Reliability

The PJM Interconnection’s Reliability Resource Initiative, a fast-track interconnection process, attracted 94 applications totaling 26.6 GW, according to the grid operator.

The proposed projects include new and uprated nuclear and natural gas-fired power plants, as well as new battery storage, PJM said March 21. Half of the proposals are new projects; the other half would increase capacity at existing power plants, according to the grid operator for the Mid-Atlantic and Midwest regions.

LS Power said it proposed converting two peaking facilities in Pennsylvania and Ohio to baseload combined cycle plants for an additional 600 MW, along with uprates totaling about 100 MW at other power plants in Pennsylvania and Virginia. The projects would cost about $1 billion, the independent power producer said.

Alpha Generation proposed about 450 MW in uprates at four power plants in Maryland, New Jersey and Ohio.

The Federal Energy Regulatory Commission approved PJM’s one-time RRI in mid-February on a 3-1 vote. Under the process, PJM will consider adding up to 50 shovel-ready projects that meet certain reliability and commercial operation date criteria to the just-started interconnection Transition Cycle 2, which already contains about 550 projects totaling about 50 GW in nameplate capacity.

“Adding RRI projects to TC2 is key to bringing additional capacity to the PJM markets before 2030,” PJM said. “Even for those that can’t [meet the timeline], it still benefits the PJM markets to have projects with an overall high score get a head start toward construction and commercial operation through participation in the RRI process.”

PJM said it expects to release more details about the RRI in mid-April.

The RRI proposal is in response to PJM’s concerns that its power supply margins are slipping in the face of power plant retirements and growing electricity demand. The grid operator estimates that it could face capacity shortfalls as soon as 2026.

PJM estimates its initiative could bring about 10 GW online 18 months earlier than if the projects followed the grid operator’s normal interconnection process, according to FERC’s decision.

In a prelude to potential lawsuits over FERC’s approval of the RRI, various companies, state officials and organizations this month asked the agency to reconsider its decision.

They include Invenergy Renewables, the American Clean Power Association, the Solar Energy Industries Association, Advanced Energy United and MAREC Action, the Sierra Club, the Natural Resources Defense Council and other groups, the Office of the Ohio Consumers' Counsel and the Environmental Law & Policy Center.

In part, they contend the RRI discriminates against proposed power projects that have been waiting in PJM’s interconnection queue.

“Much as PJM’s tinkering with its capacity market has undermined market confidence, the commission’s approval of PJM’s queue jumping proposal has begun to erode confidence in PJM’s interconnection rules and catalyze additional proposals to undermine open access in other [regional transmission organizations],” Invenergy said in its March 13 rehearing request.

The Midcontinent Independent System Operator last week also asked FERC to approve a special fast-track interconnection review process.

Rapid energy demand growth in the U.S. is threatening an aging and fragile electric grid, says the American Society of Civil Engineers, resulting in the group dropping the energy sector’s 2025 Infrastructure Report Card grade to a D+ from the C- they gave it in 2021. 

ASCE cited a shortage of distribution transformers, increases in severe weather events and a lack of transmission capacity as some of the challenges facing the U.S.

At the same time, “consumers and businesses are growing increasingly reliant on data storage facilities, artificial intelligence, and electrified products such as EVs, to name just a few examples of advancements adding immense strain” to the grid, said ASCE’s report.

“An increase in electric vehicles and a rise in data centers will demand 35 GW of electricity by 2030 alone, up from 17 GW in 2022,” said ASCE. “This rapid acceleration, compounded by federal and state net-zero greenhouse gas emissions goals, means utilities will need to double existing transmission capacity to connect new renewable generation sources.”

The report noted that transmission investments rose by $5 billion from 2017 to 2022, and the 2021 Infrastructure Investment and Jobs Act includes funding for infrastructure elements like transmission buildout. 

One IIJA investment, announced in 2023, is spending $1.3 billion on three interregional transmission lines across six states: the 175-mile Southline Transmission Project (New Mexico to Arizona); the 211-mile Twin States Clean Energy Link (New England to Quebec, Canada); and the 214-mile Cross-Tie Transmission Line (Utah to Nevada).

“The IIJA allocated $73 billion from 2021 to 2026 to modernize the electric grid, build thousands of miles of new power lines, and expand renewable energy,” ASCE said. “Much of the funding is dedicated to hardening [transmission and distribution] lines to be more resilient,” using measures like “undergrounding overhead power lines, implementing fire-resistant technologies, and replacing poles and other structures with stronger, more durable materials.”

The IIJA also “invested heavily in grid resilience,” ASCE said, with the law establishing a $10.5 billion Grid Resilience and Innovation Partnerships Program, one project of which is the Grid Innovation Program. The Grid Innovation Program is providing “$5 billion for [fiscal year 2022 through 2026] to support projects that use innovative approaches to transmission, storage, and distribution infrastructure to enhance grid resilience and reliability,” according to the Department of Energy.

However, ASCE said, state renewable portfolio standards and federal decarbonization initiatives are combining with surging energy demands and leading to “rapidly escalating funding needs in the generation and [transmission and distribution] sectors.”

“Even if funding levels established by the IIJA and [the Inflation Reduction Act] are reauthorized in 2026, the energy sector faces a $578 billion investment gap by 2033, which climbs to $702 billion by 2033 if the nation ‘snaps back’ to pre-IIJA/IRA funding levels when the bills expire,” the report said. 

For the U.S. to raise its energy infrastructure grade, ASCE made recommendations that include the adoption of a federal energy policy designed to meet current and future technology changes; the development of a robust national transformer inventory; a national grid hardening plan; and a requirement for “energy providers to adopt the most stringent consensus-based codes and standards for all overhead T&D lines, structures, and substations to ensure safety and increase reliability.”

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The U.S. energy grid is under immense strain. Aging infrastructure, surging demand and extreme weather events push the system to its limits. At the same time, commercial real estate faces its own crisis, with vacancy rates surging due to shifts in work habits. While these issues seem unrelated, they present an unexpected opportunity: transforming commercial buildings into vital assets for strengthening and stabilizing our power grid.

The grid's growing pains and how commercial buildings help

The energy grid's challenges are mounting. According to the Energy Information Administration, 70% of U.S. power transformers and transmission lines are over 25 years old. In 2022, grid congestion cost consumers approximately $20.8 billion, driven by fuel price volatility, transmission outages and rising electricity demand. Data centers alone are projected to consume up to nine percent of total U.S. power demand by 2030. These challenges require innovative solutions that can be implemented quickly and effectively.

Commercial buildings offer a unique solution by becoming "mini power plants" that generate and store energy right where it's needed. During periods of high demand – like hot summer days or freezing winter nights – these buildings can step in to support the grid, providing immediate relief to stressed infrastructure and reducing the need for expensive grid upgrades.

Benefits for property owners and tenants

Modern commercial energy systems deliver substantial advantages. Advanced systems provide multi-layer backup power with rapid switching to prevent equipment shutdown during outages. Property owners can lower energy bills by up to 30% by replacing grid power with renewables, while flywheel-based hybrid storage systems reduce peak demand charges. Battery installations smooth frequency irregularities, protecting sensitive equipment from damage or disruption. AI-powered management software enables energy forecasting and optimization, helping businesses schedule energy-intensive tasks during periods of peak renewable generation and reducing carbon emissions by up to 90%.

Why decentralized is better than large solar and battery farms

Unlike massive solar farms or centralized battery installations, a network of commercial buildings offers distinct advantages. Transmission and distribution losses currently account for about 5%–6% of electricity generated. By generating and storing energy where it's consumed, commercial buildings eliminate these losses and reduce grid congestion, potentially saving the U.S. an estimated $26–31 billion annually. If just 25% of U.S. electricity generation shifted to local production, the avoided losses could power approximately 4.6–5.5 million typical homes daily. Additionally, distributed systems respond to grid needs almost instantly, offering more flexible and efficient support than large, centralized facilities.

Utility benefits through large-scale demand response

The partnership between commercial buildings and utilities creates powerful synergies through programs like Rocky Mountain Power's Wattsmart battery program. In 2024 alone, Torus systems responded to 120 demand response events with 99.99% uptime, demonstrating the reliability of this approach. Commercial buildings can provide dependable grid support while generating additional savings through utility incentives and bill credits.

How Torus community makes it all happen

Torus Community serves as the platform that transforms individual commercial buildings into a coordinated network of energy assets. The system prioritizes each building's needs first – whether charging batteries, offsetting loads, or powering critical equipment. Only after these primary needs are satisfied does excess power support the broader community. This intelligent approach creates a powerful network effect where buildings support each other during peak demand periods, utilities gain access to reliable distributed energy resources, and communities benefit from improved power reliability while reducing carbon emissions through optimized energy use.

Financial incentives and ROI

The economics of energy storage have never been more attractive. Commercial installations qualify for a 30% federal investment tax credit under the Inflation Reduction Act, while utility rebates and demand response programs add further savings. Combined with operational efficiencies and reduced energy costs, these incentives often result in lifetime system values exceeding initial costs.

Building a sustainable future

Commercial buildings hold the key to solving two critical challenges: stabilizing the grid and reducing carbon emissions. By transforming millions of square feet of vacant space into energy hubs, property owners aren't just cutting costs – they're helping build the foundation for a more resilient, sustainable energy future. For utility executives and real estate investors alike, the opportunity is clear: turn today's challenges into tomorrow's advantages while securing long-term benefits for businesses, communities and the environment.

The Midcontinent Independent System Operator on Monday asked federal regulators to approve an Expedited Resource Addition Study process, or ERAS, to provide a framework for the accelerated study of generation projects “that can address urgent resource adequacy and reliability needs in the near term.”

MISO asked the Federal Energy Regulatory Commission to approve the ERAS proposal to be effective May 17. The grid operator is on pace for near-term capacity shortfalls, should resource retirements continue as planned, it said.

MISO proposed for projects entering the ERAS process, as opposed to MISO’s standard Generator Interconnection Queue, to be studied serially each quarter and granted an Expedited Generator Interconnection Agreement within 90 days. Renewable energy stakeholders, however, warn the ERAS proposal “adds chaos to an already complex process.”

Recent surveys and forecasts demonstrate the urgency with which MISO needs to “address significant resource adequacy needs in its footprint that are compounded by the addition of unexpected large spot loads,” the grid operator told FERC.

NERC’s 2024 Long-Term Reliability Assessment projected MISO will experience a 4.7 GW shortfall by 2028 if the current expected generator retirements occur, the grid operator said. And last year the grid operator and the Organization of MISO States published a report warning of possible capacity shortfalls beginning this summer.

The ERAS proposal “is MISO’s answer to addressing these resource adequacy and reliability needs in the near-term,” it said in its proposal. “ERAS is a unique process which recognizes that the responsibility for providing grid reliability and resource adequacy in the MISO region is shared by Load Serving Entities ... the states, and MISO.”

According to MISO’s application, as of March 13 its generator interconnection queue contained 1,603 active interconnection requests.

“This considerable backlog of applications is spread over all five of MISO’s study regions and includes queue cycles going back to 2019,” it said. “The queue size continues to be extraordinary and unprecedented — the 2023 queue cycle, the last to close in 2024, alone is 123 GW.”

Importantly, MISO said almost 70% of the total generation capacity that entered the 2017 and 2018 queue cycles was eventually withdrawn and “similar withdrawal rates are occurring in the later cycles as well.”

But the Clean Grid Alliance, which represents renewable energy stakeholders, said the ERAS framework “overcomplicates an already complex system.”

"ERAS has been introduced primarily to address the demands of a few states within the MISO footprint that are seeking to prioritize resources not currently in the existing interconnection queue, despite ample availability of generating resources that have completed the queue and are ready for commercial operations," CGA Vice President, Transmission and Markets, David Sapper, said in a statement.

Even with a 21% completion rate, the queue has 18 GW of storage and hybrid capacity, and planned transmission expansion could increase that to 29 GW, “far exceeding the projected shortfall,” CGA said in a statement. “Furthermore, ERAS is moving forward before the full effect of recent queue reforms is seen, which has already reduced the queue by approximately 33%.”

The renewables group said it is advocating for solutions that “maintain open access, avoid delays to existing processes, and leverages faster-constructing resources that are already in the queue.”

"There is no need to upset the apple cart. Rather, we encourage MISO to embrace the simplest solution, which is to stick with their existing tariff because it already allows for expediting serious projects," said CGA Executive Director Beth Soholt.

MISO’s existing Provisional Generator Integration Agreement “maintains competition, efficiency, and reliability and can quickly interconnect the most certain, non-speculative projects, including gas,” Soholt said. “It's technology-neutral and inherently prioritizes the need. Existing processes can bring capacity online quickly, while maintaining open access that keep costs down. This fast and fair solution to meeting large load demands is good for everyone."

MISO’s application assured regulators that “guardrails” will ensure that “only truly necessary and certain projects can enter ERAS.”

Projects must demonstrate 100% site control for the interconnection customer’s interconnection facilities, establish due dates for commercial operation, pay a nonrefundable deposit of $100,000 and a $24,000/MW milestone payment. They must also agree to pay for all necessary network upgrades.

MISO said it wants to sunset ERAS by the end of 2028, reflecting the grid operator’s “intention for these projects to be completed as soon as possible as well as providing MISO with sufficient time to complete other queue process improvements.”

Utilities and system operators are discovering new ways for artificial intelligence and machine learning to help meet reliability threats in the face of growing loads, utilities and analysts say.

There has been an “explosion into public consciousness of generative AI models,” according to a 2024 Electric Power Research Institute, or EPRI, paper. The explosion has resulted in huge 2025 AI financial commitments like the $500 billion U.S. Stargate Project and the $206 billion European Union fund. And utilities are beginning to realize the new possibilities.

“Utility executives who were skeptical of AI even five years ago are now using cloud computing, drones, and AI in innovative projects,” said Electric Power Research Institute Executive Director, AI and Quantum, Jeremy Renshaw. “Utilities rapid adoption may make what is impossible today standard operating practice in a few years.”

Concerns remain that artificial intelligence and machine learning, or AI/ML, algorithms, could bypass human decision-making and cause the reliability failures they are intended to avoid.

“But any company that has not taken its internal knowledge base into a generative AI model that can be queried as needed is not leveraging the data it has long paid to store,” said NVIDIA Senior Managing Director Marc Spieler. For now, humans will remain in the loop and AI/ML algorithms will allow better decision-making by making more, and more relevant, data available faster, he added.

In real world demonstrations, utilities and software providers are using AI/ML algorithms to improve tasks as varied as nuclear power plant design and electric vehicle, or EV, charging. But utilities and regulators must face the conundrum of making proprietary data more accessible for the new digital intelligence to increase reliability and reduce customer costs while also protecting it.   

The old renewed

The power system has already put AI/ML algorithms to work in cybersecurity applications with cutting-edge learning capabilities to better recognize attackers.

Checkpoint Software, the global AI chip maker NVIDIA’s security provider, is working with standards certifier Underwriters Laboratories on new levels of security for consumer devices, said Peter Nicoletti, Checkpoint’s global chief information security officer. Smart devices “will be required to meet a security standard protecting against hackers during software updates,” he said.

Another proven power system application for advanced computing is market price forecasting based on weather, load and available generation.

Amperon has done weather, demand and market price forecasting with AI/ML algorithms since 2018, said Sean Kelly, its co-founder and CEO. But Amperon’s short-term modeling now “runs every hour and continuously retrains smarter and faster using less energy, combining the strengths from each iteration in a way that humans could never touch,” he added.

Hitachi Energy’s Nostradomus AI forecasting tool, with the newest AI/ML capabilities, “has improved price forecasting accuracy 20% over human market price forecasting” since November, said Jason Durst, Hitachi Energy general manager, asset and work management, enterprise software solutions.

AI/ML-assisted technology has also emerged “as a critical pillar of wildfire mitigation strategy,” said Rob Brook senior vice president and managing director, Americas, for predictive software provider Neara. It helps utilities identify wildfire risks “across their networks by proactively assessing more variables than a human can assimilate,” he added.

AI/ML algorithms have, in the last year, accelerated the use of robotics for solar construction, said Deise Yumi Asami, developer of the Maximo robot for power provider AES. The six months once needed to retrain Maximo have been eliminated because its AI/ML algorithms autonomously learn the unique characteristics of each solar project before it begins work, she added.

The new and more autonomous AI/ML capabilities will offer “increased stability, predictability, and reliability at scale,” said Nate Melby, vice president and chief information officer of Midwestern generation and transmission cooperative Dairyland Power Cooperative. Management of system complexity “is where AI could shine,” he added.

Utilities are increasingly using new AI/ML capabilities to meet the accelerating complexities of variable loads, proliferating distributed energy resources, or DER, and other power system challenges.

New needs, new capabilities

A power system without adequate flexibility “can lead to decreased reliability and safety, increased operational costs, and capacity costs,” Pacific Gas and Electric, or PG&E, concluded in its 2024 R&D Strategy Report. “AI/ML and other novel technologies can not only bolster our immediate response capabilities but also inform long-term planning and policymaking,” it added.

PG&E’s total electricity consumption will double in the next five to 10 years, but it can limit peak load growth to 10% with AI/ML-based grid optimization of DER on the existing infrastructure, PG&E CEO Patti Poppe said at the utility’s November Innovation Summit.

Access to AI/ML algorithms is now commercially viable, and their capabilities can optimize multiple large scenarios in parallel to support decision-making for the power system’s millions of variables, NVIDIA’s Spieler said. The algorithms can also write software code to allow utilities to use “the petabytes of stored system data they have but have not used to optimize more operations,” he added.

Utilities can upload and query their internal knowledge bases of research papers, rate cases and analyses of wildfire and safety issues into a generative AI model, Spieler said. The query responses can then explain system anomalies based on performance and maintenance histories or deliver needed data and precedents for writing general rate case and other regulatory proceeding filings, he added.

Utility demonstrations are verifying the new AI/ML capabilities.

From DER to nuclear plants

Several demonstrations have focused on how AI/ML algorithms can optimize distribution system resources.

Utilidata’s Karman software platform and an NVIDIA GPU-empowered chip are embedded in Aclara smart meters and will soon be in other distribution system hardware, said Utilidata VP, Product, Yingchen Zhang. Karman reads high resolution distribution system raw data 32,000 times per second and identifies individual customer electricity usages in real time, he added.

A real world demonstration, with Karman reading and reacting to granular real-time data, found utilities can quickly stabilize EV charging-induced voltage fluctuations, a University of Michigan-Utilidata study noted.

Within one year of implementing software from data disaggregation specialist Bidgely, Avista Utilities reduced service calls in response to high bill complaints by 27%, reported Avista Corp. Products and Services Manager Andrew Barrington. Instead of a service call to check the customer’s meter, Bidgely’s software analysis identified the customer usage causing the bill spike, he added.

A Bidgely disaggregation analysis evaluated EV charging for 10,000 Ameren Missouri customers, reported Caroline Cochran, its VP, Delivery, in a Stanford-EPRI conference presentation. The analysis identified the 73 customers that could utilize better management to avoid or defer costly infrastructure expenditures that otherwise would have been needed to manage EV charging loads, she added.

Bidgely’s similar 2023 disaggregation analysis of 100,000 NV Energy EV charger owners identified “hot spots where infrastructure investment will likely be needed first,” which limited larger distribution system capital investment, reported the Smart Electric Power Alliance’s January AI for Transportation Electrification Insight Brief.

AI/ML algorithms are also finding efficiencies that reduce nuclear power plant costs and safety challenges.

PG&E is using Atomic Canyon’s Generative AI software, trained to Nuclear Regulatory Commission standards, at its Diablo Canyon Nuclear Power Plant, said Nuclear Innovation Alliance Research Director Patrick White. And innovative AI/ML-based plant designs, operations and predictive preventive maintenance are limiting costs and increasing plant safety, he added.

There are, however, things utilities must do to more fully take advantage of the accelerating AI/ML capabilities, utilities and providers recognize.

The work ahead for utilities           

Effectively capturing the benefits of AI/ML algorithms begins with recognizing the potential and acquiring and using the right hardware and software, utilities and third parties say.

Avista’s successful adoption of third-party AI/ML “began with a mindset,” said Barrington. The key questions were “how to enhance customer engagement, how to integrate customer data with system operations, and how to enhance system visibility and enable proactive strategies,” he added.

AI/ML algorithms are now extracting real-time data and making actionable suggestions, Utilidata’s Zhang said. But “utilities cannot take advantage of the suggestions because they do not have the technology and communications ecosystems in place,” he added.

Utilities need communications technologies, advanced metering and edge computing infrastructure, and data processing and storage technologies, EPRI’s Renshaw said. And, at the distribution system level, utilities should also have software that can be securely updated for new technologies as customers adopt them, Utilidata’s Zhang added.

Balancing the protection of security and customer privacy with the need to provide data to train AI/ML algorithms continues to be a significant challenge.

Protecting utility data requires “strong cybersecurity practices,” said Dairyland Power’s Melby. But utilities need to access and manage data in a way “AI platforms can leverage,” he added.

Recently, “utilities have begun doing penetration testing to prove their data is as secure in our system as in theirs,” said Bidgely’s Cochran. They also “have developed AI committees to do extra thorough reviews of the users of their data,” she added.

“There is good reason for utilities to be conservative about data privacy, but AI/ML power system applications are not yet any threat,” Utilidata’s Zhang said. Federated learning or foundation models are ways to both protect privacy and provide data for algorithm training, he added.

Federated learning allows utilities to protect proprietary data by building synthetic models of their data about specific challenges that can be shared at a secure location for further training, Zhang said.

But some think federated learning may be too limited for power system complexities. Foundation models would use orders of magnitude more data that has been anonymized and pre-trained with as much power system information as possible, EPRI’s Renshaw and others said.

Utilities may be able to create a foundation model to enable shared learning and protect their data, said PG&E Senior Director of Grid Research, Innovation and Development Quinn Nakayama.

“The bottom line is — gather more high-quality data, use, store and protect it properly, and feed it into models that are trained and updated for the right tasks,” Renshaw concluded.

FirstEnergy and other utilities are warning that Trump administration tariffs on Canada, Mexico and other countries could hurt them, according to risk disclosures included in annual reports filed last month with the U.S. Securities and Exchange Commission.

The alerts on tariffs come as U.S. utilities have been expanding their capital expenditure plans to build transmission lines and power plants to meet rising demand growth, partly driven by data center development.

“Any widespread imposition of new or increased tariffs could have an adverse effect on our results of operations, cash flow and financial condition,” FirstEnergy said in a Feb. 27 filing. “New or increased tariffs could also negatively affect U.S. national or regional economies, which also could negatively impact our business and results of operations.”

Deteriorating economic conditions triggered by tariffs or other causes generally lead to reduced electric use by customers, particularly industrial customers, according to American Electric Power.

“The current administration has implemented tariffs on certain imported goods and may impose additional tariffs,” AEP said in a Feb. 13 filing. “As a result, prevailing economic conditions may reduce future net income and cash flows and negatively impact [our] financial condition.”

Tariffs could disrupt supply chains and delay building, maintaining and repairing infrastructure needed to support operations or are required to execute AEP’s plans for continued capital investment and to transition its generation fleet, the Columbus, Ohio-based utility company said.

Tariffs could also drive up the price of materials and equipment, increase the cost of capital and extend procurement lead times, according to AEP.

President Trump on March 4 imposed 25% tariffs on imports from Mexico and Canada, and increased tariffs on imports from China by 10%. Those countries responded with plans to impose tariffs on U.S. imports.

The tariffs could limit access to electrical equipment, such as transformers, needed to maintain and expand the grid, according to a report released Monday by the Atlantic Council, a think tank. The U.S. imports about 80% of its electric transformers, with Mexico being the largest supplier, according to the report.

Also, Trump’s 25% tariffs on steel and aluminum will raise prices of grain-oriented electrical steel that is used to make transformers, increasing the price of U.S.-made transformers, the report’s authors said.

“Higher prices for transformers, especially transformers imported from Mexico, because of tariffs will raise project-development costs and delay infrastructure upgrades, hitting Texas hardest,” they said, noting there is a transformer shortage.

‘The operative word is uncertainty’

Even so, it’s not clear how the tariffs will affect utilities, according to analysts.

“It's very hard to predict what's going to happen. We’re in uncharted territory,” Paul Patterson, an equity analyst at Glenrock Associates, said in an interview, noting the tariffs could expand to Europe and other countries. “The operative word is uncertainty.”

However, it is unlikely that utility multi-year capital expenditure plans will be directly affected by tariffs, according to Patterson. More immediate issues are inflation and the possibility of the United States entering into a recession, he said. But, if infrastructure becomes more expensive to build, utilities may face pressure to delay projects, according to Patterson.

Travis Miller, a Morningstar analyst, doubts tariffs will have much effect on utility capital expenditure plans. “Most utilities either get their equipment from domestic manufacturers or have contracts for already secured equipment deliveries from outside the U.S.,” he said in an interview.

The Edison Electric Institute, a trade group for investor-owned utilities, plans to work with the Trump administration to ensure that any new tariffs don't raise customer energy bills due to higher commodity prices, according to Scott Aaronson, EEI senior vice president, energy security and industry operations. 

“Our industry must have access to the critical components, commodities, and equipment needed to operate the grid, as we work to meet growing customer demands for electricity reliably and affordably,” Aaronson said in an email. “Electric companies are committed to keeping costs to customers as low as possible.”

The National Electrical Manufacturers Association on Tuesday called for trade policies that provide predictability and certainty, with a “reasonable” transition period for large-scale manufacturing to come online in the U.S.

“NEMA urges the Trump Administration to reach a long-term deal that strengthens trade across North America, provides business certainty for the essential electrical industry, and facilitates our shared goals of a robust energy sector and strong U.S. manufacturing base,” NEMA President and CEO Debra Phillips said in a statement.

It’s unclear how long the tariffs against Canada and Mexico will last, according to Capstone.

“Capstone believes the market’s reaction to the universal tariff on all imports from Canada, Mexico, and China, coupled with the impact these tariffs will have on the US auto industry and gas prices, will prompt Trump to remove the tariffs on Canada and Mexico,” analysts with the research firm said in a Tuesday note. “Even if superficial, concessions from Canada and Mexico could give Trump an out, allowing him to parade his tariffs as successful while avoiding further market volatility.”

The Federal Energy Regulatory Commission will address regulatory issues around colocating large loads, such as data centers, at power plant sites, FERC Chairman Mark Christie said in an interview.

“Colocation is a huge issue that we need to get in front of,” Christie said. “There's a strong consensus that we need to move forward.”

President Trump on Jan. 20 elevated Christie from FERC commissioner to chairman, a position that sets the agency’s agenda. Christie’s term on the commission ends June 30; when asked about a possible second term, he said there was “no news.”

Christie said his top priorities are protecting consumers from excessive electricity costs, ensuring grid reliability and strengthening ties between FERC and states.

Colocation, especially when it occurs at existing power plants, potentially affects two of those priorities: consumer costs and reliability. Companies exploring serving data centers next to nuclear and gas-fired power plants include Constellation Energy, PSEG Power and Vistra.

In November, Christie joined FERC Commissioner Lindsay See in a 2-1 vote to reject an amended interconnection service agreement that would have facilitated expanded power sales from a Susquehanna nuclear power plant in Pennsylvania that is majority owned by Talen Energy to to a colocated Amazon data center. Talen on Jan. 15 asked the U.S. Court of Appeals for the Fifth Circuit to overturn FERC’s decision.

In a concurrence to the decision, Christie cited concerns the PJM Interconnection’s market monitor raised that the Amazon data center could remove a significant amount of electricity from the grid operator’s market. It could also increase energy and capacity prices, according to the market monitor. In the interview, Christie said he stood by the concerns he raised in his concurrence.

FERC will address colocation using information it gathered at a technical conference the agency held in early November, Christie said, noting it is too soon to say when or how the agency will take up the issue.

“We have to get it so we don't cost-shift to residential consumers who are struggling right now to pay their monthly bills,” Christie said. “We’ve got to make sure there's no cost-shifting.”

Protecting consumers

Christie said his experience as a state regulator is part of what’s driving his focus on protecting consumers. Before joining FERC in January 2021, Christie served for 17 years at the Virginia State Corporation Commission as a judge — or what most states call a commissioner — and chairman.

“When you raise somebody's retail rate, it's going to go in their monthly bills,” Christie said. “These are the people you run into in the grocery store, when you walk around … These are your neighbors.”

FERC lacks a consumer advocate representing residential ratepayer interests, Christie noted. “I wish we did have one, but we don't,” he said. “We still have to remember the public interest ... the people who are not in the room, and the people who are not represented, and people who don't have the lawyers, and people who don't have the lobbyists pushing various regulatory initiatives.”

Electricity is an essential, non-discretionary service, Christie said, and his philosophy of utility regulation is “reliable power at the least cost.”

During his tenure at the Virginia SCC, Christie said he dissented twice out of roughly 17,000 orders that he participated in. In both dissents, Christie said he opposed allowing utilities to recover half of their charitable giving from ratepayers.

FERC has little role in overseeing generation and the distribution system, which fall under state jurisdiction, according to Christie. The agency affects customers’ electric bills through transmission, however, he said.

As a FERC commissioner, Christie has repeatedly called on the agency to revisit the incentives it gives to utilities and other companies to build power lines. Christie contends the incentives shift risks and costs onto consumers. He wants to eliminate incentives such as “construction work in progress,” which allows a utility to recover its expenses while it is building a project instead of waiting to recoup those expenses via a rate case after it is placed into service.

He has also wants to see changes in how FERC approves “formula rates,” an annual process that allows transmission owners to update their transmission rates outside a typical rate case. FERC acts on the presumption that transmission owners’ spending was prudent, leaving it up to ratepayer advocates and others to show it wasn’t.

Christie said he is “certainly going to try to act” on those issues as chairman. In August, he proposed providing incentives only for projects that had been thoroughly reviewed by states.

Grid reliability and capacity markets

Gid reliability is also a major concern for Christie, especially amid “mind-boggling” load growth forecasts driven by data centers.

On Jan. 23, Christie noted that PJM that week had set a winter peak load record of 145 GW, The generation mix serving the load was gas at 43.7%, nuclear at 22.2%, coal at 21.6%, wind at 2.4%, hydroelectric at 3.6%, oil at 4.4% and solar at 0.4%.

The Midcontinent Independent System Operator’s load peaked during the same cold snap at 108.2 GW, with a generation mix of gas at 37.1%, coal at 30.1%, wind at 17.7%, nuclear at 11.3% and solar at effectively zero, according to Christie.

“In both PJM and MISO, dispatchable generation kept the lights on and heat pumps running during this freezing weather,” Christie said on X, formerly Twitter. “We need to stop the premature retirements of dispatchable generation and build more, otherwise we freeze in the dark. That is reality.”

Reports from the North American Electric Reliability Corp. and grid operators like PJM show that baseload power plants are retiring without adequate replacements, Christie said in the interview.

While FERC has no direct authority over generation, the agency regulates capacity markets run by PJM, MISO, ISO New England and the New York Independent System Operator, Christie noted.

Through its market oversight, FERC has “a big impact on what gets built and what gets retired,” Christie said. “We're not just a bystander saying, ‘Hey, look what's happening.’ We are a big actor here.”

Currently, PJM is at the center of capacity market reforms. “We're seeing numerous problems in the PJM capacity market,” Christie said, pointing to several pending market reform proposals and complaints.

Christie said he “expressed a long-time skepticism about whether this [capacity] construct is the best way to get resource adequacy” in a May 2023 Energy Law Journal article.

Strengthening FERC-state connections

Christie said he plans to continue a collaboration between FERC and the National Association of Regulatory Utility Commissioners that started during former FERC Chairman Richard Glick’s tenure.

“It is a structured way of constant communication” that it lets federal and state commissioners learn about the challenges their colleagues are facing, Christie said. “I am very, very adamant that we need to keep in constant dialogue with the states. The states are on the front lines.”

State utility regulators understand their states better than anyone, according to Christie. “I didn't know more than the regulators from California, Minnesota, Indiana, any other state, and I didn't become a genius when I came to FERC,” Christie said. “The regulators live it in those states, and so we need to listen to them … that’s what's important about going to those NARUC meetings.”

The Federal Energy Regulatory Commission is seeking comments on proposed “ride-through” reliability standards for inverter-based resources, called IBRs, such as wind, solar and battery systems.

FERC is proposing to approve two North American Electric Reliability Corp. reliability standards dealing with the ability of IBRs to ride through frequency and voltage excursions like faults on the transmission system instead of tripping offline, according to FERC. The agency is also seeking more information on exemptions for existing IBRs.

“Generator ride-through is a foundational essential reliability service,” NERC said in its ride-through proposal. “Ensuring fault ride-through capability enables dynamic reactive power support, frequency response, and other services.”

NERC has been tracking a growing list of IBRs tripping offline because of grid disturbances, including an event in 2022 when about 2.5 GW of solar in Texas unexpectedly went offline. The sudden loss of generation poses reliability risks, according to NERC.

The grid watchdog organization said its proposal establishes a clear understanding of what it means for a generator to ride-through a disturbance; establishes voltage and frequency ride-through criteria for IBRs; and ensures that post-disturbance ramp rates return to pre-disturbance levels.

The proposal would take effect on the first day of the quarter that starts 12 months after it is approved by FERC.

The proposal is part of a suite of IBR standards that FERC in 2023 directed NERC to develop. They cover IBR-related data sharing, model validation, planning and operational studies, and performance requirements, FERC said. 

FERC is bolstering standards for IBRs amid a surge in wind, solar and storage development. Those resources use inverters to convert the direct current electricity they produce to alternating current electricity used on the grid.

Synchronous generators, such as natural gas-fired power plants, typically ride through grid disturbances while IBRs must be programmed to do so.

FERC will take comments on the proposed standards for 60 days after a notice is published in the Federal Register.

Here are five other takeaways from the meeting.

Rosner highlights NERC reliability report. In its Long-Term Reliability Assessment released Tuesday, NERC projected that half of the United States is at risk of power shortfalls in the next decade under average summer and winter conditions, FERC Commissioner David Rosner said during the agency’s open meeting.

“Everyone in the room knows that this is not our first warning, and I think we all agree that this is an unacceptable risk,” Rosner said. “We need every last drop of efficiency we can get out of the current system. We need to keep a lot of the resources on the grid today, and we need to build to take advantage of the wealth of natural resources of all types that this country is so lucky to have … We need to make sure that our decisions send signals to invest in the right resources with the right attributes in the right places in the country where they're needed.”

Rosner laments decision approving removal of 900-MW project from PJM queue. FERC on Thursday rejected a complaint by Urban Grid Solar Projects over the PJM Interconnection’s decision to remove a 900-MW solar project in Virginia from its interconnection queue. Due to a mistake, Urban Grid, a Houston-based company owned by Brookfield Renewable U.S., missed a deadline for filing a security deposit, but argued it was able to the next day.

“We've got a 900-MW generator that the grid operator removed from its queue at a time when the grid is facing dire warnings about resource adequacy,” Rosner said, noting that he concurred with the decision. “But when you take a step back from the specific details of the tariff … I think the outcome here is really hard to explain. Simply put, the interconnection process is failing us when it forces a generator that's been in the queue for five years to go all the way back to the beginning of the line when it missed a deadline by a few hours, when they were willing, the next morning, when the bank opened, to send more than ten million in a security deposit to the grid operator.”

Chang concerned about ‘local’ transmission. Pointing to a settlement agreement with Public Service Electric and Gas that FERC approved earlier this month, FERC Commissioner Judy Chang said “this case highlights and I've been informed by many state regulators, including my dear colleague [Commissioner Mark Christie,] that many transmission projects are built with little or no transparency and oversight.”

Chang said she has been hearing concerns about local transmission projects from many different regions. “I am interested in hearing from stakeholders and others on ways that the commission can ensure transmission investments are cost effective and have adequate oversight, including enhanced transparency requirements,” Chang said. “This is really important going forward.”

A coalition of ratepayer advocates and groups representing large energy users on Thursday filed a complaint at FERC seeking to bar transmission owners from independently planning local transmission projects above 100-kV. 

FERC approves Allete and Algonquin Power sales. FERC dismissed concerns raised by consumer advocates and others and approved a $6.2 billion deal under which Allete, a utility company based in Duluth, Minnesota, will be sold to the Canada Pension Plan Investment Board and Global Infrastructure Partners, which is owned by BlackRock. Allete expects to close on the deal in mid-2025, subject to approval by Minnesota and Wisconsin utility regulators.

FERC also approved LS Power’s up to $2.5 billion purchase of Algonquin Power, which owns about 3,000 MW of wind and solar assets — mainly in the United States — as well as an 8,000 MW pipeline of wind, solar, battery energy storage and renewable natural gas projects.

RENEW Northeast wins ISO-NE cost complaint. In response to a complaint brought two years ago by renewable energy advocacy group RENEW Northeast, FERC on Thursday said it was unjust for New England transmission owners to require interconnection customers to pay for operating and maintenance costs for network upgrades. RENEW offered evidence its members’ projects face significant network upgrade O&M costs that were not directly attributable to the projects, FERC said.

Also, FERC agreed with RENEW that ISO-NE’s definition of “interested party” was too narrow because it deprived the group access to information related to the region’s formula rates. FERC directed New England transmission owners to revise the definition of interested party in their formula rate protocols to include but not be limited to customers under the tariff, state utility regulatory commissions, consumer advocacy agencies and state attorneys general.

The Midcontinent Independent System Operator and the Tennessee Valley Authority will be able to sell “emergency energy” to each other under a first-ever agreement filed Oct. 24 at the Federal Energy Regulatory Commission.

The TVA is not able to supply emergency energy directly to MISO due to restrictions in the TVA Act that limit exports only to neighboring electric systems that the federal agency had exchange power arrangements with as of July 1957, according to MISO’s filing. 

As a result, under the agreement, Ameren and Entergy — MISO members that meet the requirements of the TVA Act — will be able to buy electricity from the TVA during energy emergencies on behalf of MISO.

“Due to the changing configuration of the grid and recent emergency events, like Winter Storm Elliott, MISO and TVA have become increasingly focused on the need for additional coordination and planning to better ensure reliability in an emergency,” MISO said. “To that end, each has identified the need to purchase Emergency Energy from the other to maintain the reliability of each individual transmission system and, more generally, the integrity of the Eastern Interconnection.”

During Winter Storm Elliott in December 2022, about 7,000 MW flowed from MISO into the TVA’s region, according to a presentation by FERC and the North American Electric Reliability Corp. The TVA instituted nearly eight hours of rolling blackouts totaling 3,000 MW at their peak during the winter storm.

Under the agreement, emergency energy can only be requested when an Energy Emergency Alert Level 2 or higher has been declared, MISO said. The proposed agreement is similar to ones MISO has with other balancing authorities, the grid operator said.

“Emergency Energy is typically only called on in the most extreme cases when reliability is threatened and there are few options remaining,” MISO said. “Both MISO and TVA anticipate that there may be situations in the future that will meet this criteria and having the ability to purchase Emergency Energy from each other may be the key to enhanced grid stability and avoiding load shed.”

MISO asked FERC to allow the agreement to take effect on Dec. 24.

Almost two years after Winter Storm Elliott forced the largest recorded manual load shed in the history of the Eastern interconnection, the North American Electric Reliability Corp. says it “remains concerned about maintaining sufficient natural gas supplies to address extreme winter conditions.”

NERC’s statement on the “criticality of natural gas supply this winter” follows other warnings the reliability watchdog has issued regarding the need for greater coordination between the gas and electric sectors. Grid operators and gas producers this week said they are heeding those warnings and are working to weatherize their systems and improve market mechanisms to keep energy flowing.

Temperatures were up to 30 degrees below normal during the December 2022 storm, driving electricity demand higher and causing grid operators to declare emergency operations. Unplanned outages reached 90,500 MW, and transmission operators in the Southeast ordered firm load shedding that exceeded 5,400 MW, NERC, the Federal Energy Regulatory Commission and grid operators concluded in a joint assessment of the event published a year ago.

Elliott marked the fifth event in the last 13 years where gas supply disruptions played a role in cold weather-related generation outages that jeopardized bulk power system reliability, NERC said. And heading into this winter, some weather forecasts are calling for a colder-than-average December across much of the U.S. northern tier.

Elliott was “by no means an isolated example of the link between natural gas supply and electric reliability,” NERC said.

“As the electric system increasingly relies on natural gas, more gas infrastructure, including pipelines and storage, is needed to enhance deliverability,” NERC said. Supply disruption “was a central cause of generator failures that led to load shedding,” with cold temperatures resulting in declines in gas wellhead production and other system impacts.

The joint report on Winter Storm Elliott concluded that gas fuel supply issues accounted for 20% of unplanned generating unit outages, derates, and failures to start. Not all of those outages resulted from physical issues, however. The report also pointed to problems with scarcity pricing, mismatches between the timing of the gas and electricity markets, and pipeline scheduling constraints.

Since Elliott, gas operators have been working to weatherize pipelines, wellheads and other infrastructure. And grid operators say they are adjusting their planning processes and protecting their systems against extreme weather.

The Natural Gas Supply Association, representing gas producers and marketers, in a Sept. 4 fact sheet, said its members are taking a “multitude of proactive measures” to prepare for the winter, including “stringent self-inspections prior to anticipated weather conditions,” assisting customers in finding alternative market options, and mitigating weather exposure with “additional supplies and enhanced protections.”

“We operate winter continuity programs that help protect upstream facilities and field personnel during winter events, improving our ability to maintain operations during extreme conditions,” NGSA said.

Grid operators focus on weatherization, market mechanisms

The Midcontinent ISO “is currently conducting the annual winter readiness surveying cycle,” Brandon Morris, a spokesperson for the grid operator, said in an email. MISO’s territory covers 15 central U.S. states and the Canadian province of Manitoba.

“We are focused on sending the right market signals to highlight the value of resource availability and incentivize generation owners to have firm access to fuel, especially during tight operating conditions,” Morris said.

MISO faces a possible capacity shortfall in some regions beginning next summer, according to an annual report published in June.

The grid operator has recently implemented a “seasonal construct” for its annual planning resource auction to consider how much different resources bolster grid reliability during stressed periods, Morris said. “MISO will continue working with regulators, our member utilities, fellow grid operators and the natural gas industry to improve coordination with a focus on maintaining reliability,” he added.

New England uses natural gas to generate about half of the region’s electricity, “so we’re always focused on what’s happening on the gas system,” Matt Kakley, spokesperson for ISO New England, said in an email. “This is particularly true during the winter months, when supplies may be tighter due to heating needs.”

ISO New England, along with MISO, PJM Interconnection and the Southwest Power Pool, in February published a white paper on paths to improving the reliability of gas-electric coordination across their territories, including weatherization, permitting reforms and incentivizing firm gas transportation and storage for generators.

“There are significant differences in the level of scheduling flexibility available to generators to respond to [regional transmission organization] dispatch instructions, particularly during constrained system conditions,” the paper noted. The RTOs added that they “recognize that the degree of pipeline scheduling flexibility is heavily influenced by the degree of storage available on the system and the extent to which the pipeline is fully subscribed during peak conditions.”

The New England grid operator is conducting an analysis of the upcoming winter, “but [we] are not anticipating any levels of concern greater than recent years,” Kakley said. “We agree with NERC’s sentiment that close coordination between the gas and electric sectors is vital to reliable operations.”

The Electric Reliability Council of Texas is conducting weatherization inspections of generating and transmission facilities, “being more transparent in grid operations, and continuing ERCOT’s conservative approach to operations,” the grid operator said in a statement.

Since 2021, ERCOT has taken a “reliability-first approach to grid operations, bringing generating resources online early to mitigate sudden changes in generation or demand,” it said in a statement. “ERCOT will continue to use all operational tools available, including implementation of programs, as well as executing legislative reforms (like summer and winter weatherization inspections).”