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December 9, 2025

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Congress Continues Work on Permitting, but Passing a Bill Faces Major Obstacles

WASHINGTON — Permitting legislation still is being developed on Capitol Hill, but the government shutdown and the Trump administration’s actions against clean energy projects in Democratic-led states could stop it from happening this Congress.

The Conservative Energy Network (CEN) and Grid Action held a “fly-in” Nov. 5, in which state officials, business leaders and experts held more than 35 meetings with members of Congress and senior staff to push for permitting reform legislation. The meetings included those with members of the House Energy and Commerce, House Natural Resources, Senate Environment and Public Works, and Senate Energy and Natural Resources committees.

“Our permitting system makes it impossible to do things in a reasonable time frame,” Rep. Mariannette Miller-Meeks (R-Iowa) said at a press conference hosted by CEN. “And the government, whether it be local, state or federal, is often standing in the way of the market meeting the needs, especially the needs for increased energy demand.”

Congress has been working on the issue for years, and the fact that major infrastructure like transmission can take the better part of two decades to build shows change is needed, as Americans pay more for energy than they would otherwise, she added. Miller-Meeks supports the SPEED and Reliability Act, which would amend the National Environmental Policy Act to speed up agencies’ review of infrastructure projects. (See Permitting Hearing Shows Tricky Politics of Getting a Bill Passed.)

“We have an urgent, growing demand, and the question is whether Congress will act decisively or [continue] to tinker around the margins,” Miller-Meeks said.

Asked about the biggest obstacle to legislation in 2025, Miller-Meeks blamed the government shutdown “created by the Democrats,” which officially became the longest in history on the day of the press conference.

Speaking on a webinar hosted by Americans for a Clean Energy Grid (ACEG) in October, Rep. Sean Casten (D-Ill.) noted that Democrats have a different road block for bipartisan legislation.

“The currency of trust is so low when the White House is refusing to even honor existing congressionally mandated spending [and] congressionally mandated legislation,” Casten said. Talking about compromising on permitting legislation now is “a little bit like compromising with somebody who just robbed your house and is saying ‘you can trust me this time.’”

While that issue has cut the probability of legislation for now, Congress still can work on developing good policy for “when that door next opens,” Casten said.

When it comes to the grid, the issue has less to do with permitting and more to do with the right economic incentives, he argued.

“That sounds crazy,” he said. “You’d never know that if you read all the talking heads, or if you looked at the legislation going through Congress.” But regulated utilities can build rate-based generation and get it connected to their systems, and the natural gas industry has no problem getting pipelines built despite environmental risks that are arguably bigger than those of high-voltage transmission, he argued.

“The truth is, we have a profit problem,” Casten said. “The way that our energy markets are structured, we do not have an incentive to deploy cheap energy. And it comes from the fact that if you are an incumbent in the electricity sector, you lose money if a competitor builds a system on your grid that can underprice you.”

Casten said he did not blame utilities because they were following the incentives, so the goal for any legislation should be to change them. The Cheap Energy Act, which he introduced with Rep. Mike Levin (D-Calif.), aims to do that. (See Federal Energy Policy News Roundup: House Bills and DOE Returns $13B.)

“How should we rethink the way that electricity markets are structured so that we don’t wind up in a situation where every single person who deploys a zero-marginal-cost generator doesn’t essentially eat their own investment thesis?” Casten said. “Because, after all, if everybody built renewable power plants and our whole grid was served with renewables, the marginal price of power would be zero, and consumers would win, but there’d be no incentive to build anything. That’s not some innate flaw. It’s just a problem with the way that we’ve regulated the structure. We fix that.”

As both a policy and political matter, any permitting legislation needs to be technology neutral, Bill Parsons, Berkshire Hathaway Energy vice president of federal legislative affairs, said on the ACEG webinar.

“Now, some people will say, ‘Well, as long as the reforms to NEPA and other permitting statutes apply to everything, then that’s tech neutral,’” Parsons said. “I think we do need to go a bit further here. There’s going to need to be a transmission title.”

BHE supported the Energy Permitting Reform Act of 2024 from former Sen. Joe Manchin (I-W.Va.) and Sen. John Barrasso (R-Wyo.). That could be a starting point for a future permitting deal, he said.

“I think we make a mistake when we get overly binary about the policy choices here, and it’s either the status quo or a complete federal takeover of transmission,” Parsons said. “That’s a false choice. There is an opportunity to hive off a very limited number of high-priority national lines, describe them objectively, so people can understand ahead of time what qualifies and what doesn’t for consideration at FERC.”

The National Governors Association weighed in on the permitting debate recently, releasing a bipartisan proposal headed by NGA Chair and Oklahoma Gov. Kevin Stitt (R) and Pennsylvania Gov. Josh Shapiro (D).

“This isn’t a Republican or [Democratic] issue. Every American needs to heat their home and power their vehicle,” Stitt said in a statement. “As the demand for energy rises as we bring new technologies and AI online, we need to complete energy infrastructure projects in a faster, more efficient way.”

The governors’ proposal includes reforms for FERC that would have it create a National Interest Designation Process that lets a transmission facility be declared in the national interest after the hearing and consideration of several factors and consultation with the states. Groups of states could nominate National Interest Electric Lines.

FERC would get greater flexibility to allocate the costs of interstate and offshore transmission lines among all beneficiaries.

The governors also want changes to ISO/RTO governance, including giving states, or organizations of states, “jump ball” or complementary filing rights at FERC. ISO/RTOs would be required to improve interregional planning and more robustly consider states’ alternative planning options.

Another legal change would be to require ISO/RTOs to process interconnection requests for generation and storage within six months of an initial application.

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Amazon Files Complaint Against PacifiCorp for Lack of Data Center Power

Amazon has filed a complaint with Oregon regulators that accuses PacifiCorp of violating agreements to provide power to four data center campuses in the utility’s service territory.

Amazon Data Services (ADS) filed the complaint Oct. 30 with the Oregon Public Utility Commission, saying it had exhausted “all reasonable efforts for resolution with PacifiCorp.” Amazon said it invested in the data centers based on PacifiCorp’s agreement to provide service.

Amazon is asking the commission to require PacifiCorp to supply the agreed-upon power — or to move the data centers into the territory of another utility that’s willing to provide electricity.

“Despite ADS paying PacifiCorp … under binding contracts, PacifiCorp breached its statutory obligations and contractual duties by failing to supply ADS with the promised power,” Amazon said in the complaint.

In a statement provided to RTO Insider, PacifiCorp said it has been “acting in good faith to serve Amazon’s significant load in a manner that would achieve Amazon’s operational goals while protecting PacifiCorp’s existing customers from increased costs and reliability issues.”

“We are open to ongoing discussions with Amazon to reach a resolution that achieves these goals,” the utility said. “It is PacifiCorp’s policy position to avoid direct and indirect harms between customers. This is consistent with Oregon law, which ensures new data center loads do not jeopardize customer affordability.”

PacifiCorp’s response filing with the PUC is due Nov. 19; the company asked the commission to extend the deadline for filing a response and a potential motion to Dec. 19.

Amazon said it has been working since 2021 to develop four new data center campuses in PacifiCorp territory in Oregon.

For the first campus, called Specialized, PacifiCorp is “supplying significantly less power than promised,” Amazon alleged. A second campus, called Litespeed, hasn’t received any power from PacifiCorp, according to the complaint.

And for two other data center campuses, known as Pivot and Gray, PacifiCorp “has refused to even complete its own standard contracting process,” Amazon contended.

Amazon also accused PacifiCorp of trying to increase Amazon’s costs in the form of a 32.6% “tax gross-up” on capital contributions.

For the Specialized and Litespeed data centers, Amazon and PacifiCorp entered into a series of three agreements. The first two covered preliminary design and engineering work. The third agreement, known as a master electric service and facilities improvements agreement (MESA), required PacifiCorp to complete particular improvements and then deliver power as specified in the contract.

The Gray and Pivot campuses didn’t move beyond the first two agreements with PacifiCorp to a MESA agreement. According to Amazon, PacifiCorp told it to forfeit the contracts for the Specialized and Litespeed campuses if it wants agreements for Gray and Pivot.

The complaint, which was heavily redacted before being filed in the public docket, doesn’t show the amount Amazon has spent on capital improvements and development costs under the contracts with PacifiCorp. It also doesn’t give the exact location of the data centers, other than saying they’re in PacifiCorp territory.

Amazon said the four data centers in its complaint would complement existing data centers in the region. The company’s data center portfolio includes facilities in Morrow and Umatilla counties in Eastern Oregon.

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Load Growth Outpacing Distributed Generation, Eversource Says

Weather-normalized electricity demand has increased by about 2% this year in Eversource Energy’s service territories in New England, in part due to heating and transportation electrification, CEO Joe Nolan said during the company’s third-quarter earnings call.

Nolan expressed optimism about new transmission opportunities to meet this load growth, along with the potential for a more favorable regulatory environment in Connecticut in the wake of the resignation of Connecticut Public Utilities Regulatory Authority (PURA) Chair Marissa Gillett. (See Escalating Conflict with Utilities Leads to Resignation of Top Conn. Regulator.)

“Load growth in our service territory has started outpacing the impacts of distributed generation such as rooftop solar,” Nolan said on the Nov. 5 call, adding that the company experienced a peak load of more than 12 GW during the summer, its highest peak since 2013. The company’s service territory covers parts of Massachusetts, New Hampshire and Connecticut.

The increasing demand has been “driven primarily by electrification of transportation and heating, decarbonization initiatives from both the public and private sectors, and economic expansion across manufacturing and commercial sectors,” Nolan said.

The observed load growth may be part of a larger trend that experts expect to accelerate into the 2030s. By 2034, ISO-NE forecasts New England’s average annual net load increasing by more than 11% and the average summer peak load increasing by more than 8%, or about 2 GW.

The RTO experienced its highest peak load since 2013 in June 2025, though net load (not normalized to account for weather effects) over the first nine months of 2025 was about equal to 2024 net load over the same period. (See Extreme Heat Triggers Capacity Deficiency in New England.)

“The evolving electric landscape presents a need for numerous transmission projects, such as upgrades linking onshore and offshore wind to load centers, interconnections improving regional reliability and addressing congestion as the generation mix for our region evolves,” Nolan said.

Nolan added that the company expects to spend nearly $2 billion on its electric distribution business and about $1.4 billion on its transmission business in 2025.

A large portion of the company’s transmission spending is associated with asset upgrades, a major concern for New England states and consumer advocates in recent years. According to data published by ISO-NE, Eversource plans to spend about $774 million on asset condition projects expected to come online in 2025. (See More Oversight Needed on Local Transmission Spending in NE, Panel Says.)

Nolan indicated that Eversource responded to ISO-NE’s first longer-term transmission planning (LTTP) solicitation and that LTTP solicitations and land acquisitions at strategic interconnection points could create opportunities to add “billions of dollars to our future investment plans.”

“Each project that we are considering not only supports our growth trajectory, but also deepens our value proposition as a grid innovator,” Nolan said.

ISO-NE’s LTTP solicitation is the first to be run under its new process, which aims to procure transmission solutions to needs identified in long-term planning studies. The first procurement is focused on reducing transmission constraints in Maine and enabling the interconnection of onshore wind in the state.

ISO-NE received six qualified proposals prior to the submission deadline at the end of September, ranging in cost from about $1 billion to $4 billion. (See ISO-NE Reveals 1st Details of Long-term Transmission Proposals.) ISO-NE has not announced which companies submitted proposals.

Regarding the company’s business in Connecticut, Nolan appeared cautiously optimistic about financial opportunities in the state after Gillett resigned in September amid mounting political and legal battles with utilities and Republicans in the state.

“We’re seeing a constructive shift in Connecticut’s regulatory landscape,” Nolan said. “A transparent regulatory process is going to benefit all stakeholders, including our customers, and we are looking forward to getting back to work on Connecticut’s energy goals.”

Also on Nov. 5, PURA approved a rate increase for the Yankee Gas Co., an Eversource subsidiary. The decision authorized a higher revenue requirement for the company than initially outlined in a draft decision authored during Gillett’s tenure.

In the prior week, PURA similarly approved a higher revenue requirement in a United Illuminating rate case relative to a draft decision issued under Gillett’s leadership.

Connecticut Gov. Ned Lamont (D) has nominated four new commissioners to PURA, bringing the total number on the commission to five. However, both decisions were issued by the two remaining active commissioners at the authority, one of whom worked as a lobbyist for United Illuminating as recently as 2024.

While the final decisions appear more favorable to the utilities than the draft decisions, only one of the two commissioners who ruled on these cases is set to be part of the full incoming commission, and the rulings may not give much indication about the regulatory approach of the full incoming commission.

Asked whether the new commission will lead to an improvement in Eversource’s credit rating, Eversource CFO John Moreira said credit rating agencies are “in a wait-and-see mode.”

“They want to see some constructive regulatory outcomes,” Moreira said, adding, “we think that this new commission is focused on working collaboratively with all the utilities.”

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IESO Preps for ‘Virtual’ Corporate PPAs

IESO will begin allowing corporate energy buyers to purchase power from off-site renewable generators next spring, giving loads another way to reduce their Global Adjustment (GA) charges.

The new policy will be effective for the 2026/27 base period (May 2026-April 2027) for determining loads’ GA charges.

The C-PPA framework allows participants in the Industrial Conservation Initiative (ICI) to sign “virtual” power purchase agreements with renewable generators — defined as wind, water, biomass, biogas, biofuel, solar or geothermal — located anywhere in Ontario.

Before the June rule change by the Ministry of Energy and Mines (Regulation 429/04), the ICI program allowed only on-site PPAs, in which electricity is generated and consumed at the same location, behind the meter. ICI is designed to reduce large electricity users’ consumption during peak hours.

The revised regulation will help large consumers reduce their electricity costs and meet clean energy goals, while providing an additional revenue source for generators and supporting new generation investment, IESO said in an engagement session outlining the program Nov. 4.

Potential Global Adjustment Savings

C-PPAs handle financial settlements separately from the physical delivery of electricity, with the generator’s output offsetting the consumer’s demand during peak periods.

ICI participants that cut their usage during the top five peak hours over a 12-month base period (the peak demand factor) can significantly reduce their GA charges. The GA funds new grid infrastructure as well as maintenance and conservation programs.

Eligible Loads

ICI participants, called “Class A” customers, include:

    • manufacturing and industrial loads, including greenhouses, with an average monthly maximum hourly demand between 500 kW and 1 MW;
    • customers with an average monthly maximum hourly demand between 1 and 5 MW, which can opt in to the program; and
    • customers with an average monthly maximum hourly demand greater than 5 MW, which are automatically entered into the ICI program unless they opt out.

Generator Eligibility

The program allows participation by generators and customers that are distribution-connected if they are registered as a market participant and settled in the IESO market.

New generation facilities are eligible to participate if they have a municipal resolution of support and are not located on Prime Agricultural Land.

C-PPA transactions must be settled through the IESO market.

‘Stacking’ OK

The new rules allow generating facilities and customers to “stack” multiple PPAs. But they limit the “eligible” electricity under the program to that which has not already been paid for or committed (“compensated” electricity), such as that procured through IESO contracts.

IESO’s Keigan Buck (left) and Greg Moore | IESO

“The fundamental principle is that the regulation does not permit double recovery,” IESO’s Keigan Buck said. “A given unit of electricity can be either eligible electricity or compensated electricity. [It] cannot be both.”

‘Eligible’ Electricity

Generators must deliver to the IESO grid or distribution system “some volume” of eligible electricity in each hour of the base period without using temporary storage.

“Based on the IESO’s current interpretation, we understand the regulation’s requirement for generators to deliver … any non-zero amount of energy — essentially any volume above 0 MWh,” IESO spokesman Michael Dodsworth said.

The rules provide exceptions to the delivery requirement for facility outages, insufficient wind or sunlight, compliance with IESO dispatch instructions or circumstances beyond the generator’s control, such as delivery constraints.

Next Steps

IESO is accepting feedback until Nov. 18 at engagement@ieso.ca. It plans to post final documents on the program in December or January.

The C-PPA submission window opens Feb. 1, 2026, and closes March 30. Submissions must be sent by email to corporateppa@ieso.ca.

“We strongly encourage submitting early within the window, because some of the timelines are quite tight for approval of the documents, and it may require some back and forth between proponents and the IESO,” the ISO’s Greg Moore said.

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2 Regions Under Elevated Risk in Upcoming WECC Winter Assessment

WECC expects two regions to be under elevated risk as the West heads into the winter, with staff saying a prolonged weather event could impact operating reserves.

Speaking at a Nov. 4 WECC webinar about the organization’s upcoming 2025 winter reliability assessment, Matt Zapotocky, senior reliability assessments engineer, said the Northwest and Basin regions are at elevated risk — meaning there is potential for insufficient operating reserves in case of an extreme cold weather event coinciding with elevated demand or a significant reduction in resources.

The two regions cover Oregon, Washington, Idaho, Montana, Utah and western Wyoming.

A prolonged cold weather event in those areas could lead to “power not being available and the inability to maintain their operating reserves, and that’s why they were suggested as elevated this year in the assessment,” Zapotocky said. “However, it should be noted that neither area should have lost load for the upcoming winter, assuming there is import availability for both regions.”

James Hanson, manager of operations analysis at WECC, said a major concern is the impact of cold weather events on warmer regions, as seen in January 2024 during Winter Storm Heather.

“There were some significant challenges that parts of the interconnection were facing during that time,” Hanson said. “We fared relatively well. I think … readiness plans, making sure critical components on your power plants are able to withstand those extreme colds, I think that really boded well for a lot of our generation.”

Still, if cold weather extends into a more temperate area “like the Desert Southwest, we could see some operating challenges for sure,” Hanson said.

The resource mix also plays a role in the winter assessment. The West is expected to see approximately 4 GW of coal retirements in 2025, along with about 1 GW of planned natural gas retirements. However, some of the natural gas retirements will be offset by natural gas additions projected to come online in January 2026, Zapotocky said.

Those resources are valuable in the winter and can effectively address unplanned and forced outages, he added.

Though the West will see about 11 GW of solar and 7 GW of wind added across the Western Interconnection, inverter-based resources are more at risk during cold weather events, Zapotocky noted.

“Wind turbines can be susceptible to icing or cold weather cutouts, or even overspeed if the winds are strong enough,” Zapotocky said. “Solar capability can either just not be available if it’s a morning peak and it’s still dark out or just be severely limited due to snow or cloud coverage.”

WECC anticipates over 10 GW of battery energy storage coming online this winter, but those systems can only “provide about four hours of discharge,” Zapotocky said.

“So if you have a prolonged weather event, that may not be enough to quite get you through it,” he added. “There have to be strategies to stagger their use.”

The additional capacity of wind, solar and batteries will be of “particular importance” to the Northwest as the region is forecasting a winter peak 9% higher than last year’s forecast, according to Zapotocky.

WECC will publish the full winter reliability assessment Nov. 13.

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GridLab: More Renewables Could Have Saved Billions in PJM Auction

If just 10% of the land-based renewables in PJM’s generator interconnection queue had been developed, the total cost of the RTO’s 2026/27 capacity auction would have been reduced by $3.5 billion, according to an analysis GridLab commissioned by Aurora Energy Research.

The queue has 130 GW of nameplate capacity that entered before 2024, and just a fraction of the solar, wind and batteries in it would have cut 2026/27 capacity costs down to $12.6 billion from the $16.1 billion in actual costs.

“I think part of my frustration with the narrative coming out of PJM was they’re sort of blaming state policy for the reason that the auction has gone up so much. They say, ‘State policy is forcing plants to retire,’” GridLab Executive Director Ric O’Connell said in an interview. “And I just don’t think it’s true. I think the reason that the auction has gone up is because PJM basically has taken a very long time — the longest of all the RTOs — to get new capacity online.”

The only state policy actually requiring plants to retire is in Illinois, and that does not kick in for 10 years, O’Connell noted. A lot of retirements have happened in Ohio, which does not have the same stringent clean energy policies as more liberal states, he said.

Renewables have less of a capacity value than their nameplate, but the analysis used the same effective load-carrying capability values as the RTO.

“Wind actually has a really high capacity value because the risk periods are in the winter,” O’Connell said. “And the reason the risk periods in PJM were in the winter is because gas heavily underperformed in Winter Storm Elliott.”

The last time PJM’s grid faced major reliability issues was during that storm in December 2022, and the main culprit was natural gas. (See PJM Recounts Emergency Conditions, Actions in Elliott Report.)

The auction’s high prices signaled that supply and demand conditions in PJM are tight. As demand increases, the reserve margin gets narrower — making the timely connection of new resources increasingly critical to avoid high prices and threats to reliability.

PJM said in a statement that it agrees it needs to remove obstacles for all types of generation resources coming online.

“We are committed to connecting new generation to the grid as quickly as possible,” the RTO said. “PJM has processed about 160 GW of proposed generation resources, mostly renewables or batteries, since 2023. There are about 46 GW of new resources that will be processed by the end of 2026. We are currently working on multiple fronts, including our partnership with Google/Tapestry, to further streamline our processes by leveraging AI.” (See PJM, Alphabet Partnering on AI Tools to Speed Interconnection.)

As of October, about 60 GW of capacity had cleared the queue and either had signed interconnection agreements or were offered such deals, meaning that they should be ready to move forward on construction, PJM said.

But they are not getting built.

Both PJM and the GridLab study point to issues outside the RTO’s control, such as permitting, the supply chain and financing as slowing construction.

“We have called on policymakers to advance policies that will help keep existing supply and bring new supply to the power grid,” PJM said. “We also ask that they analyze any state/local permitting challenges to the deployment of new generation resources and electricity infrastructure and enact policies to facilitate construction.”

O’Connell argued that PJM should have been ready for a wave of interconnection requests from renewable power projects because that same wave washed over other markets earlier and gummed up queues in the process.

“CAISO sort of got this wave of interconnection applications in the mid- to late 2000s, and so they developed the cluster study process, and they really thought through how to address the issue,” O’Connell said. “MISO got it earlier because there was a lot of wind development.”

Up until the mid-2010s, PJM was seeing some renewables, but not enough to slow down the queue that was initially developed with natural gas and other traditional generation in mind. Then, between 2017 and 2021, the wave came and queue entry rose by 293%, according to the analysis. The RTO then announced it would not be able to study projects again until 2026, and queue entry declined rapidly.

“They should have read the room, and they should have looked around and said, ‘Oh, this happened in CAISO; this happened in MISO; this happened in SPP. It’s going to happen to us; we should get ready,’” O’Connell said.

The issue with many projects making it through the queue and not being ready to start construction also can be tied to the delayed queue, he said: Projects faced yearslong delays that compounded the issues they were facing.

“They applied for interconnection in 2018, and now they’re trying to build that project that they had envisioned in 2018 and the world’s totally different,” O’Connell said. “Prices have gone way up. Maybe their permits expired.”

The analysis suggests PJM should adopt new software to help speed up interconnection studies. It could pair large loads with capacity meant to meet the demand and expedite it through the queue, or it could adopt something like SPP’s Consolidated Planning Process, in which generator interconnection and transmission planning are handled at once.

Another major improvement would be changing PJM’s governance process and giving states a bigger role, which is an idea supported by most of the governors in the RTO, O’Connell said. (See Governors Call for More State Authority in PJM.)

“The primary problem with PJM is its governance structure,” O’Connell said. “It’s kind of owned and run by incumbent transmission owners and generation owners. And in some sense, they don’t want competition. They don’t want these new resources online. And so, I think that’s why you’re seeing PJM sort of drag its feet, because the incumbent gas generators are doing just fine. They’re making lots of money as capacity prices go up. They’re getting windfall profits.”

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NERC Files IBR Standards with FERC

NERC has filed a suite of reliability standards providing model validation and data sharing requirements for inverter-based resources with FERC, in the second tranche of standards aimed at addressing the commission’s Order 901.

Order 901, issued in October 2023, directed the ERO to develop rules addressing IBR data sharing, model validation, planning and operational studies, and performance standards, and submit them to the commission in three tranches by Nov. 4 over each of the next three years. The new standards were adopted by NERC’s Board of Trustees Oct. 31 in an action without a meeting.

NERC assigned the standards to three projects. The standard development team for Project 2022-02 (Uniform modeling framework for IBRs) worked on:

    • MOD-032-2 (Data for power system modeling and analysis)
    • IRO-010-6 (Reliability coordinator data and information specification and collection)
    • TOP-003-8 (Transmission operator and balancing authority data and information specification and collection)

MOD-026-2 (Verification and validation of dynamic models and data) was developed under Project 2020-06 (Verifications of models and data for generators), while MOD-033-3 (Steady-state and dynamic system model validation) was a product of Project 2021-01 (System model validation with IBRs). Each project’s standards were submitted in a separate docket.

The Project 2022-02 standards (RD26-1) will “advance the reliability of the [electric grid] by establishing requirements addressing the provision of [IBR] model data and parameters,” NERC said in its filing. MOD-032-2 will require planning coordinators (PCs) and transmission planners to specify the data needed to model IBRs for planning purposes and identify entities responsible for providing such data, along with requiring similar data on aggregated distributed energy resources.

IRO-010-6 and TOP-003-8 will “reinforce” requirements for reliability coordinators, transmission operators and balancing authorities to request IBR-specific data and parameters in their data specifications. Overall, the three standards will “establish the uniform framework for modeling IBRs contemplated by the commission in Order 901 … for conducting system studies.”

MOD-033-3 includes requirements for PCs to have a documented process for validating models applying to their portions of the electric system. The process must include performance comparison between actual system behavior and the steady-state and dynamic models of the system.

PCs must implement guidelines to identify and correct errors or inaccuracies between simulation results and actual behavior, with the goal of ensuring “that IBRs and DERs are included in system-level model validation … and [that] these inclusions are consistent with” the modeling data requirements in MOD-032-2.

Finally, MOD-026-2 requires generator owners and transmission owners to perform model validation and model verification of positive sequence dynamic and electromagnetic transient models provided to their TPs. NERC said these changes “will result in more accurate IBR models than [the] historic performance” of utilities’ prior modeling practices.

NERC’s Standards Committee has voted to move forward with the final tranche of Order 901 standards, with members approving two standard authorization requests covering operational and planning studies at their Aug. 20 meeting. (See NERC Standards Committee Tackles Final Order 901 Tranche.) The standards will be due Nov. 4, 2026.

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CPUC Approves New SDG&E Electrification Budget

In a rare split decision, the California Public Utilities Commission has approved $51.2 million in extra money for electrification projects for San Diego Gas & Electric customers to help the state reach its carbon neutrality goal.

Under the decision (25-04-015), SDG&E will create a new electric energization memorandum account (EEMA) for projects that will be completed outside the utility’s approved 2024 general rate case (GRC).

SDG&E originally requested about $310 million for EEMA projects between 2024 and 2026, but the CPUC at its Oct. 30 voting meeting reduced the request by 83%, saying the utility already has other methods for recovering electrification project costs.

“By most measures, SDG&E has been meeting commission goals for interconnection,” CPUC Commissioner Matthew Baker said at the voting meeting. “This proceeding is the result of state legislation stemming from concerns that some utilities have been unable to keep up with requests to connect to the grid.”

Energization projects include those that connect new customers to the distribution grid and those that upgrade distribution or transmission capacity and infrastructure for new and existing customers.

The decision is part of Senate Bill 410, signed by Gov. Gavin Newsom in 2023, which requires the CPUC to ensure that electric utilities can recover energization project costs in a timely and complete manner. Part of the bill intends to increase the speed of energization and service upgrade projects.

About $13.4 million of SDG&E’s EEMA budget will be for projects that increase capacity of existing customers; about $27.3 million will be for projects for new customers; and about $10.5 million will be for materials, such as transformers.

Commissioner Darcie Houck voted against the decision, saying it “should not include backward-looking caps for 2024 costs that have already been incurred.”

“SB 410 requires the commission to establish annual cost caps, which can be reasonably interpreted to mean cost caps set in advance of the utility incurring those costs,” Houck said at the meeting.

CPUC President Alice Reynolds replied that she found Houck’s comments “hard to follow.”

“I might have misheard, but I think there were a few inaccuracies, so I’m just gonna try to be really clear,” President Reynolds said. “The energization cost caps here are really designed to accelerate energization while also staying grounded in our statutory direction.”

Commissioner John Reynolds added that the amount of new ratemaking structures outside general rate cases has made it “harder for us to take [a] holistic view and harder for the public to have a clear picture of rate impacts.”

“It also means that rates change more often and we’ve heard complaints about this from members of the public,” he said. “On the other hand, GRCs only occur every four years and technology changes on shorter timescales.”

In comments noted in the decision, The Utility Reform Network (TURN) said SDG&E has not demonstrated any need for more money over the amounts it received in its GRC to meet customer energization demands.

TURN said that in March, “SDG&E stated that it considered it an ‘unlikely event’ that the utility would be ‘unable to accommodate the full load amount requested by the customer because of an upstream capacity constraint.’”

SDG&E said it will use the money it seeks in this application to improve its performance for additional types of energization projects, such as extending lines to new developments and electric vehicle charging infrastructure, the decision says.

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WRAP Day-Ahead Market Task Force Looks to Future After Commitments, Withdrawals

The Western Resource Adequacy Program’s Day-Ahead Market Task Force held its first meeting after the program’s binding decision deadline, with members exploring how the new, smaller participant footprint will affect transmission connectivity and other issues.

The task force was created to make WRAP compatible with the soon-to-be-launched SPP Markets+ and CAISO Extended Day-Ahead Market (EDAM). WRAP was designed before the two markets completed their designs. (See WRAP Day-Ahead Market Task Force Moves Forward on Concept Paper.)

Task force members in the Nov. 4 meeting discussed how to move forward after it became clear that most of the entities signing up for the WRAP’s first financially binding deadline have committed or lean toward Markets+.

“The DAM Task Force’s first meeting after the binding decision deadline was focused on understanding how the group should advance given the change in footprint and committed binding participation,” Michael O’Brien, WPP’s senior policy engagement manager for the WRAP, said in an email to RTO Insider.

“They agreed to explore how Markets+ could be leveraged to serve committed WRAP participants: those participating in Markets+ and those not participating in Markets+, while keeping an eye on how those who gave exit or may join in the future can leverage the DAM Task Force proposal to ensure they also receive the benefits of WRAP should they decide to participate in a binding season at some point,” O’Brien said. “It is a priority for WPP and a stated priority of the DAM Task Force that the proposals remain inclusive of future broader participation in WRAP.”

Interested participants had until Oct. 31 to commit to the program’s first binding season. Of the 16 committing, just two — Idaho Power and Seattle City Light (SCL) — have expressed leanings in favor of EDAM, although SCL’s geographic position adjacent to future Markets+ members — including BPA — could make participation in the CAISO market a challenge. (See WRAP Wins Commitments from 16 Entities.)

Among the five utilities withdrawing from the WRAP, four (NV Energy, PacifiCorp, Portland General Electric and PNM) have committed to joining the EDAM, while Eugene Water & Electric Board will be participating in Markets+ by virtue of its location within the Bonneville Power Administration’s balancing authority area.

With more clarity on which entities will participate, the task force should prioritize transmission connectivity, Matt Hayes, task force co-chair and program manager at the BPA, said at the Nov. 4 meeting.

“I think this group really needs to prioritize how we can bridge that gap between … the commercially available transmission, which is extremely limited, and the connectivity that the markets have throughout the region, which is pretty ample,” Hayes said.

Hayes also said the task force must push WRAP “to not only be something that holds people accountable but leverages to the greatest extent possible the geographic diversity we have and the diversity of resources to … not only ensure the resource adequacy is met, but also make it as cost-effective as possible for us.”

He noted some entities still are exploring whether to join a day-ahead market, saying, “I would caution about being too quick to focus on any one particular path.”

For Idaho Power, which is leaning to EDAM and committed to the WRAP’s first binding season — while expressing concerns about the program’s readiness, a key issue is connectivity requirements and how the utility should navigate between WRAP entities in the Desert Southwest with those in the Pacific Northwest, said Benjamin Brandt, director of load-serving operations at the utility.

“Idaho Power is somewhat between those two areas,” Brandt said. “So better understanding of the Markets+ footprint and connectivity … and what that might look like, I think that would be a good place for us to start.”

Derek Russell, director of power at Powerex, agreed, saying he wants the task force to refocus on “connectivity and deliverability” to ensure participants can rely on WRAP transfers.

“I think a focus of just reassessing what the region looks like and … how those transfers are enabled between participants, I think that should be a point of emphasis as we kind of go through towards an ultimate solution,” Russell said.

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43 Expedited Tx Projects Line up for MISO 2026 Planning Cycle

With its 2025 cycle of transmission projects not yet final and approved, MISO already is working through 43 expedited project requests ahead of its 2026 cycle to support almost 14 GW of new load.

Since June, MISO has fielded 43 expedited project requests for the 2026 MISO Transmission Expansion Plan (MTEP 26). Many of the project proposals deal with large load additions; together they represent 13.765 GW of new load.

At a Nov. 4 teleconference of the Expedited Project Review Technical Studies Task Force, Expansion Planning Manager Zheng Zhou said that over the past two years, large load interconnection projects have “increasingly utilized” MISO’s expedited review process for projects that cannot wait until end-of-the-year approval through the RTO’s annual MTEP process.

MISO fielded five project requests in June and approved two. Of the remaining three, two are under study and one was recommended for approval at the Nov. 4 meeting.

Of the 15 requests in August, MISO has approved five and recommended six more for approval Nov. 4, with four under study, including Entergy Louisiana’s Mount Olive-to-Cargas 500-kV line and substation work to support a new Meta data center in Richland Parish.

In October, MISO received 23 expedited requests and so far has recommended two for approval. Those two are smaller, age- and condition-based upgrades in Louisiana for 1803 Electric Cooperative, which joined MISO in June. MISO staff said 1803 is trying to get a jump on securing long-lead equipment for a “like-for-like replacement with no topological change.”

MISO has pivoted to a bimonthly processing approach to handle its growing number of transmission projects submitted by members for expedited treatment.

The grid operator now opens an acceptance window every other month for expedited project requests, with the next one in December. It has said the new cadence should be less cumbersome for staff than its previous ad-hoc approach. Until mid-2025, MISO evaluated requests as it received them. (See MISO Starting from Scratch on New Schedule for Reviewing Expedited Tx Projects.)

MISO studies smaller expedited projects in batches while larger, more complex projects receive individual assessments. It has a goal of a 30-day study turnaround for more straightforward projects. The RTO also schedules a single, monthly Technical Study Task Force meeting to discuss expedited projects instead of holding piecemeal, short task force meetings every time a request pops up.

MISO has experienced a runaway volume of expedited requests in recent years as load growth surges. The RTO said it used to process an average of six expedited requests annually before 2021. MTEP 25 contains 49 expedited transmission projects. The projects themselves are becoming larger and more complex.

MTEP 25’s more than $4 billion in expedited investment eclipses MTEP 24’s $896 million worth of expedited requests and MTEP 23’s $684 million. MISO said expedited projects are responsible for most of the 11.6 GW of large load additions that MTEP 25 will support.

Some stakeholders have asked MISO to consider adopting a load interconnection queue similar to its generator interconnection queue because of the snowballing expedited requests.