The Market Implementation Committee endorsed a PJMproposal 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.)
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.
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.
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.”
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.
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.”
“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?”
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.”
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.”
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).
RTO Insider LLC, which has been covering the U.S.’ wholesale power markets since 2013, has agreed to be acquired by Yes Energy, which provides data, tools and analysis on the same markets.
Michael McNair founded Yes Energy in 2008 to help power market participants optimize their daily trading and hedging operations. | Yes Energy
“We are thrilled about this merger and the opportunities it presents for our customers, employees and stakeholders,” said Michael McNair, CEO of Yes Energy. “Yes Energy and RTO Insider share a passion to serve complex power markets and a commitment to excellence. We will provide the deepest coverage of RTO market data, rules, regulations and policies in the industry.”
Rich Heidorn Jr., editor-in-chief and publisher of RTO Insider, said the site’s news coverage will be enhanced by incorporating real-time and historic power market data and deeper analysis from Yes Energy. RTO Insider will continue to be available as a separate subscription and will maintain its commitment to unbiased coverage.
Heidorn will continue to oversee RTO Insider and will lead its integration with Yes Energy. Ken Sands, senior vice president editorial, and Adam Schaffer, senior vice president sales and marketing, will continue running RTO Insider’s daily operations. All RTO Insider customer plans and contacts will remain the same.
Yes Energy employs more than 300 energy analysts, database architects, application developers and economists at nine offices in the U.S., Japan, the U.K., Romania and New Zealand, including its headquarters in Boulder, Colo.
Its eight products provide ISO/RTO data, locational marginal prices, FTR auction results, transmission and generation outages, real-time generation and flow data, and load and weather forecasts. Its customers include traders, analysts, asset managers, asset developers and risk managers.
Yes Energy CEO Michael McNair announces acquisition of RTO Insider | Kenneth Wajda / Yes Energy
The company was founded by McNair in 2008 to help power market participants optimize their daily trading and hedging operations.
RTO Insider is the fifth acquisition Yes Energy has made since 2022, when it obtained financial backing from Accel-KKR, a technology-focused private equity firm.
McNair announced the acquisition to more than 300 Yes Energy customers March 5 at EMPOWER 25, its annual summit, in Denver. He said acquiring RTO Insider was another step toward completing Yes Energy’s “Power Market Operating System.”
RTO Insider brings Yes Energy “a new kind of product platform through which we can deliver the news on policy, but also cover market news, events on the grid and provide in-depth analysis of physical changes to the grid,” McNair said. “You’ll see there are a lot of boxes being ticked here where RTO can benefit from or contribute to our operating system.”
Heidorn shared his vision for what he called “the second chapter” of RTO Insider at the conference.
“What really excites me about joining Yes Energy — aside from getting to work with Michael and his terrific team — is that we will have access to FTR market results, real-time transmission flows, modeling results from long-term studies and other information that will allow us to expand our coverage,” he said.
Heidorn founded RTO Insider with his wife, Merry Eisner-Heidorn, who died in May 2024.
RTO Insider Editor and Publisher Rich Heidorn Jr. describes “the second chapter” of RTO Insider as a part of Yes Energy. | Kenneth Wajda / Yes Energy
The idea behind RTO Insider was to help stakeholders monitor rule changes that matter to them and alert them to when they should begin attending the meetings themselves to advocate for their interests.
Other publications only cover FERC’s ultimate decisions, what Heidorn likened to the small part of an iceberg that is above water. “That means that if you are not in those stakeholder meetings, you’re like the captain of the Titanic, with no visibility of that iceberg until it’s too late to change course,” he said.
RTO Insider remains the only news source with reporters covering RTO/ISO meetings in person.
In addition to its flagship product, RTO Insider, the company publishes ERO Insider, which covers the Electric Reliability Organization (NERC and its regional entities) and NetZero Insider, which covers state and federal climate policy.
Competitive markets might not have the same level of support as they did early in Pat Wood’s career, but the former FERC chair believes the politics will swing back in their direction.
“Growing up in the Reagan era, you did have a big faith in free markets,” Wood told Yes Energy’s EMPOWER Conference on March 5 in Denver. “I know that’s a little bit under attack these days, but I think truth will prevail. We’ll get through this rough period here and get to the other side.”
Wood was a FERC staffer when the commission was opening up the interstate natural gas markets in the 1980s. The markets worked well and opened new supply, so that by the 1990s, industry and regulators moved onto tackling electricity, recalled Wood, who is now CEO of Hunt Energy Network.
“FERC, at the same time, as we did in Texas in the mid-’90s, decided, ‘Let’s do the same magic trick on the power markets, because God knows, they could use it,’” Wood said.
Wood was the chair of the Texas Public Utility Commission under Gov. George W. Bush and was appointed chair of FERC after Bush was elected president. Texas had a law that required its industry to move at the same pace as the federal government, so Wood and other policymakers followed the Clinton administration’s work around Order 888 and the basic requirements for ISO/RTOs. That process gave Texas an example of what not to do in the form of California.
“We figured out what they did wrong, and we did it good,” Wood said. “So, we’ve been able to go to a deep, retail, deregulated market in Texas.”
Wood moved over to FERC in time to clean up the fallout from the Western Energy Crisis and to help set up the organized markets operating in interstate commerce.
“That was my job, my four years at FERC, to get all these markets set up into being RTOs and ISOs,” Wood said. “So, we pulled California back out of the ditch. You may argue it’s still there, but I think they’ve actually come a long way.”
Part of the lesson from California was that the markets needed to be monitored. FERC required RTOs to have market monitors and won new enforcement authority from Congress a few years after the crisis.
“We really just assumed that we could wave a magic wand and things would be competitive,” Wood said. “Folks, this industry was vertically integrated, regulated to the toenails for 100 years. So, you can’t just wave the wand overnight and say, ‘Oh, you’re competitive.’ We got to kind of undo the damage that’s done by the regulated enterprise. And so that took some time, and it still is, I guess, a project that’s not complete.”
Market power mitigation is important to that project, but as the markets mature with regional planning and resource adequacy constructs, that mitigation can be wound down, he added.
One of Wood’s biggest regrets was the failure of standard market design because that would have made it easier for competitors to get into the business all around the country. As the markets evolved, that happened naturally, but Wood said it was more like “Spanish and Portuguese” than dialects of the same language.
Now the growth of new technologies including intermittent renewables and storage, which Hunt helps develop, are leading to new realities on the grid.
“I do think that as grids move to more and more renewables, which is surprising to some, Texas is probably going to go ahead of California, and pretty much anywhere else in North America, and catching up with some of our people in the world,” Wood said. “We’re moving to a much more renewable-heavy grid, and so that world needs a different set of assets than we have had historically for those last 100 years.”
Hunt has rolled out storage around the Texas grid and has also started investing in small, dispatchable peaking generators that only run an average of 100 to 200 hours a year, as those growing intermittent resources need to be balanced, he added.
RTO Insider is a wholly owned subsidiary of Yes Energy.
WALTHAM, Mass. — The uncertainty around federal funding, permitting approvals and tariffs on trade is creating major challenges for clean energy development in the Northeast, industry representatives said at the Northeast Commerce and Energy Association’s annual Renewable Energy Conference on March 5.
Turmoil in the federal government is creating “an atmosphere that is not good for business,” said Jeremy McDiarmid, managing director and general counsel at Advanced Energy United. “It’s been 44 days, and it seems like forever.”
Tariffs on Canadian imports threaten to add “hundreds of millions of dollars in potential costs for New England electric customers,” McDiarmid said, noting that this could be “extraordinarily damaging for the ratepayer at the end of the day.”
Patricia Tamez, senior adviser at Shell Energy, said the tariffs could be particularly damaging for clean energy technologies with nascent supply chains.
“Everybody needs investment certainty. … Supply chains for a new industry are difficult to set up,” Tamez said. “The starts and stops make it very hard to predict what’s going to happen.”
“There is conflicting information from the government agencies on whether a tariff can be collected on the provision of electricity,” Tamez said. “This conflict has been noted by many, but the government hasn’t yet announced a clear position.”
Meanwhile, Hydro-Quebec has considered cutting off exports to the U.S., according to reporting by The Globe and Mail. The company already faces extremely low reservoir levels because of an extended drought, putting it in “an excellent negotiating position” to potentially pause exports as it recharges its reservoirs, Robert McCullough of McCullough Research noted in an email.
Imports from Quebec have met about 11% of demand in ISO-NE over the past five years, and the RTO has said cutting them off could create “precipitous, adverse consequences” for grid reliability.
Regarding federal funding, Tamez said it appears unlikely that Republicans will fully repeal the Inflation Reduction Act, noting the large amounts of funding that have gone to Republican congressional districts and the “very large coalition that’s developed across energy sources to protect the IRA.”
McDiarmid said there is “a lot that states can do” to fill the gaps left by the federal government, but he acknowledged that the states lack the “the financial prowess to replace the finances that these federal tax credits can provide.”
Speakers said the challenges to clean energy development come at a difficult time for the region, which is preparing for an exponential increase in demand growth over the next couple decades. ISO-NE projects its peak demand to grow from about 25 GW in 2024 to about 57 GW in 2050.
The New England states will need to keep pace with load growth while simultaneously reducing fossil generation, which accounted for the majority of generation in the region in 2024. (See New England Gas Generation Hit a Record High in 2024.)
“We’re definitely moving to a world where both the supply and demand both are going to be highly variable and dependent on the weather,” said Marianne Perben, director of planning services at ISO-NE.
Michael Judge, undersecretary of energy at the Massachusetts Executive Office of Energy and Environmental Affairs, noted that the state will need to deploy about 24 times more wind and six times more solar than current levels to meet its climate mandates.
“We need to build a lot, and we need to do it really quickly,” Judge said. He highlighted the changes to permitting and siting processes enacted by the state in 2024, which are intended to streamline and expedite clean energy infrastructure approvals. (See Mass. Clean Energy Permitting, Gas Reform Bill Back on Track.)
For the storage industry, “federal policy uncertainty right now is obviously a huge challenge,” said Sean Burke, director of policy at BlueWave Energy. He said the tariffs have created complications for state procurements and power purchase agreements.
New England states are aiming to massively scale up the region’s storage capacity in the coming years. The Connecticut legislature has established a storage development goal of 1,000 MW by 2030; Rhode Island has a goal of installing 600 MW by the end of 2033; and Massachusetts plans to procure 5,000 MW over the next five years.
Hans Detweiler, senior director of development at Jupiter Power, emphasized the importance of soliciting “apples to apples bids” to enable state agencies to see how the bids are priced and potentially adjust the pricing to account for major changes in federal policy.
Detweiler said he remains optimistic about the “long-term opportunity” of storage in the Boston area, adding that “within the Boston load pocket, our view is the volatility is going to come,” which will create the demand for storage resources.
MISO plans to file with FERC by mid-March a proposal to implement a fast-tracked interconnection queue lane for select generation projects.
The grid operator gathered stakeholders for a final workshop March 7 before advancing its proposal to introduce an “expedited resource addition study” in its queue. Its plan would have the RTO processing projects designated as essential by regulators through a separate queue equipped with specialized, dedicated studies instead of the cluster-style studies it uses in the regular queue.
MISO has notified FERC staff of its intention to file. The grid operator hopes to oversee its first applicants at the beginning of June.
“We’ve heard from FERC staff that it’s one of the most talked-about changes in the industry right now,” Director of Resource Utilization Andy Witmeier said. He said several in MISO’s stakeholder community want the fast track to help resolve imminent resource inadequacy. (See Generation Developers Ask for Scoring System on MISO Queue Fast Track.)
Witmeier said MISO’s current queue is not up to the challenge of processing new projects in a timely manner because of a pileup of study delays. As of Feb. 6, the queue contains about 308 GW across 1,695 projects, according to the RTO.
MISO Executive Director of Resource Adequacy Scott Wright has said the RTO wants to conduct the serial, expedited studies to “fill the gap for a few years” until the normal queue improves so that routine processing of projects can be completed within the span of a year.
But for now, Witmeier said it is important for necessary generation projects to get the benefit of standalone studies that clearly show estimated network upgrade costs without the numerous project dropouts of the regular queue muddying study results.
Witmeier said projects “must be tied to some reliability or RA need” to enter the express lane. Developers submitting applications would need to submit a new form and documentation from their applicable regulators demonstrating a project’s importance.
MISO would not independently evaluate the need for projects, explaining that would trample on states and load-serving entities’ role as resource planners, Witmeier said. “We are not the ones to decide what generation should serve load. We study what reliability impacts occur because of generation additions, load additions,” he said.
Projects that take advantage of the express lane would be expected to be in operation no later than 2032. In the first two years of the express lane, projects would enjoy MISO’s usual three-year grace period of commercial operation dates beyond its three-year in-service expectation. Projects that enter the fast track in 2027 and 2028, however, would be limited to a single three-year period from developer submission to producing power.
The RTO intends to retire the fast track after a few years.
Witmeier said the elimination of the additional three-year extension for projects entering in later years tries to recognize the current, frazzled state of the industry’s supply chain and the hope that it can be repaired within a few years.
But Wisconsin Public Service Commissioner Marcus Hawkins said he thought the structure could open MISO to “bottlenecks” where developers rush to enter projects.
“It’s weird, and it’s hard to explain, and it’s something I think FERC would find problematic,” Hawkins said of the split deadline structure during an Organization of MISO States meeting in late February.
Warren Hess of Central Municipal Power Agency/Services asked how the RTO would ensure it was not overbuilding transmission by maintaining separate queue processes.
“There are multiple parallel processes going on all the time at MISO,” Witmeier said, adding that the Business Practices Manuals mandate double-checking the necessity of transmission projects before they are finalized.
“The one, new wrinkle — and it’s not new — is you can change the flows and have a new constraint show up,” Witmeier explained of the simultaneous queue studies.
He said that while the new process could introduce the “slight chance of over-allocating transmission capacity,” MISO is on the lookout for such constraints through its annual transmission planning.
