RWE Clean Energy has brought its Stoneridge solar-plus-storage complex online. The park, located in Milam County, has 200 MW of capacity with 100 MW of battery storage.
Amazon plans to invest an additional $15 billion in Northern Indiana to build 2.4 GW of data centers.
Under an agreement with Northern Indiana Public Service Co., Amazon will pay fees to use existing transmission lines and cover the costs for any new power plants, lines or equipment needed to serve the new campus. The company has invested $31.3 billion in the state since 2010.
The company said the investment is expected to create 1,100 jobs.
SunPower has finalized the acquisition of Utah-based installation firm Ambia Solar in a $37.5 million deal, a move the company expects will boost fourth-quarter revenue and expand its position in the U.S. residential solar market.
The transaction would create the country’s fifth-largest residential solar provider. SunPower said the rapid close of the deal prompted it to raise its revenue estimate for the fourth quarter to $88 million.
SunPower said Ambia brings an operations management team intended to strengthen its direct-to-consumer unit.
U.S. electricity outage hours reached their highest levels in a decade in 2024 due to the impact of Hurricanes Beryl, Helene and Milton, the EIA reported.
From 2014 to 2024, electricity customers averaged around two hours of outages a year unrelated to major events such as hurricanes or storms, interference from vegetation near power lines or “atypical” utility operations, EIA said.
Interruptions attributed to major weather events averaged four hours, the agency said.
In 2024, the major hurricanes added another seven hours to that figure — meaning the average customer experienced 11 hours of outages.
Outages are categorized by two metrics in the industry: The system average interruption duration index (SAIDI) measures the total duration of non-momentary outages, and the system average interruption frequency index (SAIFI) measures the number of outages in the year.
Nationally, customers averaged 1.5 outages last year. Hawaii led the country on the SAIFI, being the only state to see its power customers average more than four outages in 2024 — but the overall time they were without power was well below the national average. Hawaii had a high number of outages due to bad weather, volcanic activity, unexpected outages at oil companies and issues connecting new power plants.
Maine and Vermont took second and third place, though Mainers averaged nearly 30 hours in SAIDI and Vermonters just under 15 hours. Utilities in both states often have to deal with treefalls knocking out power, EIA said.
Maine customers averaged longer outages than customers in Florida, North Carolina and Texas, despite not being hit by any of the major hurricanes that drove the spike in SAIDI in those three states and nationally. Those Southern states saw customers average between 25 and 30 hours of SAIDI, about half the duration of South Carolina customers who averaged 53 hours of outages.
Hurricane Beryl knocked out power to 2.6 million customers in Texas in July 2024 while September’s Hurricane Helene left 5.9 million customers across 10 states without power, with 1.2 million of those in South Carolina. In October, Hurricane Milton knocked out power to 3.4 million customers in Florida.
Arizona, South Dakota, North Dakota and Massachusetts experienced less than two hours of outages in 2024, while South Dakota, Maryland, Illinois and Massachusetts all averaged less than one outage that year.
As you know, Westinghouse, its two (Canadian) owners, and the U.S. government announced plans for $80 billion of investment in new nuclear plants. Recent articles are here, here and here.
I’ve been skeptical about new nuclear for many years — whether it be microreactors for U.S. military bases, new nuclear generally, small modular reactors in Ontario, nuclear fusion or Vogtle, as I wrote about here and here. And the skeptic’s case remains powerful.
But a recent study from DOE’s Idaho National Laboratory (INL) leads me to think this recent announcement could be a vehicle for something important. Maybe very important.
The NOAK Unit
The INL study makes a strong case that the cost of new nuclear plants could decline from the Vogtle experience as multiple units are constructed, until reaching a “mature” (“nth of a kind” or NOAK) cost of around $6,000/kW at around the seventh to ninth plant. The projected cost reduction from Vogtle’s $15,000/kW? About 60%. The chart from the study (see above) illustrates the cost reduction in terms of capital cost per kilowatt (a “series” is two plants).
You can read the study for the various drivers of the cost reduction.
The China Experience
The INL study bases much of its analysis on China achieving low and declining costs and construction times with its past completion of four AP1000 (Westinghouse design) units, and its 11 CAP1000 and CAP1400 units (adapted from the Westinghouse AP1000 design) now under construction, as listed here.
A separate Harvard study is featured in a recent New York Timesarticle, with more color here. A chart shows capital costs for new Chinese projects under construction at around $2,000/kW.
This Chinese capital cost is about one-third of what the INL study says is possible in the U.S. This would suggest that the INL NOAK cost is not just whistling Dixie.
Cost of New Nuclear Versus Alternatives
So what would the INL NOAK cost mean relative to the costs of other electric power generation?
Here’s a chart from the INL study showing the anticipated U.S. cost reduction in $/MWh Levelized Cost of Energy (LCOE) terms in the context of other generation costs.
Moderate scenario LCOE values: Representative of U.S. experience | DOE
The nuclear range is shown with and without an investment tax credit (ITC). You’ll see that with or without an ITC, nuclear costs start falling below firmed-up solar (based on Lazard estimates) after several nuclear units. And new nuclear cost falls within the broad range for new gas combined cycle cost (not to be confused with the very low cost of retaining existing gas units, even with carbon emission mitigation, as I’ve discussed before).
Importantly, these LCOE cost comparisons are before consideration of the social cost of carbon. If a social cost of carbon were incorporated, such as the $66/tCO2 discussed here, with a $/MWh equivalent of about $30/MWh, the above combined cycle costs would go up substantially. Another way of looking at it is to consider the social cost of carbon as roughly similar to the ITC financial benefit, so the social cost of carbon is rough justice supporting the ITC as an economically justified subsidy.
Location, Location, Location
The prior chart illustrates another important consideration. You’ll note that firmed-up solar in MISO and ERCOT has an LCOE about $30/MWh less than firmed-up solar in CAISO and PJM. This illustrates Lazard’s detailed analysis of the costs of firming up solar and wind, finding that LCOEs differ dramatically by region and by resource.
Given that solar and wind are much more expensive in some regions than in other regions, are the high-cost regions going to decarbonize if it means a permanent economic disadvantage? The only fix (absent nuclear) would be very expensive, difficult-to-site transmission to move power from low-cost renewable regions to high-cost renewable regions.
Nuclear is not location dependent. That could be important for high-cost renewable regions to reduce carbon emissions at competitive cost.
Getting There from Here
So new nuclear might be competitive, but here’s the rub: Who’s going to put up $14,000/kW for the first two units? Or $10,000/kW for the next two? Absent taxpayer (or tech bro or foreign country) financial support, new nuclear can’t get out of the starting gate.
We should recall that taxpayers footed the bill to get solar and wind going, starting almost 50 years with an ITC. EIA estimates that between 2016 and 2022, renewables received $84 billion in federal taxpayer support, while nuclear received $3 billion over the same period.
Assuming the INL capital costs, we can ballpark what it would take in taxpayer subsidies to buy down the cost of the first six nuclear units to the projected cost of the seventh unit (which yields an LCOE below firmed-up solar). Taking the cost differences and applying the 6,600 MW of six AP1000 units comes to $30.8 billion.
Taxpayer funds could be provided over time to match a schedule for outlays. The first two to three pre-construction years for a given plant wouldn’t require much money, but they would get the ball rolling.
An Elephant in the Room
Let me acknowledge a structural weakness in this plan: the creation of a monopolist, Westinghouse. Monopolies by nature raise prices and have limited incentive to be efficient, with poster child Vogtle as I’ve written before here and here.
But the situation here might be the exception to the rule if potential profits from future NOAK units, assuming price targets were achieved, were sufficient incentive for Westinghouse and its major vendors to contain costs on the subsidized first units. And the actual agreement could have financial features designed to incent cost containment.
The Actual Agreement
Regarding the actual agreement for the new initiative, one of Westinghouse’s owners said it expects it to be done around the end of the year.
The details of such an agreement are critical to any chance of success. Who’s doing what, when, how and where? What are the incentives to do what, when, how and where? Who’s qualified to do what, when, how and where? Who’s bearing the cost overrun and schedule delay risks of what, when, how and where? Who’s independently monitoring what, when, how and where? What are the enforcement measures to ensure everyone does what they commit to do, when, how and where?
If the requisite engineering, finance, economic, commercial and legal expertise for such an agreement doesn’t exist in the U.S. government, hire it from outside. There’s too much at stake to wing it.
Bottom Line
There are three established sources of carbon-free electricity: solar, wind and nuclear (putting aside hydro with its limited expansion prospects). With staggering need for more electricity, are we going to give up on one of the three — the only one that is not intermittent and not locational? As Wayne Gretzky (actually his father) said: “You miss 100% of the shots you don’t take.”
Let’s take a shot, America.
P.S. For the holiday season in these challenging times, here are some lists of happy music courtesy of some good folks on Maryland’s Eastern Shore. And here’s a classic video for the season by the Dropkick Murphys. The best of the holidays to you and yours!
New York is adding new leadership to its advanced nuclear energy initiative: Todd Josifovski, director of the $13 billion overhaul of an Ontario nuclear power facility, and Christopher Hanson, who chaired the U.S. Nuclear Regulatory Commission during the Biden administration.
The New York Power Authority announced the appointments Dec. 1.
Josifovski will become NYPA’s senior vice president of nuclear energy development Jan. 1. Hanson will serve as a senior consultant on financing and the federal permitting process.
Popular acceptance of nuclear energy has increased in recent years, and President Donald Trump has ordered the federal regulatory process to be accelerated and streamlined, but the process of building a new commercial reactor remains potentially slow, expensive and complex. Josifovski and Hanson are expected to help New York with this.
Josifovski has worked in clean energy and nuclear power development for more than 20 years, including at Ontario Power Generation, where he was a senior manager and then director of the refurbishment of the four-unit Darlington Nuclear Power Station. That project is nearing completion at an expected cost of $13 billion CAD. Josifovski currently is vice president of development at Peak Power.
Hanson joined the NRC as a commissioner in 2020, during Trump’s first term, and served as chair from Jan. 20, 2021, to Jan. 20, 2025. He continued as a commissioner until Trump fired him June 13.
His NRC bio notes that he previously accrued three decades of public- and private-sector experience in the nuclear fuel sector.
NYPA President Justin Driscoll said Josifovski and Hanson would play important roles in moving the state’s nuclear initiative forward.
“Todd has managed the development and execution of more than 7 GW of clean energy and nuclear projects, and his approach integrates technical rigor with pragmatic risk management, stakeholder engagement and a strong commitment to operational excellence,” Driscoll said. “Additionally, Chris’ extensive experience on the federal level will prove invaluable to NYPA as we navigate this next chapter and form lasting partnerships that will deliver firm, emission-free generation for New York state.”
New York has a challenging path ahead as it tries to expand and upgrade its grid. Its renewable energy buildout was behind schedule even before Trump began his second term, and his policies are expected to further impede progress.
As a result, the aging fossil fleet that policymakers want to phase out remains indispensable: 25% of total statewide generating capacity is fossil-fired plants that are more than 50 years old.
New York’s four commercial reactors — on the opposite shore of Lake Ontario from Darlington — are a combined 198 years old and draw half a billion dollars a year in ratepayer-funded subsidies to continue operation. The state expects to rely on their output into the middle of the century. Meanwhile, state policymakers expect to need more electricity as New York decarbonizes transportation and buildings.
The confluence of factors is such that NYISO opened its 2025-2034 Comprehensive Reliability Plan with this warning: “New York’s electric system faces an era of profound reliability challenges as resource retirements accelerate, economic development drives demand growth and project delays undermine confidence in future supply.”
The existing nuclear fleet provided 21% of the power produced in-state in 2024, NYISO said in the report issued Nov. 21; a scenario in which the four reactors are retired would create shortfalls in summer and larger shortfalls in winter.
The challenge facing NYPA — and now Josifovski and Hanson — is to move the advanced nuclear initiative forward not just quickly but safely and affordably, and with a politically acceptable siting mechanism.
NYPA has issued requests for information from potential developers and potential host communities on how best to do this. (See Wanted: N.Y. Community Eager to Host Nuclear Reactor.) Their responses are due Dec. 11.
Discussion about potential changes to the NYISO demand curve reset (DCR) process dominated a recent Installed Capacity Working Group meeting and will likely take up more oxygen in stakeholder meetings throughout the coming year.
“This project has the potential to deliver transformational changes to the market in the face of evolving grid conditions,” Michael Ferrari, NYISO market design specialist in capacity and new resource integration, told the working group Nov. 17 in presenting the project’s kickoff.
The Capacity Market Structure Review project identified the DCR as an area that needed improvement. The improvement project was prioritized for 2026, meaning NYISO has budgeted resources and labor hours for it.
Stakeholders have long complained that the DCR does not provide adequate price signals for new investment, value reliability contributions or provide sufficient consideration of long-term reliability impacts. During the latest DCR, stakeholders debated whether NYISO’s preferred proxy unit, a two-hour battery system, was appropriate or reflective of what might enter the market. In addition, stakeholders said the DCR has a steep learning curve, requires a lot of stakeholder engagement and provokes contentious debates during working group meetings.
Though Ferrari’s presentation noted all these concerns, “it doesn’t seem like the concerns expressed by Con Edison are in here,” a representative of the company said. “There have been multiple conversations on our end about concerns of higher costs to customers.”
Ferrari said stakeholder feedback highlighted in his presentation was “not a comprehensive list,” though the omission of price considerations was indeed an accident.
The presentation indicated NYISO would study how to improve or refine the definition of the proxy unit used to undergird the DCR process. The ISO also would look at restructuring the development of the net cost of new entry of the proxy unit, which sets prices for the curve; look at alternative curve slopes; and possibly develop a technology-agnostic approach to net CONE.
Stakeholders asked what a “technology-agnostic approach” meant with respect to net CONE. Ferrari said it meant NYISO was considering not choosing one specific unit to serve as the proxy for new generator entry to the market.
The ISO plans to issue a draft Issue Discovery Report at the ICAP Working Group’s Dec. 16 meeting. It will present the group with a detailed proposal of initial market design enhancements for consideration at a later meeting.
In New England, increasing winter reliability concerns are driving questions about how long the region’s aging fleet of oil-fired power plants can, or should, remain on the system.
Power generation from oil has declined dramatically in New England since the start of the century. The oil plants that have remained on the system have run less frequently, mostly during tight winter periods when gas generators have limited access to pipelines.
Several high-profile oil units have already retired, and the large oil resources that remain face significant retirement risks.
Continued reliance on aging oil generators has real consequences: The units are among the dirtiest in the ISO-NE resource mix, both in terms of climate-warming emissions and local air pollution that can have significant health effects on nearby residents.
But ISO-NE forecasts that growing winter demand, coupled with obstacles to offshore wind development and limits to the region’s gas supply, will increase the need over the next decade for dispatchable generators with fuel storage capabilities. This may force the region to keep the units online longer than many policymakers hoped, or to invest in adding dual-fuel capabilities to existing gas-only units.
Uncertainty remains, however, around when a significant spike in winter demand will materialize. And changes in the wholesale markets — including ISO-NE’s ongoing capacity market overhaul, evolving Pay-for-Performance risks and the introduction of longer-duration reserve products — could also have significant effects on plant revenues, making it difficult to predict how long the resources will remain online.
“You see a lot of the owners of some of these oil facilities caught in between and not being able to see a clear picture as to whether the ISO, the states and other policymakers want to try to preserve those facilities or drive them into retirement,” said Dan Dolan, president of the New England Power Generators Association.
“A lot of them have been driven into retirement or been driven into a place in which they are right on the cusp of financial viability,” he said. “I, at this point, don’t have a clear line of sight as to how some of those standalone large steam units are going to function.”
Changing Economics
The New England oil fleet is old: Most of the oil-fired steam units were built in the 1970s. As cheaper, cleaner and more efficient sources of energy have come online, oil generation has declined dramatically, dropping from 18% of the total energy production in 2000 to 0.3% in 2024, according to ISO-NE.
The steepest decline occurred between 2000 and 2010. Over the past 10 years, annual oil generation has fluctuated, often following the severity of winter conditions.
But the region has continued to see retirements and a declining amount of oil capacity on the system. Between Forward Capacity Auctions 15 and 18, capacity supply obligations for generators running on distillate and residual fuel oil declined from over 4,700 MW to about 3,500 MW.
“Many of these units are at risk of retirement,” ISO-NE noted in its draft 2025 Regional System Plan. “They run infrequently, are less efficient and are nearing the end of their economic life.”
As the resources have run less frequently, they have become more reliant on capacity revenues, while low capacity clearing prices have pushed higher-priced generators out of the market, according to ISO-NE’s Internal and External Market Monitors.
Potomac Economics, ISO-NE’s External Market Monitor, wrote in its 2024 annual report that “the sustained low prices led to 760 MW of retirement bids from units with on-site fuel supplies clearing in FCA 18,” which applies to the 2027/28 capacity commitment period (CCP).
With essentially no dispatchable generating resources in the region’s interconnection queue, “it will be critical to retain a large share of the existing dispatchable generation and avoid mandating retirements of fossil fuel resources,” Potomac wrote.
ISO-NE analyses have “made it clear that we need dispatchable resources, and we need a fairly significant quantity of readily available fuel for those dispatchable resources,” said Brian Forshaw, principal at Energy Market Advisors and a longtime NEPOOL participant. He emphasized that his comments are not on behalf of any of his clients.
“The challenge is going to be how to identify what the value of retaining that capability is, and then developing some kind of a market mechanism, or a reserve product or whatever else to compensate them enough to keep them around,” he added.
ISO-NE’s Capacity Auction Reform (CAR) project, a major multiyear effort, is intended to help better align capacity procurements with actual reliability benefits.
The project proposes transitioning the RTO from a forward, annual capacity market, with auctions held three years prior to the relevant CCP, to a prompt, seasonal market, with auctions held about a month prior to each CCP, which would be divided into winter and summer seasons.
The effort also includes significant changes to how much capacity value ISO-NE assigns to different resource types. Under the current rules, the capacity market typically accredits resources based on an audited value intended to capture the maximum output they can provide. The methodology does not account for outage rates and maintenance requirements, which ISO-NE instead factors into its calculations for the installed capacity requirement.
Under the proposed CAR changes, resources would be accredited based on their marginal reliability impact value, which is intended to capture contributions to reducing energy shortfall during extreme model scenarios. Accreditation values would account for a wider range of factors, including resource outage rates, maintenance requirements, stored fuel and intermittency.
The changes could have major implications for the capacity revenues available to different resource types, though it is still early in the process to predict how the project will affect various resource classes.
“It is vitally important that the ISO-NE markets accurately signal which resources effectively support reliability and how much capacity is needed,” Potomac wrote in its annual report. “This is necessary to avoid premature retirement of fuel-secure resources, incentivize generators to acquire inventory or firm fuel arrangements, and avoid overpaying for capacity that does not support reliability.”
The changes to accreditation will likely be both positive and negative for oil generators.
Accounting for fuel storage appears likely to increase the accreditation values for oil units relative to other resources, and multiple participants involved in NEPOOL discussions also said the shift to a seasonal market may push prices up in the winter, providing an additional boost.
However, oil-fired steam resources tend to have higher outage rates and greater maintenance requirements, which will likely limit their accreditation values, regardless of their stored fuel capabilities or potential winter benefits.
The shift to a prompt market would also allow resources to submit retirement notifications much closer to each CCP; it would reduce this notification deadline from about four years to about one. This would enable participants to make retirement decisions based on more up-to-date information about the conditions of the market and their resources.
“There’s so many variables and moving pieces to that design — it’s going to be hard to get a clear picture until we see more about how all those pieces fit together,” NEPGA’s Dolan said.
Some stakeholders also expect future capacity prices to reflect a perceived increase in PFP risk. Capacity scarcity events trigger the PFP rules, which penalize resources with capacity obligations that fail to perform and reward resources that deliver more than their obligations.
Some oil-fired generators have racked up significant penalties during PFP events in recent years. The resources generally require significant advance notice to ramp up and come online, making them ill-suited to perform during unexpected scarcity periods.
“I think it’s fair to assume that the higher Pay-for-Performance risk that people are now starting to perceive will work its way into the supply offers that will get submitted into the market,” Forshaw said, adding that this will likely put “some upward pressure on prices.”
New Mechanisms
Taking all factors into account, “the expectation is: Some of the older resources that do maintain significant inventories of residual oil are going to face challenges going into [the 2028/29] time frame and may consider submitting deactivation notices one year prior to the start of the delivery period,” Forshaw said.
With looming retirement risks and ISO-NE’s forecast that winter reliability risks will rise in the mid-2030s, it is important to begin discussions on potential solutions and new mechanisms, he said.
In a statement, ISO-NE noted it is evaluating “the potential addition of a longer response reserve product, such as a 60- or 90-minute reserve, to help manage uncertainties caused by the increasing variability of renewable generation and real-time system demand,” which may provide additional opportunities for oil resources.
The RTO also recently established a new Regional Energy Shortfall Threshold (REST), which is intended to define an acceptable amount of shortfall risk in the region. It plans to use the threshold to evaluate risks prior to each winter and summer season, as well as in long-term assessments. (See ISO-NE Proceeding with Shortfall Threshold After Positive Feedback.)
It has yet to determine how it would select and develop solutions to mitigate risk if the threshold is violated.
Data from long-term assessments “will guide evaluation of whether the possibility of exceeding the REST in those time frames requires development of regional solutions to mitigate modeled risks and, if so, when to begin to develop solutions; these efforts would be signaled in future annual work plans,” ISO-NE wrote in a statement.
The RTO has yet to deploy the threshold in long-term, forward-looking studies. ISO-NE’s probabilistic modeling for the upcoming winter indicates the region is well short of the risk threshold. (See ISO-NE Forecasts Minimal Shortfall Risk for Upcoming Winter.)
Forshaw emphasized the importance of establishing the process for addressing REST violations well before they occur, noting that major market reform frequently is a multiyear process.
If studies show high risks of energy shortfall because of a lack of fuel, it could make sense to procure fuel, or another type of energy, that would “only be used when we’re facing load shedding, rather than in the normal course of dispatch,” he said.
Interest in Dual Fuel
Regardless of potential new mechanisms or the specifics of the accreditation changes, some of the region’s aging oil generators may be nearing the end of their useful life. Resource owners that are willing to keep units online, waiting for a spike in capacity prices, may be unwilling to make large capital investments in the case of major mechanical failures.
This long-term outlook, coupled with the region’s winter gas constraints, has driven some increased interest in adding dual-fuel capabilities to existing gas plants, enabling them to burn oil during winter periods when gas prices spike or the units are unable to access gas.
“Given the slowdown on offshore wind and the other changes at the federal level that have really slowed down the scale and the pace of other clean energy entry, there’s been a lot of interest from state policymakers, ISO New England and others about exploring what capabilities exist out there for adding more dual fuel to make up this megawatt-hour gap that may be in front of us,” Dolan said.
Potomac wrote in its report that adding on-site fuel storage to gas-fired resources is “likely the lowest-cost strategy for addressing winter reliability concerns in the near-term in light of the issues with offshore wind development.”
However, there is uncertainty as to whether the states would allow the facility changes, or if the market would support the investments, Dolan said. He added that dual-fuel investments likely would require “over a decade of payback … and years of development to put it into place.”
He noted that the tensions and contradictions between state and federal policy have created significant development challenges for a broad range of resource types.
“It’s a really tricky environment, and I don’t have a clear answer of what to do about that,” Dolan said.
Clean Energy Solutions and Environmental Impacts
The decline in oil generation, and the replacement of inefficient oil and coal units with cleaner gas plants and renewable energy, has coincided with significant reductions in emissions from nitrogen oxides and sulfur dioxide, according to ISO-NE’s 2024 emissions report.
The RTO notes that between 2015 and 2024, sulfur dioxide emissions declined by 82% and emissions from nitrogen oxides dropped by 42%. This compares to a 15% decline in carbon dioxide emissions.
New England annual average emission rates, 2015 to 2024 | ISO-NE
Oil-firing power plants “are among the highest-polluting resources that we have,” said Joe LaRusso, manager of the clean grid program at the Acadia Center. “Many of them are located in communities that are overburdened with air pollution as it is.”
Nitrogen oxides and sulfur dioxide, along with fine particulate matter, are air pollutants associated with a range of heart and lung issues, child asthma, cancer, autoimmune diseases and neurological harm, according to the American Lung Association.
In Massachusetts, these pollutants were responsible for 2,780 excess deaths in 2019, according to Boston College researchers.
While it is difficult to attribute deaths to specific generation types or plants, the study notes that stationary sources, which include power plants, industrial facilities, and heating and cooking, were responsible for about 30% of fine particulate pollution in the state.
Concerns about health effects have motivated grassroots movements to block the development of new peaking plants. In Peabody, Mass., residents fought bitterly and, ultimately, unsuccessfully to stop the construction of a dual-fuel peaker, which came online in 2024.
Any efforts to add oil capacity in the region, or to implement market mechanisms propping up these units, would likely be met with opposition from environmental groups.
LaRusso said he is optimistic that three large projects nearing completion — Revolution Wind, Vineyard Wind and the New England Clean Energy Connect (NECEC) transmission line — will reduce the need for oil peakers, potentially pushing additional units into retirement.
NECEC is intended to supply the region with a consistent source of baseload power, while offshore wind performs best in the winter, when oil units run the most. Clean energy and consumer advocates also hope that aggressive demand-side initiatives will cause load to grow at a slower pace than is projected by ISO-NE.
In the long term, LaRusso said the resumption of offshore wind development in New England, the start of offshore wind development in Nova Scotia and increased bilateral power exchanges with Quebec could help the region meet growing winter demands while eliminating most of the remaining need for oil-fired generation.
“It seems that oil is going to follow the same path as coal, unless the demand curve starts rising so fast that batteries can’t keep up,” he said. “There are so many factors in play, but none of it appears to provide a rosy picture for an oil-firing plant.”
SEATTLE — The longstanding links among U.S. and Canadian electricity grid operators won’t be fractured easily by the tariff-driven political rift between Washington, D.C., and Ottawa, industry participants on both sides of the border say.
“The grid really recognizes no political boundaries,” NERC Vice President of Government Affairs Fritz Hirst said Nov. 10 at the Annual Meeting of the National Association of Regulatory Utility Commissioners in Seattle. He was speaking during a “Northern Exposure” panel discussion moderated by Nevada Public Utilities Commissioner Tammy Cordova.
“Like any other region anywhere on the grid, we have a natural complementarity north and south of the border where different regions depend on each other for energy transfers when needed,” Hirst said. “It’s probably one of the purest examples of the energy partnership we have between Canada and the U.S.”
Hirst noted that while Canada accounts for 10% of North American electricity load, it represents “a critical piece of the pie,” with 30 U.S. states trading power with their northern neighbor to the tune of 70 million TWh per year — enough to power about 6 million homes.
Maine Public Utilities Commission Chair Philip Bartlett pointed to a concrete example of that cross-border relationship: Residents in the northern part of his state receive all their power from either local resources or transmission coming out of neighboring Canadian province New Brunswick.
“For us, this is particularly important, and when we started hearing news of tariffs and concerns about the relationship between the United States and Canada, we got pretty nervous, because these customers are really wholly dependent on the very positive relationship that we’ve built over the years,” Bartlett said.
Bartlett pointed to the lines connecting New Brunswick with the larger ISO-NE system and noted that the New England Clean Energy Connect (NECEC), a 320-kV HVDC line capable of delivering 1,200 MW of Québec hydropower output to Massachusetts, is expected to be completed by the end of 2025.
New England’s relationship with Canada is expected to grow in importance, Bartlett said, in part because of the region’s lack of natural gas pipeline capacity to support new gas-fired plants and the Trump administration’s halting of offshore wind projects. (See Feds Pile on More Barriers to Wind and Solar.)
“Maine and the region had been really expecting to rely on offshore wind as a really important way for us to meet increased load, and also to deal with the expected retirement of some of our older oil plants,” he said. “So given that offshore wind is delayed in the United States, to the extent there are opportunities in Canada to move faster, that is something that could be a real reliability benefit to the region.”
Canada’s Internal Strains
“Yes, it’s hard to be a neighbor to the U.S. right now,” said Francois Emond, a commissioner with Régie de l’énergie du Quebec (part of the Canada Energy Regulator), referring to the tariffs Trump imposed on Canada earlier in 2025.
In laying out the top three challenges he thinks Canada faces now, Emond pointed first to the impact of the trade dispute with its southern neighbor.
“Canada’s economic health is highly susceptible to global political and trade shifts, a vulnerability that’s rooted in its heavy reliance on the U.S. market, with two-way trade accounting for about 65% of the GDP,” Emond said.
Tariffs and other global disruptions — such as supply chain issues — drive up costs for consumer goods and construction materials, including those needed for transmission lines and other energy infrastructure, he said.
The second challenge is the “regional and political divisions” that threaten national unity, with parties in Alberta — and Québec — reviving talk about separating from Canada.
“Tensions persist between regions like Alberta and Ottawa, and Quebec and Ottawa, fueled by disagreements over resource allocation, federal fiscal policy and differing approaches to the energy development and climate actions,” Emond said.
The third challenge has to do with the intersection of climate policy and energy affordability. Emond said that while Canada is committed by law to getting to net zero carbon emissions by 2050, the nation’s carbon tax “has become a lightning rod for political contention, with some provincial leaders calling for its removal, citing its impact on the cost of living and business competitiveness.”
“The priority for the country right now is to build resilience across its trade networks, critical infrastructure and the national unity to prevent increasing domestic and global volatility,” he said.
But even in light of that priority, Emond acknowledged the reality that, from an electricity standpoint, Canada’s provinces are more interconnected to their U.S. neighbors than to each other, a state of affairs he attributes to the country’s internal politics and lack of a national energy policy.
“If any provinces in Canada are saying we’re going to cut power to the U.S. because we don’t like what they’re doing, it’s not possible … the grid is integrated, you cannot do that, and we need also the power coming from the U.S.,” he said.
‘Giant Battery for the West’
Amy Sopinka, director of market policy for Powerex, the power marketing arm of Vancouver-based BC Hydro, said the British Columbia grid is connected to the neighboring province of Alberta and to the Bonneville Power Administration system in Washington, but that 90% of its power trading is with U.S. entities.
Sopinka pointed to the B.C. grid’s contribution to the broad geographical diversity of load and resources in the Western Interconnection: It’s a winter-peaking system compared with the summer-peaking systems in the U.S. Southwest, so its periods of highest demand complement much of the rest of the Western Interconnection. Also, BC Hydro controls about 19 GW of generating resources, including 16 GW of hydroelectric capacity, much of which are storage dams that “can act like a giant battery for the West,” Sopinka said.
“We’ve been both net importers and net exporters over the years,” she said.
Sopinka noted Powerex’s commitment to participating in Western Power Pool’s Western Resource Adequacy Program (WRAP) and SPP’s Markets+, the latter of which is to launch in 2027.
“The Western Resource Adequacy Program is a tool for formalizing the relationship of that resource diversity and demand diversity” for ensuring and accrediting RA, while Markets+ “will allow for the transactions” that support that diversity, Sopinka said.
‘Continental Interconnection’
Cordova asked panelists to share their hopes for the future of the U.S.-Canada electricity relationship.
Bartlett said he hopes for “more integrated analysis” of certain benefits and needs on both sides of the border, as well as “additional partnerships” and the identification of new transmission lines that serve both countries.
“I think the magic wand is we need the [U.S.] federal government to be more encouraging in this effort, because I think it really would benefit the United States in terms of the economic development, [and] the ability for us to build out the renewable resources and other resources that we need, but also do it in a way that is much more reliable and probably a much lower cost, if we can have effective interconnections,” Bartlett said.
But Bartlett also expressed concern that if the U.S. “were to go through two or three administrations like this one, that’s going to make it very difficult for Canadian governments.”
Emond said those in the electric sector might have to look beyond the current challenges to adopt “a more pragmatic way of thinking” that moves beyond politics to identify real needs and “keep discussing,” “making deals” and “do what’s needed for the consumers.”
“We need more generation in North America; that evidence is quite clear as we confront our economic needs [and] the AI race,” Hirst said. “So, I think I would just underscore the need to continue uplifting the North American relationship and truly think of us as a continental interconnection.”
“We have advantages, and it’s best if we can share them all, and then the system becomes more reliable,” Sopinka said.
The Independent Market Monitor has filed a complaint asking FERC to determine that PJM has the authority to hold off on large load interconnections if they would jeopardize transmission security or resource adequacy (EL26-30).
“The question is clear. If PJM has an obligation to provide reliable service to all PJM loads, is it just and reasonable for PJM to add new loads that it cannot serve reliably? The answer to that question is no,” the Monitor wrote in the Nov. 25 complaint.
It argues the proposals PJM and stakeholders made in the recent Critical Issue Fast Path (CIFP) process rest on the faulty assumption that the RTO does not have the ability to turn away large loads even when there is not sufficient capacity to serve them.
The Monitor’s proposal, which received the second-greatest amount of support out of a dozen, would establish a queue for large loads, preventing them from coming online until they could be served reliably. The queue could be bypassed by loads bringing their own generation, with an expedited study process for those resources. (See PJM Stakeholders Reject All CIFP Proposals on Large Loads.)
“The solutions offered by PJM and most stakeholders simply assume that PJM must agree to add large loads to the system when the loads cannot be served reliably because PJM does not have the required capacity resources. From another perspective, the position of PJM and market participants assumes that PJM does not have the authority to require that large new data center loads can be served reliably before those loads are added to the system,” the Monitor wrote.
The Monitor wrote that data center load is the primary driver of a reliability gap that is expected to grow over the coming years. It states that the 2026/27 Base Residual Auction (BRA) was short of the reliability requirement by 200 MW; those tight conditions also caused a $7.3 billion, or 82.1%, increase in auction revenues which would not have occurred without that load growth. (See PJM Capacity Prices Hit $329/MW-day Price Cap.)
PJM spokesperson Jeff Shields said the RTO is reviewing the complaint and does not have any comments before it submits a formal response.
“We have said that higher pricing is being driven by a supply and demand crunch, with the dominant driver on the demand end being data center electricity needs,” Shields added.
Monitor Joe Bowring told RTO Insider the complaint would clarify PJM’s authority to its Board of Managers before it decides on how to proceed with filing governing document changes in the wake of the CIFP.
The complaint makes the case that Order 2000 requires RTOs to maintain a reliable transmission network, which PJM has accomplished through its capacity market and Regional Transmission Expansion Plan (RTEP). If a large load cannot be served while maintaining the reserve margin, PJM should be able to deny interconnection until that can be accomplished.
“Interconnecting large new data center loads when adequate capacity is not available is not providing reliable service. The obligation to provide service is the obligation to provide reliable service. The obligation to provide service is not met if customers are simply interconnected without adequate resources to meet their demand,” the Monitor wrote.
The Monitor made similar comments on a transmission security agreement between Amazon and PECO, arguing that utilities should be required to demonstrate there is sufficient capacity and transmission capability before bringing large loads online. The commission’s Nov. 21 order determined such a demonstration is not needed for agreements between customers and utilities (ER25-3492). (See FERC Approves PECO-Amazon Transmission Agreement for Pa. Data Center.)
The West-Wide Governance Pathways Initiative could lead the charge on developing an alternative to the Western Resource Adequacy Program that would integrate with CAISO’s Extended Day-Ahead Market, according to Pam Sporborg, Pathways co-chair and director of transmission and markets at Portland General Electric.
PGE continues to engage with the Western Power Pool on WRAP’s development. But if the program cannot be aligned with both SPP’s Markets+ and EDAM, Pathways’ Regional Organization for Western Energy (ROWE) could step in as an alternative, Sporborg said in an interview with RTO Insider.
ROWE was created to assume governance of CAISO’s Western Energy Imbalance Market and the soon-to-be-launched EDAM. Some stakeholders have expressed an interest in building the program to offer additional voluntary market services. (See Pathways Initiative Exploring Funding Options, Issues RFP to Staff ROWE.)
An RA program could be one of those offerings if EDAM participants’ concerns about WRAP are not resolved, according to Sporborg.
“An alternative would be to have an RA program that was governed solely by the Pathways’ new regional organization that would be more integrated into the EDAM,” Sporborg said. She noted the alternative must “provide enhanced value for PGE and PGE’s customers and other Western utility customers.”
Her comments came after the Oct. 31 deadline for entities to commit to WRAP’s first financially “binding” season covering winter 2027/28. The final WRAP commitments showed the program has mostly been divided along the line of participants in CAISO’s EDAM and SPP’s Markets+.
Among the five utilities withdrawing from the WRAP, four — NV Energy, PacifiCorp, PGE and Public Service Company of New Mexico — have committed to joining the EDAM, while Eugene Water & Electric Board will be participating in Markets+ by virtue of its location within the Bonneville Power Administration’s balancing authority area.
Of the 16 committed to the first binding season, 11 are slated to join Markets+, two are leaning to EDAM and three are uncommitted to either day-ahead market. (See WRAP Wins Commitments from 16 Entities.)
The divide and the fact that WRAP is a program requirement for Markets+ has raised concerns about the program’s governance structure, Sporborg said.
Markets+ will gain a larger share of the voting power, “and we need to see and understand how that governance will evolve to ensure that we can be confident that the program will remain equitable for EDAM entities,” she said.
Another issue is that WRAP was conceived before day-ahead markets in the West, and the program was intended to work within a different footprint from the one emerging under Markets+ and EDAM, according to Sporborg.
WRAP is realigning its operations program to reflect the day-ahead market reality. This will “fundamentally change” what the planning reserve margin is and what the diversity savings are, Sporborg said.
“We don’t have enough information right now to make a financially binding decision based on that realignment,” she said.
PGE listed its concerns in an Oct. 29 letter to the Oregon Public Utility Commission. The utility pointed to efforts by the WRAP’s Planning Reserve Margin Task Force to evaluate new methodologies for setting planning reserve margins for program participants, as well as concerns about the technology underlying the program.
“Before we can commit to a financially binding program that has financial penalties for withdrawal; financial penalties for noncompliance; and the risks that that would put our customers on, we want to actually see how those design evolutions materialize,” Sporborg said.
Talk of an alternative RA program has been ongoing since at least Oct. 21, after NV Energy said during a hearing before the Public Utilities Commission of Nevada that it is discussing the option with other EDAM participants.
“It’s a consistent and expected result that the bigger your footprint, the more connected your footprint, the more savings that you can achieve through that diversity,” Sporborg said.
But the study also suggested there are savings to be made in a separate EDAM-aligned RA program, according to Sporborg.
“So, that gives us the confidence that we can continue to work with the [Western] Power Pool on the market alignment but also help us understand that if we can’t find a solution that is equitable to the EDAM, we could pursue this alternative and not be worse off than we would from that geographic WRAP perspective,” she added.
Pathways’ potential RA role was suggested by Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition, during an Oregon PUC meeting Nov. 25 about the state’s RA program and WRAP. (See related story, Oregon PUC Votes to Waive RA Penalties for Independent Suppliers.)
Gray noted Pathways eventually could offer several “new solutions and services in the West.”
“There’s a good regional solution here that takes advantage of both load and resource diversity in multiple time zones and multiple latitudes,” Gray said about Pathways. “And that was the value proposition of WRAP. That’s the value proposition of both Markets+ and EDAM.”
When asked how WPP is working to address EDAM entities’ concerns about WRAP, organization Chief Strategy Officer Rebecca Sexton said, “With the commitments for 2027/2028, we are focused on binding operations and have a lot to do to get ready for that.
“The results of that work should improve the program and benefit our committed participants, as well as any participant who chooses to return,” Sexton told RTO Insider in an email.
The grid was never designed for the world it’s being asked to serve. Electrification is accelerating faster than planners expected; extreme heat is swelling peak demand; and climate-driven disasters are smashing records while breaking infrastructure.
Yet the electric industry is expected to build a grid that can deliver reliable power to regions that may succumb to, survive or even thrive in a future further affected by climate change.
Planning for the grid of the future requires increasingly sophisticated prognostication, and the industry needs to look to new data sources for modeling. Climate scientists and economists have become as important as engineers, and traditional peak-demand forecasts and resource-adequacy models cannot capture the compound stresses facing today’s grid.
Wayne Gretzky famously said he “skate[s] to where the puck is going to be, not where it has been.” That’s all very well if you know where it’s going to be — difficult for a puck, even more so for a grid being expanded in an environment some call a polycrisis.
Dej Knuckey
Utilities and regional planners no longer can rely on models built for a more stable, predictable climate, one that no longer exists. To build a grid that is both reliable and resilient, planners now need modeling tools that integrate growth patterns and climate risk. The next generation of modeling — probabilistic, scenario-based, climate-informed — is not simply an upgrade. It’s becoming the minimum requirement for any utility, regulator or investor hoping to keep pace with the world in which the grid must operate.
A new measure launched in November by the First Street Foundation may prove a critical tool for understanding the intersection of climate risk and economic growth.
Understanding Resilience Spread
Resilience Spread, a concept coined by First Street, captures the intersection of two opposing forces, like Dr. Doolittle’s fictitious Pushmi-Pullyu, a double-headed llama that tries to move in two opposite directions at once. In one direction, there are positive market forces, reflected in population growth, economic strength and amenities such as housing and transportation. In the other direction, there are negative climate risks.
Resilience spread growth trajectories across global cities with 1 million or more residents | First Street
The Resilience Spread quantifies the gap between a region’s climate exposure and its ability to adapt. It’s a gap that is widening in many areas, creating a patchwork of vulnerability. Looking at 400+ of the world’s major cities, First Street determined that economic strength is outweighing climate risk by a massive $1.8 trillion globally, which “illustrates that, on average, strong macroeconomic conditions and consumer confidence continue to offset the drag of climate hazards,” the report said.
But the average is meaningless for planners. What’s important is how individual cities are expected to perform, and that ranges widely. And there’s also the factor of time. While today’s global spread is net positive, “this cushion is not permanent. Without significant adaptation, the spread is projected to erode steadily, tipping negative before the end of the century as climate pressures intensify faster than foundational macroeconomic conditions.”
The speed at which we lose the economic buffer depends on how we invest in adaptation. The firm predicts that unless those investments are substantial, the global spread will be eroded fully by 2085, “as intensifying hazards outpace resilience.”
The Many Faces of Climate Risk
Climate risk comes in many flavors. The U.S. Climate Vulnerability Index map, developed by the Environmental Defense Fund and Texas A&M University, drills down on the various climate risks and impacts in each county or census tract. It maps extreme events, such as storms and droughts (see our series on the effects of extreme climate events on the grid: fire, flood and heat), as well as impacts such as heat-related deaths and other factors such as air pollution and socioeconomic stressors.
Climate vulnerability is a function of both community resilience and climate change risks. | U.S. Climate Vulnerability Index
The index accounts for an essential piece of the resilience equation: If an area already is struggling, it is less likely to withstand the challenges posed by climate change.
First Street distinguishes between chronic and acute risks: “Chronic risks reflect long-term, gradually intensifying physical climate stressors such as heat, drought or sea level rise, while acute risks capture short-term, high-intensity events like floods, storms or wildfires.”
For grid planners, chronic risks are easier to plan for, and the grid can be hardened to resist them in advance, but acute risks are more likely to damage significant portions of the grid, providing the opportunity to rebuild in a more resilient way.
Growth in All the Wrong Places
Why, in a world where we’ve known for a few decades that climate change will adversely affect major economic centers on the coasts, are some of the biggest economic centers also the most at risk of climate damage? Because many of the biggest cities were located at trading hubs, which historically were at deep ports. First Street found what it called a “striking paradox.” Of more than 400 major global cities, “over half of global urban GDP is concentrated in places facing the highest levels of acute climate risk.”
A city’s attractiveness as a place to live and do business can survive high climate risk, according to First Street. “Many of the world’s most economically productive cities remain hubs of growth despite sitting in the top quartile of acute risk.”
Miami is an example of a city that is both one of the world’s most productive, high-growth cities and among the most exposed to climate events, such as sea-level rise, heatwaves and hurricanes. Despite being in the top percentile of climate risk, its economic strength is buoyed by amenities ranging from a strong labor market to the desirability of living near wide sand beaches.
In cities like Miami, where the market effect outweighs the climate effect, First Street’s resilience spread is positive.
“These positive spreads imply that markets potentially undervalue their opportunities relative to climate risk, highlighting a hidden upside, as capital inflows remain strong and long-term attractiveness endures.” For planners, that resilience spread can be used as a factor to adjust growth models upwards.
They also caution that the spread today is looking forward from one point in time. “Resilience is not fixed. Cities that thrive today may falter tomorrow if climate risks intensify … and begin to outpace the economic foundations that support their growth.”
When the Resilience Spread is Negative
On the other end of the spectrum, a negative resilience spread occurs when the negative climate effect exceeds the positive market effect. “Climate risks’ impact on location desirability already outweighs local economic strengths in roughly 30% of global cities today,” First Street found.
New Orleans is an example where its role as a strategic port and its cultural significance fail to counterbalance the impact of its exposure to acute climate risks, most notably hurricanes and the resulting flooding.
Repeated extreme storms, including Hurricanes Katrina in 2005 and Ida in 2021, “have driven steady population decline, unaffordable insurance rates and insurer withdrawal, resulting in a deep negative resilience spread of -10.3%,” First Street said.
New Orleans is an example of a U.S. city where the market effect is lagging the climate effect, leading to a negative resilience spread. | Dej Knuckey using data from First Street
For cities such as New Orleans, grid planners face a difficult calculation: how much to invest in the grid’s resilience where climate threats are substantial and population is declining.
There is a risk that a deep understanding of climate risk modeling will lead to inequity. When there are so many competing capital investment demands, it can be tempting to deprioritize regions with weak adaptive capacity where any investments face greater risks from climate damage or economic decline. Yet those areas may depend most on investments today to withstand future challenges. Until there are discussions about managed retreat from the most climate-vulnerable areas — a topic few political leaders are willing to touch — policies must support the vulnerable communities as well as the well-resourced areas.
System Strength and the AI Demand Growth Wild Card
The market effect and climate effect are just two of the plethora of factors that planners need to consider. Infrastructure fragility — the ability of each part of the grid to withstand acute and chronic climate risks — is another key variable that will be the topic of a future column. And population trends also are key in a time of increased climate migration.
Perhaps the largest factor outside of climate change that is complicating grid planning is the rise of data centers, especially AI data centers, which weren’t foreseen only a decade ago. It has moved forecasts that had been flat to negative into positive territory. S&P Global Commodity Insights anticipates U.S. electricity consumption “to grow at a compound annual growth rate of more than 3% from 2025 to 2030, with generation in tow.”
That demand is not spread evenly throughout the country but is lumpy with intense localized demand in the areas where they are being built. Northern Virginia is the poster child for unexpected load growth, with 70% of global internet traffic carried by the more than 200 data centers in the county, according to Oxford American. As RTO Insider columnist Peter Kelly-Detwiler pointed out recently: “These facilities are large (often well over 100 MW), disconnected from the general macroeconomic environment and extraordinarily difficult to forecast.”
Investing in Foresight
With so many competing factors shaping the grid of the future, utilities, ISOs and regional planning entities will need to invest in data infrastructure and modeling capabilities, building internal capabilities and accessing external expertise as needed. A key part of this will be ensuring acute and chronic climate risks are understood and accounted for, both in cities and rural areas, and in high-risk and high-growth areas.
The competing forces of market strength and climate vulnerability vary within any territory served by each utility, grid operator or policy body, and there’s no single approach to planning that serves communities at opposite ends of the resilience scale. But all areas will be served better by industry and policy leaders who insist on, and invest in, advanced modeling.
Without smart, sophisticated modeling, planners will be flying blind—and costs, blackouts or inequities will be the price.
Power Play columnist Dej Knuckey is a climate and energy writer with decades of industry experience.
