FERC Grants Palisades Extra Time to Get Online

FERC has given the Palisades Nuclear Plant special permission to exceed MISO’s 36-month limit on generator suspensions as owner Holtec International works through the plant’s reopening. 

The commission decided Feb. 28 that Holtec can use a 22-month extension on top of the RTO’s three-year limit to bring Palisades back online (ER25-1083). 

The MISO tariff limits generation suspensions to a cumulative 36-month maximum over a five-year span. After reaching the limit, generators are expected to return to service or risk termination of interconnection service. 

Holtec told FERC that its plan to return Palisades to service was not crystalized until April 2024. Previous owner Entergy placed Palisades in suspension status with MISO in 2022. 

FERC’s leeway means Holtec now has until March 1, 2027 — instead of May 20, 2025 — to start the reactor under MISO’s rules. Holtec is currently navigating a recommissioning process with the Nuclear Regulatory Commission and hopes to have the plant online in October at the earliest. (See Anti-nuclear Groups Challenge Palisades Reopening.) 

Holtec argued that if it was not granted the extra time and lost its interconnection rights with MISO member Michigan Electric Transmission Co., it could result in “substantial delays or potential loss of baseload generation critically needed to support resource adequacy in the MISO region.”  

The Michigan Public Service Commission filed comments in support of the waiver. 

Holtec also said it is preparing a new generator interconnection agreement to file with MISO that will lay out expectations and associated deadlines on the path to reactivating the partly decommissioned nuclear plant. 

FERC said Holtec seemed to act in good faith and that a continuation of the Palisades suspension without terminating interconnection service would not harm any third parties. On the other hand, the commission said that disconnecting Palisades from the MISO system would “jeopardize the recommissioning timeline.” The commission noted that, according to Holtec, Palisades’ reopen will not require network upgrades. It also said it had Holtec’s word that MISO verified the 22-month waiver would not present “reliability concerns or interconnection queue management issues.” 

Company Briefs

NRG to Build Natural Gas Plants to Supply Data Centers

NRG Energy last week announced plans to build four new natural gas power plants to supply data centers. 

NRG said it plans to build 5.4 GW of natural gas combined-cycle power plants primarily to serve data centers in the ERCOT and PJM markets. The first 1.2 GW are expected to begin operations in 2029. 

NRG also said it plans to build three gas-fired plants totaling 1.5 GW in the Houston area. 

More: Houston Chronicle 

EDF Withdraws from Atlantic Shores Wind Project

French energy giant EDF announced it has withdrawn from its stake in the Atlantic Shores wind project off New Jersey. 

Its partner, Shell, also withdrew from the 200-turbine, 1,510-MW project in January. Following Shell’s decision, the New Jersey Board of Public Utilities decided not to proceed with a new solicitation that would have allowed Atlantic Shores to submit an updated bid. 

More: WorkBoat 

Air Products Drops Green Hydrogen Projects in 3 States

Air Products officials announced the company is canceling projects in New York, California and Texas. 

The company said the cancellation of the $500 million green hydrogen facility in New York was “based on recent regulatory developments rendering existing hydroelectric power supply ineligible for the Clean Hydrogen Production Tax Credit, as well as slower than expected development of a hydrogen mobility market in the region.” 

Air Products’ board of directors and CEO recently conducted a review of numerous projects, making the decision to cease operations to record a pre-tax charge not to exceed $3.1 billion in its fiscal 2025 second quarter. 

More: North County Now 

First Solar Q4 Sales Up

First Solar last week reported net sales for the fourth quarter were $1.5 billion, up $0.6 billion from the prior quarter. 

Meanwhile, net sales for the full year were $4.2 billion compared to $3.3 billion in the prior year. Looking ahead, sales are forecast to be about 32% higher than in 2024. 

More: pv magazine 

Federal Briefs

NOAA Suffers Mass Layoffs

The Trump administration last week informed hundreds of probationary employees in the National Oceanic and Atmospheric Administration that they were fired. The firings were expected to cost more than 800 people their jobs. 

Most of the employees were responsible for producing weather forecasts, maintaining radar systems, gathering data from satellites and monitoring commercial fisheries. Several hundred more staff members were also expected to leave as part of the resignation program. 

More: The Washington Post; The New York Times 

Congress Votes to Overturn Rule Implementing Methane Fee

The House last week voted 220-206-1 to overturn a Biden-era rule implementing a program that charges oil and gas companies for excess methane emissions. The Senate voted 52-47 the next day to repeal the rule. 

Overturning the rule does not necessarily eliminate the program, which was written into law in the 2022 Inflation Reduction Act. Fully overturning the rule appears to require additional legislation, and Republicans are expected to try to repeal it as part of their broader legislative package. Under the law, companies that emit methane at levels equivalent to 25,000 metric tons of carbon dioxide each year must pay for their excess emissions. 

More: The Hill; The Washington Post 

EIA: US Coal Retirements to Double in 2025

U.S. power generators plan to remove about 8.1 GW of coal-fired capacity this year, which would roughly double the amount that was retired in 2024, according to the Energy Information Administration. 

Coal retirements slowed last year to 4 GW, a sharp decrease from the 9.8 GW retired annually over the past decade, the EIA said. The country’s electricity supply from coal, which was once the primary source, has dropped to about 16%. 

More: Reuters 

State Briefs

ARIZONA 

House Approves Bill to Require Utility Wildfire Prevention Plans

The House of Representatives last week voted 35-25 to approve a bill that would require utilities to create wildfire prevention plans. 

The bill would require utilities to prepare wildfire mitigation plans to proactively prevent wildfires and decrease any damages that may occur. Those strategies include inspection procedures for wildfire risks, procedures for de-energizing power lines, community outreach and public awareness efforts, and new steps on how power companies will monitor compliance with their plans.  

The bill now heads to the Senate. 

More: Arizona Capitol Times 

COLORADO 

House Passes Bill to List Nuclear as ‘Clean Energy’

The House of Representatives last week voted 43-18 to pass a bill that would add nuclear power to the state’s list of “clean energy” resources. 

The state’s definition of “clean energy” determines which projects are eligible for clean energy financing at the county and city levels and determines which resources may be used by a utility to meet the state’s 2050 clean energy target. 

The bill now heads to the Senate. 

More: Colorado Politics 

DELAWARE 

NRG Closes State’s Last Coal Plant

NRG announced it officially closed the coal-fired Indian River Power Plant on Feb. 23. 

Originally scheduled for decommission in 2022, the plant was kept operational while transmission upgrades were conducted to the grid until 2026. Now, the plant will close 22 months early. 

More: WBOC 

LOUISIANA 

Meta Announces Plans for $10B AI Data Center

Meta recently announced plans to build a $10 billion AI data center in Richland Parish. 

To power the massive data center, Entergy is investing $6 billion in infrastructure, including a 10,000-acre solar farm, three natural gas turbines and 100 miles of new transmission lines. 

The facility, which is projected to be the largest of more than 20 Meta data centers worldwide, is expected to be operational by 2030. 

More: WVUE 

NEVADA 

NV Energy Seeks 9% Rate Increase

NV Energy is seeking approval from the Public Utilities Commission for a $215 million rate increase in Southern Nevada. 

The increase would raise residential rates by 9%. 

The utility is also asking to increase shareholder return on equity from 9.5% to 10.25% and save low-income residents about $20/month by eliminating the basic service charge. 

More: Nevada Current 

NEW MEXICO

House Passes Low-income Rates Bill

The House of Representatives last week voted 42-25 to pass legislation that would pave the way for low-income rates for investor-owned utility customers. 

The bill would let utilities submit applications to the Public Regulation Commission for low-income rates. The legislation does not create a low-income rate but instead allows utilities to craft a rate or develop a program that is brought to the PRC for approval. 

More: New Mexico Political Report 

SOUTH DAKOTA

Lawmakers Endorse Eminent Domain Hurdles, Enviro Studies for Carbon Pipelines

Lawmakers have advanced legislation that would make it more difficult for carbon dioxide pipeline companies to use eminent domain and would subject their projects to required environmental impact statements. 

A bill to ban eminent domain for carbon pipelines passed the House last month and is awaiting action in the Senate. Meanwhile, another bill approved by the Senate would retain eminent domain as an option but would require entities using it to first attend mediation with the affected landowner and to have a state permit before commencing eminent domain proceedings. 

Elsewhere, the House Commerce and Energy Committee voted 9-4 to send a bill to the House floor that would require an environmental impact statement for CO2 pipelines. The bill would require utility regulators to prepare or require the preparation of statements before approving a permit. 

More: South Dakota Searchlight 

PUC Approves Massive Wind Farm

The Public Utilities Commission last week approved a 260-MW wind farm. 

The $621 million project will consist of 68 turbines on 46 square miles of privately owned land in Deuel County. 

More than 50 conditions were included in the permit, addressing cooperation with local agricultural operations, daily time limits on construction, protection of threatened or endangered species, noise levels and more. 

More: South Dakota Searchlight 

TEXAS 

Shell Sells Residential Portfolio to NRG Energy

Shell last week confirmed it has sold its residential book of customers in the ERCOT market to NRG Energy. 

No other details of the transaction were released. 

More: Houston Chronicle 

VERMONT 

Lawmakers Signal Pause of Clean Heat Standard

Lawmakers last week indicated they will likely not continue to pursue development of a Clean Heat Standard. 

The discussions come a month after a report was released saying the standard would cost $1 billion over 10 years and raise heating fuel 58 cents/gallon to reduce carbon emissions in the thermal sector. 

Lawmakers are also discussing a change to the Global Warming Solutions Act, a law that created carbon emission reduction deadlines, if the Clean Heat Standard is abandoned. 

More: WPTZ 

VIRGINIA 

Lawmakers Approve Rate Relief for Appalachian Power Customers

The House and Senate voted unanimously to approve a bill that would provide relief to Appalachian Power ratepayers. 

Appalachian would be prohibited from raising rates during the winter months, while there would also be moratoriums on late fees for residential customers. 

The bills must be signed by Gov. Glenn Youngkin. 

More: Roanoke Times 

SCC Approves Dominion LNG Storage Facility

The State Corporation Commission last week approved Dominion Energy’s plans to construct a liquified natural gas storage facility. 

The 25 million gallon facility, capable of storing up to 2 billion cubic feet, would be for the utility’s 1,358-MW Brunswick and 1,588-MW Greensville power stations. 

Construction is expected to begin this year and be completed by the end of 2027. 

More: Inside Climate News 

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+.) 

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.)

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.” 

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. 

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.”

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.