Electricity imports from Canada into New York have continued without any change to prices, but the “fluidity and uncertainty” of President Donald Trump’s trade policy make it difficult to predict anything, state agencies reported to Gov. Kathy Hochul in March.
“It is still unclear whether the tariffs are meant to include electricity sales,” the New York Department of Public Service, New York State Energy Research and Development Authority, and Division of Homeland Security and Emergency Services said in a joint analysis released March 19. “While the 10% energy tariff has been in place since March 4, and energy imports have continued unchanged since they took effect, the tariffs have not yet appeared on invoices from suppliers.”
However, while “impossible to accurately forecast at this time,” it is expected that Trump’s threatened tariffs on non-energy products, such as steel and aluminum, would impact the supply chains for transmission and distribution facilities, generators and other utility infrastructure investments.
Trump imposed a 10% tariff on energy imports March 4, and additional, “retaliatory” tariffs — in response to Canada’s own tariffs — on vehicles and automotive parts will begin April 2. (See Ford Suspends Ontario Electricity Tariff as Trump Wavers.)
“While the fluidity of this situation makes it difficult to forecast the precise energy cost impacts of the tariffs, we have concluded that the potential cost impacts would not be material in the short term, but due to extensive variables outside our control, the tariffs could have significant affordability impacts in the long term,” the agencies wrote.
Electricity costs could increase by $42 million to $105 million annually, while natural gas could increase by up to $4.4 million. The agencies based this assessment on a review by NYISO of historical imports and their own review of trade patterns.
Liberty Gas — which services Franklin, Lewis and St. Lawrence counties, all along the Canadian border — is “heavily reliant” on imports for its roughly 14,600 residential household customers, 1,700 commercial and 21 industrial customers, according to the report. Two co-generation plants in the North Country region also depend on imports.
The analysis also notes that about 5,400 customers in Plattsburgh receive their gas directly from Canada, and no pipelines connect the city to the state’s gas network. If imports become unavailable, the report says the local utilities in the North Country lack the specialized equipment needed to accept truck deliveries of compressed or liquefied natural gas.
In the most extreme case, if Canada were to halt electric exports during peak summer months, “it could create reliability challenges” and retired natural gas plants could be called back into service, it says.
Connor Waldoch, founder of Grid Status and former senior associate with the NYISO Market Monitoring Unit, told RTO Insider he suspected the impact to electricity costs could be higher than the agencies estimate.
“I suspect that in real-world conditions, the tariff could incur costs greater than the $105 million high end of the range,” Waldoch said. “This is both from the direct imports side … as well as the potential increase in fuel costs for marginal units.”
He noted the agencies were working under an extremely short timeline to produce the analysis in an environment of considerable complexity. Hochul, along with U.S. Sen. Chuck Schumer, had requested the report March 10.
Kajal Lahiri, distinguished professor of economics at State University of New York at Albany, said that under the best of circumstances, economic forecasts are uncertain and include confidence intervals; this is not the best of circumstances.
“The issue right now is the market is so fragile, so uncertain as to where this is going,” Lahiri said. “What is Trump going to do? What’s really in his head?”
But regardless of what shape the tariffs take, “you know it’s going to hurt,” said Lahiri, outlining the numerous connections between the two countries. “There’s a huge business that takes place along those lines. Affecting them could mean pervasive effects on our society.”
FERC has approved filings by a pair of Massachusetts utilities establishing distribution fees for standalone electric energy storage systems (ESS) that connect to the distribution system but participate in ISO-NE wholesale markets (ER24-2795-001, ER24-2796-001.)
The filing comes in the wake of FERC Order 2222, which requires RTOs to eliminate obstacles for the participation of distributed energy resource aggregations in wholesale markets. FERC approved key aspects of ISO-NE’s compliance proposal for the order in 2023 (ER22-983-004). (See FERC Accepts ISO-NE Order 2222 Compliance Filing.)
The utilities, both subsidiaries of National Grid, wrote that ESS fees will be based on three rate components: an as-used peak demand charge; a contract demand charge; and an access charge, “reflecting different types of costs incurred by National Grid.”
The peak demand charge reflects “direct costs of owning and operating its distribution system.” The contract demand charge covers operations and maintenance expenses “for line transformers and meters, load dispatching, supervision and engineering, and allocated portions of labor-related overhead.” The access charge incorporates “costs incurred to provide WDS [wholesale distribution service] to specific customers.”
The Alliance for Climate Transition (ACT, previously named the Northeast Clean Energy Council) and the Massachusetts Attorney General’s Office (AGO) filed concerns about National Grid’s proposal.
ACT made the case that the distribution fees should not apply “when an energy storage system is providing ancillary services in response to ISO-NE dispatch instructions.”
The trade group wrote that FERC Order 841 exempts storage systems from transmission delivery fees when they are dispatched to provide ancillary services, and said the commission “should apply that same policy rationale to the corresponding issue of distribution charges.”
The group also asked FERC to remove or revise the proposed definition of distributed energy resource management systems (DERMS), writing that “the technology is not yet utilized on the company’s system,” and the timeline for implementation is unclear.
It also expressed concern that additional provisions in the proposed wholesale distribution tariffs (WDTs) would result in double charging distribution costs to ESS customers. ACT also opposed language directing ESS customers to be disconnected automatically if actual demand exceeds the contract demand value.
Meanwhile, the AGO requested that National Grid update its filing to account for the effects of recent orders by the Massachusetts Department of Public Utilities on National Grid’s state-jurisdictional wholesale distribution service rate calculations. The AGO asked National Grid to submit the orders to FERC with underlying data to support the calculations.
Responding to the protests, National Grid updated its filing to comply with the AGO’s request and removed the automatic disconnection provision highlighted by ACT.
National Grid defended its definition of DERMS in the tariffs, writing that it is “actively implementing DERMS through its ongoing grid modernization efforts and related pilot programs,” and that it will only use DERMS “when such product is a company standard offer and operational at the customer site.”
The company opposed ACT’s request to exempt ESS discharging for ancillary services from distribution fees.
“The impact of ESS imports and exports for ancillary services on the distribution system is the same as any other load or exports and loads exceeding system parameters can result in exceedance of system capacity,” National Grid wrote. “It is appropriate and necessary for ESS to pay for the use of the distribution system to provide ancillary services to ISO-NE.”
On March 28, FERC approved National Grid’s updated filing, writing that the changes to the utilities’ WDTs “are a just and reasonable rate design that allows ESS connected to the distribution system to participate in wholesale markets,” adding that the “rates reasonably reflect the costs of serving these customers.”
The commission wrote the changes made and additional evidence and clarifications provided by National Grid “address the concerns raised by the protesting parties.”
FERC agreed with National Grid’s argument that ESS discharging for ISO-NE ancillary services should not be subject to distribution fees.
“While the commission found it appropriate to exempt electric storage resources from transmission charges when they are dispatched to provide a wholesale service, the commission made no such finding with respect to wholesale distribution charges,” FERC wrote.
FERC directed National Grid to submit the effective date for the changes “no less than seven days prior to the date that the filing parties implement the proposed WDTs.”
Stakeholders Approve Protocol Changes for Real-time Co-optimization
AUSTIN, Texas — ERCOT stakeholders endorsed several protocol changes related to the ISO’s real-time co-optimization project, keeping on track a project seen as a cornerstone for future market improvements.
Alluding to the ongoing college basketball tournaments, ERCOT’s Matt Mereness, chair of the Real-time Co-optimization and Battery Task Force (RTC+B), portrayed the protocol changes as “the road to the Final Four.” Their approval sets them up for the Board of Directors’ consideration during its April 7-8 meeting, with the goal of beginning full market trials of the software and systems May 5.
“We’re six weeks out on the first set of [market] trials starting,” Mereness told members of the Technical Advisory Committee (TAC). “Today’s approval sets the stage for more approvals and people so that we can develop the code and parameters to dial those in for our market trials. That’s the gist of it.”
The key nodal protocol revision request (NPRR1269) determines and codifies policy changes that were deferred from the original RTC-related protocols developed after the project’s inception in 2019: ramping scaling factor values, ancillary service (AS) proxy offer floor parameters, and ancillary service demand curves’ (ASDC) use in reliability unit commitment (RUC) studies.
Two other NPRRs were placed on TAC’s combination ballot, essentially a consent agenda. NPRR1268 makes changes to the ASDC as modified by the Independent Market Monitor. NPRR1270 clarifies the removal of automatic ancillary service qualification and adds details for qualifying resources that provide the services in real time.
Much of the debate during the stakeholder process centered on the proxy offer floors. ERCOT initially proposed a $0 offer floor, which was supported by the IMM, but the RTC task force pushed for a $2,000 floor. A compromise eventually was reached on the minimum of a $2,000 floor or 95% of the ASDC.
The demand curves’ use in RUC studies was another “evolving discussion,” as Mereness put it, in determining the appropriate price signals within the study tool to drive efficient commitments. The Protocol Revision Subcommittee sent NPRR1269 to TAC with its approval of the ASDC compromise, a $15 RUC ASDC floor, and a $15 floor for real-time and day-ahead market ASDCs.
TAC approved NPRR1269 22-7 with one abstention. All six members of the consumer segment opposed the measure. They were joined by AP Gas & Electric, an independent retailer in Houston. In filed comments, the consumer interests asked the ERCOT board to “exercise judicious restraint before considering” the policy change.
“There is no real harm to waiting for [RTC] to be implemented before making such a fundamental shift in its design,” they wrote. “Frankly, consumers would prefer a future where ERCOT had to justify a RUC decision in a situation like this instead of a permanent structural change in the market to avoid the possibility of hypothetical RUCs.”
“Our concern is with the underlying approach. As to why you would institute a floor without evidence that it will resolve something, we would just generally be uncomfortable with unnecessarily intervening in market outcomes,” Eric Goff said during the TAC discussion. “You have to acknowledge that this is an administratively determined curve. In general, it’s appropriate for a curve to be able to indicate a lack of value, that something is demanded. That’s kind of one of the fundamental approaches that we see to the extent that the point of this is to alleviate some potential for RUCs.”
The IMM warned that the proposed ASDC floor for the day-ahead and real-time markets could result in more than $100 million in excess costs to consumers, saying the proposal is not supported by “economic fundamentals or empirical evidence.”
It said the proxy offer floor compromise “does not reflect a competitive offer and exposes consumers to unnecessary and excessive costs,” calling for an offer cap of no more than $15. The IMM also said the ASDC floor for RUC is not necessary for the commitment process to function properly when RTC goes live in December.
Large Load Task Force to Remove ‘Flexible’
The Large Flexible Load Task Force plans to return to TAC’s April 23 meeting with charter changes that rename the group by removing “flexible” from its title.
“We could never actually define flexible when the crypto miners, where this all started, came in,” explained the task force’s vice chair, Longhorn Power’s Bob Wittmeyer. “They said that they were flexible. By that, they meant they were flexible within settlement intervals. ERCOT interpreted that to mean within milliseconds, and there was some disconnect between those two things.”
The task force’s members also proposed the group be reclassified as a working group reporting to TAC, with a sub-group focused on data centers. TAC’s leadership was open to the suggestion.
“Task forces exist when the problem is envisioned to be short term and be solvable and go away,” Wittmeyer said. “Large loads certainly appear to be here to stay, and there are operational issues with city-size loads doing things. Anytime you have a city-size load, that can all react roughly at the same time, that’s a cause for concern.”
Staff told TAC that the large-load interconnection queue contains just over 99 GW in primarily standalone projects. ERCOT says it can confirm 4,616 MW have been energized.
Market Design Discussion Postponed
A scheduled discussion on a proposed new market design framework was put off until April’s TAC meeting because of March’s “weighty agenda,” said ERCOT’s Keith Collins, vice president of commercial markets.
CEO Pablo Vegas presented the framework to the board in 2024, saying the grid operator needs a structure that allows it to evaluate changes to the market design, relative to the attributes needed to reliably operate the grid. Staff presented the framework to TAC in October and received comments from stakeholders related to resource adequacy, initiative measurement and the structure’s alignment.
The framework’s pillars, as developed by staff, are to position ERCOT as an industry leader for reliability and resilience and to strengthen the footprint’s economic competitiveness. The grid operator says that while reliability is the organization’s primary objective, “costs should always be considered” as it seeks “market outcomes and solutions that result in the most competitive wholesale power rates and retail prices without compromising reliability or resilience.”
Large Load Modeling Requirements
The committee had to endorse NPRR1234 and its associated Planning Guide revision (PGRR115) twice when a desktop edit to the PGRR inadvertently created an unachievable compliance deadline, based on the measure’s anticipated approval date. Staff then conducted a triage of the NPRR to push the compliance dates out by two months.
The two changes establish interconnection and modeling requirements for large loads, defined as one or more facilities at a single site with an aggregate peak power demand of 75 MW or more. TAC unanimously endorsed both measures. Three members of the consumer and independent generator segments abstained from the PGRR.
The committee approved the combination ballot that included four NPRRs, one PGRR, a system change request (SCR) and revisions to the Nodal Operating (NOGRR) and Settlement Metering Operating Guides (SMOGRR) that, with board approval, will:
NPRR1256: Changes language in adjustment period and real-time operations protocols related to must-run alternatives (MRAs), primarily in grey-boxed language from NPRR885 (Must-Run Alternative Details and Revisions Resulting from PUCT Project No. 46369, Rulemaking Relating to Reliability Must-Run Service) to align the terminology for energy storage resources (ESRs) in the single-model era. It also specifies how qualified scheduling entities representing ESR MRAs would be settled for providing MRA service.
NPRR1268: Define the methodology for disaggregating the operating reserve demand curve into blended ancillary service demand curves.
NPRR1270: Update requirements for load resources that are changing under RTC and were not updated in earlier revisions; remove language associated with group assignments in the day-ahead market; eliminate the automatic qualification of all resources to provide on-line non-spinning reserve and SCED-dispatchable ERCOT contingency reserve service, among other changes. Resources will be required to undergo a qualification test to provide each of these services.
NPRR1273: Modify ESRs’ capacity to the amount sustained for 45 minutes included in the physical responsive capability’s calculation.
NOGRR274: Conforms the guide to NPRR1217’s (Remove Verbal Dispatch Instruction Requirement for Deployment and Recall of Load Resources and Emergency Response Service Resources) protocol changes.
PGRR119: Codify that a reliability margin will be used when limits associated with a stability constraint are modeled in the Regional Transmission Plan’s reliability and economic base cases.
SCR829: Add an application programming interface to upload and download unit testing data from the net dependable capability and reactive capability application.
SMOGRR028: Give guidance for allowing loss compensation for current limiting reactors.
The West-Wide Governance Pathways Initiative’s Launch Committee on March 28 said it hopes to seat a permanent board by either 2026 or 2027 for the regional organization (RO) that will govern CAISO’s Western energy markets.
Specifically, the Pathways Formation Committee is considering seating a permanent board by either July 2026 or April 2027 under Phase 2 of the group’s plan, which includes creating an RO that will oversee CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM), according to a committee presentation.
Speaking during a monthly update call, Kathleen Staks, executive director of Western Freedom and the Launch Committee’s co-chair, said the committee is evaluating the dates and will provide a recommendation during the next stakeholder meeting April 26.
A seven-member interim board will be put in place in the meantime, because board members must be listed when corporate documents are filed with the Internal Revenue Service, according to the presentation.
Staks clarified that the interim board will have limited duties and that the Launch Committee will retain its decision-making role. Putting in place an interim board, instead of seating a permanent one this early in the development of the RO, also saves money, Staks said.
Launch Committee member Jim Shetler, general manager of the Balancing Authority of Northern California, said about $250,000 is needed to sustain the committee through October, when the so-called Pathways Legislation is expected to pass in the California legislature. (See Pathways ‘Step 2’ Bill Sets Conditions for EDAM Governance.)
Shetler said he’s “comfortable” there’s enough money “to get us through October.”
“The issue will be post-October, … we’re looking at a couple options around when do we seat the permanent board, and the timing around that will obviously impact how much money we need. So, we’re still refining those numbers,” he said.
Shetler expects a budget within the next 30 to 60 days, “with a goal of trying to get commitments in place starting in October, November of this year to fund the remaining efforts on this Pathways Initiative.”
Pathways received a commitment of nearly $1 million from the DOE under former President Joe Biden’s administration in November to underwrite the committee’s efforts to establish an RO to oversee CAISO’s WEIM and EDAM.
The award was issued through the Pathways Initiative’s philanthropy adviser, Global Impact, which the group’s Launch Committee partnered with earlier in 2024 to secure outside funding for its operations, which so far have been supported by donations — and volunteered staff — from its participants.
President Donald Trump’s administration on Jan. 27 paused all federal grants and loans, according to a memo issued by the White House’s Office of Management and Budget.
As attendees fussed over their last morsels of breakfast, Emilie Nelson, COO of NYISO, opened the Independent Power Producers of New York Spring Clean Energy Conference with a keynote addressing the strange situation New York’s grid is in, and the need to continue to deliver reliability despite political uncertainty.
“Since the ISO’s inception in 1999, system reliability has been our top priority in the face of great change,” Nelson said. “We maintain that focus [through] societal changes, policy-based or technical issues, or being prepared to manage more frequent, extreme weather.”
Speaking of changes, Nelson was a last-minute substitution for NYISO CEO Rich Dewey, who was called away on short notice to testify before Congress. (See All 7 ISO/RTOs Send Senior Executives to Update Congress on Reliability.) Nelson touched on themes that probably were familiar to the audience: the tension between policy pushes for zero-emission generation, the aging grid, increasing customer costs and concerns about winter peaking.
“It is imperative that during this time of rapid change, … we maintain adequate supply necessary to meet growing consumer demand for electricity,” she said. “Competitive markets continue to provide the most powerful vehicle to speed investment in the grid.”
The message to independent power generators was not lost: The ISO needs them to continue to build more generators to replace retiring infrastructure.
Nelson said building effective wholesale markets has helped facilitate the grid’s transition, reduce power costs and protect ratepayers from development cost risks. Building the market to support future reliability was her “North Star,” she said.
How Things Have Changed
The address kicked off a day of discussion about navigating these treacherous waters. Concern about Donald Trump and Elon Musk’s disruptions came up repeatedly in panel discussions.
“The new administration feels like they’ve been in place for years even though it’s only been 65 days,” Todd Snitchler, CEO of Electric Supply Power Association, said during a morning panel discussion. “Across virtually all of the administrative agencies that impact our work, from FERC to DOE, to SEC to CFTC, all the places that touch the work we do are seeing some sort of disruption.”
Snitchler said some disruption was good and some was bad but all of it was confusing. He was unsure “what the goal” of the administration is.
At the same time, Snitchler said he observed a “tremendous” amount of state-level activity. Some states, like Ohio, are leaning into markets. Other states, like New Jersey, express doubts about the role of markets on the grid.
“New York is potentially in a spot where it needs a reminder about the value markets have provided and how customers have benefited,” he said.
From left: Marie French, POLITICO; Laura Chappelle of Potomac Law Group; IPPNY CEO Gavin Donohue; EPSA CEO Todd Snitchler; and NEPGA CEO Dan Dolan discuss regional challenges across control areas. | Timothy H. Raab and Northern Photo
Marie French, an energy reporter for POLITICO who moderated the panel, said she observed New York had slowed some of its climate initiatives. Some of that was due to the withering of federal support for offshore wind and other climate projects. Not all of the delays were because of Trump, in her estimation.
“They’re realizing that all of these things are more complicated to implement and a little more expensive than they had hoped,” French said.
IPPNY CEO Gavin Donohue remarked that until roughly six months ago, there had been a lot of conversation statewide about climate change, climate justice and carbon pricing. After the election, that conversation shifted abruptly.
IPPNY CEO Gavin Donohue | Timothy H. Raab and Northern Photo
“Everything has switched to be about reliability and affordability,” Donohue said. “With the economic development backdrop, we have data centers, chip fabs, just a new interest in economic development where we have to build a grid out to three to four times the size.”
Donohue said discussions about nuclear power also suddenly became prominent and that the state needs to build the market to attract all kinds of new generation technologies. He mentioned hydrogen and geothermal, which seem to have fallen out of the discussion, to his disappointment.
“Everything is going to collide, and we just need to be ready,” he said. “We need to make sure that we promote policies that are in the best interest of ratepayers and competitive markets.”
How Do You Build New Nuclear?
There’s renewed interest in building new nuclear power plants in New York. (See NY Takes a Closer Look at Advanced Nuclear.) Panelists said one key element is finding a community that wants a nuclear power plant.
Philip Church, Oswego County administrator, said that since 1969, the county has been home to the Nine Mile Point nuclear plant. The operator, Constellation, has been a good safety and economic partner, he added. “We’re the home of three nuclear power plants; 75% of New York’s nuclear plants are in our hometown.” If Church had his way, there would be a fourth nuclear unit in Oswego County.
Despite the optimism, the history of new nuclear in the U.S. is plagued with huge cost overruns and lengthy delays. The first new reactors built in the U.S. since 2016, Vogtle’s two units in Georgia went online seven years late and $17 billion over budget. (See NIA: Cost, Risk Sharing Needed to Grow Advanced Nuclear Pipeline.)
From left: Rich Barlette, Constellation Energy; Oswego County Administrator Phil Church; New York State Pipe Trades Association President Greg Lancette; Patrick White, Nuclear Innovation Alliance; and Marcus Nichol, Nuclear Energy Institute, discuss the challenges and opportunities posed by new nuclear power technologies. | Timothy H. Raab and Northern Photo
Patrick White of the Nuclear Innovation Alliance said new technologies are making nuclear power safer, more flexible and more appropriate for more locations. He cited small modular nuclear reactors, high-temperature gas reactors and sodium liquid metal reactors. Some of these are just smaller form factors of existing reactors, but others, like the liquid metal reactor, can generate enough heat to support a thermal energy battery.
“You start to see other options of how we can think differently about nuclear technology and how can it fit into a system to complement renewables,” White said.
ACE NY Executive Director Marguerite Wells | Timothy H. Raab and Northern Photo
At the same time, smaller reactors theoretically can help bring down construction costs and reduce safety concerns. If most of the components of a small reactor are built offsite and shipped to the building site, that can reduce costs. Smaller reactors run on less fuel and could be more easily contained.
While new technologies are often expensive, the panelists said this could be offset with federal, state or inter-company agreements to buy in, derisk and reduce construction costs for new technology.
“When you buy a piece of any other technology, you’re paying the average cost of what they’re able to produce it at,” White said. “Imagine how much more it would cost to buy an iPhone if you had to pay for the first iPhone’s development costs, the factory, the shipping, the supply chain, upfront.”
The panelists said co-purchasing between four to six units could hit “the sweet spot” to reduce the cost of an individual reactor.
IPPNY Study: Competitive Generation Reduces Costs
At the final event of the conference, IPPNY unveiled a study commissioned by the New York Affordable Clean Power Alliance about the impact of competitive markets on the cost of electricity. The Alliance is a new group formed out of IPPNY, the Alliance for Clean Energy New York, the New York Battery and Energy Storage Technology Consortium, and other renewable energy organizations.
Multiple Intervenors, a consortium of large industrial interests and large electrical consumers, issued a press release shortly after the conference, supporting the study.
“This report affirms Multiple Intervenors’ position that private investment in power generation results in lower electricity costs, greater reliability and improved environmental performance,” said Michael Mager of Multiple Intervenors. “Returning to utility-owned generation would only increase financial burdens on businesses already navigating challenging economic conditions.”
“Nearly 30 years ago, the New York PSC adopted a set of principals … starting with the premise that competition in the electric power industry will further [the] economic and environmental well-being of New York state,” said Shannon Maher Banaga, senior managing director of FTI Consulting, the study authors. “That premise holds true today.”
Members of FTI Consulting walked through their findings. After the introduction of a competitive generation market, the state’s electricity prices dropped steadily over the past 30 years. Meanwhile, the price of delivery increased steadily.
“If you compare the past five years of data to the five years prior to restructuring, total generation costs since are roughly 35% lower,” said Robert Kaineg, managing director of FTI. “But those of us that have been watching the news and are sensitive to these issues know that has not translated into lower bills for customers.”
Robert Kaineg, FTI Consulting Communications | Timothy H. Raab and Northern Photo
Kaineg said he found the costs of transmission and distribution had risen over time and that state policies supporting energy efficiency and clean energy further escalated costs.
“We’ve seen this come to a head recently with an announcement by Con Ed that it was going to increase its rates by 11.4%, but that buried the lead because they were raising delivery rates by more than 19%,” Kaineg said.
Kaineg added that private developers were less expensive in almost every case than utilities. Utilities faced all the same challenges that private developers did, and since restructuring, they didn’t necessarily have any in-house generation-building expertise.
“There really isn’t a reason to expect, from a cost or development perspective, that utilities are going to enjoy any advantages in asset development,” he said.
IPPNY’s Donohue said some of the increases in transmission and distribution costs fell on an overall lack of investment in the basic necessities of energy infrastructure.
“We have avoided making tough decisions on transmission and generation,” Donohue said. “When you wait 10 years to put a new line in, it’s obviously going to be a lot more expensive than it was 10 years earlier.”
ACE NY Executive Director Marguerite Wells said everyone expects more of the power system now than 50 years ago. More things are electronic; more things require electricity to work.
“We have to pay the piper to do stuff that’s been deferred for a long time,” Wells said. “But the truth of the matter is that it has nothing to do with the source of the electricity and … everything to do with serving the needs that people want from their power system.”
PROVIDENCE — Speakers at the ISO-NE Consumer Liaison Group on March 27 discussed the system-wide costs and emissions benefits of energy efficiency and demand flexibility and called on policymakers to double down on efficiency programs as energy demand grows.
State energy efficiency programs have faced some political scrutiny in recent months amid high winter energy costs. To help reduce near-term electricity costs, the Massachusetts Department of Public Utilities in late February directed utilities to shave $500 million off the upcoming three-year plan for the Mass Save energy efficiency program.
Jamie Dickerson, senior director of climate and clean energy programs at the Acadia Center, said energy efficiency is responsible for a roughly 15% reduction in the region’s overall power demand and has brought more than $55 billion in benefits to the region since 2012.
He said it’s unfortunate energy efficiency “has emerged as a scapegoat for some,” given the cost reductions it can provide. Moving ahead, he emphasized the importance of energy efficiency as peak loads increase and estimated that achieving 20% demand flexibility in winter could save the region about $8 billion in transmission spending by 2050.
“Let’s face it: In every possible way, negawatts — with an ‘N’ — are better than megawatts with an ‘M,’” said New Hampshire Consumer Advocate Don Kreis.
However, Kreis said it can be difficult to convince ratepayers they’re benefiting from energy efficiency programs when they may not receive the actual upgrades incentivized by the programs.
David Westman of the Vermont Energy Investment Corp. (VEIC), the administrator of Vermont’s energy efficiency programs, said demand reductions — especially at peak times — provide cost and emissions benefits to the entire system.
He highlighted how Vermont has helped ski resorts improve the efficiency of their snowmaking operations and said state incentives reducing the payback period for high-efficiency snow guns are a key component to convincing resorts to adopt more efficient equipment.
At Stratton Mountain in Southern Vermont, replacing 403 snow guns has enabled a 17% reduction in seasonal kWh demand and a 40% reduction in demand during the most essential peak winter hours.
He noted that VEIC operates an energy efficiency resource participating in ISO-NE’s forward capacity market (FCM), with about 116 MW of summer capacity and 156 MW of winter capacity. The resource’s participation in the FMC has generated over $80 million in revenue since 2010, all of which is invested back into energy efficiency efforts.
Westman praised ISO-NE’s commitment to keeping energy efficiency in its capacity market as it undergoes a major market reform effort. He said PJM’s move in 2024 to make energy efficiency resources ineligible for its capacity market “puts a lot of PJM ratepayers at a significant risk of higher costs.” (See PJM Asks FERC to Eliminate Energy Efficiency from Capacity Market.)
Brett Feldman, energy efficiency manager for Rhode Island Energy, acknowledged that many of the easiest energy efficiency reductions already have been achieved, with LED lighting “basically baseline now.”
However, he said there still is a lot of home retrofit work to be done as homes electrify and said it’s important to focus on electrification whenever possible with new homes. He noted that artificial intelligence tools could help provide more gains.
The flip side of artificial intelligence is significantly increased energy demand from data centers, and several speakers expressed concern that data center demand growth may wipe out some of the gains made by energy efficiency.
“AI specialized data centers are likely to represent the single largest driver of load growth in the U.S. over the next five to 10 years,” said Tyler Norris, a Ph.D. student at Duke University who is focused on power systems.
He recently authored a study that found that, because the U.S. power system is built to meet infrequent peak loads, existing headroom on the grid “is sufficient to accommodate significant constant new loads, provided such loads can be safely scaled back during some hours of the year.”
The study found ISO-NE has the capacity to add 4.3 GW of new demand with just 1% curtailment, or 3.5 GW with just 0.5% curtailment.
Pacific Gas and Electric will meet some of this year’s summer electricity demand in California through a virtual power plant demonstration project that will include as many as 1,900 residential customers.
And in another recent announcement, PG&E said it will award up to $43 million for nine microgrid projects in Northern and Central California. The money, distributed through the company’s Microgrid Incentive Program, will fund the development of community microgrids in disadvantaged areas.
PG&E described its virtual power plant program, known as Seasonal Aggregation of Versatile Energy (SAVE), as a peak load shifting and shaping program.
It will recruit up to 1,500 residential electric customers with battery energy storage systems and about 400 customers with smart electric panels. The VPP will be dispatched from June through October for up to 100 hours.
Program participants will be concentrated in California’s Central Valley and the south San Francisco Bay Area.
PG&E is partnering on its VPP demonstration with Sunrun, a company that sells residential solar-plus-storage systems.
Using Tesla’s grid services platform, Sunrun will optimize Powerwall batteries to provide a precise amount of power at specific times to certain locations. For non-Tesla batteries, Sunrun will use Lunar Energy’s Gridshare platform.
Sunrun will manage participating customers’ battery dispatches while making sure participants have at least 20% of their battery capacity in reserve in case of power outages.
“Customers with home batteries are a solution to alleviating strain on our electric grid,” Sunrun CEO Mary Powell said in a release.
Smart Panel Participants
Residents with smart electric panels will participate in the VPP program through a partnership between PG&E and grid service provider SPAN, which will shape home energy demand during peak events.
Customers will be able to set preferences on an app so they can use certain appliances during peak hours while still reducing grid congestion.
PG&E said it chose places to deploy the VPP program based on:
the potential for overloading during peak summer hours;
participating aggregators’ concentration of customers; and
ability to test performance across varying load shapes.
About 60% of SAVE participants will be in low-income or disadvantaged communities.
PG&E is conducting the VPP demonstration project as part of California’s Electric Program Investment Charge (EPIC) initiative. Funded by utility customers, EPIC invests in research that may help the electricity sector meet the state’s energy and climate goals.
Microgrid Grants
In a separate program, PG&E announced $43 million in funding for nine microgrids in communities deemed vulnerable to power outages.
The microgrids, which can be disconnected from the grid and provide energy during an outage, typically serve homes and essential facilities such as hospitals, police and fire stations, food markets, and water treatment plants.
PG&E selected the nine projects from a pool of about 50 inquiries. The projects are in California’s North Coast and North Bay areas. Four will serve tribal communities.
Generation resources in microgrid projects may include solar, battery storage, pumped hydroelectric storage, small hydroelectric and biomass.
PG&E is planning a second round of Microgrid Incentive Program grants and will accept applications from April 3 through May 30.
The current debate in the U.S. electricity sector pitting efforts to increase renewables against the need for grid reliability in the face of growing demand could be unnecessary and counterproductive, according to Ric O’Connell, executive director of the nonprofit GridLab.
Faced with ever-escalating forecasts of demand growth from data centers, “a lot of utilities and grid operators and their regulators are getting a little nervous … that we’re not going to be able to have adequate resources to meet this growing load,” O’Connell said.
“I actually don’t think that concern is valid. I think we can do both. … We can both grow the clean energy percentage of our electricity and grow the amount of load that we need to meet certain demand,” he said.
Speaking at a March 26 webinar hosted by the nonprofit Energy Innovation Policy and Technology, O’Connell cited real-world, real-time examples to support his argument.
Texas now leads the U.S. in terms of total generating capacity, growing 36% over the past decade, while also doubling its share of renewables from 23 to 42%, he said. During times of peak production, carbon-free resources may provide more than 80% of the state’s power.
ERCOT’s online dashboard, tracking energy supply and demand across the Texas grid, showed solar, wind and nuclear making up about half of its generation mix March 27.
SPP ran about 47% on carbon-free generation in 2024, with wind power across the region at times providing 90% of the RTO’s power, O’Connell added.
“Reliability is thrown out a lot, and not always accurately or correctly,” said Sara Baldwin, Energy Innovation’s senior director of electrification policy and co-author of the report. “Reliability is actually a characteristic of the entire electricity system, and individual resources contribute to reliability as part of a balanced portfolio. …
“So, whenever you hear someone talking about the reliability of a single resource, that should raise a flag.”
The Energy Innovation report defines reliability as a combination of three core components: resource adequacy (long-range planning for future demand), operational reliability (day-to-day, real-time balancing of supply and demand) and resilience (the ability to ride out and recover from extreme events).
The traditional arguments raised against renewables are that they are intermittent and therefore cannot provide the 24/7 reliability and grid support services of coal, natural gas or nuclear power. But according to Julia Matevosyan, associate director and chief engineer at the Energy Systems Integration Group, technology is available to allow solar, wind and storage to provide a full range of grid support services, through the inverters that convert the DC power from solar panels and wind turbines into the AC power the grid uses.
The capabilities of these inverter-based resources have evolved as the percentage of renewables on the grid has increased, said Matevosyan, who previously worked as the lead planning engineer at ERCOT. For example, as renewables hit 10 to 20% of generation, inverters had to be set to ensure a solar or wind project could stay online and in operation in the event of a brief disturbance on the grid.
As renewables start to replace coal or natural gas, their inverters have to be able to provide voltage and frequency support, she said. At even higher levels, up to 75%, inverter-based resources can provide “essential reliability services,” with “grid-forming” technologies, which are “advanced controls … [that] can provide the suite of reliability services that synchronous generators are providing today,” Matevosyan said. “With that technology, you can potentially go to 100%” renewables.”
Grid-forming technologies have been demonstrated on small islands and in “large-scale system studies,” she said. “So, from the technology perspective, what I want to say is, just as the grid evolves and we define what the grid needs ― we define it in technology-neutral terms ― technology will step up and provide.”
Clean, Firm Emerging
But the Energy Innovation report also acknowledges that a significant gap exists between IBRs’ technical capabilities and industry confidence in their ability to deliver when needed in real life.
“Developers must be disciplined to program their resources to ride through a voltage event [even] if such a setting should compromise their asset or their operating revenues,” the report says. Similarly, utilities and grid operators need to “quantify and understand how IBRs respond during a grid emergency” and ensure appropriate compensation in cases where they “provide a superior response.”
At present, utilities, grid operators and the Trump administration are looking to natural gas and nuclear to respond to what they see as a looming reliability crisis, while characterizing renewables as intermittent and unreliable.
In his opening remarks at a March 25 congressional hearing on grid reliability, Rep. Bob Latta (R-Ohio) said EPA regulations limiting emissions from power plants were driving early retirements of dispatchable baseload power.
“Significant subsidies for intermittent generation undermine the economics of baseload, or on-demand, dispatchable generation resources that are essential to keeping the lights on,” Latta said.
Speakers at the Energy Innovation webinar offered two potential low- or no-carbon solutions.
First, demand-side management can provide varied options for improving grid reliability, O’Connell said.
“We don’t want to just focus on the supply side. … It used to be hard to sort of have load that was responsive to price or other kinds of signals, but now we’ve got smart thermostats; we’ve got customer-sited batteries; we’ve got EV charging,” he said. “Really, this is a load that can be controlled and respond to market signals. This is a really important way that we’re going to be able to meet our reliability [needs].”
Wilson Ricks, a doctoral researcher at Princeton University, pointed to the second solution: emerging clean, firm technologies, including long-duration energy storage, next-generation nuclear and geothermal, and fossil fuel generation with carbon capture and storage.
Rising amounts of renewables on the system are flipping seasonal demand peaks from hot summer afternoons, when renewables tend to be plentiful, to cold winter mornings, when they are not. “Current batteries are not necessarily a cost-effective solution to very long periods of low wind and solar output,” Ricks said.
“There’s a whole suite of emerging technologies that are designed to help fill these very rare but important gaps and ensure a 100% reliable, clean system,” he said.
The catch, Ricks said, is that all the promising technologies are still in early stages of development and commercialization and are very expensive. Demonstration projects are in the works, he said, but “ensuring the success of at least some of these projects is going to be crucial to ensuring the availability of a portfolio of clean firm resources that we’re going to need for 100% reliability.”
Getting clean, firm generation to commercial scale could also change the role of always-on baseload power as a foundation of reliability. While it will always be needed and valuable in some circumstances, “baseload has not been a panacea in the past,” Ricks said. “It’s only one portion of our grid. We still have fluctuating demand, and baseload generators don’t meet that. It’s certainly not the end-all, be-all of reliability going forward.”
NEW ORLEANS — Sunny Wescott, chief meteorologist for the U.S. Department of Homeland Security, opened her presentation at SERC Reliability’s March 26 Members meeting by promising, “It’s only going to get worse.”
And while she was referring to the font size of the many text boxes crowding her slides, she could just as easily have meant the content of her talk about the growing risks that climate change poses to the electric grid and other critical infrastructure around the globe.
Wescott has made several appearances at ERO events in recent years, delivering speeches filled with so many warnings about developing dangers that NERC CEO Jim Robb joked at 2024’s GridSecCon security conference that he wanted to find her parents and “ask what they were thinking when they named her ‘Sunny.’” (See Weather-security Connections Highlighted at GridSecCon.)
The presentation to SERC members followed this pattern, with Wescott — who emphasized that she was there as “Sunny the scientist” rather than in her official capacity — emphasizing that the world faces unprecedented changes to weather patterns. Operators will need to prepare for an era of uncertainty that will challenge the assumptions under which all human infrastructure has been constructed.
Wescott started by laying out the basics of the changing climate, using a chart based on data from the National Oceanic and Atmospheric Administration that showed 2024 and the 10 warmest years on record — all from the last decade — in terms of monthly differences from the average temperatures in the 20th century. She warned that this trend is pushing conditions beyond what existing atmospheric models were meant to deal with.
“When we see abnormal temperatures like this, the models could not have been trained on it. It’s impossible, because this is superseding all prior years,” Wescott said. “The 10 hottest years on record all having occurred in the last decade means that this is a continuous growing trend.”
Scientific models aren’t the only things being pushed past their limits, Wescott continued. All of the materials used to build infrastructure facilities — concrete mixtures, adhesives, metals and others — were formulated to work in climate conditions similar to those that prevailed in earlier decades.
Those assumptions all need to be re-examined now, she said. Certain formulas for concrete may not set as quickly, or at all, in hotter temperatures. Epoxies may need longer to cure and not be as flexible when they do, leading to cracks. Some chemicals may begin to produce harmful vapors in higher temperatures. Extreme heat can cause metals to expand and weaken the structures of which they are a part, in addition to affecting their electrical resistance and magnetism.
More dangers will come from the winds and precipitation fueled by the increased evaporation of water. Wescott said that “super cell [storms] are now … covering more area [and] staying on the ground longer,” and went on to mention “a fivefold increase in straight line winds” and hail stones more than 8 inches in diameter recently seen in South Dakota. Hailstones also contain less air than they did 20 years ago, meaning they are heavier and more damaging.
The problems extend beyond the infrastructure equipment itself. Sustained high heat will create hazards for repair crews: They may dehydrate; their equipment may become hot enough to burn them; and their cell phones may overheat and malfunction. Extreme heat is even known to make animals and humans more aggressive and violent, meaning security could become more of a problem.
Effects may even be seen below the surface, Wescott said. She explained that aquifers around the world have run low in recent years, with heat causing both accelerated evaporation and increased use for drinking and cooling. Depleting this water leaves large voids underground, which makes these regions more vulnerable to seismic stress.
Areas of increasing seismic risk in the U.S. with locations of nuclear power plants | USGS
Wescott shared a map of the country based on data from the U.S. Geological Survey, showing areas of increased seismic risk. She overlaid this map with dots representing nuclear reactors, noting that multiple reactors were located in areas the USGS marked red, indicating highest risk.
“I’d heard it was a killer presentation. I just hadn’t realized it was actually a killer presentation,” SERC board Chair Lee Xanthakos joked after Wescott’s presentation. He asked Wescott for her opinion of the best ways to build infrastructure that could withstand the climate changes of the future. She replied that “it’s both the materials and the shape.”
“Look at the structures that we have chosen. This room is a great example,” she said, gesturing around the rectangular conference room where the meeting was held. “We know that flat edges do not sustain [wind and water] well [and] domes do. I’ve always [said] that … the future is domed, not doomed.
“If we were able to go back and choose different shapes, different material types — what does it look like to take a structure like this, not scrap it and say that the structure is weak and needs to be completely redone, but create an exoskeleton that can go over it to increase the tensile strength of the building in full? There are mitigation strategies like that. … There is no reason for most of our sites to be as under the thumb of these weather events as they are. They don’t need to take as much damage.”
CAISO’s Department of Market Monitoring (DMM) said March 27 that lower natural gas prices helped drive down energy prices in the Western Energy Imbalance Market (WEIM) in the fourth quarter of 2024.
Energy prices across the WEIM averaged about $39/MWh in the 15-minute market — down approximately 31% compared to the fourth quarter of 2023 — despite load being about 2% higher on average, according to Ryan Kurlinski, the DMM’s senior manager of monitoring and reporting.
Similarly, the DMM’s quarterly report found prices in the five-minute market “were also down 31% and day-ahead market prices were down 22% compared to Q4 2023.”
The lower energy prices were largely due to lower gas prices, according to the DMM.
“Average fourth quarter prices at the two main delivery points in California (PG&E Citygate and SoCal Citygate) decreased by 31% and 50% compared to the same quarter of the previous year, respectively,” the DMM report stated.
Prices at the Henry Hub trading point, a reference point for natural gas markets, decreased by 14% in the fourth quarter of 2024 compared to the same quarter of 2023.
Prices at Northwest Sumas and El Paso Permian also dropped by 47% and 26%, respectively, during the same period, according to the DMM.
Compared to the rest of the WEIM region, California recorded the highest average energy price at about $45/MWh in the quarter, while other regions’ 15-minute market prices ranged between $32/MWh and $38/MWh, according to DMM.
“The greenhouse gas costs in California continue to be a significant contributor to the higher prices in California compared to other regions,” Kurlinski said.
The fourth quarter of 2024 also saw an upswing in generation from renewable resources in the WEIM footprint. Renewable output “increased by about 4,320 MW (14%) compared to the fourth quarter of 2023. Over 65% of this growth was from wind and solar generation, both of which increased in every region,” according to the report.
Average hourly battery discharge in the CAISO and Desert Southwest regions also increased by 490 MW (64%) and 300 MW (125%), respectively.
Meanwhile, the report pointed to a continued pattern of congestion revenue rights auction revenues underfunding CRR payments, with the fourth quarter marking a $1.7 million shortfall. (See Congestion Revenue Rents Still Underfunded, CAISO DMM Says.)
“These losses are borne by transmission ratepayers who pay for the full cost of the transmission system through the transmission access charge,” according to the report. “Changes to the auction implemented in 2019 have reduced, but not eliminated, losses to transmission ratepayers from the auction. The [DMM] continues to recommend further changes to eliminate or further reduce these losses.”
