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March 11, 2025

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PJM PC/TEAC Briefs: March 4, 2025

Planning Committee

PJM Presents Changes to DESTF Issue Charge

PJM’s Chen Lu on March 4 presented the Planning Committee with a draft amendment to the Deactivation Enhancement Senior Task Force’s (DESTF) issue charge to add a key work activity (KWA) focused on creating pro forma language for reliability-must-run agreements with generation owners seeking to deactivate a unit identified as being necessary for reliability.

The new language seeks a proposal that would be effective for the 2028/29 delivery year, which is the tail end for a temporary measure allowing some resources operating on RMR agreements to be counted as capacity if they meet certain requirements (ER25-682). Approved by FERC in February, the temporary change allows resources that PJM believes can act as capacity to be counted in the supply stack for the 2026/27 and subsequent Base Residual Auction. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.)

While PJM will ask the Markets and Reliability Committee to vote on the changes during its March 19 meeting, Lu brought the language to the PC, Market Implementation Committee and Operating Committee during their March meetings to provide stakeholders with advance notice.

Paul Sotkiewicz, president of E-Cubed Policy Associates, asked Lu why PJM had reversed its earlier position that RMR agreements should be out-of-scope for the DESTF. He stated that RMR agreements are different from other areas the task force has focused on because they are specific to transmission security, not market design.

Lu responded that there are relevant issues around RMR agreements, such as the operational parameters needed to maintain reliability and on the markets side what is needed to count those resources as capacity. PJM believed a senior task force was the best forum rather than a standing committee.

Speaking during the MIC meeting March 5, Philip Sussler, of the Maryland Office of People’s Counsel, and Clara Summers, of the Illinois Citizens Utility Board, questioned whether the added work item would impact the ability for the task force to proceed with KWAs exploring alternatives to RMRs, an addition to the issue charge the two consumer advocates sought to have included in 2024. (See “Stakeholders Approve Generation Deactivation Issue Charge,” PJM MRC/MC Briefs: Sept. 20, 2023.)

Other work areas include education on alternatives to rebuilding transmission assets when generation deactivations would trigger reliability violations, such as reconductoring or the deployment of grid-enhancing technologies; developing alternatives to RMR agreements; and accounting for any changes stakeholders and the RTO may make to its capacity interconnection rights transfer process.

Transmission Expansion Advisory Committee

Market Efficiency

PJM’s Nicolae Dumitriu presented the Transmission Expansion Advisory Committee with an update on the RTO’s 2024/25 long-term market efficiency window.

The congestion drivers behind the analysis were identified through base cases pairing the 2024 load forecast with the expected grid topology in 2029 and 2032. An additional sensitivity was included examining how increased load identified in the 2025 forecast could impact the 2029 case to allow PJM to right-size the solutions built on the two base cases.

The inclusion of the 2024 Regional Transmission Expansion Plan (RTEP) Window 1 slate of grid updates mitigated 13 constraint overloads that prevented the market efficiency analysis from being able to calculate interface limits, in addition to reducing congestion on several lines. The remaining congestion is largely located along the PJM/MISO border. PJM also included planned resources sorted into the fast-track study queue and those with suspended interconnection service agreements (ISAs) to the analysis to allow it to meet the expected 17.8% reserve requirement.

The preliminary congestion drivers identified include the 138-kV Museville-Smith Mountain line in the AEP zone, which has $39.7 million of congestion in the 2029 base case and $51.5 million in the 2032 case; the 115-kV West Point-Lanexa line in the Dominion zone, which has $1.2 million of congestion in 2029 and $1.3 million in 2032; and the 115-kV Garrett-Garrett Tap line in the APS zone, which has $1.8 million in 2029 and $2.4 million in 2032.

PJM’s Nicholas Rodak said the next step is finalizing additional sensitivities and the models for the 2025, 2029, 2032 and 2035 simulated years.

Tightening Supply and Demand Impacting RTEP Planning

PJM’s Wenzheng Qiu presented stakeholders with an update on the assumptions being developed for the 2025 RTEP analysis, which includes an expectation that existing generation and planned resources with signed ISAs will not be sufficient to meet loads in 2030.

Window 1 will include the 2025 load forecast, which includes 16 GW of growth in 2030 above the prior year’s forecast.

The five-year analysis of the balance between load and generation finds that peak loads could be met with the addition of projects with suspended ISAs, fast-lane queue projects, the Chesterfield Energy Reliability Center planned in Virginia and the Coastal Virginia Offshore Wind project, albeit with a loss-of-load expectation of 1.6 days per year. If the 2,308 MW of offshore wind planned in New Jersey and 255 MW in Delaware are not completed, the LOLE would increase to two days per year, 20 times higher than the one-in-10 benchmark.

If all those projects are included in the seven-year base case, Qiu said the 2032 LOLE would be 2.3 days per year. The seven-year case is being included in the analysis to identify projects that could be right sized for long-term needs.

PJM’s Sami Abdulsalam said resources with suspended ISAs and fast-lane projects are being included in the RTEP analysis to allow the amount of available generation to meet peak loads. The point of interconnection for those projects is being set at the nearest bus at 500-kV or higher to avoid impacts to lower-voltage facilities. The seven-year case also includes all projects being studied in Transition Cycle 1 and 2, which will also be modeled on the high-voltage backbone network.

Responding to stakeholder questions on how any network upgrades required for those generation projects will interact with the RTEP needs, Abdulsalam said the seven-year case will inform the solutions chosen to resolve the five-year needs. Not all network upgrades expected to be completed in the latter analysis will be included in the five-year case, so any such upgrades would be removed.

Supplemental Projects

FirstEnergy presented two projects in the ATSI zone to address transmission overloads and congestion identified in MISO’s Long-Range Transmission Planning process (LRTP) and support projects in the 2024 MISO Transmission Expansion Plan.

The first would construct a 20-mile optical fiber line between the Lemoyne and Toledo Edison substations and replace line relaying at Lemoyne at a $15.6 million cost. The second would install 7 miles of fiber from Toledo Edison to the Lallendorf substation, where line relaying would also be replaced, at a $5.9 million cost. The overall $40 million project is in the conceptual phase with a projected in-service date of June 1, 2032.

FirstEnergy also presented three projects to replace transformers in the JCPL zone for maintenance issues and the infrastructure approaching the end of its useful life. The 230/115-kV Whippany transformer No. 12 is about 66 years old and has had problems with leaking oil and nitrogen gas; the unit, associated relaying and substation conductor would be replaced at a $8.1 million cost, with an in-service date of March 7, 2030.

The 230/34.5-kV Chester transformer No. 4 is nearly 46 years old and has been reading elevated ethane gas in its oil. Replacing the transformer, a 230-kV circuit switcher, 34.5-kV breaker and limiting terminal components would cost $7.3 million with an in-service date of Dec. 31, 2029. The 230/34.5-kV Chester No. 1 would also be replaced, as it was installed about 60 years ago and there are signs of degrading insulation. Its replacement would cost $7.3 million, which includes a 34.5-kV breaker and limiting terminal components.

FirstEnergy presented a $12 million project to replace the control building at its Glade substation in the Penelec zone. The building is 56 years old and degrading, with rusting walls and broken windows. Several line ratings are also limited by terminal equipment. Several other components of the substation would also be replaced, including: four disconnect switches, two 230-kV breakers, and substation conductor and the line trap on the 230-kV Lewis Run-Warren line. Substation conductor and terminal equipment would also be replaced at the utility’s Warren and Lewis Run substations. The project is in the conceptual phase with a projected in-service date of Dec. 17, 2027.

American Electric Power presented a $173 million project in its zone to connect LRTP Tranche 2 projects to the PJM grid. While the full cost would be assigned to MISO customers, there could be impacts to the PJM grid, so AEP determined to submit them as supplemental projects to be studied for any transmission violations. No “large-scale issues” have been determined, AEP said.

The Sorenson substation would be reconfigured to terminal two new 765-kV lines to the Greentown and Lulu facilities, and four new 345-kV lines would be terminated at the Sullivan substation, with two running each to Fairbanks and Dresser.

Several lines would also be modified to cut into new substations:

    • the 765-kV Sullivan-Rockport line would cut into a new Pike County substation;
    • the 765-kV Jefferson-Greentown and 345-kV Tanners Creek-Hanna lines would both cut into the Gwynneville substation;
    • the planned 345-kV Gwynneville-Tanners Creek line would cut into the existing Batesville substation;
    • the 345-kV Fall Creek-Sunnyside line would cut into a new Madison County substation; and
    • the double-circuit, 345-kV Olive-University Park and Olive-Green Acres lines would cut into the 345-kV Babcock substation.

Exelon presented a $874.2 million project to extend two 765-kV lines from ComEd’s Collins substation, which would also be expanded, to interconnect with projects in MISO’s Tranche 2.1 portfolio. All costs associated with the project would be allocated to MISO.

A new 765-kV Woodford County substation would be built in the MISO grid as part of the project, which would cut into ComEd’s 345-kV Powerton-Katydid and Powerton-Nevada lines. Two 300-MVAR line reactors would be installed at Collins, along with associated circuit brakers for each new line.

Exelon also presented a $40 million project in the ComEd zone to construct a new 345-kV substation, named Eldamain, to serve a new customer bringing 600 MW to the area of its Plano substation. The new facility would be cut into the 345-kV LaSalle-Plano line with 0.4 miles of new double-circuit line. The project is in the engineering phase with a projected in-service date of June 1, 2029.

Dominion Energy presented a $30.6 million project to rebuild 10.3 miles of its 230-kV Shawboro-Elizabeth City line as it approaches its end of life, having been built with wooden H-frames in 1975. The project is in the engineering phase with an estimated in-service date on Aug. 31, 2025.

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PJM MIC Briefs: March 5, 2025

Offer Capping Resources with Advance Commitments

VALLEY FORGE, Pa. — The PJM Market Implementation Committee endorsed by acclamation an RTO-sponsored issue charge to consider changes to how resources committed in advance of the day-ahead market are offer capped. 

Out-of-market commitments have taken on extra significance in recent months as PJM acted ahead of winter storms to schedule additional resources it believed would be necessary to maintain transmission security but had been identified as being at risk of not being able to perform on short notice. That often took the form of resources with limited ramping capability and gas generators that could have difficulty procuring fuel. (See PJM: ‘Conservative Operations’ Maintained Reliability During Jan. 2024 Storm.)  

The first phase of the issue charge envisions governing document revisions on the scheduling practices of resources committed before the day-ahead market is run and how they may be offer capped; market power mitigation for those resources is also included. The second phase focuses on adding language fuel expenses in the cost-based offers for units with advance commitments. 

The issue charge was revised during the meeting to consider how advanced commitments can impact uplift payments, spell out the timeline for the two phases and designate the Reserve Certainty Senior Task Force (RCSTF) as the forum to coordinate the discussions. 

Responding to stakeholder questions regarding whether the issue charge seeks to formalize a practice of making out-of-market commitments on holiday weekends, PJM’s Phil D’Antonio said staff plan to discuss the approach operators will take in greater depth at the RCSTF. The next task force meeting is March 12 and is set to include discussion of how winter storms impacted “operations and market outcomes.” 

Adrien Ford, director of wholesale market development for Constellation Energy, said the company would be abstaining from the vote because it does not support PJM taking out-of-market actions. Instead, she said stakeholders’ focus should be on getting the markets right so these actions don’t have to be taken. Constellation did not vote in opposition because she said it believes that if PJM is going to continue the practice, there should be rules in place governing how operators act. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, said PJM should hold a special session to discuss the intersection of all the issues related to how the gas and electric markets interact. Otherwise, he said, this proposal and the other disparate stakeholder efforts will not yield comprehensive results. “These are really crucial issues from an operational and markets standpoint.” 

PJM Director of Stakeholder Affairs Dave Anders said the RTO has a desire to move forward on phase 1 quickly and that he believes the issues Sotkiewicz raised pertain to phase 2. He suggested the RCSTF could provide a venue to discuss those issues. 

“I think that is directly in the wheelhouse of the RCSTF,” Anders said. “I get this idea of wanting a holistic review of everything in one spot and trying to figure out where that is in the manuals. A senior task force is the best place for that to happen.” 

Periodic Review of Manual 11 Deferred

Stakeholders delayed voting on revisions to Manual 11: Energy & Ancillary Services Market Operations following uncertainty around the implications of designating data centers as “plug load.” 

The language was drafted through the periodic review of the manual, which resulted in changes that PJM’s Joseph Tutino said were mainly typographical. 

Independent Market Monitor Joe Bowring questioned why data centers should be sorted alongside household appliances like washing machines. 

“Data centers are obviously a key issue, and considering them as a regular plug-in load doesn’t seem like the answer,” he said. 

PJM’s Maria Belenky said data centers are considered plug load for the purpose of curtailment service providers (CSPs) reporting load enrolled in demand response. The manual does not contain specific guidance for how that load should be categorized, and while it may not be the perfect approach, she said it reflects ongoing practice. 

“It is something that is currently done, and it’s to provide appropriate guidance for CSPs,” she said. 

First Read on Proposal to Overhaul Uplift

PJM and the Monitor presented a joint proposal to rework how the RTO determines when a unit is following dispatch and the process for assigning corresponding uplift payments or deviation charges. (See PJM Stakeholders Mixed on Uplift Proposal.) 

PJM’s Lisa Morelli said the changes seek to resolve an issue where resources instructed to ramp down could instead keep their output flat and nonetheless receive uplift payments. That is because the dispatch signals are ramp-limited and the balancing operating reserve (BOR) credit structure only considers whether a market seller followed dispatch for individual five-minute intervals. She gave an example of a unit operating at 100 MW being dispatched down to 95 MW in accordance with its ramp rate. If that unit ignored the signal and stayed at 100 MW, it would not exceed the 10% margin that defines when a unit is deviating from dispatch. Additionally, because dispatch is limited by ramp rates in the next interval, PJM could only bring it down to 95 MW again.   

The proposal would establish a Tracking Ramp Limited Desired MW (TRLD) metric that follows what a unit’s output would have been if it had followed dispatch over time. In Morelli’s example, the TLRD would continue to fall by an additional 5 MW for every interval that dispatchers sought less energy from the resource. 

The TRLD would replace the ramp-limited desired, dispatch and LMP-desired metrics currently used in the BOR credit and deviation formulas, which would seek to make resources whole to the costs they incurred with uplift limited by the output they were instructed to produce based on the TRLD metric. 

Morelli said the status quo formula is overly complex and would be simplified by calculating the BOR credits a resource would receive under the lesser of the TRLD and its actual real-time output. This would also remove punitive impacts that market sellers could experience when asymmetric inputs are used in the current formula. 

The proposal would also revise the start and end points for uplift eligibility to correspond with when a resource’s commitment began and the end of its commitment or minimum run time. 

Joel Romero Luna, a market analyst with the Monitor, said eligibility for BOR credits is currently defined according to the subjective phrase “operating as requested by PJM,” which has been interpreted differently by the Monitor and RTO. The Monitor’s position is that one is either eligible to receive uplift when it follows dispatch or not eligible if it does not follow instructions. 

Tom Hyzinski, of GT Power Group, questioned whether a market seller that changes its parameters to reflect changes in a resource’s flexibility would be held to the original or updated values. 

Romero Luna said the proposal changes how a resource that changes the flexibility of its parameters by more than 5% is treated to be dispatched according to its ramp-limited signal, instead of the LMP-desired signal that is not ramp limited. The economic minimum and maximum parameters would remain based on the original parameters at the time of commitment, while the ramp rate and offer parameters would be based on any updates the market seller makes. If a unit submits flexible parameters, but becomes inflexible and does not update, it would be penalized for not following dispatch. 

Implementation of the proposal would be phased to start with simulated settlement results being provided to market participants in late 2025 so they can become familiar with how the changes function, with rollout affected actual settlements around a year later. 

The MIC is scheduled to vote on the changes April 2, followed by the Markets and Reliability Committee on June 18 and the Members Committee on July 23. Morelli said the proposal would require tariff revisions, which might take long enough to draft to not be finalized by the time the MRC is asked to endorse the package. In that case, a special meeting for a page turn or a second vote may be sought. 

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Overheard at Yes Energy’s EMPOWER 25

DENVER — The Trump administration, pending ERCOT market changes, the future of wind power generation and uses for artificial intelligence were recurrent themes at Yes Energy’s annual summit, EMPOWER 25, held March 5-7. Here’s some of what we heard.

Trump Administration Shakes Things up

Former FERC Chair Pat Wood III, CEO of Hunt Energy Network, was among the speakers expressing concern over President Donald Trump’s first few weeks in office.

“There’s a lot of things I like about the last six weeks, but some that I don’t, like taking treasured institutions and kind of hitting a wrecking ball to them. FERC is one of those,” he said. “I think FERC will be fine. I’ve seen the statements of the new chairman there being pretty supportive of being able to work all this out, and yet I know some quality people are leaving the organization, and I do worry about the loss of that institutional knowledge that has really made markets work seamlessly and work more effortlessly than they probably should have, because you had the right people there.”

Sonya Gustafson, general manager of data services for Equilibrium Energy, which uses AI to optimize energy portfolios, said she is concerned over the potential loss of data compiled by EPA, the Energy Information Administration and other federal agencies.

“One of my biggest challenges is access to as much information as possible; that allows us to create accurate renewable energy forecasts,” she said. “The threat of that going away does create a little bit of nervousness. We’re fortunate in that for weather, we can go potentially to European models, but at the same time, it does create a shift in our businesses. So that’s been top of mind recently: making sure I’m archiving as much as possible and finding secondary and third sources for a lot of the information we need to fully optimize.”

“The uncertainty is really high right now,” said Emma Konet, CTO of Tierra Climate, a marketplace for grid-scale batteries to sell carbon offsets to corporate buyers. “I think developers with projects in various stages of the interconnection queue are now a little bit uncertain about what the [investment tax credit] is going to look like — and maybe it’s going away.”

She said although falling battery costs have driven a lot of battery deployment in California and ERCOT, the ITC will be needed for widespread deployment in MISO and SPP. “So I definitely think that’s a risk.”

Cliff Rose, senior product manager for Yes Energy (left), moderated an EMPOWER 25 panel on power market dynamics impacting asset development with Ryan Hakim, Cordelio Power. | Yes Energy

Leah Kaffine, senior director of integrated energy systems planning for Pattern Energy Group, which operates wind, solar, transmission and energy storage projects, expressed concern over the fate of the Inflation Reduction Act and the Department of Energy. “Pattern Energy, as a developer of transmission … we hope that maybe that will be spared,” she said.

Independent consultant Evan Bixby, former vice president of strategy and analytics for Pine Gate Renewables, said he is concerned over tariffs and supply chain risks. “Just the overall attitude of the federal government towards renewables is a little bit threatening,” he said. “I’m very confident in the renewable energy industry. It’s weathered storms before, and it’s a very creative, very passionate, very driven industry. So, [I’m] confident that we will be able to figure it out. But that doesn’t mean that there won’t be headwinds.”

Anticipating ERCOT Market Changes

ERCOT’s real-time co-optimization and battery project (RTC+B), set to go live in December, was mentioned at the conference frequently.

“We’re in a little bit of purgatory right now,” said Drew Peine, vice president commercial for Hunt Energy Network, which is building energy storage in ERCOT.

“We’re going into this kind of unknown with RTC+B. You’ve got the day-ahead markets that are going to be financial, both energy and ancillary products, and then you’ve got that five-minute optimization on top of it. ERCOT is writing the rules as we speak. [It is] a little bit frustrating that we don’t have all the rules right now [that] we need to start, but we’re participating in that process with our regulatory team trying to understand what ASDC [ancillary service demand curve] is, first of all, and then what it means for our optimization. And … we need to be there on that Day 1.” (See ERCOT TAC Opens Discussion on Proposed RTC Changes.)

Gustafson predicted an “exciting” first couple months. “Whenever there’s new products launched, there’s more volatility. Later on, we may see slightly more depressed prices, but I’m excited for the first three or four months.”

EMPOWER

Also on the power market dynamics panel were (left to right) Judd Rogers, Scout Clean Energy; Evan Bixby, Bixby Analytics; and Leah Kaffine, Pattern Energy Group. | Yes Energy

“A lot of people, I don’t think, fully appreciate how dynamic this market’s going to be, and they’re going to be kind of stuck in their old ways,” Peine added.

“What’s really interesting is, once we get to real-time optimization, they have nothing to train on. We have no real-time price data for ancillary services,” Konet said. “So, I think that’s going to be a really interesting dynamic.”

Uses of Artificial Intelligence

AI isn’t just driving data center growth, speakers said. It’s also taking an increasing role in the work lives of power professionals.

“I think I spend more time talking to ChatGPT than to any human in my life right now,” Gustafson said. “It’s an awesome platform to learn, and it’s something that I use every day when I’m developing code. It makes me faster.”

“Asset optimization has been around forever. But I think where AI and [machine learning] and these kind of neural net type models can really come in is in the inputs to those optimizations,” Konet said.

Peine said AI will become increasingly important. “The amount of data that we consume is phenomenal; I just cannot believe how much data we consume on a daily basis,” he said.

EMPOWER

Jesse Carver, Yes Energy (left), moderated a panel on batteries in evolving markets with (from left): Emma Konet, Tierra Climate; Sonya Gustafson, Equilibrium Energy; and Drew Peine, Hunt Energy Network. | Yes Energy

Peter Kelly-Detwiler, co-founder of NorthBridge Energy Partners, said he uses Perplexity AI regularly — but still reads 44 newsletters, up from 42 with the recent addition of two on data centers.

“People have told me, ‘Why the heck do you read 42 newsletters — now 44 — and scan all that instead of teaching an AI tool to give you what you need?’ My answer is, I don’t trust yet that I’m going to ask it the right things to look for. And so much of my learning is still accidental.

“When I used to go into a library, the book that I was looking for was not the one that was usually the most valuable to me. It was next to it in the stack, in the adjacencies. And I still enjoy the accidental adjacency, because that’s when I find so many of the things I didn’t know were going to be valuable to me. And I’m afraid of taking my AI lens and making it so narrow that I build biases into it that exclude the broader world that I need to look at, especially for the data that’s going to come slamming into my head and destroy a paradigm that I thought I knew. I love when that happens.”

Future of Wind Generation

Wind development has fallen way behind solar in generation growth, but it will remain an important player, speakers said.

According to EIA, a record 30 GW of utility-scale solar was added to the U.S. grid in 2024, 61% of all capacity additions. Battery storage also hit a record last year, adding 10.3 GW. EIA predicts an additional 32.5 GW of utility-scale solar and 18.2 GW of utility-scale battery storage in 2025.

By contrast, wind added only 5.1 GW last year, the smallest amount since 2014, with slightly more (7.7 GW) expected in 2025.

“Wind is a lot harder to develop,” said Ryan Hakim, vice president of commercial and corporate strategy for independent power producer Cordelio Power. “You need a lot of acreage. … There’s a lot of things that can kind of go wrong. But if you are able to take a project to completion, there is quite a lot of demand for that product just because … it profiles generally the opposite of solar.”

“One of the reasons why we don’t see as much wind development is there’s a lot of sites that have been picked over,” he added. “But another thing to consider is, we’ve got more technology where you can build bigger turbines, higher towers; where you’re able to extract some of the wind in places where you previously hadn’t. And so I think there’s new regions that are also opening up.”

“Solar and batteries pretty quickly saturate themselves, whereas wind diversification as a species will always be highly valued,” agreed Kaffine. “And I think, yeah, people find it refreshing and different.”

“You can’t do it all with just one technology,” Bixby said. “You can’t do it all with solar and batteries. [You] probably could, but you need to overbuild by a lot. So you need wind in there. … You’ll need advanced geothermal. You’ll need new types of battery storage technology. You’ll need advanced controls to be able to manage all of it [and] new market mechanisms to pay for it.”

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

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

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

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

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

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

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

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

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

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

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

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

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

‘Foundational Investment’

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

load

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

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

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

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

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

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

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

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

Evan Bixby | Bixby Analytics

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

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

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

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

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

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

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

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PJM OC Briefs: March 6, 2025

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

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

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

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

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

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

Stakeholders Resume Discussions on SATA

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

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

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

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

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

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

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

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

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

February Operating Metrics

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

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

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

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

SOS Updates

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

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

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

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

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PJM Stakeholders Endorse Changes to Black Start Compensation

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

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

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

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

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

PJM Monitor Joe Bowring | © RTO Insider LLC

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

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

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

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

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

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

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

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

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

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

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

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

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NYISO Stakeholders Debate Purpose of Capacity Market

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

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

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

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

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

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

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

Caplan said that NYISO and the stakeholders needed to accurately consider how the market was actually 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 was already heading. Zachary Smith, senior manager of capacity and new resource integration, said the ISO was considering Younger’s proposal and how it would impact things like collateral requirements for small loads.

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Moody’s Forecasts Long-term Population Downturn in NY

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

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

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

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

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

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

Thomas went on to explain that even if the overall stock of vehicles declines because of population loss, there would still 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 that there will be about 6 million electric vehicles on the grid consuming 30 TWh of electricity. 

Building electrification is also 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 that 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 that 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.”