Search
April 4, 2025

Posted on

EPSA Conference Tackles Markets in a Time of Rapid Demand Growth

WASHINGTON — Load growth caught an industry that was in the middle of a spate of retirements of older fossil fuel-fired power plants off-guard, but now the markets are starting to respond, experts said at the Electric Power Supply Association’s Competitive Power Summit on April 2.

PJM is expecting load growth of 32 GW from last year to 2030 when its peak will hit 184 GW, mostly from new data centers coming online in its footprint, said its CEO, Manu Asthana. The RTO is dealing with that through its Reliability Resource Initiative, which recently received 94 applications to build resources that will keep the grid stable in the near term. (See PJM Receives 94 Applications for Expedited Interconnection Process.)

“We’re seeing a reaction,” Asthana said. “We’ve seen over 1,000 MW of generation rescind their retirement notices. We have seen almost 27 GW come into our Reliability Resource Initiative.”

On the morning of the event, it was announced the former Homer City coal plant in Pennsylvania was being redeveloped around natural gas to serve data centers, which comes a few months after the Three Mile Island plant signed a deal with Microsoft to reopen to serve a data center, Asthana said. (See Data Center Campus with up to 4.5 GW of Gas Generation Planned for Pa.)

Policy changes can help with the issue too, Asthana said, pointing to the backup generation at data centers as a potential resource that cannot be used because they most often have diesel generators that have limited run-times in their permits, so their ability to offer demand response is limited.

“If we can access that flexibility — or through policy changes, increase that flexibility — even if it’s for a transitional period, I think you can serve more data centers,” Asthana said. “It’s not that we’re short every hour of the year; we’re short some hours of the year.”

PJM is worried about the end of this decade, but MISO has been dealing with a system running at its reserve margin target since 2022, said Todd Ramey, the RTO’s senior vice president of markets and digital strategy. Some of its states are pushing policies to deal with climate change that have retired baseload power plants and favored renewables for new resources, which cannot replace dispatchable power plants on a one-for-one basis.

“So, over the last few years, we rapidly worked down our surplus spinning reserves and kind of hit the minimum,” Ramey said. “Once you get to minimum, it really is all hands on deck at that point — just figure out what we can do to maintain.”

Several years after that first started, MISO was facing zero demand growth, but now it expects growth of 2% annually for the next five years and then jumping up to 3.5% in the 2030s. In 15 years, MISO is expecting demand to grow by 60%.

NERC is expecting summer peak demand to grow by 132 GW around the continent over the next 10 years and winter peak to grow by 150 GW, while 115 GW of older power plants will retire, said Camilo Serna, the ERO’s senior vice president of strategy and external engagement.

“More than 50% of the U.S. is at risk of resource energy adequacy issues, so … we’re going to be running very, very tight,” Serna said.

Another issue is the growing use of natural gas on the system, which is especially concerning in the winter when demand for direct heating use competes with power generation, especially during weather events.

“Weather patterns today are kind of longer, deeper and impact a broader set of regions,” Serna said. “So that will continue to create a lot of resource adequacy issues.”

For years the industry tricked itself into thinking that extreme weather events — such as the 2014 polar vortex, which roiled PJM’s energy markets, and 2021’s Winter Storm Uri, which led to hundreds of deaths in Texas and spiking prices around the country — were random and rare, Asthana said. “I think the lesson from that really is that we need to think differently about resource adequacy.”

NYISO has made changes around its winter requirements, so CEO Rich Dewey said he feels more comfortable about reliability in the season as his operators can call on a fleet of dual-fuel generators to meet demand during cold snaps. But New York faces issues around keeping old legacy plants online for the foreseeable future.

Dewey started his career as a power plant engineer for Niagara Mohawk. He said he was working on plants that were expected to shut down in 2000 and are still running now.

“And we’re counting on them being there for at least the next 10 years of our planning horizon, and there is nothing lined up to replace them,” Dewey said. “So, I worry about that. I worry about the adequacy that the plant owners have to do the necessary maintenance and life extension, which is going to be so crucial. I worry about having the right kind of incentives.”

One of the resources that New York was planning on to replace such plants with was offshore wind, which ran into cost overruns and supply-chain issues before an unfriendly administration took over in Washington. Another issue the Trump administration has put front and center in New York and other Northern markets are tariffs.

NYISO has set up rules to collect tariffs on any imports that flow into its system from Canada, though Dewey would prefer not to use them as the trade is mutually beneficial. New York sets its reserve margin and capacity market inputs around some baseline of imports from Canada.

“If we get into a situation where the politics escalate and we suddenly can’t count on that for anything anymore, then there’s going to be a real reliability issue,” Dewey said.

Another issue that tariffs cause for the industry is exacerbating supply chain worries around key grid components like transformers, Asthana said.

“We have 31 tie lines with Canada,” Serna said. “The systems are designed to work together electrically. So, besides the energy adequacy issues that Rich was pointing to, there are some other reliability services that we count on the two systems providing to each other: voltage [and] frequency support. So, if you have an extended period where you don’t get that power from Canada, there could be other implications beyond just having enough energy to meet demand.”

The changes in demand have changed the discussion around new generation, with Vistra CEO Jim Burke saying he has had to explain why new natural gas generation is in vogue recently to a conference of oil and gas executives.

“I think the solution set of wind, solar and battery is not set up at the moment to meet 24/7 loads that [data centers] have,” Burke said. “It’s also not set up to meet the retirement of coal and the growth on the electric grid. So, gas has proven itself as a more near-term, viable, dispatchable, reliable solution.”

Debating which specific technology is needed to meet the rising demand is a 1990s issue, Competitive Power Ventures CEO Sherman Knight said. The industry needs to build everything it can.

“If you let the markets work and you send the right price signals, it will react, and we will react to that,” Knight said.

In addition, “taking off the handcuffs” from every type of technology so it can help meet the demand will enable the industry to rise to the challenge. And in the case of markets, both Knight and Burke noted that they will pay the price for any wrong bets as they have before.

Vistra’s predecessor firm made a bad bet on building a new coal plant in Texas after Hurricane Katrina caused natural gas prices to spike, Burke said.

“We brought the plant online in 2011, and by 2018 we retired that plant because natural gas prices due to fracking had come down so dramatically,” Burke said. “We wrote off over $1.25 billion as a company. We did not seek any recovery of that. That should be on us; we made a bad decision. The customer didn’t pay for that, and that’s something I think competitive markets are not given enough credit for.”

Earlier in the day, FERC Commissioner David Rosner read off a list of billions of dollars that different organized markets have reportedly saved consumers over the years.

“What’s great about markets?” Rosner said. “It allows us to do more with less. It allows us to optimize around the generation and transmission assets that we have and efficiently use the system.”

While it would help to get better forecasts on what is actually going to show up on the grid, regulators can be certain that demand will rise, he said.

“In places where we have markets, the goal is to make sure that we have a set of rules in place that fit the needs of what businesses want to do,” Rosner said. “I personally don’t have a ‘one-size-fits-all’ in mind on this.”

Rosner said he is hopeful the commission will be able to set some rules on data center co-location so the industry can move forward and meet that demand.

“The only other thing I’d say is I hope that our open proceeding doesn’t discourage people who have developed things that they might want to bring to the commission from doing that whenever it’s ready, because I personally am willing to consider things on a case-by-case basis,” he added.

Posted on

MISO, SPP Solicit Feedback on Joint Transmission Studies

MISO and SPP staff asked for input on a joint system study in 2025 during their annual transmission issues evaluation March 28 with their Interregional Planning Stakeholder Advisory Committee (IPSAC), which was only too happy to discuss stakeholders’ issues with the current process and suggest improvements. 

Missouri regulators called for examining the region encompassing southwest Missouri, southeast Kansas, northeast Oklahoma and northwest Arkansas, rather than just Oklahoma and Arkansas. Clean energy groups urged the RTOs to increase the bidirectional interregional transfer capacity along the seam they say will generate billions of dollars in regional benefits. A transmission developer recommended that the staffs follow its road map in working with FERC to enable the “timely development” of interregional projects. 

The staffs will use the feedback in determining whether or not they conduct a Coordinated System Plan (CSP) this year. They told the IPSAC in December that they will not perform a CSP in 2025 but will accept transmission issues for their annual review, as per their joint operating agreement (JOA). (See MISO, SPP to Revise Joint Agreement, Focus on TMEP Process in 2025.) 

MISO’s Jon George reminded stakeholders that the RTOs have proposed expanding the CSP’s scope to yield a more robust and comprehensive interregional planning process in the 2024/25 planning cycle. They are focusing on identifying “immediately actionable” system upgrades that improve reliability and resilience and strengthening transfer capability between the two systems. 

The study incorporates reliability, economic and transfer analyses using forward-looking 10-year models and assumptions. It aligns with key elements of FERC Order 1920, staff said. 

SPP and MISO have filed a waiver request with FERC for certain multiyear modeling and benefit valuation requirements in their JOA. Staff said they believe the study can proceed as scoped, but that certain JOA provisions may prove challenging. 

Stakeholders reacted positively to the RTOs’ 2034 blended models for issue identification and benefits evaluation: economic, light-load reliability, and extreme hot and cold events. The blended models were also used in the 2023 CSP. 

The Sustainable FERC Project and Natural Resources Defense Council’s Natalie McIntire said the RTOs should be focused on building a bigger grid, given the increase in extreme weather. 

“We really urge the RTOs to focus on the full seam for future comprehensive interregional studies,” she said. “Things are changing so rapidly that we need to keep our focus on all parts of the seam and how we can optimize that for all consumers. The focus in this interregional transfer capability and resilience study on resilience during the extreme weather is great. We support that, but we think there’s further work that can be done to really move away from the prior silo transmission planning frameworks that have been undertaken across the seam in the past.” 

The CSP builds on each RTO’s respective regional process. The RTOs then coordinate on model development, issues identification and technical analysis throughout the evaluation process. 

“We’re already in a solution-submission window for the 2025 [SPP Integrated Transmission Planning portfolio], but to the best we can, we will definitely cross reference solutions from these studies,” SPP’s Spencer Magby said. “If we see something promising in these regions in the 2025 ITP, we’ll be sure to screen them through this study as well.” 

The JOA, which was updated in 2019, requires that a CSP be performed every two years. Stakeholders have until April 23 to submit their final issues. At that point, the RTOs’ Joint Planning Committee, which comprises staff from both grid operators, will meet and determine whether a study will be conducted. 

Five previous CSP studies have failed to produce any joint projects over differences in allocating costs. That led the RTOs to try a different approach with the Joint Targeted Interconnection Queue, which identified a five-project portfolio estimated to cost as much as $1.6 billion that could support up to 29 GW of interconnecting generation along their seam. 

Posted on

West’s Mounting Challenges Require Increased Coordination, Panelists Say

LA JOLLA, Calif. — Regional initiatives aimed at increasing coordination and collaboration among Western power entities are essential to tackle mounting technical and political challenges, panelists said during a discussion at the spring joint meeting of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body on April 2.

Many of the challenges the Western Interconnection faces are coming out of the White House, according to WECC CEO Melanie Frye.

Frye pointed to executive orders impacting the federal workforce, sweeping tariffs and funding pauses for projects in the West. All of this is coming at a time when the risk to reliability is “out front and center,” Frye said in reference to wildfires in Los Angeles, data center demand growth and cybersecurity threats, among other issues.

Coordination and collaboration are key to facing these challenges, Frye said.

An example of such collaboration, according to Frye, is WECC’s adoption of five risk areas the organization’s board of directors approved last year, including:

    • Effects of drought and long-term aridification on the Western grid
    • Reliability challenges related to inverter-based resources
    • Data accuracy and modeling of the interconnection
    • Coordinated planning of the resources in the transmission system
    • Energy policy

“We know we have an integrated grid, and I think it’s going to take the communication, the coordination, the collaboration and the courage to make sure that we continue to keep those lights on,” Frye said. “Through those four C’s, I think we have tremendous possibilities to advance the desires of all of the various states and provinces that are in our footprint.”

Keegan Moyer, a partner at Energy Strategies, said most of the major successes in the Western interconnection, like the Western Energy Imbalance Market, have come through regional coordinating efforts.

However, successful initiatives require trial and error, and “you have to stick with them sometimes for many, many years for them to have any benefit at the end,” Moyer contended.

Additionally, state leadership in regional initiatives is “paramount,” Moyer said.

“So when you look across … what we’re doing now in the region, whether it be [Western Transmission Expansion Coalition], [Western Resource Adequacy Program], the activities going on in WECC, Markets+, [Extended Day-Ahead Market], all these different efforts, state engagement is critical just like it has been in the past,” Moyer said.

Sarah Edmonds, CEO of Western Power Pool, pointed to WRAP as a successful initiative that has brought together Western resources and helped representatives across the energy industry find common ground “to solve the problem of a very serious and looming threat to reliability and resource adequacy in the West.”

However, referencing the other speakers, Edmonds also noted there are challenges in the West, “and that has been difficult for all of us to manage.”

“There’s a lot of layers that you have to navigate through, and you have to make a lot of connections between initiatives and efforts that seem disconnected, but are, in fact, quite organically connected in a number of ways,” Edmonds said.

Despite the many challenges, the Western Interconnection “will decide its own future,” Frye said.

“And I think it’s really important that we not lose sight of the fact that, you know, we’re operating the grid that’s existed for decades, and we know how to do that,” Frye said. “We know the people in this room, and we know the people in the industry that we need to bring to the table. So I think those are important things to not lose sight of.”

Posted on

CAISO CEO, Others Point to Reliability Aspect of BPA’s Market Decision

BPA’s day-ahead market decision will have “major reliability and affordability impacts” on electricity customers in the Northwest and across the West, CAISO CEO Elliot Mainzer said in a report he presented to the ISO’s Board of Governors March 26. 

Mainzer’s statement came weeks after BPA issued a draft policy saying it intends to join SPP’s Markets+, the market competitor to CAISO’s Extended Day-Ahead Market (EDAM). (See BPA Selects SPP Markets+ in Draft Policy.) 

As BPA approaches its final market decision in May, energy leaders and experts in the West are focusing on potential reliability issues should the agency choose Markets+ over EDAM. 

“We’ve seen a lot of changes in the last decade in the West, with gas plant retirements and a rapid rise in solar generation in California,” Fred Heutte, senior policy associate at the Northwest Energy Coalition, said in an interview.  

“Coordination between Bonneville and CAISO has been critical in this decade, especially when things get really tough, like under extreme weather conditions. We depend on transmission and strong coordination in the region to keep the lights on,” Heutte said. 

One central concern is that BPA could choose a different reliability coordinator under the Markets+ option. BPA currently relies on CAISO’s RC West as its reliability coordinator, but could switch to SPP’s reliability coordinator, Western RC Services, BPA’s draft policy says. 

“Then the region will have two coordinators,” Heutte said. “How they will work together, especially when demand is high, needs to be thought about in more detail.” 

Having multiple non-contiguous reliability coordinators and market operators in the Pacific Northwest “will pose many operational and commercial challenges,” BPA’s draft policy acknowledges. 

Switching reliability coordinators could come at a price: BPA’s draft shows the total internal implementation cost of Markets+ could be between $53.7 million and $74.2 million, whereas the cost for joining EDAM ranges from $29.9 million to $38 million.  

Estimated internal implementation costs of market options | BPA

The higher cost estimate for Markets+ is driven in part by an assumption that BPA switches its RC from CAISO to SPP, the draft policy says. While BPA’s draft included the estimated costs for changing RCs for transparency, the agency isn’t certain it will make the change, which will depend on future policy development, the document says.  

In an email to RTO Insider, BPA spokesperson Doug Johnson noted that Markets+ comes with higher upfront costs, while production cost modeling analysis done for the agency shows lower revenue in Markets+ compared to EDAM. (See BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits.) 

However, Johnson added, the ongoing participation fees “suggest that these upfront costs could level out over time between the two markets, with Markets+ showing potential for significantly lower market operating costs over the long-term. While EDAM’s implementation fee is quite low at $3 million, the recurring annual fee is double that of Markets+.” 

WRAP Key Factor for BPA

From a resource adequacy standpoint, both day-ahead market options include an evaluation for resource sufficiency, but BPA has said it prefers the design in Markets+, primarily because the SPP also includes a long-term RA requirement, the agency said in its draft policy. 

Markets+ includes a standardized resource adequacy requirement in which all load responsible entities must participate in the Western Resource Adequacy Program (WRAP) administered by the Western Power Pool, while CAISO’s EDAM does not include any such requirement. 

“While the CAISO BAA has its own RA framework, this framework is not extended to other entities outside of CAISO’s BAA in general,” the draft says. “Bonneville believes that Markets+ requiring participation in WRAP, a standardized RA framework, will better meet this [RA] principle.” 

Regardless of its market decision, BPA will be responsible for its system’s reliability, and will do so by acting as transmission planner, balancing authority and transmission operator. BPA will remain responsible for compliance with applicable NERC reliability standards as well. This is because day-ahead markets and market operators do not assume any of the reliability roles of a utility — as in a full RTO, the draft says. 

‘Valued Partner’

In an email to RTO Insider, Mainzer didn’t elaborate on his comment about the reliability impact of BPA’s decision, but reiterated his support for the agency and its ongoing market decision analysis.  

“BPA has been a valued partner to the CAISO for many years and played an essential role in the development of the Western Energy Imbalance Market (WEIM),” Mainzer said. “There is a seat at the table for BPA to remain an active member and architect of a broad, electrically connected energy market that will build on our shared success with WEIM.” 

Irrespective of how BPA ultimately chooses to proceed, CAISO will maintain focus on EDAM implementation and providing technical support to the West-Wide Governance Pathways Initiative (which is working to bring more independent governance to CAISO markets), Mainzer said in his CEO report.   

“We are proud of the fact that the EDAM market design was crafted through an extensive and transparent process with a wide variety of stakeholders before being approved in full by FERC last year,” he said in the report. This message is “a reiteration of the message that … CAISO and many others in the Northwest have been conveying to BPA over the past year,” Mainer told RTO Insider. 

WECC is also following the formation of both day-ahead markets, Kris Raper, the reliability organization’s vice president of strategic engagement and external affairs, told RTO Insider.  

In general, WECC supports the current developments because market structures allow for more effective and efficient dispatch around transmission constraints — leading to a more reliable system, Raper said.  

“However, it is not WECC’s role to evaluate what market, if any, would be better for a utility to join. That said, as a partner in the Western Interconnection with a mission to mitigate risks to reliability, we [will] address any concerns about reliability as the conversation evolves and the markets develop,” Raper said. 

Posted on

Data Center Campus with up to 4.5 GW of Gas Generation Planned for Pa.

A data center campus planned in western Pennsylvania would include up to 4.5 GW of on-site gas-fired generation and be the largest facility of its kind in the U.S., a group of developers announced April 2. 

The 3,200-acre Homer City project would stand on the site of what had been Pennsylvania’s largest coal-fired plant, a 1.88-GW facility decommissioned in 2023. 

The effort brings together GE Vernova, Kiewit Power Constructors and Knighthead Capital Management. It carries a price tag expected to surpass $10 billion — not counting the data centers themselves, which would cost billions more. 

Homer City Redevelopment (HCR), which is leading the effort to restore the site to economic productivity, said it would be the largest investment of its kind in state history and is expected to start producing power by 2027. 

HCR indicated that many of the components are already procured for the project, limiting the chances of supply-chain delays. GE Vernova will deliver the first of seven hydrogen-enabled gas-fired turbines in 2026, for example. And critical infrastructure remains in place from the coal-burning plant, including transmission lines to the PJM and NYISO grids, substations and water access. 

There is also the nearby Marcellus Shale formation, one of the most productive U.S. sources of natural gas. Pennsylvania is the No. 2 gas producer in the U.S., after Texas. 

Not discussed in the announcement is the typically slow pace of interconnection and the controversy surrounding co-located large loads. 

“We are fully aware of the project and recently met with the developers,” a FirstEnergy spokesperson told RTO Insider. “We are working closely with them to determine the necessary steps and milestones for them to move ahead with their plans for the site. FirstEnergy is committed to helping to improve the economies of the communities we serve, and we are eager to work collaboratively with the right parties to achieve their visions.” 

A spokesperson said PJM could not comment in detail without seeing more specifics. New resources are important in an era of increasing demand and tightening supply, they said, and the Homer City proposal would be well situated. 

Comeback Planned

When it was built in 1969, the Homer City Generating Station became a physical and economic standout in the rural region 40 miles east of Pittsburgh, providing jobs and boasting a smokestack variously described as the tallest in the state or in the U.S. 

But it ran into regulatory and financial problems as coal-fired generation fell out of favor, and it finally shut down July 1, 2023. The smokestacks and cooling towers were leveled with explosives just recently. 

The gap of years between shutdown of the old plant and startup of the new plant may factor into the interconnection process. Generation owners are able to request that the capacity interconnection rights held by a retiring resource be transferred to another queue project for up to one year after the unit shutters. That window has already closed. 

The other pathway for new projects to quickly make their way through PJM’s interconnection queue would be through participating in the RTO’s one-off Reliability Resource Initiative, which will allow 50 projects to be added to the Transition Cycle 2 study cluster. PJM said in March that it had received 94 applications for the program and will winnow those down to 50 based on several characteristics, including nameplate capacity, in-service date and location. 

Meanwhile, the PJM spokesperson said the issues surrounding large-load co-location await clarification by FERC. PJM recently submitted comments to FERC in the matter in which it expressed reservations about large co-located load configurations participating behind the meter (EL25-49). (See PJM Responds to FERC Co-located Load Investigation.) 

The RTO said its BTM rules were designed for smaller configurations, such as warehouses with on-site solar generation. PJM proposed several configurations that are permissible under the current rules while floating others the commission could consider exploring. 

Posted on

ISO-NE’s van Welie Discusses Congressional Testimony with NEPOOL

In a rare appearance before the NEPOOL Participants Committee on April 3, ISO-NE CEO Gordon van Welie discussed his recent testimony at the U.S. House Energy and Commerce Subcommittee on Energy, emphasizing the important role that states play to reduce price volatility in the wholesale markets.

Representatives of every ISO and RTO testified to Congress on March 25 about grid reliability. (See All 7 ISO/RTOs Send Senior Executives to Update Congress on Reliability.) Van Welie spoke about New England’s pipeline constraints, the value of offshore wind and the importance of “alignment between federal and state policies.”

Much of van Welie’s time in Washington was spent responding to antagonistic questions about renewables. In his written testimony submitted to Congress and addressing the PC, van Welie stressed that markets alone cannot guarantee resource adequacy and urged the New England states to hedge against high market prices.

While ISO-NE’s wholesale markets “are essentially short-term ‘spot’ markets,” van Welie wrote, the states can enter long-term contracts “to protect consumers against undue price volatility in both the energy and capacity markets, and to incent the development of sufficient resources to meet the resource adequacy standard that is priced in the capacity market.”

States have an important role in reducing the barriers to entry for new resources, he said. He acknowledged that recent federal policy changes — including antagonism towards offshore and onshore wind and new tariffs on imports — create significant challenges for renewable energy development.

“Over the past few weeks, we have seen firsthand the impact that shifts in federal policy can have on our region,” van Welie wrote. “If the large amount of offshore wind that has been contracted for by the states is significantly delayed or ultimately does not materialize, the region would need to assess the potential impacts and determine what other options might be needed to meet resource adequacy needs in the future.”

If the struggles of offshore wind development continue, the region could pursue an increase in the dual-fuel capabilities of its gas fleet, or an increase of its gas pipeline import capacity, van Welie said. However, he noted that increasing gas capacity into the region is likely not a short-term solution. Increased pipeline capacity would reduce the constraints that contribute to high gas prices in the region but would come at a significant upfront cost and could create risks of stranded costs as the New England states eye a long-term shift away from natural gas.

One stakeholder referenced a 2017 study by Synapse Energy Economics that found a proposed Enbridge pipeline intended to reduce the region’s gas constraints would cost about $6.6 billion, a price tag that would likely be significantly higher today, given the increased costs of large infrastructure projects.

Operations Report, Votes

Also at the PC meeting, ISO-NE COO Vamsi Chadalavada reported that energy market revenue totaled $456 million in March, up from $256 million in March 2024. The increase corresponded with significantly higher average natural gas prices compared to March 2024.

The monthly peak load was 17,200 MW, and there were no capacity deficiency events to report.

Power system emissions have trended up so far this year relative to 2024, largely because of lower temperatures across the region.

The committee voted to approve the consent agenda, which included tariff changes intended to improve its economic study process and changes to the ISO-NE operating procedure concerning protection outages settings and coordination.

It also approved a slate of three candidates for the ISO-NE Board of Directors. The slate now goes to the board for approval.

Posted on

Asthana, Vegas to Headline ERCOT’s Innovation Summit

ERCOT said April 2 that PJM CEO Manu Asthana will join its own CEO, Pablo Vegas, in opening the grid operator’s second annual Innovation Summit on May 6 in Round Rock, Texas.

The two chief executives will discuss how their organizations and others are adapting to and managing the complexities of “rapidly changing grids” in an opening “Energy Insights” conversation during the summit.

ERCOT said the summit will bring together leaders to share ideas and technology advancements and to collaborate on innovative solutions facing grid transformation in Texas and across the country.

The agenda includes ERCOT’s grid-transformation initiatives and panels on data center interconnection, demand response, probabilistic planning methods and industry innovation in other ISOs and RTOs.

“I am excited to join colleagues at the Innovation Summit to explore how we can collectively maintain reliability during rapidly evolving industry dynamics,” Asthana said in a press release.

Ballooning load from data centers has been at the heart of stakeholder discussions and capacity market redesigns at PJM in recent years. The RTO has made changes to its process for transmission owners to submit large load additions and is working with stakeholders to revise its effective load-carrying capability probabilistic modeling of the intersection between system risks and generation accreditation. (See PJM Stakeholders Endorse Proposals to Rework ELCC Accreditation.)

Registration closes April 18.

Posted on

NERC Warns Many Inverters’ Information Not Up to Date

NERC will have to issue its highest level of alert to address shortcomings revealed in a recent information request about inverter use, the ERO said in a report issued April 1. 

A Level 3 alert indicates specific steps deemed essential for certain stakeholders to ensure reliable grid operation. The ERO has only used it once before, to set out “essential actions” for utilities to prepare for cold weather in 2023. (See NERC Board May Force Action on Cold Weather Standard.) Issuing a Level 3 alert requires approval from NERC’s Board of Trustees. 

The Aggregated Report on NERC Level 2 Recommendation to Industry summarizes the findings from a Level 2 alert sent to stakeholders in June 2024, inspired by concerns over inverter-based resources and related modeling practices after a series of grid disturbances in recent years involving such generators. (See NERC Targets IBR Modeling Concerns in Level 2 Alert.)  

NERC directed the alert at generator owners (GOs), transmission planners (TPs) and planning coordinators (PCs). GOs that own grid-connected IBRs were required to provide a range of information about them, including:

    • manufacturers of inverters on their systems;
    • model numbers for their inverters and their quantity;
    • nameplate ratings for each model of inverter;
    • inverter- and plant-level voltage and frequency protection settings;
    • inverter- and plant-level reactive power capabilities and control information;
    • model types used to represent facility model data to TPs and PCs; and
    • dynamic and load-flow model files for each facility.

NERC also provided a series of questions for IBR owners, TPs and PCs including whether their organizations have publicly available model submission and quality requirements, what type of generator models are permitted during the interconnection process, and how the organizations verify accuracy of their models. 

The ERO said stakeholder feedback “indicated that GOs do not keep the requested data and information readily available and up-to-date and are reliant on [original equipment manufacturer] and consultant support” to provide the information when requested. Not only does this make event analysis more difficult, it calls into question the quality of planning data submitted by GOs. 

GOs’ responses to the question about generator models revealed that an overwhelming majority, 78%, submit only standard library models to their TPs and PCs. 15% submit manufacturer-specific models, and only 7% submit both — despite the fact that “NERC guidance and FERC Order 2023 indicate that both should be submitted.” 

The top five IBR manufacturers represent more than 83% of the North American fleet by MW. | NERC

A majority of GOs indicated that they have publicly available model submission and quality requirements, and believe their requirements align with NERC’s dynamic modeling recommendations. But only 16% of GOs said they require equipment-specific, user-written positive sequence phasor domain generator models to be submitted for interconnection studies, while a slim majority — 97 out of 190 respondents — said they do not require submission of equipment- and site-specific electromagnetic transient (EMT) generator models during the interconnection process. 

78% said they perform EMT model verification, and 70% indicated they do not integrate EMT models into generator interconnection studies. 81% said their organization lacks the tools and personnel to effectively perform EMT analysis. 

The question about inverters’ origins revealed that five original equipment manufacturers account for about 74% of the inverter fleet by generation capacity, and 83.1% by number of inverters. Although the Level 2 alert did not mention cybersecurity concerns, the dominance of a small number of manufacturers has caused concern among the cybersecurity community because inverters produced by the same company may share common vulnerabilities that make infiltration and sabotage easier. 

NERC has not said what would be in a potential Level 3 alert, but the ERO emphasized that it would contain “only voluntary essential actions, [with] the mitigation of risk … left up to individual stakeholders.” 

Posted on

ISO-NE Releases Longer-term Transmission Planning RFP

ISO-NE on March 31 published the request for proposals for its first longer-term transmission planning (LTTP) procurement, which is focused on increasing North-to-South transmission capacity in New England and interconnecting onshore wind resources in Northern Maine.

The RFP is the culmination of months of work between ISO-NE, the New England states and stakeholders from across the region, and it could set the precedent for future procurements to meet anticipated transmission needs. (See FERC Approves New Pathway for New England Transmission Projects.)

The main objectives and requirements of the RFP were established by the New England States Committee on Electricity (NESCOE) in December. (See ISO-NE to Work on State-backed RFP for Northern Maine Transmission.)

NESCOE defined the objectives as “strengthening the connection between northern and southern New England,” and “facilitating the integration and deliverability of additional affordable generation resources located in Maine.”

At a minimum, proposed projects must increase the transfer limit of the Maine-New Hampshire interface to 3,000 MW, the limit of the Surowiec-South interface to 3,200 MW and establish new infrastructure in Central Maine to facilitate the interconnection of 1,200 MW of onshore wind. The RTO wrote that applicants could propose upgrades that go beyond the minimum requirements.

The Maine-New Hampshire interface currently has a transfer limit of 2,000 MW, and the Surowiec-South interface has a limit of 1,800 MW.

“All three of these needs must be addressed by Dec. 31, 2035, unless a QTPS [qualified transmission project sponsor] respondent can demonstrate supply chain issues that warrant a later in-service date,” ISO-NE wrote in the RFP.

The two interfaces were identified as high-likelihood concerns in ISO-NE’s 2050 Transmission Study. The focus on onshore wind is driven by its significant potential for low-cost renewable energy production in Northern Maine. (See Long Road Still Ahead for Aroostook Transmission Project.)

The deadline for project submissions is Sept. 30. ISO-NE expects to take about a year to evaluate proposals and select a preferred solution.

Applicants will be required to submit a $100,000 deposit, which will be used to cover study costs. Project sponsors can submit solo or joint proposals, but all proposals must be complete solutions. ISO-NE plans to publish a summary of every proposal received for the RFP.

The RTO wrote that project developers can include in their proposals “corollary upgrades” to infrastructure in the service territory of a different participating transmission owner (PTO).

“As part of the corollary upgrade, the PTO may install new facilities only to interconnect the QTPS respondent’s longer-term proposal to the PTO’s existing transmission system. Any other corollary upgrades must only be upgrades or replacements of existing facilities,” ISO-NE wrote.

The RTO noted that corollary upgrades could include “reconductoring an existing line, rebuilding an existing line, rebuilding a single existing circuit in a double-circuit configuration … multiple-circuit tower separation, operating voltage changes or replacement of circuit breakers with higher-rated breakers.”

Other than infrastructure to interconnect the project, applicants cannot propose new infrastructure in another TO’s service territory without an agreement or joint proposal with the TO.

To screen proposals, ISO-NE will perform steady-state, stability and short-circuit analyses, as well as a transfer analysis “to confirm that the required minimum interface capabilities on the Maine-New Hampshire and Surowiec-South interfaces in the future year are met.”

The RTO will also conduct energy and capacity tests to assess whether the solution will facilitate the required onshore wind interconnection.

If a project passes all the screening tests and meets all the requirements, ISO-NE will conduct a cost-benefit analysis, calculated based on “an independent capital cost estimate, using a consistent capital cost estimating methodology, to ensure consistency in its review of the longer-term proposals and their cost estimates.”

To be eligible for selection, the cost-benefit analysis must show that the project would provide the region with net cost benefits. If no projects pass this threshold, one or more states could opt to cover the costs that exceed the benefits.

The analysis will include capacity expansion, production cost and resource adequacy models to calculate benefits, which it will evaluate over a 20-year period after a project’s in-service date.

ISO-NE will also calculate the benefits of avoided transmission investments “based on the extent to which the project eliminates the need for projects already included on the [Regional System Plan] project list, replaces assets that are already planned to be replaced due to asset condition and included on the Asset Condition List, or replaces assets that are likely to be replaced due to equipment age.”

For all projects that pass the cost-benefit threshold, ISO-NE will “holistically” consider both quantitative and qualitative factors to select the preferred solution. The highest-priority factors in this evaluation will include life-cycle costs, cost-containment provisions, permitting challenges, potential to interconnect additional resources and incorporate future needs, and impacts on system performance.

Lower-priority factors will include operational, environmental and winter reliability impacts, project constructability, and the use of advanced transmission technologies.

ISO-NE will present its preliminary preferred solution to the Planning Advisory Committee for feedback. After ISO-NE posts the preferred solution, NESCOE will have the opportunity to terminate the process or submit an alternative cost allocation methodology.

In a press release, Advanced Energy United wrote that the RFP “demonstrates that with the right planning and collaboration, we have the will and means to build the transmission infrastructure necessary to power a clean energy future,” adding that “it is critical to ensure that this RFP results in well vetted, competitively sourced projects getting built quickly to bring net benefits to New England.”

Posted on

Brattle Report Stresses Need for Southeast Regional Tx Plan

A new Brattle Group report spotlights the Southeast as the only major U.S. region without thorough transmission planning and recommends it develop a portfolio of projects or risk failing to keep up with the times.  

The April 2 report — prepared for the Carolinas Clean Energy Business Association, Clean Energy Buyers Association and the Southern Renewable Energy Association (SREA) — concludes that “the status quo approach for planning and building the future region-wide Southeast grid is insufficient” to meet load growth and growing reliability risks brought on in part by weather extremes.  

“Transmission development today is driven by utilities planning their systems in isolation, focusing primarily on their service areas (or in some cases the joint network within a state) instead of taking a broader, regional approach to grid expansion,” authors J. Michael Hagerty, Peter Heller and Evan Bennett write. They asked Southeastern utilities to “think larger and embrace regional solutions that supplement utility-specific upgrades.”  

The Brattle report says a bolder planning approach is a must, especially since meaningful regional transmission projects have failed to materialize for more than a decade through the utility-created Southeastern Regional Transmission Planning Process (SERTP). It concludes that recent Southeast transmission projects conceived separately by utilities or even small groups of utilities such as the Carolinas Transmission Planning Collaborative and the Georgia Integrated Transmission System are lacking.  

“Without a regional, forward-looking strategy that maximizes the value of transmission investments, Southeast utilities risk inefficiently investing in lower-value local reliability projects within their respective systems, resulting in rising transmission rates without achieving the greatest return on their transmission investments,” the authors said. “Instead of maintaining existing systems, utilities should prioritize regional upgrades that supplement necessary local reliability upgrades and support a reliable grid, new energy generation and long-term load growth.”  

In an April 2 webinar to review the report, Hagerty pointed out that the Southeast’s big players — Southern Co., Duke Energy, Louisville Gas & Electric and Kentucky Utilities Co. — have quadrupled spending on local transmission needs since the early 2000s, when they collectively spent about $500 million per year. Now, those utilities have spent nearly $2 billion annually in the past five years. He and the two other report authors said the spending was mostly to replace aging infrastructure, connect new generation and support “moderate” load growth.  

The report warned that conducting transmission planning largely in isolation leads to missing out on opportunities to build larger, more cost-effective projects and their resilience benefits.  

The report said a $5 billion investment in three 500-kV lines that SERTP evaluated in 2024 could save $2.9 billion conservatively on production costs, $3.3 billion on load diversity and $1.6 billion on resilience benefits. However, the report said SERTP adopted an “overly narrow view of cost savings” and found no benefits of increased transfer capability among Duke Energy, Southern Co. and the Tennessee Valley Authority due to the three major upgrades.  

However, the report said the Carolinas Transmission Planning Collaborative’s in-progress Multi-Value Strategic Transmission Study could show promise for the two states and be replicated on a larger scale in the region.  

‘Lifelines’ for SERTP

SREA Executive Director Simon Mahan said the Southeast’s unprecedented projected load growth means new transmission “lifelines” are necessary. Without them, the Southeast grid risks higher energy costs and reliability disruptions.  

“At the end of the day, lives are on the line without enhanced transmission solutions,” Mahan said.  

Lead author Hagerty said by 2035, the Southeast’s electricity demand is expected to rise by 25% to 21 GW. He and the other authors noted that amount is similar to a doubling of New York City’s demand, and said the Southeast will need regionally planned transmission to connect the estimated 80 GW in new generation to keep up while maintaining reliability.  

Hagerty said SERTP planning is inadequate to take on the modern needs of the Southeastern grid. The report criticized SERTP’s planning structure — composed of 10 sponsor utilities from 12 states with no independent staff — as too narrow to be effective. Mahan said the process, which isn’t open to the public and state regulators aren’t involved in, is mysterious.  

Hagerty also said SERTP’s single model doesn’t produce a realistic future resource mix and the group should reach out to states to get a better view of future generation.  

“The proof is in the pudding,” Hagerty said, adding that over the last 11 years, SERTP hasn’t proposed a single regional upgrade. He said the process is “unlikely to support the investment needed in the Southeast” as demand rises and that a lack of regional planning would correlate with higher costs, delays in serving new load and reliability troubles as more extreme weather stresses the grid.  

Carolinas Clean Energy Business Association Executive Director Chris Carmody said Southeastern utilities are building “very tall silos” of new generation that could burden ratepayers with higher costs.  

“Without transmission, it’s going to be dressed up with nowhere to go,” Carmody joked. He said the Southeast should adopt Eisenhower’s attitude when trying to get the interstate highway system built.  

Carmody added that “one weather event after another” seems to strike the Southeast, and regional transmission could stand in for hard-hit areas that lose service on lines.  

The report said FERC’s Order 1920 could provide the Southeast with an opportunity to create proactive planning that exceeds the federal rule’s parameters. SERTP could use the multi-value and scenario-based planning that exists in other planning areas in the country and incorporate load forecasting to land on portfolios of transmission solutions or even interregional projects, it said.  

Hagerty said the Southeast should view Order 1920 as a “floor” and go beyond the rule’s requirements for an even more dependable grid.  

The Brattle report asked SERTP to shed more light on its planning and share input assumptions, study results and project costs publicly. It also recommended SERTP adopt a “beneficiary pays” method for cost allocation of regional lines.  

Carmody said Southeast utilities should ignore the instinct to build up their islands and work together to avoid leaving their systems vulnerable or missing out on a new manufacturing plant. He said utilities can either choose to continue driving a 1950s Rambler or “accept that that’s not going to be safe or efficient for us” and make investments.  

“Proactive transmission planning supports a growing economy,” Clean Energy Buyers Association’s Katie Southworth added.

SREA previously criticized SERTP’s planning and said Order 1920 could nudge SERTP “away from a process that studies regional transmission lines to justify not building them.”  

SERTP did not respond to RTO Insider’s request for comment on whether there is room for improvement in its regional planning or its still-developing plans to comply with Order 1920.  

Recent calls for stronger transmission planning in the Southeast also extend to MISO South.  

Stakeholders at MISO’s Board of Directors Week in March lined up during a public comment period to ask the RTO to engage in long-term planning in the RTO’s South region. While MISO has designated two long-term portfolios at a combined $32 million in the Midwest, grid planners have yet to prescribe any long-term projects for the South region. (See MISO Fields Divergent Calls for Stronger South Planning, IRA Reversal in Tx Futures.)