Chapter 14. Succeeding in the Smart Grid Space by Listening to Customers and StakeholdersWilliam Prindle and Michael KoszalkaChapter OutlineIntroduction 343What's the Difference Between DR and EE with Respect to Smart Grid Technology? 346How are Customer Benefits Typically Identified and Valued from Smart Grid, DR, and EE? 347Regulatory Review Experience with Smart Grid Deployment Proposals 350Utility and Customer Implementation Experience with Smart Grid and Related Deployment Programs 356Filling the Gaps: What Smart Grid Designers Should Focus on to Better Document Customer Benefits 366Conclusions 367References 368This chapter focuses on the field experience with smart grid programs, examines the potential for smart grid technologies and related services to provide energy efficiency as well as demand reduction benefits, and provides recommendations on program design and regulatory strategies to maximize the chances for successful deployment. It reviews macro assessments of the estimated customer benefits from smart grid technologies, and points out the practical difficulties of quantifying those benefits in real-world contexts. It also reviews the pace of smart grid technology deployment nationally, disaggregating national results to point out where deployment is lagging. It looks at the regulatory experience of smart grid deployments in three states to better understand the challenges they face in the regulatory arena. It then examines field experience of customer offerings, both meta-reviews and three specific program examples in Massachusetts, Washington, DC, and California. Drawing on the lessons learned from these deployment experiences, it concludes with a set of principles to guide smart grid deployment strategies.Smart grid, customer response, customer behaviorIntroductionThis chapter reviews the field deployment experience of programs that seek to deploy smart grid (SG) technologies to support the peak reduction goals of demand response (DR) and the energy savings goals of energy efficiency (EE). It seeks to distill lessons learned, both in program design/implementation and in the process of gaining regulatory approval, and in so doing to provide smart grid stakeholders the benefit of this experience. The chapter's objective is to help make smart grid deployments in the future more successful, in terms of both customer acceptance and regulatory approval.Smart grid is defined by the Electric Power Research Institute as follows1:1Hauser & Crandall offer a more extensive discussion of smart grid definitions, goals, and desirable attributes.The term Smart Grid refers to a modernization of the electricity delivery system so that it monitors, protects, and automatically optimizes the operation of its interconnected elementsfrom the central and distributed generator through the high-voltage transmission network and the distribution system, to industrial users and building automation systems, to energy storage installations, and to end-use consumers and their thermostats, electric vehicles, appliances, and other household devices. (EPRI, 2011)Smart grid technologies are best viewed in a system context. In such a framework, one might view Smart Grid technologies in terms of what they enable. Smart Grid technologies are expected to enable the following kinds of actions, improvements, and related benefits:Increase customer participation in energy usage. The smart grid can provide consumers information that helps them modify how they use and purchase electricity. It can provide them choices, incentives, and disincentives in their purchasing patterns and behavior, which in turn can help drive new technologies and markets.Accommodate diverse generation and storage technologies. These power generation options range from centralized power plants to distributed energy resources (DER) such as system aggregators, grid-scale power projects like wind farms, and building-scale DER such as solar PV or combined heat and power (CHP) systems. Storage systems of various kinds would also be integrated into a mature smart grid system.Enable markets for new products and services. A smart grid can help enable markets that give consumers greater access to competitively provided energy and related services, from unregulated power purchasing to enhanced information, communication, and control features.Improve power quality. Smart grid technologies, if deployed in an integrated power grid, can improve the reliability and quality of power supply. With digital technologies increasingly ubiquitous, uninterrupted power supply with consistent voltage, frequency, and related characteristics is increasingly important to individual homes and business operations as well as the productivity of the economy as a whole.Improve utility system asset utilization and operating efficiency. A smart grid helps manage customer loads and system assets in a more coordinated fashion, such that the system can provide more useful energy services from its total asset base. It also reduces system inefficiencies and operating costs.Minimize outages and system disruptions. A smart grid can be self-healing to a greater extent than current power grid technologies permit. It identifies and reacts to system disturbances, using largely automated mitigation methods that enable problems to be isolated, analyzed, and restored with little human interaction. It can use predictive analysis to detect existing and future problems and initiate corrective actions.Improve system security and resilience. Smart grid designs can resist both physical and cyber attacks. Sensing, surveillance, switching, and intelligent detection, analysis and control software can be built into grid operations to detect and respond to threats. This can make grid systems more resilient, with self-healing technologies that can respond faster and with less impact to human-made and natural incidents.Another way of looking at these SG benefits from the utility perspective is to list the potential value propositions to the utility, including enabling a host of functionalities, features, and services that are not currently feasible: Dispatchable load Generation investment deferral Reduced need to raise capital Increased diversity of the supply portfolio Reduction in net power costs Non-spinning reserves Market price mitigation (wholesale) Customer satisfaction improvement Cold load pickup during power restoration (dispatch event or power outage) Voltage response Frequency response Reduction in the risk to system reliability Load shifting Transmission investment deferral Distribution investment deferral Reduction in emissions Reduction in line-losses Shorter power outages from faults or other causesBecause several other chapters give more detailed treatment of these issues, we only include this list here.This chapter focuses on how utilities and other stakeholders can learn from early smart grid deployment experience, fill the gaps in knowledge and program features needed to demonstrate greater net benefit to customers, and advance to the next generation of smart smart grid customer offerings. The definitions and goals outlined above embrace a wide range of utility system technologies, from digital switching in transmission systems to digital metering in customer premises, with distribution automation and other technologies in between. In the simplest terms, SG technologies are electronic, capable of two-way operation, capable of some automated functions, and may have some IT-based intelligence capabilities for sensing, reporting, and controlling electricity system components. For the most part, SG technologies are viewed as utility-owned assets, and the only SG technologies that directly touch customers are digital metering devices.However, it cannot be said that digital meters touch customers unless they are used to provide additional information, sensing, or control features. The establishment of a two-way communication system via SG technologies provides the opening for the marketplace to provide new technologies and devices that can aid consumers' management of their energy use and cost. Other chapters, includingChapter 16go beyond the meter, andChapter 15discusses the set and forget technology options. We therefore do not provide much detail on the technology content of customer offerings, except to the extent it helps demonstrate customer benefits or the ability of a given program strategy to gain market acceptance and regulatory approval.This chapter contains the following sections: What's the Difference Between DR and EE with Respect to Smart Grid Technology?: Differentiating energy efficiency and demand response with respect to smart grid technology How are Customer Benefits Typically Identified and Valued from Smart Grid, DR, and EE?: How customer benefits are defined in smart grid customer offerings Regulatory Review Experience with Smart Grid Deployment Proposals: Recent regulatory experience with smart grid deployment Utility and Customer Implementation Experience with Smart Grid and Related Deployment Programs: Recent implementation experience with smart grid deployment Filling the Gaps: What Smart Grid Designers should Focus on to Better Document Customer Benefits: Filling the gaps in smart grid strategy and program design ConclusionsWhat's the Difference Between DR and EE with Respect to Smart Grid Technology?Demand-side management, or DSM, is the collective term used to describe non-generation demand side (or distributed) resources. Energy efficiency and demand response are subsets of these DSM resources and have their own delineations as well. From a utility perspective, DR and EE are very different resources. Defining precisely the difference between demand-side and supply-side resources is challenging as there are many variations in what constitutes demand response.All KWh are equal, but some KWh are more equal than othersThe National Action Plan for Energy Efficiency's report on the coordination of energy efficiency and demand response contrasts EE and DR in this way:Energy efficiency refers to using less energy to provide the same or improved level of service to the energy consumer in an economically efficient way; it includes using less energy at any time, including during peak periods. In contrast, demand response entails customers changing their normal consumption patterns in response to changes in the price of energy over time or to incentive payments designed to induce lower electricity use when prices are high or system reliability is in jeopardy[1].Figure 14.1is an effort to define the various types of demand response resources. It can be found in many similar forms in the literature. DR is divided into two major types: those that are dispatchable and can be implemented in the ancillary services market, and those that are not dispatchable. Dispatchable DR resources have a known or very precisely predicted result when dispatched as would a generation resource. SG technologies can facilitate greater adoption of these various DR products as supply-side operators would refer to them.

Figure 14.1The relationship between DR and EE in a DSM portfolio.Source: NERC[2]

How are Customer Benefits Typically Identified and Valued from Smart Grid, DR, and EE?A recent EPRI report (EPRI 2011) provides an electric industry perspective on valuing the benefits and costs of smart grid technology. It covers the full range of smart grid technologies, including transmission, distribution, and customer-level technologies. This analysis estimates a total cost of $338476 billion, and total benefits of $1.32 trillion, yielding a benefit-cost ratio in the range of 2.86.0.Direct benefits to customers, however, are harder to pinpoint, coming from several different streams, which can be difficult to compare in the same time and value framework. For example, benefits related to enhanced energy efficiency are estimated as shown inFigure 14.2in the range of $.421.76 billion. These benefits are projected for a single year2030. However, the other major stream of benefits that can be linked closely to customersreduction in customer service costs such as meter reading, service connection and disconnection, and billing and call center operationsare estimated over 20 years, inFigure 14.3as $97.8 billion. EPRI also estimates avoided generation benefits of $192 billion to $242 billion in the 20102030 period.

Figure 14.2Value of smart grid energy efficiency benefits.Source: EPRI 2011

Figure 14.3Advanced metering utility cost reduction benefits.Source: EPRI 2011

Customer-related costs are estimated by EPRI to fall in the range of $24 billion to $46 billion. However, the cost recovery period for these costs depends on their regulatory treatment; utility commissions have to decide how quickly these costs can be recovered, and how the asset value is treated. The customer cost impact of treating AMI costs as any other rate-based asset through a general rate case could result in a longer-term cost recovery period. Special cost recovery riders, as proposed in several AMI initiatives, may have shorter cost recovery periods related to the shorter expected lives of the equipment. These and other regulatory treatment issues, including shareholder returns on rate-based assets, will strongly affect the costs that customers experience in a given year.It can thus be difficult for regulators to fully capture and align benefits and costs of smart grid investments in a single regulatory proceeding.2Costs are known quantities, so customers and their intervenors can see those in filed documents and will experience them soon after the proposal is approved. Benefits, however, typically flow unevenly, both across time and across different customers and customer classes. Deferred generation benefits, as well as some energy efficiency and DR benefits, may appear years later and are not guaranteed to occur, while costs are seen by customers as certainties that are incurred now. So depending on how specific streams of benefits and costs are treated in a given regulatory proceeding, regulators may not find utility smart grid proposals compelling in terms of direct, near-term benefits to customers. These issues are explored further in the section below on regulatory treatment of smart grid deployment proposals.2SeeChapter 4for a fuller discussion of equity and other issues revolving around allocation of costs and benefits.Regulatory Review Experience with Smart Grid Deployment ProposalsSmart grid technologies present a set of new challenges to regulators in making decisions regarding smart grid investments. U.S. electricity systems have largely operated at high reliability levels at the transmission level, though distribution system reliability varies. But as long as the lights stay on and rates remain relatively low, it can be difficult for policymakers to understand how smart grid technologies can improve the value of electricity systems. It can also be challenging to understand the incremental value of smart grid investments, as they are often implemented in stages, with each stage requiring regulatory approval. But many smart grid benefits come from the combined and cumulative effects of a portfolio of smart grid technologies over time. The Illinois Commerce Commission summarized this conundrum recently (ISSGC, 2010):The issue of smart grid cost recovery has been a matter of controversy and litigation for several years. Disagreements exist about whether recovery of a utility's smart grid costs should be restricted to the traditional rate-base method, or whether a non-traditional method (e.g., rider recovery) should be used. Some stakeholders are concerned that utility proposals for cost recovery of smart grid investments would lead to significantly higher monthly bills and a shift in the risk of investment from utilities to ratepayers. Others believe that non-traditional cost recovery would be essential to accelerate deployment of smart grid technologies.Despite these challenges, smart grid technology deployment is proceeding apace. The FERC's 2010 report on AMI and Demand Response (FERC 2011) shows that AMI has been deployed to 8.7% of total U.S. electric meters as of 2010, up from 0.7% in 2006 and 4.7% in 2008. The FERC report, however, also shows substantial unevenness in the penetration of AMI technology: Investor-owned utilities (IOUs) lagged the national average, showing a total of 6.6% AMI penetration, compared to penetration rates above 20% for rural electric coops and public power districts. States showed a wide disparity of AMI deployment: only five states (AZ, OR, ID, WI, PA) exceeded 20% AMI penetration, while the majority of states (29) showed AMI penetration at less than 5%.The fact that IOU AMI penetration lags the national average is a concern, because IOUs serve some 75% of total customers. And the unevenness of state action indicates widespread resistance to universal AMI deployment, even as several states move ahead rapidly. These data suggest that unless some of the issues restraining AMI deployment are resolved, the rapid growth of AMI in the last 5 years may slow or even plateau. In fact, the FERC data indicate a slowing in the growth rate in AMI deployment in the 20082010 period compared to the 20062008 period, from a nearly ninefold increase to just under a doubling. While the more than $4 billion in federal stimulus funding is estimated to support the deployment of some 18 million additional advanced meters, even the availability of federal grant funds has not fully overcome state-level concerns about the net benefits of AMI (see Maryland case below).Three recent smart grid/AMI deployment case studies serve to highlight the regulatory, perceptual, cost, and process issues that can stymie otherwise promising projects:Maryland. Baltimore Gas & Electric (BGE's) 2010 proposed AMI deployment plan was initially rejected by the Public Service Commission (PSC); after responding to PSC and stakeholder concerns, a modified proposal was ultimately approved[3]. The original proposal cost $835 million for deployment of over 2 million meters, with an immediate cost recovery surcharge mechanism, and mandatory TOU pricing for all customer classes. Part of the urgency for this proposal was a federal stimulus grant BGE had been awarded, which would have covered some $136 billion of AMI costs; the Department of Energy had asked for an August 2010 approval from the PSC as a condition for grant funding.The issues raised by the Maryland Office of People's Counsel (OPC) summarize the concerns relating to demonstration of benefits to customers[4]: About 20% of the benefits in the original proposal were based on BGE operational savings in meter reading and operations, and in distribution management costs. The other 80% of benefits were projected in terms of capacity revenues from wholesale market forward-capacity markets, reduced wholesale prices that would reduce future standard offer rates, reduced energy bills as an effect of dynamic pricing and customer feedback, and reduction in T&D infrastructure costs. OPC pointed out that these 80% of projected benefits were subject to considerable uncertainty, and they depended heavily on customer response to price signals and on future wholesale energy and capacity prices. In 2010, wholesale market prices in the PJM power market had shown signs of softening due to the recession; this shift tended to support the OPC argument that such factors are uncertain. OPC strongly objected to the cost recovery surcharge element of the proposal, asserting that it places all of the risk on ratepayers, with no comparable guarantee of benefits. OPC rejected the mandatory TOU pricing element of the proposal, stating that it imposes higher bills on some customers, and that BGE did not include in its proposal any customer-enabling technologies that would help them respond to TOU prices, such as in-home displays or automated appliance control devices. OPC also objected to the proposal on the grounds that it would remove consumer protections by enabling remote service disconnects, and also raised customer privacy and security concerns that have not yet been fully addressed by national efforts.The PSC largely agreed with OPC's objections in its initial order, stating:The Proposal asks BGE's ratepayers to take significant financial and technological risks and adapt to categorical changes in rate design, all in exchange for savings that are largely indirect, highly contingent and a long way off. We are not persuaded that this bargain is cost-effective or serves the public interest, at least in its current formThe Proposal is a no-lose proposition for the Company and its investors. (MD PSC Order No. 83410. June 21, 2010, pp. 1, 3)In response to the PSC's initial decision, BGE revised its proposal to remove the automatic cost recovery surcharge, treating the project's costs as a regulatory asset to be recovered through subsequent proceedings, much like any rate case. It also removed the mandatory TOU pricing element, and included an expanded customer education and outreach element. The PSC approved the revised proposal later in 2010. For comparative purposes, the PSC approved Pepco's AMI proposal, which also included a federal grant cost offset, in large part because it did not include a special cost recovery mechanism or mandate TOU pricing. This tends to support the inference that guaranteed cost recovery without risk or cost sharing between customers and shareholders, and the imposition of mandatory time-based pricing, can be significant obstacles to AMI deployment.OPC also raised the issue that alternative ways to meet utility peak load reduction and system operations goals can be less expensive and less burdensome on customers. While this issue did not become a central point in the BGE case, it has been raised in other states, and can be a critical issue in some situations. For example, in New Jersey the Department of Public Advocate commissioned a study[5]on utility AMI deployment, which focused largely on alternative approaches to meeting the stated goals of the utility AMI deployment proposals. Key points raised in this report include: Automated metering reading (AMR) is a less expensive way to obtain a large fraction of the benefits of AMI. Though limited in functionality (may not have hourly reading capability or two-way communication potential), AMR has been deployed by several utilities successfully as based on avoided meter reading and operations costs. If AMR is in place, the benefits of AMI deployment become much harder to justify, as indicated in the Brattle Group's analysis for the Institute for Electric Efficiency (IEE, 2011, p. 13). Direct load control (DLC) and related utility load management programs can serve to achieve the peak load reduction benefits of AMI deployment. Utilities have been conducting DLC programs cost effectively for many years. The Synapse report further analyzed the dependence of forecast AMI benefits on three key factors: the average load reduction per customer, percentage of customers participating in dynamic pricing, and the long-term persistence of savings. Synapse pointed out that utilities' estimates for customer participant in dynamic pricing were more than double historic participation rates for DLC programs around the country.Illinois. Commonwealth Edison planned one of the most thoughtfully designed smart grid pilot projects yet conceived, testing a variety of rate designs, information services, and other features in a large sample of some 130,000 customers. Com Ed filed its application with the Illinois Commerce Commission (ICC) for a $360 million pilot program. In late 2008, the ICC approved $274 million in AMI cost recovery charges for the pilot through a special rate rider. Because the ICC had disallowed some of its costs from the 2007 application, the utility initiated an appeal with the Illinois Appellate Court, mainly on matters related to labor costs. This triggered a number of interventions in the appellate court case, including the Illinois attorney general and Citizens Utility Board3(CUB), objecting to the ICC's approval of the special cost recovery rider. As was the case in Maryland, consumer representatives objected to the accelerated, automatic cost recovery features of Com Ed's cost recovery mechanism. The appellate court case turned into an expanded version of a full-blown ICC adjudicatory proceeding. In 2010, the appellate court struck down the ICC's 2008 decision, leaving Com Ed's pilot and its entire smart grid initiative in regulatory limbo[6]. In its 2011 session, the Illinois legislature sought to resolve some of these issues through legislation. As of May, however, the governor was threatening to veto the bill, and the situation remained unresolved at this writing.3SeeChapter 16.While this case may reflect the nature of Illinois politics more than the merits of smart grid technology, it does reinforce the core point of the Maryland PSC's treatment of BGE's original AMI application, in which the utility's original special rate rider/surcharge mechanism was rejected as forcing ratepayers to take all of the risk and front all of the costs for smart grid deployment. The lesson that may lie at the core of both of these case studies is that for regulated utilities, especially in states with a history of vigorous consumer representation, smart grid proposals are likely to be more successful if they defer cost recovery to future rate cases or use other methods that give stakeholders more opportunity to advance their views.Colorado. The Boulder SmartGridCityproject has been widely heralded as an innovative smart grid experiment. Working with the city of Boulder, one of the greenest municipalities in the United States in its commitment to clean energy and environmental protection, Xcel worked with its business partners, including Accenture, Gridpoint, Landis and Gyr, and Current Group, and other stakeholders to design a state-of-the-art program, using fiber-optic technology as part of its AMI deployment. Xcel conducted extensive customer research via surveys and focus groups to help define the kinds of offerings customers would prefer. Fifteen thousand Landis and Gyr advanced meters were ordered for residential installation beginning in 2008; the vision was ultimately to include some 50,000 customers in the program[7].SmartGridCitywas designed as an inclusive vision: it was to include new renewable energy sources connected to the grid, such that customers could choose low-emission power pricing plans. It allowed for electric vehicle recharging, and included utility-side upgrades for substations, feeders, and distribution automation hardware and software. In the original plan, customers were to be offered: Advanced meters that communicate with home appliances for energy and cost savings Energy efficiency incentives integrated with the program Online tools for tracking energy use and making changes to fit their lifestyle and efficiency goal The ability to automatically manage energy use based on real-time price signals or green-power price signals Charging options for plug-in hybrid electric vehicles Automatic outage notification Automated load management options to reduce peak load and prevent outages The ability to choose on-site renewable energy options like wind, solar, and batteries Web-based tools to support the above features, including: A control portal: to set use preferences for major appliances and household outlets. An analysis portal: for secure access to usage information and analysis options. An information portal: to educate customers about reducing costs and lowering their carbon footprint.Customer choice was part of the program design, such that customers would be able to (1) select a plan that works for them, (2) specify their personal plan parameters, and (3) monitor and control their energy use.Xcel did not initially propose to recover costs from its ratepayers using special rate riders or other mechanisms that resulted in regulatory controversy in Illinois or Maryland. The project was viewed primarily as a research and development initiative, and the company did not feel compelled to require official approval or cost recovery from the Colorado Public Utility Commission (PUC). However, the project ran into cost overrun problems: Xcel originally anticipated that capital costs would be around $15.3 million in early 2008, but in May 2009, it revised the number to $27.9 million, and in 2010 to $42.1 million. PUC staff estimate that total costs will exceed $100 million. As the costs mounted, the PUC ruled that Xcel would be required to apply for a Certificate of Public Convenience and Necessity (CPCN), which will give the PUC authority to regulate the project, including its cost recovery. As that proceeding has unfolded, the City of Boulder has asked to be removed from the proceeding, partly to protect itself from exposure to cost recovery[8].The PUC in December 2010 approved an Xcel rate increase, primarily to pay for a new unrelated coal-fired facility. But $11 million of this increase is to cover Boulder smart grid costs. How the remainder of costs are to be recovered remains to be soon; possibilities include the City of Boulder and its customers, all Xcel customers, Xcel's business partners, and Xcel shareholders. PUC staff were quoted in 2010 as saying it is difficult to ascertain what portion ratepayers should bear, if any.The program is in operation, with meters installed and many of the planned services available. The company continues to use it as an R&D project, However, the cost issue has placed a shadow over the project. A significant part of the cost overruns appears to stem from unexpected costs for fiber-optic line installation. Xcel's PUC filing in May said that more underground fiber had to be laid than expected, and that installation costs rose due to having to drill through granite with diamond-tipped drill bits and remove large boulders with cranes and dump trucks SmartGridCityturned into a major infrastructure construction effort, using technologies with which there was little local experience. This may in hindsight have been a weakness in the program design. Difficulty in predicting and controlling costs always creates risks in a new project. And yet the project was deliberately intended to test new technologies, so there may have been no other way to find out what the challenges and the costs would be. The difficulty for Xcel was that costs rose high enough to trigger regulatory review. In hindsight, the company might have conducted the project through an unregulated organization structure. Perhaps the principal takeaway is that risks and costs for smart grid technology, as for any new technology, can be uncertain and substantial, and that risk management should be part of the planning process.Another takeaway from the Boulder project, again benefiting from hindsight, is that many of the customer benefits could have been tested and demonstrated prior to installation of the core infrastructure. Enhanced information and feedback, customer engagement and goal-setting, and even customer device control can be piloted without AMI deployment. Running a series of smaller pilots and field tests for such customer-side elements prior to full construction mode for the core infrastructure might have created an experience base that could have built confidence in the benefits of AMI-based customer offerings. Such a base might help weather later challenges in the technology deployment process.These three cases, in which AMI deployment has met significant regulatory complications, were not selected to cast a negative light on smart grid technology or its prospects. They were chosen rather to illustrate the challenges that smart grid deployment faces in traditional regulatory structures. Like it or not, in many states these kinds of challenges are likely to emerge, and utilities and other smart grid proponents can learn from these experiences. Key lessons that can be drawn from these cases include:Share risks and costs. The MD PSC made it clear that the initial BGE submission put too much of the cost and risk burden on customers, and the IL court decision seems to reinforce that point.Demonstrate benefits before seeking cost recovery. The MD PSC ultimately accepted BGE's revised proposal when it sought to recover costs after deployment. Even though BGE had run an AMI pilot and showed some benefits from that, the PSC did not see a strong enough case for systemwide ratepayer cost recovery prior to deployment.Don't mandate time-based pricing for smaller customer classes. This may not be an issue in every jurisdiction, but in many states consumer advocates have made strong cases against class-wide pricing plans that involve critical-peak pricing, time-of-use pricing, or other rate structures that tie prices to time of use. This implies that such pricing plans will have to be marketed actively to gain the high market penetration rates needed to fully realize the benefits of smart grid technology, but if this is the path to initial regulatory approval, then that may be the reality smart grid deployment faces in many states. This approach may actually be helpful in the long run, as it could force utilities to learn more about customers, market segments, customer preferences, and the specific bundles of technologies and services that will catch on in various segments.Utility and Customer Implementation Experience with Smart Grid and Related Deployment ProgramsDeployment of smart grid technology, especially in the form of advanced metering, is beginning to be seen on a wide scale, as the FERC report cited above indicates. We have reviewed a selection of the ample literature of utility and customer experience with smart grid and related customer offerings from which we seek to distill a few key lessons learned, and to glean insights for the future of smart-grid-based offerings.Pilot programs and other initial field experience with smart-grid-related customer offerings tend to show that customers reduce energy use as well as peak demand. Most of this experience comes from dynamic-pricing-based offerings, though some also include customer feedback and control options. For example: King and Delurey's[9]meta-review found that dynamic pricing produced average savings of 4% of annual energy use. However, reliability-oriented demand response programs reduced energy consumption by only 0.2%, largely because event-driven programs are activated well under 100 hours per year. Information/feedback programs showed stronger savings effects, up to 11%; these typically give customers usage information via the internet or in-home displays but do not involve direct load control. They also found that savings varied greatly, from 5% to 20%, which serves to warn against placing predictive value on these results. ACEEE's[10]meta-review of 36 customer feedback programs in North America, Europe, and Asia found that energy savings can range from 3.8% to 12%.Figure 14.4illustrates the results for the five categories of programs analyzed. The first two categories, enhanced billing and estimated feedback, do not require advanced metering, and so are not dependent on smart grid technology. The three highest categories of savings, however, come from programs that require AMI as a minimum; the highest savings category involves real-time feedback down to the device level. As with King and Delurey, however, the sample size is not large enough to be used for predictive purposes. The National Action Plan for Energy Efficiency[1]report on utility rate design included a review of the energy savings impacts of several recent dynamic pricing programs. Those results are summarized inTable 14.1; it shows annual energy savings as high as 7.6%, occurring in the Ontario Hydro One pilot, which combined AMI with in-home displays (IHDs) in half the participating homes. Savings in homes without the IHDs averaged 3.3%, less than half the IHD group. The literature search for this report also reflected a consistent theme in smart-grid-related field programsrelatively few of them measure annual energy savings data. This is understandable to the extent that the purpose of the program was peak demand reduction, not annual energy savings. But given the challenges facing smart grid deployment in terms of documenting customer benefits, it is vital that more data be collected on the annual energy savings impacts of smart-grid-based customer offerings.

Figure 14.4Energy savings from customer feedback programs.Source: ACEEE[10]

Table 14.1Energy and Demand Savings from Dynamic Pricing Programs

Sources:California Statewide Pilot: George et al. (2006); Gulf Power Company: comments from Ervan Hancock III, Georgia Power Company; Ontario Energy Board: Hydro One (2006); Community Energy Cooperative: Summit Blue Consulting (2004); and NAPEE[11].

ProgramRate/Price TypeLocationCustomer Type/Load SizeParticipantsCustomer IncentiveDurationPeak Demand ReductionsEnergy Savings

California Statewide Pricing PilotCPPSouthern California Edison Service AreaCommercial/industrial