3
The Evolving Electricity System and the Potential Role of Advanced Nuclear Reactors
The electric power system is undergoing its greatest and most uncertain transition yet, underpinned by many new realities, including, but extending beyond climate change. The deployment of advanced nuclear reactors could be affected by—and affect—the drivers and trajectory of this transition. Supply is changing as a new suite of low-carbon power generation technologies enter the market. Demand is also changing as more energy services (e.g., transportation and space heating) are electrified and active demand management strategies are employed. The supply and energy management options available to customers are changing, as are customers’ expectations for reliability, resilience,1 affordability, and equity. The regulatory system is evolving to address these changes and to reflect an altered economic environment. While this evolution is under way, the threats facing the aging electric power system are becoming more acute, including extreme natural events borne by climate change and physical and cyber sabotage (NASEM 2021b).
This chapter will address major drivers of change in the electricity sector and their implications for advanced nuclear technologies. Key to the discussion is a recognition that the drivers of change are interdependent, and the prominence of each is affected by location—regulations, markets, power system topology, and local attitudes play a large role in shaping the extent of the drivers for change and the speed at which changes might unfold. Moreover, these changes to the electric power system could either bolster or reduce the competitiveness of advanced nuclear power: the fact that advanced reactors are not yet commercialized makes reliable assessments of their role in the future power system difficult.
THE POTENTIAL COMPETITIVENESS OF NUCLEAR
A large suite of technologies has emerged that is altering both power supply and power demand. Most prominent among these are renewable energy systems and storage; the growth of residential and commercial energy management models like variable tariffs, smart metering, demand response, and microgrids; and the accelerating electrification of transportation, buildings, and industrial processes.
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1 Reliability refers to designing and operating the grid so that sufficient electricity is distributed to customers in a safe and stable way. Resilience, while intertwined with reliability, refers to the ability of a system to withstand and recover from extreme events, whether owing to weather and natural events, physical sabotage, or cyberattacks.
To compete in this changing electricity system, advanced nuclear power needs to be (1) affordable for owner investment without “betting the company”; (2) economically competitive with other technologies, including renewables and energy storage; (3) socially acceptable, enabling communities to accept reactor siting proposals; and (4) commercially available to utilities as they make large investments in electrification in the next few decades.
Even in future electricity grids with high deployments of wind and solar, clean, firm, generation resources will still be required. Advanced nuclear reactors could have substantial market opportunities for supplying reliable and flexible electricity generation, as well as in supporting the further expansion of the electrification of end uses in other sectors (transportation, buildings, and industry). The scale and speed required to achieve the full clean energy transition within challenging timescales may make it attractive to reuse existing transmission lines or other facilities that are now linked to fossil fuel thermal generators (coal and gas plants). Nuclear power could also generate electricity at high-capacity factors2 and recover costs by serving non-grid energy needs (the focus of Chapter 5), such as the production of hydrogen. However, in each case, this is most likely to happen only if nuclear costs are competitive with low-carbon alternatives and the other barriers to deployment discussed in this report are resolved.
At the same time, it is important to recognize that there are multiple pathways to a reliable, decarbonized electricity system, with or without advanced nuclear technologies. Advanced nuclear will be competing against other forms of zero-carbon energy to provide energy, capacity, and grid stability.
THE CUSTOMER: CHANGING EXPECTATIONS
On the demand side, the “average customer” in 2030 could need and expect a host of services from the electricity system that do not exist today or would be considered niche services. Some customers want freedom of choice to pursue energy alternatives. Some desire to become completely self-sufficient and disconnected from the grid. Some customers also want to pursue renewable technologies as a commitment to contribute to the reduction in carbon emissions. Large commercial and industrial customers are responding to growing interest by their investors in environmental, social, and governance goals (BusinessWire 2020; Eckhouse 2020; Wongtrakool 2020; Venkataramani 2021; Saad 2022). These changes in customer preferences have a potentially significant impact on planning, load profiles, and grid architecture. Any movement for the design, planning, construction, and operation of new nuclear facilities must consider these elements, some of which might make new nuclear technologies attractive—if their benefits are demonstrated.
Multiple socio-technical forces are catalyzing this shift in households, chief among which is the existence and increasing affordability of a host of new distributed energy resources that enable customers to generate electricity on-site. This option once was the province of large institutional customers, such as manufacturing facilities, but is now open to individual households as well. In addition to a substantial decrease in the cost of solar photovoltaic systems and energy storage, new technologies like microturbines and hybrid battery-generator systems are emerging. Two other key technical developments are revolutions in building science and appliances that could dramatically increase energy efficiency. Attempts to decarbonize other sectors of the economy are rebounding on household energy use as well; electric vehicle charging at home is an example of a currently unfolding technological change that will increase household energy consumption and potentially stress power grids. Last, there is a shift in engagement between technologies and their users, with some demanding the ability to exert greater control over when their energy systems consume electricity. This last shift has been enabled by information and communication technologies that have made visions of smart homes possible. Individuals and households pursue these technologies for many reasons. In addition to reducing their electricity bills, some consumers seek to reduce consumption or minimize greenhouse gas emissions. There is also a growing preference among consumers for “local” economic activity, where possible, and of disentangling themselves from large corporations. Some customers are also demanding deeper social and environmental commitments from the companies they patronize. Companies are starting to recognize and respect these demands and are making ambitious social and environmental commitments, including the pursuit of net-zero emissions (Melville 2022).
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2 A measure of how much energy is produced by a plant compared with its maximum output. High-capacity factors reduce the per unit cost of electricity and can be an important component for a plant to recover costs and be economically viable.
Some of these trends extend beyond households and exist among commercial and industrial customers. However, the preponderance of effort among those customers has focused on ways to lower electric service bills, ensure quality power (voltage, frequency), or increase reliability. Deploying generators and other electric power systems on-site enables these customers to enhance power quality or to avoid significant demand charges by shaving peak loads or shifting demand. Some have gone so far as to establish microgrids that would enable them to ride through outages without service interruption—a market that is growing rapidly (ReportLinker 2022; Technavio 2022). As extreme weather events increase in intensity and frequency, supply and demand become more variable and dynamic. The consequences of poor resilience will become more visible, as evidenced by the recent disruption at Samsung’s Austin semiconductor fabrication plant, a consequence of the 2021 Texas power crisis (Carlson 2021). The extent to which future nuclear reactors, including small and microreactors, can capitalize on these trends is unclear, but worthy of analysis.
New and advanced nuclear reactors have the potential to serve smaller, more diffuse loads, which could fit well into the more decentralized generation needed under a decarbonized energy system. However, even as novel deployment models and business cases for small and micro reactors are envisioned, they will be subject to the same level of scrutiny regarding safety, reliability, affordability, and equity once a site is chosen.
THE GRID: CHANGING DEMAND AND SUPPLY, AND IMPLICATIONS FOR RELIABILITY AND RESILIENCE
Changing Demand and Supply
Both electricity demand—and the generation sources that supply this demand—are expected to change considerably between now and 2050. Customer demand for electricity will evolve owing to multiple factors, including electrification of end uses, energy efficiency improvements, production of low-carbon fuels including hydrogen, and changes in demography. These drivers affect the magnitude, shape, and flexibility of customer electricity demand, which in turn affects the use cases and business strategies of advanced nuclear technologies. They also affect how the grid should evolve.
Among these expected changes, electrification and the overall growth in demand offer the greatest market opportunity for advanced nuclear power. After over a decade of relatively flat growth in the United States, customer electricity demand is poised to increase (EIA 2021a), with electrification of new end uses being the primary contributor to this growth (see Figure 3-1). The electrification of passenger cars will drive this growth in the near term, but electrifying other end-uses, such as space heating and some industrial processes, will likely continue to boost demand well into the 2040s and 2050s, as economies seek to achieve deep decarbonization targets.
To meet this new demand, most studies forecast or demonstrate potential for significant growth in wind, solar, storage, and transmission owing to falling technology cost projections for wind, solar, and batteries (DOE 2021; Cole et al. 2021b; NAS 2020; Clack et al. 2020; Larson et al. 2020). For example, DOE’s Solar Futures Study shows the potential for solar alone to meet more than 40 percent of electricity demand by 2050 as part of a 95 percent decarbonized grid (DOE 2021). This much solar is economically possible only because of the expected growth in diurnal storage—that is, <12 hours of discharge at rated capacity—which can shift the oversupply of daytime generation to serve evening load storage (Frazier et al. 2021). Growth in these technologies also require adequate sites, materials, manufacturing supply chains, workforce, and permitting, among other factors needed to sustain growth (DOE 2021). Low-cost natural gas—driven greatly by the increase in hydraulic fracking—has made the market penetration of alternative sources of energy generation difficult and may, in the absence of decarbonization policies, continue to pose a barrier to entry for advanced nuclear technologies. Without decarbonization policies or high fossil fuel prices, developing and deploying advanced nuclear reactors could remain difficult.
Estimates of the role for advanced nuclear energy in this mix is highly dependent on assumptions. A recent multi-institution study led by the Electric Power Research Institute (EPRI)—with the Environmental Protection Agency (EPA), Energy Information Administration (EIA), and National Renewable Energy Laboratory (NREL)—aimed to understand how model structures and input assumptions affect nuclear energy in long-term planning models (EPRI 2022). The assumptions with the greatest impact on nuclear deployment were policies and technology cost. The model comparison showed that decarbonization policies support existing nuclear generation
but are not sufficient to support significant new nuclear builds in the absence of significant cost reductions or a nuclear technology carveout.
The EPRI study is consistent with many recent studies that show significant growth for new nuclear to meet grid needs3 when certain conditions are met:
- Nuclear costs are substantially lower than those experienced recently in the United States (~$2,000–$4,000/kW). In this case, nuclear is competitive regardless of other factors such as decarbonization policies, timing of advanced nuclear’s commercial availability, and assumptions about renewable energy (RE) and natural gas competitiveness (EPRI 2018, 2022; Cole 2021b; Larson et al. 2021; IEA 2022).
- Highly constrained growth of RE and transmission owing to issues such as supply chain or land availability, which in turn increases overall system cost, enabling nuclear energy to be competitive at higher costs (e.g., ~$5,500/kW, depending on assumptions). These conditions also assume commercial availability starting in 2035 (or sooner) and stringent decarbonization policies (Larson et al. 2021; Denholm et al. 2022).
- Limitations on availability of other technologies that provide capacity (e.g., no biofuels, hydrogen, CCS, or long-duration energy storage) assuming decarbonization policies and $4,000–$6,000/kW nuclear costs (Brown and Botterud 2021).
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3 These studies did not optimize nuclear deployment to include meeting non-grid energy demands. These opportunities are discussed in Chapter 5.
Long-term capacity expansion models such as featured in the EPRI study do not alone address the full suite of questions related to power system planning. Future market and generation capacity expansion models include many uncertainties and are highly dependent on model formulation, cost assumptions, and policy evolution. No model can account for the full range of possible scenarios and non-economic attributes. For example, the Los Angeles 100% Renewable Energy (LA100) study (Cochran and Denholm et al. 2021) employed more than 15 models to evaluate reliability, distribution grid interactions, and environmental justice, among other questions that are central to planning.4
Broadly, studies show that while nuclear capital costs are an important driver for nuclear’s deployment, there remain situations in which nuclear generation can be competitive. For example, a more uncertainty-oriented approach would incorporate aspects of “real options” that value the future trajectory of technology options and ensure that options are not prematurely eliminated from consideration. While the approach may ultimately not yield decisions to deploy nuclear as a low-carbon alternative, it would properly reflect the value that is inherent in maintaining flexibility in grid expansion decision making (Caunhye et al. 2022). Balanced approaches to decarbonization that incorporate a wide variety of technologies can also spread risk across multiple supply chains and limit challenges in integration (IEA 2021; Brick and Thernstrom 2016).
Finding 3-1: Electrification owing to economy-wide decarbonization presents a significant market opportunity for advanced nuclear generation to serve the grid, particularly if its widespread commercial availability occurs when utilities are scaling up infrastructure to respond to this demand. Nuclear’s competitiveness to serve this new demand is sensitive to cost projections. Models suggest that advanced nuclear will likely be competitive if sufficiently low costs are achieved (e.g., $2,000–$4,000/kW) regardless of other conditions. Advanced nuclear could also achieve significant growth at higher cost ranges (e.g., ~$4,000–$6,000/kW) if other power system costs are higher than expected (e.g., owing to limited transmission growth or limited materials) or there is growing demand for non-electricity products (e.g., hydrogen).
Implications for Reliability
In a more electrified economy, grid reliability is paramount. The changing grid, especially the growth of inverter-based technologies5 on both the bulk power and distribution grids, raises questions about how to maintain and strengthen reliability and how to create regulations and market signals that incentivize attributes needed for reliability, at both investment and operating timescales.
The North American Electric Reliability Corporation (NERC) defines reliability in terms of two aspects: adequacy and operating reliability.6 Adequacy is the ability of the electric system to always supply and deliver the aggregate electric power requirements of electricity consumers, considering scheduled and reasonably expected unscheduled outages of system components. Operating reliability, meanwhile, is the ability of the electric system to withstand sudden disturbances, such as electric short circuits or unanticipated loss of system components (NERC 2007).
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4 LA100 evaluated scenarios to 100 percent RE in which the utility retains its Arizona-based nuclear generation. While nuclear does provide capacity during normal operations and helps offset the need for new RE supply, its distance from the load center and reliance on transmission means that this source of generation might not be available for LA’s critical contingency planning events, such as multiple transmission outages owing to earthquakes or wildfire mitigation. Instead, the LA100 study meets adequacy requirements in LA by building local sources of firm capacity (e.g., hydrogen- or biofuel-combustion turbines). LA100 serves as an example of how a location-specific analysis can better capture transmission and operational constraints that require simplification in national studies.
5 Technologies such as wind and solar generators and batteries produce DC power. They are connected to the grid via power electronic inverters and are referred to as inverter-based technologies. Inverters convert DC power to AC power at 60 Hz, which is compatible with electrical grids in the United States.
6 All bulk power system owners, operators, and users must comply with NERC-approved mandatory reliability and critical infrastructure protection standards. NERC and FERC continuously monitor the bulk electric system and severe fines and penalties are imposed for violations (NERC 2007).
Resource Adequacy
The combination of wind and solar could contribute to the bulk of low-carbon generation, with batteries especially useful at shifting the supply of daytime generation to meet evening demand. But these technologies are not currently cost-effective to meet demand throughout the year (Cole et al. 2021a). During periods of low wind and solar, or periods of high demand, planners must look to sources of firm capacity. Low-carbon electricity generation options include hydropower, nuclear, geothermal, fossil with carbon capture, biofuels, fuels produced from low-carbon electricity, such as hydrogen, and demand response options. These options each have their own constraints but are among the options that utilities are considering today. During periods when wind, solar, and batteries cannot contribute to the system in sufficient quantities, these alternative sources can become competitive, even if they are not otherwise (or generally) competitive based on levelized cost of energy.
Nuclear generation, with its near year-long availability (typically), could help meet energy needs during periods of especially low renewable power production or high demand, but would likely provide above market-clearing price electricity during most of the year in a system with significant deployment of wind and solar. Wind and solar have limited operating costs and thus are typically dispatched first. However, nuclear energy could still be competitive depending on cost projections, further projected increases in load, or if nuclear secures additional sources of revenue for its excess heat or electricity production (Box 3-1).
Operating Reliability
Operating reliability addresses the capabilities needed to maintain voltage and frequency, provide system protection, and recover from disturbances. Synchronous generators were at one point considered essential to grid reliability, but inverter technology has advanced considerably over the past decade and already exceeds
the performance of synchronous generators in maintaining grid frequency if the underlying energy is available (EPRI 2019; Loutan et al. 2017). More recent advances have centered on the inverters evolving from grid-following to grid-forming technologies, in which they actively and autonomously control frequency and voltage. For example, a portfolio of research is exploring how grid-forming inverters can black-start a system (restoring a power system after an outage without relying on a broader transmission grid) and provide other services (Sajadi et al. 2022; Lin et al. 2020; Lasseter et al. 2020). Continued technological and cost advances in inverter technologies could enable a new class of technologies to provide the full range of essential grid services. These changes, in turn, would affect the value of grid services and methods to incentivize their provision.
While these grid-forming technologies have been demonstrated at the device and plant levels, the grid is not yet prepared to operate completely on inverter-based resources. However, given the significant growth expected of inverter-based technologies, many of the questions about the technology will need to be addressed in the coming decade, in advance of the commercial availability of advanced nuclear generation.7 For example, Maui will soon be able to supply its 70,000 customers with 100 percent inverter-based generation for many hours of the year (Hoke 2020). Larger grids such as ERCOT and Ireland have already managed 66 percent and 70 percent instantaneous inverter-based generation levels, respectively, through combinations of approaches including grid-forming inverters, synchronous condensers, and demand-side response (Matevosyan et al. 2019).
The role of advanced nuclear generation in providing essential grid services beyond the provision of energy (e.g., providing voltage and frequency stability) could come down to a question of cost in comparison to both inverter-based and non-inverter technologies such as synchronous condensers, fossil with CCS, or combustion turbines fueled by renewables or other low-carbon resources. In addition, the extent to which grid-forming inverters do not just mimic the characteristics of synchronous generation but establish a completely new approach to grid stability that focuses on inverter characteristics could also affect the need and market value for nuclear capabilities.8
Finding 3-2: Grid reliability is paramount in an increasingly electrified economy, and a broad range of low-carbon technologies are currently available—or soon will be—to support reliability, both resource adequacy and operating reliability. On resource adequacy, advanced nuclear power can provide the high-value, low-carbon energy needed when wind, solar, and batteries are unavailable, but its overall economic competitiveness depends on the value of its (grid or non-grid) energy at other times of the year. Regarding operating reliability, advanced nuclear will be competing with many technology types—conventional and inverter-based—to offer grid services such as voltage and frequency stability. While the grid is not yet prepared to operate solely on inverter-based resources today, reliability solutions have the potential to evolve rapidly to match the growing deployment of inverters. These advancements, which could occur before commercial availability of advanced nuclear, could affect the market value for nuclear power to provide essential grid services.
Resilience
The climatic, technological, and political forces that are remaking the electric power system will have profound repercussions on how to assess and ensure system resilience. Resilience is interrelated but distinct from reliability. Where reliability focuses on what is needed to keep the grid operational through different kinds of
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7 Remaining questions include how operations can be maintained with a mix of grid-following and grid-forming inverters; how the programmed inverter controls can be coordinated so that they do not counteract each other and raise new stability impacts; and how to evolve black start strategies from today’s top-down, serial-restoration approach to a bottom-up, parallel inverter-based approach in the future (Gevorgian 2020). In parallel, grid codes and market designs will need to be revisited as approaches evolve.
8 A system with high levels of inverter-based generation will require different controls compared to a system based on synchronous generators owing to the underlying differences in dynamics. There could be conditions in which operational security and stability is more easily provided exclusively by grid-forming inverters that adjust to real-time settings than by a mix of grid-forming and synchronous generators (Sajadi et al. 2022).
events (e.g., generation or transmission outage, surge in demand), resilience focuses on how to recover from an event in which power is disrupted. More specifically, resilience is the ability to prepare for and adapt to changing conditions, maintain critical service during times of disruption, and recover rapidly from disruptions, including deliberate attacks, accidents, or naturally occurring threats or incidents (Figure 3-2).
Growing fears of cyber-physical disruption and extreme weather events have led to an increased focus on resilience in the past two decades. For example, every 2 years, the North American Electric Reliability Corporation (NERC), under its Information Sharing and Analysis Center (E-ISAC), conducts high-level virtual event tests—known as GridEX—to test the response and recovery plans of participating organizations in the face of events that disrupt the grid (such as extreme weather) or simulated cyber or physical attacks.
The discussion about resilience among utilities has nothing to do with choosing a specific generator type. Improving power system resilience requires expensive, laborious, and coordinated implementation of strategies that are “in the weeds” (NASEM 2017). Resilience requires extensive preparation—rarely at the level of generators, which are already highly resilient, but at other levels of the power system, and must involve investments in grid hardening, fuel storage, situational awareness, and the deployment of distributed energy resources (Campbell 2012) and advanced grid operations. In each case, site-specific considerations are of paramount importance, and have much more to do with standard operating procedures regarding vegetation management cycles and rapid post-disaster access to sites than they do with the choice of a specific generator. Nuclear reactors, like most generators, are generally resilient to weather events (NEI 2018). For example, in 2018, all but 1 of the 20 reactors in Hurricane Florence’s path across the Carolinas, Georgia, and Virginia remained operational at full power throughout the storm. However, as climate change increases the intensity of severe weather events, nuclear power plants, like most generators, will be tested to new extremes (Jordaan et al. 2019; Ahmad 2021). For example, in the recent Texas storm of 2021, inadequate weatherization of feedwater pumps required one of the nuclear units at the South Texas Project to go offline (World Nuclear News 2021), and France cut nuclear production at several plants during July and August 2022 heat waves owing to excessive cooling water temperatures. The 10 biggest blackouts in
U.S. history have occurred within the past 30 years, and half of those in the past decade. The frequency and severity of these events is expected to increase as climate breakdown continues.
Finding 3-3: At the moment, investors rarely focus on resilience in choosing among generators, except in highly constrained environments, because generators are relatively more resilient components of the grid. When it comes to enhancing power system resilience, utilities focus on the transmission and distribution systems because they are more vulnerable to damage.
Recommendation 3-1: A forum similar to GridEX should be established by vendors, utilities, and industry support organizations, with the active participation of experts from the Departments of Energy and Homeland Security, to elaborate any additional risks that emerge owing to novel reactor deployment paradigms—such as placing reactors in industrial parks, underground, at sea, or in close proximity to multiple other modules, or controlling them remotely—and develop rules, guidelines, and standard operating procedures for reactor operators that ensure nuclear power’s continued resilience and that seek to capitalize on the proposed versatility of advanced nuclear reactors.
THE REGULATORS: PRICING AND REGULATORY REFORM WILL AFFECT NUCLEAR COMPETITIVENESS
The evolution of the grid will necessitate the development of new regulatory regimes and rate structures to adequately manage the grid and maintain public infrastructure. There are constant interactions among the physical elements of the grid, information and communications technologies, and organizational aspects. Changes in one aspect require changes in the others, and grid evolution is already leading to increased investment in grid technologies, digitization, data analytics, distribution system sensing and monitoring, and controls to enhance operational efficiency and to integrate new resources.
Grid operators and utilities are carefully considering what reforms may be necessary in wholesale energy and ancillary service markets to maintain reliability and resiliency. To address these issues, the Federal Energy Regulatory Commission (FERC) has been conducting a series of technical conferences focused on reforms that modernize electricity market design, including critical questions regarding the nature and timing of such reforms. There is growing recognition that balancing a grid with generation and load that are both increasingly variable requires incentivizing operational flexibility and firm capacity. If new and advanced reactors prove small and versatile in their ability to load-follow, these market reforms would help the competitiveness of nuclear resources.
A white paper prepared by the FERC staff (Docket No. AD21-10-000) states that Regional Transmission Organizations (RTO) or Independent System Operators (ISO) have increasingly had to rely on out-of-market actions (e.g., manual commitments, posturing, load biasing) to address the limitations of conventional RTO/ISO market design and manage resource variability owing to insufficient levels of operational flexibility. These out-of-market approaches can undermine price formation in energy and ancillary service markets and reduce incentives for investments in the flexible resources needed to manage operational uncertainty. RTOs/ISOs are adopting different market reforms to address the expected operational challenges associated with the changing customer resource mix and load profiles. To address these challenges, FERC leadership is focusing on three prime issues: “how system needs are changing; how those changing services are being procured in organized markets; and the best way to price products and services” (FERC 2021).
Regulatory Reform
Regulation plays a key part in how the electric power system will evolve, and it continues to be stimulated by major energy legislation. Congress has recently passed the bipartisan Investment and Jobs Act (Infrastructure Law) and the Inflation Reduction Act (IRA). Together, these laws will help fund the rebuilding of critical infrastructure and enhance investment in clean energy to tackle the growing threat of climate change. The Infrastructure Law provides more than $65 billion to upgrade power infrastructure in the United States by funding the addition of
thousands of miles of new transmission that could help integrate clean energy technologies. This law also provides $7.5 billion to build out a national electric vehicle (EV) charging network; $65 billion for high-speed Internet through broadband infrastructure deployment; and $50 billion to make the electricity infrastructure more resilient to the impacts of climate change weather events and cyber-attacks.
On the regulatory front, FERC, electricity market operators (i.e., RTOs/ISOs), federal power marketing entities, public power utilities, and state regulatory commissions play a vital role in the development and enhancement of the electric transmission system. The National Academies in its recent publication The Future of Electric Power in the United States emphasizes the need for “support across the government for the evaluation, planning and siting of regional transmission facilities in the U.S.” (NASEM 2021).
Along those lines, FERC has recently issued a Notice of Proposed Rulemaking (NOPR) in Docket No. RM21-17 addressing regional transmission planning and cost allocation. This NOPR can encourage greater dialogue involving FERC, DOE, the Department of the Interior, state commissions, utilities, other transmission providers, RTOs/ISOs, and other key stakeholders.
FERC has stressed in the NOPR that robust, well-planned transmission system is foundational to ensuring an affordable and reliable supply of electricity. FERC has also supported a joint state/federal board to address the broad array of issues surrounding cost allocation and siting issues. It is hoped that these two major initiatives will jumpstart the expansion of transmission to integrate advanced new nuclear and other evolving technologies.
Despite the accomplishments of past legislation and regulation, the regulatory process is slow; it cannot respond to rapid changes in technology and changing customer expectations. Greater informal collaborations are needed to expedite and improve critical decision-making in areas of particular concern. The regulatory and economic environment needs to encourage innovation and seek to mitigate rather than expand risks that arise from uncertainty in the regulatory process. The structures of the electricity system in the United States limit what is achievable through action at the federal level, and thus the states are vital laboratories for experimentation and implementation.
States with renewable mandates have changed their supply mix. Over the past 8 years, more than half of new electricity generation capacity was wind and solar. With these developments, the grid is becoming more transactive9
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9 The National Institute of Standards and Technology defines transactive energy as “a system of economic and control mechanisms that allows the dynamic balance of supply and demand across the entire electrical infrastructure using value as a key operational parameter” (NIST 2017).
at both the wholesale and retail level. This direction is clear from a recent landmark FERC Order 2222, which allows distributed energy sources at the retail level to be aggregated and participate in wholesale electricity markets on the same basis as utility power plants (see Box 3-2 for additional details).
A recent report by Poudel et al. (2021) examined how small and advanced reactors could be integrated in a distributed fashion to provide benefits to the grid under the context of FERC Order 2222. First, there are critical applications for which these reactors might be appropriate, like military facilities. Second, these reactors might be able to alleviate the need for enormous investments in new transmission infrastructure if they are deployed at problematic nodes along the power grid that are especially congested. Otherwise, transmission congestion would make it difficult to transmit electric power produced from renewable generators to load. This could become especially important as the demand profile changes radically owing to the electrification of vehicles and buildings, as well as the demand-side management strategies. It will not be economic to upgrade the transmission network to handle peak loads in each case and adopting mitigating measures like dynamic pricing—while very useful—can only go so far in resolving this problem.
Third, small reactors could participate in virtual power plants (VPPs) with a hybrid mix of generation technologies. This solution could alleviate issues related to siting reactors very close to communities operating VPPs. VPPs do not have a physical boundary but rather aggregate and coordinate generators, storage, and loads within the distribution system to provide power and ancillary services to the grid. In addition to providing congestion relief, such VPPs can also provide ancillary services such as reactive power support, frequency regulation, secondary and tertiary frequency control, and load following. Continuous coordination with the distribution system operator (DSO) and transmission system operator (TSO) is critical to optimizing VPP operation.
Finding 3-4: Federal Energy Regulatory Commission Order 2222 opens the door for small and advanced reactors to have their output aggregated to serve evolving electricity markets. These reactors, if located on congested transmission nodes, could alleviate the need for new transmission.
Pricing Reform
There also is an urgent need for pricing reform both with respect to wholesale bulk power markets and retail electricity markets. At the wholesale level, particularly in organized markets, the minimum price offers may not be sufficient to sustain the operation of some existing nuclear facilities, let alone new and advanced nuclear facilities.
State regulators and/or RTOs and ISOs support flexible rate structures—including performance ratemaking and other approaches that consider changing customer preferences, loads, power supply mix, and demographics. This new direction could enhance the prospects of nuclear power, particularly with its high historic capital cost. Some nuclear plants in the PJM Interconnection10 were forced to shut down because they were unable to meet the price level that could sustain their base load operation in view of declining renewable energy and natural gas prices. Externalities such as the social cost of carbon are not explicitly considered in wholesale pricing models, so even though nuclear is playing a significant role in avoiding carbon emissions, it is not afforded clean energy priority consideration in organized power markets. That said, any developments that serve to recognize the value of low-carbon energy would benefit a wide range of technologies.
Nuclear power’s carbon-free benefits are typically not priced in today’s markets, so the value of nuclear cannot properly be valued using market prices only. This can send unclear signals to plant owners about how to best manage lifetimes of existing nuclear plants. To address this challenge, both New York and Illinois have given nuclear priority status in their markets in view of its benefits in carbon reduction and role in maintaining reliability. The IRA provides tax credits for energy produced from existing nuclear, which can extend the useful life and enhance the competitiveness of baseload nuclear facilities. It also provides new tax credits to stimulate the development of advanced new nuclear. Changes also are needed in retail electricity markets. Electricity demand
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10 The PJM Interconnection is a Regional Transmission Organization within the Eastern interconnection grid. PJM operates an electric transmission system serving all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.
must be more price responsive, so state commissions should establish time variant tariffs that encourage more efficient use of electricity, as well as performance-based rates. A small percentage of retail consumers can see and respond to real-time prices and changes in energy system conditions. It is important for utilities to probe new rate designs to enhance the relationship with the customer by putting less emphasis on increased usage (sales) to increased breadth and variety of electricity services (electrification).
Finding 3-5: Regional Transmission Operators (RTOs) want to integrate more low-carbon electricity generation resources. The Inflation Reduction Act adds/modifies various clean energy tax provisions in the Internal Revenue Code, which will expand the participation of clean energy technologies, including existing and advanced new nuclear, in wholesale, bulk power markets and retail electricity markets.
Recommendation 3-2: The Federal Energy Regulatory Commission (FERC) should continue to examine approaches to improve the Minimum Offer Price Rule (MOPR) to better value generation sources, like nuclear, that can provide resilience, reliability, and low-carbon benefits. FERC should conduct additional workshops and technical conferences to discuss the development of clearer rules and price signals for clean generation and the capabilities provided by existing and evolving nuclear plants. In making changes to the MOPR, FERC should consider provisions in the Inflation Reduction Act that provide for existing nuclear to receive credits (Zero Emissions Nuclear Facilities Credit) for electricity produced after 2023 and before 2033 and consider legislation adopted in New York and Illinois that recognizes the value of existing nuclear. Last, FERC should consider the potential future impact of a broad range of new and expanded tax credits that apply to new nuclear, renewables, energy storage, hydrogen, and other clean energy technologies that serve electricity markets.
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