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December 15, 2025

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CAISO Postpones EDAM Congestion Revenue Decision

CAISO has delayed its final decision on how to allocate congestion revenues in its Extended Day-Ahead Market (EDAM) after receiving comments from stakeholders asking for more analysis. 

CAISO planned to vote on its draft final proposal in late May but decided to hold off until June. Adjusting the proposal’s planned approval date has “allowed us to further explore additional enhancements suggested by stakeholders,” said Anna McKenna, CAISO vice president of market design and analysis, at a May 20 WEM Governing Body meeting. 

The congestion revenue initiative is a top priority for CAISO in 2025. The organization received comments from PacifiCorp that questioned the way congestion revenues will be allocated in the proposed EDAM design. The primary concern is whether certain congestion revenues should be allocated to the balancing area in which the congestion costs accrued, or to the neighboring EDAM balancing authority area where the transmission constraint is located, specifically in cases in which parallel — or loop — flows occur. 

On May 19, CAISO published a revised draft final proposal, which fine-tunes the allocation of parallel flow congestion revenues “based on the exercise of eligible firm point-to-point and Network Integration Transmission Service and Open Access Transmission Tariff transmission rights.” 

The revised draft provides details about congestion revenues that are not received under the current design for the EDAM entity. Any remaining parallel flow congestion revenue accrued because of a transmission constraint in a neighboring EDAM balancing area would be allocated to the area where the binding transmission constraint is located, CAISO wrote. 

The revised draft is consistent with FERC requirements that say congestion revenues accruing internal to an EDAM balancing area because of an internal transmission constraint are allocated fully to that balancing area — i.e., where the transmission constraint is located, CAISO wrote.  

“Stakeholders continued to note the concern that the proposed design in the near term may incent self-scheduling by transmission customers in order to receive a congestion hedge, a ‘use it or lose it’ concept to the exercise of transmission rights,” CAISO said in the draft. “In this context, stakeholders indicated broad support for an economic bidding enhancement to enable parallel flow congestion revenue allocation for balanced cleared market schedules based on economic bids, not only self-schedules.” 

The revised proposal includes an example of a load event that shows how much money would be distributed to four balancing areas: BAA-A, BAA-B, BAA-C and BAA-D. In the example, the market footprint net settlement is an over-collection in congestion revenue of $135,800. Under the current EDAM design, all of the congestion revenue is allocated to the BAA where the constraint is modeled, CAISO wrote. However, under the revised draft, the congestion revenue associated to balance OATT self-schedules is allocated to the EDAM entity where OATT rights are exercised. 

CAISO will hold a stakeholder meeting on the revised final draft proposal May 27, with comments due by June 2. CAISO plans to publish a final proposal June 6. 

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U.S. Senate Approves Resolution to End California’s EV Mandate

The U.S. Senate voted 51-46 to approve a resolution of disapproval against California’s Clean Air Act waiver that allows it to mandate that 100% of the cars sold in the state be electric vehicles starting in 2035. 

The measure, which the Senate approved late May 21, was approved by the House of Representatives earlier in the month and now moves to the White House; it was a goal of President Donald Trump’s Day 1 executive order on “Unleashing American Energy.” 

Sen. Shelley Moore Capito (R-W.Va.) helped lead the effort under the Congressional Review Act in the Senate. She welcomed the outcome in a statement decrying Democrats’ efforts to block the vote. 

“The impact of … California’s waiver would have been felt across the country, harming multiple sectors of our economy and costing hundreds of thousands of jobs in the process,” Capito said. 

Democrats said the Republicans “went nuclear” to get around the 60-vote requirement to overcome a filibuster to pass the resolution ending the mandate, overruling the Senate parliamentarian, who had found the waiver was not subject to the CRA. 

“Under this logic, the Trump administration could send an endless stream of non-rule actions to Congress, going back to 1996, including: vaccine approvals, broadcast licenses, merger approvals and any number of government decisions that apply to President Trump’s long list of enemies,” Sen. Alex Padilla (D-Calif.) said in remarks on the Senate floor. “All it would take is a minority of 30 senators to introduce related bills, and the Senate would be bogged down voting on agency grocery lists all day.” 

California Gov. Gavin Newsom (D) blasted the Senate vote for going around normal procedures and promised to challenge the resolution. 

“We won’t stand by as Trump Republicans make America smoggy again — undoing work that goes back to the days of Richard Nixon and Ronald Reagan — all while ceding our economic future to China,” Newsom said in a statement. “We’re going to fight this unconstitutional attack on California in court.” 

World Resources Institute Senior Fellow Dan Lashof said the resolution’s approval goes against nearly 50 years of precedent that has allowed California and other states to adopt vehicle emissions standards that exceed federal rules. 

“The U.S. auto industry’s competitiveness in the global market depends on innovation, which has historically been and continues to be driven by California standards,” Lashof said. “People across the country want cleaner, more efficient cars, trucks and school buses, and the cleaner air that results.” 

Twelve other states have passed measures to use the standards developed under California’s waiver, the Consumer Energy Alliance said in a statement welcoming the Senate’s vote. 

“The Senate’s actions today represent a crucial step toward preserving consumer choice by preventing policies that would make energy and transportation more expensive and less reliable for everyday Americans,” CEA President David Holt said. “We urge President Trump to swiftly sign House Joint Resolution 88 into law.” 

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NERC Standards Committee Rejects IBR Definitions Request

A proposal at the monthly meeting of NERC’s Standards Committee to reject a standard authorization request (SAR), despite its support from industry stakeholders in a 2024 comment round, prompted a debate among the group’s members over the appropriateness of the action.

At issue was an SAR that the SC accepted in July 2024, proposing to update NERC’s Glossary of Terms to add owners and operators of inverter-based resources (including those not currently subject to NERC’s standards) to the glossary definitions of generator owner and generator operator. The SC assigned the SAR to the standard drafting team for Project 2024-01 (Rules of Procedure definitions alignment — generator owner and generator operator).

Presenting the proposal, NERC Manager of Standards Development Alison Oswald explained the SDT reviewed the comments on the SAR from a comment round in August and September 2024. The review was delayed by the need to focus on an SAR assigned to the project earlier.

SDT members concluded they already achieved the SAR’s objective through other revisions to the GO and GOP definitions. The team also considered it best to avoid IBR-related definitions because they are being addressed by Project 2022-02 (Uniform Modeling Framework for IBR). The SDT therefore recommended the committee vote to reject the SAR, with a letter of explanation to the submitters, which include the American Public Power Association, the Electric Power Supply Association, the Large Public Power Council and the Transmission Access Policy Study Group.

But Marty Hostler of the Northern California Power Agency objected, pointing out the SAR received 68 positive comments from industry stakeholders against 22 negative ones and professing himself “not clear exactly why the consensus is being ignored.” He added that the SDT members “haven’t even asked the commenters if they feel that [the team] has addressed the issues.”

“It also says in the Standards Processes Manual [SPM] that NERC staff and the drafting team should be giving ‘prompt consideration to written views and objections.’ Well, this wasn’t prompt at all,” Hostler continued. “The comments were requested and closed in September of last year, and the comments weren’t even addressed till March.” He also pointed out the SAR for Project 2022-02 does not permit the SDT to create definitions.

Responding to Hostler, NERC Director of Standards Development Jamie Calderon described the support from industry in more nuanced terms, saying “there were industry participants who approved of one or more … definitions and some who disapproved of one or more … definitions.” In addition, Calderon clarified that SDTs do have the ability to consider definitions … within the realms of” their work.

SC Chair Todd Bennett, of Associated Electric Cooperative Inc., reminded attendees “the SPM only gives us two options on this … either [to] authorize drafting or … reject the SAR.” But, he continued, NERC’s standards development process provides “other ways to influence that path and provide feedback and input.”

The proposal to reject the SAR ultimately passed, with Hostler and four others voting against it. Nine members voted in favor and six abstained.

Additional Actions

Several other standards items passed the SC with comparatively little discussion and no objections.

First, members voted to approve the posting of proposed reliability standard MOD-026-2 (Verification and validation of dynamic models and data), developed under Project 2020-06 (Verifications of models and data for generators).

The standard, found on Page 11 of the agenda, is meant to address FERC’s Order 901, issued in 2023, which required NERC to develop standards to improve the reliability of IBRs. (See FERC Orders Reliability Rules for Inverter-Based Resources.) It will be posted for a 26-day formal comment period, with ballots conducted during the last 10 calendar days.

The SC next approved the appointing of three new members to the SDT for Project 2020-06, which Calderon explained was intended to “round out the drafting team” after several recent departures.

Finally, the committee voted to accept an SAR aiming to modify NERC’s Critical Infrastructure Protection (CIP) standards by grouping protected cyber assets (PCAs), electronic access control or monitoring systems (EACMS), and physical access control systems (PACS) together in a single standard as “CIP applicable” systems. Oswald told attendees this move will bring clarity to NERC’s enforcement process.

Currently, a failure to appropriately identify PCAs, EACMS and PACS is addressed under CIP-010-4 (Cybersecurity — configuration change management and vulnerability assessments). But Oswald said this approach is only a “temporary solution” that poses an administrative burden on both the industry and the ERO.

The SAR will be posted for a 30-day formal comment period and assigned to Project 2021-03 (CIP-002).

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ISO-NE Open to Asset Condition Review Role amid Rising Costs

With projects to replace deteriorating transmission infrastructure adding billions of dollars to New England electric bills, ISO-NE has announced it’s open to taking on a limited “asset condition reviewer” role, intended to help increase oversight on the projects. 

“Given the significant benefits to the region from a robust process and independent review of asset condition projects (ACPs), we are now exploring the issue further,” ISO-NE wrote in a memo May 15. 

While the scope of the role has yet to be determined, the RTO has insisted it could take on only a strictly advisory role and would not review the prudence of investments or assume any legal liability. The regional transmission owners would retain the right to decide whether to move forward with individual projects.  

The rising costs associated with ACPs have drawn increased scrutiny over the past two years. There are about $6 billion in asset condition projects listed as proposed, planned or under construction in ISO-NE’s ACP project list, while more than $5 billion in asset condition projects have come online since the start of 2015. 

According to a 2024 report by the Rocky Mountain Institute (RMI), asset condition spending in New England “increased eightfold from 2016 to 2023” and now makes up a majority of pooled transmission system spending in the region.  

The high costs are not limited to New England; RMI’s report noted that the portion of residential electric bills spent on transmission and distribution increased from 10% in 2005 to 24% in 2020. The bulk of this added spending has gone to local projects, as the U.S. has built far fewer new high voltage transmission lines in the early 2020s compared to the prior decade.  

Along with rising costs, New England officials have expressed concern about a lack of transparency and regulatory oversight on the projects, with some arguing transmission owners have abused the process to increase spending.  

“These asset condition projects frequently do not receive oversight from state regulatory authorities, as rebuilding aging assets is often exempt from state regulatory processes,” said Claire Wayner of RMI, one of the authors of the asset condition report, speaking at the annual symposium for the New England Conference of Public Utility Commissioners (NECPUC) on May 20.  

While the projects are subject to a prudence review at FERC, the formula rate process provides “very few opportunities for oversight of these projects,” Wayner added.  

Some asset condition projects have drawn specific concern from state officials, including a $385 million line rebuilding project proposed by Eversource Energy in New Hampshire. (See New England States Raise Alarm on Eversource Asset Condition Project.) 

Recently, a couple of projects presented at the NEPOOL Reliability Committee highlight potential discrepancies in how transmission owners approach asset condition projects. Vermont Electric Power Co. (VELCO), a transmission company collectively owned by the states’ distribution utilities and structured to return profits back to customers, proposed to replace 41 wooden structures on a 115-kV line, with a projected cost of $5.8 million.  

At the same meeting, Eversource, an investor-owned utility company, presented an update on a project to replace 41 wooden structures on a couple of sections of 115-kV line in Connecticut. The project’s estimated cost is over $16 million, more than double the cost of VELCO’s similar project. 

While Eversource serves roughly half the load in the region, it’s responsible for 79% of all spending in New England on ACPs that have come online since 2015, according to ISO-NE data. The company has stressed its investments are critical to preserving the reliability of its aging grid. 

“Inconsistent decision and design standards across transmission owners that lead to notable cost disparities between the same or very similar asset condition projects is just bad behavior,” said Commissioner Kerrick Johnson of the Vermont Department of Public Service (DPS). Prior to taking his position as a DPS commissioner, Johnson held several senior roles at VELCO. 

“Bad behavior by any New England [transmission owner] impacts every customer in each of the six New England states,” Johnson said, adding that this “undermines trust in the entire regional collaborative transmission enterprise and punishes those least able to pay.” 

Johnson added that he recently reviewed six ACPs flagged as the most “needlessly expensive” by the New England States Committee on Electricity (NESCOE), finding that the “cost delta between that which would have been expected for these projects and that which was submitted for each of these projects … totals nearly half a billion dollars.” 

He said he based his review on VELCO cost analyses and accounted for the varying costs typically seen in different states and utility service areas. 

ISO-NE previously expressed reluctance about taking on an asset condition oversight role, arguing it is not a regulatory entity. However, following discussions with the states and transmission owners, ISO-NE said it is comfortable taking on a limited reviewer role.  

Anne George, chief external affairs and communications officer at ISO-NE, said the RTO’s board met the prior week and offered support for continued discussions “about ISO-NE having an asset condition review role.” 

George stressed the importance of limiting the role to a non-regulatory, advisory function, but said it could “provide additional information and address some of those concerns about information asymmetry, and then people could take that information to FERC or take it to another forum and make the case.” 

NESCOE and the Massachusetts Attorney General’s Office, along with transmission owners Avangrid and National Grid, offered public support for the concept following the announcement.  

“NESCOE expects that the asset condition reviewer will provide states and stakeholders with an independent, objective review of asset condition proposals, including needs, solutions and cost drivers,” NESCOE wrote. “ISO-NE’s asset condition reviewer should provide information necessary to enhance confidence in the proposed investments, or in the alternative, information that others would be able to rely on in challenging a project.” 

NESCOE added there remains a “core need” to better incorporate asset condition needs into the regional planning process, which could enable those projects to be appropriately sized in anticipation of the need for more transmission capacity. ISO-NE has estimated new transmission to meet load growth through 2050 could cost up to $26 billion. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B and ISO-NE Analysis Shows Benefits of Shifting OSW Interconnection Points.) 

In March, NESCOE asked FERC to direct the creation of an independent transmission monitor (ITM) with a broader scope, intended to “support the efficacy and efficiency of transmission planning and cost transparency.” Some stakeholders also have supported the concept of a monitor with authority to review the prudency of transmission projects. 

ISO-NE has expressed concern about having a separate independent entity overseeing the RTO’s planning processes and has resisted taking on anything more than an advisory role. 

At the NECPUC symposium, some stakeholders expressed interest in state or federal regulatory changes to go along with a new asset condition reviewer role for ISO-NE.  

“There’s definitely additional work that FERC could do to improve its formula rate-making process,” said Wayner of RMI. Wayner said this could include “looking at the automatic presumption of prudence that transmission projects get through formula rates and maybe reconsidering that for some of these projects if they are not being adequately reviewed at the state level.” 

Johnson of the Vermont DPS expressed his hope “the states pass individual review of asset condition projects like we have in Vermont.” 

In Massachusetts, Gov. Maura Healey (D) recently introduced a bill that would allow the state’s Energy Facilities Siting Board to review “any proposed reconductoring, replacement or rebuilding of a transmission facility or group of transmission facilities on an existing transmission corridor that has an estimated cost of at least $25 million.” (See Mass. Gov. Healey Introduces Energy Affordability Bill.) 

As state officials consider other changes to the asset condition process, ISO-NE has said it’s considering adding the evaluation and creation of an asset condition review role to its 2026 work plan.  

“Following the ISO’s assessment and the development of any preliminary framework, we plan to bring that proposal to our stakeholder community for discussion and feedback,” it added. 

For ACPs proposed in the interim period before a reviewer role can be established, Johnson asked representatives of the transmission companies at the NECPUC symposium to commit to answering all outstanding stakeholder questions before proceeding with a project. Representatives of each company signaled their agreement to the commitment.  

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Power System’s Shifting Direction Highlighted at Energy Future Forum

WASHINGTON — President Donald Trump’s policies and the growth in demand from data centers and other new customers have changed the trajectory of the power system, speakers said May 19 at the Energy Future Forum.

“Demand is going up, but we’re losing exactly the dispatchable resources that we need,” FERC Chair Mark Christie said. “Particularly we’re losing coal resources, and we’re losing some gas, and over the last 20 years, we’ve lost nuclear.”

The “reality that is tracking us down” is demand rising from data centers, manufacturers and other sources, while too many resources are retiring.

“And they’re not being replaced with sufficient dispatchable capacity,” Christie said. “So, it’s just arithmetic. You don’t need to be a Ph.D. in math to see the numbers are not adding up.”

FERC’s main role in dealing with that situation is regulating wholesale markets, which cover about three-fourths of the customers in the country, he said. It has a larger role in restructured states that have left their generation investment decisions largely up to those markets. “A lot of states effectively delegated their ability to determine their generation mix to these FERC-regulated markets.”

A key role for FERC as a regulator is to be a truth teller about the reliability issues facing those markets, he continued. The commission is holding a two-day technical conference on June 4 and 5 to detail the status of resource adequacy across those markets.

“One of the things that I really worry about is that we kind of continue to march down the path of removing diversity from the grid,” NERC CEO Jim Robb said.

While plenty of forensics remain to be done to determine the causes of the massive blackout in Portugal and Spain on April 28, Robb said a major factor in its size was the lack of traditional generation operating on their grid at the time, with 74% being inverter-based resources (primarily solar and wind).

The rest was hydro and natural gas, which provided some inertia that can help cushion the grid against frequency disturbances, but ultimately it was the “wall of inertia” from the French nuclear fleet that stopped the blackout’s growth, Robb said. Generators from across the Strait of Gibraltar in Morocco provided black start to bring back Iberia’s grid within a day.

While traditional generation helped bail out that blackout, Robb said some new inverters are capable of grid forming, and other technologies like flywheels and synchronous condensers can provide vital ancillary services too.

“Batteries can also kind of help on frequency response,” Robb said. “We’re seeing that in Texas right now. And the solar-battery combination is really a killer summer generating resource.”

Solar and batteries are a great pairing in regions with a lot of sunshine, with the best in the U.S. being Texas and the Desert Southwest. But the combination is not nearly as effective in the winter, only helping balance the grid a little.

“It’s kind of a horses-for-courses thing: Any one resource can be good for one thing, but not everything,” Robb said. “And that’s true of gas; it’s true of coal; it’s true of nuclear.”

Batteries also can help address the main issue of growing demand by helping balance the transmission system and adding flexibility to data centers without the emissions associated with more standard diesel backup generation, Eolian CEO Aaron Zubaty said. He brought up a Duke University study that has been making waves since its release this winter. (See US Grid Has Flexible ‘Headroom’ for Data Center Demand Growth.)

“We’re building a 2-GWh site right now in Texas, next to a retiring coal power plant,” Zubaty said. “We’re finishing multiple 1-GWh sites right now in Portland, Ore. These are designed to be locations so that you don’t need to rebuild transmission, and so that the grid runs more efficiently.”

Batteries can help all kinds of large, inflexible loads connect more easily to the grid by running during peak times, avoiding the need to expand the grid in order to keep them running. On top of data centers, Eolian also is working on projects with large industrial sites like aluminum smelters to accomplish the same thing, Zubaty said.

Eolian is focused on lithium-ion batteries because they have become commoditized, and their affordability is making longer-duration batteries more economic.

“When you can do eight and 10 hours — where, by the way, we can turn it on in 250 milliseconds — that is a very unique asset on the energy grid for all the reasons we heard earlier about reliability,” Zubaty said. “The combination of many, many hours of reliability plus instant response has pretty much never existed in the history of the grid at this scale.”

While renewables and storage continue to grow, the flow of capital in North America has shifted to natural gas and other traditional resources, 1PointSix CEO Terrence Keeley said. And it’s not just the U.S.

“It will be very interesting to watch the metamorphosis of Mark Carney as [Canadian] prime minister from central banker. We’re going to find that he’s much more interested in developing Canadian tar sands than perhaps he had been as a banker,” Keeley said.

Even with the Wall Street money flowing increasingly to other resources, renewables continue to grow. Keeley criticized language in this year’s budget bill on clean energy tax credits. (See House Committees Mark up Budget Bill that Guts Energy Tax Credits.)

“One of the big problems we’re having amongst Republicans is how quickly these incentives are going to be removed for renewables,” Keeley said. “Turns out they fought against the [Inflation Reduction Act] when it was going into law, but they’re now fighting to not take it off too quickly. St. Augustine needs to be called out, in light of our new pope: ‘God, grant me chastity, but not yet.’”

power systems

GE Vernova Gas Power CEO Eric Gray speaks at the Energy Future Forum on May 19. | © RTO Insider LLC

GE Vernova Gas Power CEO Eric Gray has seen firsthand the rise in demand for the turbines it manufactures as industrialization, data centers and electrification are growing its orders.

“Given the fact that gas turbines can be installed in a relatively short period of time versus some of the other technologies out there, gas is a good solution to what we need today,” Gray said.

As recently as late 2023, GE Vernova could have fulfilled an order for a turbine in 12 to 18 months. If one is ordered today, it will not be delivered until 2028. The company is responding to the uptick in demand with $600 million overall invested this year, including $300 million in gas.

Part of that money is going is going to its manufacturing plant in Greenville, S.C., where it is installing 500 new pieces of equipment in a bid to make the facility efficient and capable of producing more turbines. The investments are expected to grow the firm’s production capacity by 35%, Gray said.

Domestic demand has been constant for about 12 months. Before that, the firm was seeing more orders from Southeast Asia, Taiwan and Saudi Arabia, he said. Another wrinkle is Trump’s tariffs, but Gray said they’re not having much of an impact on business.

“If you fast forward to tariffs, as we said publicly, around 5% of our spend comes from China, Mexico and Canada,” he added. “It’s definitely not immaterial, but it’s something that we’re working our way through. The conversations we’re having with our customers today — obviously, having an increase in price changes the economics that they thought they were underwriting, but the fact of the matter is that the demand is still there. We need the electrons, so they’re being somewhat accepting of the tariffs and the price increases that they’re seeing as a result.”

The forum was sponsored by the National Center for Energy Analytics, RealClearEnergy and the U.S. Chamber of Commerce.

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Texas RE: ESRs to Boost ERCOT During Summer

A “tremendous” growth in resources for ERCOT has resulted in a “significantly lower” probability for an energy emergency alert this summer, according to the Texas Reliability Entity. 

During a May 20 “Talk with Texas RE,” Evan Shuvo, a senior engineer with the organization, said a spike in energy storage resources has substantially lowered the risk level during the early evening hours as solar energy tails off. 

“Storing power in these energy storage resources for when demand is high and there is not enough solar generation available will help the reliable operation of our grid,” he said. “There’s a low risk of energy shortage during early evening hours compared to last summer.” 

ERCOT has added 7.4 GW of ESRs since summer 2024, Shuvo said. That’s more than half of the 13 GW in increased storage capacity since last summer across NERC’s ERO footprint. Overall, ERCOT has boosted its expected capacity by more than 15 GW. 

“We have plenty of reserves under the expected peak conditions,” Shuvo said. 

According to the data shared by Texas RE, ERCOT is projecting a 0.7% increase this summer in net internal demand of 81.9 GW, with 3.3 GW in demand response deducted. With the additional resources since 2024, the grid operator will enter the summer months with a prospective reserve margin of 43.9%. 

ERCOT’s monthly outlooks for resource adequacy (MORA) for June and July predict it will have a little more than 91 GW each month to meet demand as high as 79.6 GW during the hour of highest risk for reserve shortages (the hour ending at 5 p.m.). 

The ISO will release its August MORA on June 6. August tends to be the hottest month in Texas; ERCOT’s record peak of 85.5 GW was set during that month in 2023. 

ERCOT has yet to publish its summer outlook — Shuvo said it will be released the last week of May — but the National Weather Service said in April it’s expecting summer 2025 to be among the hottest on record in Texas. The past three summers ranked among the top six hottest summers since 1895. The grid operator set a record for May when average demand peaked at 77.8 GW on May 14. 

Shuvo said the Lone Star State’s drought conditions will continue with the precipitation outlook “leaning on the dry side of normal.” 

“Conditions like this can contribute to high temperatures,” he said. “This has a very direct impact on the reliability of generation and transmission system elements. Extreme heat can contribute to elevated load levels for prolonged periods and this can lead to reduced transmission line ratings and major derates of thermal resources.” 

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N.Y. Finalizes REC Contracts for 2.57 GW of Renewables

New York has executed renewable energy certificate contracts for 26 solar, wind and hydro projects to help meet its clean energy goals. 

The combined 2.57 GW of nameplate capacity and estimated 5,000 GWh of annual output would help rebuild the state’s renewable energy portfolio, which saw sharp attrition in late 2023 and early 2024 as previously executed REC contracts became financially untenable because of soaring construction costs. 

The New York State Energy Research and Development Authority’s 2024 Tier 1 solicitation was launched 11 months ago. The results were reported May 21.  

In its announcement, NYSERDA said the projects would generate more than $6 billion in direct private-sector investment. But it said REC pricing details will not be reported until the projects reach commercial operations. 

A spokesperson said this is being done to align NYSERDA with industry standards and to avoid releasing information that does not reflect actual ratepayer costs. 

The 2024 Tier 1 solicitation included provisions for price adjustments to reduce the possibility of renewed attrition between contract award and final investment decision. 

Considerable price volatility faces renewable energy developers in early 2025, due in part to federal policy shifts. Supportive policies at the state level are expected to be important to continuing the clean energy transition that accelerated in the Biden era. 

Gov. Kathy Hochul (D) highlighted this in the announcement: “The advancement of renewable energy is part of the foundation of New York’s plan to transform to a zero-emission electricity system and continue our green economy’s momentum forward.” 

The 26 projects and their estimated 5,000 GWh are expected to direct more than $300 million in commitments to disadvantaged communities and reduce emissions by more than 1.7 million metric tons per year. Several of the projects have begun construction, and all are expected to be operational by 2029. 

For perspective, NYISO reported recently the state used approximately 151,000 GWh in 2024. 

Support and Opposition

The two hydro, six wind and 18 solar projects awarded REC contracts are mostly in remote or less populated upstate areas. All are far removed from the New York City region, which is heavily reliant on fossil-fuel generation and looking over the horizon for renewable power that would allow it to turn off the fossil plants and enjoy improved air quality. 

This strategy sets up a friction point in a state with stark upstate-downstate differences: Some upstaters resent having to look at wind turbines and solar arrays and resent the state’s recent efforts to limit local governments’ ability to thwart siting of these facilities. 

One of the new REC contract holders — Terra-Gen’s 147-MW Prattsburgh Wind Farm near the Finger Lakes — said May 15 that it will begin pre-construction work June 8. 

Around the same time, a local opposition group asked the Public Service Commission (Matter 21-00749) to block any movement of soil until a protocol for the golden nematode is clarified and accepted by the U.S. Department of Agriculture. 

Another of the newly contracted projects is Repsol Renewables’ Mill Point Solar 1 in Montgomery County, which at 1,124 acres and 250 MW would be one of the largest solar farms in New York state. 

renewables

A map shows the sprawling footprint proposed for Mill Point Solar I, which at 1,124 acres and 250 MW would be one of the largest solar farms in New York. | Repsol Renewables

It also would be placed in one of the hot spots for solar development, and for utility-scale solar opposition, where there is a combination of affordable farmland and woodlands populated by multigenerational residents who like looking at those fields and woods. Many have come out against Mill Point. 

The state Office of Renewable Energy Siting and Electric Transmission has permitted Prattsburgh Wind. It still is reviewing Mill Point I and has scheduled a May 28 public comment hearing at a school near where the solar farm would stand. To judge by the 300-plus comments submitted (Matter 23-02972) in opposition to and support for the proposal, it could be a crowded and lively session. 

Other projects that received the new REC contracts may prove less controversial.  

The little village of Lyons Falls lost its main industry and hundreds of jobs a generation ago when the local paper mill closed. The crumbling eyesore eventually was demolished, but its hydro plant would be repowered under a plan that now carries state support. 

NYSERDA said the state continues to emphasize engagement with host communities to build support for the projects and spread their benefits. 

The List

The contracts awarded REC contracts are: 

Agricola Wind in Cayuga County 

Dolan Solar in Washington County 

Dolgeville Hydro in Herkimer County 

ELP Ticonderoga Solar in Essex County 

Flat Creek Solar in Montgomery County 

Fort Covington Solar Farm in Franklin County 

Hawthorn Solar in Rensselaer County 

High Bridge Wind in Chenango County 

Highbanks Solar in Livingston County 

Homer Solar Energy Center in Cortland County 

Horseshoe Solar Energy Center in Livingston and Monroe counties 

Lyons Falls Mill Repower in Lewis County 

Mill Point Solar I in Montgomery County 

Moraine Solar Energy Center in Allegany County 

Prattsburgh Wind Farm in Steuben County 

Shepherd’s Run Solar Project in Columbia County 

Skyline Solar in Oneida County 

Somers Solar in Washington County 

South Ripley Solar in Chautauqua County 

Tracy Solar Energy Center in Jefferson County 

Two Rivers Solar Farm in St. Lawrence County 

Valcour Altona Windpark in Clinton County 

Valcour Bliss Windpark in Wyoming County 

Valcour Clinton Windpark in Clinton County 

Yellow Barn Solar in Tompkins County 

York Run Solar in Chautauqua County 

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MISO Gen Developers Sour on RTO’s JTIQ Cost Allocation

MISO generation developers have pushed back on MISO’s cost allocation of the $1.65 billion Joint Targeted Interconnection Queue (JTIQ) portfolio in partnership with SPP, reportedly saying MISO’s late-stage alterations have eroded the value of the seams planning.

The discord became apparent after a MISO announcement in April that it now plans to incorporate JTIQ lines and assign new generation upgrade costs from them beginning with the 2023 cycle of interconnection queue entrants. The RTO must seek FERC permission to begin including JTIQ lines beginning with the 2023 interconnection cycle because it would use the modeled lines in an earlier queue cycle than it first anticipated.

MISO confirmed in mid-May that it will file with FERC soon to allow the earlier incorporation of JTIQ into its queue studies. (See MISO Readies JTIQ Filings, Hints at More Tx Portfolios with SPP.)

Ordinarily, MISO locks in modeling assumptions when it kicks off studies shortly after it accepts the new cycle of generation projects. However, MISO’s 2023 class of interconnection customers have been in a holding pattern while MISO attempts to get a handle on its oversaturated queue. The RTO has said models as they existed two years ago are too stale to be relied upon as it begins processing proposals again. MISO said it would work from its latest transmission modeling when studies kick off. (See MISO: New Software Effective, Faster than Previous Queue Study Process.)

Some generation developers in MISO reportedly are unhappy with JTIQ being accounted for in the 2023 queue cycle. That stems from concern that cost assignments on the lines could climb as high as under MISO and SPP’s erstwhile affected system study process.

MISO said its view is queue cycles that have not yet started down the study process “must be able to take advantage of all approved transmission and reduce uncertainty for the next cycles.”

MISO and SPP are assessing JTIQ costs 100% to interconnection customers; costs will be assessed a per-megawatt JTIQ charge that is billed directly by either MISO or SPP.

Beyond that, MISO in 2024 added a second step to its JTIQ cost assignments in the form of what it calls the Expanded Scope Study. The additional study is meant to pinpoint line upgrades beyond JTIQ projects that interconnecting generation might require.

Clean Grid Alliance (CGA), speaking on behalf of some of the developers it represents, said it regards the Expanded Scope Study as the old affected system study that produced unexpectedly high upgrade costs and was meant to be replaced by the JTIQ process. In an interview with RTO Insider, CGA representative Rhonda Peters said though the name is different, the function is the same.

MISO has said while the JTIQ study is designed to address congestion for about 28.6 GW of generation projects wishing to connect near the seams, the Expanded Scope Study is designed to address lingering issues around the point of interconnection.

CGA told MISO it is “strongly against” merging JTIQ projects in the 2023 interconnection cycle. The alliance asked MISO to begin work on changing its tariff and joint operating agreement with SPP to make cost assignments more certain and contained for MISO generation developers. The alliance made a similar request when MISO was designing its JTIQ cost allocation in 2023 and 2024. It said its request was ignored repeatedly.

CGA said as it stands now, interconnection customers beginning with the 2023 cycle could be in “for high cost variability when projects are subjected to JTIQ.” It said the penalty-free withdrawal option in MISO’s queue likely won’t be enough to counter the costs because it doesn’t expect the Expanded Scope Study or the JTIQ cost estimates to be completed at that point in the process.

MISO has said the point of JTIQ allocation is to know up front what portion of costs that generation will be on the hook for. The RTO has said the alternative to including JTIQ in the 2023 queue cycle is MISO and SPP conducting another affected system study, where costs wouldn’t be fleshed out until the second or third phases of the queue. MISO also pointed out that its interconnection procedure is “not a risk-free process.”

MISO expects costs from the separate, Expanded Scope Study would be known later, once in the first phase of the queue and again in the second phase of the queue. MISO and SPP will treat a few buses into one another’s footprint as their own system for the purpose of determining whether a generation developer should pay for upgrades under the Expanded Scope Study.

Differing DFAX Thresholds

Generation developers in MISO also oppose MISO employing a lower distribution factor (DFAX) threshold than SPP uses for its internal projects in allocation. When singling out necessary upgrades on generation projects requesting unguaranteed energy resource interconnection service, MISO holds its developers to a more rigid 10% DFAX impact threshold than SPP’s 20%. For projects requesting the higher-quality network resource interconnection service, MISO and SPP both use a 5% DFAX impact threshold.

MISO halved its 20% DFAX value in 2023 despite opposition from stakeholders who claimed MISO did not complete an engineering analysis to support the change. They also argued that such a major change belonged in a tariff filing to FERC, not in a business practice manual edit.  Their complaint over MISO’s change is pending before FERC. (See Renewable Developers Challenge MISO’s Lower Congestion Limit.)

In comments to MISO, CGA said MISO’s lower DFAX means that MISO developers will have more exposure to SPP network upgrade costs than SPP developers. The alliance also said that unsuspecting “projects far away from the seams that would have never needed JTIQ lines” nevertheless could get pulled into JTIQ cost sharing “simply because of power flows in the path of least resistance.” CGA said the second study step once again means developers at the seams will have no solid cost predictions on the network upgrades their projects might induce.

CGA also told MISO that the JTIQ 345-kV portfolio lines not having a cost cap mechanism is problematic, given the 100% cost assignment to developers. CGA said that cost overruns on transmission construction would add to generation developers’ tabs. Peters said MISO using its usual network upgrade allocation of 90% to interconnection customers and 10% to load on 345-kV and above projects would have afforded some budget oversight because states likely would question mounting costs even on their 10% portion.

Peters also said the 5% power flow DFAX threshold seems arbitrary and insignificant, and that MISO would be better served if it split costs among generators that actually cause or worsen constraints. CGA said JTIQ essentially reversed a long-standing FERC precedent: the “but for” principle that assigns costs to cost-causers. The alliance said that under JTIQ, many interconnection customers would be assigned costs for JTIQ lines even though they do not depend on the lines and have not contributed to any constraints if the lines were not in the model.

‘Affected System Study on Steroids’

MISO developers opposing allocation methods declined to be interviewed for this article and instead opted to effectively speak through Clean Grid Alliance’s comments.

Peters confirmed that many generation developers oppose MISO’s JTIQ cost allocation mechanisms and called them poorly understood among stakeholders.

Peters said cost recovery of the transmission lines is uncapped for generation developers and that their costs can increase over the 10-plus years the lines are built.

“There is no regulation or oversight on cost increases on those lines,” Peters said. She said the current two-phase JTIQ allocation could saddle developers with more costs than MISO and SPP’s past affected system study process. She said that’s why MISO’s JTIQ cost allocation was so strongly opposed by MISO interconnection customers at FERC. She also pointed out that CGA and other renewable trade associations are appealing the JTIQ cost allocation at the 7th U.S. Circuit Court of Appeals.

Peters said generation developers made sure to enter the 2023 cycle to avoid potentially “disastrous” outcomes funding the JTIQ projects.

“These projects spent a lot of money to enter when they did,” Peters said. “[And] MISO customers are going to have to build out SPP’s system to a 10% DFAX.” She added that the uneven threshold between MISO and SPP is likely to “significantly cost shift from SPP to MISO generators near the seams.”

“We call it affected system study on steroids,” Peters said, adding that she thought the JTIQ began as a good idea, but generation developers got “trampled” in the stakeholder process, including cost allocation discussions. She said there are “fatal flaws” in several aspects of the allocation methodology that make costs to generators highly unpredictable.

Peters said developers made “commercial decisions to enter the queue” based on the absence of JTIQ cost sharing in the 2023 cycle.

“This introduces significant uncertainty and cost increases to projects which undermines the predictability necessary for project financing and development. [Definitive Planning Phase] 2023 projects entered the queue having specifically modeled the transmission system without the unpredictable cost exposure JTIQ creates, and do not want the process changed at this point,” CGA said in its comments to MISO.

Shell’s Savion, a solar and energy storage developer, agreed that developers entered the queue in 2023 strategically before JTIQ integration began. In comments to MISO, Savion said the RTO’s move to group the 2023 entrants into the cost allocation now is “akin to retroactive ratemaking.”

MISO: Allocation Already Has FERC Support

MISO, on the other hand, stressed that FERC unanimously approved the JTIQ cost allocation, including the Expanded Scope Study, in late 2024.

“The JTIQ portfolio was developed in close collaboration with SPP and our joint stakeholders to support generation at our seam and strengthen regional reliability. MISO and SPP followed a transparent, stakeholder-driven process to develop the JTIQ study framework and cost allocation methodology,” MISO spokesperson Brandon Morris wrote in an emailed statement to RTO Insider.

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Calpine Proposes Time-varying TCCs at NYISO

Calpine has proposed that NYISO split its 24-hour-only transmission congestion contracts into on-peak and off-peak products, arguing it would reduce the cost of congestion hedging by better aligning it with load and generation behavior. 

“We are asking for this to help us manage our risk [and] the renewables sector — solar and wind generators — to manage their risk,” Jung Suh, manager of ISO analytics for Calpine, said at the Budget Priorities Working Group meeting May 19. “All of the benefits from this will benefit the consumer, the ratepayer and the end user.” 

TCCs allow generators to hedge the congestion component of their output. Suh said this was especially important for intermittent resources because of their varying load profiles. Wind and solar power do not and cannot operate at maximum capacity with perfect predictability, which makes more precise hedging preferable, Suh explained. 

NYISO is the only grid operator not to offer time-granulated financial transmission rights. Suh argued that offering such rights could increase TCC auction revenue, increase market transparency and decrease the cost of hedging congestion. He said this would allow load-serving entities to fit the demand profile of their customers better. 

Howard Fromer of Bayonne Energy Center asked whether stakeholders had heard this presentation before. Suh said he gave the exact same presentation five years ago. 

“You were five years younger and five years better looking back then when I presented it,” Suh said. “It received the No. 1 ranking in the [project prioritization] survey five years ago.” 

“So it never got picked up by the ISO, is what you’re saying?” Fromer asked. “It was ranked, and ranked high, and it wasn’t pursued?” 

Another stakeholder chimed in that the ISO worked on it for a year before shelving the proposal. 

Several stakeholders supported the proposal. One said it would help them hedge flows between ISOs and help their renewables portfolio. Others said they strongly supported the proposal and hoped it got in the 2026 project prioritization list.

Project Prioritization: 2026

NYISO has identified 44 market projects for next year. Of those, five are mandatory projects, five are continuing projects for next year, and 22 are on the “prioritize” list for next year.  

The ISO will share its scoring of the projects on June 24 and send stakeholders their own survey to complete June 30. The stakeholder survey results should be in at the end of July, and a preliminary budget should be released by mid-August.  

“I think it would be useful … that when we list project prioritizations, the market participants understand which ones you are recommending,” said Doreen Saia, of Greenberg Traurig. “That could affect the list we see as part of project prioritization. Folks need to understand if they are waiving their choices.” 

Fromer asked about the Market Purchase Transaction Hub project, which is listed for deployment in 2026. He said that seemed strange, given that all of the work was done and all that was left was to turn it on. 

Kevin Pytel, director of product and project management for NYISO, said the market design was finished but the software still needed to be completed in order to get it to deployment, so it’s back on the table for the prioritization process.  

Kevin Lang, speaking on behalf of New York City, expressed confusion, asking why the project would have to be reconsidered after being prioritized multiple times and with the design complete. 

Pytel said implementation costs might change opinions as to what projects needed to be prioritized year to year. He showed a slide where the definitions of project milestones were listed. “Market Design Complete” is considered fairly mature but not quite ready to have software developed to implement it, for example.  

“Anything under the blue line that reaches that milestone in 2025 is automatically considered a continuing project for 2026,” Pytel said. “Functional Requirements is the first milestone; if you achieve that this year, you will be automatically considered continuing for next year.” 

Pytel said stakeholder feedback should be sent to his email by May 31 to be incorporated into the next prioritization presentation. May 30 is the deadline for stakeholders to identify new projects and have them included in the scoring survey. 

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BOEM Lifts Stop-work Order on Empire Wind

The Empire Wind project off the coast of New York is back from near death after the U.S. Bureau of Ocean Energy Management lifted a stop-work order and its developer Equinor announced it would move forward.

“We appreciate the fact that construction can now resume on Empire Wind, a project which underscores our commitment to deliver energy while supporting local economies and creating jobs,” Equinor CEO Anders Opedal said in a statement May 19. “I would like to thank President Trump for finding a solution that saves thousands of American jobs and provides for continued investments in energy infrastructure in the U.S. I am grateful to Gov. [Kathy] Hochul for her constructive collaboration with the Trump administration, without which we would not have been able to advance this project and secure energy for 500,000 homes in New York.”

The stop-work order was issued on April 16 and was criticized by New York officials and renewable energy advocates. The 810-MW project is planned for just off the coast of New York City and would connect to the grid at a site in Brooklyn. (See Feds Move to Halt Construction of Empire Wind 1.)

Hochul welcomed the change in course from the Department of the Interior, saying in a statement she had spent weeks working with the federal government to ensure the project could move forward.

“Equinor will resume the construction of this fully permitted project that had already received the necessary federal approvals,” Hochul said. “I also reaffirmed that New York will work with the administration and private entities on new energy projects that meet the legal requirements under New York law. In order to ensure reliability and affordability for consumers, we will be working in earnest to deliver on these objectives.”

Interior Secretary Doug Burgum posted he was pleased with Hochul’s comments.

“I am encouraged by Gov. Hochul’s comments about her willingness to move forward on critical pipeline capacity,” Burgum posted on X. “Americans who live in New York and New England would see significant economic benefits and lower utility costs from increased access to reliable, affordable, clean natural gas.”

Burgum is correct directionally, but the project at issue, the Constitution Pipeline, would increase supply for some natural gas customers, while the pricing problem in the Northeast comes in winter at peak electricity demand, when generators cannot access the gas they can at other times of the year.

Trump has spoken publicly in favor of reviving the project, and the executive order setting up the National Energy Dominance Council, which Burgum chairs, calls for approving pipelines into New England.

FERC approved the Constitution Pipeline more than 10 years ago, but it did not get a permit from the New York State Department of Environmental Conservation. Developers effectively asked FERC to overrule the state, but in 2018 the commission denied the request, with three Trump nominees all voting for the order.

Hours before BOEM reversed course, in a talk largely focused on how Trump’s election was leading to more capital flowing to fossil fuels, 1PointSix CEO Terrence Keeley criticized the decision to stop work on the project. Halting work on a permitted project funded by Norway’s state oil company that was about a year from delivering electricity to the grid “seemed punitive,” he said.

“You can say goodbye to foreign direct investments in the United States for any type of project, renewable or unrenewable, when that type of unreliability becomes commonplace,” Keely said.

American Clean Power Association CEO Jason Grumet made a similar point in a statement calling the decision to move forward with Empire Wind good for reliability.

“Fully permitted projects must have policy consistency and certainty to deliver the infrastructure required to meet America’s growing electricity demand,” Grumet said. “Our nation needs all types of energy infrastructure to lower energy prices and support economic growth. In lifting the stop-work order, the administration has honored a principle that is essential to all infrastructure investment.”

At a Federal-State Current Issues Collaborative meeting on gas-electric coordination in April, ISO-NE CEO Gordon van Welie testified that the region has been dealing with constrained gas at peak demand for decades, and it leads to high prices as reliability is dependent on attracting LNG cargoes when demand also is in Europe and Asia. (See FERC-NARUC Collaborative Examines Ongoing Issues with Gas-electric Coordination.)

A decade ago, FERC found a creative attempt by the New England states to require electric utilities to pay for extra pipeline capacity outside of its authority. Since then, states have focused on imports from Canada and offshore wind development to hedge against price volatility in the winter, van Welie said.

“Recently, the issue of affordability has been given more emphasis, and the idea of possibly investing in additional gas infrastructure has resurfaced,” van Welie said. “However, it isn’t clear if there is an available counterparty in New England to commit to the long-term contracts that will be required. So, in summary, any viable solution to the gas constraint issues must involve, and requires the support of, state officials.”

The move to increase pipeline capacity in the Northeast is opposed by environmental groups, with Food and Water Watch noting in a statement that Hochul already has approved major fossil fuel expansions in recent months, including new compressors for the Iroquois pipeline.

“If Gov. Hochul moves to revive the Constitution Pipeline — or any other fracked gas pipeline project — it would be a reckless and unacceptable capitulation to President Trump and the polluting fossil fuel interests backing him,” said Laura Shindell, the group’s New York state director. “This pipeline was defeated already because the overwhelming majority of New Yorkers refused to be collateral damage for the gas industry. Turning her back on communities to appease polluters would be an astonishing failure of leadership. If Hochul decides to go down this foolish path, she will be met at every turn by the full force of New York’s energized climate movement. She will certainly regret it.”