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March 13, 2025

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DOT Sec. Duffy Rescinds FHWA Memo on States’ Use of IIJA Funds

In February 2023, Shailen H. Bhatt, then-administrator of the Federal Highway Administration, issued a memorandum titled Policy for Using Bipartisan Infrastructure Law Resources to Build a Better America.  

The memo specifically recognized states’ authority to “determine which of their projects shall be federally funded by federal-aid highway formula dollars.” It also set a list of seven key priorities for such projects, the first of which was “improving the condition, resilience and safety of road and bridge assets consistent with asset management plans,” followed by “promoting and improving safety for all road users.” 

However, Transportation Secretary Sean Duffy rescinded the memo March 10, calling it an act of federal overreach that “displaced the long-standing authorities granted to states by law [and] added meritless and costly burdens related to greenhouse gas emissions and equity initiatives.” 

DOT’s top priorities should be “building critical infrastructure projects that move people and move commerce safely,” Duffy said. 

The specific environmental and social justice elements in the memo include: 

    • prioritizing infrastructure resilience to reduce vulnerability to “a changing climate”;
    • addressing projects’ environmental impacts, such as stormwater runoff and greenhouse gas emissions; 
    • “future-proofing” infrastructure to allow for the installation of emerging technologies like electric vehicle chargers and broadband in existing highway rights of ways; and 
    • including communities, including “disadvantaged and under-represented groups,” in project planning and design. 

The memo also includes specific citations from the U.S. Code and the Infrastructure Investment and Jobs Act, also called the Bipartisan Infrastructure Law, that support its priorities. 

For example, to support its call for addressing environmental impacts, the memo cites a 2021 law that requires states to develop plans to reduce carbon emissions from transportation. Emissions reduction strategies included in the law range from encouraging more use of public transportation and carpooling to designing “transportation assets that result in lower transportation emissions as compared to existing approaches.” 

Similarly, infrastructure resilience is defined as the ability to ride out or recover from emergency events. 

DOT did not respond to questions from NetZero Insider on the specific items in the memorandum that Duffy identified as executive overreach without basis in existing law or advancing a “radical social and environmental agenda.” The memo was removed from the FHWA site sometime after submission of those questions. 

Elaine O’Grady, transportation director for the Northeast States for Coordinated Air Use Management, pointed to the potential public health impacts of Duffy’s rollback of the memo and its support for the deployment of EV chargers.  

“[Shutting] off federal funding for EV chargers will cause unnecessary public exposure to harmful levels of air pollution from cars and trucks,” O’Grady said. “In practical terms, this means more asthma attacks and emergency room visits for our children and more missed days of school and work as a result.” 

‘Foundational Investment’

On Feb. 26, the Senate Committee on Environment and Public Works held a hearing on the implementation of the IIJA, where business and state and local government leaders were unanimous in their support for continuing and increasing federal funding for infrastructure improvements and the projects that have been completed since the law’s passage. 

Russell McMurry, a commissioner at the Georgia Department of Transportation and vice president of the American Association of State Highway and Transportation Officials, praised the flexibility the law gives states “to plan and leverage state and local funds to optimize the use of federal funding. … 

“Georgia’s best successes from the IIJA come from the core formula programs which give us funding certainty so we can properly plan and deliver,” McMurry said in his prepared statement for the hearing. “Federal funding represents a foundational investment towards state of good repair for our highways and bridges. In Georgia, 75% of our capital maintenance program is from the IIJA formula programs and 90% of our bridge program is federally funded.” 

The top challenge to completing IIJA projects is the inflation-driven rise in project costs, he said. McMurry mentioned environmental reviews in the context of delays caused by long permitting timelines; he also said more flexibility, and waivers, are needed for the law’s “Buy America” provisions. 

The most negative comments on the law’s provisions related to environmental impacts and greenhouse gas emissions came from Michael Carroll, deputy managing director of Philadelphia’s Office of Transportation and Infrastructure and president of the National Association of City Transportation Officials. 

He singled out the Promoting Resilience and Operations for Transformative, Efficient and Cost-Saving Transportation (PROTECT) program funded by the IIJA for guidelines specifically focused on climate change and resilience, which he said, have put key Philadelphia projects at risk.  

The city received a $14.2 million PROTECT grant in April 2024 to rehabilitate two bridges, both built in the 1800s, according to information on the FHWA website. 

“‘Safety’ is not a buzzword, neither is ‘repair,’ nor is ‘access to jobs and opportunity,’” Carroll said in his prepared statement. “Americans expect all of you to keep your word and deliver on the expected results in safety, good repair and access to opportunity that are the core of every project and not to breach that trust over semantics.”  

The PROTECT program provides funds for cities, states and tribes “to plan for and strengthen surface transportation to be more resilient to current and future weather events, natural disasters, and changing conditions, such as severe storms, flooding, drought, levee and dam failures.” 

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Ontario Premier Ford Slaps 25% Tariffs on Power Exports to US

The Canadian province of Ontario on March 9 began adding a 25% surcharge to all power exports to the U.S., a move that could cost up to $400,000 every day it remains in place. (See Ontario Threatens 25% Tariff on Electricity to US.) 

Ontario’s actions come a week after President Donald Trump implemented tariffs that include a 10% levy on Canadian electricity imports. Provincial Premier Doug Ford said the 25% tariff would remain in place until the U.S. drops its fees. (See ISO-NE Braces for Tariffs on Canadian Electricity.) 

“We will not back down, pausing some tariffs, making last-minute exemptions,” Ford said at a press conference. “We need to end the chaos once and for all. We need to sit down, work together and land a fair deal. A deal that gives businesses the confidence to invest; a deal that gives workers the security they need and deserve.” 

Ford told reporters he could ramp up the tariff or shut off power flows altogether if the trade dispute between the two nations continues to escalate. 

Ontario exports power directly to Minnesota, Michigan and New York, but its flows go beyond those states and into other markets, such as PJM, which can see 1,000 GWh per year of imports from the province — a fraction of a percent of its total consumption. Most of the exports to the U.S. go to either Michigan, at 5,440 GWh last year, or New York, at 6,518 MWh, while Minnesota gets just 145 GWh, according to Ontario’s Independent Electricity System Operator (IESO). 

MISO said in a statement that it still was reviewing the impacts of any electricity tariffs from Ontario, which would be assessed on the Canadian side of the border. 

“NYISO is analyzing the impacts of the order by the Ontario premier and working closely with the Independent Electricity Operator of Ontario to ensure a reliable grid and stable flows of electricity across interregional transmission lines,” the ISO said in a statement. “NYISO expects to have adequate reserves to meet reliability criteria and forecasted demand for New York.” 

Michigan Public Service Commission Chair Dan Scripps told a local NPR affiliate that he did not expect the tariffs to have much impact there because most of the power flows on to other states. 

“If a state like Michigan flows our power through and sells it, as the premier said, to Ohio, that means the impact of this surcharge is going to reverberate right across America … not just in Michigan … or New York or Minnesota, but now in all the states,” Ontario Minister Energy and Electrification Stephen Lecce said at the press conference with Ford. 

Power flowing from Michigan to Ohio means it crosses the seam into PJM, where an RTO spokesman said it does not have any direct links with the province so the extra fees will be handled elsewhere. 

While Ontario officials floated some pretty high bill impacts on Americans for the surcharge, the ultimate impact depends on the power markets. Ontario ships excess power south and generally is a price taker, and so its tariffs would influence wholesale prices only if the power was marginal supply for an RTO. 

Before Trump’s tariffs scrambled North American trade, the big news involving trades between Ontario and the U.S. was a new potential power line being developed by NextEra Energy to ship power directly to PJM under Lake Erie. The Lake Erie Connector made it through recent cuts from the U.S. Department of Energy to be included in one of three National Interest Electricity Corridors. (See DOE Cuts NIETC List from 10 to 3 High-Priority Transmission Corridors.) 

That underwater project initially was proposed by ITC, which upon filing for approval with Canada’s National Energy Board back in 2015 said the connector would “provide the opportunity to earn additional export revenues on surplus generation.” 

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Fears of ‘Phantom’ Loads, Stranded Assets Aired at Yes Energy Conference

DENVER — Prospects of load growth driven by electrification and artificial intelligence have buoyed utility stocks in recent months, but attendees at Yes Energy’s annual summit March 5-7 questioned how much of the load will materialize and warned of the potential for stranded assets.

Independent consultant Evan Bixby, former vice president of strategy and analytics for Pine Gate Renewables, called for more transparency on potential loads.

“Right now, it’s really a black box,” he said during an EMPOWER 25 panel discussion March 6 on power market dynamics impacting asset development.

“Where is this load going to be? How large is it going to be? … How is it actually going to participate in the market?” he said. “Whether it’s crypto, [data center] hyper-scalers, industrial facilities … they all participate in very different ways.”

Bill Thomas, chief energy officer for CleanArc Data Centers, said the prototype data center envisioned in his company’s 2021 business plan — which assumed only a migration to cloud computing — was to serve 24 MW of critical information technology. As a result of increased demand from AI, the company’s first data center, due to go online in Virginia in 2027, will serve 134.4 MW of IT demand.

“The market has completely taken off, to a point now where it’s unreasonable and unsustainable in a lot of ways,” he said during a conversation with Isaac Velander, Yes Energy’s chief product officer.

The 15 states that make up 80% of expected load growth from data centers are not ready for the increased demand, Thomas said.

load

Bill Thomas, chief energy officer for CleanArc Data Centers (left), was interviewed by Isaac Velander, Yes Energy’s chief product officer, on the role of data centers in grid dynamics. | Yes Energy

“No chance,” he said. “It’s somewhat akin to what happened during the early California [renewable portfolio standard] days … and they had to kind of revamp the way that they were thinking about that generator interconnection queue. And they came up with standards and rules, and everything was transparent, and it was auditable, and there were milestones and performance requirements. That doesn’t exist on the load side. … It’s basically been, ‘Hey, I need 5 MW, do you have a circuit for me?’ And utilities would say, ‘Yeah, sure, great. More retail load. Awesome. Let’s do it now.’

“They’re trying to figure out how to do this and how to do it fairly. The reality is that there’s no roadmap and there’s no standardization in it, so the utilities are really struggling to keep up.”

Thomas also questioned whether natural gas generation will benefit as much as believed from the data center boom.

“Natural gas has become all the rage in data center world, and there’s a lot of people that are going around talking about it. But there’s not a lot of people who are going around actually providing solutions to data center operators with natural gas,” he said. “I talked to the large [original equipment manufacturers] that make the machines — the gas reciprocating engines and turbines — and they’re not seeing the demand actually hit their order books. They’re hearing the noise. They have channel partners flittering all around the world, proclaiming to be selling gigawatts of this stuff, but it really hasn’t happened yet.”

Thomas said his company won’t rely on centralized gas plants for backup. “We want to have our redundant generators, which are redundant on a one-for-one megawatt — actually more than that — basis behind the meter; we want to use gas reciprocating engines instead of tier 2 or tier 4 diesel engines.”

Thomas said a 600-MW data center could consume 200,000 dekatherms of gas daily. “Now, we’re not going to do that forever, but we might do it for a couple of years. And so the infrastructure required to get that gas to our facility, and then our ability to actually get those molecules, is going to be critical, and it’s going to weigh on the gas system as well.”

Peter Kelly-Detwiler, co-founder of NorthBridge Energy Partners, warned that utilities building generation to serve AI data center loads could be left with stranded assets if the number of AI players shrinks over time, as happened with search engines in the dotcom boom.

Evan Bixby | Bixby Analytics

“We all know there were a whole bunch of claimants to the throne of search engine, and eventually, only one of them made it to the top,” he said in his keynote address. “And if you don’t believe me, you can go ‘Ask Jeeves.’ …

“There will be carcasses on the road” among the current AI competitors, he added. “And the question then is, do the other players in the space buy up those data centers, or does something else happen?”

He said the longest contracts for AI data centers are for 10 to 12 years after a four-year “ramp” period.

“And then there’s no commitment after that. If the company exits the scene, they pay an exit fee, assuming they still have the capital to do it. So you have this 30- to 40-year time frame for your supply assets, and you have a four-year ramp and then a 12-year temporal period for your contracts. So we have this really significant potential mismatch between load and the … supply resources. … Woe to the utility that builds all this stuff, and then somebody goes away.”

Kelly-Detwiler said it’s too soon to know whether the current load projections are a new bubble. “But we’ve gotten this wrong before,” he said. “Our forecasts in the past, for years and years and years, have suggested we were going to have a much larger power grid than we had today, and then efficiencies kick in.”

He also warned there are likely “phantom” load applications, just as generation developers file more interconnection requests than they expect to complete. A bill introduced in the Texas Senate would require data center applicants to divulge where else they’re also seeking power.

“I wager a year from now, we have a different conversation. Because really, the data center conversation is only two years old,” he said. “As a utility industry, I would argue that we’re sitting in a situation which is one of the riskiest we’ve ever had in terms of capital allocations and the possibility for stranded assets.”

RTO Insider is a wholly owned subsidiary of Yes Energy.

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PJM OC Briefs: March 6, 2025

VALLEY FORGE, Pa. — PJM Senior Dispatch Manager Kevin Hatch presented more detail on the RTO’s plan to scale back a 30% adder it added on the synchronized and primary reserve requirement in May 2023. (See “Stakeholders Discuss Synchronized Reserves,” PJM MRC/MC Briefs: Feb. 20, 2025.) 

The adder would be scaled back incrementally if average reserve performance increases across three consecutive events. If performance is above 75% for three events, the adder would be reduced to 20%; if performance increases to 85%, the adder would be set at 10%; and if performance gets above 95%, the adder would be removed. The plan also includes a fallback if average performance across three consecutive events declines below 75%, in which case the adder would increase by 10%. 

The adder would be capped between 0 and 30%, meaning that the reserve requirement could not fall below 100% of its tariff-defined value nor increase above 130%. Once the adder has been changed in either direction, the three-consecutive-event counter would be reset. Only events exceeding 10 minutes would count toward the average. 

Hatch said PJM’s hope is that the implementation of changes to automatic generator control (AGC) for reserve resources in December 2024 will improve the ability for generation owners to understand when and how they are being deployed. It updates resources’ basepoints with reserve instructions and allows for units to be deployed at less than their full output. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.) 

Hatch said PJM went with the 10-minute threshold because that is the amount of time synchronized and primary reserves are expected to perform for. 

Hatch said the AGC proposal was the first step in the right direction and PJM is open to making further changes to make sure there are adequate incentives for units to respond. While PJM wants to start backing off the requirement increase, it has to be performance driven. 

Stakeholders Resume Discussions on SATA

Stakeholders resumed talks on a proposal to define rules for storage as a transmission asset (SATA) years after the Markets and Reliability Committee (MRC) deferred voting on the package. 

The proposal was endorsed by the PC in December 2020, but the MRC delayed action the following February until after rules governing how storage acts in PJM’s markets had been developed. PJM brought a problem statement and issue charge before the PC to reopen the subject in September 2024. The committee delayed action in October due to the number of pressing issues before stakeholders. The motion to defer precluded action on the issue charge before February 2024 and called for education to be conducted first at the OC. (See “Vote on Issue Charge to Establish SATA Rules Deferred,” PJM MRC Briefs: Oct. 30, 2024.) 

PJM’s Jeff Goldberg said there would be several distinctions between SATA and other transmission assets, including downtime during charging periods limiting its ability to resolve some types of violations.  

To maintain RTO independence, SATA owners would be responsible for maintaining state of charge on single- or multi-peak days by submitting schedules for charging and discharging times. The batteries would need to be configured in an automatic operation to allow them to respond instantly to frequency or local load security needs. Installations would not be able to be moved between sites under normal operations. Any change in location would require a new baseline reliability study. 

Granular load curves would be used to determine how much storage must be in place to resolve a violation; if those curves were not available, then four hours of storage of sufficient scale would be required. 

The proposal would apply only to storage acting solely as transmission, with the possibility for dual use between transmission and markets put off to possible future discussions if transmission rules are finalized. Goldberg said dual use being the third phase of storage rules, following markets and transmission, was PJM’s intent when the SATA rules were first drafted, and that remains the possible road map. But a key consideration is that batteries would need to retain enough charge to resolve transmission needs while also participating in the markets. 

Several stakeholders questioned how PJM would determine when to deploy SATA assets to resolve a transmission need instead of dispatching market-based resources.  

PJM Director of Transmission Planning Sami Abdulsalam said operators would have to monitor and take SATA deployment into account. It would be used for reliability and not arbitrage to play in the market. Director of Stakeholder Affairs Dave Anders said that will be part of the education and subsequent package development, adding that some areas of the proposal developed in 2020 may need revisiting. 

Exelon Director of RTO Relations and Strategy Alex Stern said the reliability issues PJM is experiencing have grown since SATA last was discussed and states increasingly have pushed for its deployment. When the package was drafted, the intention was to allow PJM and TOs to evaluate if SATA could be used as a solution to both regional and local transmission needs; the challenge for stakeholders is how to do that in a way that isn’t making storage a market asset while allowing it to participate on the transmission side. If that cannot be accomplished, there should be a record created to explain the barriers to member states.  

February Operating Metrics

Presenting monthly operating metrics, PJM’s Joe Mulhern said the RTO saw three days in February where load forecast error exceeded staff’s 3% benchmark, mainly due to unexpected weather conditions. The overall hourly error rate was 1.81%. 

The peak for Feb. 2 was 4.04% under forecast due to a storm that brought unexpectedly cold temperatures and snow, increasing load throughout the middle of the day and the evening peak. On Feb. 6, another storm system led to an unusual load shape where the forecast peak occurred two hours later in the evening than expected, though the scale of the peak was the same as forecast. On Feb. 16, cold temperatures and a storm that brought rain contributed to a 4.13% hourly and 3.18% peak under forecast. 

PJM’s David Kimmel said there were three shared reserve events, three spin events, one pre-emergency load management load reduction and two cold weather alerts in February. Two shortage cases were issued Feb. 5 due to unit trips and a third was issued Feb. 11 due to a sharp increase in load paired with smaller generation trips. 

Feb. 5 saw a spin event lasting 10 minutes and 3 seconds, with 1,827 MW of generation expected to respond and 1,155 MW received, while all 98 MW of demand response (DR) performed. Penalties were assessed against 672 MW of generation that did not respond. Another event the following day lasted 4 minutes and 59 seconds with 1,800 MW of generation expected and 1,149 MW received, while 53 MW of DR was committed and 32 MW responded. A 5 minute, 19 second spin event Feb. 11 expected 933 MW of generation and 1,021 MW received, while 104 MW of DR was expected and 40 MW received. 

SOS Updates

Presenting an update on System Operations Subcommittee discussions, Hatch said an 85 MW pre-emergency load management deployment was issued in the Ashburn area of Dominion on Feb. 19 to when a transmission line needed to be taken out of service due to issues with a potential transformer. An existing outage caused by a tree falling on a nearby line earlier in the week also contributed to the need for the deployment. 

The load reduction mitigated the need for a pre-contingency load shed, which may have been needed to avoid a cascading failure identified under N-5 analysis. The deployment began at 4:20 p.m. and mandatory participation ended at 9 p.m. 

PJM conducted its second voltage reduction test Feb. 5, which reduced system voltages by 5% between 7 and 7:30 a.m. 

The test was expected to lower loads by 1.9%, or 1,439 MW, but a 0.7% reduction, amounting to 520 MW, was observed. Hatch said there also was a large impact on MVAR capability, with about 2,560 MVARs of generator capability lost, illustrating a need to increase MVAR reserves. 

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PJM Stakeholders Endorse Changes to Black Start Compensation

The Market Implementation Committee endorsed a PJM proposal to revise the base formula rate for compensating black start resources, receiving 95% support. A competing proposal from the Independent Market Monitor received 11% support. (See “First Read on Black Start Compensation Proposals,” PJM MIC Briefs: Feb. 5, 2025.) 

The proposal would replace a central component of the formula — the zonal net cost of new entry (CONE) — with a five-year average of the RTO-wide net CONE for the 2025/26 delivery year, which thereafter would be updated annually using the Handy-Whitman index. The changes were proposed in response to the possibility that high projected energy and ancillary service (EAS) revenues could depress regional net CONE values, causing black start revenues to also fall. 

PJM’s Glen Boyle said the proposal also would break the tie between the capacity market and black start revenues, which he said would reduce volatility for black start providers and load. 

“If we do nothing under the status quo, we would see the black start revenue drop significantly from where they currently are,” he said. 

Monitor Joe Bowring said the impetus for PJM’s proposal already has been resolved with FERC’s approval of a request the RTO made to shift the reference resource from a combined cycle (CC) generator to a gas turbine (CT). PJM argued the reference resource change was necessary as the higher EAS revenues for CC units were a major contributor to the drop in net CONE. He said there is no immediate problem and establishing cost recovery payments based on anecdotes rather than evidence is not the way to go. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.) 

PJM Monitor Joe Bowring | © RTO Insider LLC

He said the Monitor’s data showed the exact levels of payment under the current net CONE approach, which does not support the need for a change in the approach. 

“The facts do not support the assertion that black start revenue would drop significantly. In response to the goal that all black start providers receive the same payment,” he said. 

The Monitor’s package would use the RTO-wide net CONE, rather than the five-year average, with Bowring calling for stakeholders to continue their discussions on black start compensation to pursue a solution that identifies the best way of defining the cost of providing black start service and compensate for that with a reasonable profit. 

Bowring said PJM has not defined a metric that defines adequate compensation. 

“Absent a metric based on the cost of providing the service, there is no way to objectively evaluate the need for different compensation. PJM’s assertions are not based on any actual evidence. The failure to propose a metric and the assertion that a metric cannot be created are an indication that PJM is not thinking about the issue clearly. PJM’s arguments could have supported any level of increase in payments,” he said. 

Exelon’s Alex Stern said PJM has held numerous requests for proposals (RFPs) for additional black start capability that have gone unanswered. Failing to reconsider how resources are compensated could put the reliability of the grid in jeopardy, he said. 

“We’re seeing an elevated risk with respect to black start, and we’re most definitely seeing black start resources exiting providing the service, and it’s concerning.” 

Boyle said even with the change in reference resource, net CONE values still will fall in the 2025/26 delivery year and PJM has heard concerns that lower black start revenues could fail to cover the costs generation owners incur providing the service.  

“We want to fix the immediate problem, but we would certainly be interested in further discussion down the road,” he said. 

Bowring said there’s no evidence black start resources are leaving because they’re not being adequately compensated. He said the Monitor’s proposal is to look at the issue rationally and make sure revenues are enough to provide the service. 

“The only way to determine whether the payments are covering the costs of providing black start service is to take a detailed look at the costs. PJM has resisted that proposal,” Bowring said. 

Boyle said he’s unsure what kind of metric PJM could produce to demonstrate whether generation owners are likely to participate in black start RFPs, adding that the RTO has been canvassing market participants. He also said the proposal would not increase compensation over current levels, which PJM feels are appropriate. 

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NYISO Stakeholders Debate Purpose of Capacity Market

NYISO and its stakeholders continued their review of the capacity market’s structure March 3 with at-times philosophical debate on the market’s purpose in New York, with some arguing that state policy has played an outsized role in new resource entry.

The ISO opened the meeting of the Installed Capacity Working Group with a statement summarizing its position on that purpose, which had been requested by stakeholders: to accurately value resources according to how they contribute to system reliability, provide nondiscriminatory price signals and function without unnecessary administrative complexity, among other ideals and goals.

Staff also summarized stakeholders’ proposed changes to the market so far:

    • incorporating additional revenue streams and resource attributes into the demand curve reset (DCR) process;
    • shifting the DCR anchor from cost of new entry to “forward going cost” of existing resources;
    • bifurcating the capacity market into new and existing resources;
    • developing an “attribute-based” market, which could include resource adequacy, transmission security or environmental attributes;
    • increasing the seasonality of the capacity market, valuing capacity where it is needed more during the peak months;
    • enhancing the zonal elements of the capacity markets;
    • refocusing the capacity market to ensure price stability regardless of public policy shifts.

NYISO noted the arguments for and against each proposal in its presentation; it intends to present the group with its recommended list of items to remove from further consideration March 17 and prioritized list of changes to consider March 26.

Much of the debate between stakeholders centered on the role of state policy and how to factor that into the market, if at all.

“It is the TOs’ position that we need to critically evaluate the degree to which the market is the driver for new entry versus state policy,” said Stuart Caplan, representing New York Transmission Owners. “Over the last four-plus capability years, all the new entry has been public policy resources.”

Caplan said that NYISO and the stakeholders needed to accurately consider how the market actually was functioning; otherwise the process would generate a solution that was “inappropriate” and “not produce just and reasonable results.” The base assumption of what the capacity market is for, and the context in which it functions, should be analyzed as part of the review, Caplan argued.

Doreen Saia, chair of Greenberg Traurig’s energy and natural resources practice in Albany, said that Caplan had turned the problem on its head.

“Either we are going to have a state policy for every kind of resource we could add to the system, or we need to think about designing the new structure so we can keep open the ability of the market to choose resources and place them,” she said.

Caplan replied by saying he was just describing things as they are and that failure to accommodate those facts could produce unjust results.

“If the primary driver remains state policy, state solicitation and contracts, then all you have is a massive wealth transfer from consumers to existing, primarily fossil fuel, generators,” Caplan said. “And the price signal would not be the driver of new entry.”

Matt Schwall, director of regulatory affairs for Alpha Generation and chair of the meeting, said that he had seen roughly 2 GW of investment that had been attracted to the competitive market.

“I compare that to the amount of megawatts that have been built in the wholesale market as a result of state policies, and I don’t know that one is greater than the other,” Schwall said. “I think to the extent that the markets can’t continue to attract investment and resources the state wants, it’s because we’ve been chipping away at the fundamentals of competitive market design.”

Caplan said that this was missing his point, “like two ships passing in the night.” He said that the situation that New York faced — high capacity prices without new resource entry — creates a problem where there is no mechanism to create competitive prices. This needed to be reckoned with during the market redesign process.

Saia said that there had been numerous studies indicating that the renewables the state wants added to the grid do not provide the reliability the system has “gotten used to,” so the market would need to compensate extant fossil fuel generation for some period. She pointed to the evolution of technology in both fossil fuel and energy storage.

“We have some very difficult decisions. I have not a doubt that some of this is going to be complicated,” Saia said. “We may need to, rather than change the demand curve reset process, add some kind of provision for a transmission security mechanism … so that we can manage that dispatch ability that we’re looking for.”

One stakeholder said that a key element of the discussion was whether the market should accommodate state policies, or if state policies should accommodate the market. He said at this point in the process, stakeholders and the ISO should take the opportunity to look at things holistically, rather than assume whether state policy or markets should come first.

A different stakeholder spoke in favor of using the capacity market to help value non-emitting resources for reliability.

“To ignore zero carbon in the capacity market and to not identify a separate product that brings us reliable capacity is, in my view, a mistake,” they said. “It’s holding on to Old World views of the capacity market and what the policy is.”

Another stakeholder representing Shell disagreed, saying that introducing an integrated resource planning mechanism into the capacity market would dull the market’s ability to reward reliability attributes.

Seasonal Capacity Accreditation Proposal

Starting this May, NYISO will implement different capacity demand curves for summer and winter to represent the differences in risk for each capability period.

Mark Younger of Hudson Energy Economics proposed a way to take this further, breaking out both the peak and shoulder months from the season. Under this structure, the market would compensate capacity at 180% of the seasonal ICAP value during peak months and 20% during the shoulder months.

Younger clarified that the specific multipliers were just examples and should be reviewed to make sure that they promoted the right behavior from resources. Under his example, November, March and April would be considered the winter shoulder months, while May and October would be the shoulder months for the summer. June and September would be paid the baseline summer price.

“I’ve identified an issue that has not been explicitly part of the ISO’s focus that I think should be, and should be included in their winter reliability project,” Younger said. “What I’m focusing on is that the reliability needs are not the same in each month of a capability period.”

Younger said this was critical now because there are resources for which the capacity is purchased in the winter’s shoulder months but not during the peak months. Now that the ISO was becoming more concerned about winter reliability risks, Younger said it made no sense to pay those resources more for contributing when they are less valuable and not contributing when they are more valuable.

He cited Hydro-Quebec specifically and said it was unlikely to behave differently after the Champlain Hudson Power Express is built.

“That’s my fear: They have nothing in their contract; they have no credit for capacity in the winter months,” Younger said. “They can sell capacity in the winter months, but that’s outside of contract.”

Several stakeholders said this seemed like a logical extension of where NYISO already was heading. Zachary Smith, senior manager of capacity and new resource integration, said the ISO was considering Younger’s proposal and how it would impact things like collateral requirements for small loads.

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Moody’s Forecasts Long-term Population Downturn in NY

NYISO on March 4 presented its assumptions for the economic and electrification trends that would drive load growth through the 2040s based on Moody’s Analytics data, which show statewide population to “significantly” decline, dropping below 18 million by 2055. 

The steepest areas of decline are western and central New York, Max Schuler, demand forecasting analyst for NYISO, told the joint meeting of the Load Forecasting Task Force and Transmission Planning Advisory Subcommittee. The state’s population as of the 2020 U.S. Census was 20.2 million. 

Household growth is projected to be flat through the end of the decade, then begin to decline along with the population throughout the 2030s and 2040s. Total employment is expected to increase during 2025 but decline in the long run. Gross state product has recovered from the COVID-19 pandemic and is expected to be strong in the long term.  

Despite the drop in population, NYISO expects electricity demand to continue to grow, in part from electric vehicle adoption and building electrification. The ISO’s baseline assumption is that 80% of new vehicle sales will be those of electric models by 2035.  

A stakeholder asked whether these scenarios had been developed with the recent presidential election in mind.  

“These scenarios were more pre-election and so probably won’t account for new changes in policies recently,” said Ebby Thomas, NYISO demand planning analyst. “The rates are based on the data we do have.” 

Thomas went on to explain that even if the overall stock of vehicles declines because of population loss, there still would be millions of new vehicles coming onto the grid. The growth curve becomes exponential during the “stagnant” population decades of the 30s and 40s. By 2040, NYISO projects there will be about 6 million electric vehicles on the grid consuming 30 TWh of electricity. 

Building electrification also is projected to grow through a variety of technological changes, including air source, ground geothermal, electric resistance and dual-fuel heat pumps. 

“In 2024, Moody’s tells us there’s 7.7 million households throughout the state. By 2040 that drops to 7.6 million,” said Arthur Maniaci, principal forecaster for NYISO. 

By 2030, New York would be “close” to the Public Service Commission’s targets for electrification in each utility’s footprint, a little under 250,000 homes statewide. By 2040, 22% of housing units will have adopted some form of electric heating technology, the ISO predicts. If adoption occurs at that rate, NYISO projects the state will be using 4,000 GWh annually for electric home heating in 2040. By 2050, 75% of all homes would be electrified. 

Moody’s forecast for heat pumps includes different adoption rates in different regions. NYISO does not anticipate high rates of ground geothermal heat pump adoption in New York City, for example, instead projecting that such systems will be more popular upstate. 

Some stakeholders questioned the rates of replacement NYISO put forward.  

“You’re talking about a major expense for something that otherwise one wouldn’t do,” said Mark Younger of Hudson Energy Economics. “The [New York State Energy Research and Development Authority] incentives are borderline insignificant in the face of the expense.” 

After some back and forth, Maniaci said it was possible NYSERDA could open up the incentives “like they did for solar” to enhance adoption rates statewide. He said these incentives had been enormously influential in getting solar onto residential roofs. 

“What we are trying to do is give our best effort at incorporating emerging technologies consistent with state energy policies,” Maniaci said. “Everyone knows that the [Climate Leadership and Community Protection Act] has some aggressive goals. This forecast is making our level best effort at incorporating those.” 

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Report Faults Utilities on Data Center Planning

The new grid infrastructure needed for the much-publicized data center buildout is being unevenly subsidized by other ratepayers through minimally publicized utility agreements, a report from the Harvard Electricity Law Initiative charges. 

This has the effect of foisting upon the public billions of dollars worth of upgrades to benefit a handful of very wealthy corporations, legal fellow Eliza Martin and Electricity Law Initiative Director Ari Peskoe wrote March 5 in their announcement of the paper. 

The authors of “Extracting Profits from the Public: How Utility Ratepayers are Paying for Big Tech’s Power” said they reviewed nearly 50 regulatory proceedings to reach their conclusions and devise their recommendations. 

Their focus is utilities funding discounts to Big Tech and its electricity-hungry data centers by socializing the cost across other ratepayers, then redacting the details of those agreements in public utility commission filings in the name of trade secrecy. 

“Utilities tell PUCs what they want to hear,” the report says: “that the deals for Big Tech isolate data center energy costs from other ratepayers’ bills and won’t increase consumers’ power prices. But verifying this claim is all but impossible. … The subjectivity and complexity of ratemaking conceal utility attempts to funnel revenue to their competitive lines of business by overcharging captive ratepayers.” 

Because big data centers have a big economic impact, the authors add, there is political pressure on PUCs to not endanger their construction in a particular state or district by rejecting proposed data center contracts. 

The report notes the oft-cited predictions that data centers will drive soaring near-term U.S. power demand, and it notes an oft-cited observation about regulated utilities: When they build more infrastructure, they are in line for more regulated profits. 

So they have incentives to be optimistic about future growth, the authors say, and as monopolies, they do not face competitive pressures that would push them toward less expensive or more efficient solutions. 

The report lays out reasons PUCs may deviate, intentionally or not, from the “cost causation” principle that guides ratemaking: 

    • Attributing the utilities’ costs to various ratepayer classes depends on contested assumptions and disputed methodologies; different approaches to cost allocation will yield different results. 
    • PUC commissioners, whether elected or appointed, may feel political pressure to favor a certain ratepayer class. 
    • The utility may exploit its informational advantages and intentionally provide false information. 

With the data center market, utilities are competing for a profitable chance to serve an energy-intensive customer that bases siting decisions in part on power costs — so they have incentive to offer low prices that shift cost to other ratepayers, the authors write. 

They focus on three mechanisms through which that shift can be carried out: 

    • Special contracts containing secret terms are approved through opaque regulatory processes, often in short and conclusory orders with only cursory analysis. 
    • Gaps between federal and state regulations allow costs for data center infrastructure to be left to ratepayers; saddle ratepayers with stranded costs that arise; and allow data centers to reduce their share of regional charges by reducing their energy use a few hours per year. 
    • Data centers contract directly with co-located power generation, disrupting power market pricing and delivery rates. 

Collectively, these factors create problems, the authors argue: “Without systematic changes to prevailing utility ratemaking practices, the public faces significant risks that utilities will take advantage of opportunities to profit from new data centers by making major investments and then shifting costs to their captive ratepayers. The industry’s current approaches of luring data centers with discounted contracts or lopsided tariffs are unsustainable.” 

They offer several recommendations to protect consumers: 

    • Establish more rigorous guidelines for reviewing special contracts — many states now give PUCs broad discretion but no particular standard of review, and these special data center contracts seldom are rejected. 
    • End special contracts and require new data centers to take service under tariffs. 
    • Amend state law to require retail competition and allow for “energy parks” that bring generation, storage and connected customers together either isolated from a utility network or with just an export-only interconnection. 
    • Require utilities to disclose data center forecasts to foster competition. 
    • Allow new data centers to connect only if they commit to flexible operations that can reduce system costs. 

Finally, the authors reject the idea that hiding subsidies for data centers in utility rates is a valid policy tool. Utility rates always have been a means to achieve economic and energy policy goals, they write, and this allows policymakers to avoid the unpopular move of raising taxes to pursue these goals. 

But data center subsidies fail the traditional cost-benefit analysis applied to such subsidies, they say, and they interfere with needed reforms in the power sector. 

To meet data center demand, utilities propose more of the central power generation and transmission expansions that they always have relied on, the report says, rather than using advanced technology and improved planning and operational policies. These revised policies would extract more value from the existing infrastructure but would not carry the same profit margins, and the option is being ignored. 

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SPP Stakeholders Grapple with Energy Transition

IRVING, Texas — Taking the stage to welcome attendees to SPP’s Energy Synergy Summit, incoming CEO Lanny Nickell said the two-day event has been long in the planning.

“It’s something that we’ve been wanting to talk about for a long time,” he said during the March 3-4 event. “I’ve been in this industry a long time. I’ve seen a lot of change, but we’re changing at a rate that is faster than I’ve ever seen before, and that makes it exciting to be part of this industry.

“So that’s what we’re intending to talk about today. How can we align resources with the demand that we know is increasing?”

Exciting? With SPP already seeing changes in the resource mix from renewable sources? With thousands of megawatts of dispatchable generation retiring, as Nickell said? With load growth increasing at levels seldom seen?

The challenge, he told the 280 attendees — an SPP record for an external meeting — is infrastructure.

Case in point: SPP’s approval in November of a record breaking $7.65 billion transmission planning portfolio of 89 projects, including its first 765-kV project. (See SPP Board Approves $7.65B ITP, Delays Contentious Issue.)

“With all of the load growth we’re already seeing, the challenge is to have the resources we need. We need to add more, and we need to add more quicker. With the change in risk, we have to get ahead of the game. We have to add transmission. It’s coming, but it can’t get here quick enough,” Nickell said.

“The questions we have to answer, and it starts today, is how can we do this reliably? How can we do this affordably? How can we add the generation we need quicker? How can we add the transmission we need quicker? What can we do with the system that we have today? Those are the questions that have to get answered.”

Roger Freeman, Talus | © RTO Insider LLC

“I think if we could go back like five years and we talked about [Texas’] economy, things started changing pretty quickly,” ERCOT COO Woody Rickerson said during a later panel discussion. “We thought, ‘Man, this is grid transformation. Focus is really accelerating.’ It was nothing compared to what’s going on now. All the reports, all the dashboards, everything we do is different now because you’ve got this energy component. And then on top of all that, you come in with 10,000 MW of data center load. … So, yeah, it’s kind of the Wild West of the grid right now. I think we’re going to see even five or 10 years of really rapid changes, and what we come out with is not going to be anything like what we have today.”

Morgan Scott, vice president of sustainability and global outreach for the Electric Power Research Institute, offered some pathways forward. She said flexibility is the key to meeting load growth, in addition to forecasting, stability and reliability, and adequate supply and delivery capacity.

This includes flexibility with the transmission system, where additional infrastructure can be slow in coming.

“As one person put it on a roundtable I was facilitating last year: ‘I’ve got to sweat my transmission assets as much as I can sweat those things. I have to squeeze as much capacity out of the transmission system as I can,’” she recalled. “This is the conversation that starts to get around [grid-enhancing technologies], right? How do we get these technologies onto the system that help us to take advantage of the system that is already built as is today?”

Scott used what she said was an ancient Greek proverb, often attributed to Warren Buffett, to make her case for continued infrastructure investment.

“Society prospers when old men plant trees that they’re never going to sit in the shade of,” she said. “The concept fits so right for me as we think about this particular moment in the power system and this industry. We’ve got to be making decisions and investments today in the grid that we’re not going to necessarily see the benefits of. … I encourage us to really think about what’s the power system that we need in the next 30 to 50 years, and how do we make those responsible decisions now?”

Morgan Scott, EPRI | © RTO Insider LLC

SPP’s incoming COO, Antoine Lucas, agreed during his panel’s discussion of how best to adapt to the new digital era. He said the grid operator is using its transmission planning process to ready itself for “many different circumstances.”

“We look at various different scenarios that give us the opportunity to identify needs that are consistent across those different futures, and we try to use that information to lead us to more of the no-regrets type of transmission plan under that circumstance,” he said. “If we’re going to recommend an investment, we know it’s going to address an issue or at least we’re highly confident that it’s going to address an issue on the system. The question just becomes the appropriateness of the scale of the project [minimizing] some of those risks or concerns, but that also puts us in the position to be able to meet the challenges and needs.”

Roger Freeman, head of power for Talus Renewables, provided a customer’s perspective, saying their engagement can be useful in designing the systems of the future.

“I think it’s useful that we’re having sort of a high-level conversation about system planning. That’s really important as we think about the big questions for how we structure our energy system,” he said. “I think as we sort of build the energy system of the future, that conversation needs to change a little bit to broaden out the range of options.

“So I would say to the regulators and others in the utilities in the room, ‘How do we sort of change the mindset so we can have sort of a more dynamic conversation,’ so it’s not just ‘Tell me what you want, I’ll build it and rate base it,’ but it’s ‘Here’s the different ways that you could build a system that you want to build,’” Freeman added.

Kim David, elected to the Oklahoma Corporation Commission in 2022 and now its chair, said she expected a boring job when she joined the OCC. Now, she says, “This is a pretty exciting time moving forward.”

“You guys also speak a different language, but being innovative and thinking outside the box,” she said. “Yes, we have to keep our reliability, and we have to make sure everything is used and useful and we protect our customers. But it is truly with new technology happening, I think this is a time to let the free market have the reins and come up with some innovative ideas to bring forward to us on how to put it together.”

“The main message here is we’re dealing with innovation,” said NextEra Energy Resources’ Mark Ahlstrom, who chairs SPP’s Future Grid Strategy Advisory Group. “Innovation is kind of like a fast form of evolution. It’s a very unstoppable force. We can shape it, we can’t just get in the way and say, ‘Stop.’ It’ll go either right through you or around you and find another way of accomplishing it. We really have to embrace this as an opportunity to innovate and figure out how we’re going to do that at many levels.”

OG&E’s Emily Shuart listens to energy consultant Will McAdams make his point. | © RTO Insider LLC

Former Texas Public Utility Commissioner Will McAdams, who now runs his eponymous energy group and partners with a lobbying firm, recalled his days at the PUC and as its liaison with SPP. The experience was eye-opening.

“I got to see the Wild West, which was ERCOT, and then I got to see the opposite of the Wild West, which was SPP, and that was a world of free-wheeling, Libertarian, valued regulations,” he said. “Do you build it? We’ll figure out how to make it work together. That’s a tough world for an ISO/RTO manager to manage, and then you have SPP. It’s the land of the 16 kingdoms, the transmission owners, and the elders that rule it with an iron fist, and nobody wants to change that.

“And so that’s a great experiment of who’s going to win the race on this data center employment, who’s going to win the race in attracting large loads to their region and thus experience the benefits of the diverse risk cycle of tax base, economic development and job growth partnership,” McAdams added.

“There might be a happy medium between the Wild West and the people that make up that Wild West and the 16 kingdoms. How do you work within the needs of the utility to create the synergies between the load and the utility, to allow the opportunity to scale at the same time providing the reliability needs and, frankly, the cost allocation necessary to bring costs down at the same time as building out infrastructure to bring more loads? And I believe that is possible.”

Lucas shared McAdams’ optimism as he reflected on the conversations surrounding large loads.

“I hear a wide range of perspectives about it, from some that are excited about it but then there are others who say, ‘I just don’t want it, don’t need it,’” he said.

But wherever you stand, Lucas said, additional investment and transmission infrastructure will be needed to maintain grid reliability.

“That’s the numerator in the equation, but I think about these large loads as a real opportunity because to the extent we’re able to significantly increase the denominator in that equation, that might be our ticket to be able to fund the investments as necessary to maintain reliability and do it in a fashion that’s affordable,” he said. “So I would implore everyone here to think about the opportunity in front of us and how we may be able to take advantage of that opportunity to create some affordability as we get through this transition.”

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FERC Approves Power Up NE Tx Filing amid Funding Uncertainty

Amid uncertainty about grant funding from the U.S. Department of Energy, FERC has approved a guarantee for National Grid to recoup all prudently incurred costs for the company’s portion of the Power Up New England transmission project if the project is terminated due to factors outside the company’s control (ER25-866). 

The Power Up project aims to build two interconnection points for offshore wind projects in New England. Spearheaded by the Massachusetts Department of Energy Resources (DOER), the project is supported by the six New England states and includes proposed upgrades to transmission infrastructure owned by National Grid and Eversource. 

In 2024, DOE’s Grid Resilience and Innovation Partnerships (GRIP) program — created by the Infrastructure Investment and Jobs Act (IIJA) in 2021 — awarded a $389 million grant to the Power Up project, estimating the project would create $1.55 billion in electricity savings. (See DOE Announces $2.2B in Grid Resilience, Innovation Awards.)  

National Grid has estimated its portion of the project — intended to facilitate the interconnection of up to 2,400 MW of offshore wind at Brayton Point in southern Massachusetts — would result in $1.2 billion in electricity savings for the region.  

However, the Trump administration has taken a hostile stance to the offshore wind industry and paused the disbursement of IIJA funding that it deemed to undermine the policy priorities outlined by the administration. 

The Grid Deployment Office (GDO) lists the project’s funding status as “selected,” which indicates that DOE has not issued the final funding award. A DOE representative confirmed this status is up to date.  

The Massachusetts DOER — the lead applicant for the project’s application for grant funding — replied through a spokesperson: “The federal grant for Power Up New England has been conditionally awarded to the New England states, obligating the $389 million. We secured these funds through an agreement with the U.S. Department of Energy. We will continue to coordinate with our fellow New England states as we work through the final phases of the award with DOE.”

The GDO declined to comment. 

Significant risks remain even if the grant is awarded by the Trump administration; the funding is contingent on the project coming online within eight years of the finalization of the federal funding agreement. In its filing with FERC, National Grid acknowledged that losing the federal funding would increase the risk of cancellation. (See First FERC Filings Shed Light on New England OSW Tx Project.) 

In response to the heightened risks, National Grid and Eversource have requested FERC authorization for an “abandoned plant incentive” allowing the companies to recover all prudently recovered costs on their portions of the project if it is canceled. The costs of the project will be allocated to customers in ISO-NE on a load ratio basis, with a base return on equity of about 11%. The companies cannot earn an ROE on the portion of the project covered by the federal grant. 

The New England States Committee on Electricity (NESCOE) supported both filings in accordance with agreements between NESCOE and the companies. These agreements authorize the states to cancel the project if the expected costs increase and require the companies to make annual reports on incurred and projected costs. 

FERC wrote that National Grid has “shown that the project faces risks and challenges beyond the control of applicants that could lead to the project’s abandonment, and that approval of the Abandoned Plant Incentive will address those risks and challenges.” 

However, the commission emphasized that any recovered costs must be prudently incurred and highlighted potential uncertainty around the federal funding for the project.  

“The commission’s prudence determination could consider the reasonableness of investment decisions given the status of potential obstacles to project development that were reasonably foreseeable including DOE grant funding availability,” FERC added. 

In its filing Jan. 6 to FERC, a representative of National Grid said the funding award is slated to be executed “in the early months of 2025.”  

In a concurring statement with FERC’s ruling, Chairman Mark Christie wrote that, because the project is driven by state clean energy policies and targets, his concurrence depended on the states’ unanimous agreement “for their consumers to bear the costs of this project using a cost allocation formula to which they all agreed.” 

While the majority ruling noted that National Grid has provided clear evidence the project would create significant congestion cost savings, Christie stressed that the Power Up project “is a public policy project, not a reliability or an economic project, even if there are some ancillary reliability and congestion benefits as there always are with any project.” 

“As we move into the Order No. 1920-A compliance process,” Christie wrote, “this is an excellent example of the opportunity and authority granted to states in that rule to agree to jointly share costs of such projects.” 

FERC has yet to rule on a similar request made by Eversource, and issued the company a deficiency letter in February requesting more information on potential reliability and cost benefits of the company’s part of the project (ER25-747).