Modernizing the Electric Power System to Support the Development and Deployment of Increasingly Clean Technologies
Developing and deploying cost-effective increasingly clean energy technologies will require an electric power sector with systems, regulation, and infrastructure that encourage and accommodate those technologies. Developing such a power sector will, in turn, require technological changes to the power system and fundamental changes in the regulation and operation of electric power utilities. Power systems—the electric power transmission and delivery grids—will need to become capable of integrating new technologies and in greater quantities. To achieve this goal, regulators will need to implement regulations that give utilities incentives to become fully engaged in innovation and the demonstration of new technologies, with rules that permit reasonable and nondiscriminatory access to the transmission and delivery systems.
Since the restructuring activities that began in several states in the 1990s, the electric power industry has been under pressure to change in a number of ways. While restructuring efforts mostly stopped by the early 2000s, several states enacted policies to encourage higher adoption rates of specific increasingly clean power generation technologies, principally for electricity from renewable sources. The growth of renewable and distributed energy resources, the expansion of energy-efficiency programs, slowly growing or declining utility sales, low natural gas prices, and the need to invest in the grid to maintain its reliability and security have prompted consideration of the significant changes in utility technical, business, and regulatory models needed to facilitate the truly wide-scale adoption of increasingly clean power technologies. However, the industry is in the early stages of evaluation of these changes. Investors will not fund the development of increasingly clean technologies without a realistic opportunity to capture market share and earn economic profits as these options become cost-effective. Current utility
technical, business, and regulatory models present barriers to the development of new technologies and the entry of new firms, especially in the case of distributed and variable generation technologies. This chapter describes such barriers and the opportunities to develop new regulatory frameworks and business models that could both improve industry performance and create opportunities for increasingly clean energy technologies while enhancing the customer experience and delivering value for both customers and investors. The transmission and delivery systems are both complex, and present many challenges and opportunities; the emphasis here is more on distribution and distributed and variable resources, with some coverage of transmission.1
This chapter begins with a brief review of the challenges and opportunities currently faced by the U.S. electric power industry. It then describes the current electric power system—its structure and its regulatory framework. Finally, the chapter lays out the features of a modern power system that would support the development and deployment of increasingly clean energy and energy-efficiency technologies.
The electricity industry is facing significant new expectations and requirements to replace aging infrastructure, mitigate the effects of storms and other disruptive events, secure the electric system and critical infrastructure that depends on electric power against cyber and physical attacks, and maintain system stability. At the same time, the industry is dealing with retiring coal and some nuclear generation and integrating variable large-scale renewable and distributed resources. Moreover, current utility business models often rely on volumetric increases in sales to provide funds for new investments. With slowly growing or declining sales, many utilities lack the revenue growth used historically to fund new investments. This trend could leave the nation with an outdated power system and prove costly to consumers.
1 The full suite of issues surrounding transmission (and delivery) could take up an entire report on its own. The committee notes that at the time of this writing (summer 2016), another National Academies of Sciences, Engineering, and Medicine study was under way that was charged with examining how the transmission and delivery systems can evolve to become more reliable and resilient, including “greater reliance on distributed power generation.” Readers are encouraged to consult the report of that study once it becomes available.
Much of the existing U.S. electric power infrastructure was built more than 40 years ago and is in need of replacement and modernization. The American Society of Civil Engineers (ASCE) estimated in 2011 that maintaining this infrastructure would require $673 billion in new investment by 2020. To put this figure in perspective, the total market capitalization of U.S. investor-owned utilities equaled $504 billion as of December 31, 2013 (EEI, 2014). ASCE forecasts significant economic consequences if the electric sector fails to close the investment gap:
As costs to households and businesses associated with service interruptions rise, GDP will fall by a total of $496 billion by 2020. The U.S. economy will end up with an average of 529,000 fewer jobs than it would otherwise have by 2020….In addition, personal income in the U.S. will fall by a total of $656 billion from expected levels by 2020. (ASCE, 2011, p. 20)
In its 2013 report on the state of America’s infrastructure, ASCE notes a recent decline in investment in electricity distribution systems. It reports that aging equipment has resulted in an increasing number of power disruptions and that “significant power outages have increased from 76 in 2007 to 307 in 2011” (ASCE, 2013, p. 61; see also EPRI, 2013). More than 90 percent of customer service interruptions can be the result of distribution outages.
Increasing Reliability Problems and Outages
Electric utilities experienced an increasing number of weather-related outages from 1992 to 2012 (Executive Office of the President, 2013).2 Such outages cost the U.S. economy between $25 billion and $70 billion per year (Campbell, 2012; Hines et al., 2009). These costs could rise with increasing reliance on information and communication systems as well as digital devices and control technologies that depend on access to reliable sources of electricity. The costs also could rise with the evident increase in the frequency of severe weather events. A power outage can impact the economy of an entire region, as illustrated by Superstorm Sandy, which caused outages for more than 8 million customers in 21 states and an estimated $65 billion in damages. These outages left fuel pumps at gas stations unable to function and curtailed operation of the Colonial Pipeline, which brings refined petroleum products from the Gulf of Mexico (DOE, 2013). And the high cost of power outages to consumers is
apparent from the growing number of customers that have installed their own backup means of power generation. It has been estimated that more than 12 million commercial and industrial customers have installed more than 200 gigawatts (GW) of backup generating capacity (Gilmore and Lave, 2007), while the penetration of residential distributed generation is growing by more than 20 percent per year, with an estimated 3 percent of residential customers having installed backup generators (Generac, 2014).
Electric utilities also have been placed on the front lines in defending the power system from cyber-security and physical attacks. The Department of Homeland Security’s Industrial Control Systems Cyber Emergency Response Team (ICS-CERT) reported responding to 198 cyber incidents in fiscal year 2012 across all critical infrastructure sectors. Forty-one percent of these incidents involved the energy sector, particularly electricity (DHS, 2013). Most experts agree that the risk of a significant attack on the power system is significant, and its consequences could be large (see, e.g., Dlouhy, 2013). The 2003 Northeast blackout was an example of “the failure of a software program”—in this case “not linked to malicious activity”—that left operators unaware of system conditions and “significantly contributed” to a region-wide power outage. The operators’ lack of awareness and resulting failure to return the system to a reliable state helped create conditions in which tree contacts with transmission lines would ultimately trigger the outage (U.S.-Canada Power System Outage Task Force, 2004, p. 131).3 The blackout impacted more than 50 million people and cost the U.S. economy an estimated $6 billion.4 A large-scale cyber attack or combined cyber and physical attack could potentially have even greater costs, triggering sustained power outages over large portions of the electric grid and prolonged disruptions in communications, food and water supplies, and health care delivery. The investment requirements associated with tracking and mitigating security risks are substantial and will increase as understanding of these risks continues to evolve.
Significant Growth in Distributed and Variable Generation Capacity
Utilities are seeing significant growth in customer-sited, distributed generation. Combined heat and power (CHP) has reached significant scale in the
3 While the information system failures in this case were not the result of a malicious attack, the task force nonetheless found “potential opportunities for cyber system compromise of Energy Management Systems (EMS) and their supporting information technology (IT) infrastructure,” and supported new cyber and physical security standards.
4 The Department of Energy estimated costs of $6 billion—close to the $6.4 billion midrange estimate prepared by Anderson Economic Group. For a summary of estimates of the blackout’s costs, see Electric Consumers Resource Council (ELCON) (2004).
United States—more than 80 GW in 3,700 industrial and commercial facilities (DOE and EPA, 2012). While the rate of development of these facilities declined after 2005 when the Federal Energy Regulatory Commission (FERC) lifted the requirement of the Public Utilities Regulatory Policy Act that utilities in competitive markets purchase power from these facilities, CHP installations are once again increasing. An additional 870 megawatts (MW) of CHP generation was added in 2012, with a further increase estimated to have occurred in 2013 (BNEF, 2014b; Chittum and Sullivan, 2012). In an August 2012 executive order, the White House targeted a further increase of 40 GW by 2020 (White House, 2012). Rooftop solar photovoltaic (PV) systems added 1,458 alternating-current MW in 2014 and 2,158 alternating-current MW in 2015 (EIA, 2016i).5 Distributed generation imposes new investment, control, and protection requirements on distribution systems that historically were designed for one-way power flow to customers.
In addition to distributed generation, total capacity additions of solar (which includes rooftop solar PV, utility PV, and solar thermal) and wind added nearly 10,000 alternating-current MW in 2014, representing 27 percent and 26 percent of U.S. electricity generation capacity additions in that year (EIA, 2016i). These additions to capacity are driven in part by public policy and utility rate designs that recover a portion of fixed costs through kilowatt hour (kWh) charges (EIA, 2014i). The rebound in wind capacity in 2014 was likely driven by the extensions and modifications of the federal production tax credit (PTC) (EIA, 2016i). In 2003, renewable resources other than hydroelectric represented less than 2 percent of U.S. power generation capacity; by 2012, these sources—primarily through the growth of wind and solar—represented more than 7 percent of generation capacity.
Variable resources create significant integration and investment challenges. For example, the California Independent System Operator (ISO) forecasts that by 2020, the combination of a reduction in solar output and an increase in demand in the evening could produce as much as a 13 GW increase in net load on its system over a 3-hour period (California ISO, 2013). Such rapid changes in net demand would have to be offset by significant additions to flexible generating capacity, storage, or responsive demand. Additionally, a future power grid must be built to accommodate continuous changes in wind and solar generation as wind speeds change and clouds pass overhead.
Financial Challenges for Utilities
Electric utilities have increased their total capital expenditures since 2007. However, that increase has had a negative impact on their cash flow. In 2013,
5 The Energy Information Administration (EIA) collects electric capacity data in alternating-current megawatts. Solar PV generators produce electricity in direct-current megawatts. Generally, PV systems are associated with an AC-to-DC ratio of between 80 and 90 percent (EIA, 2014c).
capital expenditures and dividends of investor-owned electric companies (IOUs) exceeded net cash from operations by $23.5 billion. Over the period 2007 to 2013, IOUs posted a net cash deficit of more than $155 billion (EEI, 2014). Although utilities have been able to finance this deficit during a period of relatively favorable interest rates, whether the industry will be able to sustain the required pace of investment is unclear. As of the first quarter of 2016, 36 percent of electric utilities had a Standard and Poor’s credit rating of BBB or lower (EEI, 2016).
As discussed in earlier chapters, electric utilities also are facing slowly growing, flat, or declining sales. Total U.S. electricity sales declined by 0.1 percent in 2013 and have fallen in 5 of the last 6 years. The Energy Information Administration (EIA) and many utility load forecasters are predicting less than 1 percent growth in electricity consumption (EIA, 2014j), continuing a long-term decline in the growth of electricity demand that began in the 1950s (Barbose et al., 2013; EIA, 2012; Faruqui, 2013). Many factors are likely to continue limiting growth in electricity sales, including expanded energy-efficiency programs; revisions to state and federal efficiency codes and standards; the falling cost and associated growth in customer-sited PV generation; growth in gas-fired CHP generation; and fuel switching from electricity to natural gas for certain heating, cooling, and industrial process applications.
Most utility costs for electricity distribution are fixed and represent investments in poles, wires, and other equipment or systems. In the conventional regulatory model, fixed costs often are recovered through volumetric rates charged on a per kWh basis. Slowly growing or declining sales remove a key source of revenue for new investment, while new investments tend to produce increases in customer rates. These higher rates can further depress sales, eventually creating a self-reinforcing cycle that could over time undermine the conventional utility business model (Kind, 2013).
While the challenges facing the electric power industry are substantial, there are also significant opportunities for improvement.
Improved Reliability through Distributed Resources
Distributed resources, if integrated under appropriate interconnection standards, in microgrids, or in automated distribution systems, offer the potential to improve grid reliability and resilience for customers that place a high value on uninterrupted service. These distributed resources may include increasingly clean energy technologies such as CHP, PV, and efficient fuel cells. Another possibility is the use of electric vehicles for load balancing and distributed storage. This concept, sometimes dubbed vehicle-to-grid, is viewed as being
potentially useful for storing excess electric power at night, when wind generation tends to peak. The concept has been studied under circumscribed and controlled model conditions. However, limited data have been collected on the value of uninterrupted service to different customers, nor has there yet been a full-scale demonstration of vehicle-to-grid (Centolella and McGranahan, 2013; Sullivan et al., 2009; Tomić and Kempton, 2007).
Opportunities to Improve System Efficiencies
Generation capacity factors and the average utilization of transmission and distribution assets are often below 50 percent (EIA, 2013a, Tables 3.1A and 4.7A)—far below the levels typical of other capital-intensive industries, in which asset utilization is commonly 75 percent or greater (Board of Governors of the Federal Reserve System, 2012). Better load factors could improve asset utilization and reduce investment requirements and costs. A great deal of the demand for electricity is associated with the thermal inertia of buildings or devices that have flexibility with respect to the timing of electricity usage. Smart thermostats and other intelligent devices can improve load factors while preserving the quality of service experienced by consumers. By optimizing equipment operation and reducing energy usage when homes or buildings are unoccupied, such technologies also can reduce overall energy consumption.
Opportunities to Create and Capture Additional Value through Increased Research and Development
Electric utilities spend 0.2 percent of their revenues on research and development (R&D) (Battelle Memorial Institute, 2011, p. 21; Lester and Hart, 2012)—less than one-tenth the average rate for all sectors of the U.S. economy and much lower than the rate in the most productive sectors (AEIC, 2010; Anadon et al., 2011, p. 222; NSF, 2010). Utilities could make a more significant contribution to the development and demonstration of advanced increasingly clean and energy-efficiency technologies, but realizing these improvements will often require new business and regulatory models. As a result, suppliers to the industry are unlikely to provide sufficient support for the development of advanced technologies without utility leadership. Fortunately, policy makers and industry stakeholders are beginning to actively consider changes in utility business and regulatory models.
This section describes the current structure of the electric power sector and the existing utility regulatory framework.
Current Structure of the Power Sector
The U.S. power sector encompasses diverse and multilayered systems of ownership, operation, and governance. Municipal and cooperative systems account for the vast majority of the nation’s more than 3,000 electric utilities and 26 percent of electricity sales and revenues. Investor-owned electric utilities account for 60 percent of industry revenues, and independent power producers for the remaining 14 percent of revenues.6
Regulatory Authorities and Structure of the Industry
The power system in the continental United States comprises essentially three mostly distinct large interconnections: the Eastern Interconnection, the Western Interconnection, and the Electric Reliability Corporation of Texas (ERCOT). Each operates as an integrated machine that instantaneously matches generation and use and directs the flow of power.
Regulation of the system is balkanized and complicated. In general, each state, each territory, and the District of Columbia regulate many aspects of the electric power system within their jurisdictional boundaries. Typically, the regulation is codified by the state legislature and carried out by a public utility commission. These regulatory commissions regulate other utilities, such as telecommunications and water, as well.
State public utility commissions regulate the retail rates, distribution reliability, and service of investor-owned electric utilities. For nearly the first century of the industry, states took the stance that electric power was a natural monopoly like other utilities, the assumption being that competition is unstable, and avoiding duplication by competitive firms actually lowers prices. Absent an effective competitive market to create efficient prices, states have accepted that they must regulate these natural monopolies in a way that produces the same result that would occur if effective competition did exist. Indeed, “the single most widely accepted rule for the governance of regulated industries is to regulate them in such a way as to produce the same results as would be produced by effective competition, if it were feasible” (Kahn, 1970, p. 17).
Through the 1990s, several states took steps to restructure their electricity markets so that electricity supply became “unbundled” from transmission and distribution.7 In those states that now have retail competition, state public utility commission authority may be limited to distribution, the acquisition of power for default service, and certain types of rules applied to retail suppliers. In other states, utilities tend to be vertically integrated, and state commissions may
6 Some power marketers are owned by holding companies that also own utilities.
regulate the planning and construction or acquisition of generation facilities.8 Eighteen states and the District of Columbia permit retail competition for electricity for some or all consumers. These states account for more than half of electricity sales (in megawatt hours [MWh]). In those states with unlimited retail competition, a majority of industrial and commercial customers purchase power from competitive suppliers. In Texas, Illinois, and Ohio, more than 50 percent of residential electricity consumers also purchase power from competitive electricity suppliers. State commissions generally do not regulate cooperatively and municipally owned utilities, although the state may regulate the siting of major facilities and have jurisdiction over energy emergencies.
FERC regulates the transmission and wholesale sale of power in interstate commerce. It approves reliability standards for the bulk power system developed by the industry through the North American Electric Reliability Corporation (NERC) and NERC’s eight regional reliability organizations.9 However, FERC cannot, on its own, propose and adopt new reliability standards. It also cannot address the reliability of distribution systems, which accounts for more than 90 percent of customer outages.
In large regions and the state of California, ISOs and regional transmission organizations (RTOs) are responsible for the planning and operation of the bulk power transmission grid and the commitment and dispatch of central station generating units.10 FERC regulates ISOs and RTOs with the exception of ERCOT, an interconnection entirely within the state of Texas that is regulated by the Texas Public Utilities Commission. While the California ISO is regulated by FERC, the governor of California currently appoints its board.
Each ISO and RTO operates a system of markets including day-ahead and real-time energy markets that coordinate the operation of central station generation and efficient utilization of transmission assets. Additionally, PacifiCorp, a utility operating in six western states, and the California ISO have agreed to create an energy imbalance market to coordinate generation dispatch in real time. Other utilities in the West are considering participating in this market. With the exception of Georgia and Oregon, which permit limited competition for large commercial and industrial customers, utilities in the District of Columbia and each of the states that allows retail competition also participate in regional ISO or RTO wholesale markets.
8 Electricity generators and utilities also are subject to extensive regulation by federal and state environmental protection agencies.
9 The eight regional reliability organizations are Florida Reliability Coordinating Council; Midwest Reliability Organization; Northeast Power Coordinating Council; ReliabilityFirst Corporation; SERC Reliability Corporation; Southwest Power Pool, RE; Texas Reliability Entity; and Western Electricity Coordinating Council.
10 California ISO, ERCOT, ISO New England, Midcontinent ISO, New York ISO, PJM Interconnection, and Southwest Power Pool. Canadian RTOs/ISOs include Alberta Electric System Operator and Independent Electricity System Operator.
Federal agencies and power marketing administrations, including the Tennessee Valley Authority, Bonneville Power Administration, Southeastern Power Administration, Southwestern Power Administration, and Western Area Power Administration, operate significant generation facilities in some regions and account for 6.5 percent of the nation’s total generating capacity (APPA, 2014).
In addition to investor-owned and publicly owned utilities, about 12 percent of electricity customers are served by rural electric cooperatives (NRECA, 2016). Cooperatives are private, nonprofit businesses that are owned by the customers and are incorporated under the laws of the state in which they operate. They are governed by a board of directors that is elected from the membership (NRECA, 2016).
Infrastructure of the Present Power System
Today’s power grid was built to deliver electricity produced by a few large power plants. Electricity is produced at central power stations at high voltages, and gradually stepped down to lower voltages as it flows through the transmission and distribution network until it is delivered to the user at a voltage that is considered safe for residential and commercial use. Figure 6-1 depicts the structure of today’s power system (EPRI, 2014). Most consumers are billed based on the quantity (kWh) of electricity they use over a fixed period of time (e.g., a month), information that is collected either by utility employees (meter readers) who physically visit individual meters to note usage, or in some areas by meters that can send an electronic record of use directly to the distribution company for billing purposes. In each case, however, the flow of electricity and the flow of information are unidirectional, in opposite directions: electricity flows from the utility to the end-user, while information about usage flows from the consumer back to the utility. Planning for electricity generation capacity in this conventional power system typically is centered on a few key stakeholders (e.g., ISOs/RTOs, utilities owning generation assets, state public utility commissions and power siting boards), and focuses on larger generation facilities and transmission lines. This approach has achieved virtually universal access to electricity and an average annual reliability of 99.97 percent in the United States (IEEE, 2011). While this level of reliability was accepted in an industrial economy, it is lower than that achieved in many other developed countries (compare CEER  and Eto and LaCommare ) and may not be optimal for many customers in today’s digitally based economy. Unfortunately, the traditional power grid will not support the level of distributed energy technologies that will occur based on current trends and demands for increasingly clean and more efficient, reliable, and resilient electric power.
Stakeholders with diverse and often conflicting interests are active participants in ISO/RTO committees and parties to FERC and state regulatory
proceedings. The complex organizational and governance structure of the power sector has facilitated experimentation and presents a challenge for the development of national energy policy.
The Current Utility Regulatory Framework
Electric utilities are mature organizations, often with conservative cultures. Well-aligned incentives and the engagement of policy makers, regulators, and external stakeholders with utilities are likely to be important to enabling utilities to embrace innovation and fully support the adoption of cost-effective increasingly clean energy and energy-efficiency technologies that can deliver net value to customers. This subsection describes the traditional cost-of-service model for regulation of electricity distribution and vertically integrated electric utilities and its limitations. The next section outlines alternatives that might better align utilities with the deployment of advanced increasingly clean energy and energy-efficiency technologies where such technologies would benefit society and utility customers.
As noted above, utility regulation has historically been intended to replicate the pressures of competitive markets for services even though the utilities’ services are provided on a monopoly basis. The regulation of electricity distribution has focused on minimizing utility costs and avoiding the undue exercise of monopoly power. Regulators have been charged with ensuring that utilities provide adequate service and do not charge unreasonable or discriminatory prices. However, this is only a part of the function of regulation.
The objectives of regulation also include supporting investments that deliver net value to customers, ensuring the quality and reliability of service that customers value, and encouraging innovation to create dynamic efficiency gains. Given new challenges and customer expectations, regulators and policy makers have begun to question how best to realize both sets of objectives.
State public utility commissions have used a cost-of-service approach to set the rates charged by electricity distribution and vertically integrated utilities.11 This process establishes the total of all costs prudently incurred to provide service, then sets rates necessary to enable the utility to recover the costs incurred during the year under review and realize a return on invested capital.
Given current conditions, the cost-of-service model has significant limitations (Malkin and Centolella, 2014):
- Quasi-judicial proceedings—Rates typically are set through time-consuming, quasi-judicial proceedings in which the utility files a lengthy application and testimony detailing the cost basis for a requested increase in rates. In some cases, the parties reach an agreement stipulating to a result that is recommended to the commission. Such agreements can provide parties greater flexibility, but if one or more parties do not agree, the case can revert back to a litigated process. Litigation can work well when the relevant questions can be answered on the basis of historical facts; however, it may not provide an ideal basis for making the types of risk and value judgments that utilities and regulators increasingly face.
- Status quo fallacy—Utilities frequently are asked to justify any significant changes from practices previously accepted by the regulator. To do so, they often must demonstrate that a new practice will lower their costs. However, this focus on incremental utility costs assumes that the utility will continue to provide the same fixed set of services. In reality, distribution utilities are increasingly expected—and in many cases required—to perform new functions. A conventional utility cost analysis may present a barrier to investments that expand future options, lower societal and environmental costs, and diminish incentives for innovation that could provide long-term benefits.
- Misaligned incentives—In the current environment of increasing costs and slow growth, cost-of-service regulation often fails to provide appropriate incentives for investment, efficiency, and innovation. With cost-of-service regulation, there is a lag between the time a utility makes a capital expenditure and the time it begins to recover its costs following a subsequent rate case. This lag has a
negative impact on cash flow and can impair a utility’s ability to earn its authorized return, which can in turn cause the utility to defer discretionary investments that would otherwise benefit customers. However, simply shortening this lag time can reduce the incentive for efficient operations. An assumption of cost-of-service regulation is that the interval between rate cases will create an efficiency incentive because the utility retains any firm-wide cost savings realized during that period. But if the utility has to file frequent rate cases, it has little opportunity to benefit from such cost savings. Cost reductions will be passed on rapidly to customers, as the utility’s expenditures in one year become the basis for its allowed revenue in the next.
- Barriers to innovation—Innovation may introduce regulatory risk for a utility. If a new system fails to perform as expected, the utility may see its costs disallowed. Although firms in competitive markets have an opportunity to earn higher profits when innovation delivers value to their customers, utilities are seldom rewarded for assuming the risks of innovating. While firms in competitive markets can rapidly innovate, learn, and, if necessary, redirect their efforts, a regulated utility may need to cycle through a lengthy regulatory review process and justify changes from previously approved practices. The time between when the utility identifies a valuable commercial innovation and the innovation’s full implementation can extend to as long as a decade.
Finding 6-1: To expedite innovative solutions, it will be necessary to redesign business models and regulatory incentives currently designed for a centrally controlled system so they are built on a customer-driven model with multiple solutions.
A MODERN POWER SYSTEM THAT WOULD SUPPORT THE DEVELOPMENT AND DEPLOYMENT OF INCREASINGLY CLEAN ENERGY AND ENERGY-EFFICIENCY TECHNOLOGIES
This section describes the features of a modern power system that would support the development and deployment of increasingly clean power and energy-efficiency technologies—its technical features, a supportive regulatory approach and specific regulatory policies, new utility business models, and workforce development.
The committee’s recommendations in these areas are directed at both federal and state policy makers and state utility regulators. While much of the focus of this study was on national policies, the committee recognized that state utility regulation plays a central role in creating the conditions necessary for the
development and deployment of cost-effective increasingly clean energy and energy-efficiency technologies. In addressing its recommendations to the states, the committee recognizes that different regions have different industry structures and opportunities that may require tailoring its recommendations to local conditions.
A modern electric power system that supports and encourages the development and deployment of increasingly clean power and energy-efficiency technologies will have certain essential features that can be identified now and may require others that will become evident over time. Perhaps the most essential feature is the further refinement and implementation of a regulatory framework and business models that align incentives for power generators, system operators, and utilities of all types with key objectives of reducing or eliminating pollution and other unpriced environmental harms, ensuring system reliability, safeguarding physical and virtual assets from malicious or accidental harm, improving and upgrading grid infrastructure, and protecting consumers from unfair pricing or other harms. A system that can produce these outcomes is one that (AEE, 2014)12
- encourages innovation in power generation technology, transmission and delivery infrastructure, and service models;
- empowers customers by giving them tools and options for managing their electricity costs;
- improves the design, operation, and coordination of power markets;
- moderates future customer bill increases relative to what otherwise would be experienced; and
- creates sustainable business models for firms in the power sector.
Special attention to the last point is warranted because, simply put, the job of creating and running a modern electric power system that encourages and produces these outcomes must be financially attractive for firms and their investors. Power-sector business models, however, are built largely in response to regulatory environments. Legislatures must create and regulators must implement a regulatory system of markets and incentives that support and encourage these investments.
Finding 6-2: Regulatory and business models that encourage firms to invest in developing and deploying increasingly clean power and energy-efficiency technologies are critically important.
12 This paper was produced as part of working group effort involving a number of electric power utilities and other firms. See the paper for a complete list the utilities and other organizations involved.
Technical Features of a Modern Power System
The challenges and drivers described above reveal an electric power industry that is starting to make transformative changes in energy production and use. Supporting these new patterns of electricity production and use will require a power grid that is physically and institutionally different from the grid of today.
A modern grid would support multiple actors at more (e.g., distributed) points of generation and/or consumption, and respond quickly and efficiently to variability in loads. Its main feature is that the distribution network is integrated with other components of the grid through active management and operation (IEEE, 2011). Figure 6-2 depicts a modern, integrated electricity grid as envisioned by the Electric Power Research Institute (EPRI) (IEEE, 2011), whose structure is very different from that of the current system as illustrated earlier in Figure 6-1. The distinguishing characteristic of this integrated grid is the multidirectional flow of both electricity and information (data) between energy supply and energy use and the suite of advanced smart-grid technologies that would enable the efficient management of these flows.
The ability of customers to route excess electricity back to the grid for use by another customer elsewhere in the system has system-wide advantages. First, customers can benefit from decreasing their net power consumption or actively participating in power markets. Second, distributed energy technologies can enhance the overall reliability experienced by customers, provide distribution voltage support and improve voltage quality, and reduce system losses. The power system’s resiliency can also be enhanced, as portions of the grid with appropriate control technologies can continue to function during system outages through the use of islanding techniques (Passey et al., 2011). Third, environmental impacts can be reduced because new (possibly higher-polluting) generation and capacity additions can be avoided, and resources that are no longer cost-effective to maintain can be replaced. Overall, enabling this multidirectional flow of electricity allows value to be gained from the use of distributed energy technologies, especially given storage capability.
The multidirectional flow of information and the integration of advanced information and communication technologies with the operation of the power system are key features of a modern integrated power system. The system enables customers to participate and provides system operators with detailed real-time data that can be used to optimize system operations. Advanced metering infrastructure (AMI) is one of the enabling technologies. It measures and records electricity usage at short intervals and can provide the data to both the customer and the utility. The most advanced AMI has built-in two-way communication capability for real-time data. Communicating thermostats and other smart energy-using devices in customers’ homes and businesses, together with access to information on anticipated electricity prices, can optimize the
timing of energy demand. Utilities also can forecast changes in customer demand and use this information in optimizing system reliability and efficiency.
A Supportive Regulatory Approach
This subsection describes an evolution in utility regulation that could support the development of a modern, integrated power system such as that described above. Establishing a well-functioning modern grid that provides increasingly clean and more efficient, reliable, and resilient electric power will require a supportive regulatory and business environment. A wide variety of policies have already begun to stimulate and drive U.S. investment in smart-grid technologies, such as that resulting from the American Recovery and Reinvestment Act of 2009, which provided more than $3.4 billion in stimulus funding for smart-grid technology development and demonstration (plus $615 million for smart-grid storage). With the expiration of that act’s funding, new regulatory models have begun to emerge to support needed upgrades and technology investments.
The Importance of Regulatory Frameworks
Utilities base their business models on the regulatory frameworks within which they operate. Various alternative regulatory models could incentivize and reward the development and deployment of increasingly clean power and energy-efficiency technologies and the necessary supporting systems and infrastructure.
Over time, regulators have taken steps to adapt to changing conditions, including experimentation with alternative regulatory models.13 Some of these alternative models provide greater support for new investment. These models may involve prior regulatory review of utility plans to align them with regulatory objectives, and also may be conditioned on utility commitments to making specific improvements. Such alternative models include the following:
- Annual rate cases with a forecast test year—In some jurisdictions, the utilities forecast their investment expenditures based on prior planning reviews. By using these forecast values in annual rate proceedings, the utilities and their regulators can better match costs and revenues to the prospective level of rates. However, frequent regulatory involvement can make this approach administratively burdensome. Examples in which this approach has supported investment include the Public Service Commission of Wisconsin with its biennial Strategic Energy Assessment and annual rate cases, and the Iowa Utilities Board’s preconstruction approvals of new generation.
- Capital expenditure trackers—A tracker is a separate rate-adjustment mechanism that allows for the recovery of specific costs outside of the conventional rate case process. Historically, tracker mechanisms were reserved for significant and volatile costs, such as fuel, which are largely beyond the utility’s control. More recently, several states have permitted accelerated recovery of specific capital expenditures outside of a cost-of-service rate case. For example, Pennsylvania’s Distribution System Improvement Charge allows accelerated recovery of costs associated with approved long-term infrastructure plans.
- Formula rates—In this approach, a specific formula for setting rates is established in advance by statute or a prior public utility commission order. The utility then files its cost data, and the information used to determine its allowed rate of return in a standard format. While the formula sets the types of cost that may be recovered, costs may be subject to review based on whether the
expenditures were prudently incurred. Examples of formula rates include FERC’s transmission rates and the Illinois Energy Infrastructure Modernization Act.
These approaches can support investment, but they can involve a high level of regulatory oversight. They also offer limited incentives for the utility to reduce its costs and share any cost savings with consumers. For example, capital cost trackers have been criticized for diminishing efficiency incentives and for allowing rate increases for the cost of new capital additions without consideration of countervailing cost reductions. Similarly, some commentators have criticized formula rates on the grounds that they fail to encourage cost-efficiency and productivity improvements (Costello, 2009).
Other alternative models are designed to provide strong incentives for reducing costs. These models include the following:
- Multiyear revenue and price caps—Under this model, changes in utility revenues or rates can be indexed to inflation and adjusted for a targeted rate of productivity improvements and any extraordinary events. Alternatively, the regulator may set annual step changes or freeze revenues or rates for the duration of the rate plan. These multiyear rate plans can promote cost reduction by enabling the utility to share in any cost savings and absorb cost increases during the years covered by the plan. In the absence of strong reliability standards or incentives, however, they have been associated with a reduction in spending on operations and maintenance and an increase in the average duration of customer outages. In addition, unless the multiyear plan is tied to a reasonable utility business plan for new investment and changes in its operations, the revenue or rate cap may not match the rate levels needed for required capital investments.
- Sliding-scale rate plans—In a few states, including Alabama, Louisiana, and Mississippi, regulators determine a target return for the utility and set rates based on cost and revenue forecasts to achieve the return target, subject to a predetermined ceiling on rate increases. The regulator also sets a range of authorized earned returns. The utility’s actual earnings are later reviewed, and if the earned returns are within the authorized range, the utility may retain or must absorb all or a share of any variance between its target and actual earnings. The opportunity to retain earnings within the authorized range provides an incentive for the utility to be efficient. If actual earnings exceed the authorized range, however, the utility may be required to return the excess earnings to customers. Sliding-scale plans also can incorporate performance incentives based on reliability, customer satisfaction, or other metrics. The sliding-scale approach may be considered a light-
handed form of regulation and has not attracted significant support from policy makers in other regions.
An Emerging Regulatory Model in the United Kingdom
Regulators, utilities, and other stakeholders are actively seeking to define regulatory models that support needed investments, incentivize cost savings, and encourage innovation. U.S. regulators have taken note of a rate-setting framework being implemented by the utility regulators in the United Kingdom, Office of Gas and Electric Markets (Ofgem). New York State Department of Public Service (2014) commented favorably on this model in its report in New York’s widely followed “Reforming the Energy Vision” (REV) proceeding. Ofgem is implementing an approach for the regulation of network companies called RIIO (Revenue set to deliver strong Incentives, Innovation and Outputs).14 RIIO is an incentive-based framework intended to mimic the effects of competitive markets by linking revenue to output metrics, innovation, and cost savings. It encourages transmission and distribution utilities to focus on delivering net long-term value to customers. RIIO’s major components include the following:
- Revenues set based on a review of the utility’s business plan—The review of the utility’s business plan includes benchmarking of planned operating expenses and an engineering assessment of capital expenditures.
- Cost savings shared with customers—RIIO includes an earnings-sharing mechanism with large sharing factors. To the extent that a utility’s actual earnings exceed its authorized return, 50 percent to 60 percent is refunded to customers, while if costs are higher than anticipated and earnings fall below the authorized level, the utility may have to absorb up to 50 percent of the loss in earnings. The precise sharing percentages can vary among utilities based on the regulator’s assessment of a utility’s cost projections.
Clearly defined results-based metrics and output incentives—Incentives can be bidirectional, either increasing or decreasing earnings. The regulator may adjust output metrics and incentives during the rate plan, with adjustments being applied to the remaining years of the plan. Ofgem has proposed or adopted performance incentives related to the following:
- − The frequency and duration of outages—Incentives are based on studies of the value placed by different customers on uninterrupted service.
- − Customer satisfaction—Incentives may include an up to 1 percent up or down adjustment in revenue based on customer surveys and an additional incentive of up to 0.5 percent of revenue based on an independent panel’s assessment of the utility’s stakeholder engagement practices.
- − Environmental impacts—Incentives may be based on reductions in line losses; the visual impact of power lines (undergrounding); and reductions in greenhouse gas emissions, including leakage of sulfur hexafluoride (SF6), a potent greenhouse gas used in insulating transformers and other electrical equipment.
- − Social obligations—Incentives address issues of fuel poverty and assistance to vulnerable customers in accessing available services.
- − Timing and efficiency in connecting customers—New customers purchase electric service from competitive suppliers. Incentives are based on utilities’ performance in connecting customers.
- − Meeting worker and public safety standards.
- Application of the revenue cap to total expenditures—At the start of the rate plan, the regulator fixes the percentage of revenue that will be recovered in each rate year, with the residual being capitalized. Once this ratio has been established at the beginning of the plan, it does not change based on the nature of the utility’s actual expenditures. The utility has the flexibility to take advantage of learning and modify its spending plans to meet its output objectives as efficiently as possible. An annual rate adjustment aligns revenue with authorized levels.
- Innovation programs—Ofgem is funding innovation programs for the piloting of large projects, small projects, and the rollout of proven solutions. These programs enable third parties to partner with the utility to deliver cost savings, carbon reductions, or other environmental benefits. An expert panel disburses multiple rounds of funding.15
- Limited revenue reopeners—While Ofgem’s general approach is to require utilities to manage business risks, it may define circumstances in which rate plans may be reopened to address changes in underlying economic assumptions or unknowns such as new cyber-security requirements.
- End-of-period adjustments—Ofgem tracks asset health and may implement an additional positive or negative incentive at the end of the rate plan to ensure that assets have been appropriately maintained,
15 Ofgem publishes an annual report on projects funded through its Network Innovation Competitions. As of this writing, the list of projects funded in 2015 was the most recently available (https://www.ofgem.gov.uk/sites/default/files/docs/innovation_competitions_brochure_webready_0.pdf).
replaced, or upgraded. Ofgem also may allow recovery near the end of the rate plan for investments designed to produce benefits during the next rate plan. Ofgem may allow utilities to carry forward into the next rate plan a share of cost savings realized near the end of the current plan.
RIIO is an example of a regulatory authority attempting to balance incentives for cost savings with performance incentives based on specific output metrics. In many respects, Ofgem was dealing with concerns comparable to those facing U.S. regulators. The U.K. power industry faces aging infrastructure, a changing power generation mix with increased reliance on variable renewable generation, and limited revenue growth. In developing its reform program, Ofgem sought to engage consumers in defining desired results. It also recognized that accelerating innovation could play a key role in making power and energy affordable, as well as meeting the nation’s climate objectives. Ofgem’s electric power innovation programs are currently providing funding of more than $60 million for projects designed to test advanced technologies for facilitating the integration of renewable generation, cutting distribution losses, reducing generation requirements through distribution voltage optimization, and improving the flexibility and operation of transmission and distribution networks (Ofgem, 2014). The United Kingdom is in the early stages of implementing RIIO, with the first plans now in place.
There are important differences between the regulatory environment in the United Kingdom and that in the United States. RIIO builds on 20 years of U.K. experience with price cap regulation. Both the regulator and utilities had accumulated skills and tools to help them develop a long-term performance-based rate mechanism. Moreover, the regulatory process in the United Kingdom is more consultative than that in the United States and lacks a comparable history of contentious rate case litigation. For example, the regulator in the United Kingdom is able to offer a utility a menu of different incentive contracts designed to incentivize the utility to disclose accurately its expected cost for meeting performance metrics.16
Taking differences in their regulatory environments into account, several U.S. regulators are considering how to adapt the RIIO framework to their own circumstances with some core results-based concepts, including
- revenues based on forward-looking business or grid modernization plans;
16 This practice is known in the United Kingdom as an information quality incentive and more generally as a menu of contracts approach to setting rates. For background and a description of how the approach is implemented, see Cossent and Gómez (2013) and Ofgem (2010a, p. 66).
- multiyear revenue caps that provide an incentive for the utility to pursue efficiency improvements and retain a share of the resulting cost savings or bear a share of the resulting cost overruns;
- caps on total expenditures that give utilities the flexibility to shift spending between operating and capital expenditures to meet requirements efficiently as new information becomes available;
- earnings-sharing mechanisms that allow customers to benefit from cost savings or bear a share of costs incurred during multiyear plans;
- output-based, bidirectional performance incentives for reliability, energy efficiency, customer satisfaction, and other performance metrics; and
- funding set aside specifically for research, development, and other innovation projects.
Advancing Consideration of Alternative and Emerging Regulatory Models
There has been or is ongoing consideration of alternative and emerging regulatory and utility business models in many states, such as California,17 Hawaii,18 Illinois,19 Maryland,20 Massachusetts,21 Minnesota,22 New York,23
17 See California Public Utilities Commission, In the Matter of Order Instituting Rulemaking Regarding Policies, Procedures and Rules for Development of Distribution Resource Plans Pursuant to Public Utilities Code Section 769, Order Instituting Rulemaking, Public Utilities Commission of California Rulemaking 14-08-013 (August 20, 2014).
18 See Public Utilities Commission of Hawaii, In the Matter of Public Utilities Commission regarding Integrated Resource Planning, Docket No. 2012-0036, Decision and Order No. 32052, Exhibit A: Commission’s Inclinations on the Future of Hawaii’s Electric Utilities (April 28, 2014).
19 Illinois enacted a formula rate statute—the Energy Infrastructure Modernization Act—to support grid modernization. This formula rate framework is scheduled to sunset in 2017. Additionally, the Illinois Commerce Commission is currently considering how best to provide competitive suppliers access to customer information while protecting customer privacy.
20 See Maryland Public Service Commission Staff, Report on Performance Based Ratemaking Principles and Methods for Maryland Electricity Distribution Utilities, In the Matter of the Electric Service Interruptions in the State of Maryland Due to the June 29, 2012 Derecho Storm, case no. 9298 (July 1, 2014).
22 The Great Plains Institute recently partnered with Xcel Energy, Minnesota Power, the Center for Energy and the Environment, George Washington University Law School, and other stakeholders to review regulatory models in Minnesota in what is called the e21 Initiative (see http://www.betterenergy.org/projects/e21).
and Texas.24 Given the power industry’s current challenges, state regulators and policy makers would do well to investigate and consider such regulatory models that align utility incentives with achieving long-term cost savings, providing net value to customers, promoting public policy objectives, and encouraging innovation.
Many state regulatory commissions have limited staff and will require tools and training beyond what they currently have if they are to develop and effectively implement alternative models (see Fox-Penner, 2014). Several commissioners consulted during the course of this study emphasized that they would welcome and greatly value assistance from the Department of Energy (DOE)25 to help train and educate commissioners and staff. In particular, they suggested creating a national program that would provide additional resources and training, and perhaps serve as both a coordinator and repository for best practices and lessons learned as many states move forward with regulatory reforms.
Finding 6-3: Many state regulatory commissions require additional analytical tools, training, and other resources to develop and implement effectively regulatory models that support and encourage the development of increasingly clean energy and energy-efficiency technologies.
Recommendation 6-1: DOE should develop information, tools, and programs that would facilitate state regulatory commissions’ consideration and implementation of regulatory models tailored to meeting current challenges. These resources would be a natural extension of the Electricity Policy Technical Assistance Program already operated by the Office of Electricity Delivery and Energy Reliability.26
Specific Supportive Regulatory Policies
This subsection reviews utility regulatory policies designed to advance the cost-effective deployment of advanced increasingly clean power and energy-efficiency technologies.
25 Or possibly other national organizations, such as the National Association of Regulatory Utility Commissioners.
Automation of Customer Preferences in Energy-Using Devices
A low-pollution energy future will require more efficient integration of variable low-carbon resources into power system operations. Today, integration requirements can limit the use of renewable generation or require the continuing operation of additional fossil fuel-fired units primarily for the purpose of offsetting changes in the output of variable resources.
Additionally, a significant portion of the energy used in buildings is wasted. One study estimates that 39 percent of residential energy consumption is wasted, with the majority of that waste due to heating and cooling of unoccupied spaces or overheating or overcooling of the home to achieve comfortable temperatures in some parts of the home (Meyers et al., 2010). Given the reach and declining cost of communications with distributed devices and advances in data analytics, automated systems may be able to significantly reduce such waste and lower carbon emissions. Unlike prior generations of programmable thermostats, a modern smart thermostat can
- sense when a home or portion of a building is unoccupied;
- identify when consumers with smartphones are arriving back in their home neighborhood;
- automatically fine tune operational schedules to address seasonal changes;
- reduce run times of air conditioner compressors on less humid days when the compressors are not needed;
- balance heat pump operations to provide desired comfort and reduce the use of less efficient auxiliary heating elements;
- prompt customers to change their furnace filters when accumulated dirt has reduced the filters’ efficiency; and
- provide reports on the efficiency of energy use and recommendations for energy savings.27
One study estimates that the installation of smart thermostats could reduce the energy used by residential air conditioners in southern California by more than 11 percent (Nest Labs, Inc., 2014).
Many people rely on automated customer choice technologies to perform a variety of functions in their lives. An example is booking flights. Consumers can enter the date on which they want to fly, the hours they prefer to travel, and the number of connections they are willing to make. An application then sorts through thousands of flights and suggests the least expensive options consistent with consumers’ preferences. In the same way, one can enter a preferred temperature and program a smart thermostat to give it 1-2° of temperature
flexibility. Today’s communicating thermostats can access forecasts of local temperatures and humidity, sense whether anyone is at home and determine when the house generally is unoccupied, and learn the building’s characteristics and the efficiency of its cooling and heating systems. Using precooling and smart operating strategies, such thermostats have reduced peak use of residential air conditioners by 50 percent in 100o F-plus Texas temperatures (Nest Labs, Inc., 2013) and cut demand in a Nevada utility program by more than 3 kW per household.28 In the Nevada program, annual electricity and natural gas usage in participating homes was cut by 3.6 percent and 6.4 percent, respectively. 29
The impact of such automation could be great. One California study estimated that the thermal inertia of residual air conditioning, given no more than 1° C of temperature flexibility, water heaters with up to 4° C of flexibility, and refrigerators with up to 2° C of flexibility, could permit smart devices to shift 20 GW or more of the state’s residential demand during more than 2,000 hours of the year and provide at least 8-11 gigawatt hours (GWh) of energy storage throughout the year. This estimate suggests that during much of the year, smart devices have the potential to shift a majority of California’s residential electricity demand to different time intervals. For California residential customers, shifting electricity demand to lower-cost intervals could reduce their estimated energy cost for air conditioning (at wholesale market prices) by about 10 percent and their energy costs for water heating and refrigeration by up to 40 percent or more (Mathieu, 2012; Mathieu et al., 2012).30 A 2011 National Energy Technology Laboratory study concluded that enabling system operators to send signals to smart energy-using devices could reduce peak demand by more than 25 percent and produce billions of dollars per year in economic, reliability, and environmental benefits (Goellner et al., 2011). Most uses of electricity, including heating and cooling buildings, heating water, and refrigeration, have thermal inertia or, in the case of most pumping loads, batch processes, and charging of electric vehicles and other devices, flexibility in the timing of power use. Moreover, smart devices could respond continuously to help system operators offset ramping of variable resources or, if carbon and other environmental impacts were appropriately priced, to shift consumption to periods when resources with an optimal combination of lower costs and environmental impacts would be used.
28 Application of Nevada Power Company d/b/a NV Energy for Approval of its 2014 Annual Demand Side Management Update Report as it relates to the Action Plan of its 2013-2032 Triennial Integrated Resource Plan, Volume 5—Technical Appendix, http://pucweb1.state.nv.us/PDF/AxImages/DOCKETS_2010_THRU_PRESENT/20147/39345.pdf (hereafter Nevada Power Application). See also Kerber (n.d.).
29 Nevada Power Application.
30 Estimates were based on estimated device saturations in 2020. As a point of comparison, the contemporaneously prepared forecast for 2020 of residential noncoincident peak demand was 29,105 GW and of residential average hourly electricity consumption was 11,959 GWh (California Energy Commission Staff, 2012).
The barriers to a future in which smart devices can reduce the costs and environmental impacts of energy use by implementing the preferences of ordinary consumers are not primarily technological or economic; rather, they are largely regulatory and policy-related. Consistent with previous recommendations of the National Research Council (NRC, 2010c), pricing carbon and other environmental externalities would help ensure that the changes in consumption patterns over the long run associated with increasingly responsive demand would reduce both total societal costs and those costs currently reflected in electricity prices.
Important Roles for Regulators to Enable Automation
FERC and state utility regulators could take several steps to enable greater use of automated technologies to optimize demand participation in power markets.
First, in organized power markets, wholesale settlements are in many instances based on distribution utility load shapes, not on the actual load patterns of each retail supplier’s customers. Where settlements are based on customers’ actual demand profiles, energy service companies (ESCOs) can have a competitive advantage by packaging energy with demand-optimizing technologies. For example, a competitive retail supplier could provide a smart thermostat and offer a lower rate to customers with less peak coincident load shapes.31 Basing wholesale settlements on each ESCO’s actual load shape could be accomplished with, but does not require, AMI, as many AMI meters can record interval data.32 Alternatively, usage from conventional meters could be allocated to time intervals based on sensors at a sample of each supplier’s customers. Given an emerging role for smart devices, accessing such data could be as essential to effective competition in power markets as access to transmission was seen to be 20 years ago. Offering customers financing or demand-side management incentives for adopting smart devices also could accelerate their adoption. In a regulated environment where rates are not directly tied to each customer’s contribution to system and distribution circuit peak demands, a significant portion of the economic savings produced by changing demand patterns may be enjoyed by nonparticipating customers.
31 Technologies that automate customer energy choices do not require the use of dynamic retail prices. However, such prices may produce additional economic-efficiency benefits. Devices that automate customer preferences could make it easier for customers to take advantage of two-part and dynamic pricing to control their energy bills (Centolella, 2012).
32 AMI meters include a two-way communication capability. Advanced meter reading is an older technology that provides an automated way to collect meter data.
Finding 6-4: Customer adoption of smart devices may be important to provide the information needed to operate an efficient competitive power market.
Finding 6-5: Basing wholesale settlements on the actual load shapes of the customers of each ESCO can provide incentives for customers to adopt smart devices.
Second, ISOs and regional transmission organizations (RTOs) typically settle with load participants in organized wholesale power markets on an hourly basis. Incentives could be enhanced and responsive demand could play a greater role if load, like generation, were settled on a 5- or 15-minute interval basis. Customer-specific and more granular wholesale settlements could encourage utilities and competitive retail suppliers to work with their customers to automate and manage more efficiently the timing of flexible demand, offering lower prices to customers who use automation to create efficient changes in their usage profile.
Finding 6-6: The settlement of load in wholesale markets on a 5- or 15-minute interval basis instead of hourly would enable and provide an incentive for a much greater role for automated demand in maintaining reliability, balancing variable resources, and reducing peaks in demand.
Third, although most ISOs and RTOs develop short-term price forecasts, only the New York ISO and ERCOT publish such information. Information based on these indicative “look-ahead” forecasts could be used to position demand for anticipated system conditions and would be highly beneficial if made available to devices all the time, everywhere they are available, in a standard format, as inexpensively as possible.33 The Federal Power Act directs FERC to “facilitate price transparency” and to “provide for the dissemination,
33 The ISO and RTO “look-ahead” price forecasts are not settlement prices. As with any forecast, there will be differences between the indicative forecast and after-the-fact prices in the real-time market. Nonetheless, making available information based on “look-ahead” forecasts could enhance demand participation. First, an intelligent device could now consider both the day-ahead price and a “look-ahead” forecast that incorporated information about operating-day conditions and reliability events. Second, unlike an hourly day-ahead price, the “look-ahead” information could provide more granular interval data, enabling short-term demand participation. Third, once “look-ahead” forecasts were being made available, ISOs and RTOs would have an incentive and the opportunity to improve the publication of information about forecast prices. Providers of the data analytics underlying responsive devices would have a comparable incentive to use the information to help customers take power when it was least expensive. State and federal collaboration on appropriate privacy protections and data sharing with system operators also could help enhance forecast accuracy.
on a timely basis of information about [wholesale] prices…to…the public.” FERC is authorized, if necessary, to “establish an electronic information system” for this purpose (16 USC §824t). If wholesale price forecasts were coupled in a systematic and predictable way to retail prices, system operators could provide smart devices with market price forecasts that would enable those devices to improve their performance in response to information from the system operators regarding anticipated market conditions.
Fourth, system operators have the capability to incorporate response curves that reflect statistically predictable relationships between prices and demand into forecasts used for both operations and planning purposes.34
Recommendation 6-2: System operators should consider utilizing their capability to build response curves that reflect predictable price-demand relationships to enable flexible demand that responds to short-term prices, and incorporate those curves into the forecasts they use for operations and planning purposes.
Fifth, state regulators could spur more demand for smart devices that are connected to the home or building, such as a smart thermostat or commercial building energy management system, by allowing these devices to be financed through on-bill repayment programs. These programs would permit the financing of energy management and energy-efficiency devices to be linked to the premises and be transferred from one owner or tenant to the next, which could prove an effective way for customers to finance the devices.
In contrast with current demand-response programs, the response of intelligent devices need not depend on a payment to a curtailment service provider35 or the calculation of a baseline. This feature reduces administrative costs and inconvenience to customers (Bresler et al., 2013), avoids dissimilar treatment of otherwise comparable customers (Borenstein, 2014), and minimizes opportunities for abuse.36 According to the Board of Managers for PJM, one of the nation’s largest RTOs, PJM’s long-term vision is that “Price Responsive Demand, which allows more customers to respond directly to market prices and to voluntarily reduce their consumption when wholesale prices rise, is the
34 The recommendation for the straightforward recognition of these relationships also appears in Centolella and Ott (2009). Such recognition would avoid imposing on millions of price-responsive customers who receive no payment in the wholesale markets burdens and penalties comparable to those applied to supply-side resources.
35 As a result, this approach can be fully consistent with the Circuit Court’s decision in Electric Power Supply Association v. F.E.R.C, Case No. 11-1486, U.S. App. LEXIS 9585 (D.C. Cir. May 23, 2014), rehearing pending.
36Enerwise Global Technologies, Inc., Order Approving Settlement, 143 FERC ¶ 61,218 (June 7, 2013); Rumford Paper Co., Order Approving Settlement 142 FERC ¶ 61,218 (2013).
ultimate solution to demand participation” (PJM, 2009). Technology is now offering a means of democratizing demand participation and significantly improving system efficiency.
Volt/Volt Ampere Reactive (VAR) Optimization (VVO)
In a conventional distribution system, voltage is increased at the substation and may be boosted at intermediate points to levels consistently above minimum requirements to ensure that as power usage changes over time and voltages drop through the length of the distribution circuit, minimum voltage levels are consistently maintained for customers at the end of each line. VVO programs can reduce electricity generation requirements on many distribution circuits by 2-5 percent using modern solid-state power electronics on distribution circuits and smart inverters in distributed resources or, in some cases, a range of control technologies in conjunction with load tap changers (LTCs), regulators, and capacitor banks (DOE, 2012a; EPRI, 2012). They do so by managing voltage in real time, leveling and reducing unnecessary voltage levels across the circuit, and thereby reducing both losses and the apparent power delivered to customers’ meters. This can occur without reducing the overall power quality needed by customer devices. VVO appears to represent a significant and often cost-effective means of improving energy efficiency and reducing emissions. The same advances in power electronics also can help integrate distributed and variable resources, reduce peak demand, ensure consistent voltage levels for end-use devices, and improve power quality on the grid.
Despite recent advances, however, VVO programs have not yet been widely adopted. Some of this delay is due to the continuing evolution of the technology. However, there also are several nontechnical barriers, including the following:
- Regulators may not recognize VVO as an energy-efficiency program since it occurs on the utility side of the meter. VVO will reduce the energy usage recorded at the meter. For a utility that is recovering fixed costs through volumetric charges and does not have a revenue decoupling mechanism, failing to adjust rates for the lower metered energy usage associated with VVO means a loss in earnings.
- Measurement and evaluation techniques, metrics, and associated standards have been slow to develop. Universally accepted approaches for measuring and verifying results on an ongoing basis as loads and circuit characteristics change over time do not yet exist.
- The impacts of VVO technologies will vary from circuit to circuit. Moreover, universally accepted planning tools for identifying those locations in distribution systems that could benefit the most from the use of different approaches to VVO do not yet exist.
Finding 6-7: Volt/VAR optimization has the potential to enable significant decreases in the amount of power generation required to support transmission and delivery and to increase system quality and reliability, but faces several nontechnical barriers.
To take full advantage of VVO, state regulators could investigate and consider cost-effective distribution utility VVO programs. DOE could play a key role in facilitating the cost-effective deployment of VVO technologies by supporting the development of planning, benefit-cost analysis, and measurement and verification tools and standards and promoting the sharing of experience and best practices. Additionally, DOE and the electricity industry could consider establishing a cooperative program to promote the understanding of these technologies, their potential benefits, and consideration of options for removing regulatory disincentives among regulators and industry stakeholders (DOE EAC, 2014a).
Recommendation 6-3: DOE should support distribution utility VVO programs and facilitate the cost-effective deployment of VVO technologies by supporting the development of planning, benefit-cost analysis, and measurement and verification tools and standards and promoting the sharing of experience and best practices.
Dedicated Innovation Budgets and Roles for Utilities
Utilities have historically devoted a very small percentage of their revenue—about 0.2 percent—to R&D. Some jurisdictions are addressing this funding gap by setting aside dedicated funds for R&D and fostering innovation. California energy consumers support energy R&D through both the Electric Program Investment Charge, a public goods charge that funds research programs managed by the California Energy Commission (2016), and a unique joint venture between the state’s electricity distribution utilities and Lawrence Livermore National Laboratory—California Electric Systems for the 21st Century (CES-21).37 Under the state’s Energy Infrastructure Modernization Act, Illinois electricity distribution companies have an innovation accelerator and venture fund—the Energy Foundry—that supports innovative energy technology companies.38 The Massachusetts commission recently decided to establish dedicated funding for utility R&D as part of its Grid Modernization program
(Massachusetts Department of Public Utilities, 2014). And New York utility customers pay a systems benefit charge to fund the New York State Energy Research and Development Authority, which supports energy research, development, and innovation programs.39
Ofgem’s RIIO framework offers another example of such an approach. Under RIIO, funds are set aside for a package of innovation stimulus policies comprising the Network Innovation Competition (NIC), the Network Innovation Allowance (NIA), and the Innovation Roll-out Mechanism (IRM). The NIC is a U.K.-wide competitive funding opportunity that is open to any network utilities. Utilities must demonstrate that they have a process in place to facilitate collaboration with other (e.g., non-network) companies, and funds are awarded by an independent panel based on the extent to which proposed projects
- accelerate the development of a low-carbon energy sector and/or deliver environmental benefits and have the potential to deliver net financial benefits;
- provide value for the money for network electricity/gas customers;
- Create knowledge that can be shared across energy networks in Great Britain (GB) or create opportunities for rollout for a significant proportion of GB networks; and
- are innovative (i.e., not business as usual) and have an unproven business case, but the innovation risk warrants a limited trial research, development, or demonstration project to demonstrate its effectiveness.
Utilities also need to demonstrate that the incentives within price control regulation are not sufficient to justify the project.
The NIA is a set-aside allowance that each utility receives to fund small-scale innovative projects. A set-aside innovation budget can enable utilities to grow their innovation capabilities and support projects, primarily at the pilot or small demonstration scale, without the risk of such funds being diverted for ongoing operations.
Finally, the IRM enables utilities to apply for additional funding within the price control period for the rollout of initiatives that have demonstrable, cost-effective low-carbon and environmental benefits.
Recommendation 6-4: State regulators and policy makers should implement policies designed to support innovation. For example, they could evaluate approaches in which utility or energy customer funds are set aside to support state and regional innovation programs.
Chapter 3 includes discussion of and recommendations for increased utility involvement in innovation, particularly at the demonstration stage and as partners in regional innovation networks.
Energy Efficiency and Energy Management Financing: On-Bill Repayment
On-bill repayment is another potential tool for financing energy efficiency and energy management. For detail, see Chapter 4.
New Utility Business Models
Over the last two decades, the power system in much of the country has been fundamentally changed by open-access transmission,40 the development of ISO and RTO markets,41 market-based pricing of wholesale generation,42 demand response in wholesale markets,43 regional transmission planning,44 and competitive retail supply. Nonutility generators now provide about 40 percent of the nation’s electricity (EIA, 2016d, Tables 3.1.A and 3.3.A). By 2012, ISO and RTO demand-response programs were playing a major role in organized markets, with the potential to provide up to 10.7 percent of capacity requirements in ISO New England, 7.3 percent in the Midcontinent ISO, 7 percent in PJM, 5.8 percent in the New York ISO, and 5.2 percent in the California ISO (FERC, 2013). In jurisdictions that permit retail competition for power supply, more than 17 million households and a substantial majority of businesses have shopped for power from competitive retail electricity suppliers (Compete Coalition, 2014). And in Texas, arguably the most open market in the country, all consumers are served by competitive retail electricity suppliers, and these suppliers are offering more than 300 different packages of pricing and services to help customers manage their energy bills (Compete Coalition, 2014).
In many primarily southern and western states, changes have been less dramatic. Utilities remain vertically integrated, with bundled retail rates for generation, transmission, and distribution services being regulated by state
40Promoting Wholesale Competition through Open Access Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order 888, 61 FERC 61,080 (April 24, 1996); Preventing Undue Discrimination in Transmission Services, Order 890, 72 Fed. Reg. 12,226 (March 15, 2007).
41Regional Transmission Organizations, Order 2000, 81 FERC 61,285 (December 20, 1999).
42Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, Order 697, 119 FERC 61,295 (June 21 2007).
43Wholesale Competition in Regions with Organized Markets, Order 719, 73 Fed. Reg. 64,100 (October 28, 2008).
44Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order 1000, 136 FERC 61,051 (July 21, 2011).
commissions. However, utilities in these jurisdictions have nonetheless participated in industry developments. Utilities in a number of these jurisdictions have participated in competitive procurements for generation (Tierney and Schatzki, 2008). Some vertically integrated utilities have invested in grid modernization and advanced metering and have been leaders in offering time-varying and dynamic rates (FERC, 2013; IEE, 2013).45 New nuclear generating facilities46 and demonstrations of carbon capture and storage (CCS) technologies47 are being developed by vertically integrated utilities with the ability to recover generation costs in state-regulated rates. However, projects such as the Vogtle and V. C. Summer nuclear units and the Kemper County CCS facility have experienced schedule delays and cost increases. These delays and cost increases may reflect both (1) risks inherent in these projects and (2) the limited ability of regulation to replicate the incentives created by competitive markets and an opportunity to shift cost and schedule risks to ratepayers. Mechanisms such as the Regional Innovation Demonstration Funds proposed in 48
Emerging Opportunities for New Business Models
The business model for electricity distribution until recently has remained relatively stable among most utilities. However, it is in distribution as well as in retail energy services that new utility business models are emerging. The need to consider new business models is driven in part by the challenges and opportunities previously discussed: replacement of aging infrastructure,
45 For grid modernization, advanced metering, and time-varying and dynamic pricing programs supported by the American Recovery and Reinvestment Act of 2009, see https://smartgrid.gov/recovery_act/project_information.
46 The Tennessee Valley Authority (Watts Bar 2) and vertically integrated utilities in two traditionally regulated states (Vogtle 3 and 4 [Georgia, lead utility: Southern Company] and V. C. Summer 2 and 3 [South Carolina, lead utility: South Carolina Electric and Gas]) are the principal owners of the new nuclear units under construction in the United States. For information on proposed U.S. nuclear power plants, see http://www.worldnuclear.org/info/Country-Profiles/Countries-T-Z/USA--Nuclear-Power.
47 Southern Company has proceeded with its Kemper County Carbon Capture and Sequestration project despite cost overruns. However, American Electric Power halted its Phase 2 CCS project at its Mountaineer plant in West Virginia “because they did not believe state regulators would let the company recover its costs” (Wald and Broder, 2011, p. A1). For additional information on CCS projects, see http://sequestration.mit.edu/tools/projects/us_ccs_background.html.
48 Two carbon capture for enhanced oil recovery projects—Summit Power’s Texas Clean Energy Project and NRG’s Energy Parish Project—received support from DOE’s Clean Coal Power Initiative and are being pursued in a competitive power market.
expectations for greater reliability and resilience, cyber and physical security requirements, integration of variable and distributed resources, slowly growing or declining sales and limited revenue growth, and the opportunities created by new distributed energy technologies.
As discussed earlier, historically, power flowed from central station generation, through the transmission grid, and in one direction from the substation linking transmission and distribution to the customer (see Figure 6-1 earlier in this chapter). Distribution systems were designed based on the assumption that power moved only in this one direction. Distribution investments were sized to meet the peak demands of the customers expected to connect to each circuit. The fixed costs of the distribution system could be recovered through volumetric rates because there was little risk that customers would produce significant energy with customer-sited generation. Indeed, 44 states and the District of Columbia adopted net metering policies that effectively pay small customers retail rates for power delivered into the grid, initially with limited utility opposition.49 While net metering has become a highly contested issue, it was not viewed as a significant threat to the utility business model when these policies were first adopted (DOE, 2015a).50
As illustrated earlier in Figure 6-2, new distributed energy technologies are challenging this model of distribution operations. First, the falling cost of information and communication technology is making it cost-effective to manage demand by improving home and building operations and automating customer preferences for savings and comfort. As a result, there are now millions of end uses for power that could respond in real time to anticipated changes in prices or grid conditions. Utilities will have opportunities to connect to what is being called “the internet of things” to influence the timing of energy demands across their distribution systems in potentially very significant ways. Second, PV and other distributed generation technologies in some regions are becoming cost-competitive with retail rates. While this does not imply that such technologies cost less than providing the same energy services from conventional generation, cost parity with retail rates may make them attractive to customers and lead to their adoption, perhaps at an accelerating rate.51 Utilities face potentially significant challenges in integrating these distributed technologies with the planning and real-time operation of their distribution systems.
49 For a description of state net metering policies, see http://www.dsireusa.org/resources/detailed-summary-maps/net-metering-policies-2.
50 For a utility industry perspective, see http://www.eei.org/issuesandpolicy/generation/NetMetering/Pages/default.aspx.
51 As more customer-sited generation occurs, the throughput in distribution systems will tend to decline. As a result, additional rate increases may well be required to maintain the existing utility infrastructure, which could in turn provide a greater incentive for customers to self-generate.
In the last 5 years, moreover, many utilities have planned and begun implementing programs to modernize their distribution systems. These programs are built on the integration of information and communication technologies into power system planning and operations. Grid modernization or “smart-grid” initiatives have the potential to provide significant cost savings and improvements in reliability and customer value. EPRI estimated in 2011 that national deployments of smart-grid technologies could produce net economic benefits over the 20-year period through 2030 of $1.3-2.0 trillion. To deliver these benefits, utilities would need to invest roughly $17-24 billion per year, with an average benefit-to-cost ratio of between 2.8 to 1 and 6.0 to 1. Similarly, the Smart Grid Consumer Collaborative, representing a broad cross-section of industry stakeholders, found that smart-grid investments would produce a benefit-to-cost ratio of between 1.5 to 1 and 2.6 to 1 and net present value benefits of between $247 and $713 per utility customer (EPRI, 2011; SmartGrid Consumer Collaborative, 2013; see also Schneider et al., 2012). And the early results from such efforts confirm the availability of significant benefits (see, e.g., DOE, 2012a,b,c; EPRI, 2012; Faruqui and Palmer, 2012; Schneider et al., 2012).52 To ensure that grid modernization works effectively, secure interoperable standards are necessary. Efforts to develop standards and protocols to ensure that different systems and devices can communicate and operate with each other are being undertaken by the National Institute of Standards and Technology (NIST, 2014).
Two Potential Business Models to Address Challenges and Needs in Distribution
The above developments are leading to consideration of two emerging parallel and potentially complementary business models for distribution utilities and/or other market participants: distribution system operator (DSO) and customer energy service provider (CESP) (see Fox-Penner, 2010; Rocky Mountain Institute, 2013). These models may be able to address several challenges that distribution networks will encounter with increasing levels of distributed and variable generation assets. Both models, however, face challenges to their full development and implementation.
First, the efficient integration of distributed energy technologies, distribution automation, VVO, and other characteristics of a smarter power grid will require a more active DSO. Historically, distribution operations could largely ride off of the operation of the transmission system. A system that includes intelligent distribution and distributed energy technologies will require detailed and transparent planning and real-time operational management and coordination. The operation of a system in which distributed technologies can impact both distribution and transmission system operations may require
- a federated control architecture connecting transmission and distribution operations;
- integrated modeling and state estimation to give both transmission and distribution operators real-time awareness of power flows across transmission and distribution systems;
- a flexible, advanced information architecture to manage a major expansion in operational data and integrate an evolving set of information systems and applications while maintaining cyber security;
- the ability to commit and dispatch or forecast and coordinate the operation of large numbers of distributed technologies, dynamically manage the topology of mesh or microgrid-based distribution networks, optimize voltage, and simultaneously maintain phase balance across the distribution system; and
- distribution-level market structures that can coordinate settlement of transactions.
These requirements, in part, parallel the types of systems that had to be developed for the operation of RTOs and ISOs. However, efficient operation of a distributed system may have to accommodate a larger number of control points and manage greater complexity. The development of such systems will take time and require a coordinated R&D effort. DOE has taken only partial steps to address such requirements through the Green Electricity Network Integration (GENI) program in the Advanced Research Projects Agency-Energy (ARPA-E), formation of the Office of Electricity and Energy Reliability’s Grid Tech team, and support for standards development and the Smart Grid Interoperability Panel. While the DSO role is likely to develop over a number of years, the development of needed operational systems in time to match the pace of cost-effective deployment of distributed energy technologies could prove challenging. With market participants connecting with the distribution system, clearly defined interconnection and interoperability standards will be needed, and distribution planning will need to become more transparent.
Finding 6-8: Clearly defined interconnection and interoperability standards and more transparent distribution planning will be essential for connecting increasing numbers of market participants to the distribution system.
Enhanced, accessible distribution planning tools may be needed to support the development and regulatory approval of distribution plans. DOE has supported the development of distribution planning models, including GridLAB-DTM, an advanced distribution system simulation and analysis tool that provides information to users who design and operate distribution systems.
However, GridLAB-D is not widely used by regulatory commissions or other industry stakeholders. Regulators in parts of Europe and Latin America have addressed such gaps by developing reference network models (RNMs). An RNM is a planning tool that, using heuristics and contingency analysis, forecasts the distribution investments reasonably needed to integrate new resources, achieve desired reliability targets, and meet forecast demand in an approximately optimal fashion. RNMs may differ in scope from conventional distribution planning models in automatically generating expansion candidates from a library of standardized equipment rather than relying on a distribution planner to propose candidate investments, and in validating the feasibility of planning decisions both electrically and in terms of physical considerations when integrated with a geographic information system (Domingo et al., 2011). By identifying a reasonable plan that meets distribution planning objectives, an RNM can help regulators examine the impacts of distributed energy resources and evaluate proposed utility distribution investments (see Cossent et al., 2011; Jamasb and Pollitt, 2008; Larsson, 2005).
In a distributed energy system, these operational and planning functions (or some aspects thereof) will be natural monopoly roles. Policy makers will have to weigh considerations related to existing utility capabilities, economies of scope, and the need for transparency and independence when determining whether the DSO/CESP function should be assumed by distribution utilities, ISOs or RTOs, or new independent entities. To the extent that these functions reside within existing utilities, the focus of the distribution utility would change from being primarily a wires function to one that incorporates much greater reliance on information and communication technology, operational models, and data analytics. Definition and development of the roles and functions of DSOs and CESPs is now beginning to be explored in a number of fora.53
New distributed energy technologies also will create opportunities for utilities and/or competitive suppliers to offer customers a broader range of energy services. Competitive retail energy suppliers could transition from providing commodity electricity service to managing customer energy bills. Some suppliers already offer packages that include smart thermostats that optimize energy usage and automate customer preferences. Suppliers might support enhanced service quality and reliability with the deployment and operation of distributed generation and storage, such as backup generators or PV and battery storage. And there are firms that currently offer microgrid development services to commercial, institutional, and industrial customers.
A wide range of well-funded firms—including providers of home security services (e.g., ADT), telecommunications companies (e.g., Verizon), cable providers (e.g., Comcast), big box retailers (e.g., Lowes, Home Depot),
53 California Public Utilities Commission Order Instituting Rulemaking Regarding Policies, Procedures and Rules for Development of Distribution Resource Plans Pursuant to Public Utilities Code Section 769. Order Instituting Rulemaking, Public Utilities Commission of California Rulemaking 14-08-013, 2014 (August 20, 2014).
manufacturers of consumer electronics (e.g., Samsung, LG) and controls (e.g., Honeywell), and tech giants (e.g., Google, Apple)—are already competing for a share of the market for home energy management services. These firms, as well as start-ups in the market, can be expected to participate in the market for consumer energy services.
Utilities also may become customer-focused energy service providers. Given their existing capabilities and customer relationships, utilities may be able to accelerate the availability of “adjacent energy services.” The utility could provide a portal that would give customers access to such services from third-party suppliers. Alternatively, such services might be available directly from the utility or from a utility affiliate. In vertically integrated markets, the utility might offer enhanced reliability services and demand management through its energy-efficiency or demand-response programs. Some jurisdictions might follow a model, comparable to that used during deregulation of telephone services, allowing utilities to offer adjacent services on a competitive basis, subject to light-handed regulation, with a portion of the revenue offsetting the cost of providing regulated distribution services. Other jurisdictions might require corporate separation of potentially competitive services from regulated distribution functions.
Effective DSOs have the potential to provide support for large-scale deployment of cost-competitive increasingly clean distributed power assets. They could do so in a way that would reduce energy costs while providing greater reliability and value to customers. For DSOs to be effective, however, would require timely development of a number of capabilities, including
- an effective control architecture and systems for the federated management of transmission, distribution (including dynamic distribution topologies), and deployment at scale of distributed energy technologies;
- integrated operational modeling and systems providing real-time operator awareness of multidirectional power flows across transmission and distribution systems;
- a flexible information architecture and related interoperability standards to support the expanded availability of power system operational data and the evolution of operating systems and applications;
- operational models, systems, and applications to support the integration and management of more intelligent and dynamic distribution systems and distributed energy technologies;
- advanced cyber-security systems for a power grid that to an increasing extent relies on information and communication technology;
- distribution-level market structures that can coordinate settlement of multidirectional transactions; and
- enhanced distribution planning models that also are transparent and user-friendly to facilitate regulatory and stakeholder review of distribution planning decisions.
Finding 6-9: The creation of effective DSOs and CESPs will require the timely development of key capabilities.
For these systems to be effective, they will need to be developed based on widely accepted interoperability standards. They also will need to be made ready to defend against and respond to attacks and accidents. Poorly designed systems and those developed without appropriate security will be particularly vulnerable to cyber attack.
Recommendation 6-5: DOE should undertake a multiyear R&D program to ensure the timely development of the capabilities needed for effective DSOs or CESPs through policy analysis; dialogue; and the sharing of experience and best practices among regulators, utilities, and other stakeholders to advance understanding of the emerging business models. DOE should strongly consider prioritizing the development of robust, well-designed systems that incorporate appropriate security measures to guard against and respond to cyber attacks.
Utilities currently face a significant, multifaceted workforce challenge—one that can undermine the potential for positive transformation in the electric power sector if not properly resolved. As of 2008, projections showed 50 percent of the electric utility workforce being retirement-eligible within 10 years, representing more than 200,000 skilled employees (Hardcastle, 2008). This attrition would add to an already existing reduction in the utility workforce over the past two decades. The workforce declined precipitously (by approximately 50 percent) in the 1990s and 2000s as the sector restructured and many utilities began participating in competitive markets. Mergers, acquisitions, and cutting of every nonessential cost through minimal hiring were mainstream in the industry. Over time, these practices drove employee numbers downward and created the gap of workers in their 30s and 40s and concentration of workers in their 50s and 60s now characterizing the sector (Hardcastle, 2008; Lave et al., 2007).
To maintain power system functionality, it is imperative that these employees be replaced as they retire. Yet while replacing a workforce of this magnitude represents an already significant human resource challenge, this
challenge is exacerbated by the fact that new workers will need both to continue operating legacy systems and to meet new requirements (Lave et al., 2007). The changing nature of the electricity sector—as detailed throughout this chapter and elsewhere in the report—requires a trained and motivated workforce with a very different profile from that of the past. The future utility workforce will be responsible for introducing such technologies as those needed for smart-grid operations, and thus will require employees with greater “niche” skills to support the implementation, maintenance, and operation of systems with primarily digital components. Advanced technologies will require employees comfortable with analytical and mathematical methods, possessing spatial awareness, computer proficiency, and problem-solving skills (Lave et al., 2007). New training programs also will be required as outdated guidance documents and technical manuals (e.g., solar interconnection manuals) become updated. The future utility employee will be responsible not only for learning the new standards and procedures associated with these updates, but also for responding quickly and efficiently to the dynamic technological and regulatory environment that will mark the modern electric power system. This level of flexibility is a key differentiator between a modern utility workforce and the more traditional workforce of today. Recruiting individuals with this initial capability and continually training them once they enter the workforce is itself an inherent challenge.
Finding 6-10: The electric power industry faces a challenging shortage of skilled, appropriately trained workers.
Finding 6-11: The necessary skill base for the electric power workforce has changed and continues to evolve. The future workforce will need to be trained in new technologies, such as smart-grid devices, and to implement and maintain new systems, such as advanced distribution networks engineered for two-way power flows and high levels of distributed generation assets.
The main factors contributing to the challenge of recruiting qualified individuals to plan and manage modern electricity systems are themselves interrelated. The curricula of U.S. educational institutions do not emphasize electric power systems and related electrical engineering and computer science foundations. As one example, 13 U.S. universities currently make up the Power Systems Engineering Research Center—a National Science Foundation industry-university cooperative research center that sees itself as “empowering minds to engineer the future electric energy system” (PSERC, 2016). Each of these universities houses programs in electrical and computer engineering, and students obtain disciplinary degrees (e.g., control systems, operations research, economics) for which the coursework may include power system-related
courses. Of these 13, however, only 2 list specialized programs of study in electric power systems (PSERC, 2016). In part, the relative absence of such programs is a direct result of the withdrawal of electric utilities in the wake of deregulation and consolidation from what were previously plentiful utility-university partnerships. Prior to deregulation and restructuring, it was common for electric utilities to engage in long-term relationships with local universities. Utilities would provide tuition scholarships, fund internships, provide general “support” funds for programs of study in electric power systems, and even establish designated power systems research centers within local universities. These programs often provided opportunities for students to master the textbook fundamentals and simultaneously engage in real-world training (Russell, 2010).
Unfortunately, the absence of such programs of study also is due to a lack of demand from students, and this represents the second major factor contributing to the overall lack of qualified applicants. The electric utility industry historically has not garnered perceptions of professional status and “achievement,” and thus has not attracted individuals interested in mathematics, engineering, and computer science, who have gravitated toward other emerging and more “stimulating” industries, such as aerospace and chemicals manufacturing. The electric utility industry also has developed a reputation for not paying as well as others, offering instead a safe, steady, but “dull” form of employment (Lave et al., 2007). Overall, the combination of these demand-side and supply-side problems in U.S. education in power systems is an important factor in the utility workforce challenge.
It is imperative, then, to recreate a vision of the electric power industry as one that is attractive, stimulating, and worth celebrating for the vital role it plays in people’s lives and in driving the nation’s prosperity. Doing so will require encouraging new dedicated degree programs in power systems engineering and electronics at the college and postgraduate levels, as well as chaired faculty and other filled tenure-track positions committed to teaching and research in this area (Russell, 2010). Training also could benefit from beginning in high school and grade school curricula—to emphasize, and generate an interest in and comfort with, mathematics, computer science, and analytical problem-solving skills in young people. In addition to classroom learning modules, training could extend to such activities as power plant tours and even brief work-study arrangements (Lave et al., 2007). Finally, compensating entry-level graduates with competitive salaries would help bolster the image of the electric utility industry as one that is serious and values requisite skills.
DOE could provide support for energy and power workforce development activities. This could include support for industry-educator partnerships for training a skilled, technical workforce. Additionally, DOE could, consistent with the recommendations of its Electricity Advisory Committee, coordinate workforce development activities with those of other federal agencies and the private sector, evaluate the impacts of its American Recovery and Reinvestment Act workforce training grants, and make training curricula and content
Planning and implementing new (or modified) educational programs across the country will take some time. In the meantime, utilities can undertake—and governments can support—several initiatives that can help bridge the immediate gap in the skilled workforce. Knowledge retention programs will be essential as retirement-eligible staff with technical and institutional expertise exit and inexperienced new hires enter the workplace. Increasing an employee’s compensation for participating in additional voluntary new-hire mentor programs, as well as other incentive programs, such as allowing phased retirements whereby employees can reduce their hours gradually over a few years’ time, could help ensure that utility and industry-specific knowledge is preserved (DOE EAC, 2014b).
Finding 6-12: Industry-educator partnerships are the most effective way to train a skilled, technical workforce, and can bridge the immediate gap in the skilled electric utility workforce. Governments can support such initiatives to make them more effective.
Utilities and customers also could benefit from expedited deployment of many advanced grid technologies. Outage management systems provide one example. Such systems can save costs associated with incorrect outage reports by verifying power outages at customer facilities. PECO estimates that it avoided 7,500 crew dispatches in 2005 because it was able to see that those customer-reported outages were inaccurate (Pritchard and Evans, 2009).54 More recently, in 2012 Oncor implemented an integrated system of advanced meters and an outage management system along a 3.2 million meter-long network, capable of remotely sensing outages and restoring power to customers before the outages are physically sensed at the customer site. In the first 6 months, this new system helped Oncor avoid hundreds of power outages (Wolf, 2012). Intelligent, integrated systems such as these not only reduce costs by increasing operational efficiency, but also deliver real value to customers in the form of increased reliability and heightened confidence in the utility’s abilities.
54 PECO, the former Philadelphia Electric Company, is a distribution subsidiary of Exelon Corporation.