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March 4, 2025

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Seattle City Light, Others Urge BPA to Pause Day-ahead Decision

The Bonneville Power Administration should remain in CAISO’s Western Energy Imbalance Market (WEIM) and hold off on joining a day-ahead market, Seattle City Light and other Northwest parties urged in a letter sent to BPA CEO John Hairston days before the agency is expected to issue its draft day-ahead market decision. 

In the March 3 letter, City Light, Portland General Electric (PGE), PacifiCorp and three labor groups praised BPA for pushing for independent market governance in the West, saying the agency’s involvement in developing day-ahead markets by SPP and CAISO has resulted in important market governance reforms. 

With BPA slated to release its draft day-ahead market decision March 6, the signatories argued the “DAM decision presents a critical opportunity for BPA to acknowledge the results of its leadership on governance reform, the desire for additional progress, and the need for additional information to provide the strongest business case for a decision to join a DAM that delivers the greatest economic and reliability benefits to BPA customers.” 

The letter contended that BPA has three options: 

    • joining SPP’s Markets+, which has independent governance but a smaller footprint with a higher risk of market seams and “great efficiency challenges for itself and the region”; 
    • participating in CAISO’s Extended Day Ahead Market (EDAM), “a market within CAISO governance but with a larger footprint and momentum and progress towards independent governance”; and 
    • joining neither market and continuing to participate in the WEIM. 

When asked to comment on the letter, BPA spokesperson Doug Johnson told RTO Insider in an email that the agency “has no plans to alter its current timetable for the day-ahead market decision.” 

BPA staff previously recommended Markets+ largely because of the market option’s independent governance design. Dawn Lindell, CEO of City Light, argued in a November letter that BPA’s Markets+ leaning was “alarming,” saying the agency ignored studies showing the economic benefits of EDAM. (See Rising Tensions Evident at BPA Day-ahead Markets Workshop and Markets+ Leaning ‘Alarming,’ Seattle City Light Tells BPA.) 

A municipal utility, City Light is the largest entity in BPA’s “preference” customer base of publicly owned utilities.  

In January, Hairston tamped down expectations that BPA is all in on SPP’s Markets+. (See In Letter to Senators, BPA Tempers Markets+ Leaning.) 

In the March 3 letter, City Light and the other signatories again pointed to the studies to argue that EDAM could provide significant benefits and that joining Markets+ would be costly. 

Additionally, “BPA’s own analysis through the Western Markets Exploratory Group (WMEG) shows double the benefits for BPA when choosing to remain in the WEIM with current market commitments compared to participation in Markets+ ($398 million v. $203 million),” the letter stated. 

BPA’s March 6 deadline also ignores recent steps taken to create a new independent regional organization that will assume governance over CAISO’s markets, according to the letter. 

California state lawmakers on Feb. 20 introduced a bill that sets the conditions under which CAISO and Golden State utilities can participate in energy markets governed by an independent regional organization. (See Pathways ‘Step 2’ Bill Introduced in Calif. Legislature.) 

In asking BPA to postpone its day-ahead market decision, the letter also took note of the need for more information and recent staffing challenges brought by the Trump administration. (See 2 Top BPA Execs to Depart; Army Corps of Engineers also Faces Massive Cutbacks) 

“[W]e ask that BPA choose to remain in the WEIM for the foreseeable future and not commit to join a day-ahead market at this time,” the letter stated. “This would allow BPA to explore mechanisms to better monetize its participation in WEIM, while continuing to lead on governance reform as it considers future DAM opportunities. Additionally, it would delay the creation of an unavoidable, not easily managed or reversible, seam and maintain the coordination in the West that is critical to keep the lights on and costs down.” 

Another notable aspect of the letter: It was signed by three International Brotherhood of Electrical Workers locals representing workers at City Light, BPA and Tacoma Power, marking the first time any of those unions have taken a position on the day-ahead markets issue. IBEW 125 in Portland, Ore., represents workers at PGE and PacifiCorp, in addition to BPA. 

Tacoma Power last month became the second Northwest entity to commit to joining Markets+. (See Tacoma Power to Join SPP’s Markets+.) 

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ISO-NE Braces for Tariffs on Canadian Electricity

In preparation for potential fees on electricity imports from Canada, ISO-NE requested authorization from FERC on Feb. 28 to collect import duties while simultaneously arguing that the RTO “is not the appropriate entity” to do so (ER25-1445).

The Trump administration’s monthlong pause of the tariffs on Canadian goods, which include a 10% fee on energy imports, expires March 4.

Vague language in the original executive order, coupled with limited communication from the administration, has created significant uncertainty regarding what is included in the energy carveout, how the tariffs will be applied and whether the tariffs apply to electricity. (See Uncertainty Remains Around Energy Tariffs amid Last-minute Deals.)

Along with the 10% energy tariff, President Donald Trump on Feb. 1 imposed tariffs of 25% on all other imports from Canada, as well as those from Mexico.

At a press conference March 3, Trump said the tariffs will proceed, with “no room left for Mexico or for Canada” to avoid them.

ISO-NE has argued that the tariffs “do not appear to apply to electricity and that, even if they do, ISO New England would not be responsible implementing them.”

The RTO noted that the definition referenced by the February order on Canadian imports does not explicitly include electricity. It defines energy or energy resources as “crude oil, natural gas, lease condensates, natural gas liquids, refined petroleum products, uranium, coal, biofuels, geothermal heat, the kinetic movement of flowing water and critical minerals.”

ISO-NE also pointed to statements from the U.S. International Trade Commission indicating that electricity is exempt from U.S. tariff laws.

The RTO’s proposal is intended to protect it if the administration does in fact determine it is responsible for the tariffs, which would pose a “significant financial risk to the ISO” if it does not have the means to collect the fees, it said.

It noted that the “failure to have a cost-recovery mechanism in place prior to the effective date of a Canadian import tariff would place the ISO at risk of noncompliance with a federal obligation and, in a worst-case scenario, could force the ISO to seek bankruptcy protection.”

If it is unable to pay the duties, the federal government could direct the RTO to suspend imports, which could create “precipitous, adverse consequences” for grid reliability, ISO-NE wrote.

It estimated that a 10% tariff on electricity imports would cost the region about $66 million annually, while a 25% tariff would cost the region about $165 million annually. The RTO noted that Canadian imports have covered about 11% of the region’s load over the past five years.

Imports are poised to increase when the New England Clean Energy Connect (NECEC) transmission line comes online, likely by early 2026. The NECEC project includes a long-term contract for the supply of baseload power from Québec to Massachusetts. Hydro-Québec has said it is monitoring the potential effects of the tariffs on its long-term contracts.

To prevent potential fallout for the New England market, ISO-NE proposes a “temporary mechanism” enabling it to collect the tariffs. In the absence of direction from the administration regarding which entities ISO-NE should collect the duties from, the RTO would charge the fees “to the entities selling the assessed electricity into the ISO-administered market.”

If the federal government provides more specific information around the responsible entities, ISO-NE would alert its market participants and adopt the requirements, the RTO noted.

The proposal will only take effect if the Trump administration determines ISO-NE is responsible for the tariffs. If the temporary mechanism does take effect, the RTO said it would work with stakeholders to create a “cost-collection mechanism that is specific to the terms and conditions of the import tariff and resulting imposed import duties.” The RTO would be required to file the final mechanism within 120 days of the date the temporary mechanism takes effect.

ISO-NE said its proposal is intended to apply to any other future import duties imposed by the federal government on electricity. The Trump administration has said it may increase the tariffs if Canada retaliates with its own duties on U.S. goods.

Ontario Premier Doug Ford on March 3 said he is prepared to cut off electricity exports to the U.S. “with a smile on my face” if the tariffs go into effect.

“They rely on our energy. They need to feel the pain. They want to come at us hard; we’re going to come back twice as hard,” Ford said.

The RTO requested an expedited review of its order, asking FERC to rule on its filing by the end of March and accept a March 1 effective date for the proposal. It also asked for a shortened comment period ending March 10.

ISO-NE’s filing mirrored a proposal submitted by NYISO on the same date. NYISO also argued that the executive order does not appear to apply to electricity but asked FERC to authorize it to collect tariffs if required to do so by the administration. (See NYISO Preparing to Collect Duties on Canadian Electricity Imports.)

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ACORE Panel: Did Loper Bright Really Overturn Chevron?

WASHINGTON ― The headlines in the wake of the U.S. Supreme Court decision in Loper Bright Enterprises vs. Raimondo were unequivocal: The Chevon doctrine had been overturned, ending court deference to federal agency expertise in interpreting vague or ambiguous legal statutes. 

Well, maybe not, according to David Hill, executive vice president for energy at the Bipartisan Policy Center. “It’s absolutely true, Chevron was overruled,” Hill said during a panel on the changing legal landscape under the Trump administration during the second day of the American Council on Renewable Energy’s Policy Forum on Feb. 27. “But it’s worth actually thinking about what was the Chevron decision, and what were the courts and the agencies actually doing … and what did the court in Loper Bright … actually say?” 

Hill and others on the panel spent an hour trying to untangle the legalities, or lack thereof, in the onslaught of executive orders and actions unleashed in the six weeks since President Donald Trump was inaugurated, along with the impact of major court decisions like Loper Bright. 

Going back to the original Chevron doctrine, Hill said, the decision to defer to agency expertise in interpreting a statute was supposed to be a two-step process in which the courts first had to determine whether a statute was ambiguous or “clear on its face.” Part of the problem with Chevron was how it was applied, he said. 

“The courts would be all over the board with it. There were judges in individual cases that would disagree about whether or not a statute was clear or ambiguous,” Hill said, which complicated the second step of deciding whether an agency’s interpretation should be deferred to.  

Once again, the courts decided if an agency’s interpretation was permissible and reasonable. Under Loper Bright, courts no longer can give “binding deference” to agencies, he said. What they can do is “give the agency very great respect, due respect. They can consider it highly persuasive, especially informative, [give it] most respectful consideration, great weight. So, what’s the difference between that and some pretty great amounts of deference?” 

As the lower courts ruled on how to apply deference under Chevron, they also likely will “decide how much Loper Bright actually changed the real law,” Hill said. “Now they can’t say … ‘we’re just stuck with what the agency said,’ but they can give a lot of weight to what the agencies did, and I think they will on some of the really technical, statutory interpretations.” 

Cary Coglianese, director of the Penn Program on Regulation at the University of Pennsylvania’s Carey Law School, generally agreed with Hill’s interpretation of Loper Bright, but said the ruling likely would have symbolic impacts. Beyond the court overturning a 40-year-old precedent, “you have to also think about Loper Bright in the context of a larger Supreme Court that’s deeply skeptical of administrative power,” he said. 

Coglianese pointed to other recent cases, such as West Virginia vs. EPA, which raised the “major question doctrine demanding greater clarity whenever agencies are to use statutes to do something important, like regulating to protect against climate change.” 

Future cases may be “a little less about how Loper Bright is actually written and what it says, but more [about] what it actually means to be part of a larger, shifting legal landscape,” he said. “And quite frankly, we can’t discount at all the administrative and political landscape that’s shifting as well.” 

Is the Endangerment Finding Safe?

Speaking from the legislative side, Ana Unruh Cohen, Democratic staff director for the House Natural Resources Committee, said individual lawmakers “always aspire to write a very clear and direct … piece of legislation, and then things get negotiated; things change.”  

Certainly, as representatives move new bills, they are focused on ensuring their language is clear, Unruh Cohen said. Similarly, Hill said, agency staff writing regulations will have to think carefully about building a well-argued paper trail to validate their interpretation of statutes without relying on Chevron.  

Could Loper Bright also be used to advance further deregulation, such as a rollback of EPA’s 2009 endangerment finding, which allowed the agency to regulate greenhouse gas emissions under the Clean Air Act? 

Unruh Cohen noted that the Supreme Court has not overturned the endangerment finding in the past, even when it had the opportunity to do so, but Coglianese again pointed to the shifting legal and administrative landscape. “Maybe this current Supreme Court would be willing,” he said. “If they’re willing to go back and overrule Chevron, if they’re willing to go back and overrule Roe v. Wade,” is the endangerment finding really safe? 

“Maybe they would be happy to say, yeah … we now accept that EPA under the Trump administration has a better reading of the Clean Air Act that says it never authorized regulating greenhouse gas emissions.” 

Coglianese and Unruh Cohen both expect that any approach to overturning the endangerment finding would have to be done on statutory grounds rather than a full-on attack on climate science. Congressional Republicans have shifted their approach from one that questions climate science itself to one that asks which policies can best address the issue, Unruh Cohen said. 

Coming at it from a statutory perspective starts from the “question of whether we have the statutory authority in the first place to do this,” Coglianese said. “Then, quite frankly, none of that technical information really matters.” 

Coglianese also laid out the statutory and constitutional issues related to Trump’s funding pause. “One has to ask the people who are issuing these directives, do they have statutory authority? Second, are they acting in a manner that is not arbitrary? … 

“Then there’s these constitutional questions about whether it’s consistent with our separation of powers. Whether it’s consistent with the spending clause of the United States Constitution for the executive branch on its own to simply decide what we want to spend money on or not, even though Congress has approved and told the administration to carry out the spending.” 

The catch, he said, is the pacing and timing problem: “Those who control the computers are able to block funding, and there’s not a lot of transparency around that. The courts are being much more deliberative and trying to figure out what’s going on.” 

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FERC Approves $420K in Penalties for RF Utilities

FERC has approved a $380,000 penalty leveled against American Electric Power (AEP) by ReliabilityFirst for violating NERC’s reliability standards for relay trip limits, along with a separate $40,000 penalty against the Lansing Board of Water and Light (BWL) for infringing on NERC’s facility rating standard. 

The commission announced in a Feb. 28 filing that it would not further review the settlements between RF and the two utilities, filed by NERC on Jan. 30. FERC also indicated it would approve two other settlements involving violations of NERC’s Critical Infrastructure Protection standards. Details of these infractions, including the utilities and regional entities involved, were not made public in keeping with commission policy on CIP violations. 

According to the AEP settlement, the utility notified RF of its violation in June 2021 via a self-report (NP25-7). AEP told the RE that it had identified a potential noncompliance with PRC-023-4 (Transmission relay loadability) involving a relay on the Nagel-Phipps Bend 500-kV circuit. 

Requirement R1 of the standard lays out the criteria that utilities must use to ensure its circuit terminals do not “prevent [their] phase protective relay settings from limiting transmission system loadability while maintaining reliable protection of the” grid.  

Entities may choose one of 13 criteria to implement. Criterion 1 requires entities to “set transmission line relays so that they do not operate at or below 150% of the circuit’s highest seasonal facility rating” for a defined loading duration as close as possible to four hours.  

The relay in question went into service Dec. 27, 2019. RF said AEP didn’t know at the time that an engineer had listed the phase time overcurrent (TOC) setting for the relay in AEP’s settings workbook incorrectly, the result of the worker misreading an “engineering template default setting [that] limited the loadability of the line.” During a “storm and period of high load” on Feb. 16, 2021, the relay tripped and caused a misoperation on the Nagel-Phipps Bend circuit. 

RF said the values communicated to AEP’s transmission planning personnel for the relay’s summer normal and emergency ratings were 3,609 MVA, while the communicated winter normal and emergency ratings were 4,473 MVA. However, the actual ratings in all cases were 396 MVA. AEP performed an extent of condition review and did not discover any further PRC-023-4 noncompliance. 

The RE said the root cause of the noncompliance was the engineer placing the wrong settings into service. This error itself was due to confusion created by the relay-setting software. The software created a new folder every time a setting was changed, while keeping the original, unaltered settings in a separate folder called the working folder. The engineer used the settings from the working folder instead of the new folder. 

RF noted that AEP also lacked sufficient internal controls for validating relay settings. While the utility performs a peer review before settings are placed in service, and the correct settings were reviewed in this case, the problem arose after the review when the engineer mistakenly input the settings from the wrong folder. 

The RE assessed the risk posed by the violation as “serious and substantial,” observing that “improperly setting relays for transmission system components can prematurely trip these components out of service, limiting system operator flexibility and their ability to take controlled actions,” and “the worst-case scenario (a tripped relay that caused a misoperation) actually occurred during a storm and period of high load.” 

AEP’s mitigating actions — which the utility completed on Sept. 23, 2021 — include: 

    • Correcting the relay settings the day of the misoperation. 
    • Working with the settings software vendor to improve the confusing folder setup. 
    • Reviewing all relays with default settings enabled for the relevant areas. 
    • Introducing an automated relay settings tool to minimize human error when calculating settings. 
    • Checking similar protective relay settings for other instances in which the phase TOC was enabled incorrectly. 

Lansing BWL Settles for Ratings Errors

BWL’s settlement with RF stemmed from violations of FAC-008-3 (Facility ratings). It was the only settlement submitted in NERC’s monthly spreadsheet notice of penalty (NP25-8). Unlike AEP’s infringement, this violation was discovered by the RE during a compliance audit Dec. 11, 2020. 

RF determined that BWL had failed to “establish facility ratings consistent with its facility ratings methodology (FRM),” as required by requirement R6 of the standard — and requirement R1 of FAC-009-1 (Establish and communicate facility ratings), the standard in effect when the violation began.  

Under BWL’s FRM, all transmission lines and their vertical clearance should be capable of operating safely at 160 degrees Celsius. However, BWL only could demonstrate a safe operating temperature of 100 degrees C. RF attributed this discrepancy to a software issue. 

BWL updated its FRM to reflect the lower safe operating temperature and to “more clearly account for sag limited ratings.” After these changes, the utility still had to remediate thermal rating inconsistencies at two transmission lines, which it did by assigning both lines a higher sag limited rating. 

RF said the root cause of the issues was “multifaceted”; the incorrect software setting was due to inadequate verification controls, while the derates related to the thermal violations occurred because BWL’s procedures did not account for the “particular attributes” of field conditions around the two lines. Violations dated back to 2011, when the utility registered as a transmission owner and was required to comply with FAC-009-1, and ended on March 8, 2024, when BWL updated its FRM and completed remediation on the last line. 

The RE said the violation posed a moderate risk to grid reliability, due in part to the duration of the violation and the size of the derates on the two lines (39% and 83%). But RF also called the risk not serious because the company never operated the affected lines within 10% of the corrected facility ratings and no harm is known to have occurred. 

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IBR Lessons Can Guide Data Center Challenges, WECC Report Finds

With data centers already causing “major disturbances” on the grid, the industry could learn lessons from the recent growth and implementation of inverter-based resources (IBRs), according to a new Elevate Energy Consulting study.

The study, commissioned by WECC, noted that Northern Virginia experienced a large load loss event in July 2024 that resulted in “1,500 MW of data center load switching to backup power. Nearly 60 data centers spread across 25 to 30 substations disconnected from the [bulk power system]. Voltages throughout the area rose significantly and local capacitor banks were removed by operators to bring voltage back within limits.”

Meanwhile, WECC expects electricity demand across the Western Interconnection to increase by “an unprecedented 20%” over the next decade. Balancing authorities forecast demand to increase from 942,000 GWh in 2025 to 1,134,000 GWh in 2034, according to the study.

The report found that the rapid expansion of data centers is projected to be the largest contributor to demand growth and will likely impact BPS reliability.

The study noted that the electric power system has not seen this level of growth since the 1950s. Failure to effectively tackle those challenges “may result in unreliable operations of the BPS, an undesired outcome for grid operators and large load operators alike,” according to the study.

The situation is similar to the rapid growth and challenges brought by IBRs over the last decade, the study authors wrote.

“It is clear that the path ahead for the industry with these large load interconnections may follow a very similar trajectory as the interconnection of IBRs onto the grid,” the study stated. “The experience integrating IBRs can be used as a playbook for mitigating the reliability risks from large loads. The industry must learn from its past with IBRs and act rapidly to address the BPS reliability risks before larger and larger grid disturbances occur and impact the BPS.”

For example, while there are standardized procedures for BPS-connected generators governed by FERC, those mandated procedures do not exist for large load interconnections. Specifically, there is a lack of comprehensive data-sharing requirements, study milestones, timelines and other factors, according to the study.

“This may have sufficed when load interconnection requests were orders of magnitude smaller, and the breadth of requests was much lower,” the study states. “Today, an agile and well-documented load interconnection process is critical for ensuring BPS reliability and administering a fair, just and equitable interconnection process.”

FERC Order 2023 and the overhaul of the generator interconnection process driven by the growth of IBRs could provide guidance, the study authors contend. The order shifted the pro forma interconnection rules from a first-come, first-served serial process to a first-ready, first-served cluster study process. It ramped up financial requirements for developers and set penalties for transmission providers that fail to meet deadlines for completing interconnection studies. (See FERC Updates Interconnection Queue Process with Order 2023.)

Regulators must adapt quickly while ensuring regulations are “flexible, agile and updated frequently to adapt to the changing technology landscape and complex needs of large load interconnections,” according to the study.

“[T]ransmission providers typically do not have adequate interconnection requirements in place for large loads and may be challenged to enforce requirements on interconnection customers,” the authors wrote. “As has been observed with IBR risks, ensuring that clear, consistent and applicable interconnection requirements are in place to ensure that adequate data sharing, modeling, studies and operational performance are achieved is a critical aspect for BPS reliability.”

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MISO Approaching LMR/DR Accreditation Based on Availability

CARMEL, Ind. — MISO is nearing an overhaul of its capacity accreditation methods for load-modifying resources (LMRs) and demand response that would be based on whether they can assist during periods of high system risk.

The grid operator plans to accredit LMRs and its emergency DR and behind-the-meter generation depending on their offers during low-margin and risky hours where a capacity advisory, maximum generation alert or warning, or energy emergency is in place. The RTO reasoned that those hours best reflect when it is likely to need those resources.

MISO said it would require DR and LMRs to designate a response time when registering their assets. It plans to dock accreditation when resources report inaccurate availability.

Joshua Schabla, MISO market design economist, said the RTO has “dozens” of DR resources that have never updated availability throughout a planning year.

“We want to accredit a resource based on when it’s most needed. That’s the crux of this,” Schabla told the Resource Adequacy Subcommittee on Feb. 26. He warned that MISO compensates resources that never perform, and he said some resources “look like they exist when they in fact do not.”

MISO said data from its demand-side resource interface show that about 2 GW of DR is accredited but is never designated as available or self-scheduled.

The RTO plans to rely on the past year as a reference for accreditation. Staff said they are aware that using a single year makes for a more severe accreditation style, but that is by design to send a signal to respond. Last year it mulled using the past three years as a reference but decided that would water down accreditation too much.

Additionally, the RTO plans to split its LMR category into rapid responders with greater responsibility and those with a more lenient availability scheme by the 2028/29 planning year. (See MISO Closing in on New LMR Accreditation.) Nimbler LMRs would have a maximum response time of 30 minutes and presumed availability for all maximum generation emergency step 2 events. Slower LMRs would have a maximum six-hour response time and would be called up earlier — sometimes on a voluntary basis — during maximum generation warnings.

The accreditation plan would have an all-or-nothing aspect: MISO plans to assign zero values for the entire duration of an emergency or near-emergency event when resources fail to make any contributions for even one hour.

“It sounds harsh; it sounds mean. But that’s the line we’ve drawn in the sand. … That’s the tension we experience between availability and adequacy,” Schabla said.

He also said MISO wants to transition to an unlimited number of deployments instead of limiting DR’s deployments to a handful of times per season, as is practice now.

However, after a DR resource, BTM generator or the slower LMR type deploys once in a year, they can choose to declare themselves as unavailable in future deployment calls in exchange for reduced accreditation. Schabla said those resources can decide if a deployment is too expensive to carry out. The category of faster LMRs, on the other hand, would not be permitted to designate themselves as unavailable under any circumstances.

MISO staff have stressed that it is imperative that LMRs respond when called upon to retain resource adequacy as the fleet transitions.

“We want to make sure their accreditation is tied to their performance,” Zak Joundi, executive director of market innovation, said in front of MISO South regulators Feb. 24. Joundi reminded attendees that LMRs have chosen to register as capacity resources.

As part of its accreditation filing, MISO plans to debut a capacity availability tolerance band for DR resources, in which they would be required to perform between 88 and 112% of their stated load-reduction capability. MISO would cap the tolerance band at no less than 1 MW and no more than 30 MW for underperforming resources. Despite the upper bounds of the tolerance band, DR resources would not be penalized for overperformance.

Some stakeholders have said the tolerance band is too complex to include in the new accreditation method.

“Forecast errors are inevitable, and penalties are not appropriate for LMRs providing good-faith estimates,” WPPI Energy’s Steve Leovy said. MISO should waive accreditation penalties when LMRs provide “near-real-time demand data” or have used rigorous forecasting methods to estimate their availability, he said. A few tens of megawatts of standard deviation should not make a difference to MISO operations, he argued.

Schabla said LMRs using a firm service level to gauge reductions instead of a megawatt amount would not face accreditation penalties without the tolerance band. He pointed out that LMRs specifying megawatt reductions likewise face performance penalties. MISO’s DR resources can use either a firm service level or a megawatt value as the measuring stick for their reductions.

“We believe it’s fair to treat all demand response resources the same,” Schabla said, stressing that resources should be indicating their availability. He said there are LMRs in MISO who input the same availability information year-round, never adjusting for likely seasonal changes. The RTO expects DR to perform when called on, even if it proves expensive for the resource. Schabla said it is only fair that unresponsive resources take hits to their accreditation when unavailable.

“We’re paying you for years in between deployments,” he explained, adding that MISO compensates LMRs to respond only in emergency situations.

The RTO has called up LMRs 12 times since 2017, with half of those occurring during winter storms over the last few years.

“These events are very infrequent, and that’s to be expected in a system with a one-day-in-10-years reliability standard,” Schabla said.

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Study Finds Considerable ‘Grid Flexibility’ Potential in New York

A Brattle Group study released in February found that New York could achieve 8.5 GW in “grid flexibility” measures by 2040, saving consumers more than $2 billion a year.

The study was commissioned by the New York Department of Public Service as part of its Grid of the Future initiative, which defined grid flexibility as the “ability to shift either demand or supply to meet bulk power system and/or local distribution needs.” (See NY PSC Launches Grid of the Future Proceeding.)

The 8.5-GW figure is roughly 21% of NYISO’s forecasted winter peak demand and more than six times the current potential of 1.2 and 1.4 GW in the winter and summer, respectively. Grid flexibility measures could help by “displacing the need” for higher-cost resources, the study says.

“This report has really important implications for regulators, decision-makers and figures in industry,” said Amy Heart, senior vice president of public policy at Sunrun. “It sets out what the potential is, and how to get there. It demonstrates that this isn’t theoretical.”

The study says that implementing grid flexibility improvements could avoid $2.9 billion a year in power system costs by 2040, $2.4 billion of which could be returned to consumers. These cost savings come primarily from reducing how much investment in generation capacity would be needed to maintain reliability. Avoided distribution and energy costs were $408 million and $384 million, respectively.

“Really for the first time this says that there is a unique way for a flexible grid to meet this growing demand,” Heart said. “And we have the potential to use these resources and build programs that are cost effective.”

Currently New York’s grid flexibility primarily comes from NYISO demand response programs — Special Case Resources and Emergency Demand Response — amounting to about 1,300 MW of flexibility. An additional 414 MW of flexibility is facilitated by the Economic Demand Response program, in which large consumers reduce loads based on price signals in the day-ahead market.

Brattle found that managed electric vehicle charging, heat pump load control and residential behind-the-meter storage all had significant potential for increasing grid flexibility. In a future report, Brattle will examine the potential of thermal energy storage, thermal energy networks, increased efficiency, front-of-meter distributed storage and large loads with microgrids.

“This flexibility study is looking at things that we’re either currently doing or really close to doing, moving out of a pilot phase into mass market,” said Deb Peck Kelleher, deputy director of the Alliance for Clean Energy New York, highlighting EV charging demand-reduction programs. “I’m glad to see that those programs are working as they were envisioned to work.”

Noah Ginsburg, executive director of the New York Solar Energy Industries Association, said he was pleased that the report looked at the grid in a holistic way and that it did a good job identifying both barriers and opportunities for flexibility.

“The moral of the story to me is if we are smart and address these barriers and create the right pricing and regulatory conditions to deploy a lot of these flexible assets, that’s just a huge savings opportunity,” Ginsburg said.

Barriers Identified

Brattle identified several key barriers to getting grid flexibility measures implemented, with the lowest-hanging fruit being regulatory barriers like zoning, permitting and lack of state goals.

This hampers adoption by consumers and does not incentivize utilities to incorporate grid flexibility into their projections. The study also notes that New York’s cost-benefit analysis framework may undervalue flexibility initiatives, leading to the deprioritzation of some technologies.

Brattle is saying, “‘Hey, just make this simple and effective and easy for customers to navigate, to sign up and to bring these resources to the table,’” Heart said. “These are the sort of tangible actions that we can get everyone together and hammer out.”

Tariff complexity prevents consumers from understanding or evaluating potential benefits from established compensation mechanisms. Utility tariffs also lack support for bidirectional distributed energy resources, like chargers and batteries, which depresses adoption. Retail rates also are not designed for customers to take advantage of grid flexibility.

Ginsburg said that local building codes compound other regulatory problems. He noted that in most of the Consolidated Edison footprint in New York City, residential battery storage is banned for fire safety reasons.

“This isn’t a matter of getting batteries built; it’s a matter of fairness,” Ginsburg said. “Frankly, New York City and Con Ed ratepayers are funding a lot of the statewide incentive programs that the city of New York doesn’t allow them to access.”

Now that Brattle had identified the barriers, it was now on DPS to pick a pathway to advance, Ginsburg said. He said he hoped this would lead to improved rate design and compensation for distributed storage programs both behind and in front of the meter.

Peck Kelleher said the biggest challenge for DPS would be coordinating across all of its various proceedings and initiatives revolving around grid modernization.

“It was great work that was published by the Brattle Group,” Peck Kelleher said. “But how to take that data and inject it into each of the separate proceedings and keep them going in the same direction” will be a challenge.

Realistic?

“I think all power systems have unexploited flexibility and that something can, and should, be done,” said Francisco de Leon, a professor of electrical engineering at New York University. “I don’t think flexibility is the final answer to electric energy challenges of the future because its full-blown implementation (as described in the report) is very expensive.”

While de Leon said he was not opposed to the idea of increasing grid flexibility, the report was being “overly optimistic” about grid flexibility. He said the expected cost of generation in the report was far too high for the state to bear politically.

“Using the numbers in the report, the cost of marginal generation of electricity is expected to increase from $40 to $70/kW-year to over $200,” de Leon wrote in an email. “Would you like your electricity bill to increase by three to five times?”

Brattle says its analysis “found that overall net costs may be small relative to the size of the state’s economy and will be offset by the health and societal benefits. Nevertheless, managing power system costs will be crucial to delivering an affordable transition for New Yorkers.”

But de Leon said to expect a change of state government if the price of generation goes up that high as a result of decarbonization. With the current federal government not investing in renewables, and likely consumer unwillingness to deal with such steep price increases, decarbonization by 2040 was extremely unlikely, he said.

While load shifting could be “low-hanging fruit,” de Leon was also pessimistic about HVAC upgrades serving as a cost-effective way to reduce demand. He said that the cost of acquiring and installing new heat pumps makes retrofitting cost “thousands of dollars per room,” which is difficult to sell to homeowners and “impossible” to sell to renters.

“We should not pass on the opportunity of heat pumps for new construction,” de Leon wrote. “But in my opinion the cost to retrofit old buildings is very large.”

Demand for electricity is going to grow in New York, whether from AI centers or electrification or manufacturing; no matter what the cause, people still want ways to manage their electricity, Heart said.

“The question becomes how are we going to squeeze as much juice out of these resources that are in people’s homes and businesses to help keep those costs low,” Heart said.

She pointed to the distributed resource deployment in Massachusetts, where consumers can enroll in smart thermostat, solar and battery programs that compensate them for injecting power into the grid. (See Mass. DPU Approves 1st Round of Utility Grid Modernization Plans.)

“They have a very successful program,” Heart said. “While we encourage experimenting, we’ve done pilot programs; you don’t have to start from scratch. You can take this framework.”

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Wash. Bill Seeks to Attract Fusion Energy Developers

A bill to help attract nuclear fusion energy ventures to Washington is working its way through the state legislature.  

House Bill 1018 would allow developers of fusion projects to approach either the Washington state government or appropriate county government for permission to build on a parcel of land in the state. That would give fusion projects the same options that solar and wind energy ventures have in picking their approving authority.  

Most solar and wind developers in Washington have chosen the state as the entity less likely to bow to local opposition to a project.  

The state pathway in Washington is through the Energy Facility Site Evaluation Council (EFSEC), a committee of representatives from several state government departments. EFSEC makes recommendations to the governor, who issues final decisions. 

The Washington House approved HB 1018 95-1 on Feb 6, and the bill is now in the Senate’s Environment, Energy and Technology Committee.  

The Puget Sound area now boasts five fusion-related ventures. They include Helion Energy, which is working to provide fusion power to Microsoft by 2028; Zap Energy and Avalanche Energy, which are also working to develop fusion reactors; and ExoFusion and a subsidiary of Japan-based Kyoto Fusioneering, which are developing fusion-related technologies. 

Helion and a separate project at Lawrence Livermore National Laboratory have achieved fusion reactions that release more energy than went into the reactor. Based in Everett, Wash., Helion in January landed $425 million in funding from various investors. 

At a Jan. 20 House committee hearing on the bill, Helion representative Tom Bugert did not commit to a specific timeline for when fusion power would be commercially viable, but said “it’s right around the corner.”  

“I believe fusion energy is the future of clean energy. … This bill will attract cutting-edge research,” said Rep. Clyde Shavers (D), the bill’s sponsor. No one spoke in opposition to the bill during the hearing. 

Meanwhile, three other bills involving EFSEC died in committee because no action was taken on them by the Feb. 28 deadline to leave their committees. These were:  

    • House Bill 1188, which would have required affected tribes and the host county to approve an energy project before EFSEC makes its recommendations to the governor. The bill was a Republican response to EFSEC last year recommending that then-Gov. Jay Inslee approve a large wind farm in the Horse Heaven Hills area of Central Washington despite opposition from the Benton County government and local residents. Inslee approved the project. (See Wash. Gov. Approves Controversial Wind Farm.) 
    • Senate Bill 5283, which would have prohibited EFSEC from ignoring land use or zoning laws for siting electrical battery storage facilities in environmentally sensitive areas. The bill also represented a GOP reaction to EFSEC overruling Benton County’s land use and zoning laws. 
    • House Bill 1237, which was Democratic legislation that would have required a public hearing prior to an EFSEC recommendation in which the council determines that a proposed site is not complying with applicable land use plans or zoning ordinances. 
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Data Center Grid Integration Top Theme at CEC Workshop

As some data center operators plan to power their facilities with onsite generation, one researcher suggested it might be better to get electricity from the grid instead. 

“At the end of the day, the hyperscalers do not want to be in the business of running a powerhouse on their data center property,” said David Porter, vice president of electrification and sustainability at the Electric Power Research Institute. “What they really want long-term is a reliable and resilient power supply. And that doesn’t come from any better place than the grid.” 

Porter’s comments came during a California Energy Commission workshop Feb. 26 on California’s economic outlook, including data center growth. The workshop is part of the CEC’s 2025 Integrated Energy Policy Report (IEPR) process. 

Even if a data center had small modular reactors or a combined cycle turbine on site, Porter said, operators would have to contend with maintenance, refueling and repairs. 

“And it’s not a great equation for anybody that is connected to the grid to have the grid operator provide only backup service in times of extreme need and have to hold capacity back in their planning processes for some of those rare-type conditions,” he added. 

An issue for data centers is that the energy-intensive facilities can be built relatively quickly but may need to wait for capacity or transmission infrastructure. 

Helen Kou, a global research lead on data centers at BloombergNEF, said a standard feature of data centers is a backup generation system for reliability. But grid interconnection issues are now prompting data centers to explore a broader role for onsite generation. 

“As data center loads continue to scale, the exact mix of onsite generation, be it natural gas, batteries, renewables or small modular nuclear, really just ends up depending on the project timeline, local regulatory frameworks and the corporate sustainability goals of the data center facility owner,” Kou said during the CEC workshop. 

Bridging the Gap

Another strategy is the use of “bridge” solutions to meet a data center’s energy needs until transmission is available. 

That could mean bringing in skid-mounted generation, Porter said, or installing solar-plus-storage to temporarily serve the data center. Even after the data center connects to the grid, the solar-plus-storage could stay in place in front of the meter as a grid resource, he added.  

Another hot topic for data centers is their ability to be flexible in their energy use, particularly during grid-constrained hours. 

One possibility might be for a data center to tap into its backup generation system at those times, panelists said. That could create air quality issues if backup power comes from diesel generators. But other technology is available.  

Panelist Kushal Patel from Energy and Environmental Economics (E3) pointed to a Microsoft data center in San Jose, Calif., that has a backup power microgrid fueled by renewable natural gas. The RNG microgrid also allows Microsoft to participate in PG&E’s Base Interruptible Program, which pays customers to reduce electricity use when energy supplies are tight. 

“The kind of capability and the kind of resource may be there,” Patel said. “Are there the right kind of regulatory incentives, policies in place to be able to maximize that?” 

EPRI in October announced an initiative called DCFlex, which will establish flexibility hubs for data centers to try out new strategies that boost operational and deployment flexibility, streamline grid integration, and transition backup power solutions to grid assets. (See EPRI Launches DCFlex Initiative to Help Integrate Data Centers on the Grid.) 

The initiative is bringing together hyperscalers, data center developers, technology providers, utilities, ISOs and RTOs. In February, EPRI announced an expansion of the program into Europe. 

Peak Load Growth

In its 2024 IEPR, the CEC projected about 3,500 MW of new data center peak load in California by 2040, on top of roughly 1,000 MW in 2024. (See CEC Ups Data Center Demand Forecast After PG&E Revisions.) Those estimates will be updated as part of the 2025 IEPR. 

Southern California Edison has about 80 MW in existing data center demand and is forecasting an increase to 1,000 MW by 2045, Elliot James Dean, an SCE data science specialist, said during the CEC workshop. Uncertainty in the forecast comes from potential on-site generation, increased energy efficiency, technology advancements and market conditions in the SCE service territory. 

The data center pipeline in Pacific Gas and Electric’s territory totals 5,500 MW, including almost 1,500 MW in final engineering or construction, according to a workshop presentation. 

One key question for utilities is how many inquiries from data centers are “real” versus an information gathering process to compare different regions. Dean said SCE has started assigning a confidence level to each project, based in part on whether it is also making inquiries elsewhere. (See Data Center Load Uncertainty Tied to Broader Economy, Google Rep Says.) 

“That is not very straightforward,” Dean said. “And clear communication from the project is greatly appreciated on that piece for sure.” 

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As Policies in Washington Change, Grid Investment Still Needed

WASHINGTON — Even as President Donald Trump and the new Republican-controlled Congress begin to roll back the clean energy policies of the Biden administration, the grid still needs to expand to meet new demand and become more resilient to extreme weather, state regulators heard last week.

Democrats tried to pass numerous transmission “permitting reform” bills last Congress to help realize the clean power investments in the Inflation Reduction Act, and that has impacted the partisan split on the subject. But now that demand is growing at a pace not seen in decades from data centers, the need to expand the grid goes beyond connecting renewable resources that are far from cities.

“We’re trying to solicit as many comments as we possibly can so that we can get this right, because it’s going to be threading a needle between the Republicans and the Democrats,” Sen. Shelley Moore Capito (R-W.Va.), chair of the Senate Environment and Public Works Committee, said at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit. “There’s certain things that I might want that I’m going to fight hard for. There’s certain things, particularly on the transmission side, that the Democrats want. We’re going to try to marry those up and make an effective and long-lasting permitting.”

“There’s a lot of voices making that connection: that companies are looking for electrons,” Clean Energy Buyers Association Senior Director Bryn Baker told reporters Feb. 26 in a webinar on the state of transmission policy under the Trump administration and the new Congress. “And that there are economic advantages to those states and regions that are proactively planning for transmission, and that’s fundamental to getting those industries sited and built here.”

Serving the new loads from data centers, which are being built out by some of CEBA’s members, will require all kinds of investment in transmission, from interregional lines to reinforcing the existing system with grid-enhancing technologies and advanced conductors.

“I think transmission is kind of under that umbrella of energy infrastructure,” Americans for a Clean Energy Grid Executive Director Christina Hayes said on the webinar. “We’ve heard a lot more clarity under Secretaries [Doug] Burgum and [Chris] Wright [head of the departments of the Interior and Energy, respectively] talking about the importance of the backbone of the grid.”

Four years ago, predictions for demand growth were flat in most of the country, and AI was more of a vague concept for science fiction novels than it was a reality both on app stores and in the physical world, she said.

“The growth of data centers and artificial intelligence is driving up energy demand in ways we have not seen in decades, making transmission reform even more critical,” Hayes said. “Despite significant discussion about energy policy, we still need more definitive action, especially if we want to meet our projected energy demands.”

Even without hyper-scalers driving demand to new levels, the power system needs to be adequately maintained, and Exelon CEO Calvin Butler said that requires some spending. He recalled that before his company bought Pepco, the utility was running about a 6.4% return on equity and was in the fourth quartile for reliability.

“The utility wasn’t meeting its obligation to provide strong customer service and strong reliability,” Butler told NARUC during a panel on capital markets Feb. 25. “What we have recognized as a company [is that] operations and high customer satisfaction are foundational elements. We have to do that well before we can come to you and talk about our long-term strategy.”

By 2021, Exelon had gotten Pepco’s ROE up to 9.4% and its reliability improved by 50%, which involved investing in the underlying infrastructure needed for reliable and resilient service, Butler said.

In a panel Feb. 24 at NARUC on mutual assistance during extreme weather events, Southern Co. CEO Chris Womack said his firm was ready to meet demand from new sources thanks to the amount of investments it has made in its system, including new generation.

“With the careful oversight of our state regulators, elected officials, customers and shareholders, we have designed and engineered a remarkably flexible, resilient and affordable system,” Womack said. “We recently added new nuclear generation and now can dispatch in the largest nuclear station in America at Plant Vogtle.”

The Trump administration’s goal is for “energy dominance,” which Womack said translates to energy abundance that is important to meeting the new loads coming online in Southern Co.’s utility territories.

“Both energy dominance and energy abundance require a safe and secure energy grid, and thankfully, our nation’s power grid is up to that challenge,” Womack said. “It is advanced; it’s flexible and is integrated in a way that allows us to rely on each other day to day.”

Wildfires are becoming more common in Oregon, Portland General Electric CEO Maria Pope said. Devastating fires in California last decade caused its northern neighbor to start considering how the events could impact its utilities back when they were rarer, which proved prescient as Oregon saw more acres burn than any other state or Canadian province in 2024.

Now wildfires are so common, Pope argued that regulators need to insulate utilities from potentially devastating litigation as long as they can prove they followed a set of best practices, which would be similar to legal defenses against medical malpractice.

“Until we have something like that across this country, we’re going to continue to have economic hardship on the utilities,” Pope said. “Wildfire is an example. Like all the storms we’re talking about here, disasters are society-wide problems, and they need a society-wide solution, not just the backstop of a utility and the devastation that that brings the utility’s balance sheet.”