Category: Safety

Enhancing the transmission and distribution of electricity is a priority to ensure a reliable and resilient power supply, as demand increases and grid challenges mount.

Providing more electricity to meet growing global demand for power has put a spotlight not only on adding more generation to the grid, primarily through construction of new power plants, but on improvements to the grid itself. Enhancements to support power grid reliability include investments for a variety of technologies, such as battery energy storage systems (BESS), advanced transmission lines, smart grid infrastructure, and distributed generation. Upgrades also focus on improved grid monitoring and control systems that allow for better and faster response to fluctuations in demand and disruptions caused by weather, equipment, or other issues.

“Needed enhancements span across condition monitoring, advanced data analytics, fire mitigation, and improved system control mechanisms,” said John Russell, senior director, Solution Consulting at AspenTech, a provider of software and services for the process industries. “Reliability in these systems is crucial not only for preventing downtime but also for ensuring that power is consistently delivered to consumers with minimal disruptions. Specifically, key areas for enhancement include the implementation of condition-based maintenance, improved data collection with smart meters, AI [artificial intelligence]-powered asset management, and advanced control technologies for both transmission and generation systems. By integrating modern technologies, these systems can proactively address failures, optimize performance, and respond to real-time conditions.”

“Reliability is central to the modern power grid, especially as we integrate more renewables and electrify transportation and heating. Much work has been done in generation and distribution, driven by smarter hardware, predictive software, and data analytics,” said Brandon Young, CEO at Payless Power, a Texas-based electricity group. “On the generation side, predictive maintenance technologies become game-changers. IoT [Internet of Things] sensors and AI are monitoring equipment like turbines and transformers in real time to pinpoint potential failures before they occur. That way, downtime is kept to a minimum, and power generation stays efficient.”

Utilities and grid operators are studying a variety of ways to improve the reliability of power generation and delivery, with data at the heart of much of the research.

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“Reliability enhancements should be approached as a comprehensive, multi-pronged strategy that addresses design concerns and utilizes new and emerging technologies for improved data analytics,” said Michael Bennett, chief transformation officer at Powin, a battery energy storage company. “Up front, suppliers need to design and engineer components with reliability as a core principle. This includes using advanced materials, robust designs, and high-quality manufacturing processes.”

Bennett added, “Ensuring transmission, distribution, and generation assets are equipped with IoT sensors for real-time data collection, monitoring, and reporting capabilities has become a core focus over the past few years as well. These sensors provide operators with actionable insights into system performance and potential issues, allowing them to leverage both cloud and on-premise data to uncover complex insights, correlations, and predictions.”

Thomas L. Keefe, vice chair and U.S. Power, Utilities & Renewables Sector leader for Deloitte, said, “Increasing visibility and control through advanced grid technologies” is a major part of increasing grid reliability. “Sensors embedded throughout the network, including smart meters, automated control systems, and advanced monitoring tools, can provide real-time data on energy flow, equipment health, and grid stability,” said Keefe. “Analyzing sensor data can allow operators to anticipate equipment failures before they happen, preventing outages, enhancing the utilization of existing resources, and ultimately increasing grid reliability.”

Efficiency a Key Part of Upgrades

Upgrades to transmission infrastructure (Figure 1) are just part of the work being done to improve power grids. The need for maintenance, particularly during a period of transition to digitization of energy systems, is evolving as well.

1. Power grids across the U.S. and throughout the world are in need of upgrades to handle increased loads. Those enhancements also are needed to help integrate more renewable energy resources into electricity transmission and distribution systems. Courtesy: Salvatore Ventura / StockSnap

“There are several proactive maintenance solutions to improve grid reliability, such as implementing distributed intelligence [DI] systems for real-time monitoring and diagnostics,” said Matt Smith, who leads the global business and product strategy for the grid management business at Itron, a global group helping utilities develop innovative solutions for their operations. “Additionally, predictive analytics and edge intelligence can identify trouble spots below the substation, enabling utilities to automate fault isolation and repair processes, reducing the need for manual intervention, which leads to faster recovery times and improved grid stability. This integrated approach allows for a more efficient, resilient power grid, especially during times of increased demand or extreme weather events.”

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Smith listed what he called “key enhancements” to improve the overall reliability of electricity transmission and distribution, including decentralizing grids.

“Traditional centralized grids are vulnerable to cascading failures during extreme weather events, like major hurricanes and heatwaves, which are becoming more prevalent. Switching to a decentralized model, which includes incorporating distributed generation resources [such as renewables] closer to demand points, improves resilience,” said Smith. The Itron executive also noted the importance of leveraging intelligent grid edge solutions. “Integrating distributed intelligence into utility systems enables grid sectionalization, allowing power to be rerouted automatically. This reduces outages by leveraging real-time data to detect anomalies more efficiently than manual inspections.”

The use of distributed generation is helping provide additional power apart from centralized power plants. Advanced metering infrastructure is helping monitor power usage in real-time, and supporting demand response programs. And then there are efforts to combat the problems associated with keeping the lights out during extreme weather events.

“At the top of the list for transmission and distribution is grid hardening and modernization,” said Young. “Utilities are replacing aging infrastructure with weather-resilient materials, and deploying smart grid technologies such as automated reclosers, which isolate faults and reroute power almost instantly, reducing outages. The growth in smaller energy sources, such as rooftop solar and batteries, has been supported by distributed energy resource management systems [DERMS] that aggregate them to provide stability to the grid in times of peaks or emergencies. Future technologies, like grid-forming inverters, will stabilize grids with high renewable penetration, controlling voltage and frequency independently and acting as virtual power plants.”

Itron’s Smith said, “EV [electric vehicle] charging stations are an increasingly valuable resource that can be quickly repurposed before and during grid failures to provide grid services and backup power, respectively. Additionally, EV batteries within vehicles, specifically within larger vehicles like buses, offer a robust source of energy storage. These batteries can be tapped during outages to enhance grid resilience and maintain power for critical operations, making them an essential component in modernizing grid infrastructure to cope with outages.”

Deloitte’s Keefe said that reinforcing physical infrastructure is another important step. “Strengthening, upgrading, and hardening key components, such as power lines, substations, and transformers, can not only help handle higher loads but also reduce transmission losses and improve resiliency and energy delivery efficiency,” said Keefe. “A few states have signed bills mandating that utilities consider grid-enhancing technologies as a shorter-term solution in their IRPs [integrated resource plans]. Replacing outdated transformers with high-efficiency models can cut energy consumption by up to 12%, further boosting grid efficiency.”

Keefe added, “Deploying grid-enhancing technologies and advanced conductors to add capacity and flexibility to the existing transmission system [improves] transmission reliability. These technologies offer a cost-effective way to expand capacity compared to rebuilding transmission lines. Upgrading to high-efficiency conductors can minimize transmission line losses by 10% to 20%.”

Keefe also noted how model predictive control (MPC) technology can support reliability. “MPC uses a mathematical model to predict future system behavior within a set timeframe. It is popular in power electronics for managing constraints, multiple inputs and outputs, and nonlinearities. Unlike other control methods, MPC explicitly considers system constraints and optimizes control actions over a prediction horizon. This results in better performance, lower energy consumption, and increased reliability in power electronic applications. In renewable energy systems like photovoltaic [PV] and wind energy, MPC can optimize power extraction and facilitate maximum power point tracking [MPPT]. It also coordinates multiple energy sources, storage devices, and loads to ensure optimal performance and reliability.”

Grid Projects

Jersey Central Power & Light (JCP&L), a subsidiary of FirstEnergy Corp., in December began construction on infrastructure upgrades designed to enhance electric reliability for customers in three Morris County communities in New Jersey (Figure 2). The work, scheduled to be completed in October of this year, is part of JCP&L’s New Jersey Reliability Improvement Project, which is an element of the company’s rate review settlement approved by the New Jersey Board of Public Utilities in February 2024. Equipment enhancements will take place along more than five miles of power lines in Chester, Washington, and Roxbury townships.

2. Upgrades to the power delivery system in Morris County, New Jersey, got underway in December 2024. The construction is part of Jersey Central Power & Light’s New Jersey Reliability Improvement Project. Courtesy: First Energy / Jersey Central Power & Light

Doug Mokoid, FirstEnergy’s president for New Jersey, in a statement said: “The upgrades we’re making under the New Jersey Reliability Improvement Project are part of our commitment to providing safe, reliable electric service for all our customers. These improvements, in particular, target areas where customers have experienced some of the most frequent outages in recent years.”

The New Jersey Reliability Improvement Project is a two-phase effort to enhance reliability for customers on high-priority lines selected based on historical outage data. The first phase, which includes at least $95 million in upgrades, is set to be completed over the next three years, according to FirstEnergy. The second phase, which includes longer-duration projects, is expected to be completed by year-end 2028.

The upgrades include replacing existing infrastructure with thicker, stronger wires and poles that can carry more electricity and provide more resiliency in storms. The work also includes upgrading fuses, and installing additional devices and reclosers that allow power to be rerouted to adjacent lines when an outage occurs, minimizing the number of impacted customers.

Several projects are underway or planned to build new high-capacity transmission lines to facilitate power transfer across long distances, often to move renewable energy resources from remote, rural areas to the grid. Advanced conductor materials are being used to reduce transmission losses. Smart grid tech is being deployed for dynamic load management, and battery storage is being installed along the grid (often at substations) to help with grid flexibility and balancing.

The U.S. Department of Energy (DOE) last year awarded $2.2 billion to eight electric transmission and microgrid projects across 18 states, with a goal of adding electricity delivery capacity and strengthening the grid against extreme weather. Jennifer Granholm, the Energy Secretary during the Biden administration, at the time said the money was part of a program to add 1,000 miles of transmission lines and 50,000 MW of electricity to the grid. Granholm at the time said, “and there’s much more to come,” although it’s not known how the Trump administration will approach funding for electricity transmission and distribution (T&D).

The DOE said $700 million would go to the North Plains Connector project, a high-voltage direct-current power line that would create the first large-scale grid connection between the Eastern and Western interconnections, the U.S. grid systems divided by the Rocky Mountains. Minnesota-based Allete Inc. and transmission builder Grid United are developing the project.

3. Deployment of renewable energy across the U.S. has been slowed by issues with integrating wind, solar, and other clean energy resources to the power grid. Courtesy: Shutterstock.

The Utah Office of Energy Development was awarded nearly $250 million to install 250 miles of advanced conductor cables, increasing line capacity to support delivery of 500 MW of renewable energy (Figure 3) across six states.

Another grant, for $30 million, was made to the New York Power Authority for its Clean Path New York project. That strategy is designed to deliver 1,300 MW of renewable energy from upstate and western New York to New York City, which the DOE said would help reduce reliance on coal- and natural gas–fired power generation.

Handling Increased Demand for Electricity

Technology innovations to improve power generation, transmission, and distribution have brought more complexity into power networks. That means utilities and grid operators are rethinking some of their earlier practices to adapt to a changing energy landscape.

Jon M. Williams, CEO of Viridi, a battery energy storage company, said, “The energy system is on the brink of a paradigm shift that will profoundly reshape energy transmission and distribution. After decades of relatively stable demand [no load growth], the grid must now manage an enormous demand increase resulting from industrial onshoring, the growth of data centers and AI, and, perhaps most significantly, the electrification of heat and transportation. Complexity has also been added as distributed generation resources, like rooftop solar, complicate system management. These antiquated 19th-century grids are decentralizing, and the transition must be accommodated.”

Williams told POWER: “The solution to this challenge will not be to redesign and rebuild the grid of the 19th century. Instead, we must use new advances that prioritize safety, reliability, and enhancing system level efficiencies while focusing investments on technologies that provide layers of benefit. There is no greater technology to benefit power grids as we electrify everything than intelligently managed distributed energy storage. Distributed storage can enhance the value and operability of on-site generation. With advanced connectivity, it can be leveraged as a ‘virtual power plant [VPP]’ to better enable host facility loads for grid support through constraints and failures in real time.

“Behind-the-meter distributed energy storage has the potential to improve resilience, support decarbonization, shave peaks, enhance value of behind-the-meter generating assets, enable utilities to pursue beneficial ‘non-wires’ alternatives, and avoid the massive costs that a replacement of the old grid would entail,” said Williams.

Utilities have developed programs to support a reliable power supply. The American Public Power Association (APPA) has a Reliable Public Power Provider, or RP3, program “that recognizes utilities that demonstrate high proficiency in reliability, safety, workforce development, and system improvement.” The group’s list includes utilities, both large and small, from across the U.S.

Said Young, “Real-world examples show the benefits: Florida Power & Light’s ‘Storm Secure’ program—undergrounding power lines and deployment of smart grid—has reduced outage durations after a hurricane like Irma. Similarly, Pacific Gas & Electric is now using AI to predict the risks of wildfires by analyzing weather, vegetation, and grid conditions in order to take action before disaster strikes.

“This brings, in short, today’s enhancements in reliability toward the goal of making the grid smarter and more resilient as AI and other power-hungry needs increase the demand for energy. Advanced software, durable hardware, and data-driven systems are revolutionizing how we manage and distribute electricity for future needs,” he said.

“The process of monitoring and setting up a system to proactively maintain assets to extend their lifecycle and prevent malfunctioning is also known as ‘asset lifecycle management (ALM)’,” said Terry Saunders, Worldwide Utilities and Industry leader at IBM. “As organizations continue to look for ways to conduct more efficient, cost-effective, and sustainable operations many are turning to ALM. For energy equipment specifically, ALM practices may include installing sensors and using cameras for immediate eyes on equipment to identify factors affecting performance, and using AI-infused software that recommends specific maintenance directed by the data. By approaching maintenance and operations management from a preventive, data-driven approach companies can ensure that their systems are performing optimally for longer, ultimately maximizing their return on investment.”

Tyler Lancaster, partner at Energize Capital, a group that invests in climate technology, including renewable energy, told POWER: “A big shift in the power sector has been moving away from cycle-based maintenance programs to data-driven, proactive maintenance programs. Some aspects can also be automated to drive further efficiency and reliability. This is true across every form of power infrastructure.

“For example, historically, utility poles were inspected on a cycle once every five to 10 years. Over time, utilities and their service providers have built up a large amount of data and information on common failure modes for utility poles,” said Lancaster. Increasingly, analytical models can be applied to estimate the probability of failure for each pole based on the type of wood, environmental factors like moisture, location, etc., and can tailor maintenance activities to inspect and repair higher risk poles sooner.

Lancaster said it’s difficult to standardize operations to improve reliability. “This is a key challenge for the power sector, as operations tend not to be ‘one-size-fits-all.’ Different grids, with different environmental factors and natural systems, with different power infrastructure configurations—generation mix, T&D system setup, consumption segmentation and load profile, etc.—require tailored operations to ensure reliability. Where operations can be standardized is through the use of modular and adaptable technologies which can be easily configured to the unique needs of a specific power plant or grid operator’s context.”

“Standardization can play an important role in power system reliability as it promotes consistency, predictability, and interoperability,” said Keefe. “It can help reduce human error, and improve communication and coordination—especially during emergencies, with faster response times, etc.”

Combating Failure

Working to eliminate grid failures, or at least mitigate their impacts, is a goal of those working with utilities and grid operators. That can involve gathering data, knowing how to interpret it, and also having systems in place to deal with issues as they arise.

“Reliability at the equipment or component level is driven by two key factors—probability of failure and impact of failure. Enhancements that address one or both these factors are key to improving reliability,” said Steve Morris, a managing director with FTI Consulting’s Construction, Projects & Assets practice. “Whether it’s a power plant or the grid, reducing the probability of failure comes down to maintaining the assets in good operating condition through preventive and condition-based maintenance. Reducing the impact of failure is reliant on having redundancy in the system so that the failure of a single asset or component doesn’t reduce plant or system performance.”

Morris said, “For a power plant or electric substation, this is typically achieved by having spare capacity that can be used if there is a failure. For example, instead of having one power transformer in a substation running at full capacity, you would have two running at 50% or less capacity. If one fails, you can switch the other with no impact on the system. For the transmission grid, in most cases, if a single transmission line fails, there is sufficient capacity to switch to another transmission line, which has spare capacity. For the distribution grid, redundancy is achieved by interconnecting circuits and having auto reclosers, which can automatically restore after a fault is cleared, and sectionalizers that can section off parts of the system to reduce the number of customers impacted by an outage.”

Sally Jacquemin, vice president and general manager, Power and Utilities at AspenTech, told POWER: “Redundancy plays a vital role in maintaining the reliability and stability of both power plants and power grids. As the energy landscape shifts toward greater integration of renewable sources like wind and solar, the variability of these resources increases the importance of backup systems. Redundant infrastructure, including reserve generation and microgrids, ensures that power continues to flow smoothly during both planned and unexpected disruptions, such as outages or system failures, minimizing the risk of blackouts.”

Jacquemin said, “Historically, utilities maintained excessive reserve generation to protect against worst-case scenarios, ensuring power availability in case of failure. Today, however, there is a balance between maintaining enough redundancy to prevent outages and avoiding over-investment in reserve capacity. Modern systems focus on understanding the critical threshold of necessary redundancy, ensuring operational efficiency while still providing reliability in the face of unexpected events like sudden generation loss or extreme weather conditions.”

Jacquemin added, “Microgrids and localized redundancy solutions are increasingly important as they allow certain areas to maintain power even when the larger grid is disrupted. Powered by local generation sources like solar or batteries, microgrids can operate independently, providing resilience during storms or grid failures. The integration of renewable energy further highlights the need for redundancy, as renewables introduce variability that requires additional backup systems, such as storage or traditional generation, to ensure a reliable and stable power supply.”

“Redundancy is most important for the transmission system as North American Electric Reliability Corporation [NERC] requires that the transmission system must be able to handle the failure of a single component without causing a significant outage,” said Morris. “Therefore, transmission lines and substations are designed with redundancy. Redundancy is less important for power plants as typically a single unit of a power plant only produces a small portion of the power on the grid. In addition, power grids are required to have reserve capacity to be able to handle unit unavailability, maintenance, and higher than normal demand. The distribution system is similar to power plants in that most equipment serves a small number of customers, so a failure has little impact on the overall grid. Therefore, there is little redundancy in the system, other than in substations.”

Morris listed several ways to enhance reliability of power generation and the transmission and distribution system. He noted that advanced distribution management systems can automatically detect faults, and also identify the impacts of anomalies. He also noted a distributed energy resource management system “monitors, optimizes, dispatches, and manages all types of distributed energy resources including black start for grid shutdowns. Dynamic line rating calculates real-time transmission capacity of a line to optimize capacity usage to reduce congestion.” Meanwhile, an “asset performance management system monitors real-time equipment condition to identify [any] need for maintenance or indicate increasing risk of failure.” Morris also noted what he called “non-intrusive inspection,” which can help operators “understand power plant equipment condition without taking it apart. [This] includes technologies such as ultrasonic, radiography, eddy current, magnetic particle, acoustic emission, dye penetrant, leak testing, vibration analysis, and thermography.”

Lancaster said there are programs that can be implemented to enable proactive replacement and/or restoration of older equipment—both software and hardware—in power plant and power grid systems. He referenced his earlier comments about power poles, and said, “Another example is for transformers. Transformers are a key piece of equipment for the electric transmission and distribution system. They convert high-voltage electricity down to the lower voltages, eventually to the 120V type that we commonly use in our homes and businesses.

“There are several methods that have emerged to predictively identify transformer failure through sensor technology and data science or machine learning techniques,” said Lancaster. “For example, sensors that measure the accumulation of dissolved gas particles in the oil contained within a transformer can prevent transformer failure before it causes broader damage to other power grid equipment nearby.”

Utilizing Digital Twins and Energy Storage

Ildi Telegrafi, a policy fellow at the Alliance for Innovation and Infrastructure, said digital twins—often used to study power generation equipment—can also be a vital part of understanding electricity transmission and distribution.

Cybersecurity and Grid Reliability

Shankar Somasundaram is CEO at Asimily, a risk management platform that secures Internet of Things (IoT) devices for healthcare, manufacturing, public sector, and other industries that depend on numerous connected devices. Somasundaram talked with POWER about how enhancements to support grid reliability also should address cybersecurity issues (Figure 4), especially with more digitization in power plants and along the transmission and distribution system.

4. Global and U.S. energy infrastructure, particularly the power grid, has become a major target for both physical attacks and cyber threats. Grid operators and utilities are responsible for protecting their systems from risk, with the federal government and national laboratories supporting those efforts as part of their mission to protect national and economic security. Courtesy: Asimily

“Cybersecurity has become an increasingly fundamental variable for power system reliability as utilities digitize operations and add more network-connected devices and equipment,” said Somasundaram. “As headlines in this industry continue to show, a more interconnected power infrastructure—particularly its operational technology [OT] systems that directly control physical equipment—means that cyber vulnerabilities can directly impact system reliability.

“In transmission and distribution systems, cybersecurity measures need to protect essential OT components like supervisory control and data acquisition [SCADA] systems, smart meters, and automated switches through authentication, encrypted communications, and continuous network monitoring,” said Somasundaram. “Power plants require additional protection for their digital control systems, including distributed control systems [DCS] and programmable logic controllers [PLCs]. This necessitates network segmentation, regular security patching, and strict access controls to prevent equipment damage or forced outages.”

Somasundaram told POWER, “Supply chain security and the human element are equally crucial for reliability. Utilities must verify the integrity of software updates and new internet-connected equipment while maintaining comprehensive training programs for personnel who operate and maintain OT systems. Building a culture of cybersecurity awareness cannot be glossed over.”

Somasundaram said as more automation enters maintenance programs, more vulnerabilities to cyberattacks are exposed. “From a cybersecurity perspective, every component in a power plant and the grid is potentially vulnerable if it has an access port. Historically, physical protection and maintenance have provided a strong defense. However, as network access and its many benefits are deployed more, this physical security is becoming less effective,” said Somasundaram. “Cybersecurity maintenance for power plants is like the price of democracy—it requires constant vigilance. This vigilance involves always detecting potential and current attacks. This requires processes backed by software that continually look for evidence of such weaknesses and attacks. When evidence is found, it’s important to act quickly to close security gaps or, in the worst-case scenario, terminate a successful attack.”

Somasundaram added, “Fortunately, much of this has been automated by the software industry. Implementing people and processes to leverage this technology effectively and act quickly, however, is not always in place. Ensuring this implementation is key to maintaining automated maintenance and reliability.”

“The clean energy transition is driving the energy industry toward a new dynamic with vast renewable energy resources that can supply a high volume of energy over the year but with high intermittency,” said Telegrafi, who is also an analyst for New York-based utility Con Edison. Telegrafi said the need for bidirectional power flow management, and the inclusion of energy storage onto the grid “to stabilize intermittency and flatten the peak,” means “the tools necessary to manage this continually changing dynamic are digital. Balancing an ever-increasing power dynamic that must satisfy inconsistent load with intermittent generation supported by storage components requires the creating of a digital twin of the grid.” Of course, cybersecurity must also be considered whenever digital technology is added to a system (see sidebar).

Telegrafi said the digital twin “models the components individually and the systemic constraints binding operation via mathematical formulas. These mathematical formulas allow for optimization of the dynamic from the current dynamic to the future clean energy equilibrium that industry establishes. The digital twin can be manipulated freely to add or remove components into the digital emulation of the grid’s dynamics, enabling ‘what if’ scenarios for application toward strategically planning investment and policy.” Telegrafi said Optit S.r.l., an optimization and solutions group, has been working on these projects in the U.S.

Powin’s Bennett also noted the importance of digital twins to “enable continuous monitoring, simulation, and optimization of power plant or grid equipment, providing a real-time view of asset health.” Bennett said having “virtual replicas of physical assets” is just one of “several components of an effective, automated maintenance program to ensure the reliability of power plants and grid.” He cited condition-based maintenance, or CBM, which enables “transitioning from predefined maintenance schedules to dynamic, condition-based programs that rely on real-time monitoring and performance data. SCADA [supervisory control and data acquisition] systems and IoT devices provide the necessary data for this approach.”

Bennett said predictive maintenance also is important. “Using AI and machine learning algorithms to analyze historical and real-time data from sensors, enabling the prediction of failures before they occur… [where] data sources can include environmental conditions, operating history, and current performance metrics,” he said. There is also automation, where “automating data correlation in the cloud allows predictive insights to be seamlessly integrated into control systems or maintenance scheduling tools. This reduces response time and ensures resources are allocated efficiently to address the highest-priority issues.” Inspections of power plant assets, and the power grid, using robotic systems and drones “can automate inspections of hard-to-reach areas, reducing the risk to personnel and minimizing downtime,” said Bennett.

FTI Consulting’s Morris said, “To enable proactive replacement/refurbishment of older equipment requires understanding several elements. First, there is a need to understand the condition of the asset and what the probability of failure of that asset is. Second, there is a need to understand the consequence of failure in terms of its impact. Third, the probability and consequence of failure need to be combined to understand the amount of risk. Once risk is known, it can then be assessed against the cost of replacement/refurbishment to determine the appropriate time for an intervention.” For example, a well-informed user can plan to replace equipment when the risk value exceeds the cost of replacement.

Morris continued, “In order to understand the condition of the asset, there is a need to invest in condition monitoring hardware, which varies based on the application. These are typically wired or wireless devices, which can be placed on equipment to collect different types of data. In addition to the hardware, there is a need for asset performance management software, which takes the data from the monitoring devices and performs analysis to identify the risk of failure. It does this by creating a digital twin of the asset and analyzing the data being provided by sensors and monitors to simulate the impact on the asset’s condition. This software typically can also determine the consequence of failure and calculate the risk value.”

Viridi’s Williams said the use of BESS can address several grid-related issues. “By charging batteries when energy is abundant and lower cost—in many parts of the U.S., this occurs during peak solar production—and discharging when energy is at a higher price or when the grid is operating at a higher carbon intensity, distributed, behind-the-meter storage has the capacity to provide significant benefits to the host site,” said Williams. “These benefits include active management of on-site generation and cost reduction through peak shaving, while also supporting the grid by releasing energy when needed—all for the benefit of the battery owner. However, fulfilling these roles requires that the BESS be absolutely safe, and they must have advanced communications and controls capacity so they can be monitored and managed from anywhere and leverage real-time opportunities to provide forecasted return on investment.”

5. Twelve lithium-ion batteries, installed in a dedicated room, provide 500 kWh of usable power for resiliency backup and demand charge management for the Hauptman Woodward Medical Research Institute, located on the Buffalo Niagara Medical Campus. Courtesy: Viridi

“A good example of the diverse benefits from distributed storage is the 600-kWh Viridi BESS installation [Figure 5] in occupied space at the Hauptman Woodward Medical Research Institute (HWI) in Buffalo, New York,” said Williams. “HWI had an undersized interconnection to support installation of a new cryogenic electron microscope. This need was satisfied by installation of the Viridi BESS, which charges in moments of lower power draw and discharges when the building is peaking to provide adequate power for this equipment whenever it is needed. However, when not used for this purpose, HWI uses the BESS in an automated fashion to peak shave, setting a kW ‘ceiling’ on operations that results in cost savings and reducing local grid strain. In this way, the BESS fulfills the promise of energy storage, which benefits both the host and the overall electric ecosystem.”

—Darrell Proctor is a senior editor for POWER.

The Evolving State of Power Plant O&M

February 23, 2025

Jeff Prescott

asset management Business Digital Transformation electrification energy infrastructure Energy Security Full Coverage grid modernization News O&M operations and maintenance Power power grid reliability power plant efficiency predictive maintenance renewable energy O&M Safety Supply Chains Technology Trends Workforce No Comments

As power plants confront aging infrastructure, surging demand, and the sweeping changes of rapid electrification, operations and maintenance (O&M) are being redefined to tackle unprecedented challenges and seize new opportunities.

In December 2025, the North American Electric Reliability Corporation (NERC), the region’s designated electric reliability organization, issued a sobering assessment of the power sector’s outlook for the next decade. More than half of North America may be at risk of electricity shortages, it warned. The scenario is exacerbated by the accelerated retirements of 78 GW of aging, fossil-fueled capacity—with an additional 37 GW announced but not yet confirmed—and sluggish progress on new resource additions. Compounding the challenge, power demand is projected to soar by 15% over the next decade, driven by rapid electrification, industrial growth, and the increasing energy needs of the data-driven economy.

In this context, the region’s existing fleet will play an outsized role, underscoring a role for their sound operations and maintenance (O&M). However, NERC also flagged forced outages as a critical and growing concern for the power sector, noting that unplanned outages caused by equipment failures, insufficient maintenance, and resource shortfalls pose significant reliability risks, most prominently during extreme weather events. Without robust O&M practices, these issues could further undermine the grid’s ability to meet rising demand, particularly as winter peaks begin to outpace summer peaks. That has exposed new vulnerabilities in resource adequacy planning, it said.

But as experts told POWER, the realm of O&M is itself rapidly evolving to address new complexities and expectations introduced by the rapid transformation. As IHI Power Solutions Director of Business Development Doug Machon notes, O&M emerged historically as a straightforward business function managed internally by utilities operating within regulated monopolies. The realm began a shift in the 1990s, as competition, introduced by electricity deregulation, ushered in third-party O&M services that offered basic maintenance, compliance support, and operational oversight. Today’s landscape adds a growing involvement from private equity investors, a decline in long-term power purchase agreements, and the rise of diversified energy portfolios—including renewables, distributed energy resources (DERs), and hybrid configurations.

No longer limited to routine tasks, modern O&M necessitates “a higher level of expertise and innovation in plant operations,” says Machon. The significant shift has catalyzed “the development of comprehensive O&M strategies designed to maximize efficiency, reliability, and profitability in an ever-changing energy landscape.” Providers today are expected to integrate advanced technologies, foster flexible plant cultures, and navigate stringent regulatory landscapes, he notes. Essentially, O&M today functions both as a critical lever for optimizing performance and enabling grid reliability in an increasingly dynamic energy environment, but it must also simultaneously mitigate risks and seize opportunities, he says.

Tackling New O&M Challenges

According to Ricardo Guerrero, general manager for Global O&M at GE Vernova, O&M advancement varies by region. “It’s different in every part of the world, but I would say the main factor that is affecting O&M services at this moment is the penetration of renewables,” he says. Plunging costs for renewables have ushered in new operational demands for traditional thermal power plants, including combined cycle gas turbine (CCGT) power plants, which were historically designed as baseload workhorses. “Cycling is a big issue,” Guerrero acknowledges. “Cycling is associated with how you are going to react, how you are going to accommodate your team, how you are going to accommodate your strategy, your planning—everything associated to O&M services—to be really productive, take care of cost, and be efficient.”

Cost pressures amid inflation and market demand further compound these challenges. Power sector O&M costs typically fall into fixed costs and variable costs. Fixed costs cover consistent expenses like routine maintenance, staff salaries, and long-term equipment contracts, while variable costs fluctuate based on fuel prices, material needs, and unexpected repairs. Over the past five years, cost fluctuations have hinged emphatically on rising material costs for critical resources such as steel, copper, and silicon, with particular implications for aging thermal power plants that require frequent and costly repairs.

Table 1. A December 2023 U.S. Energy Information Administration (EIA) cost and performance survey conducted by Sargent & Lundy summarizes costs for most technologies, including overnight capital cost information, fixed operating and maintenance (O&M) costs, and variable non-fuel O&M costs. Notes: USC = ultrasupercritical; CTs = combustion turbines; CC = combined cycle; SS = single shaft; BFB = bubbling fluidized bed; MWAC = megawatt alternating current; WTG = wind turbine generator; BESS = battery energy storage system. Source: EIA, Capital Cost and Performance Characteristic Estimates for Utility Scale Electric Power Generating Technologies, January 2024.

Renewable O&M costs, while generally lower than those of thermal power plants, have been steadily decreasing due to technological advances, economies of scale, and experience-driven efficiencies. However, they remain sensitive to material price volatility and the growing demand for specialized maintenance services. Offshore wind, in particular, faces higher O&M costs compared to onshore wind, driven by logistical challenges, harsher environmental conditions, and the need for specialized vessels and remote monitoring systems. Meanwhile, costs for advanced technologies such as biomass and small modular reactors remain comparatively high. A cost and performance analysis conducted by engineering firm Sargent & Lundy compared 19 different technologies based on their capital and O&M costs (Table 1). Even as these emerging technologies promise operational efficiencies and decarbonization benefits over time, their high upfront investments and significant ongoing O&M expenses can pose serious feasibility challenges.

Enduring the Vast Realm of Policy and Regulatory Uncertainties

Still, the current power landscape is compelling more companies to adopt new technologies and approaches. A significant factor has been compliance with the evolving patchwork of government mandates, including regulations and incentives increasingly focused on accelerated decarbonization. The U.S. Environmental Protection Agency’s (EPA’s) April 2025–finalized Carbon Pollution Standards mandate carbon capture and sequestration (CCS) for existing coal units and new baseload combustion turbines, adding to rules regulating nitrogen oxides, mercury, effluent, and coal ash. Regional decarbonization differences and overlapping state-level policies are, meanwhile, creating additional complexity, driving operators to adopt tailored strategies to meet diverse compliance requirements.

Beyond emissions, regulations now also emphasize grid stability and reliability, compelling conventional generators to provide ancillary services such as fast frequency response and inertia. The need for resilience has also generally spurred mandates that require plants to bolster infrastructure to withstand extreme heat and cold events, floods, and droughts. Cybersecurity is another growing focus, with federal directives requiring power plants to implement stricter digital protections and incident reporting protocols.

“You must adapt to the market. If you don’t react, if you don’t change, if you don’t adjust yourself to the new conditions, you’re going to disappear,” notes GE Vernova’s Guerrero. GE Vernova’s approach has been to prepare customers for these transitions, including tailored maintenance strategies. “We take into account the specific operational stresses caused by renewables integration, ensuring that even older assets comply with regulatory thresholds while optimizing performance,” he explains.

Siemens Energy, a global provider of power technology, solutions, and services, shares a similar outlook. “Our O&M service is designed to manage and maintain various types of technology infrastructure or equipment. This approach is especially beneficial in diverse and complex operational settings such as carbon capture, where multiple types of technology coexist,” says Andrew Robson, Siemens Energy’s technical expert for O&M Solutions.

Best Practices for Maintenance in the Evolving Power World

While power plant maintenance is a cornerstone of reliable power generation, designing and maintaining an effective program will require careful consideration of modern challenges and strategies. Engineers at infrastructure solutions firm Gannett Fleming offer some pointers.

Understand Your Assets. Develop a detailed asset register to categorize and document critical assets, including electrical, mechanical, and civil infrastructure. Involve multidisciplinary experts to ensure a comprehensive understanding of maintenance needs.

Develop a Maintenance Strategy. Balance reactive, preventive, and predictive maintenance to address immediate needs while minimizing future risks. Document the rationale for each maintenance task based on regulatory requirements, manufacturer guidance, and risk analysis.

Leverage Technology. Invest in a computerized maintenance management system (CMMS) like Maximo or SAP CMMS to streamline scheduling, documentation, and data analysis, ensuring efficient resource allocation.

Stay Agile. Avoid static programs. Continuously assess and adapt maintenance strategies to reflect advancements in technology, changes in asset conditions, and best practices.

Prioritize Tasks. Prevent over-commitment by ranking maintenance activities based on risk to ensure critical tasks are executed effectively.

Address Challenges Holistically. Be wary of knee-jerk reactions to failures and aim for balanced solutions through root cause analysis and measured troubleshooting.

Foster Collaboration. Streamline decision-making by clearly defining roles while incorporating input from stakeholders to maintain agility in program updates.

“In the next decade, Siemens Energy will continue to offer expert O&M services to manage customer reliability risks, enhance efficiency, and centralize skills for consistent and reliable service supported by data-driven digital technologies,” Robson adds. While the need to decarbonize conventional power generation affects all utilities and is not specific to O&M, the company’s services “ensure that these technologies operate reliably and efficiently, contributing directly to meeting decarbonization goals,” he explains. Additionally, he underscores broader sustainability benefits, particularly through the use of a global network of remote operations and control centers. “Especially during COVID, it became clear that it is not always necessary to fly specialists around the world, but that a lot can be done remotely,” he says (see sidebar “Best Practices for Maintenance in the Evolving Power World”).

Solving the Workforce Puzzle

For now, experts agree the most urgent challenge facing the power sector is the shortage of skilled personnel. “O&M is all about people,” says Guerrero. “People tend to believe that in the future, power plants will be operated completely by robots, but we are really far away from that.” A key issue is that the workforce, traditionally the backbone of power plant operations, is aging, and with that comes the loss of decades of invaluable experience. “At the same time, we’re finding it increasingly difficult to attract younger talent, who are often drawn to tech-savvy industries like software and artificial intelligence [AI] rather than traditional fields like ours. It’s a problem we cannot afford to ignore because, without skilled workers, even the most advanced plants won’t function,” he says. To address these challenges, Guerrero explains that GE Vernova has developed structured knowledge-capture systems, including detailed playbooks created during contract mobilizations. “These are comprehensive guides that ensure when experienced team members retire or move on, their expertise doesn’t leave with them,” he says.

At the same time, GE Vernova, driven by its “lean” business philosophy, has already begun transitioning from traditional reliability-based maintenance approaches to more proactive, data-driven design-making enabled by AI and analytics. Guerrero said the company has developed autonomous robot technology capable of conducting inspections and identifying issues that human workers may miss. Demonstrating these technologies carries operational benefits, but a key intent is to transform the perception of O&M, positioning it as innovative, future-focused, and dynamic—attributes that could be attractive to a younger workforce, he says.

1. Completed in early 2025, the Leipheim Power Plant in Bavaria, Germany, is a cutting-edge gas turbine facility developed by Siemens Energy and German energy giant LEAG to bolster grid stability during renewable energy shortfalls. The plant, capable of ramping up remotely within 30 minutes to deliver 300 MW of power, is operated entirely from Siemens Energy’s ISO-certified Remote O&M Support Center in Erlangen. Courtesy: Stefan Hobmaier/Siemens Energy

Robson echoes Guerrero’s concerns. “Even utilities with extensive experience in power plant operation and maintenance are now seeking our O&M expertise due to the skilled workforce shortage,” he notes. Siemens Energy’s approach has been to double down on technology. “Remote services are key to maintaining reliable operation and efficient maintenance,” says Robson, citing Siemens Energy’s 72-hour unmanned operation of the 300-MW Leipheim Power Plant in Germany (Figure 1). “Our remote monitoring centers handle routine monitoring and data analysis, freeing up experts for tasks that cannot yet be fully automated.”

According to Emily Obenauer, global director of Product Marketing at SiteTracker—a software-as-a-service platform that provides end-to-end asset lifecycle management—emerging tools are also set to play a transformative role in streamlining O&M operations with tangible workforce benefits. “Tools like ours are also shown to increase the satisfaction and increase the effectiveness of those workers out in the field because we’re getting so clear on what needs to be done and validating that that work has been done correctly the first time around,” she said.

Shoring Up Supply Chains

While workforce challenges have long afflicted the sector, more recent global supply disruptions are posing new concerns, prompting companies to reassess the resilience of their O&M operations. Siemens Energy’s Robson notes that, while temporary bottlenecks for parts and consumables remain a concern, “The shortage of people is, so to speak, the biggest bottleneck in the supply chain,” he says. He explains that most original equipment manufacturers (OEMs) proactively approach supply chain challenges to mitigate risks, leveraging global networks for flexibility. “We can access stock that was originally planned for other projects in the longer term. Additionally, close monitoring allows for the identification of required parts at an early stage as part of predictive maintenance,” he says.

2. To bolster its supply chain and prepare for increasing demand for its heavy-duty gas turbines and upgrades globally, GE Vernova moved in November 2025 to acquire Woodward Inc.’s combustion parts business in Greenville, South Carolina. This image shows a 7HA.03 gas turbine at GE Vernova’s own facility in Greenville, where it manufactures and tests gas turbines to provide global engineering support and other activities. Courtesy: GE Vernova

GE Vernova’s strategy is similar, entailing a proactive, collaborative approach with its customers (Figure 2). The company closely monitors its customers’ equipment and provides advance warning of potential failures. In addition, Guerrero says it helps customers pre-position critical spare parts to minimize downtime in the event of an issue. For example, when GE Vernova identified that the generators at a 20-year-old power plant in Taiwan were nearing the end of their life, it advised the customer to purchase a spare stator and rotor in advance. Two years later, the rotor failed, but because the spare part was already on-site, GE Vernova was able to quickly replace the rotor, getting the customer back online in just seven days, he says.

The Rise of Third-Party O&M Services

In another important trend, given modern complexities and evolving risks in the power sector, many utilities and power companies are increasingly turning to value-driven partnerships, often through third-party O&M service contracts. These partnerships encompass project management, robust training programs, detailed plant assessments, and the adoption of tailored best practices to optimize operations. Many are designed to leverage economies of scale and advanced remote operations, providing utilities with cost efficiencies and enhanced reliability in managing diverse energy assets.

“For many plant owners, O&M is no longer a core focus,” Guerrero explains. “Their priority is on generating and selling energy, which opens the door for third-party providers like us to step in with specialized expertise. But it’s not just about taking over operations—it’s about adding value. By leveraging performance-based contracts and advanced technologies, we focus on aligning our services with plant owners’ goals for reliability, efficiency, and profitability.” Guerrero notes that performance-based contracts are increasingly becoming a defining feature of third-party O&M services because they play a pivotal role in aligning incentives with plant reliability, availability, and efficiency. The contracts ensure accountability by incorporating measurable metrics, such as performance guarantees, and often include penalties for underperformance as well as rewards for exceeding targets. “This model ensures that everyone is focused on the same goal: maximizing the plant’s performance,” he says.

Global renewable energy developer Invenergy— a company known for its extensive portfolio of wind, solar, and storage projects—also highlighted the value proposition. The company says it approaches O&M services with an “owner’s mindset,” a philosophy that ensures top-tier maintenance practices and builds trust within their communities. “In addition to prioritizing safety, Invenergy Services’ other O&M pillars deliver benefits to customers through innovation, flexibility, and cost savings,” it says.

O&M’s Future: Tech and Sustainability

According to experts, the future of O&M in the power sector will be shaped by two transformative forces: technological innovation and the global push for sustainability. Already, as power generation grows more complex, modern O&M practices are increasingly integrating cutting-edge technologies like predictive analytics, autonomous systems, and maintenance strategies. “The future of operations and maintenance will heavily depend on integrating AI with digital tools to analyze data in real-time. This allows us to predict issues before they occur, saving costs and improving asset performance across the board,” says Guerrero.

Obenauer echoes this point. “We know that the future lies in digital transformation, and AI is a major focus. By applying AI to fieldwork and O&M processes, we’re already testing how to enhance efficiency and reliability while aligning with the workforce and industry needs.” AI-driven solutions also promise to unlock new opportunities in lifecycle management, she notes. “By centralizing asset data, companies can use AI to optimize resource allocation and focus on long-term asset health while navigating complex operational challenges.”

3. Operational since June 2023, the Kela PV Plant Phase 1, located in Sichuan Province, China, stands as one of the world’s largest hydro-solar hybrid power plants, combining 1 GW of solar capacity with the 3 GW Lianghekou Hydropower Plant. The site exemplifies advanced O&M practices in a challenging environment. Given that it is situated at an altitude of 4,600 meters, the plant endures extreme cold and high winds. Using a smart O&M platform with features like remote monitoring, automated fault detection, and real-time diagnostics, the plant minimizes manual intervention and ensures reliability. Courtesy: Huawei

On the other hand, sustainability will support the general charge toward cleaner energy sources, such as accommodating new technologies and hybrid configurations (Figure 3). Companies are exploring how to integrate emerging solutions such as hydrogen retrofits, thermal energy storage, and batteries into power plants, all while keeping costs low, maintaining reliability, and minimizing environmental impact.

As Guerrero stresses, a key takeaway is that O&M will need to be flexible and responsive rather than rigid. “You can navigate the sea as a cruise ship, or you can be a motorbike on the beach moving quick, and that’s the idea, that’s what we are doing,” he explains. Ultimately, proactivity will be necessary for nimble adaptation to keep pace with the changing landscape, he says.

—Sonal Patel is a POWER senior editor (@sonalcpatel, @POWERmagazine).

Correction (Feb. 18, 2025): This article previously misstated that the Sargent & Lundy analysis examined hydrogen retrofits. A clarification in this version refines the discussion of cost comparisons for advanced technologies. The Table 1 citation has also been updated to January 2024 instead of 2025, as previously cited.

NRC Proposes Deep Fee Cuts for Advanced Nuclear

February 23, 2025

Jeff Prescott

advanced nuclear reactors Business energy infrastructure federal energy policy Legal & Regulatory News NRC fees Nuclear nuclear industry policy nuclear innovation nuclear regulation power sector trends regulatory costs Safety SMR licensing Technology No Comments

The Nuclear Regulatory Commission (NRC) has proposed to sharply reduce its hourly service fees—by more than 50%—for advanced nuclear reactor applicants and pre-applicants in a move designed to incentivize innovation and accelerate the deployment of next-generation nuclear technologies.

In a proposed rule published in the Federal Register on Feb. 19, the regulatory body moved to revise its fees for licensing services, inspection services, and special projects (under 10 CFR part 170) by establishing a two-tiered hourly rate system.

Starting in August 2025, the agency plans to raise the professional hourly rate from $317 to $323. This increase, the NRC said, is driven by “an approximately $5.4 million increase in resources requested in the FY 2025 budget request.” The agency earmarked these funds to support several key initiatives, including:

Technical reviews of 10 CFR Part 50 construction permit applications, including to facilitate reviews necessary for construction permit applications for non-power reactors.
The relocation, design, and construction of the Headquarters Operations Center (HOC) to enable the NRC to exit one of its headquarters buildings before its lease expires in November 2027.
Development and implementation of IT and cybersecurity upgrades, including an artificial intelligence (AI) infrastructure to facilitate responsible AI adoption. (The measure is in line with Executive Order 14110, which the Trump administration revoked on Jan. 20).
Increased salaries and benefits to support federal pay raises for NRC employees, an effort that seeks to ensure the agency can retain and attract qualified personnel.

A Drastically Reduced Rate of $146/Hour

However, in a bid to implement Section 201 of the ADVANCE Act, which revised the 2019 Nuclear Energy Innovation and Modernization Act’s (NEIMA’s) fee structure, the NRC proposed a drastically Reduced Hourly Rate of $146 for advanced nuclear reactor applicants and pre-applicants. The lower rate is slated to take effect on Oct. 1, 2025 (when the ADVANCE Act provisions become effective)—which would fall into the NRC’s FY2026 budget. The ADVANCE Act, notably, sunsets the Reduced Hourly Rate for advanced nuclear reactor pre-applicants on Sept. 30, 2030.

Signed into law on July 9, 2024, the legislation mandates that costs associated with international nuclear export and innovation activities (Section 101) be excluded from the fees collected by the NRC. It also exempts costs related to reviews and pre-application work for early site permits required to demonstrate advanced nuclear reactors at the Department of Energy (DOE) or critical national security infrastructure sites (Section 204) from NRC’s fee calculations. The NRC’s proposed rule indicates these provisions may take effect as part of its FY2026 rule.

The NRC’s decision to front-load the Section 201 change in the FY25 rule, rather than waiting for the FY26 rule, is a strategic move that will avoid billing delays and provide early notice and initiate an opportunity to comment, it said. Pivotally, “It also would provide greater regulatory certainty to external stakeholders for planning and budgeting for future 10 CFR part 170 service fees for advanced nuclear reactor applicants and pre-applicants,” it said.

The proposal also specifically defines which entities could qualify for reduced fees. It defines an “advanced nuclear reactor applicant” as an entity that has formally applied for a license to build and operate an advanced nuclear reactor. That application must be for an initial operating, combined, or manufacturing license—not for an amendment to or renewal of an existing license. An “advanced nuclear reactor pre-applicant” is an entity that has submitted a detailed licensing project plan outlining its intention to apply for a future license for an advanced nuclear reactor. Again, that future license must be for an initial operating, combined, or manufacturing license. The NRC has proposed to limit these applications to advanced nuclear reactors as defined in NEIMA.

According to the proposal, the reduced hourly rate will also only apply to certain activities related to the review of applications submitted by advanced nuclear reactor applicants and pre-applicants. Specifically, fees assessed for reviewing an advanced nuclear reactor applicant’s formal licensing application could qualify, as may fees related to reviewing submitted materials that are explicitly outlined in a licensing project plan from a pre-applicant. Other NRC activities, such as license amendments or renewals, will continue to be billed at the full professional hourly rate of $323.

In recent years, the agency has also revised how it calculates fees for small modular reactors (SMRs) as part of broader efforts to tailor costs to emerging nuclear technologies. In 2016, the NRC modified its rules (10 CFR 171.15) to establish a specialized method for calculating annual fees for small modular reactors (SMRs) that use light-water reactor (LWR) technology. In 2023, the NRC expanded those provisions to include all SMRs (not just LWRs) and introduced a reduced minimum fee and adjusted fee structure for very small SMRs (250 MWth or less). The agency’s proposed rule says fee calculations for bundled SMR units and larger SMRs (over 250 MWt) will remain unchanged, and because no SMRs are currently in operation, the NRC will not impose specialized SMR fees in 2025.

Regulatory Relief for Advanced Reactors

The NRC’s proposal is poised to be well-received by the advanced nuclear industry, which has consistently called for measures to reduce regulatory costs and streamline licensing pathways. In a 2021 report, the Nuclear Innovation Alliance (NIA) suggested hourly fees have rapidly risen from an average of $214/hour between 1995 and 2004 to $280/hour over the last several years. The report argues that the NRC’s current fee structure has posed a significant barrier to the development and deployment of advanced nuclear reactors, disproportionately burdening new entrants and hindering innovation.

“The open-ended costs associated with paying fees impose barriers to new entrants,” the report explains. “License applicants must pay NRC fees before they begin earning revenues. This is particularly burdensome for developers with limited capital and new customer types like small towns, rural communities, and industrial users. NRC is in the process of modernizing its existing regulatory framework, which was designed for light water reactors. At least until this modernization is complete, advanced reactor licensing requires significant extra regulatory work,” it says.

The NRC on Thursday said its FY25 budget request is $994.9 million. It proposes to use $20 million in carryover funds, making the total budget authority used in the FY25 proposed fee rule $974.9 million—an increase of $30.8 million from FY24. Under NEIMA, the NRC is required to recover approximately 100% of its total budget authority in FY25, except funds for specific excluded activities. After accounting for the excluded activities and net billing adjustments, the NRC estimates that it must recover approximately $826.1 million in fees in FY25. Of that amount, the NRC estimates that $216 million will be recovered through service fees under 10 CFR Part 170, and $610.1 million will be recovered through annual fees under 10 CFR Part 171.

Compared to FY24, the agency’s proposed annual fees would increase for licensed operating power reactors, spent fuel storage/reactor decommissioning activities, non-power production or utilization facilities, transportation activities for the DOE, the Uranium Mill Tailings Radiation Control Act Program, and 48 materials users fee categories. The proposed annual fee for each operating power reactor in FY2025 is $5,359,000, up from $5,336,000 in FY 2024. In addition, each reactor will be assessed a spent fuel storage/reactor decommissioning fee of $341,000, up from $326,000 in FY2024. That represents a total annual fee per reactor to $5,700,000—an increase from $5,662,000 in FY 2024. The proposed annual fees would remain stable for fuel facilities, it said.

The NRC is actively seeking feedback on all aspects of the proposed rule. The deadline for submitting comments is March 21, 2025. The agency is expected to hold a public meeting to describe the FY2025 proposed rule and answer questions from the public. The NRC will review all comments received and consider them in developing the final fee rule, which is expected to be published later this year.