The project is the largest solar and storage facility within PacifiCorp’s six-state service territory. It involved capital investment of more than one billion dollars, rPlus Energies previously noted.

In 2024, Utah Governor Spencer Cox announced Operation Gigawatt, an initiative aimed at doubling Utah’s energy production over the next 10 years.

In 2024, rPlus Energies said it amended a PPA with PacifiCorp to quadruple the battery storage capacity at the Green River Energy Center project that was under development at the time. The project was originally designed as a 400 MW solar PV facility integrated with a battery storage system. This expansion increased the project’s storage capacity from 400 MWh to 1,600 MWh, making it one of the largest solar-plus-storage projects under development in the U.S.

Last summer, rPlus Energies closed on a tax equity financing commitment exceeding $500 million with RBC Community Investments and a syndicate of investors to support Green River Energy Center, utilizing the federal Investment Tax Credit (ITC). Later that summer, the company announced it had closed over $1 billion in construction debt financing for the project.

“Operation Gigawatt is about ensuring Utah has the reliable, homegrown energy needed to power opportunity for generations,” said Utah Governor Spencer Cox. “Green River Energy Center represents the kind of large-scale energy investment we need to deliver reliable energy, support rural Utah, and help power the next generation of prosperity across our state.” 

Green River Energy Center will generate more than $55 million in property taxes for schools and public services. During construction, the project employed hundreds of workers, including several local contractors for key components. Project partners committed $375,000 in scholarships for local students who plan to build their careers at home while strengthening the region’s long-term workforce in local and energy-related industries.

The successful commissioning of the project was celebrated during an on-site ceremony held on Monday, June 22, attended by Governor Cox, project partners, and community members. 

“This project represents years of collaboration and commitment from all of the project partners,” said Luigi Resta, rPlus Energies President & CEO. “Together, we believed in the vision, and today Green River Energy Center is delivering reliable power and real value to families across the American West.” 

The project has received both national and local recognition, including Project Finance International’s “Renewables Deal of the Year – Americas” and the Emery County Business Chamber’s 2024 “Energy Company of the Year” award.

By Michael J. Reidy, Interaction Associates  

Nuclear power is experiencing a historic resurgence.

Driven by a clean energy transition, technological advancements, and the massive power demands of AI-enabled data centers, U.S. electricity demand is projected to increase by 25% by 2030 and 78% by 2050. The market has responded by rapidly adding new nuclear capacity as an essential strategy for long-term baseload generation.

Governments are reversing phaseout policies, and new technologies, like Small Modular Reactors (SMRs), promise faster, more flexible construction. However, this explosion of activity risks prioritizing the result – getting plants online quickly – over the operational infrastructure necessary to safely build and sustain them.

To meet this demand safely, nuclear power industry leaders should heed the wisdom of Festina Lente. They must “make haste slowly,” relying on a three-legged stool approach to success that values process, relationship, and results equally.

This is the product of facilitative leadership, a model that creates the conditions for every worker, regardless of rank, to speak up, challenge assumptions, and co-own safety outcomes.

Defining Facilitative Leadership as a Critical Safety Mechanism

Too often, a culture of fear in the nuclear power sector prevents workers from reporting safety concerns before they become critical incidents.

For example, Nuclear Regulatory Commission (NRC) inspections at a Florida nuclear power plant previously revealed a culture of fear where employees worried about facing retaliation or dismissal if they reported concerns.

To address these concerns, leaders will seek the maximum appropriate involvement of all stakeholders, including those closest to the decision-making process. Powered by conscious inclusion, this approach promotes a shared responsibility for safe daily operations.

No single person or isolated executive group can ensure the safe operation of complex new builds or legacy nuclear facilities.

This shared responsibility must span every operational facet, from executing routine outages to integrating new technologies, grounded in the kind of trust and interpersonal accountability that safety-critical operations demand.

Leading Indicators of Safety Culture

Understandably, power production results are highly measured. Megawatts generated and uptime metrics serve as significant factors in meeting market needs and satisfying customer demands.

However, in the facilitative leadership model, results represent only one leg of the three-legged stool. The other two legs are the process (how we get to the result) and the relationship (who gets to co-create the result).

Results are inherently a lagging indicator because they materialize at the end of a cycle. Meanwhile, operational failures almost always appear first as process issues.

Process is one leading indicator. The other is less measurable but equally critical: relationships.

Relationships are just as important, serving as a leading indicator of connectedness among team members and operationalizing these processes.

In a nuclear facility, relationships are inextricably linked to trust, an absolute requirement for critical operational functions such as shift handovers. Trust requires painstaking cultivation. It is a slow, deliberate build that can be lost in a single instance of poor leadership.

Over the next five years, the nuclear industry must focus on building trust and process capabilities to drive the lagging indicator of reliable power generation successfully.

Moving From Divergent Brainstorming to Convergent Execution

Healthy operational planning begins by inviting differences of perspective. This is known as divergent thinking and must be followed by a narrowing phase, in which individuals align on a collective execution strategy.

Leaders can facilitate this shift by applying specific narrowing skills, such as actively eliminating duplication. A highly practical tool is the “N over 3” method, which takes the total number of proposed operational solutions (N) and divides it by 3, narrowing the group’s focus to the most viable top-tier options.

Throughout this process, teams must maintain true dialogue.

Keeping the window of dialogue open directly prioritizes a culture of safety with urgent growth demands. This conscious, competent approach to expanding meaning is exactly what drives bold industry advancements across the country.

Shared Accountability is the Foundation of Risk Mitigation

Surging electricity demand has renewed enthusiasm for nuclear energy. The potential upside for companies, consumers, and communities is tremendous, but so are the risks.

This stage of nuclear investment presents a profound test of executive discipline.

If the industry allows the pressure for rapid deployment to overshadow human-centric safety protocols, the public and political mandate for nuclear energy will vanish with a single misstep.

A facilitative leadership model will help leaders make safety and risk mitigation a shared priority, getting us close to zero-emission baseload power, starting with zero-silence control rooms.

About the Author: Michael J. Reidy, a senior consultant at Interaction Associates, has more than 25 years of experience in consulting and responding to the learning needs of adults in the financial services, biotech, power, and service industries.  Michael’s interest is in adult education, and his belief is that the workplace has become the ‘third place’ of learning and development for the 21st century. Michael holds a master’s degree in Public Administration from the HKS, Harvard University. Interaction Associates is best known for introducing the concept and practice of group facilitation to the business world in the early 1970’s. For over 50 years, IA has provided thousands of leaders and teams with practical, simple, and effective programs, tools, and techniques for leading, meeting, and working better across functions, viewpoints, and geographies. Learn more by visiting https://www.interactionassociates.com/ and connect with Michael on LinkedIn.

The Public Utility Commission of Texas (PUCT) recently approved ERCOT’s Batch Zero process for large-user connection requests, which ERCOT says is meant to ensure large electricity users like data centers “only connect in quantities and locations the Texas grid can reliably support.”

ERCOT is the first Independent System Operator (ISO) in the nation to use a batch process to assess large electricity users wanting to connect to the grid. The new batch framework groups qualified large projects that are 75 megawatts (MW) and greater into a single study. ERCOT says this process will allow it to assess the “full picture” of future electricity demand at once, allocate available grid capacity, and identify needed transmission upgrades. The batch framework eliminates a previous project-by-project evaluation that ERCOT argues had become “lengthy and repetitive” as large electricity users rushed to connect to the grid.

“Texas is experiencing an energy transformation unlike anything we have seen before,” said ERCOT President and CEO Pablo Vegas. “This new process represents a fundamental shift in how ERCOT manages the significant growth of large load interconnection, providing a structured, transparent path forward that protects reliability for Texans while supporting the state’s continued economic growth.”

ERCOT is tracking more than 438,000 MW of large load requests, nearly 89% from data centers alone. “Batch Zero” is the name of the first group of large-user applicants to go through the new process.

“The response from the Texas energy community was remarkable. The depth of participation and quality of feedback were extraordinary, and both directly shaped how ERCOT manages large load connections in Texas,” said Jeff Billo, Vice President, Interconnection and Grid Analysis.

The framework was approved by the Protocol Revision Subcommittee (PRS), Reliability and Operations Subcommittee (ROS), the Technical Advisory Committee (TAC), and the ERCOT Board of Directors before PUCT consideration.

The principles established through the Batch Zero framework will serve as the foundation for an ongoing transmission planning process developed in partnership with stakeholders later this year.

“Change has to come faster while also ensuring reliability,” said an ERCOT representative at the Infocast Transmission & Interconnection Summit this week. “Batch zero is kind of a moonshot for ERCOT, and we are now in the ‘radio blackout period.’ We overhauled the large load interconnection process in about 4.5 months […] We’ve written these rules, but we don’t know how they’re going to play out in reality.”

However, some analysts are concerned that speed-to-power may actually become slower in ERCOT once Batch Zero takes effect, as any serial queue process, even in batches, can get behind and cause delays.

‘Reliability-Focused’ Connection Pathways

The Batch Zero framework gives large electricity users additional pathways to connect to the ERCOT grid.

The framework includes provisions for large customers that want to build their own onsite generation to self-supply some or all of their electricity, reducing the need to draw from the larger grid. Facilities that are truly islanded with no grid connection would generally fall outside ERCOT’s interconnection process, though they may still be subject to registration requirements with the PUCT.

Additionally, the framework creates a pathway to connect for large customers who agree to let ERCOT curtail their power use in response to local transmission constraints, reducing demand where and when the grid needs it most.

Following the approval, ERCOT expects to notify Batch Zero applicants of their project classification in August 2026, at which point the full scope of Batch Zero will be known. A final transmission plan covering the entire batch of projects across the state is expected to be published in Fall 2027. While not all interconnection requests result in built projects, ERCOT data shows the majority expect to be operational by 2030.

Applications for Batch 1 are expected to open in Summer 2027.

PJM QUEUE MOVING AGAIN

ERCOT isn’t the only grid operator hoping to improve the interconnection process in light of the huge increase in large load requests. The PJM Interconnection generation queue is finally moving again after years of uncertainty and delays, and PJM hopes a new “fast track” proposal will help address the reliability challenges posed by the recent swarm of large load additions (data centers) to its system.

Earlier this month, the Federal Energy Regulatory Commission (FERC) approved PJM’s request to create its Expedited Interconnection Track (EIT), a temporary fast-track interconnection process designed to bring large “shovel-ready” generation projects online more quickly. 

The EIT process will be a separate, expedited interconnection pathway, conducted outside the normal PJM interconnection process. PJM’s intention was to create an independent queue to fast-track a limited number of large projects that could otherwise get caught up in the normal slog.

PJM previously estimated that it needs approximately 15,000 megawatts (MW) of new capacity to address its identified capacity deficiency. The EIT will allow up to 10 projects greater than 250 MW unforced capacity (UCAP) to proceed per year. The projects can be of any fuel type, including storage, but they must be sponsored by a PJM state and interconnected within the sponsoring state. PJM also requires EIT projects to be “capacity resources,” meaning they must request capacity interconnection rights at the same time as their EIT application. Finally, PJM stipulated that EIT projects must achieve commercial operation within three years of submitting an application.

FERC’s historic action

FERC is getting serious about large load interconnection tariffs.

Earlier this month, FERC issued tailored show-cause orders under section 206 of the Federal Power Act to each of the six regional grid operators within its jurisdiction, directing them to either justify or reform the rules governing how large energy users like data centers connect to the electric grid. The regional transmission operators (RTOs) and independent system operators (ISOs) are PJM Interconnection (PJM), Midcontinent Independent System Operator (MISO), Southwest Power Pool (SPP), California Independent System Operator Corporation (CAISO), ISO New England (ISO-NE), and New York Independent System Operator(NYISO).

FERC’s action on Docket RM26-4-000 is one of the most significant the Commission has ever taken to modernize the nation’s electric markets, aiming to “push the economy into the future by speeding integration of large energy users onto the grid.” By requiring RTOs, ISOs, and their transmission operators to either defend or revise their tariffs, FERC says it is acting to ensure that Americans have reliable, affordable power, even as electricity demand accelerates.

Under the orders, each RTO/ISO and its transmission owners have 60 days to either justify why their current tariffs remain just and reasonable without provisions tailored to large loads, or to file tariff changes that address the issues the Commission identified. Each tailored order tees up five categories of reform for the grid operators to address:

• Developing efficient transmission service application and study processes, including consideration of alternative transmission technologies
  
• Preventing cost shifting and requiring transparency into transmission costs
  
• Accommodating co-location agreements and behind-the-meter generation
  
• Providing new transmission services for flexible large loads
  
• Developing a process to study generating facilities that serve electrically proximate large loads and co-located loads

Conventional generation availability deteriorated in 2025, adding another reliability pressure point as the North American grid absorbs rapid demand growth, large computational loads and a changing resource mix, according to the North American Electric Reliability Corp.’s 2026 State of Reliability report.

The report, released June 24, found that the annual weighted equivalent forced outage rate, or WEFOR, for conventional generation rose to 9.2% in 2025. That is above the historical norm of 7% to 8% and up from 7.6% in 2024.

NERC said the increase was not tied to a single event but was distributed across most months of the year, indicating a broader decline in baseline performance across parts of the conventional fleet.

Coal and combined-cycle units were the largest drivers. Coal units saw WEFOR rise from 11.2% in 2024 to 14.1% in 2025, adding 39.8 TWh of unavailable energy year over year. Combined-cycle units rose from 4.2% to 5.7%, adding 19.1 TWh of unavailability.

NERC said forced outage performance is a foundational reliability indicator because it shows whether generating resources are available not just on average days, but during high-demand periods, stressed system conditions and extreme weather. As forced outage rates increase, planning reserve margins may need to increase to account for the added uncertainty, the report said.

The organization also said most large coal units are more than 40 years old and were not designed for regular cycling, which has become an operational requirement in some regions and an economic necessity in others. That has implications for outage planning, inspection intervals, spare parts strategies and life-extension decisions across utility and IPP fleets.

In a voluntary survey of 41 generators that experienced at least 1 TWh of additional unavailability, NERC and the regional entities received responses covering 26 units. Sixteen reported equipment destruction extensive enough to significantly prolong outages, while eight cited manufacturer-level supply chain constraints as a reason outages lasted longer than expected. Six units reported complete or partial turbine blade release or vibration events that likely would have resulted in eventual blade release after further inspection.

NERC said generator owner-operators should consider strengthening turbine inspection procedures and performing inspections more frequently or during other major outages when possible. The report also said owners should ensure manufacturers have the capability and plans to replace major components after failure, while manufacturers should consider increasing trained maintenance personnel and verifying material procurement and processing capabilities.

NERC said reliability risk is shifting away from single-contingency or localized disturbances toward correlated, systemwide stresses. Those include energy limitations, lower-inertia operating challenges and declining availability of aging combustion generation. The report also said generation development has not and is not expected to keep pace with demand growth because of supply chain constraints, changing economics and rising grid upgrade costs.

Large-load integration emerged as another major reliability variable in 2025.

Projected annual energy demand reached nearly 4.95 million GWh, while data center customer-initiated load reductions, or CILR, became a documented grid reliability issue. In February 2025, a transmission fault in the Eastern Interconnection triggered 1,800 MW of data center CILR. Additional Eastern Interconnection events involved 428 MW in February, 227 MW in March, 540 MW in May and 1,300 MW in June.

ERCOT also logged nine cryptocurrency mining facility CILR events in 2025 that each exceeded 100 MW.

NERC said the events demonstrate why planners and operators need better models and operating data for large computational loads. As individual facilities grow larger and are developed near one another, the size of future load-reduction events could increase, creating measurable frequency or voltage stability concerns.

NERC has issued a Level 3 Essential Actions Alert directing transmission planners, planning coordinators, transmission operators, reliability coordinators and balancing authorities to take specific steps to manage computational load risks. Those actions include improving computational load modeling data, studying large-load impacts, updating planning processes, establishing commissioning procedures and creating direct communication and joint operating procedures with computational load facilities.

Battery energy storage also played a growing but mixed role in the 2025 reliability picture. NERC said BESS capacity additions approximately matched solar additions last year, while battery resources demonstrated fast frequency response capability and helped smooth the load curve in areas with significant solar generation.

That smoothing effect can reduce ramp stress on older thermal units by giving conventional generators more time to come offline and online during difficult parts of the operating day, particularly as solar output declines before evening peak conditions.

At the same time, NERC highlighted a failure mode unique to BESS. In January 2025, a 300 MW battery facility at Moss Landing experienced thermal runaway during routine testing and was functionally destroyed. NERC said the permanent, unplanned loss of a facility in that manner has little equivalent in conventional generation, although the report said such failures do not currently represent a significant concern to overall system reliability.

NERC also cautioned that BESS resources are typically designed for limited duration and are not a standalone solution for long-duration, widespread degradation events such as major winter storms. ERCOT has approved new grid-forming capability requirements for BESS resources with interconnection agreements dated on or after April 1, 2026.

For inverter-based resources, NERC said no major widespread disturbances tied to previously observed common-mode tripping mechanisms were identified in 2025. However, the report identified a 1,132 MW loss event caused by sub-synchronous oscillation protection tripping, a failure mode NERC described as previously unobserved at that scale.

NERC also reported the conclusion of a three-year IBR registration initiative, having identified approximately 531 facilities meeting the Category 2 generator owner and generator operator registry criteria. Beginning May 15, 2026, identified Category 2 facilities were registered and became subject to compliance with applicable reliability standards.

IHA said a total of 28 GW of hydropower capacity was commissioned last year, including a record 11.7 GW of pumped storage. For the first time, global pumped storage capacity has surpassed 200 GW, with a further 243 GW currently under construction worldwide.

“While conventional hydropower remains essential for low-carbon electricity generation, increasing shares of wind and solar power are driving growing demand for flexibility, balancing services and long-duration energy storage,” the association said. “As a result, pumped storage is becoming a strategic priority in major electricity markets worldwide.”

Global installed hydropower capacity, including both conventional hydropower and pumped storage, reached 1,469 GW in 2025.

China remained the leader in hydropower development in 2025, accounting for more than 40% of global capacity additions. The country now has more than 300 GW of hydropower under construction, including 218 GW of pumped storage.

IHA cited last year’s start of construction on the Yarlung Zangbo River Hydropower Project, which is projected to become the world’s largest hydropower facility, capable of generating roughly three times as much electricity as the Three Gorges Dam.

In North and Central America, IHA said governments are increasingly focused on modernizing conventional hydropower plants, extending the lives of existing facilities and developing new pumped storage projects. Canada fully commissioned the 1.1-GW Site C project in British Columbia during 2025, while the U.S. advanced major permitting reforms and fast-track measures to support modernization efforts and new infrastructure.

More than 60 GW of pumped storage projects are now in development across the U.S., the association said.

The report also identified growing demand from data centers and artificial intelligence as a major emerging driver for hydropower worldwide. In North America, technology companies including Google and Microsoft signed landmark long-term hydropower supply agreements during 2025.

Despite strong momentum globally, IHA’s outlook warns that significant barriers continue to slow hydropower deployment in many markets. The report said financing constraints, permitting delays, transmission bottlenecks, climate-related hydrological variability and regulatory uncertainty remain major obstacles to both conventional hydropower and pumped storage development.

Arizona Public Service (APS), Salt River Project (SRP) and Tucson Electric Power (TEP) announced they have begun a preliminary siting study to evaluate locations across Arizona, building on a collaboration first announced in early 2025.

The utilities said the study will use an industry-standard, phased screening methodology to identify a short list of candidate locations before selecting a preferred site. Existing and retired coal-fired power plant sites remain among the locations under consideration.

During that time, APS, SRP and TEP plan to begin stakeholder engagement and community outreach, including public meetings near potential sites later this year.

Completion of the study would not commit the utilities to building a nuclear plant. Instead, it would provide the foundation for evaluating technical, financial and regulatory considerations before deciding whether to pursue an Early Site Permit application with the U.S. Nuclear Regulatory Commission (NRC).

The utilities disclosed they were not selected for a DOE grant they applied for in early 2025 to support the effort. The funding request, submitted under DOE’s Generation III+ Small Modular Reactor program, would have helped offset the cost of early site evaluation work. The utilities said they will continue exploring future funding opportunities while advancing the initial planning effort.

No reactor technology has been selected for a potential project, but the utilities said both small modular reactors and large-scale reactor designs remain under consideration. They added that priority would be given to commercially proven technologies with demonstrated operating performance and experienced suppliers.

The continued nuclear evaluation comes as electricity demand accelerates across Arizona. APS, SRP and TEP each set peak demand records during 2025, driven by population growth and continued data center development.

Nuclear development in Arizona is also be the focus of an Arizona Corporation Commission workshop on Thursday, where utilities, policymakers and industry stakeholders are expected to discuss the role advanced nuclear technologies could play in the state’s future resource mix.

Palo Verde Generating Station is currently the only commercial nuclear power plant in Arizona. Located west of Phoenix, Palo Verde has the capacity to produce 4,200 MW, and is the largest power generator in the western United States.

Palo Verde is also the only nuclear plant in the world that does not have access to a surface body of water. It uses 100% recycled wastewater from surrounding cities for cooling. It is operated by APS and owned by seven utilities: APS, SRP, El Paso Electric, Southern California Edison (SCE), Public Service Company of New Mexico (PNM), Southern California Public Power Authority (SCPPA) and Los Angeles Department of Water and Power (LADWP).

APS is seeking to extend the operating licenses for all three units at Palo Verde, which could extend operations from the mid-2040s through the mid-2060s.

Chevron and Engine No. 1 have been collaborating on the development, known as Project Kilby. Kilby is expected to deliver approximately 2.67 GW of capacity, built through a phased, modular approach that Chevron says “enables incremental expansion over time.”

A majority of the generation will come from large GE Vernova turbines and associated electrical infrastructure, with additional capacity provided by Caterpillar subsidiary Solar Turbines. First power delivery is anticipated in 2028.

“AI is reshaping the global economy, and abundant, affordable, reliable energy is essential to fueling that transformation,” said Jeff Gustavson, Chevron president of New Energies. “Chevron is uniquely positioned to deliver power to customers with certainty, speed and at a competitive cost, leveraging Permian natural gas and our proven execution capabilities. This project links Chevron’s traditional strengths to emerging demand, creating differentiated value for our shareholders and the communities where we operate.”

By co-locating new, large-scale power generation with the data center, Kilby is designed to deliver dispatchable electricity directly to Microsoft while aiming to mitigate impacts on the regional grid.

In lieu of freshwater, Kilby plans to use non-potable, brackish groundwater sources for power plant operations. Chevron is also working to advance solutions for reuse of produced water from oil and gas operations. The plant design will incorporate air emissions control technologies, including selective catalytic reduction systems designed to reduce NOx emissions, as well as measures to minimize noise and light impacts on surrounding communities.

Last year, GE Vernova, Chevron and Engine No. 1 announced intentions to build a new company aimed at delivering up to four GW of reliable power for U.S. data centers. The partnership formed as energy demand for AI development and data processing continues to skyrocket. The companies cited early actions of the Trump Administration “setting the critical foundation to encourage investment leveraging America’s energy abundance to enable America’s AI leadership.”

The projects are not designed to initially flow through the existing transmission grid. Over time, surplus electricity from the projects could be sold back to the grid through future interconnects, providing additional capacity to the broader energy market without driving up costs for consumers.

The first projects, branded as “power foundries,” are expected to leverage seven GE Vernova 7HA natural gas-fired turbines, secured under a slot reservation agreement, on an accelerated timeline. The turbines are expected to serve co-located data centers in the U.S. Southeast, Midwest and West regions.

“The rapid growth we’re experiencing in AI and cloud, driven by customer demand, requires energy infrastructure that can scale quickly and reliably,” said Noelle Walsh, Microsoft president of Cloud Operations + Innovation. “Our agreement with Chevron helps ensure we’ll have dedicated, large-scale power to support the evolution and reliability of advanced compute. Through this partnership, we’re delighted to grow with and become a deeper part of the West Texas community.”

The U.S. Department of Energy (DOE), through its Office of Energy Dominance Financing (EDF), has issued a conditional loan commitment of up to $17.5 billion aimed at accelerating the deployment of 10 new large-scale nuclear reactors across the United States.

The financing package would support the purchase of long-lead equipment for a fleet of new nuclear projects equipped with Westinghouse’s AP1000 reactors. DOE said the funding structure is designed to reduce costs, strengthen domestic manufacturing capabilities and accelerate construction timelines as the federal government pursues a broader expansion of nuclear generation capacity.

Under the proposal, the financing would be distributed through up to five separate loans, with each loan supporting a two-reactor project site. Westinghouse would partner with as many as five utilities or energy companies to develop the projects.

DOE said each project would be jointly owned by Westinghouse and its utility or energy company partner. Before accessing federal loan funds, both parties would be required to commit $500 million in project equity, representing a combined $1 billion upfront investment per project.

The department said Westinghouse has already signed letters of intent with seven potential partners, each tied to identified project sites. Procurement activities would be staggered based on the timing of equity commitments and other project-specific considerations.

The AP1000 is the only licensed large-scale advanced commercial reactor operating in the nation. Each unit can generate approximately 1.1 GW of electricity, meaning the proposed 10 reactors would provide roughly 11 GW of new capacity.

Federal officials said the financing structure focuses specifically on long-lead equipment, which includes complex nuclear plant components that require extensive manufacturing and delivery timelines. By enabling bulk equipment purchases across multiple projects, DOE believes the program can create supply chain efficiencies, reduce component costs and shorten reactor deployment schedules by as much as three years.

The loan commitment remains conditional, meaning DOE and participating companies must still satisfy technical, legal, environmental and financial requirements before funds are disbursed.

The announcement comes in response to growing electricity demand projections tied to artificial intelligence, data centers, electrification and domestic manufacturing expansion. These trends have renewed interest in dispatchable generation resources, including nuclear power.

“America has always won when it thinks big and builds for the future,” said Westinghouse President and CEO Dan Sumner. “If we want to lead in artificial intelligence, advanced manufacturing, and the industries that will define the next century, we need more American baseload energy.”

The proposed financing package represents one of the most significant federal commitments to large-scale reactor deployment in recent years. It follows President Donald Trump signing an executive order calling for support of 10 large nuclear reactors to be designed and under construction by 2030.

The last two large nuclear reactors completed in the United States, Vogtle Units 3 and 4 in Georgia, entered commercial operation in 2023 and 2024, respectively. The AP1000 units were the first newly built commercial nuclear reactors to come online in the U.S. in more than 30 years.

Building a nuclear power plant is one of the most complex and capital-intensive infrastructure undertakings in the energy sector. Large nuclear projects often face lengthy development timelines, supply chain challenges, inflationary pressures and construction risks. Vogtle Units 3 and 4 ultimately cost billions of dollars more and took years longer to complete than originally projected.

However, industry leaders and policymakers frequently point to Vogtle as a learning opportunity for future deployments. They argue that lessons learned during the design, licensing, construction and commissioning processes could help reduce costs and shorten schedules for subsequent AP1000 projects.

The Clean Air Act (CAA) never imagined the current data center boom. Congress last amended the CAA in 1990 before the internet and email transformed public life. Data centers demand both baseload and emergency power, which creates significant air emissions. Therefore, the current regulations are forced to fit this new industry.

Most data centers are located to pull power from traditional utilities and shift the generation emissions onto the power plant, keeping only their backup power emission in house. But fifty to one hundred emergency generators can by themselves be a major source under the Prevention of Significant Deterioration (PSD) and Title V regulations. The PSD (or state non-PSD) construction permit is required before construction starts; usually the Title V operating permit is applied for after startup, but this can depend on geographic location.

New Source Performance Standard (NSPS) Subpart IIII regulates emissions from diesel generators. Warning: these are some of the most confusing regulations you have ever read! NSPS IIII limits particulate matter (PM), nitrogen dioxides (NO_x) plus non-methane hydrocarbons (NMHC), and carbon monoxide. Note that the PM limits are for all sizes of only filterable PM, and that NMHC can be assumed equal to volatile organic compounds (VOC). Generator limits are grouped in “Tiers” based on model year and size. New generators must meet the most stringent Tier 4 limits unless they are used only for emergency purposes (which can meet the higher limits of Tier 2 or Tier 3). Each individual emergency generator is allowed to operate for 100 hours per year (hr/yr) for testing and maintenance with unlimited operation allowed in an actual emergency. Exceeding 100 hours means the generator is not “emergency” and must meet Tier 4 limits. NSPS IIII does not allow a Tier 2 or 3 generator to be retrofitted to meet Tier 4 limits; it must meet Tier 4 based on the original equipment manufacturer’s design, which they apparently requested during rule writing. PM less than 10 microns and less than 2.5 microns (PM₁₀ and PM_2.5) can be calculated using standard EPA factors from the AP-42 reference document or vendor data, as long as both the filterable and condensable emissions are included.

An emergency generator is not allowed to participate in a peak shaving or non-emergency demand response agreement with the local utility; however, 50 of the 100 allowed hours per year can be used for grid stabilization under very specific conditions. Diesel generators are usually certified by the manufacturer to the Tier limits and thus don’t require stack testing. An emergency is a natural disaster or a power outage. It is not utility voltage fluctuations that haven’t yet caused an outage or an emergency that might happen. This regulatory interpretation likely conflicts with a data center’s definition of an emergency.

A PSD construction permit is required if the data center’s emissions exceed 250 tons per year (tpy) of either NO_x or carbon monoxide. This threshold decreases in an area with existing poor air quality (a nonattainment area). PSD permits can take 12 to 18 months to obtain.

National Ambient Air Quality Standards (NAAQS) are set by EPA to define clean air. Most data centers will be required to conduct air dispersion modeling to demonstrate that they will not cause or contribute to a violation of the NAAQS. It is not simple to model compliance from 100 diesel-fired generators. Common solutions are bundling several stacks together so that heights can be raised significantly, limiting testing/maintenance operation to daylight hours, limiting how many generators can be tested simultaneously, and fencing in as much property as possible. But most importantly, no generator can have a raincap or a horizontal discharge; it must exhaust in a vertical, unobstructed manner. A tractor flap type exhaust, which blocks rain when not in use and opens for free exhaust when in use, is allowed. It may be necessary to take the dominant wind direction into account so that individual plumes don’t overlap significantly.

A few additional insights:

• Onsite generation that does not feed the grid is not subject to the Acid Rain regulations.
• The potential-to-emit of a new emergency generator is calculated using either 100 or 500 hours per year, depending on the applicable state regulatory requirement.
• These generators will have a displacement of less than 10 liters per cylinder (NSPS IIII uses this parameter for applicability).
• Only ultra-low sulfur diesel is allowed (15 parts per million sulfur or 0.0015% sulfur).

Data centers are booming and air permitting can make or break a project. Don’t leave air quality as an afterthought.

About the Author: Robynn Andracsek, PE, is a Senior Project Engineer- Air Quality at T. Baker Smith with 29 years of experience in air permitting for utilities and district energy facilities.  T. Baker Smith (TBS) is a full-service engineering, surveying, and environmental consulting firm serving clients across the Gulf Coast and beyond. Founded in 1913, the firm brings more than a century of experience helping public and private sector clients plan, design, and deliver projects that strengthen infrastructure, support economic growth, and protect coastal and environmental resources. Guided by its core identity of its unique blend of Heart + Knowledge + Grit, TBS delivers integrated, technology-enabled solutions across diverse markets including government, energy, industrial, coastal, transportation, and commercial land development. Today, the firm employs more than 350 associates with offices spanning the Gulf Coast from Texas to Alabama. Her email address is robynn.andracsek@tbsmith.com.

Today, FERC issued tailored show-cause orders under section 206 of the Federal Power Act to each of the six regional grid operators within its jurisdiction, directing them to either justify or reform the rules governing how large energy users like data centers connect to the electric grid. The regional transmission operators (RTOs) and independent system operators (ISOs) are PJM Interconnection (PJM), Midcontinent Independent System Operator (MISO), Southwest Power Pool (SPP), California Independent System Operator Corporation (CAISO), ISO New England (ISO-NE), and New York Independent System Operator(NYISO).

FERC’s action on Docket RM26-4-000 is one of the most significant the Commission has ever taken to modernize the nation’s electric markets, aiming to “push the economy into the future by speeding integration of large energy users onto the grid.” By requiring RTOs, ISOs, and their transmission operators to either defend or revise their tariffs, FERC says it is acting to ensure that Americans have reliable, affordable power, even as electricity demand accelerates.

“We are setting the stage for a resilient, reliable, and forward-thinking grid that empowers communities and safeguards consumers by transforming the way large energy users access the grid. It is also critical that FERC provide certainty for investors by directing the markets to protect existing deals and unlock opportunities for technological advancement and economic expansion. We can facilitate both, which is exactly what we did today,” said FERC Chairman Laura V. Swett.

FERC’s action focuses on the unique operational profiles of large energy users, including those co-located with their own generation, and on the distinct challenges each regional grid operator faces in meeting soaring demand from the proliferation of large loads.

Five Categories of Reform

Under the orders, each RTO/ISO and its transmission owners have 60 days to either justify why their current tariffs remain just and reasonable without provisions tailored to large loads, or to file tariff changes that address the issues the Commission identified. Each tailored order tees up five categories of reform for the grid operators to address:

• Developing efficient transmission service application and study processes, including consideration of alternative transmission technologies
  
  
• Preventing cost shifting and requiring transparency into transmission costs
  
  
• Accommodating co-location agreements and behind-the-meter generation
  
  
• Providing new transmission services for flexible large loads
  
  
• Developing a process to study generating facilities that serve electrically proximate large loads and co-located loads

Additionally, within 30 days, each grid operator and its transmission owners must submit a detailed informational report describing how the grid operator intends to ensure that adequate generation will be available to serve existing and new large loads. The reports should include:

• Any proposals under consideration in its stakeholder process to address the issue of resource adequacy to serve new large loads
  
  
• A detailed schedule of key milestones, such as stakeholder or board votes, that includes the estimated date by which they expect to file any such proposal with FERC, and any ongoing stakeholder processes aimed at accelerating the addition of generating capacity in the region.

The reforms could create much-needed regulatory certainty and transparency, says the national clean energy business association Advanced Energy United, as well as safeguards to ensure that co-location won’t negatively impact electric rates and system reliability for all other customers.

“Addressing the rapid influx of new large loads requires speed, clarity, and transparency, and FERC’s orders today make meaningful progress on all those fronts,” summarized Caitlin Marquis, managing director at Advanced Energy United and guest on the newly-launched Factor This Policycast. “Importantly, FERC recognized that grid flexibility, advanced transmission technologies, and new co-located generating resources are critical to solving the challenge of accommodating large load. Now it is up to grid operators and the industry to respond to FERC’s directives quickly with workable, durable solutions that are fair for all customers.”

Among the highlights, according to Marquis:

• The orders indicate that grid operators must accommodate large loads either through co-location or through flexibility that allows for potential curtailment during peak energy demand.
• The orders require cost recovery agreements and leave states responsible for ensuring that transmission costs flow to large-load customers and are not shifted to other customers.
• The orders require grid operators to examine installing advanced transmission technologies (ATTs) when making transmission upgrades. 

“Deploying more advanced energy technologies and enabling more grid flexibility are essential to meeting fast-rising energy demands, and we’re pleased to see the commissioners prioritize these solutions in their Order,” added Marquis. “These changes must be complemented by fixes to the generator interconnection process for energy projects, or supply won’t keep up with fast-rising energy demands. We look forward to working with state leaders and grid operators on reforming the grid-connection processes that are still too slow and unpredictable for this demand-growth moment.” 

Regional Differences

Because the six grid operators are unique in their individual progress toward large load innovation and structure, market design, stakeholder composition, and geography, the Commission’s orders recognize that a one-size-fits-all solution is not currently the most efficient solution for integrating large, energy-intensive loads onto the nation’s electric grid. FERC recognizes that regional differences exist in the procedures and strategies implemented by grid operators to date, and will continue to shape future proposals.  The orders have been designed to reflect these variations.  Several significant distinctions include:

• The RTOs, ISOs, and their transmission owners have different existing processes for studying transmission service requests on behalf of large loads, with some already pursuing stakeholder efforts to address the proliferation of large loads in their footprints.
  
  
• SPP stands out for its High Impact Large Load and High Impact Large Load Generation Assessment processes, which are expedited frameworks created to reliably serve massive new power demand from large loads such as data centers.
  
  
• FERC addresses co-located loads in PJM in a separate proceeding, in which it takes the next step with the issuance of item E-2 on this morning’s agenda.
  
  
• Transmission service models differ, including in CAISO, which does not offer traditional Order No. 888 transmission services.
  
  
• Roles and responsibilities for transmission planning are split differently among RTOs, ISOs, and transmission owners across the regions.
  
  
• The orders leave room for each RTO and ISO to define large loads and to create operational requirements for those large loads that are particular to their region.
  
  
• The orders also account for regional differences on topics such as cost transparency, study processes, and network upgrades.

FERC notes that nothing in today’s orders intrudes on the authority of states to select, site, and permit generating resources or on the authority of state public utility commissions to set the rates, terms, and conditions of retail sales of electricity. The orders also make clear that the Commission acts today to guard against cost shifting among transmission customers, but leaves to the states the responsibility to ensure that there is no cost shifting among retail customers.  In addition, FERC insists the orders are not intended to disrupt existing agreements that large loads have negotiated, or are in the process of negotiating, for the provision of transmission service. These orders provide that the RTOs/ISOs should allow a reasonable amount of time to finalize agreements that are nearing completion when any tariff revisions are filed with the Commission.