. The intent was to extend smart metering infrastructure to all customers and develop associated time-varying and dynamic rates for large customers. Starting in 2003, the investor owned electric utilities were ordered to develop new demand response programs and tariffs for customers as well as expand existing emergency triggered programs. The California Energy Action Plan II (EAP II) placed demand response at the top of the resource procurement loading order with energy efficiency: “EAP II continues the strong support for the loading order – endorsed by Governor Schwarzenegger – that describes the priority sequence for actions to address increasing energy needs. The loading order identifies energy efficiency and demand response as the State’s preferred means of meeting growing energy needs. After cost-effective efficiency and demand response, we rely on renewable sources of power and distributed generation, such as combined heat and power applications. To the extent efficiency, demand response, renewable resources, and distributed generation are unable to satisfy increasing energy and capacity needs, we support clean and efficient fossil-fired generation…” The State’s Energy Action Plan identified twelve key action items with regard to demand response (see below), many of which focus on the installation of smart metering infrastructure and its integration with dynamic pricing programs (including the proposals to adopt smart 14

metering by the large electric utilities, educate Californians about the time-sensitivity of energy use and how they can participate in demand response programs, and incorporate demand response appropriately and consistently into the planning protocols of the California Public Utilities Commission and the California Energy Commission) Smart meters are the central technological element in these action items, which is, among other things, one of the main reasons why we chose to focus our policy studies on California. Demand Response Key Actions in California EAP II 1. Issue decisions on the proposals for statewide installation of advanced metering infrastructure for all small commercial and residential IOU customers by mid-2006 and expedite adoption of concomitant tariffs for any approved meter deployment. 2. Expedite decisions on dynamic pricing tariffs to allow increased participation for summer 2006 for customers with installed advanced metering systems and encourage load shifting that does not result in increases in overall consumption. 3. Identify and adopt new programs and revise current programs as necessary to achieve the goal to meet five percent demand response by 2007 and to make dynamic pricing tariffs available for all customers. 4. Educate Californians about the time sensitivity of energy use and the ways to take advantage of dynamic pricing tariffs and other demand response programs. 5. Create standardized measurement and evaluation mechanisms to ensure that demand response savings are verifiable. 6. Provide that the utilitiesâ&#x20AC;&#x2122; demand response investment opportunities offer returns commensurate with investments in traditional plant. 7. Integrate demand response into retail sellersâ&#x20AC;&#x2122; electricity resource procurement efforts so that these

8. Provide customer access to their energy use information and allow participation in demand response programs, regardless of retail provider. 9. Evaluate and, if appropriate, incorporate demand response technologies such as programmable communicating thermostats into the 2008 building standards. 10. Incorporate demand response appropriately and consistently into the planning protocols of the CPUC, the CEC, and the CAISO. 11. Encourage the integration of demand response programs into a capacity market or other mechanisms.

Key action number 1 requires a coordinated quick action of all involved agencies and the approval of certain smart meter types. It, therefore, refers to regulation and technological standards. As we mentioned earlier, the regulatory structure in CA is very complex, and there are several agencies involved in the decision process. Action number 10 emphasizes the importance of coordination among these agencies, which is one of the most important barriers to smart 15

metering deployment in California. Thus, among other questions, we’ll focus on the importance of centralization in our analysis. 2.2.1. DEMAND RESPONSE GOALS AND BUDGET The demand response goal is set in action number 3 as: “Identify and adopt new programs and revise current programs as necessary to achieve the goal to meet five percent demand response by 2007 and to make dynamic pricing tariffs available for all customers.” This was the first identification of an explicit goal for demand response in California. This goal was further refined and published by the CPUC in a June 2003 Decision as shown in Table 2.1.

Table 2.1: Demand Response Goals (as defined in 2003)

The actual peak reduction from demand response consistently lagged behind the goals, so these goals were substantially revised (see Table 2.2).

Table 2.2: Revised Demand Response Goals

The number of regulatory agencies and the lack of coordination between them is one of the reasons why California was substantially lagging behind its ambitious schedule, which is very adverse to the quick action plan. The EAP II continues to stress the initial five percent target. Demand response budgets are significantly increased as utility achievements have not yet matched the current goal (see Table 2.3). The current budget of $87.4 million per year is more than twice as large as the budget of $35.8 million that was allocated in 2003, and it is expected to increase further [Faruqui, 2007].

Table 2.3: Annual California Demand Response Budgets

One key event that accelerated the demand response movement in California was the heat storm in July 2006. During those days customers participating in demand response programs played a critical role by reducing their energy usage when called upon by the utilities and the California ISO and played a significant role in making it through the tough days. This motivated CPUC to pursue demand response programs that are more aggressive, more successful, and more inventive. 2.2.2. STATEWIDE PILOT PROGRAMS California conducted a Statewide Pricing Pilot (SPP), which was a multi-million dollar study designed to: “Gather specific information about price elasticities and customer preferences, testing the following features: California’s current regulatory, energy, and economic climate; critical peak pricing with and without automated response; preferences of small commercial and residential customers; a variety of electricity usage levels, appliance holdings, and climate zones; and voluntary rates” [George et al. 2006] The SPP began in July 2003 and ran through December of 2004. Roughly 2,500 residential customers participated in the pilot over this time period. Initially, the study received a budget of $12 million dollars for calendar year 2003, but this was incrementally expanded in later years. The duration of SPP was also extended through the summer of 2005 for commercial and industrial customers. The SPP study concluded that customers do respond to price signals and that significant demand response could be achieved through well-designed dynamic pricing strategies and smart meters. The findings of this study provided the evidence necessary to support utilities’ smart metering infrastructure filings.

2.3. SMART METERING IN CALIFORNIA To achieve its demand response goals, CA needs to install smart metering infrastructure throughout the state. To get the most from this infrastructure investment, it is necessary to equip the customer with enabling technologies. Demand response programs and time-of-use pricing are already instituted for large, industrial customers. But new metering and communications infrastructure is needed to extend those programs to the rest of the energy consumers. In the summer of 2004, the California Public Utilities Commission (CPUC) ordered its investor owned utilities to develop business cases for both full and partial deployment of advanced metering (often called smart meters). The commission also provided a policy direction regarding the minimum level of system functionality that should be supported by a smart metering infrastructure for purposes of analyzing full-scale smart meter deployment. According to the ruling, the system analyzed should support the following six functions [CEC, 2005, Implementing Californiaâ&#x20AC;&#x2122;s Loading Order for Electricity Resources]: Minimum smart metering infrastructure system functional requirement criteria a. Collection of usage data at a level of detail (interval data) that supports customer understanding of hourly usage patterns and how those usage patterns relate to energy costs. b. Customer access to personal energy usage data with sufficient flexibility to ensure that changes in customer preference of access frequency do not result in additional advanced metering infrastructure system hardware costs. c. Compatible with applications that utilize collected data to provide customer education and energy management information, customized billing, and support improved complaint resolution. d. Compatible with utility system applications that promote and enhance system operating efficiency and improve service reliability, such as remote meter reading, outage management, reduction of theft and diversion, improved forecasting, workforce management, etc. e. Capable of interfacing with load control communication technology. f. Implementation of the following price responsive tariffs for: (1)

Residential and Small Commercial Customers (200kW) on an opt-out basis: (a)

Two or Three Period Time-of-Use (TOU) rates with ability to change TOU period length;

(b)

Critical Peak Pricing with fixed (day ahead) notification (CPP- F);

(c)

Critical Peak Pricing with variable or hourly notification (CPP-V) rates;

(d)

Flat/inverted tier rates. 18

Smart metering infrastructure project proposals were required to be cost-effective and utilities needed to provide a comprehensive plan for implementing their smart meter projects, deployment and system integration. All of the utilities have filed proposals for the installation of smart meters and associated communication systems throughout their service territories with the California PUC. The scope of Southern California Edison's (SCE) metering solution is to replace 5.3 million electric meters for SCE's residential, commercial and industrial customers (below 200kW in demand) between 2009 and 2012. Pacific Gas and Electric Company (PG&E) proposed to deploy 5.1 million smart meters between 2007 and 2012; and, San Diego Gas & Electric (SDG&E) 1.4 million between 2008 and 2011(Table 2.4).

Table 2.4: California Advanced Metering Infrastructure Deployment Comparison [SCE, SDG&E, SCE proposals to CPUC]

The utilities investigated available smart metering technologies and included which ones they are planning to deploy in their proposals. SCE, in particular, did extensive research on several case studies to select the best smart metering technology that is, also, cost effective. In a press release in June, 2007, Lynda Ziegler, SCE’s senior vice president of customer service said: “When California launched its advanced metering initiative in 2005 we chose a different path, refusing to accept available technologies that lacked adequate customer value and challenging the metering industry to design a completely new, lower-cost, higher customer benefit system. This week we have informed regulators our approach has succeeded. We are ready to deploy the most significant advance in metering technology in a century with projected deployment savings greater than costs.” The other utilities, PG&E and SDG&E, are upgrading their approved smart meter functionalities and deployment plans with respect to SCE’s proposal, as SCE’s proposal is being regarded as the most successful one. SCE proposed to deploy smart metering technology capable of wireless communication with home area networks, giving customers access to energy information and control. The new meter will be able to “talk” to the upcoming generation of smart household

devices, such as communicating thermostats that give customers options for saving energy and money. Features standard in SCE’s system include (SCE, regulatory filings): •

Next-day availability of the previous day’s energy use information in hourly increments via the Internet and near real-time data available through a home area network link built into the meter;

•

Remote service-activation technology allowing customers who are moving to order their new service instantly instead of scheduling a field service representative to do so on-site at a home or business;

•

Open standards-based design and assured compatibility with the next generation of smart thermostats, display devices and properly equipped appliances that will be capable of automatically responding to customer energy usage and cost preferences; and

•

Assurance of long-term remote upgrade compatibility as technology advances are made that benefits customers and reduce their costs.

SCE also announced the vendors selected in its competitive solicitation process for its smart metering infrastructure program, Edison SmartConnect. eMeter will provide the meter data management system that will be the repository of Edison SmartConnect meter and event data to support customer billing, energy information and utility operations. Corix Utilities, will provide meter installation services and IBM will serve as the system integrator for Edison SmartConnect, managing the development and integration for the network management and meter data management systems. Table 2.5 compares advanced metering infrastructure features that PG&E, SDG&E and SCE have proposed. PG&E’s and SDG&E’s proposals have been approved. SCE’s latest proposal is pending. Yet, after SCE’s proposal, the other two utilities also decided to update theirs. CPUC’s approval of these proposals is a direct result of a statewide policy to rely on smart meters and demand response programs to reduce peak load in an attempt to reduce electricity prices and the need to construct expensive new generation facilities.

Table 2.5: California Smart Metering Infrastructure System Comparison [CPUC, Order Adopting Changes to 2007 Utility Demand Response Programs]

Section 3

Technical Standardization of Smart Metering

Smart metering technology includes a variety of potential technology options, facilitating in turn very different types and uses of smart metering data. This multitude of possibilities makes it necessary to start any policy analysis regarding smart meter implementation with an evaluation of the different available smart meter functionalities in order to extract the greatest benefits for the target groups (i.e. consumers or suppliers), to warrant interoperability between consumers and different suppliers, as well as to understand the full implications of such a large-scale alteration to the electricity grid. In particular, this addresses our leading question regarding what the minimum functional requirements or technical standardization should be for smart meter implementation in California. The following section will introduce the relevant technological components. Canonical effectiveness studies will be cited to evaluate the actual savings associated to single components, as well as to illuminate the susceptibility of customers to certain technologies. Recommendations for California will be provided at the end of the section, which will provide a background against which the plans of the three California utility companies are to be assessed. This is of timely importance, as the provider with the most advanced smart metering technology, SCE, is still pending approval to deploy its technology, and the two other major providers, PG&E and SDG&E, have delayed their roll-out for the possibility of adopting the improved technology standard. This somewhat unusual situation highlights the necessity of technological standardization and early communication among all stakeholders about minimum functional requirements. Note that our findings of the current section will have to be balanced by economic arguments provided in a later section. 3.1. THE SMART METER As a starting point, it is helpful to distinguish between the smart meter itself and periphery systems such as its interfaces to customers and providers, data transmission channels and the supplier base [Vasconcelos 2008]. With respect to the metering device itself, the primary decision must be made which variables are actually measured. This decision basically breaks down into two sub-categories: on the one hand, one must decide how temporal information is being used, including for example how often information is updated and stored. California is currently leaning towards hourly update intervals for domestic customers, whereas Italy and Ireland update information every 15 minutes (cf. case studies below). The latter has clear advantages in terms of feedback precision and pattern evaluation, but requires more advanced data processing capacities. In principle, both hourly and quarter-hourly updates allow for realtime consumption display, consumption history and pattern analysis, and TOU pricing; however, the higher frequency represents a significantly more responsive and customer-oriented approach, and makes better use of the most central advantage of smart meters â&#x20AC;&#x201C; temporal correlation of consumption. From a technological point of view, the proposed hourly smart meters of Californiaâ&#x20AC;&#x2122;s suppliers differ only marginally from the business variant with 15-minute update frequency, namely in the storage capacity and the processing effort for the bill. Given the farreaching consequences of this decision, we believe a higher frequency is preferable despite the minimally higher hardware costs.

On the other hand, one must determine how many and which channels are actually measured. In particular, the decision must be made whether to measure only total consumption (aggregated metering), or single appliances and circuits (disaggregated metering, cf. Box 3.1). These two central technology decisions influence a wide range of associated technological issues, e.g. the required data storage and processing capacity, the display and interface requirements, the capacity of data processing, or communication bandwidth, some of which will be addressed below. Furthermore, there has been an ongoing debate about whether smart meters should be able to measure several ports of incoming electricity to allow for microgeneration as part of a more comprehensive smart grid [Vasconcelos 2008]. We believe that micro-generation and smart-grid options are currently not widespread enough to justify such a costly technical addendum. However, we recommend a separate study to evaluate their feasibility.

BOX 3.1 Effectiveness study: Disaggregated metering

•

Disaggregated metering and feedback provides information about the consumption of single appliances as opposed to the overall consumption. A major trial involved 1000 Norwegian households, which were given a pie-chart on their energy bill showing the breakdown of six main domestic end-uses [Harrigan 1995, Darby 2006]. 81% of of the test households considered this useful, and 38% claimed to have learned something new from it.

•

In principle, both instantaneous displays and indirect feedback such as informative billing (cf. below) can be used to give disaggregated information. Real-time disaggregated feedback, however, is relatively expensive and complicated to supply. Portable outlet monitors serve same function and costs about $30 per plug. Alternatively, direct displays (cf. below) show the customer immediately what happens to the consumption when they switch on the kettle or the central heating pump. Given these viable alternatives, we recommend to not make disaggregated feedback a mandatory feature.

BOX 3.2 Effectiveness study: Direct display and separate monitors

•

The existence of direct displays is commonly considered inevitable for the success of smart metering. Savings of ~ 10% are reported even for simple displays, showing instantaneous electricity consumption together with the current cost per hour [Mountain 2006].

•

Higher savings can be expected from more advanced displays, including TV or interactive web-pages. In a Japan trial, a complex interactive online display providing consumption history, daily and 10-daily costs, living room temperatures and comparisons with other homes, reached 18% electricity savings over the nine-month period for 10 test households [Ueno 2005]. However, the estimated costs of $5000 per unit prove prohibit a large-scale installation.

•

There are several arguments against direct display via TV or internet: “While [direct] online billing can provide a useful interactive feedback service and can incorporate analysis and advice, it is unlikely to be an adequate substitute for a direct display. Ideally, every household needs to be able to see what is happening to consumption without having to switch on an optional feedback service.” [Darby 2006]

BOX 3.3 Effectiveness study: Ambient displays

•

Ambient displays do not show text or numbers, but give simple alarm signals when something relevant has changed or is about change [Mountain 2006]. Though extremely simple, ambient displays can serve as efficient reminders. Successful trials include the “energy orbs” to monitor the current tariff regime and to announce changes via color changes [Martinez and Geltz 2005]. The orb started to flash two hours before a ‘critical peak’ and successfully contributed to peak load-shifting and energy saving. In another trial, the ambient display signaled to turn off the AC as soon as the outdoor temperature had dropped below 68°F, which resulted in savings of 16% over a three-week period [Seligman 1979]. Ambient displays are thus a weaker variant of automated switches in a smart grid.

3.2. THE CUSTOMER INTERFACE Besides the actual smart meter device itself, the two most immediate devices that need to be considered in terms of technological layout are the interfaces to the customer and to the provider. The interface to the customer can be realized either by centralized monitor, typically attached directly to the smart meter, or alternatively through remote or “clip-on” displays, which can be located anywhere in the house. The latter are often preferable as electricity meters are often located at non-central or inaccessible places in the house, which prevents effective direct display (cf. Box 3.2). Both of these options are considered “direct displays.” Direct displays give customers the possibility to closely monitor their instantaneous consumption and gain information about specific BOX 3.4 events (e.g. of abnormally high Effectiveness study: Pre-paid / pay-as-you-go meters consumption or changes when switching on a certain appliance). • Actual energy savings via pre-paid systems are marginal Direct displays may vary greatly in (~3%). Pre-paid meter benefits come mostly through the fact suppliers minimize the risk of debt accumulation. Especially terms of data presentation, using low-income / high risk households may thus obtain better e.g. alpha-numeric displays, control over their consumption. Pre-paid meters have become graphical displays, or simple audiovery popular in Northern Ireland, where suppliers offered a 2% price discount as an incentive to switch to key-pad meters. visual signals for certain events About 25% of the households currently use keypad meters such as peak-consumption and price [Owen and Ward, 2006]. One study showed that over 80% of warnings – so-called “ambient electricity customers wished to continue with this method of payment even if it was more expensive than payment in displays” (cf. Box 3.3). Direct arrears [Waddams Price 2001]. displays may furthermore include information about current and future • Another large-scale implementation took place in Ontario, Canada, where in some local town areas smart meters with tariffs, consumption history, and pre-paid capacity were installed in 25% of the households. The certain processed information such supplier, Woodstock Hydro, claims savings for customers to be a translation of kWh into USD or 15- 20%, mostly due to increased awareness of consumption [Woodstock Hydro 2004]. The observed difference to the UK is CO2 emissions. questionable, but may be due to differences in what is displayed to customers [Darby 2006].

Customer interfaces may also incorporate pre-payment options. Pre-paid electricity meters represent the crudest “smart” feedback technique and are based on the assumption that information alone might not change individual behavior towards saving (cf. Box 3.4). They function similarly to other pre-paid systems such as cell phones. Test series and large-scale installations have been carried out primarily in the UK with so-called “key-pad meters”, where customers need to buy a new pre-paid card from which they enter a 20-digit PIN number in the meter keypad once electricity credit is used up. Key-pad meters are ‘semi-smart’ in that they allow transfer of information such as tariff-changes through the PIN. However, pre-paid options are useful only when electricity costs represent a large fraction of a household’s subsistence, which is not the case for the majority of the Californian households. We therefore conclude that pre-payment should not be a mandatory feature. As we see will below, smart meters also provide more sophisticated improved means for the supplier to address high-risk customers. Feedback to the customer can also be given as indirect feedback, most notably using the option of informative billing. Current aggregate bills provide generally highly inefficient feedback: “A utility bill is a form of feedback in which the feedback loop is too far removed from the use of inputs to have any information value” [Gaskell 1982]. However, this notion has changed considerably with the availability of smart meter technology, where bills can be adapted to effectively to reveal both small-scale consumption patterns as well as broad trends in consumption behavior (cf. Box 3.5). Informative billing may include regular graphic representation of the data and historic data (previous month, previous year) and is particularly efficient when aiming at comparative information, both temporal (previous weeks, months, or year) and referential (“average households”). Temporal comparison allows customers to identify major changes (e.g. a new person moving into the household, the acquisition of a new appliance, or the installation of energy saving measures). Reference comparison matches the household with a representative comparison group and may include data on how consumption is typically distributed between end-uses in an average home [Wilhite 1999; Kempton 1995]. We highly recommend the adoption of informative billing practices for all three California utilities. This notion will be further supported by arguments from a later section concerning customer education. BOX 3.5 Effectiveness study: Indirect feedback and informative billing •

Studies show that there is an inherent distrust referential comparative feedback, as customers are generally suspicious about the validity of their comparison group [Roberts 2004].

•

In a Norway study [Wilhite 1995], informative bills were provided for periods of 60 days, which resulted in savings of up to 12% (averaging 10% for customers of Oslo Energi) as well as a high persistence of savings over several years. The average rose to 12% when the bills were supplemented by comparisons to the same period of the previous year and all periods in between. 79% of customers showed an interest in continuing with the new billing system, which eventually resulted in a policy act to make informative billing mandatory.

•

A second Norwegian study [Wilhite 1997] involved Stavanger customers regularly reading their electricity meters themselves and sending the readings to the utility supplier. Due to this active engagement, the households were found to use 8% less electricity consumption in comparison to households receiving quarterly bills. Additional help was provided to understand new informative energy bills by a well-designed brochure. The effects proved sustainable for a period of 3 years, and the consumer response to this project was very positive

3.3. THE PROVIDER INTERFACE The counterpart of the smart meter interface to the customer is the interface to the provider. The provider interface demarcates the two basic designs of smart meters, the Automated Meter Reading type and the Automated Meter Management type, which require different technological considerations. Automated Meter Reading (AMR) refers to the information channel from the customer to the supplier, which allows for the highly efficient and detailed meter read-outs mentioned above. There seems to be general consensus in the survey literature that the greatest benefits for the provider arise from remote reading [Darby 2006, Vasconcelos 2008, MacDonald 2007]. AMR also enables, to a limited extent, individualized contract arrangements and TOU pricing. As of today, most smart meters are limited to AMR capability. A more detailed appraisal of the AMR advantages will follow in a following section regarding the economics of smart metering costs and benefits. On the other hand, Automated Meter Management (AMM) introduces a second communication channel from the supplier to the BOX 3.6 household, which opens a whole new Effectiveness study: TOU pricing (in a nutshell) dimension of “smart” interactions. In particular, it allows for real-time cost • Studies show that the collective effects induced by TOU allocation and hence advanced TOU pricing might reduce the peak load as much as 27%. However, domestic customers are generally not too pricing options on a (sub-)hourly basis, enthusiastic about complex pricing schemes which force as well as other types of signaling from them to pay much more attention and make them subject the supplier to the customer, potentially to strong price fluctuations on short term notice, as they fear that the costs and risks of utility are transferred onto including remote disconnection of users them [IEA-DSM 2005, Barbose 2004]. There is also a in case of grid emergencies or after danger that TOU pricing would penalize low-income accumulation of debt. households for which it is more difficult to alter their consumption patterns.

Both AMR and AMM technology is most effective in combination with differentiated TOU pricing schemes. However, an extensive study of electricity pricing is beyond the scope of the current work and shall hence be touched upon only briefly here. TOU pricing and related forms such as criticalpeak pricing (i.e. special tariffs restricted to critical times when the supplier anticipates a shortage) and real-time pricing (permanent pricing updates) allow suppliers to transfer the real marginal production costs of electricity to customers, who in turn might adapt their behavior accordingly and economize in the market situation. Therefore, TOU

BOX 3.7 Effectiveness study: AMR readouts and communication

•

One of the major economic benefits of SM technology derives from the possibility of remote data read-out in the AMR setup. Most currently installed AMR meters employ short distance, low-power unlicensed radio-frequency technology to allow readings to be transmitted from the meter to a drive-by vehicle when this vehicle comes within range of the meter. Even with this comparably simple technology, it is possible to raise the number read-outs per day from a previous ~300 read-outs accomplished by a service staff accessing every single household, to about 10,000.

•

Despite the advantages in this simple setup, permanent broadband communication via phone, internet or PLC seem highly preferable from a technological point of view, especially when considering a possible expansion to AMM technology and advanced TOU pricing.

schemes play a particularly important role for a certain set of economy-rooted objectives such as peak load shifting (cf. Box 3.6 and Section 4). TOU schemes are of great interest to areas with summer and winter peaks in demand allied with supply constraints, such as California, Ontario, the northeastern states of the USA and parts of Australia. All three California suppliers plan to engage in TOU pricing, as required by the California Action Plan (cf. Section 2). 3.4. THE COMMUNICATIONS CHANNEL TO PROVIDER Finally, both the AMR and AMM technology rely on the existence of dedicated channels of communication between the smart meter interface and the provider. These channels can be realized by means of different technologies (cf. Box. 3.7). Current smart meter systems include power line carrier (PLC) communication, landline or mobile phone technology, internet, and radio-frequency (RF) transmission. The three utility companies in California utilize different techniques with emphasis on RF technology. This is somewhat surprising, as RF represents the least advanced technology option, at least in a non-integrated form (The pending roll-out plan for SCE includes the integration of smart meters into a grid.). We believe that the use of RF transponders does not represent a sufficiently sustainable choice. In particular when an expansion from AMR to AMM operation shall not be excluded, permanent broadband technology via phone, internet, or PLC should be preferred. We recommend that PG&E, SDG&E, and SCE asses the feasibility of different transmission techniques and consider switching to phone, internet, or PLC communications technology during the delayed rollout, or to integrate RF-based smart meters into a larger mesh. Note that this recommendation goes beyond the current plans of all three utilities. 3.5. COMBINATIONS OF METHODS In conclusion, the above sections have identified three main technologies that enable feedback for demand response control via smart meter technology: direct feedback, indirect feedback and TOU pricing. These three sources can be combined to mutually enforce each other. Presupposing that smart meter technology is implemented with appropriate TOU pricing schemes, the total saving figures can be expected to reach 18% for direct feedback, and 12% for indirect feedback [Darby 2006]. Although these figures are certainly not fully additive (i.e. both saving effects are part parasitic of each other), the overall energy savings resulting from a customer-oriented implementation of smart meters as a combination of direct and indirect feedback may well exceed 20%. The single technological components associated to smart metering technology are summarized in Fig. 3.1. A set of recommendations for California follows below.

Fig. 3.1: Detailed overview of smart meter technology options to be considered for standardization

LESSONS LEARNED Smart metering technology includes a variety of potential technology options. It is therefore important to evaluate the effectiveness of different technology options and to define a feasible minimum technological standard for smart metering. Such standards are crucial for warranting interoperability between different suppliers, and to construct a sustainable smart electricity 29

system. This is reflected in the deadlocked implementation plans among the three suppliers in California. To address our leading question regarding what minimum level of technical standardization California smart meters should adopt, we propose that California’s suppliers adhere to or consider the following technological standards for smart meters or consider upgrading to them during the current roll-out break: •

Smart meters should in principle be capable of two-way communication between the meterprovider interface and the network operator (AMM technology). This is fulfilled by all three suppliers in California. The specific weight between the use of AMM and AMR functions is subject to the supplier and may depend on individual contract arrangements. An economic analysis of AMR and AMM functionality will follow in a coming section and will make specific recommendations regarding what relative weight should be given to each technology. The communication system should preferably be realized via phone technology, PLC or internet as opposed to RF technology, if the latter is not integrated in a mesh. This implies that in particular PG&E and SDG&E should use the roll-out break to consider moving away from RF technology.

•

Smart meters should be equipped with a direct display capable of monitoring the instantaneous consumption. Furthermore, they should update and store information in intervals of 15 minutes (as is the case for our case studies below). California’s suppliers currently plan hourly updates for domestic smart meters, which we consider inefficient given the minimum additional hardware costs. The direct displays should be capable of giving information about the previous 24 hours plus certain types of averaged information for the past week and month, which is currently not planned in California, as all three providers refer the customer to internet pages. We believe that a more direct feedback approach would be beneficial, which could be realized with permanent broadband communication standards. Smart meter data storage and processing capacities should be adapted to the update rate and display capacities and should altogether be sufficient to warrant the storage of a 3-month data set. Moreover, the architecture of each smart metering system should include sufficient redundancy to ensure the integrity of data collection and adherence to performance specifications.

•

If the smart meter is located in non-central, inaccessible place, an additional remote monitor should be provided to preserve the high savings potential of direct displays.

•

We recommend that smart meters include a (non-mandatory) upgrade option for disaggregated metering of single appliances and pre-payment capacities. These options should be part of individual contract arrangements. Due to the still relatively rare occurrence of micro-generation facilities in private households, California should refrain from costly smart meter micro-generation interfaces for large-scale implementation schemes at the present point.

•

In order to achieve optimum efficiency for customers, direct feedback must be supported by indirect feedback in the form of informative billing. California should incorporate informative billing specifically in their Energy Action Plan, for example as an amendment to sub-point 8 (cf. previous section). The information should be provided monthly in a simple, graphical manner and contain temporal comparative values (previous month / year). 30

â&#x20AC;˘

Smart metering technologies are most effective in combination with the financial incentives created through TOU pricing. We highly recommend that suppliers provide adequate, flexible, and individualized pricing schemes. Pricing changes must be announced with 24 hours advance notice. To our best knowledge, Californiaâ&#x20AC;&#x2122;s utility companies plan to meet this requirement.

Section 4

Cost Benefit Analysis

To further inform our assessment of what particular technical functionality Californiaâ&#x20AC;&#x2122;s smart metering system should adopt, we analyze the economics of the likely costs and benefits of smart metering. This section presents an overview of these numerous costs and benefits as well as a qualitative analysis of various cost-benefit studies from the European Union. Included in this overview is a breakdown of which benefits are attributed to which stakeholders in a smart metering system, which benefits are attributed to which smart metering functions, as well as cost-benefit ratios and net present values for the outlined costs and benefits of smart metering. From an economic analysis of these costs, benefits, and previous studies, we draw conclusions regarding why technical standardization of smart meters is necessary, what minimum level of functionality California smart meters should include, and why California should work to realize the consumer benefits of smart metering in their implementation scenario. These conclusions allow us to make recommendations regarding two of our leading questions: what level of standardization should California smart meters adopt and whose interests, customers or suppliers, should be favored in smart meter deployment? 4.1. SMART METERING COSTS There are a wide variety of costs associated with the installation and use of smart meters, which differ largely with the particular technology implemented. The following is a qualitative overview of these expenses. A detailed quantitative review is difficult due to the variance of different cost elements with jurisdiction. 1. Hardware and Installation A significant fraction of the cost of implementing smart metering includes the unit and installation costs of the actual smart meter hardware and real-time display as well as installation and contract fees for the employed communications technology and service. Generally speaking, landline and wireless broadband connections are the most expensive, followed by public-switched telephone network, the various wireless technologies such as 3G and GSM (global system for mobile communications), and finally power line communication. Installation costs will likely vary by jurisdiction due to differences in geography, customer density and type, and labor costs. Additionally, costs of this type are also influenced by how fast and how broadly smart meters are to be installed in a given jurisdiction. Hardware capital costs and fees for installation comprise the largest fraction of the total system cost with installation costing about half as much as the meter and communications hardware. Finally, the hardware cost of an indoor customer display remotely connected to the smart meter can be as much as 1.5 times the installation cost. 2. Stranded Assets/Costs If smart metering technology is deployed before the total costs of the current metering technology are amortized, a cost is associated with the lost income that will not be 33

recovered from the remaining economic life of the current metering system. These stranded assets are higher the earlier that this technological replacement occurs. This can be as high as half the installation cost. 3. Operation and Maintenance (O&M) Because smart metering technology is inherently more complex than existing meters, costs associated with their upkeep are higher than those for current technology. For instance, to ensure accuracy, electronic meters need to be tested more frequently than current electromechanical meters. One significant contributing factor to this higher O&M cost is the operation and maintenance of the smart metering communications system. For example, data storage, management, and presentation to the customer will be significant parts of the O&M costs. These expenses increase with the frequency at which meter data is read by the electrical supplier or sent to the customer. Total O&M costs can be as much as a third of the installation costs. 4. Old Meter Removal and Disposal The safe removal and disposal of current electrical meters when they are replaced by smart meters adds another cost. This cost is expected to increase for meter hardware that contains potentially hazardous materials. 5. Data Infrastructure and Systems There is an initial system setup cost at the electric utility for the infrastructure and equipment to store, manage, and transmit all of the data being gathered by the smart meters. This is another significant cost that can be nearly as high as the installation costs of the smart meters themselves. 4.2. CONSUMER BENEFITS The implementation of smart metering could have a wide range of possible, very valuable benefits for the involved stakeholders â&#x20AC;&#x201C; consumers, network and meter operators, electricity suppliers, and the public at large. The specific benefits for consumers include: 1. Energy and Cost Savings Conventional wisdom maintains that given real- or near real-time information regarding their energy consumption and its associated cost, consumers will decrease their energy usage to decrease their bills. The extent of this conservation, however, is not clear, as it is likely influenced by socio-economic status, the presentation of the data, availability of supporting advice and energy management tools, and whether smart meter implementation was mandatory or voluntary. Additional considerations when calculating the total saved energy are the increased amount of energy consumed by smart meters relative to current electromechanical meters as well as how people spend the money they save from increased energy conservation. 34

The total energy savings are closely related to individual energy savings. Presupposing that smart metering technology can be effectively and sustainably implemented for much of the population, the total savings can be expected to reach 3-18% for direct feedback, and 12% for indirect feedback. Following the arguments about combinations of several feedback techniques, the expected overall energy savings can be as high as 20% for customer-oriented, multi-layer implementation of smart metering and related feedback mechanisms [Darby 2006]. Perhaps of greater interest to consumers is the resulting cost savings when peak energy consumption is reduced. When TOU tariffs are applied, this is particularly relevant for very price-sensitive electricity consumers who can use smart metering and TOU tariffs to significantly reduce their energy costs. 2. Service Quality Smart metering has the potential to significantly enhance the consumer experience when dealing with the electricity supplier. For instance, consumer aggravation with inaccurate aggregate or estimated billing, time waiting for meter readers to arrive, and lack of readily available account and usage information can all be mitigated through smart metering. The inherent real- or near real-time usage information can be remotely read by the supplier and used for much more accurate billing that reflects the true price and amount of electricity used by the consumer at given points in time. Additionally, such usage and billing information is easily made available online to the consumer, subsequently reducing telephone inquiries to utility call centers. As a result of the wide availability of consumer usage information, privacy concerns may also arise. 3. Increased Supplier Competition Consumers will also benefit from an increase in competition amongst electricity suppliers. Using the detailed usage information and patterns gathered by smart meters, suppliers can offer pricing schemes and customized service packages targeted to specific consumers, competitive plans that customers can then choose between. Furthermore, this supplier competition is encouraged by the ease with which customers can change suppliers and compare competing supplier offers via their smart meters. Such increased supplier competition can decrease overall electricity costs as well as provide customers will service plans more suited to their individual energy consumption patterns. 4. Domotic Applications Depending on the particular technology, smart meters could be integrated as part of a larger smart home system including automated or smart appliances, security systems, and advanced electricity management tools. One very attractive possibility is the ability to manage oneâ&#x20AC;&#x2122;s own energy consumption through control over appliance energy usage by the consumer or remotely by the supplier. For example, during peak load times or when

prices exceed a particular threshold, certain appliances may be automatically disconnected. 5. Prepayment & Vulnerable Customers Smart meters also easily allow for prepayment-type plans for energy usage. Not only does the meter allow the customer to easily switch between payment plans, but also, it enables the electricity supplier to control the energy supplied for a certain prepayment without having to make a site visit to service or install separate equipment. For those customers vulnerable to falling into bad debt, pre-paid plans might be the option of choice to control their consumption. In addition, smart metering allows suppliers to send warning messages to those vulnerable to falling into bad debt and to implement a phased disconnection instead of an abrupt termination of service. Customers who are particularly sensitive to fluctuations in electricity price â&#x20AC;&#x201C; i.e. those for which electricity costs are a significant fraction of their income â&#x20AC;&#x201C; can benefit greatly from smart metering and TOU tariffs. Through these measures, such customers (more than any other) alter their consumption behavior and reduce their energy costs as a result.

4.3. ELECTRICITY SUPPLIER BENEFITS 1. Peak Load Shifting & Reduction

One of the largest benefits of smart metering to suppliers is its potential use for peak shifting peak loads, meaning a shift in energy consumption away from times of day when energy consumption abruptly spikes to very high levels (i.e. breakfast hours, ACintensive afternoon hours). The main reason that such a peak load would shift is the disproportionately high marginal cost of supplying electricity during peak hours, which means that even a drop in peak demand of a few percent can result in a large economic benefit for suppliers. For example, Fig. 4.1 illustrates this extreme sensitivity of price on energy demand. It presents the market unit price of electricity as a function of the load on the California independent system operator. The price dramatically spikes as the load is increased.

Fig. 4.1: Market unit electricity price as a function of energy load [Borenstein 2002]

As a result of a shift in peak demand, the electricity demand throughout the day is smoother. This improves supply security, as energy consumption is more stable and predictable. The risk of blackouts is subsequently significantly diminished. In reality, however, the amount of energy consumption that can be easily shifted to offpeak times â&#x20AC;&#x201C; things like household appliances â&#x20AC;&#x201C; account for only a modest fraction of the peak load (5-6%) [Mott MacDonald 2007]. An additional economic incentive would likely be required to significantly change consumer behavior to this end, particularly when considering that many consumers will be unwilling to run things like a washing machine at night. An example is a time-of-use tariff in which consumers are charged significantly more for electricity during peak hours. For this to be successful the different in electricity price between peak and off-peak times needs to be significant and the time window over which consumers can take advantage of the lower prices must be large. When consumersâ&#x20AC;&#x2122; behaviors change and they reduce their energy consumption, they do so at all times of day. This translates into a reduction in peak time energy consumption. Measures taken by consumers to reduce their energy waste are, in fact, likely to have the most impact during peak load hours of the day. 2. Remote Control Another significant benefit to the supplier is the reduced cost associated with not having to visit each individual household and service the appropriate equipment to perform a variety of functions. Since the communications ability of smart meters enables suppliers 37

to read a customerâ&#x20AC;&#x2122;s meter remotely, the cost to the supplier is greatly reduced, In combination with the ability to remotely connect or disconnect a consumer, this remote control saves the supplier transactions costs with a network operator that would otherwise have to perform these functions in person on-site. Smart meters also allow electricity suppliers to remotely switch consumers between different payment schemes. An indirect benefit of this is that consumers may be more inclined to avoid bad debt, since they know the utility has such remote control over their energy supply and billing. A hidden effect of increased smart meter deployment, however, is that the remaining conventional meters become more sparse and spaced farther apart, thus increasing the cost of reading each remaining conventional meter. 3. Reduced Inquiries While the initial influx of calls to utility call centers will likely increase due to consumersâ&#x20AC;&#x2122; unfamiliarity with the new meters, once consumers become familiar with their operation, call inquiries are expected to dramatically decrease. Most such calls are related to billing questions, change of household occupant, and change of supplier. Since smart meters enable all of these concerns to be addressed remotely by the consumer himself, suppliers estimate that call volumes will fall by approximately 30%, resulting in overhead costs savings of as much as 20% [Mott MacDonald 2007]. 4. Prepayment, Vulnerable Customers, Reduced Debt Handling With smart meters, suppliers are able to detect and prevent possible bad debt amongst their consumers, an ability that will save utilities a significant amount in costs. In particular, this can be done through direct communication with the customer and remotely connecting, disconnecting, and limiting the supply of energy to troubled consumers. Furthermore, suppliers can more readily switch such problematic consumers to different payment schemes (e.g. pre-paid contracts) in an attempt to prevent bad debt. 4.4. NETWORK AND METER OPERATOR BENEFITS 1. Remote Measurement Smart metering allows network and meter operators to measure energy consumption (on behalf of an electricity supplier) across the network with far more accuracy than was previously available with electromechanical meters. Furthermore, the ability to do this remotely and at any time saves operators costs that historically went into making site visits to measure energy consumption. 2. Fraud and Network Loss Detection Because of the detailed usage information provided by smart metering, fraud and electrical theft are readily identified. Additionally, it is easier to detect the specific locations of power losses and supply disruptions on the electrical network, to appropriately repair them in a timely, efficient fashion, and to verify restoration of service.

3. Power Quality Included with the wealth of new, detailed information provided by smart meters is more accurate and detailed power quality data regarding voltage, phase, and supply continuity that may allow network operators to improve power supply quality. 4. Network Investment The information provided by smart meters could be used by network operators to make more informed decisions about how to manage the network as well as how best to invest in network upgrades. For instance, if peak loads were to significantly change, a network operator would have accurate information with which to make an informed decision on how to appropriately respond. The same is true if there were an increase in distributed generation. The network operator would have detailed usage information to inform investments in the grid to meet the demands of the new power being supplied. 5. Remote Connection and Disconnection The remote communications abilities of smart meters allow network operators to connect or disconnect a household (on behalf of an electric supplier) without having to make a costly site visit. Additionally, operators may limit the usage of a particular customer. 4.5. BENEFITS OF SPECIFIC METER FUNCTIONALITY The number of these aforementioned benefits afforded by smart metering differs significantly with the employed technology. Each such benefit falls into one of several functional or technical categories [Mott MacDonald 2007]: •

•

• •

Customer Display Unit or Real-Time Display (CDU or RTD) – Benefits arising from the display of detailed information to the customer and feedback gathered by the smart meter. Accounts for approximately 40% of the total number of potential smart metering benefits. Automatic Meter Reads (AMR) – Benefits arising from a reduction in site visits and call center inquiries for billing and account issues, enhanced debt handling, and reduced theft and losses. Accounts for 44% of the total number of potential smart metering benefits. Time-of-Use Pricing (TOU) – Benefits arising from peak load shifting and TOU tariffs. Along with other benefits, accounts for 9% of the total number of potential smart metering benefits. Automated Meter Management (AMM) – Benefits arising from remote-controlled functions such as connection/disconnection/power management and remote supplier or pricing switching. Accounts for 7% of the total number of potential smart metering benefits.

Table 4.1 presents the benefits attributed to specific smart metering technologies in place in the UK. D+S, BEAMA, and ERA are different types of smart meters while the remaining two options are non-smart modifications of current electromechanical meters. The least advanced technology is clip-on while the most advanced smart meter is ERA. 39

Table 4.1: Benefits attributed to certain modified electromechanical electricity meters and more advanced smart meters in the UK [Mott MacDonald 2007]

A majority (in terms of number) of the potential benefits are attributed to the three presented smart metering technologies â&#x20AC;&#x201C; D+S, BEAMA, and ERA. While an improvement over basic electromechanical meters, the two non-smart technologies â&#x20AC;&#x201C; Clip-on and Retrofit â&#x20AC;&#x201C; do not afford nearly the same number of functional benefits. Only the most advanced technology, ERA, enables the most advanced AMM-type functionality. The other two smart meters, D+S and BEAMA, mostly contain the less advanced AMR features.

4.6. GENERAL, SYSTEM-WIDE BENEFITS In addition to the benefits specific to individual stakeholders or particular smart meter functions, numerous benefits to the whole system, all stakeholders, or the public at large also exist. Many of these benefits arise when smart metering is utilized in combination with time-of-use tariffs. 1. Distributed Generation By providing the consumer with easily accessible and detailed information regarding his energy consumption patterns (and the associated costs), it is possible that some will be more likely to adopt and invest in microgeneration, in the same way that such information could potentially empower consumers to invest in energy efficiency and load 40

management devices. An important point, however, is that smart meters cannot be used to directly measure the output generated by microgenerators at the consumerâ&#x20AC;&#x2122;s household. Since smart metering may induce consumers to invest in microgeneration, the potential for distributed generation greatly increases as more consumers feed their excess energy back into the grid for use by others. 2. Environmental Security Under smart metering, the potential exists for reductions in overall energy consumption. As an additional benefit, these reductions lead to an associated reduction in greenhouse gas emissions from power production. Such emissions reductions are only realized if overall energy consumption for a given power source decreases. If peak load decreases, but off-peak usage increases in response, the environmental benefits will be far less significant. Additionally, as with energy savings, the increase in carbon emissions from the increased energy usage of the smart meter and communications system relative to standard meters is an additional consideration of importance. 3. System Security If smart metering successfully induces consumers to reduce consumption overall and at peak load times when spare generation is minimal, the system is much less vulnerable to service disruptions, ensuring continual service for customers as well as heightened infrastructure security for network operators and suppliers. In automated demand response systems, at very high peak loads, electricity supplied to certain appliances could be reduced or disconnected altogether to bring the grid back into balance. Similarly, if there is an unexpected surge in electricity supplied to the grid by intermittent renewable energy sources during off-peak hours, such demand response management can also serve to automatically increase loads to re-balance the network. 4. Transparency The detailed real- or near real-time information gathered by smart metering provides transparency for all stakeholders in a smart metering system. Consumers know how exactly they are being charged; suppliers have detailed information on customer usage patterns, and network operators can more accurately monitor activity on the grid. Furthermore, this is also advantageous for regulators, as a lot of new information on the electricity market is available under smart metering that isnâ&#x20AC;&#x2122;t under a conventional metering scheme. This will enable them to make more informed policymaking decisions.

4.7. QUALITATIVE REVIEW OF COST-BENEFIT ANALYSES To evaluate whether the possible benefits of smart metering are more valuable than the costs for implementation, cost-benefit analysis is used. This assessment uses two key indicators: net present value (NPV) and cost-benefit ratios (CBR). NPV indicates how much a particular investment is worth in current monetary terms and is calculated as a sum of the net cash flows 41

discounted to todayâ&#x20AC;&#x2122;s monetary value; a higher, positive NPV signifies a more worthwhile investment that would add value while a negative NPV indicates that a particular investment or project will subtract value. The CBR is the ratio of the NPV of the benefits to that of the costs and will be greater than unity for worthwhile investments. A British study produced a series of CBRs for different smart metering technologies and implementation scenarios. Ideally, a smart metering system should have a benefit-to-cost ratio greater than unity and a positive NPV for multiple implementation scenarios. The various implementation options that were studied are characterized by the way and rate with which smart metering is deployed as illustrated in Fig. 4.2 which presents the number of smart meters installed as a function of time for various roll out schemes:

Fig. 4.2: Different smart meter roll out scenarios [Mott MacDonald 2007]

Market roll out refers to the implementation of smart metering via free market mechanisms in which consumers choose to upgrade based on an advantageous cost-benefit ratio. The primary market players are the consumer, the electric supplier, and the network and meter operators. There is no government intervention in such an option. In a tipping point scenario, the free market still drives smart meter roll out; however, implementation increases slowly at first until a threshold or tipping point is reached at which smart metering becomes so cost effective that it is more economical to deploy smart meters rapidly and on a very large scale. Regional franchise is similar to the free market roll out, but it is supplemented by a government mandate that stipulates all new and replacement meters should be smart meters. Finally, the baseline scenario is a fully managed strategy in which universal smart meter implementation is completely mandated in all aspects. The government specifies the implementation time frame as well as whose meters are to be replaced. 42

The British cost-benefit analysis also accounted for optimism bias, a systematic tendency to be overly-optimistic concerning the risks and uncertainty associated with various costs and benefits that are predicted for a certain implementation scenario. The benefit-to-cost ratios of the analysis are presented in Table 4.2 for three different types of British smart meters. The most advanced, fully AMM-type meter is ERA while the least advanced, AMR-style smart meter is Dumb+Smart.

Table 4.2: Benefit-to-cost ratios for different types of British smart meters deployed during different roll out scenarios [Mott MacDonald 2007]

The results of this analysis indicate that of the smart metering technologies (BEAM, ERA, D+S), only D+S has a consistently favorable (>1) ratio of benefits to costs for all implementation scenarios evaluated, whether corrected for optimism bias or not. Furthermore, an accelerated market roll out, such as the previously described tipping point scenario, provides a better CBR than the other implementation strategies. CBRs not corrected for optimism bias are consistently higher than those that are corrected for such bias, as expected. The CBRs for a particular technology decrease as the technology becomes more advanced indicating that the added value of including the most advanced smart metering functions does not outweigh the added costs for their implementation. This conclusion is confirmed by an analysis of the raw NPV for these three smart metering technologies. Fig. 4.3 presents the net present value for the three previously-presented smart meters for the same set of roll out scenarios.

Fig. 4.3: Net present values of different British smart meters under different deployment scenarios [Mott MacDonald 2007]

As before, D+S is the only favorable smart metering technology. Here it is seen that D+S is the only technology with a consistently positive net present value. The other, more advanced smart metering technologies have negative NPVs, indicating that their implementation will result in a net cash loss. Alternatively, the positive NPV of the D+S option means that implementation of 44

this technology will result in a net cash gain or a net increase in value. The reason for this is likely due to the fact that D+S offers many of the same benefits of more advanced smart metering technologies, but it does so at a much lower cost. D+S can be thought of as an intermediate between the most advanced, complete smart meters and a simple non-smart retrofit of the old meter. Another reason contributing to the high NPV and CBR of this particular technology is that it only includes those smart metering features which add the most value per given unit cost while not including other advanced features that may not necessarily add significant value or benefits. This observation is further supported by the previously presented information on the number of benefits attributed to specific smart meter functionality. By far, the largest fraction (in terms of number, not cash value) of the benefits arises from the more basic functions of smart meters such as a customer display and AMR functionality. More advanced meters incorporating AMM only contribute a small number of additional benefits, which is likely not worth the large extra costs associated with these more advanced abilities. Also, as presented in the previous breakdown, intermediate-level D+S smart meters contain nearly as many of the benefits and functions of more advanced BEAMA and ERA smart meters, but as shown in this CBA, there are far fewer costs associated with D+S implementation. As a result, the most cost-effective smart metering implementation is not one that contains the most advanced (and most costly) features, but rather, it is an intermediate option that only contains the most valuable smart metering functions, often the most fundamental and basic smart meter features that yield large pay-off at a small cost. Another cost-benefit analysis from the Netherlands assessed the relative cash value of specific costs, benefits, and functions of smart meters. As before, a positive cash value indicates a net added value while a negative cash value indicates a net loss or cost. Fig. 4.4 presents NPVs for various possible effects and requirements of smart metering for both gas (G) and electric (E) smart meters.

Fig. 4.4: Net present values of different requirements and effects of smart metering [Siderius & Dijkstra]

According to this analysis, the greatest benefits (in terms of present cash value) gained from implementing electrical smart meters results from easily switching between suppliers (increased competition), a demand response shift in electricity consumption, a decrease in inquiries to utility call centers, and cost savings from avoided meter readings. The greatest costs (in terms of present cash value) arise from smart meter installation, data storage and management infrastructure, and the overhead due to more detailed billing under a smart metering system. The analysis also evaluated the aggregate costs and benefits to various stakeholders in a smart metering system. Fig. 4.5 presents NPVs for costs and benefits attributed to households or consumers, meter operators, network operators, electricity suppliers, power generators, and national authorities.

Fig. 4.5: Net present values for the aggregate costs and benefits of various stakeholders in a smart metering system [Siderius & Dijkstra]

By far, consumers benefit the most (in terms of added present cash value) from smart metering implementation, while the implementation costs to other stakeholders is relatively higher than those for the customer. These results indicate that market players such as network operators, metering companies, and electric suppliers pay for the initial costs of and are responsible for the initial roll out of smart metering. On the other hand, the consumer, at least initially, has very little to do with this roll out (as illustrated by the very low costs assigned to households) but benefits greatly from this change in infrastructure. This analysis ignores whether the initial implementation costs borne by stakeholders other than the customer are ultimately passed back to the household in the form of additional fees, higher service prices, and/or contractual obligations. LESSONS LEARNED These specific results â&#x20AC;&#x201C; values of costs, benefits, CBRs, and NPVs â&#x20AC;&#x201C; will clearly be different for California than in these specific studies. However, while these analyses were performed for the UK and the Netherlands, we can still draw general conclusions from their results and apply them to the implementation of smart metering in California in order to provide recommendations regarding two of our particular questions of focus â&#x20AC;&#x201C; specifically, what level of technical standardization or minimum functional requirements California smart meters should adopt and whose interests, customers or suppliers, should be realized.

1. Smart Meter Functionality Should be Standardized to Ensure Interoperability In order to maximize the benefits of smart metering with respect to its costs, the chosen technology will have to be standardized for all consumers. Such a minimum level of standardization should be implemented in California to keep smart metering costs uniform for all customers as well as to ensure that the most valuable functions of smart meters that result in the greatest economic payback are utilized by as many people as possible. For instance, all smart meters in California should enable the customer to easily switch between different electric suppliers. If such functionality isn’t standard across all deployed smart meters, the potential economic value gained from this feature will not be fully realized since only a handful of customers will be able to utilize this feature. Only when every customer can do this can California gain the maximal economic benefit offered by this specific smart metering feature. Additionally, this technological standardization is critical to ensure interoperability across the whole system. For example, it guarantees that consumers, when switching to another supplier, can successfully interact and interface with that new supplier. Standardization guarantees that all customers can successfully interact with all of the other market players, particularly electric suppliers. This is critical to the success of smart metering, as the communications function of the new metering system requires that all parties – consumers, suppliers, network and meter operators – be technically compatible in order to work together. This wasn’t a concern in the old metering system, since everything was performed in person or over the phone. 2. Minimum Functional Requirements – Most Advanced Option Isn’t Necessarily Best It is likely that the most cost effective smart metering solution in California will not be the most advanced or most functional smart meters. Rather, a balance will have to be found between the benefits afforded by a given smart metering technology and functionality as well as the costs associated with implementing that particular option on a large scale. For instance, California should implement an intermediate smart metering option, not the most advanced technology available. As shown by the uniformly maximized CBRs and NPVs in the UK study for such an intermediate technology option, this approach is the most cost effective, as it affords the majority (but not all) of the most valuable potential benefits of smart metering at a significantly lower cost than would be required for implementing all of the most advanced smart metering features. This conclusion is further supported by the previously-presented data indicating that the majority (in terms of number, not cash value) of benefits of smart metering result from basic features like a real-time display and AMR functionality, not the more expensive and more advanced AMM abilities. More specifically, we can use the Netherlands analysis to make generalizations and recommendations regarding the kinds of particular minimum functionality California smart meters will require in order to maximize the value of the benefits afforded by various smart metering functions. At a minimum, California smart meters should enable automatic meter readings from a remote location such that network or meter operators or 48

the supplier doesnâ&#x20AC;&#x2122;t have to make an on-site visit to measure electricity consumption. The meters should also allow for customers to easily switch between prospective electricity suppliers on their own without having to call the utility, a functionality that will yield increased competition amongst suppliers as they customize their pricing plans and service packages for their consumers. Customer billing should fully take advantage of the new information available from these smart meters. More accurate and transparent billing practices will decrease calls and complaints to utility call centers. Finally, smart meters implemented in California should, at a minimum, have an indoor display that provides detailed real- or near real-time usage and cost information so that customers may be more informed about their actual usage and what itâ&#x20AC;&#x2122;s costing them so they can make behavioral changes in terms of energy consumption. This demand response shift in consumption is more likely and will have a greater beneficial impact if the provided feedback from the meter is more detailed and contains more useful information regarding cost to the consumer, how and when energy is being used, and what the consumer can do as a response. 3. California Should Focus on Realizing Consumer Benefits Finally, since the Netherlands analysis found such overwhelming value of the benefits afforded to consumers in their smart metering implementation relative to consumer costs, costs to other individual stakeholders, and the benefits to other stakeholders, smart metering implementation in California should favor the interests of customers rather than those of suppliers. By implementing smart metering in such a way as to realize the aforementioned benefits to consumers â&#x20AC;&#x201C; rather than focusing on fulfilling the benefits to suppliers and network operators â&#x20AC;&#x201C; the aggregate benefits for the system as a whole would seem to be maximized in terms of cash value, according to the Netherlands analysis. Were California to focus on realizing the benefits for other stakeholders, the overall increase in cash value of the system as a whole may not be as large due to the significant lower NPV of the benefits to these other stakeholders. Additionally, benefits that consumers want (that suppliers may not) such as energy savings and enhanced energy efficiency should be the focus of smart metering implementation, as it provides additional benefits to society as a whole, instead of just an individual stakeholder as presented in the previous section concerning general, systemwide benefits. This is a particularly compelling reason to focus on realizing the consumer benefits of smart metering. Customer benefits such as energy savings naturally lead to larger societal benefits such as associated emissions reductions, enhanced energy efficiency, and the proliferation of distributed or micro-generation that are all also good for our society as a whole and, thus, should be realized in any smart metering deployment. Were California to focus on achieving the benefits of another stakeholder like suppliers, many of these greater societal benefits would not be realized.

Section 5

EU Case Studies: Italy and Ireland

To gain insight into the kinds of regulatory structures that have resulted in rapid and effective smart meter deployment (and could therefore potentially be applied to California’s own smart meter implementation), we examine two case studies based in the European Union (EU). European policy has fostered smart metering in many of its member states, including Italy, Norway, Ireland and the UK. In particular, we have chosen Italy and Ireland, two countries that have plans to achieve universal smart meter deployment but are at very different stages of their implementation plans. Italy is approaching universal installation, while Ireland is quickly moving through the pilot stages and is laying plans for full-scale implementation. Recommendations for California can be made by examining the policies these nations have put in place to ease the transition from traditional electromechanical meters to more advanced smart meter technology. The various electricity authorities at different levels of the EU and the disparate market conditions present in each member state result in a regulatory structure whose complexity rivals that of California. Within both Italy and Ireland, a single agency is responsible for electricity regulation and a single company dominates the electricity market. Across the EU, policymaking is extremely decentralized as member states are not required to adopt all EU Directives. Infrastructure standardization is becoming increasingly important as the EU aims to eventually integrate its member states into one electricity market. Depending on the specific goals each country hopes to realize with its smart meters, policies have been designed to maximize the benefit to different stakeholders. Because California’s market and regulatory conditions and smart metering goals differ from those of the EU and its member states, not all best practices can be directly transferred. When these differences are taken into account, however, it is possible to extract recommendations appropriate for California. A table detailing the differences between the Californian, Italian and Irish electricity markets is included with our case study recommendations. We begin with an overview of the EU regulatory agencies and the EU Directives that directly affect smart metering. We then proceed to the smart metering and electricity systems in Italy and Ireland, including information on the major power companies, chosen smart meter technology and market model, the types of consumers targeted and the regulatory structure. Finally, we present the recommendations for California that address two of our three leading questions – regulatory centralization and technological standardization. 5.1. EU SMART METER REGULATORY STRUCTURE The general structure for smart metering in the EU is detailed in Figure 5.1 below. The European Commission (EC) is responsible for preparing proposals for electricity regulation and submitting them to the EU’s parliament and council. They are advised by the European Regulators' Group for Electricity and Gas (ERGEG) and parliament lobbyists such as the Council of European Energy Regulators (CEER) on acceptable goals and standards beneficial to EU member states. These recommendations and proposals are based on results from various pilot programs. Once the proposals are approved by parliament and council, directives are issued to the regulatory bodies of EU member states.

Obeying principles of subsidiary, these national regulatory bodies have sole authority to utilize the directives as they see fit. The European commission can only intervene when they deem it necessary. National regulatory bodies assess the directives and make implementation recommendations to the government. Government-approved recommendations become mandatory Regulatory Orders and are implemented by the regulatory body. Utility companies are rewarded or penalized according to the Regulatory Orders that promote smart metering. Finally, consumers interact with utilities via the actual smart meter technology.

EU Italy Ireland

EU European Commission

1) General Directives are given as suggestions to the electricity regulatory bodies of EU Member states.

*Note: Advisory boards provide information and proposals for the European Commission

European Advisory Board (ERGEG)

2) Regulatory bodies assess the Directives and make implementation recommendations to the government.

National Regulatory Body

National Government 3) The Government denies or approves the recommendations. Approved recommendations become mandatory Regulatory Orders and are implemented by the regulatory body.

*Note: In certain cases, Utilities motivate EU European Commission Directives (ENEL Smart Meter Pilot Programs).

Electrical Utilities:

4) Utility companies are incentivized or penalized according to the Regulatory Orders that promote smart metering.

5) Actual smart meter 2-way technology allows interaction between consumers and utilities.

*Note: Consumer boards may lobby for higher incentives. Consumers

Regulatory Action Recommendation X

Decision Maker

Advisor

Fig. 5.1: Smart Meter Regulatory Structure for the EU

5.2. RELEVANT EUROPEAN COMMISSION REGULATORY DIRECTIVES The European Commission does not directly implement smart metering policies in EU member states; however, some of these laws have helped to shape smart metering in the EU. Most approved directives have general references to demand response, energy efficiency, and metering functionality. The particular incentives, penalties, and technological requirements for such broad directives have influenced what smart metering has evolved into in Europe. Here we present those directives most relevant to smart metering in the European Union. 5.2.1. EC ELECTRICITY DIRECTIVE (2003/54/EC) Common rules for the internal market in electricity The directive was initially created in 1996 (EC Directive 96/92/EC) and has gone through several iterations. This document was responsible for the creation of EU regulatory body ERGEG and national regulatory bodies such as AEEG and the Commission for Energy Regulation (CER). While not explicitly referencing smart metering technology, the directive was a push for the unbundling of the Distributed Network Operator (DNO) by the end of 2003. There is a clause that allows for the free entry of EU-based DNOs, metering companies and suppliers into the electricity market. This will enable customers to switch electricity suppliers and to renegotiate their rates according to the best offers available. This functional unbundling will be required for all vertically integrated European utilities by 2010. A current proposal for amendments 6 to the Electricity Directive concerns the minimum technological requirements for smart meter technology. It states that customers must have their consumption data at their disposal and may do what they want with it. This proposal, if adopted by an EU member state, also stipulates that the DNO or metering company will bear the cost of the smart meter and data collection. However, if this company is separate from the transmission and generation businesses, they will have little motivation to replace old meters unless they are given incentives by the government. 5.2.2. EC METERING DIRECTIVE (2004/22/EC) Measuring Instruments This directive was officially adopted in 2004. It calls for the standardization of all electricity energy meters in the EU 7 . EU member states shall ensure conformity with the minimum essential requirements established by this standard. The harmonized European standard has been published in the Official Journal of the European Union, C series. All meters manufactured in the EU shall be easily recognizable by the presence on it of the "CE" marking and the supplementary metrology marking.

Proposal for a Directive of the European Parliament and of the Council amending Directive 2003/54/EC concerning common rules for the internal market in electricity 7 Article 13 (1)

This allows smart meter manufacturers in a member state of the EU to provide products and services to any other EU member state. This, when combined with unbundling of electric utilities, allows for more consumer choice. 5.2.3. EC ENERGY SERVICES DIRECTIVE (2006/32/EC) Energy end-use efficiency and energy services This directive was officially adopted in 2006. Article 11 (1) sets the stage for individual EU countries to provide incentives towards smart metering. It says that member states may establish a fund or funds to subsidize the delivery of energy efficiency improvement programs and other energy efficiency improvement measures, and to promote the development of a market for energy efficiency improvement measures. Such measures shall include the promotion of energy auditing, financial instruments for energy savings and, where appropriate, improved metering and informative billing. The funds shall also target end-use sectors with higher transaction costs and higher risks. Article 13 elaborates possible smart meter technological requirements: “(1) Member States shall ensure that, in so far as it is technically possible, financially reasonable and proportionate in relation to the potential energy savings, final customers for electricity… are provided with competitively priced individual meters that accurately reflect the final customer's actual energy consumption and that provide information on actual time of use”. When an existing meter is replaced, competitively priced replacement meters shall always be provided, unless this is technically impossible or not cost-effective in relation to the estimated potential savings in the long term. When a new connection is made in a new building or a building undergoes major renovations, as set out in Directive 2002/91/EC, such competitively priced individual meters shall always be provided. Member states shall also ensure that, where appropriate, the following information is made available to customers in clear and understandable terms by energy distributors, distribution system operators or retail energy sales companies in or with their bills, contracts, transactions, and/or receipts at distribution stations: • • •

current actual prices and actual consumption of energy; comparisons of the customer's current energy consumption with consumption for the same period in the previous year (preferably in graphic form); wherever possible and useful, comparisons with an average normalized or benchmarked user of energy in the same user category

The article serves as a guideline for possible minimum information requirements smart meters should have, but it is very clear that smart metering must be within reasonable budgetary constraints. The following cases will analyze the resulting smart metering policies for the aforementioned EU member states.

5.3. CASE 1: SMART METERING IN ITALY Italy has been the frontrunner in smart metering technology. Initially developed to prevent electricity theft, a successful pilot smart metering program in 1999 led to Italian electricity regulatory body Autorita per l’Energia Elettrica e il Gas (AEEG, established 1995) imposing mandatory replacement of all regular meters with smart meters over a four-year period (from 2008 to 2011) [Vasconscelos 2008]. With a population of 58 million, there are approximately 35 million meter points. 27 million of those meter points are residential. 5.3.1. MAJOR POWER COMPANIES ENEL (Ente Nazionale per l’energia Elettrica) is the major power company in Italy and the third largest provider worldwide. They provide electricity to some of Europe and South America, and currently have approximately 30 million customers in Italy. Formerly the sole electricity provider for Italy, ENEL is now partially privatized with government control. Following the Bersani Decreto, ENEL was forced to give up a little over 50% of their electricity market share to competitive companies. Major competitors include Edison S.p.A and Energia Italia. Municipal utility companies such as ACEA, Hera, Azienda Energetica Municipalizzata (AEM) Milano and AEM Torino account for about 4% of the country’s power [Thomas & Hall 2003]. The three biggest generators in the country account for 69% of its capacity. After jumpstarting their smart metering program (independent of regulatory activity), ENEL has installed 40,000 smart meters per day for a total of 27 million smart meters over a five-year period (from 2001 to 2006). ENEL claims that the meters paid for themselves after four years and are now generating costs savings of €500 million annually that would otherwise have gone into demand management and manual meter reading costs. 5.3.2. ITALIAN SMART METERING TECHNOLOGY & MARKET MODEL After International Business Machines (IBM) provided smart meters for their pilot program, smart meters in Italy currently utilize Echelon Smart technology (same company being used by Duke Energy in the US). The meters take 15 minute measurements, are fully software-driven, and capable of Automated Meter Management (AMM). This allows two-way communication between the meter and the electricity supplier using power line communications. ENEL customers can use the Internet to monitor and manage their power consumption using a Web portal developed by the utility. Italian electricity is currently regulated by the AEEG (not liberalized). It is currently a vertically integrated bundled system; this means that a single company is in charge of power generation, transmission, distribution, and supply. The Distributed Network Operator (DNO), in this case ENEL, owns the meter and is in charge of installation, maintenance, meter reading, and data management. Each meter point has a code defined by the DNO which is a common 14 digit code. All customers taking supply at 1kV and 56

above must have an hourly meter. ENEL has installed a smart meters at all 30 million meter points that it serves. The meters store consumption information in 15 minute intervals and send daily aggregated data to ENEL Distribution. The supplier can also communicate with the meters when spot prices reach pre-determined levels so that a signal could be sent to turn equipment off and on. Although consumers can currently access smart meter data, there are no rules on who should have access to the data and what the data can be used for. The communication protocols have not yet been standardized and different DNOs adopt different systems and communication protocols in order to transfer data with retailers. AEEG is still deliberating on third party access data, an important tool for enabling consumer switching of electricity providers. 5.3.3. TYPES OF CONSUMERS All High Voltage (HV) and Medium Voltage (MV) consumers currently use smart meters. These are typically industrial and commercial electricity consumers, with power consumption greater than 5.5kW. Currently 86.2% of the countryâ&#x20AC;&#x2122;s Low Voltage (LV) electricity consumers are using smart meters. These are typically household electricity consumers, with power consumption less than or equal to 5.5kW. Figure 5.2 shows the mandated plans for LV smart meter installation: 25% in 2008, 65% of 2009, 90% in 2010, and 95% from 2011 (AEEG Regulatory Order 235/07). At 86.2% in 2008, Italy has clearly exceeded its LV smart meter goals of 25% implementation and shows no sign of slowing down. Plan for installation of smart meters with LV customers

Mandated Percentage Implementation

100% 90% 80% 70% 60% 50%

Plan for installation of smart meters with LV customers

40% 30% 20% 10% Dec-12

Jun-12

Dec-11

Jun-11

Dec-10

Jun-10

Dec-09

Jun-09

Dec-08

Timeline

Fig. 5.2: Regulatory Plan for Installation of Smart Meters with LV Customers

5.3.4. ITALIAN SMART METER REGULATORY STRUCTURE EU Italy

European Advisory Board (ERGEG)

EU European Commission

1) Directives: 2003/54/EC 2004/22/EC 2006/32/EC

2) Regulatory bodies assess the Directives and make implementation recommendations to the government. National Regulatory Body (AEEG)

National Government 3) Approved AEEG Regulatory Orders 235/07 248/07

*Note: In certain cases, Utilities motivate EU European Commission Directives and National Regulatory Orders (ENEL Smart Meter Pilot Programs). Electrical Utilities: (ENEL)

4) Implement AEEG Regulatory Orders 235/07 248/07

5) Echelon two-way communication.

Consumers (30 Million)

*Note: Consumer boards may lobby for higher incentives.

Regulatory Action Recommendation X

Decision Maker

Advisor

Fig. 5.3: Italian Smart Metering Regulatory Structure

As seen in Figure 5.3, the Italian regulatory structure follows the EU regulatory structure except for a few minor additions: • •

Italian consumer boards may lobby for higher incentives for smart metering Due to ENEL’s market power and pioneering smart metering program, the utility may motivate EU European Commission Directives and National Regulatory Orders (ENEL Smart Meter Pilot Programs).

Italian electricity is regulated nationally by AEEG. As a member of the European Union (EU), it is also subject to guidelines and recommendations from the European Regulators' Group for Electricity and Gas (ERGEG) and the European Commission. The directives given by these European regulatory bodies have impacted smart metering in Italy. For example EC Electricity Directive (2003/54/EC) served as the catalyst for the Bersani Decree, leading ENEL to split itself up into separate generation, transmission/distribution and sales companies. Some of the manifestations of EC directives regarding smart meters can be seen in the following AEEG regulatory orders: 5.3.5. AEEG REGULATORY ORDER No. 235/07 Guidelines for entry into service of electronic meters and remote systems for in the deliberations on December 18 2006, n. 292/06, and the introduction of performance indicators that use remote systems This directive is an update to the initial Regulatory Order 292/06. An explicit regulatory order in support of smart metering, it provides a detailed plan for full implementation of smart metering for LV customers by 2011 (See Figure 5.2). Article 12 also lists an incentive mechanism to be paid in 2010 for smart meter installation: It stipulates that every distribution company that intends to adopt a system that uses electronic meters for low voltage customers is entitled to a monetary incentive of an initial 50,000 euros and 15 euros per smart meter installed. This regulatory order facilitated the issuance of “white” certificates, a subsidy for every 1% reduction in energy consumption growth (e.g. if energy was supposed to grow by 5% and it grew by only 4%, utilities are issued white certificates). This intangible commodity functions similarly to emissions certificates in cap-and-trade systems. In the Italian electricity market white certificates are traded amongst utilities. 5.3.6. AEEG REGULATORY ORDER No. 348/07 Text of the provisions of the Electricity and Gas for the provision of electricity transmission, distribution and measurement of electricity for the period 2008-2011 and regulatory provisions on economic conditions for the disbursement service connections This resolution provides some tariff and price structures for smart meter implementation for 2008-2011. Article 2(1) lists different pricing options for MV and LV customers. Customers utilizing smart meters have electricity fees reduced by 10% if they are LV consumers and by 5% if they are MV. 59

Article 3 also lists possible exemptions to the penalties for failing to install smart meters adhering to the standardized functionality by 2011. 5.4. CASE 2: SMART METERING IN IRELAND In Ireland, the deployment of smart meter technology is only slightly more advanced that it is in California. However, the Irish electricity regulatory authority, the Commission for Energy Regulation (CER, established in 1999), has been implementing forward-looking policies since 2004. These policies are designed to ease the transition to smart metering, allowing the affected utilities to prepare for the change. Ireland’s population is 4 million, corresponding to roughly 2 million residential meter points. 5.4.1. MAJOR POWER COMPANIES The Electricity Services Board (ESB) was the dominant electricity supplier in Ireland since electrification began in 1927. The 1999 Electricity Regulation Act created the CER and described one of its goals as the “promotion of competition in the generation and supply of electricity” [Public Act 23/1999]. In 2001, the first step towards unbundling was taken when each of ESB’s production and supply systems were separated into their own separate corporations: ESB Power Generation, ESB Networks and ESB Customer Supply. Power generation and industrial and residential electricity supply were opened to competition in 2005, while transmission and distribution was maintained as a natural monopoly. As of 2006, ESB Power Generation supplied 60% of Irish electricity, competing against several smaller independent producers [CER Press Release 291106]. The CER has mandated that ESB Power Generation will divest 30% of its generating capacity by 2010 in order to reduce itself to 40% of the Irish market. ESB Customer Supply is the default source of electricity for consumers who have not elected to contract with an independent supplier. In 2006, ESB Customer Supply serviced approximately 2 million domestic and business customers, or 53% of the total market. Although the business and industry market is highly diversified, with a total of seven competing companies, ESB Customer Supply controls greater than 95% of the residential market [CER/05/112]. As the licensed Distribution System Operator (DSO), ESB Networks owns and operates the lower voltage power lines connecting all homes and businesses to the national grid, including those powered by an independent supplier. ESB Networks owns all electricity meters, and is responsible for installing, maintaining and reading them, as well as data management. 5.4.2. IRISH SMART METER DEVELOPMENTS AND MARKET MODEL Two smart meter pilot projects are currently underway: a small-scale behavioral experiment and a 25000 meter national pilot. The meters used in the national pilot are substantially similar to those which will be universally deployed; they monitor usage in 30 minute intervals, are capable 60

of two-way communication via General Packet Radio Service (GPRS), and can facilitate distributed power generation. The method of consumer feedback has not been determined. In-home displays, electricity bills detailing consumption habits, and an online portal are all being considered. Although the residential electricity supply is theoretically unbundled, it remains effectively bundled due to the lack of market competition. The CER is taking steps to reduce the size of the incumbent and encourage competition in the residential electricity supply market, but to date ESB Customer Supply services over 95% of residences. All distribution and metering services are provided by ESB Networks, which is managerially and operationally separate from ESB Customer Supply. As the CER-licensed Distribution System Operator (DSO), ESB Networks has been granted a monopoly on low- and medium-voltage electricity distribution. All highvoltage power lines are operated by EirGrid, the government-controlled Transmission System Operator (TSO). 5.4.3. TYPES OF CUSTOMERS All HV and MV consumers (i.e. any facility consuming more than 1 kV) currently use 15 minute interval smart meters (QH meters). There are several peak reduction programs already in place for the largest consumers, who generally must consume more than 30 kV to be eligible [KEMA Scoping Study for SEI]. LV consumers have simple electromechanical meters that are read manually six times per year. A small percentage (less than 10%) of LV consumers has â&#x20AC;&#x153;dual meters,â&#x20AC;? a pair of electromechanical meters that separate electricity used during the day and at night. A rudimentary peak reduction program encourages these consumers to shift their electricity usage to nighttime by charging a much lower rate during those hours.

5.4.4. IRISH SMART METER REGULATORY STRUCTURE EU Ireland

European Advisory Board (ERGEG)

EU European Commission

1) Directives: 2003/54/EC 2004/22/EC 2006/32/EC

National Advisory Board (SEI)

2) Regulatory bodies assess the Directives and make implementation recommendations to the government.

National Regulatory Body (CER)

National Government 3) Approved Regulatory Orders 04/064 07/085 07/198

Electrical Utilities: (ESB)

4) Implementing pilot programs as directed by CER.

5) GSMtwo-way communication

*Note: Consumer boards may lobby for higher incentives. Consumers (5 Million)

Regulatory Action Recommendation X

Decision Maker

Advisor

Fig. 5.4: Irish Smart Metering Regulatory Structure

The Irish electricity-regulating structure is only slightly different from the EU structure, as illustrated in Figure 5.4: • Sustainable Energy Ireland (SEI), a non-partisan government body, advises the national regulatory authority, CER, on the creation and implementation of policies promoting alternative energy and energy efficiency. • CER receives formal feedback from ESB and other affected parties on draft legislation. Although Ireland has not begun full-scale smart meter deployment, the CER has been preparing for that eventuality since 2004, motivated the EC Electricity Directive (2003/54/EC). By implementing the policy framework for smart meters, the CER hopes to smooth the transition to smart metering. The following CER Regulatory Orders assist ESB Networks and other affected parties in preparing for the transition. 5.4.5. CER REGULATORY ORDER No. 04/064 Market Arrangements for Electricity: Demand Side Participation Before the power generation and electricity supply markets were opened for competition in 2005, the CER developed a framework for these markets known as the Market Arrangements for Electricity. Section 3.4, Supplier Incentives, contained a clause with provisions for future demand side management: “The extent to which suppliers are incentivised to induce a demand side response from their customers will in practice depend on: • The nature and extent of any contracting they may have in place. • The relationship between tariff levels and the wholesale market price. • The availability of suitable and cost effective technology for consumers to see and respond to price signals.” 5.4.6. CER REGULATORY ORDER No. 07/085 Metering Code: Incorporating Changes for the Single Electricity Market Beginning in 2007, the wholesale electricity markets in the Republic of Ireland and Northern Ireland were joined to form the Single Electricity Market (SEM). This Regulatory Order was passed before the formation of the SEM and details the technical, design and operational criteria that all electricity meters must meet. Section 6 of the document contains specific information about the requirements of quarter-hourly smart meters. “This Section describes the technical requirements for Quarter Hourly metering. These requirements are additional to those described in section 5.” Standards for measurement parameters, data storage, data communications, password security and timekeeping are included. A portion of the data communications regulation reads: “6.4.1 Load profile metering will be equipped with standard communications ports for local and remote downloading of load profile data and other metered data. 63

6.4.2 All data communications equipment shall conform to the relevant International Telecommunications Union (ITU) standards and recommendations for data transmission over telecommunications systems.” 5.4.7. CER REGULATORY ORDER No. 07/198 Smart Metering: the Next Step in Implementation This Regulatory Order explains CER’s plan for determining which technologies are most appropriate for smart metering in Ireland. The CER’s goal is described as follows: “The Commission has decided to work with ESB Networks, suppliers and other stakeholders in structuring and implementing the role out of an optimally designed universal smart metering programme that will embrace all aspects of smart metering relevant to the Irish electricity market. The functionality required by different parts of the market, and the benefits that will arise are likely to be different in each sector of the energy market.” CER does not intend to take on this ambitious task alone, but rather will work with representatives from the affected parties. “The Commission believes that the project should draw on the experience and expertise of a working group that embraces all stake-holders in the electricity and gas markets. The working group will operate under the direction of a steering group comprising: • The Commission for Energy Regulation • ESB Networks • Department of Communication, Energy and Natural Resources • SEI”

LESSONS LEARNED Table 5.1 presents a summary of Italian, Irish and Californian electricity markets and smart metering. Based on the success of Italian smart metering programs and their rapid progression in Ireland, several general conclusions can be drawn from these cases from which we later make recommendations about California’s own smart metering deployment. In particular, we address two of our three leading questions regarding regulatory centralization and technical standardization. COMPARISONS Deployment Stage Regulatory Bodies Electricity Providers Customers Ownership of Meters Operation of Meters

Italy 86.2% Complete AEEG ENEL 30 million Distributor Distributor

Market Structure Meter Communication Metering Frequency

regulated, bundled 2-way, Echelon 15 minutes

Ireland Pilot Program CER ESB 4 million distributor distributor regulated, partially bundled 2-way, GSM 15 minutes

California Pilot Program CEC, CPUC, FERC PG&E, SCE, SDG&E 36 million under discussion under discussion partially regulated, bundled under discussion under discussion

Table 5.1: Electricity market and smart metering summary for Italy, Ireland and California

1. Regulatory Centralization Although it is tempting to attribute the success of the Italian and Irish smart metering projects to their unified regulatory systems, smart metering progress has been observed across the EU’s diverse jurisdictions. The number of electricity regulatory authorities in the European Union far outweighs the number found in California, but the jurisdiction of each agency is extremely clear. The boundaries of these agencies are transparently set by national boundaries, while California’s agencies are divided by subject matter and have unclear jurisdictional boundaries. The EU has a further advantage in that the European Commission is unequivocally the lead organization from which the other organizations accept directions. California’s regulatory agencies are currently situated as equals, which can confuse which agency is responsible for encouraging smart meter deployment and has the final authority on issues such as technological standardization and how competing interests should be satisfied. We recommend that California designate a “lead agency” for its smart metering project. This agency would coordinate action amongst the other statewide agencies as well as local and municipal utility authorities. The CPUC is the most appropriate choice for this position, as electricity services is part of its core mission and it has well-established relations with California’s electric utilities. 2. Technical Standardization While regulating the use of certain smart metering technologies may speed the initial implementation, the regulatory agencies should provide guidance only on the necessary and required capabilities and technical standardization. The regulations set forth by the 65

EU specify only the functional goals of smart metering technology, but do not mention how these should be achieved by the member nations. Legislation passed by AEEG and the CER is designed in the same way, allowing the electricity suppliers and distributors who will interact with the technology on a daily basis to select the specific technologies that are best suited to fulfill the minimum standardized capabilities set by the regulatory authorities. When delegating tasks to the other agencies, the CPUC should follow this pattern and refrain from regulating specific technologies as long as the minimum standard functional capabilities are met. For example, the specific kind of indoor display should not be specified, but rather, the information it must be able to display should be standardized. This minimum level of technological standardization in the smart meterâ&#x20AC;&#x2122;s capabilities should be set by the regulatory authority and be appropriate to the present and future structure of the electricity market. For example, because the California electricity market is unbundled, it is imperative that installed smart meters allow the electricity supplier to be changed without undue effort or expense. Both Italy and Ireland ran smaller scale pilot programs before beginning universal deployment of smart meters. These pilots allowed the regulatory bodies and electricity companies to test what level of standardization is necessary and to make adjustments before tackling the logistics of nationwide installation. The communication protocols used by smart meters in Italy and Ireland changed at least once between the initial pilot and large scale implementation, and the data management systems went through several iterations as well [CER/07/198]. The universal installation of smart meters should not be mandated before these pilot projects are complete and the technology, infrastructure and policies are adequately prepared. Any problems present in a small implementation will only be amplified if the process is pushed to full scale too quickly. In Italy, 27 million smart meters were installed in 5 years without a government mandate. 86% of the Italian LV market was penetrated by smart meters before AEEG instituted its schedule for universal adoption (Figure 5.2).

Section 6

Education for Persistent Change: The Behavioral Importance of a Customer‐Oriented Approach

This section will provide evidence for the importance of individual behavioral changes in order to make smart meter technology effective. It will review some studies that analyze such individual behavioral changes and the associated effects on energy savings, as well as the persistence of these effects. This will help to answer our leading question regarding whether smart metering policy should be focused on consumer or supplier benefits. The following quote by Darby nicely captures the motivation behind such an analysis: “The main general points to make are the importance of internal motivation as opposed to external incentives and controls [de Young 1993; Dwyer et al 1993] and the need for feedback to be maintained over time in order to allow householders to monitor the impact of any changes in their lifestyles, housing and appliances.” [Darby 2006] It is interesting to note that early studies on energy feedback, carried out in the 1970s and 1980s, were carried out mostly by psychologists. Feedback was seen as an ‘intervention’, an interruption in the normal behavior. Typical early feedback experiments would for example use posted notes on the consumer’s kitchen window each morning, telling her how the previous day’s consumption compared with some reference level. These studies demonstrated the measurable effect of feedback on consumption behavior and paved the road for an understanding of demand response as an active learning process [Ellis & Gaskell 1987, Darby 2006]. The changes introduced by smart meters should hence be interpreted in light of these psychological insights, and must pay respect to the well-known difficulties of learning processes. Particular emphasis is put on the role on incentives and persistent feedback to warrant the persistence of effects: “People may need additional help in changing their habits – this is where wellthought-out energy advice can be of use. Where feedback is used in conjunction with incentives to save energy, behaviour may change but the changes are likely to fade away when the incentive is taken away. As a rule of thumb, a new type of behaviour formed over a three-month period or longer seems likely to persist – but continued feedback is needed to help maintain the change and, in time, encourage other changes.” [Darby 2006] Initial incentives are important to raise people’s interest. Generally, information alone is not a sufficient trigger to induce major behavioral changes as people have to overcome a certain resistance due to unfamiliarity at first. “Learning to use energy more effectively is not possible unless the consumer experiments with the system. While people may appreciate the message, few are likely to be spurred into action.” [Darby 2006] A large number of studies were performed which focus on the issue of sustainability, analyzing the savings associated to different components of smart metering technology in a variety of experimental settings.

Generally, there seems to be consensus in the literature that more information is always better, and regular reminders of consumption must be seen as a continuing influence, promoting persistent conservation behavior [Darby 2006]. A review of “smart” heating billing in the Nordic countries found that the longer the duration of a trial and the more information available to the customer, the more persistent the effects were likely to be [Henryson 2000]. On the other hand, a study on gas consumption showed that gas savings dropped if the smart meter display monitor was removed from homes [Houwelingen 1989]. Even without advanced meters, behavior-based initiatives that make people check their energy meters regularly in combination with dedicated education programs have proven very successful (savings 10%-20%) [Darby 1999, Staats and Harland 1995]. Additional energy education may also take place in schools, possibly including home audits. In one particular study, “76% of pupils' families took some action and the level of behavioural change appeared to be higher than that achieved by advice services such as the EEACs” [Darby 2006; study in NP/NFA 2003]. Literature values about the time frame until persistent changes are incorporated vary greatly, but seem to be of the order of at least a few months. The West Lothian energy study mentioned in [Darby 2006] proposes a three-month period. Other studies refer to long-term effects that require over year. A Norwegian study used interviews to check persistence of behavioral changes [Wilhite 1995]. Although customers neither displayed uniform adaptation patterns nor had memory of critical learning situations, a solid incorporation of behavioral changes associated with informative billing was found, leading to continuingly high energy savings above 10% after three years. ”Our impression from the interviews is that after three years the changes people made had become so routine that they had trouble identifying them.” [Wilhite 1995] Equally important to the persistence of feedback is the representation of the feedback information. Studies indicate that the largest effects can be expected if the feedback is given in simple language or graphical form. Successful Norwegian implementation was aided by welldesigned brochures in simple language to help customers understand new informative energy bills. Customers appreciated improved accuracy and extra information (historic and comparative feedback, a guide to which end-uses were the highest consuming) and began to read their bills more frequently and with more understanding. [Wilhite 1997, Wilhite 1999]. A web page of the Californian electricity system showing a graph of current grid load, available capacity, and forecasts received more than two million hits each day during the 2000/01 electricity crisis [LBNL 2001, Darby 2006]. The page was created as a simplified version of data that had previously only been available to energy policy makers and utilities. From the above, it follows that smart metering as a tool for demand management should be essentially aimed at the customer for two reasons. First, the installation of a smart meter alone will not change anything, no matter what the technological or the economic choices. Instead, the key to success is the change in individual behavior, which then is the basis for large scale effects. In other words, demand response necessarily depends entirely on the acceptance of the consumer. It is therefore plausible that especially during the initial roll-out phase, smart meter technology should benefit the customer as much as possible.

Second, in order for smart meters to create a sustainable system of electricity supply for the next few decades, it must be warranted that the observed effects are not limited to short term trials. This implies that the success of demand response management largely depends on persistent learning effects on the customers, which re-iterates the importance of a customer-oriented approach to steer individual behavior. LESSONS LEARNED From an analysis of these previous European experiments and studies on the importance of behavioral changes on the effectiveness of smart metering, we draw several conclusions addressing one of our leading questions â&#x20AC;&#x201C; specifically, whose interests should be realized in the roll out of smart meters in California, customers or suppliers? â&#x20AC;˘

The effectiveness of smart meter technology strongly depends on individual behavioral changes, and persistent learning effects must take effect if demand response shall be a sustainable tool. We therefore recommend that smart meter implementation policy should be strongly targeted at the customer, especially during the initial roll-out phase, in order to warrant stability of the effects.

â&#x20AC;˘

Studies indicate that different feedback mechanisms (direct + indirect) in conjunction with dedicated education efforts show the highest effects. Smart meters should meet certain minimum functional standards (as identified in the technology section) in order to fulfill these criteria. During the initial roll-out phase, customers should be given clear financial incentives to engage in smart metering technology, and the implementation should be supported by brochures, counselors, and school-campaigns. All information should be articulated in a simple, preferably graphical, form. Strong active feedback is recommended for a period of at least 6 months.

Section 7

Recommendations and Conclusions

With the pressure of the electricity crisis in 2001, heat storms of 2006, and increasing population growth in drier, hotter inland areas, California is adopting aggressive efficiency and demand response goals. Yet, the state is lagging substantially behind its ambitious schedule for a variety of reasons not the least of which is the coexistence of numerous de-centralized regulatory agencies and the lack of coordination between them. As there are several utility companies, the technological standardization of the deployed smart meters is another key concern in California’s roll out scenario. Finally, the interests of consumers differ from those of other smart metering stakeholders such as electricity suppliers. A final important consideration is the tension between these competing interests and stakeholders. From our analysis contained in each of the preceding sections as well as the conclusions drawn from these analyses pertaining to our three leading questions of focus, we provide specific recommendations to California that guide how we believe smart metering implementation should be carried out. Should California adopt a more centralized regulatory structure or remain as it currently is? •

California should designate a “lead agency” to guide its smart metering deployment. This agency would coordinate action amongst the other statewide agencies as well as local and municipal authorities. California’s disparate regulatory agencies currently do not have clear jurisdictional boundaries such as those in the European Union or clearly dominant authority over the other agencies. This can make it difficult to efficiently resolve disputes such as competing stakeholder interests and questions regarding who has final authority over technical standardization choices and oversight of the deployment scenario.

•

The CPUC is the most appropriate choice for a “lead agency”, as electricity services is part of its core mission and it has well-established relations with California’s electric utilities.

What level of technical standardization, if any, should California smart meters adopt? •

California’s smart meters should be technologically standardized to ensure costs are more uniform across the state for consumers as well as to maximize the economic gain from the benefits of particular smart metering functions. Only when smart metering is technologically standardized can the potential economic benefits be fully realized, since every customer has access to and can utilize the same set of smart metering functions – features that have been shown to provide significant economic gains if deployed on a large scale.

•

Technical standardization further ensures interoperability between all consumers and all electrical suppliers, an issue that wasn’t a concern under the old metering system since functions were performed in person and over the phone. Because smart metering enables these functions to be done remotely via a communications channel, it is necessary to ensure technical interoperability between all parties utilizing the technology to ensure they can successfully work together. 72

The importance of standardization is reflected in the delayed implementation plans of the three suppliers in California, where the approval of the most advanced smart meter technology (SCE) is still pending, and the remaining two smart metering implementation plans (PG&E, SDG&E) have been halted to take advantage of this new standard. •

We propose that California’s electricity suppliers should meet or upgrade to the following specific technological standards for smart meters: o California should not focus on implementing all of the most advanced AMM-style metering technology. Rather, it is more economically feasible to focus on providing the more fundamental AMR-type features for customers. Features of this type provide the largest fraction of smart metering benefits as well as the highest value benefits relative to their costs of implementation. This is not to say that AMM functionality should not be included; rather, it should not be the focus. o We recommend that suppliers in California use the current temporary break in smart metering roll out to consider moving away from RF technology in favor of phone, internet or PLC technology, or to alternatively integrate RF-based meters in meshes. o Under all circumstances, smart meters should be equipped with a direct display capable of monitoring the instantaneous household consumption, since direct feedback represents the largest share of the potential savings (~18%). We also recommend using intervals of 15 minutes for information update and storage, which exceeds the current plans in place by California’s electricity suppliers. This can be realized with only a small increase in hardware and processing costs. o We furthermore recommend that indirect feedback should be provided in the form of informative billing and should include comparative information for different time periods (previous week, month, year). This feedback should refrain from comparison to reference groups. Finally, the information should be presented in a simple, graphical manner. o In addition to an indoor display providing detailed near real-time energy consumption information, California’s smart meters should also enable automated meter readings and allow customers to easily switch between suppliers, as these features have been shown to be some of the most valuable in terms of cash value. o California smart meters should include a (non-mandatory) upgrade option for disaggregated metering of single appliances and pre-payment capacities. Costly micro-generation options should be excluded at the current point because of its relatively low prevalence.

•

We recommend that suppliers provide dedicated flexible and individualized TOU pricing schemes. 73

•

While regulating the use of certain smart metering technologies may speed their initial implementation, the regulatory agencies should provide guidance only on the necessary and required capabilities and technical standardization. When delegating tasks to the other agencies, the CPUC should follow this pattern and refrain from regulating specific technologies as long as the minimum standard functional capabilities are met. For example, the specific kind of indoor display should not be specified, but rather, the information it must be able to display should be standardized.

•

The level of standardization needed for smart meter technology should be set by the regulatory authority according to the present and future structure of the electricity market. For example, because the California electricity market is unbundled, it is imperative that installed smart meters allow the electricity supplier to be changed without undue effort or expense.

•

The universal installation of smart meters should not be mandated before successful pilot projects have been completed and the technology, infrastructure and policies are adequately prepared. This is to ensure that the proper level of technical standardization is experimentally determined and any problems with the proposed implementation scenario are solved on a small scale first.

Should the interests of consumers be favored over those of electricity suppliers in the implementation of California smart metering? •

California should focus on realizing the benefits specific to its customers over that of suppliers in any smart metering implementation in order to maximize the potential economic value gained by the system as whole. This is so because the benefits to consumers have been shown to provide, by far, the greatest net cash value to the smart metering system.

•

Furthermore, unlike benefits to other smart metering stakeholders, some of the customer benefits that result from smart metering also enable general, system-wide benefits that apply to society at large. For example, smart meters may enable customers to reduce their energy consumption. This naturally leads to greater societal benefits such as energy efficiency, a reduction in CO2 emissions, and an additional incentive to invest in distributed or micro-generation – larger advantages that benefit society as a whole.

•

We recommend that smart meter implementation policy should be strongly targeted at the customer, especially during the initial roll-out phase, in order to sustain behavioral changes in the demand response of the customer. The success of smart meter technology strongly depends on individual behavioral changes, and persistent learning effects must take effect if demand response is to be a sustainable tool for energy management.

•

To help in realizing the benefits to consumers, they should be given clear financial incentives to engage in smart metering technology, and the implementation should be 74

supported by brochures, counselors, and school campaigns. All information should be articulated in a simple, preferably graphical form. Particularly strong active feedback is recommended for a period of at least 6 months.

ACKNOWLEDGEMENTSÂ The team wishes to extend gratitude to all of the people who helped with the development of this term project. The inspiring comments they made on our work assisted us in finding an appropriate focus in smart metering, which was essential in the early stages of the study. The team specifically wishes to express its appreciation to the following experts and individuals who offered guidance in the process: Amy Chiang Director of International Affairs, Office of Energy Efficiency and Renewable Energy, DOE Ernest J. Moniz Professor of Physics and Cecil and Ida Green Distinguished Professor, MIT Harvey Michaels Energy Efficiency Scientist and Lecturer, DUSP, MIT Jose Ignacio Perez Arriaga IIT/Institute for Research in Technology, Universidad Pontificia Comillas Mark Martinez Manager, Demand Response Program Dev., Southern California Edison Aideen Oâ&#x20AC;&#x2122;Hora Project Manager, Sustainable Energy Ireland Frank R. Field, III Senior Research Associate, Center for Technology, Policy and Industrial Development, MIT Junjay Tan Graduate Student, Mechanical Engineering, TPP, MIT

APPENDIXÂ Other Specific Barriers to Implementation Political Competing jurisdictions between state and federal government A frequently cited barrier to smart meter implementation is the conflict between Regional Transmission Organizations (RTOs) and state public utility commissions for control over the programs. The smart meter programs have remained primarily with the utilities, rather than as a shared responsibility with the CAISO, and the CAISOâ&#x20AC;&#x2122;s ability to become involved in it is further complicated by the existence of two regulatory agencies in the state [Faruqui and Hledik, 2007]. Lack of Load Management Standards The CPUC and CAISO currently do not have a formal rulemaking process for policies regarding adoption of load management standards under the California Energy Commissionâ&#x20AC;&#x2122;s existing authority. Invalid Customer Perceptions Oriented Rate Design Rate and program designs must be developed to better reflect the value of demand response to the electricity system and the value of consumption to customers [Faruqui and Hledik, 2007]. At the same time, the designs should be able to reflect a better understanding of customer perceptions, needs and ability to respond as well as being effectively marketed to customers. Commercial How to Minimize the Overall Costs There is a need to minimize the overall cost of the smart metering initiative in order to to ensure the benefits outweigh the costs in the long term. To achieve this, we need to analyze all significant costs involved one by one. For example, the cost of communication should be minimized steps should be taken to ensure that regulated entities participate to the fullest possible extent. Lack of Funding According to a recent FERC study, policies regarding the disbursement of state funds that were previously dedicated to energy efficiency can prove to be a significant barrier to obtaining 77

appropriate funding for DR programs [Faruqui and Hledik, 2007]. In particular, a Connecticut commissioner indicated that there was a lack of support for allocating a portion of the system benefit charge to DR programs. Similarly, in California the size of the Energy Efficiency budget is much larger than that of DR. Uncertainty/Risk Customers, retailers and manufactures have been hesitant to invest in the equipment and training necessary to implement smart meters. A FERC study cites the inherent “ boom and bust” nature of smart meter programs as an impediment to their adoption. Volatility in electricity prices has posed a barrier because Demand Response based on smart metering tends to expose customers to a greater amount of uncertainty in prices [Faruqui and Hledik, 2007]. Technical Technological Obsolescence Concerns Uncertainty in meter life expectancy and risk of post-installation technological obsolescence remain. Technical obsolescence or a short lifetime would both result in having to replace the meters before the original costs are recovered [FERC 2007]. Lack of Interoperation Standardization and Open Standards Regarding the various communication interfaces in this system, it is necessary to introduce technical standards within California for distributor business processes, such as data presentation to customers. There are technology standards on common functionality of AMI systems. In particular, ANSI C12.19 enables metering data and data tables to be transferred from one computer application system to another. The next standard, ANSI C12.22 (Protocol Specification for Interfacing to Data Communication Networks), which would enable C12.19 metering data structure to be shared over any combination of “physical” network media, is pending [FERC 2007]. Need of Further Development in Automate Demand Technology While substantial advances have been made in enabling technologies and automation, additional progress is still needed. The use of existing technologies that facilitate an d automate demand response should be integrated into program and tariffs offerings while further development of such technologies should continue. Insufficient Smart Meter Supplier Availability There are many factors that may contribute to the insufficient supplier availability, such as delayed decision making of regulatory agencies and the number of vendors chosen. How to Ensure Installation Quality 78

A sudden increase in manufacturing of smart meters under tight schedules would raise the risk of reduced quality. These issues are usually not apparent until some time after meter installation or warranty expiration. Lack of Skilled labor for Effective Installation Training of available installers may not be an issue for residential single phase metering, but could be an issue if fast deployment of complex metering is expected. Lack of skilled labor from service providers should also be a barrier. Low Market Penetration of Smart Meters of Small Customers (less than 200 kW of demand) Many of Californiaâ&#x20AC;&#x2122;s small customers do not currently have AMI, the low penetration smart meters has posed a barrier for residential customers, because it prevents providing more customers with dynamic pricing Regulatory Invalid Measurement and Evaluation Standard To accurately assess the benefits of smart meters, it is necessary to have standardized practices for quantifying and measuring the value of demand reduction. In California, while some costeffective tests have been developed, no standard has been set. The issue is being examined in a new CPUC proceeding (R.07-01-041) [Faruqui and Hledik, 2007]. A Requirement of Clear and Consistent Regulatory Framework Set up a regulatory framework for smart meters. A key concern for distributors will be recovering the cost of this large capital investment. So itâ&#x20AC;&#x2122;s necessary to develop clear costrecovery policies and procedures. Evolving Electricity Distribution System Another constraint influenceing the implementation process is the evolving structure of the electricity distribution system in California. The implementation should begin promptly to meet the governmentâ&#x20AC;&#x2122;s target installation dates Social How to Gain Customer Cooperation and Support Customer cooperation and support are essential to achieve the goals of smart meter implementation. A carefully orchestrated communication and education plan that is consistent with messages at the local levels should be executed. Customers must be shown how using the new smart metering technology can save them money. 79

Lack of Customer Awareness and Education A lack of customer education is an early barrier to smart meter implementation. Not only do customers need to fully understand the dynamic rate structure, but they should also be made aware of the financial and societal benefits of participating in the programs [Ahmad Faruqui and Ryan Hledik, 2007]. There should be a department in charge of retaining responsibility for policy decisions over the life of the project. This agency would develop and guide the communication process to ensure electricity consumers in the state have a clear understanding of the objectives of smart meters and the need to develop a conversation culture [Ahmad Faruqui and Ryan Hledik, 2007]. According to the discussion in â&#x20AC;&#x153;The State of Demand Response,â&#x20AC;? lack of customer interest and ineffective program marketing are recognized as barriers in California. There is a need to better educate customers about the costs embodied in current rates, the benefits that could come from broad adoption of time-varying and dynamic rates, the true impacts on electricity costs that would come from such a change and the options they have for responding. Many customers assume such rates would amount to rate increases when in fact utility revenue would not change. Customers whose consumption patterns reflect below average peak consumption would see bill reductions; those with above-average peak consumption would see increases that reflect the degree to which their peak consumption is currently receiving a hidden subsidy from other customers [ERGEG, 2007]. Social Diversity during implementation process Diversity in the type of customer base, demographics and telecommunications infrastructure available will require distributors to select systems that are most appropriate, cost-effective and available in their service area.

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