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May 5, 2025

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FERC Approves $180M Annually for RMR Deals with Brandon Shores and Wagner Plants

FERC issued an order approving settlements on reliability must run (RMR) deals that will keep the Brandon Shores Generating Station and the H.A. Wagner Generating Station in Maryland running until May 31, 2029 (ER24-1787 and ER24-1790).

Talen Energy owns both plants, which are located near Baltimore and had sought to retire this year. But PJM found that would have led to reliability issues. Brandon Shores is a 1,289-MW coal plant, and Wagner is an 843-MW oil-fired unit. Now they will run until transmission improvements are ready to replace them reliably.

Brandon Shores is getting $145 million a year and Wagner $35 million, which includes fixed-cost charges, a monthly investment tracker payment to recover spending that’s needed to keep the plants running and a reimbursement mechanism to cover operations and maintenance costs.

Talen entered into settlements with Exelon, PJM, the Maryland PSC, the Southern Maryland Electric Cooperative and the Old Dominion Electric Cooperative on the RMR deals, which cut its initial annual cost from $175 million for Brandon Shores and $40 million for Wagner. Talen will credit market revenues the plants earn back to customers, and it agreed to limits on investments in the plants, which require PJM approval.

PJM said the settlements represent a significant achievement of consensus on issues between Talen and a broad coalition of load parties that will pay for the RMR deals.

The deal was opposed by PJM’s Independent Market Monitor and the Maryland Office of People’s Counsel, who took issue with how the plants determined their sunk costs. Talen was spun off from PPL in 2015, and at that point Brandon Shores was appraised at $648 million. But in 2012, the firm bought both plants for just $372.5 million. The people’s counsel argued that using the higher number amounted to a windfall for Talen.

FERC trial staff countered that the sunk costs are within the just and reasonable range and will be offset by capacity revenues being credited back to customers. And costs would be greater if outages occurred in the area because the plants were retired too soon.

“Under this approach, the commission need not find that the rate is exactly the rate the commission would establish on the merits after litigation,” the order said. “The commission need only find that the overall package, resulting from the give and take of the bargaining which led to the settlement, falls within a broad ambit of various rates which may be just and reasonable.”

Precedent gives the commission a few legal rationales for approving settlements. The one it picked focuses on the end result of the deal and involves a balancing of the benefits with costs and the potential effect of continued litigation.

The deals provide a high degree of certainty to market participants that the units will be available, including a longer RMR (five months more than initially proposed) and fewer circumstances under which Wagner and Brandon Shores can terminate operations. It also gives PJM flexibility to end the RMR deals early if market conditions change.

“This certainty provides value to the settlements, especially in light of the serious reliability concerns at stake without the settlements that could lead to much greater costs overall,” FERC said.

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NYISO Details Proposed Metrics for IDing Poor Performers in Reserve Market

NYISO has proposed the metrics for identifying operating reserve suppliers that consistently underperform as part of its plan to remove them from the market. 

The ISO first presented the proposal in January, but it had not yet specified the thresholds for determining whether a supplier was underperforming. (See NYISO Explains How It Would Put Poorly Performing Resources in Time-out.) 

One metric is aimed at frequently called poor performers and examines how they performed during Reserve Pick-up (RPU) events — defined as when the area control error exceeds 100 MW — and audits. 

The other targets those that are qualified to provide reserves but are rarely called to do so and examines their performance when dispatched in the energy market. “We’re looking at their energy dispatch in the cases where they weren’t picked up for an RPU but are still a provider,” NYISO Associate Engineer Andy Bean told the Installed Capacity Working Group on April 24. 

Bean explained that the first metric would be a snapshot of the last three months of RPU performance data. The ISO would divide the difference of the expected basepoint and energy provided by the total sum of the expected basepoints for the three months. Generators that fall below 70% of their expected performance would be subject to a rebuttable presumption of removal from the market. 

The metric would be applied any time a resource eligible to provide 10-minute operating reserves is dispatched during an RPU event and during manual audits of eligible resources. 

The energy performance metric is structured similarly, but instead of comparing an expected basepoint to energy provided, it uses the same formula to compare energy requested to energy provided over the past three months. Bean said this metric would be assessed any time a resource in the operating reserves market is scheduled, but not when it is providing regulation. If energy performance falls below 50%, it would be subject to a rebuttable presumption of removal. 

Resources that fail to meet these thresholds would be eligible for removal from the market for at least 30 days. 

Richard Bratton, representing the Independent Power Producers of New York, asked how the ISO had come up with the thresholds. 

Bean said NYISO staff had looked at historical data, and those percentages were where they saw “natural breaks” and the worst-performing units separating out. These units, Bean said, were also aligned with what the Market Monitoring Unit identified as the worst performers. 

The ISO found that in 2024, roughly 550 MW of operating reserve suppliers would have failed one or both of the metrics and would have been subject to the threat of removal from the market. If all of them had been removed for three months, this would mean that operating reserves would be down 100 MW each month in 2024. 

Bean presented a slide showing historical audit data, demonstrating that between the 2022 and 2024 capability years, there were about 80 audits stemming from RPU issues. 

Resources may rebut the metrics by showing that the data are incorrect, they were in an outage or their basepoints are inconsistent with what they can provide. Extreme circumstances outside of operator control would also rebut the ISO’s presumption that the resource was performing poorly. 

If the resource is unable to rebut, they would be removed from the operating reserves market for 30 days in the first instance and 90 days in subsequent instances. The ISO would retest resources to allow them back on the market. 

Mark Younger of Hudson Energy Economics, representing generators, asked whether there would be a mechanism for permanently removing a resource from the operating reserves market. Bean said that was currently not part of the proposal. 

Bean said NYISO would consider stakeholder feedback before finalizing the metrics, mentioning several times that he had “starred” comments and questions in his notes over the course of the meeting. 

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IPF25 Attendees Plan Future OSW Resurgence

VIRGINIA BEACH, Va. — Bruised by President Trump’s aggressive efforts to shut down offshore wind projects, developers and industry advocates are strategizing on how to reset the industry and position it to re-emerge in two to four years. 

Speakers and attendees at the International Partnering Forum (IPF) 2025 Conference, while shocked at the pace and ferocity of Trump’s opposition, said they’re optimistic the rapidly rising demand for energy means the federal government eventually will have to harness wind power to meet the nation’s needs. 

Key on their minds was Trump’s announcement upon taking office that the nation is facing an energy emergency, then soon after taking steps to shut down offshore wind projects. He issued a memorandum essentially freezing projects in the permitting process and has stopped New York’s Empire Wind mid-construction. He also stalled New Jersey’s Atlantic Shores project, asking for new information even though the project received its final approval in October. (See Feds Move to Halt Construction of Empire Wind 1 and EPA Puts Hold on Atlantic Shores OSW Permit.) 

Developers such as Equinor, Ørsted and Vestas have given grim assessments of the U.S. market. (See Equinor, Ørsted, Vestas Say US OSW Market in Trouble.) Speakers at the IPF conference sought to portray the situation variously as a “pause,” a “reset” or a moment when the industry could use the forced downtime to plan for the future. 

“Our job, all of our jobs, is to keep pushing so that regulators, citizens and politicians will realize that offshore wind, it’s not optional — we have to have it,” Oceantic Network CEO Liz Burdock said April 29, opening the conference’s second day. 

“We’re not just here to trade business cards,” she said. “We’re here to unlock the full force of our collective creativity, to rethink, redesign and reignite the U.S. offshore wind industry.” 

“But in our fight, we must adapt and adapt fast, while we grapple with indecision, economic uncertainty and political turbulence,” she said. “Our opponents are loud and they’re organized and they’re holding elected leaders accountable to their demands. It’s time we respond with strength on strength. No more passive storytelling, no more silence while the narrative is shaped by others. We must amplify the truth.” 

Sam Eaton, president and CEO, RWE US Offshore Wind | © RTO Insider

Sam Eaton, CEO of RWE’s U.S. Offshore Wind operation, said in an interview with Burdock that a “reset” period will enable it to sharpen its purpose and address its core issues. 

“It’s important that we don’t lose sight of the success that we’ve had here in the U.S.,” Eaton said. “But now we face a question as to where the next evolution of offshore wind is going to be, and we need to think about this fundamental question: Are we developing a technology that will serve an important niche, or are we developing a technology will scale to an American mainstream?” 

States’ Initiative

Before Trump moved against the OSW sector, President Biden issued leases for 60 GW of power, said Sam Salustro, senior vice president of market and policy strategy at Oceantic Network, adding that “state demand exceeds about 115 (GW) at this point.” The U.S. has one commercial-scale project operating, South Fork in New York, and projects totaling about 19 GW of power have full federal approval and are heading toward completion. 

Among them is Dominion Energy’s 2.6-GW project Coastal Virginia Offshore Wind (CVOW), which has two pilot turbines in operation about 27 miles off the Virginia shore. With 176 turbines, the project is designed to power 600,000 homes. Construction is expected to be completed in 2026. 

In Massachusetts, Vineyard Wind is producing about 50 MW of energy. Construction is scheduled to be completed in 2025 on the full 800-MW output, Elizabeth Mahony, commissioner for the Massachusetts Department of Energy Resources, said at the conference. 

“We’re actively engaged right now with our legislature, with our governor and with the industry to make sure that despite what might happen in D.C., that Massachusetts will continue to be a place for the industry to come this year and next year, or for the next 10 years,” Mahony said. 

Elizabeth Mahony, commissioner, Massachusetts Department of Energy Resources | © RTO Insider 

Several speakers said that given the federal government’s position, states need to take a larger role to push the sector forward. “They are the market movers, and they have continued to act over the last few months,” Salustro said. 

Another key factor is collaboration, said Megan Outten, policy manager for the Maryland Energy Administration. 

“That goes down to supply chain, knowing how we can support some of our neighboring states, in Delaware, Virginia, New Jersey, and where we can fit in,” she said. “Not every state is going to be their own regional hub for supply chain. We’re going to have specialists in each state,” some for the supply chain, and others for transmission issues, she said. 

The potential benefits of collaboration were underscored by the release on the conference opening day of a strategic action plan by the Northeast States Collaborative on Interregional Transmission, which comprises nine states: Connecticut, Delaware, Maine, Maryland, Massachusetts, New Jersey, New York, Rhode Island and Vermont. The collaborative was formed to explore “opportunities for increased interconnectivity” between ISO-NE, NYISO and PJM. The latest plan outlines an interstate planning process for transmission projects. (See Plan Lays out Steps for State-led Interregional Transmission in Northeast.) 

Part of the plan ensures there are consistent standards — such as for technology — used in procurement through the collaborative members, said Bruce Ho, senior policy adviser of the Connecticut Department of Energy and Environmental Protection. 

That could “give confidence to the manufacturers that this is where not just one state is going, but where a whole group of states are going,” he said, adding this approach could lower costs. 

Ready to Fight

Georges Sassine, vice president of large-scale renewables at the New York State Energy Research and Development Authority (NYSERDA), said stakeholders need to understand how this situation is different from the past, when projects became mired in supply chain problems, cost inflation and the legacy of unsustainably low bids. 

“Before, it was a crisis. How do you lead in a crisis?” he said. “Today, our collective leadership challenge is how to lead in a time of uncertainty. And that that requires a completely different reaction.” 

Part of that leadership, he said, can be seen in New York Gov. Kathy Hochul’s commitment to vigorously oppose the stop work order issued to halt Empire Wind, and also to keep pursuing wind and transmission projects, and even solicitations. 

Georges Sassine, NYSERDA | © RTO Insider 

“We really have to fight, and we would like to partner with you, the stakeholders, to join us in that fight,” he said. 

“Our goal here is to figure out how do we protect the projects under construction and make sure that they get built?” he said. “The second goal is, how do we make sure that the industry across the board keeps on investing over the next four years, and keeps on building, and then how do we position ourselves to pick back up exponentially, when the industry wants it, whether it’s in the short term or the long term?” 

For all stakeholders, a key element of the pushback, he said, will be “telling the story, a cohesive story, around the value of offshore wind and offshore energy.” 

Derisking Projects

Several speakers said stakeholders need to position wind sources to become routinely accepted as one of the “all-of-the-above” categories of power considered in the public debate.  

Analysts predict a rapid rise in demand from data centers, which consume vast amounts of power, and from electric vehicles and appliances. The closure of fossil-fuel generators across the region highlights the need for more generation. 

“A lot of studies have been coming out over the past couple months that have pointed to the same thing,” Salustro said. “Some estimates are 50% (demand increase) over the next 10 years. Some of it is double over the next 20 or 25 years. Offshore wind is going to be a key part of helping solve this problem of the need for more energy and getting it online fast and soon. Offshore wind is the shovel-ready industry right now. We have projects that are permitted, ready to go.”  

Mark Mitchell, Dominion Energy | © RTO Insider

With that in mind, Mark Mitchell, senior vice president for project construction for Dominion, said at the conference that his company has drafted a plan to provide energy to 3 million Virginia homes through an “all-of-the-above energy approach” using OSW, solar, battery power, natural gas generation and small nuclear reactors. 

“Having a variety of generation sources helps maintain reliability by avoiding over-reliance on any given power source,” he said. “It also helps maintain affordability by insulating our customers and the company against outsize price shocks for a particular fuel source or generation component.”  

Still, he added, “renewables are a key element of our strategy,” and the CVOW project is “expected to save customers $3 million of fuel cost over the next 10 years.” 

A representative of Ørsted, which closed two New Jersey projects — Ocean Wind 1 and 2 — in 2023 due in part to rising costs and supply chain issues, offered a more cautious assessment when asked in one forum what trends could affect future projects. 

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Massachusetts Lawmakers Focusing on Energy Affordability in 2025

In the wake of skyrocketing energy costs over the past winter and the loss of federal support for state clean energy initiatives, Massachusetts policymakers are facing difficult questions about balancing decarbonization with energy affordability in the state’s 2025/26 legislative session.

Lawmakers have passed major climate and energy bills in each of Massachusetts’ past three sessions. Most recently the House and Senate agreed to compromise legislation after the conclusion of formal sessions in 2024, overhauling clean energy permitting and siting, updating utility regulations to enable gas pipe decommissioning and authorizing a sizeable procurement of energy storage resources. (See Mass. Clean Energy Permitting, Gas Reform Bill Back on Track and Compromise Climate Bill Finally Approved by Mass. Legislature.)

The two prior bills, passed in 2021 and 2022, included sector specific decarbonization targets, a new opt-in municipal building code, authorization for offshore wind procurements, electric vehicle rebates and EV sales mandates.

Sen. Mike Barrett (D), co-chair of the Legislature’s Joint Committee on Telecommunications, Utilities and Energy (TUE), told RTO Insider his “first priority is to make sure Massachusetts emerges from the Trump years with its climate capacity intact.”

“We are basically trying to change over an entire economy,” Barrett said. He added the state should avoid “unintentionally paralleling federal cutbacks with cutbacks of our own. We can’t compensate literally for the missing federal dollars, but we want to sustain a very serious state effort, rather than throw up our hands.”

If the Trump administration prevents additional offshore wind procurements, Massachusetts should consider focusing its efforts on rooftop solar, which does not rely on federal approvals, Barrett said. He added the state’s decarbonization strategy is meant to be flexible, and the state could amend its clean energy procurement laws to readjust its strategy.

Barrett also emphasized the importance of maintaining sources of work for the state’s clean energy workforce throughout President Donald Trump’s second term, and that pivoting toward distributed energy resources could help provide these opportunities.

“You might concede that Trump can slow you down, but you don’t want to give him the opportunity to destroy the effort altogether,” Barrett said.

Rising Energy Costs

The winter of 2024/25 was the first since 2014 to feature sustained below-normal temperatures, driving a significant increase in natural gas prices and demand. On Feb. 1, gas supply rates increased 16% to 22% for customers of the state’s investor-owned gas utilities. The supply rate increase coincided with increased delivery fees, which were caused in part by adjustments to the Mass Save efficiency program and continued investments to repair and replace leaky pipes.

High residential energy costs caused significant public pressure on state officials to provide ratepayer relief, and the Department of Public Utilities (DPU) required temporary reductions in delivery fees and ordered $500 million in cuts from the 2025/27 plan for Mass Save “to protect ratepayers from excessive bill impacts.” The Mass Save cuts drew some criticism from clean energy advocates, who argued the move would hurt ratepayers in the long run.

Meanwhile, Gov. Maura Healey (D) announced in March an “energy affordability agenda,” returning to ratepayers $125 million in funds collected from alternative compliance payments for state clean electricity standards. Healey also committed to filing “an energy affordability and independence bill to explore new ways we can make Massachusetts more affordable.”

Residential Competitive Supply Ban

Heightened attention on energy costs may boost efforts to ban competitive residential electricity suppliers, a proposal that fell short in the negotiations for the 2024 compromise bill. Healey, the Office of the Attorney General (AGO), the city of Boston and top senators all expressed support for a ban during the session, but the proposal ultimately was derailed by opposition in the House.

Competitive suppliers in the state currently are allowed to market directly to ratepayers, and the state has struggled to prevent predatory suppliers from locking customers into deceptive and expensive supply contracts. Supporters of the industry have argued that predatory practices can be addressed through reforms, while critics have argued that a ban is the best way to protect consumers.

“I don’t think any of us are backing off on the determination to bar competitive suppliers from selling to low-income households door to door,” Barrett said.

A 2024 report by the AGO estimated that residential customers of competitive electricity suppliers paid over $577 million more than basic utility service customers over an eight-year period. The report also found that “low-income consumers and people of color continue to suffer a disproportionate amount of the consumer harm.”

Larry Chretien, executive director of the Green Energy Consumers Alliance, said a ban is “is likely the easiest thing to do to make energy more affordable, because it doesn’t require taking money from one account … it doesn’t require tax dollars, and it doesn’t require raising one person’s rate to lower another person’s rate.”

“We’re going to hope that the House takes an open-minded view of this,” Chretien added.

Utility Reforms

While lawmakers and advocates are quick to support the idea of energy affordability, in practice, the concept can motivate widely ranging policies with varying effects on decarbonization efforts.

Kyle Murray, director of state program implementation at the Acadia Center, said he would like to see the energy affordability bill include limits on utilities’ return on equity (ROE), potentially restricting ROE to an average of the surrounding Northeast states.

“Our position has long been that utility return on equity is really inflated and could serve to come down a few points,” Murray said, while also acknowledging that passing ROE reforms would be challenging due to the complexity of utility ratemaking and likely opposition from investor-owned utilities.

Murray also said he hopes lawmakers will consider changing the funding mechanism for some programs currently funded through volumetric charges in electricity and gas rates. He said funding programs like low-income discounts, Mass Save and renewable energy charges through fixed bill charges or through the tax base could save most ratepayers money.

He also expressed interest in legislation limiting the expansion of the state’s gas network, a priority shared by Mass Power Forward, a large coalition of climate and environmental justice groups.

One of the main bills backed by the coalition would prohibit the state Energy Facilities Siting Board from approving new fossil infrastructure within five miles of state-designated environmental justice communities. The group also is pushing for legislation to prevent utilities from using ratepayer funds to cover the costs of industry associations, lobbying activities and promotional advertising.

Mass Power Forward coordinator Claire-Karl Müller said lawmakers should address utility incentives that encourage expansion of the gas network and undermine Massachusetts’ decarbonization mandates and long-term strategy to reduce gas reliance. (See Massachusetts Moves to Limit New Gas Infrastructure.)

“If you’re in a hole, stop digging,” Müller said. “We have to stop expanding the gas system immediately.”

The coalition’s other priorities include a proposal to make fossil fuel companies pay for the costs of climate resilience through a “climate change superfund,” as well as new outdoor and indoor air pollution protections for vulnerable communities.

Looking Forward

The state is in the early stages of its 2025/26 legislative session, which will conclude at the end of July 2026. Lawmakers already have submitted nearly 250 bills to the TUE committee, which has yet to begin bill hearings.

The House TUE co-chair, Rep. Mark Cusack (D), is new to the committee this year, and it remains to be seen whether his priorities will differ from Rep. Jeff Roy (D), who served as the House co-chair from 2021 through 2024. Roy was not reappointed to the committee after the Boston Globe reported he had a romantic relationship with a lobbyist working for clients regulated by the committee, including a third-party electricity supplier.

While no longer serving on the TUE committee, Roy has been appointed to House leadership by speaker Ron Mariano (D) and could remain an influential voice in the House on energy issues. Both Cusack and Roy did not respond to comment requests for this article.

Meanwhile, the Healey administration is expected to file energy affordability legislation in the near future, which should help define the scope of the Legislature’s discussions and negotiations on climate and energy issues.

A spokesperson for the Massachusetts Executive Office of Energy & Environmental Affairs said Healey soon will “file an energy affordability and independence bill to explore new ways we can make Massachusetts more affordable,” adding that the administration “will use every tool we have to help make sure families and businesses can afford to heat their homes and keep the lights on.”

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Outgoing E-ISAC CEO Manny Cancel Reflects on Security Challenges

Since 2020, Manny Cancel has led the Electricity Information Sharing and Analysis Center through diverse challenges including the COVID-19 pandemic, the Russo-Ukraine war and intrusions into U.S. critical infrastructure by multiple state-backed actors, such as Volt Typhoon. He sat down with ERO Insider’s Holden Mann to discuss the state of the security environment and the challenges faced by incoming E-ISAC CEO Michael Ball. The following exchange has been edited for clarity. 

ERO Insider: As you manage the leadership transition at the E-ISAC, what are some of the biggest cyber and physical security challenges facing electric utilities today, and how are you and your partners positioning for those challenges? 

Manny Cancel: The environment continues to remain incredibly complex and really requires us to be constantly vigilant and responding. The threats continue to evolve, and the adversaries continue to take advantage of tried and true plus new techniques, and gaps in cybersecurity and physical security programs that our members have. 

Complicating the matter is the supply chain. We are all reliant on each other, all the critical infrastructure sectors. We rely on many of the same products — the software that runs our businesses and the hardware and software that is used to protect our environments. You know, all these do a great job, and there have been some tremendous advances in technology. When I think of what we had in place when I first got started in this industry, it’s amazing to see what’s been accomplished.  

At the same time, I think we all agree that these products could be more secure. They weren’t necessarily designed, and still probably are not designed, with the appropriate levels of security that help to eliminate or mitigate nation-state attacks, or attacks from very serious adversaries. 

But in general, I feel really good about where the industry is. We didn’t just wake up to this issue. I’m really proud of this sector for its ability not only to monitor, but to evolve and transform and take the necessary actions and collaborate. Unlike other sectors, we do a great deal of collaboration and working with each other to share information and threat intelligence. The E-ISAC and NERC are a big part of that, but the industry really supports that too. And the leadership of the industry, all the way up to the CEOs, sets the tone there, and I think that goes a long way to putting us in a good position. It doesn’t necessarily mean that we defeated our adversaries, but we put up an incredible defense. And we take this role very seriously. 

Q: The electric grid was a target for cybercriminals before you joined the E-ISAC, but today we are seeing a growing threat from sophisticated nation-state actors like China, Russia and Iran. What can the E-ISAC and its partners do to address these concerns?  

A: There has been significant evolution. For one example, the exponential increase in interconnected devices is just mind-blowing. When you think about all the smart assets, whether they are distribution, transmission, consumer assets that plug into and need electricity — all of that sort of stuff has just expanded that attack vector. 

So, the adversaries have more things to test to see if they’re vulnerable. The big change is that we’ve always had components of our infrastructure that were vulnerable to security issues. But it used to be much more individual, meaning they would target one or two products. What the bad guys have figured out is the one-to-many problem. They don’t have to attack each one of us. They can just attack a product that we all use — your iPhone, an enterprise software product, an enterprise control product. And if they figure out a way to get into that, and figure out the vulnerabilities, they can really take advantage. 

You’re seeing this play out in attacks like the Volt Typhoon actors from China, who are incredibly stealthy, incredibly persistent and patient. They go across the spectrum of products and look for those vulnerabilities and then lay in wait to think about how they can use this. The concern is it’s not just for espionage. It is probably for taking control when they deem appropriate. Both the Director of National Intelligence in the United States and the Canadian Centre for Cyber Security, in their worldwide threat assessments, always conclude that the major nation-state actors possess the capability to disrupt critical infrastructure. So that’s something that we don’t question; we take it very seriously, and it’s part and parcel to our mission. 

We’ve got to develop much more tolerant and resistant software. And if we don’t, we’re not only exposed to these vulnerabilities, but we also lose the race on other technology shifts — crypto, AI, the development of data centers, the further adoption of the cloud. There are so many great things that these technologies bring to society, but if they’re fraught with risk, the adoption of them is going to be challenged. So we have to figure out a way to incent these manufacturers to do this. They are rewarded for selling products, providing capabilities. That’s what makes the stock price go up, not so much that they’re secure. We have to reward security and do everything we can to put it in there. 

Q: What role do you see specifically for the E-ISAC in pushing those security incentives? 

A: It’s through our members, through the trade associations, and in our consultations with organizations like FERC and with legislative leaders in both the local, state, provincial and federal governments in the U.S. and Canada. Making sure they’re aware of these issues and thinking about how we move this forward.  

I think one of the things that I’m proud that the E-ISAC has done is, we started our vendor affiliate program about two and a half years ago. It’s a pay-to-play program, not a revenue generation program — we don’t make boatloads of money on it. The biggest benefit that we get out of it is the collaboration with the technology community, who can advise us on security issues, and we can work together. I think forums like that really help, and they exist in other critical infrastructure sectors as well.  

When you see what’s going on with the Typhoon threat actors, and their targeting of the telecommunication industry here in the United States, I’m really proud of the industry for sharing information about those attacks. They didn’t have to do that, but they recognize their role in the critical infrastructure pipeline. Stuff like that has to continue to happen.  

The governments in both the United States and Canada also have tried some outreach. The Department of Energy has programs with the National Labs to work with vendors on cyber-informed engineering. Secure by design — former Cybersecurity and Infrastructure Security Agency Director Jen Easterly put that together during her tenure at the Department of Homeland Security. Those are really great programs, but they have to continue. We have to build upon them and make them more effective. 

Q: On the physical security side, we continue to see reports of violence against substations across the grid. What sort of drivers has the E-ISAC seen for this behavior and what kind of measures might be needed to address it? 

A: There are a variety of motivations — political, environmental, criminal. I think current economic conditions are lending more credence to the criminal side. The price of copper has reached all-time highs, so we’re seeing an increase in the theft of copper. Not to the extent that it’s compromising the grid, but as economic conditions deteriorate, you will see theft as a motivation. 

On the more grid impacting side, those incidents generally have plateaued at about 3% of the total physical security events. That’s still troubling. There are a couple of opportunities for improvement there. One is, we have to continue to do as much as possible to protect these facilities. That doesn’t necessarily mean fences and cameras, or more standards. It probably means making the grid even more fault-tolerant.  

The grid is incredibly tolerant as it is; it has multiple levels of contingencies. But do we need more? Do we need to treat assets differently, even those we might consider low-risk? You can bunch together several low-risk assets — if you look at the plot in Baltimore, to disrupt several substations for what basically was an ideological motivation. (See Neo-Nazi Convicted in Baltimore Grid Attack Conspiracy.) They knew what they were going after, and they were not all big, bulk power stations. Fortunately, that plot was foiled, but that could have been a lot worse.  

One more thing I’d say — we hear a lot about the attacks, but what we don’t hear about is apprehension and the results. There’s not been an arrest made in the Moore County attacks; there are no arrests in the Metcalf incident. That’s not to criticize the folks that are trying to do this, it’s just amazing in this day and age that we’re not able to figure that out. I think we need to show people that, look, if you want to be stupid and do those things, here’s the price you’re going to pay. The headline is not just the damage, the headline is also, hey, we got these guys.  

Q: How did the challenges of the moment affect the choice of Michael Ball to succeed you? What skills did he bring to the table that NERC and the E-ISAC thought would be useful in the current environment? 

A: I couldn’t be more assured and happy to hand the reins over to Michael. He is eminently qualified for this position. I’ve known him for over 10 years, back to when I was at Con Edison. He knows us; he knows NERC, he knows the E-ISAC, he knows the industry. 

I think what’s especially compelling about Michael’s CV is his tenure at Berkshire Hathaway. He’s been the CISO there, not only advising the company’s energy portfolio but also the insurance portfolio, the real estate portfolio, the logistics, rail, air and finance portfolios. He’s been exposed to other critical infrastructure sectors, which I think gives him a real unique perspective on the threat landscape. 

On top of all that, he’s a good, reasonable guy, a great leader, a consensus builder. Somebody who will continue to, not just execute our mission, but do what we do even better. I’m very confident and I look forward to seeing that. 

Q: We’re also in the middle of a presidential transition, with several key agencies, including CISA, still lacking confirmed heads. How does that affect the work of the E-ISAC and your partners?  

A: Most presidential transitions do take some time. It’s not unusual for things to still be shaking out. I’m confident we will have colleagues in the U.S. and Canadian governments. I think our missions are very aligned. When you look at what this administration is trying to accomplish from an energy policy perspective, there are a lot of things that we can support and we look forward to doing that. 

It’s important to know that while we are in transition, we still are working with the government. We still are working with folks at CISA, at DOE and at FERC. That continues and has not been interrupted. So I’m sure we’ll learn more, particularly as folks are confirmed. I’m hopeful that we’ll continue to make progress. Certainly, energy is important to all of us, and that has been said clearly by this administration. 

You can’t depend on the federal government to fix everything, and likewise, you can’t depend on the private sector to fix everything. It is a collaboration. But where is the right delineation of responsibilities? How do we share actionable intelligence, and what do we do about it? I think there’s always an opportunity to think about how we enhance current programs, pivot to other programs, or leverage the private technology sector as they develop their things. 

Q: What kind of hopeful signs do you see for the E-ISAC and the rest of the sector, and what developments are you looking forward to seeing play out? 

A: We’ve seen a huge increase in the E-ISAC membership. When I joined, there were about 900 members. We are at almost 1,900 members now in five years. And when you look at the number of utilities in the United States and Canada, it’s over a 50% saturation rate. That’s one measure of the E-ISAC’s success I feel good about, but I think we can do more. I feel really good about our collaboration with the other critical infrastructure sectors. The Critical Infrastructure ISACs meet once a month to share intelligence and information about their programs, legislative challenges and other things. I think that collaboration couldn’t be better. 

I look forward to seeing what happens with things like secure by design, and how we think about how to deploy things in a more secure and resilient fashion. One of the hallmarks of our industry is mutual assistance; we use it typically for storm restoration. But a lot of people don’t know that we also have cyber mutual assistance, where utilities can request help on a cyber issue. It’s not widely used, thankfully; we haven’t had to. But it’s good to have that in place in case that rainy day comes. 

I like where we are, but I’m not declaring victory. We’ve got to keep our foot on the pedal and our hands on the steering wheel. 

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Demand Growth and Carbon Targets Prompt New Interest in Nuclear

Past talk about a nuclear renaissance has mostly produced aborted projects. But with demand growing and some in the industry still focused on climate change, utilities again are considering the resource for their long-term plans.

After the Fukushima accident in Japan — and the advent of cheap shale gas — the only two nuclear projects to move forward were the Tennessee Valley Authority’s Watts Bar Unit 2, completed in 2015, and Southern Co.’s Plant Vogtle Units 3 and 4, completed in 2023 and 2024.

A neighboring utility, Duke Energy, recently submitted a report to the North Carolina Utilities Commission outlining what reactors have been developed and built around the world recently, as well as detailing its own plants and where it could build new ones. The firm is not moving ahead with any major investments yet, but its integrated resource plans contemplate adding more than 11,000 MW of new nuclear capacity in the Carolinas by 2050, Duke spokesperson Anne McGovern said.

“The deployment of any new technology will be contingent on ensuring safety, affordability and reliability,” McGovern said. “To move forward with a decision on new nuclear generation, we will need to address several key items: the maturity of the technology and the supply chain to support it; cost overrun protection to protect our customers; federal tax credit certainty; and the ability to recover costs on a more timely basis to lower the overall costs of these projects for customers. We will have an opportunity to update state commissions on our progress regarding the potential for future new nuclear investments later this year.”

Duke has selected a 1,000-acre site near the Belews Creek Steam Station in North Carolina for a potential advanced nuclear deployment, and it could submit an early site permit application to the Nuclear Regulatory Commission in late 2025. The utility also has kept its combined license from the NRC for its canceled W.S. Lee III plant in Cherokee County, S.C., which gives it the option to build two Westinghouse AP1000 units (the kind used at Vogtle 3 and 4) at the site, McGovern said.

The Lee plant, first proposed in 2007, was part of the last wave of interest in nuclear energy. Around the same time, Progress Energy Carolinas asked the NRC to approve a combined operating license application for additional reactors at the Shearon Harris Nuclear Plant site in North Carolina. Duke merged with Progress several years later, and it has kept the permit request effectively on life support, where it could advance it in the future, according to the report filed with the NCUC.

Even at the Lee site, the report notes, the license would need to be revised to update it for lessons learned from the construction of Vogtle Units 3 and 4.

Plant Vogtle’s initial price tag of $14 billion already was high, but the final bill was more than $30 billion, which helped scare other utilities away from building nuclear plants as natural gas and renewables are far cheaper. The experience there has many who watch the industry focused on small modular reactors for the next wave of nuclear development.

“We’ve seen that it’s very expensive right now,” Brattle Group Principal Dean Murphy said in an interview. “The promise for SMRs is that they’re small enough that we’ll be able to build them in a factory and deliver them on a barge or a rail car and install them. And maybe that’s true, and maybe that’s the pathway to get the cost down by a lot.”

In the long term, Murphy is bullish on nuclear energy’s future, but he predicted it would take decades for it to ramp up to where it is being installed at scales similar to gas plants, solar or wind today. The next plant built is likely to be expensive, but if it works out, more will follow and costs should drop. That, however, could take until the second half of the century to ramp up in a major way.

Part of the reason Vogtle cost so much was because it was starting construction after a 30-year pause in the U.S., Georgia Public Service Commissioner Tricia Pridemore told the Electric Power Supply Association’s Competitive Power Summit in early April.

“Please, can we get more nuclear before that workforce and that supply chain that we struggled and bled for to bring up for Vogtle Units 3 and 4 atrophies?” Pridemore said.

Murphy said the rest of the industry would need to see a new nuclear plant — or two or three — successfully developed and then run for a while before it is confident enough to move ahead with others. That might lead to a second wave that is five times as many as the first small batch.

“Then those are going to have to go pretty well before people jump in and commit on a broad scale,” Murphy said. “And that gets you out to sort of midcentury before we’re really engaging heavily in building a whole bunch of nuclear.”

Vogtle was planned well before artificial intelligence moved from the pages of science fiction novels to the business press, but its completion came just as demand growth started to take off.

Demand growth helps when you are making big, lumpy investments in new generation such as nuclear because it almost always is overbuilt somewhat, Murphy said.

“If demand is growing faster, you’re going to catch up much sooner, and you’re not hanging out with an excess of capacity for nearly as long,” he added.

Both Southern Co. and Duke are vertically integrated firms, which Murphy said could help them in their efforts. A large investment in infrastructure needs some guarantees on its future revenue, and state regulators in those states can push costs, including overruns, through to ratepayers.

“But then, even in a vertically integrated market, regulators might put some limits on how much cost you can pass through, and if you overrun that limit, then that can come back to bite you,” Murphy added.

North Carolina also has another key policy Murphy sees as important for nuclear development: a climate law, HB 951, that requires net-zero emissions by midcentury.

“A greater focus on clean energy and climate change could increase the value of nuclear, because it’s about the only thing that can provide clean energy and provide firm capacity,” Murphy said.

Even states like California and New York could turn to nuclear in the future to meet their midcentury climate targets, which also include meeting new demand from electrifying heating and the growth in electric vehicles, Murphy said. While much of that work can be done with technologies that are cost competitive today, the industry needs some kind of dispatchable, emissions-free resource to get to a 100% clean grid, he said.

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House Committee Weighs Bill to Let Dispatchable Resources Jump Queue

A bill that would allow dispatchable energy projects to jump ahead in the interconnection queue under certain circumstances sparked debate during a House Energy and Commerce Subcommittee on Energy hearing April 30. 

Subcommittee members grilled two panels of experts during the hearing to gather information related to 14 energy-related bills. One of those was H.R. 1047, the Guaranteeing Reliability through the Interconnection of Dispatchable (GRID) Power Act, introduced by Rep. Troy Balderson (R-Ohio) in February. (See Bills Introduced in Congress to Speed up Queues for Dispatchable Power Plants.) 

The bill would direct FERC to launch a rulemaking that would allow transmission providers to file requests to move their dispatchable power projects up in the interconnection queue. Applicants would be required to show why the prioritization was needed and how it would improve grid reliance or resilience. Transmission providers also would need to conduct a stakeholder engagement and public comment process before submitting the applications. 

FERC then would be required to issue a decision within 60 days. 

Todd Snitchler, CEO of the Electric Power Supply Association, described the provisions of the GRID Power Act as “an emergency relief valve.” EPSA has endorsed the legislation. 

“What it seeks to do … is a very balanced approach to try and address a critical issue in a way that does not immediately advance any one project to the front of the line and in fact takes a measured approach to try and ensure reliability over time,” Snitchler said in response to questioning from Balderson. 

Snitchler compared the bill to PJM’s Reliability Resource Initiative (RRI) that FERC approved in February. PJM described the initiative as a way to get shovel-ready projects connected faster by adding them to the final transition cycle of its reformed interconnection process, rather than waiting for the new cycle to be implemented next year. (See FERC Approves PJM’s One-time Fast-track Interconnection Process.) 

“This has a very similar flavor in trying to address the occasions as they arise in a way that will allow the emergency to be relieved, and then go back to business as usual,” Snitchler said. 

The GRID Power Act defines dispatchable power as “an electric energy generation resource capable of providing known and forecastable electric supply in time intervals necessary to ensure grid reliability.” 

Some lawmakers, including Rep. Jake Auchincloss (D-Mass.), said that instead of focusing solely on dispatchability, “the first [project] to get connected should be the first that’s ready.” 

Rep. Robert Menendez (D-N.J.) said natural gas power plants may face lengthy delays in receiving new turbines. 

“We want to get projects on the grid. The interconnection process is absolutely a part of that,” Menendez said. “But getting projects on the grid also includes financing, local permitting and supply chain issues that all must be addressed as well.” 

Witness Kim Smaczniak, a partner at energy law firm Roselle LLP, said the GRID Power Act would make it easier to create an interconnection queue that “picks winners and losers among resources.” Smaczniak was a special counsel at FERC, where she helped develop the commission’s Order 2023 interconnection reforms. 

In written comments, Smaczniak said that because of the limited transmission capacity, the bill would increase uncertainty and costs for power projects seeking to connect to the grid. 

“Timely, certain, cost-effective interconnection can make or break whether a project is commercially viable,” she said. 

No action was taken on the GRID Power Act or other legislation during the hearing. Lawmakers have 10 business days to submit additional questions on the bills. 

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IESO Nodal Market Launch Successful

IESO successfully launched its nodal market May 1, reporting few glitches during its rollout.

The Ontario ISO added nearly 1,000 generation, load and intertie pricing nodes to replace its province-wide price while also creating a financially binding day-ahead market.

Nodal real-time prices ranged from ‑$100 to $367/MWh as of mid-afternoon.

“It seems like everything kicked off without a hitch,” said Portia Gilman, market monitoring manager for Yes Energy. The company’s systems began receiving pre-dispatch data at 2 a.m. EPT and real-time pricing data about 4 a.m.

The Market Renewal Program is intended to improve the way IESO supplies, schedules and prices power. The ISO says the new market will save Ontario $700 million over the next decade through reduced out-of-market payments and increased efficiency.

IESO suspended the real-time market at 10 p.m. April 30 to begin the transition to the new market. It also temporarily stopped the use of its Prudential collateral system, implementing an alternative monitoring procedure until the system resumes on May 8.

The day-ahead market will not run on May 1 or May 2, subject to IESO’s market failure rules (Chapter 7, section 4.3.2).

The ISO suspended automated electronic dispatches in the lead-up to the launch, announcing at 2:01 a.m. that HE03 pre-dispatch results would be published for the HE04 look-ahead period and used going forward. It said it would issue dispatch instructions verbally during the transition period.

At 3:07 a.m., the ISO acknowledged that market participants were having trouble accessing public and private reports from the HE02 pre-dispatch run, a problem it reported had been resolved by 8:25 a.m.

It said planned maintenance between 6:15 and 6:30 a.m. could cause three five-minute dispatches to be missed, and verbal dispatch instructions would be issued as needed.

Posting in the ISO’s Power Data section should resume by the end of May 4, and static market content will be updated on the public website after the market suspension is lifted May 2.

IESO says nodal pricing — which is used in all seven U.S. RTOs and ISOs — is crucial to efficiently dispatching and providing market signals to renewables and new resource types such as distributed energy resources, storage and hybrids.

Another milestone will come on May 8, when the ISO begins virtual trading in nine zones. (See Ontario Introducing Nodal Market May 1.)

[Note: RTO Insider is a wholly owned subsidiary of Yes Energy.]

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N.J. Gubernatorial Race Spotlights Clean Energy Policy

Clean energy policies and their impact on rising utility rates are under scrutiny in New Jersey’s most competitive gubernatorial race in years as voters decide on a replacement for Democratic Gov. Phil Murphy, a champion of green energy. 

Six Democrats and five Republicans have filed to seek the governor’s office, which Murphy used to aggressively promote offshore wind (OSW) projects, electric vehicle (EV) adoption and building electrification strategies. Murphy called on the state to have 100% carbon-free electricity by 2035. 

With the primary scheduled for June 10 and the general election Nov. 4, candidates have been bombarding voters with campaign ads for weeks. 

Yet the terrain faced by the candidates is vastly different — and less friendly to clean energy — from the one Murphy enjoyed in his two terms in office. The state’s major gamble on OSW largely has stalled amid logistical and cost challenges, flagging public support and opposition to wind power from President Trump. 

And the state could experience energy shortfalls because too few new generating sources are coming online as fast as old fossil-fueled plants shut down. That has helped cause a dramatic hike in electricity prices that has led to consumer outrage. (See NJ Lawmakers Sound Energy Supply Alarm.) 

Ratepayers will see the average bill rise by about 20% on June 1, a hike that has triggered a vigorous inquiry from legislators on what happened and how the state can boost its supply. Observers say electricity generation likely will emerge as a campaign issue with an intensity rare in electoral and public policy debates. 

“I don’t think it’s hyperbole to say that this is probably the most important gubernatorial primary in recent memory for both sides of the aisle, for the directions of both parties, and certainly for policies for environment and energy,” said a leading environmental advocate. 

Future Power Shortage

The rate hike comes as the public already clearly is concerned about energy costs, according to a poll by the William J. Hughes Center for Public Policy at Stockton University. It found that 67% of registered voters said utility costs were getting worse, compared with 27% who said they remained the same. 

New Jersey officials say the rate hike was created by the PJM capacity auction in July 2024, which resulted in a price increase that was 10 times larger than in previous years. PJM says the auction outcome was shaped in part by a surge in demand from EV use and a predicted influx of energy-intense data centers. New Jersey officials blame PJM’s inaccurate forecasting, saying it predicted more future demand than is realistic, which pushed up auction bid values. 

Micah Rasmussen, director of the Rebovich Institute for New Jersey Politics, said energy likely will be a more central issue in the general election than in the primaries. 

“The Republican candidates all point to Gov. Murphy’s clean energy policies as being responsible for the high cost of energy in the state, as well as present and future supply constraints,” he said. “We should expect to see some (GOP) scapegoating of New Jersey’s clean energy investments as being responsible for this year’s sticker shock in the cost of residential electric, even though that’s directly attributable to the annual PJM auction.” 

Moreover, “Democratic candidates will not be jumping to the outgoing governor’s defense,” he added. “So there’s not a tremendous amount of intra-party contrast.” 

The Trump Effect

New Jersey traditionally leans Democratic — both U.S. Senators are Democrats, and no Republican has won a U.S. Senate seat since the mid-1970s. The Democrats control both state legislative houses. But Republicans have succeeded in gubernatorial races — with Chris Christie and Christine Todd-Whitman each winning twice in the past 30 years.  

To add to the uncertainty, Murphy’s second electoral victory, in 2021, was much closer than his 2017 election, which some analysts attributed to public concern over his clean energy push. Others felt it was a reaction to the impact of the pandemic. 

Throw in Trump’s dominance of the Republican party, and his recent ability to attract swing voters, and the gubernatorial outcome is far from predictable. Vice President Kamala Harris in the 2024 election won by only 5 points. 

That has unnerved some environmental groups, which hope a Democratic victory would enable the state to continue many of Murphy’s policies even in the face of Trump’s crackdown. They argue that clean energy is the solution to the state’s pending energy shortfall. 

“The political environment, the protection of our natural resources, is more important than ever,” said Ed Potosnak, executive director of the New Jersey League of Conservation Voters. “I think right now, affordability is front of mind. I just can’t say it enough: Clean energy is the cheapest energy, and it’s also going to save money in the long run.” 

Democratic Nuance

The six Democrats seeking the governor’s office include Steve Sweeney, a longtime legislator and the former state senate president, and Steve Fulop, a former Marine and an Iraq war veteran who is mayor of Jersey City, the state’s second-largest city. 

Two members of the U.S. House of Representatives are running: Mikie Sherrill, a former Navy helicopter pilot and federal prosecutor, and Josh Gottheimer, who worked at the U.S. Commission on Civil Rights under Presidents Obama and Clinton. Also running are Ras Baraka, the mayor of Newark, New Jersey’s largest city, and Sean Spiller, a former high school science teacher and mayor of Montclair, who also is president of the New Jersey Education Association, the state’s powerful teachers’ union. 

In general, the candidates support a commitment to clean energy, with some nuanced divergences from Murphy’s path. Gottheimer, for example, who is more of a centrist Democrat, touts an “all-of-the-above” energy strategy on his campaign website, setting a distance from Murphy’s single-minded focus on electrification. 

Sherrill’s commitment to “invest in clean energy like solar” suggests a far more vague clean energy focus than the current governor’s vision. 

Fulop backs Murphy’s OSW commitments, one of the governor’s most controversial moves. Polls have shown a drop in support for offshore wind, from 82% in favor in 2008 to 54% in 2023. Republicans and Jersey Shore residents in the past 18 months have waged an aggressive campaign to head off the projects, in part by expressing concern — somewhat improbably — for the impact on the area whale population.  

Baraka embraces Murphy’s stance of fossil-free electricity generation by 2035. 

Sweeney largely avoids energy issues on his campaign website, but suggested to Fox News that he would halt the state’s adherence to Murphy’s earlier commitment to be 100% clean energy by 2050.  

Potosnak, of the League of Conservation Voters, said his organization endorsed Sherrill, in part because she is “not the same as Murphy” and has a “fresh perspective.”   

She outlined a more “robust and innovative” solar program than Murphy’s, “putting solar on as many as is practical government buildings and parking lots, which is great, because that saves us from cutting down forests,” he said.  

“I don’t think the environment is a left or right issue. It’s an issue of critical importance to our future, for our families, for our businesses,” Potosnak said. But he added that while Republican candidates for a variety of offices have in the past courted the League’s support, none did in this gubernatorial race. 

“We reached out to them,” he said. “Unfortunately, none applied for the endorsement.” 

GOP OSW Ban

That disinterest in the League’s outreach likely stems in part from the GOP’s tight embrace of Trump, who has frozen the nation’s offshore wind projects and is believed to be considering cuts to subsidies for clean energy, such as the federal tax credits for solar and EVs. 

A poll released April 25 by the Eagleton Institute of Politics, a unit of Rutgers University, found that the Democratic race is close, with Sherrill leading the pack with 17%, followed by Fulop at 12% and Spiller, Baraka and Gottheimer all at 9 or 10%. 

The poll found the Republican race much less open, with 42% of New Jersey registered Republicans and Republican-leaning independents surveyed saying they prefer Jack Ciattarelli. A former assemblyman, Ciattarelli ran against Murphy in 2021 and came within three points of beating him. The second-place candidate in the poll, former radio host Bill Spadea, drew 12%. 

Ciattarelli, Spadea, Barbera and Kranjac are all strong Trump supporters. 

Bramnick has criticized Trump, and he argues that he’s the Republican most in tune with New Jersey’s centrist voters and so is most electable in the general election.  

Spadea, in a recent post on X, rebuffed Democratic criticism that PJM carries the blame for state’s future energy shortfall. He blamed the Democrats’ “radical climate change agenda” for plant closures. He said he would scrap Murphy’s Energy Master Plan, cut subsidies for wind and solar, and increase nuclear and natural gas electricity generation. 

Bramnick has called for the state to pursue natural gas and nuclear solutions until clean energy technologies become “more affordable and reliable.”  

Ciattarelli says that if elected, he would draft a state Energy Master Plan based on an all-of-the-above energy policy. He wants to ban offshore wind farms and withdraw New Jersey from the Regional Greenhouse Gas Initiative (RGGI). He also would “repeal unrealistic and unaffordable state mandates and timelines regarding electric vehicle sales, household appliances, home renovation and home construction — which would make New Jersey even more expensive,” his website says. 

He doesn’t name the mandates, but that likely would include Murphy’s 2021 commitment to New Jersey to California’s Advanced Clean Truck (ACT) regulations, which require truck manufacturers to meet increasing electric vehicle sales targets, and his 2023 adoption of the Advanced Clean Cars II, which will require all new light-duty vehicles sold in the state to be zero emission by 2035. 

Murphy’s administration also has vigorously promoted building electrification — the use of electric heating and hot water systems — but has not mandated their use and says he would rather use incentives to get the job done. 

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FERC-NARUC Collaborative Examines Ongoing Issues with Gas-electric Coordination

It’s been more than a decade since participants in the natural gas and power sectors identified the lack of gas-electric coordination as a key risk for the operations of both industries. 

And while there’s been progress since then, the steady growth of gas-fired generation and continued disconnect between the sectors’ business models gave the Federal-State Current Issues Collaborative plenty to discuss on the subject during an April 30 meeting at FERC headquarters. 

“I think I saw a number that 47% of all power gen in America now is gas,” FERC Chair Mark Christie said at the meeting, which brought together representatives of FERC and the National Association of Regulatory Utility Commissioners (NARUC). “So, gas has become just absolutely critical to our to our electric system’s reliability.” 

But gas also is important to manufacturers, as well as residential and other end-use customers who rely on the fuel to stay warm in winter, he added. 

Gas generation is important to the grid not only for the huge volume of power it produces, but also because its operational characteristics enable it to balance intermittent resources, which have been growing rapidly, NERC CEO Jim Robb said. 

“I’ve also been a very outspoken critic of the state of natural gas-electric industry coordination since my time as the CEO of WECC in the Western Interconnection and over the past seven years in my time as the CEO of NERC. I’ve described these challenges as the most admired problem in the energy sector, and it’s time to stop admiring them,” Robb said. 

The electricity industry has experienced five well-publicized winter reliability events over the past 14 years that implicated gas-electric coordination, though changes made in response to those events bore fruit this past winter as industry participants made it through several weeks of arctic cold without incident, he added. (See FERC, NERC Say Grid Winter Recommendations Working.)  

But more work is needed, as highlighted by the massive April 28 blackouts on the Iberian Peninsula. It will take some time for the industry in Spain and Portugal to determine the cause of the outages, and it could be weeks before the true causes are known, Robb said. 

“There are, however, a couple of observations that do seem clear,” he said. “By all open-source reports, there was very little traditional generation in operation at the time of the cascade. While other factors may play a role, the lack of spinning generation and the inherent inertia it creates undoubtedly allowed the situation to spiral out of control more quickly than had those plants been operating.” 

Lack of Inertia

Inverter-based resources such as wind and solar do not offer the grid the same levels of inertia that a large spinning mass provides, which means when grid frequency deviates from a stable level, there are fewer resources capable of absorbing that change, allowing outages to cascade more broadly, Robb said. Some new inverters could address that issue, but the technology has not been proven, he said. 

Largely islanded systems, like those in ERCOT and the U.K., already are running into inertia issues today, said ISO-NE CEO Gordon van Welie. But those problems are not expected to be felt in the Eastern Interconnection for another decade or so, he said. 

Van Welie contended that gas-electric coordination issues are still relevant today because the gas system and electric grid are really one system aimed at delivering energy. ISO-NE’s position at the end of the gas pipeline network, without any local supplies of the fuel, makes those issues more acute for New England. 

“Fundamental differences between the gas and electric markets require acknowledgment and specific actions to mitigate and/or account for those differences,” van Welie said. “The electric system is planned and built on forecast mode, while the gas system relies on ad hoc, long-term customer contracts. This makes it difficult for the gas and electric systems to function efficiently as interdependent systems.” 

He pointed out that gas pipelines are built based on firm contracts signed with demand, and that there is no central planning to meet peak demand plus a reserve margin like on the power grid. 

Ohio Public Utilities Commissioner Dennis Deters asked what can be done with large data centers that are “bringing their own generation” to get to market quickly and what impact that could have on the gas system. 

That development illustrates the possibility that the gas industry is not planning for new demand, van Welie said. 

‘Intense’ Planning

But natural gas utilities do have to plan to meet demand on the coldest day of the year, when the gas system delivers three times as much energy as the grid does on the hottest day, American Gas Association CEO Karen Harbert said. 

“We do have intense resource planning, and we do have long-term contracts so that the people that have contracted for the gas get the gas — full stop,” Harbert said.  

She said data center operators used to start their development process at offices of state governors, seeking to get the best tax treatment possible.   

“And then the last place they would go would be the utility. Where’s the first place they are going now? It’s the utility,” she said. 

That allows the utilities to explain how much headroom is available on their system and how long it could take to connect major new demand, she added. Those questions increasingly are driving where data centers go, and Harbert said it’s important to keep those facilities in the U.S. 

Harbert expressed agreement with many in the electric sector that new pipelines and other infrastructure — especially storage — will be needed to ensure reliability for both systems. The politics of expanding pipelines in New England have for years been fraught, but van Welie said an increased focus on affordability in the region could start to change that.  

“I think the real gap, though, is that there was an unintended consequence when we restructured the industries, particularly the electric industry, 25 years ago,” van Welie said. “So, in a place like [Dominion Energy’s Virginia territory] or in Florida, when you build a new gas power station today … you bring the package along to the state regulator and you get approval for the whole thing — the power plant, plus the firm gas transportation contracts, which then results in infrastructure. So, when we unbundled the industry 25 years ago, we broke those linkages.” 

Contributing to the problem is the fact that local gas delivery companies must plan around firm load for their direct customers, but not for electric generators. Resolving that issue is important to both industries because extreme cold can cause issues on either the gas or electric system that then degrade the reliability of the other, as seen in Texas in February 2021 during Winter Storm Uri, van Welie said. (See Texas Supremes Hear Arguments in Last Uri Case.) 

“It’s not a criticism, it’s a reality,” van Welie said. “We’re not planning it to meet the full demand that’s being placed on that system, both the average demand that we placed on it over time as well as the instantaneous demand that is placed on it for purposes of balancing the electric system.” 

Expansion of gas storage represents one way to deal with the issue. On that front, the gas industry has increased the amount of LNG storage in the Northeast in recent years, since the region lacks the right geology for natural storage caverns, said Harbert.  

But while that helps her members, the disconnect in the business models means the issues van Welie highlighted are still there. 

Dominion Energy Virginia has faced nothing like the issues New England confronts around gas-electric coordination, but the fuel has become the backbone of its system in recent years, said Edward Baine, the company’s president of utility operations. The utility won approval in February for its Brunswick-Greensville LNG storage facility to serve two of its gas plants that lacked alternative supplies. 

“Between 2019 and 2023, these two power stations contributed more than 25% of the company’s energy production and achieved a combined capacity factor of approximately 75%,” Baine said. “Importantly, Brunswick and Greensville are two power stations in our fleet that do not presently have on-site backup fuel or access to multiple gas facilities.”