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December 5, 2025

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Let’s Own the 5th Industrial Revolution

Pat Wood III

By Pat Wood III

Two weeks ago, a reporter asked me what I thought about Energy Secretary Chris Wright’s recent Section 403 directive to FERC. Being immersed in things ERCOT as of late, I was puzzled. “Rick Perry’s ‘save the coal plants’ project from 2017?”

“No, I’m talking about large load interconnection.” Oh.

So, I read it. And it was good, even elegant. I read it again. I liked Wright’s strong reliance on the standard generator interconnection policy we adopted in Order No. 2003 back when I led FERC. There is a clear parallel between what we did then to speed the building of new generation at the turn of the millennium and what DOE wants to do today to accelerate the growth of critical data infrastructure.

States regulate the building of large generation; FERC regulates their interconnection to the interstate transmission grid. States regulate retail service to large loads; why shouldn’t FERC regulate their interconnection to the interstate transmission grid?

This symmetry on both ends of the bulk electric system seems like a slam dunk in the courts. From the past Supreme Court rulings, and considering its current direction, it would seem FERC would get a warm reception there.

Then, the real question is: In standardizing a large load interconnection process, what could FERC do to actually make things better?

The ‘Energy Intelligence’ Era

First, acknowledge this is a national imperative. Large new power users must have rapid and predictable access to electricity. The Fifth Industrial Revolution is underway, its start date accelerated, ironically, by the pandemic that spread from China.

This “Energy Intelligence” era is defined by the rapid electrification of the planet and the advent of artificial intelligence. Our failure to timely serve these customers will cede the leadership role for this revolution to China. You don’t have to be born on the Fourth of July to know that is unacceptable.

Second, lay down the law about the other two-thirds of the power system: generation and delivery. The inane pissing match between fossil fuels and renewables, between central station and distributed power, benefits only those who don’t want American dominance. We need EVERYthing.

To enable that, we need a much more robust and smarter transmission and distribution system. Wind, solar and natural gas are the cheapest fuels to create power, and this country has huge amounts of all of them. Storage and flexible demand are the newest players on the field, and I expect nuclear, geothermal and others will come. All of this is being enabled by dramatically advanced information technology. So, Team America wins with addition, not subtraction. And the faster, the better.

Standardize and Connect

On to substance. Adopt a clear, transparent interconnection process for large load customers. Use a standardized large load interconnection contract and require grid operators to complete interconnection studies on aggressive timetables.

To encourage transmission owners to also move at the speed we need, we should reward them for making network upgrades quickly and penalize them for taking too long. If the large load customer can get local construction and engineering done faster and/or cheaper through a third party than the utility, that adds discipline and cost control to the overall process.

For all connections to the transmission grid, we should embrace the “connect and manage” approach we’ve used successfully with interconnecting ERCOT generators since 1997. Spread it to all generation and to large loads nationwide.

In effect, we tell the interconnecting facility, “we’re going to hook you up pronto and do our best to serve you 24/7, but you’re going to get best efforts (interruptible) service for a while until we get the grid beefed up in your neighborhood.”

If interruptible service isn’t acceptable to large load customers, we should ensure that on-site generation and batteries are a viable option. Assuming most customers want firm service eventually, we can use the network upgrade process from Order No. 2003 where interconnecting customers fully fund their local interconnection costs and front a deposit for new network upgrades that they trigger. This deposit should be large enough to protect other grid customers if the large load fails to show up.

A key factor causing slow interconnections to date is the calculation of needed network upgrades and their cost. On a swiftly evolving network where flows change every second, computing and attributing a transmission network upgrade’s cost to a single party is a fool’s errand. The important thing is to set a fair deposit amount quickly and conclusively. Ideally, a flat rough average $/kW amount should be sufficient. A version of this “entry fee” concept is being used for generators in SPP.

Manage the Grid with Latest Tools

While the regional infrastructure is being upgraded, utilities and grid operators must manage and get more out of the network with grid-enhancing technologies, advanced power flow controls, topology optimization, dynamic line ratings, reconductoring with high performance conductors and the like.

I’ve seen these tools employed in specific applications for a couple of decades now; it’s time we make them a central part of 21st century grid operations. Large load customers’ demand profiles sometimes could resemble those of a steel mill or foundry.

Customers with highly varying loads should be encouraged to manage those with on-site equipment like batteries with inverters and on-site controller software. This could be done through incentives like shorter timetables or reduced entry fees. I prefer carrots like these to sticks, but perhaps this jagged load profile impact upon the grid is one where a requirement may be in order.

‘Win-win’ Cost Allocation Scenarios

Issues relating to rates that the large load pays to take retail service remain with state regulators. We already see utilities and regulators creating new tariffs to protect other customers from cost shifts from large load customers.

Many of these new customers have deep pockets, so if there is any cost shifting at all, it should benefit existing customers, who have paid plenty already to build the system we have. There are many win-win scenarios here.

Some believe that data centers, in particular, will be the flexible load we’ve been waiting for to bring discipline to what always has been a generator-centered system. I’m not sure how flexible they really are. But that’s OK. Let’s set up a market to purchase flexibility just as we buy generation, and we’ll find a lot of other customers who are flexible.

Getting the wires interconnection done is crucial, but the power itself is most important. Several large players are developing their own gas/battery/solar microgrids to accelerate their market entry. That’s fine as a speed-to-market strategy, but the whole reason we worked for the past generation to set up robust, open access, wholesale market grids was to enable reliable, cheap and clean power for all customers.

Let’s bias toward ultimately relying on the grid for primary power, and favoring local assets for backup power, instead of vice versa. But if large loads do add backup power, we should allow and encourage them to use it to benefit all of us, particularly when extreme weather stresses the grid. Again, I prefer market-based carrots rather than regulatory sticks on this.

Thoughtful standardization reduces costs, speeds entry and provides certainty for customers. The Good Lord has blessed our country with abundant natural resources. And with optimism. Let’s put it all to work. Now. At scale. Game on.

Pat Wood III, Executive Chairman of the Hunt Energy Network, is past chairman of the Public Utility Commission of Texas and of the Federal Energy Regulatory Commission.

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PUCO Fines FirstEnergy $250M After Investigation into HB 6 Scandal

The Public Utilities Commission of Ohio approved $250 million in fines for FirstEnergy, which comes after a federal investigation in 2020 found the utility had bribed lawmakers to secure a bailout for its nuclear plants. (See Feds: FE Paid $61M in Bribes to Win Nuke Subsidy.)

The bribes went chiefly to state legislators including former House Speaker Larry Householder (R), but former PUCO Chair Sam Randazzo also was charged with taking bribes before he killed himself in 2024. (See Scandal-ridden Former PUCO Chair Sam Randazzo Found Dead.)

PUCO issued two separate orders, finding that FirstEnergy’s utilities in the state (Cleveland Electric Illuminating Co., Ohio Edison and Toledo Edison) violated state law, PUCO regulations and orders, and ordered them to pay a combined $250.7 million in restitution to customers and civil forfeitures.

“The commission has remained steadfast in ensuring that we have followed the facts wherever they may lead,” PUCO Chair Jenifer French said in a statement. “Our hope is the events underlying these proceedings will remain a cautionary lesson of accountability and honesty in utility regulatory matters.”

FirstEnergy already paid a fine to the U.S. Treasury over the bribery allegations, and the $250 million resolves issues PUCO uncovered after it launched investigations into the utility after the federal probe became public.

PUCO found that the FirstEnergy utilities failed to show they adhered to a 2016 order it approved authorizing them to collect a “distribution modernization rider” to update their distribution grids. Instead, FirstEnergy took some of the money to subsidize its unregulated generation affiliate between 2017 and 2019. The company since has sold its unregulated generation.

The utilities will have to return $179.99 million over three billing cycles for that activity, which PUCO arrived at by tripling the $59.996 million the company spent in bribes to get House Bill 6 passed. The law provided a subsidy for the company’s nuclear plants.

“These funds represent an unnerving shadow over our regulatory role in this state and have harmed each and every consumer whose interests we aim to protect in proceedings before us,” PUCO said about the $60 million. “There have been many actions intervenors have called upon us to take in response to these events that lie outside of our authority to provide; however, when we do have the authority to order restitution for all Ohioans harmed by the companies’ actions discussed in these proceedings, we must do so in the interest of justice.”

FirstEnergy must refund an additional $6.64 million plus interest for some transactions it billed to customers but lacked supporting documentation or were misallocated to customers, as identified in an audit by PUCO.

The rest of the $250 million is due in the form of civil forfeitures after PUCO found FirstEnergy violated Ohio’s corporate separation laws when it entered into a consulting agreement with the Sustainability Funding Alliance in 2013. Regulated utilities were allocated costs for a consulting deal that benefited its generation affiliate, and the company owes $21.78 million in restitution.

The commission found FirstEnergy failed to disclose a side deal with the Industrial Energy Users-Ohio during a 2015 proceeding. The commission ordered the utility to pay a civil forfeiture of $18.93 million.

The last chunk is from a 2021 corporate separation audit, which found seven areas of violation between the company’s regulated and unregulated affiliates including a lack of a chief compliance officer and missing cost allocation information. FirstEnergy owes $23.36 million for that behavior, which PUCO said “contributed to the conduct giving rise to the HB 6 scandal.”

PUCO said FirstEnergy’s utilities have worked to fix their culture since the scandal and have new leadership that was not involved in the bribery, but the commission said it would remain vigilant to ensure compliance going forward.

“These proceedings were the first, and we trust the last, of their kind,” French said. “It is our responsibility and duty to impose appropriate remedies so as to ensure that they are.”

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Avoiding Bunker Fuel: CEC OKs 54 MW of Additional Gas Generation in Burbank

The California Energy Commission approved a request to increase the output of a Burbank gas-fired power plant to address grid reliability issues, prompting some organizations and locals to protest out of concern about the facility’s emissions and costs.

The CEC during its Nov. 17 business meeting granted about $36 million to the City of Burbank to refurbish the Magnolia Power Plant’s (MPP) compressor system for about $23.2 million and add a new gas path system for about $12.8 million.

The project would increase MPP’s capacity by 54 MW to make up for lost output stemming from degradation at the plant, a CEC resolution says. MPP’s added capacity will be available during extreme events for five years from the commercial online date.

The increased capacity was needed due to tight grid conditions in California over recent years, CEC Vice Chair Siva Gunda said at the meeting.

“[We’ve] had to throw everything on the table to keep the lights on,” Gunda said. “That meant basically turning on every backup generator in the state, like diesel backup generators, and unhooking large marine vessels from shore power and running them on bunker fuel.”

The CEC’s docket for the MPP project contained letters from nearby residents asking the commission to reject the facility’s renovation plan.

“Investing more money into an aging gas plant risks stranded assets — infrastructure that soon becomes unusable but still costs ratepayers,” wrote Suzanne York of Pasadena to the CEC on Nov. 14.

Gunda said that it is “really important for us to acknowledge the comments that were made by many of the community members.”

“Please don’t stop pushing back because … the next choice will be influenced by the comments you all make.”

The renovated MPP facility will operate with fewer environmental impacts than a peaker plant, Mandip Samra, general manager of Burbank Water and Power, said in a Nov. 14 letter to the CEC. Renovating MPP is also more cost effective than constructing a new facility, she added.

The CEC certified MPP in 2003, and the facility began operations in 2005. MPP is owned by the Southern California Public Power Authority (SCPPA) and operated by the City of Burbank and Burbank Water and Power.

The project’s funding is part of the CEC’s Distributed Electricity Backup Assets (DEBA) program, which provides incentives for constructing cleaner and more efficient distributed energy assets to strengthen electricity reliability, the commission said in its resolution.

At this point, the CEC has approved all natural gas efficiency improvement projects presented in the DEBA’s notice of proposed awards, a CEC spokesperson told RTO Insider in an email. The facility will never go beyond its nameplate capacity or what was originally certified for its output, the spokesperson wrote.

The CEC has approved two similar projects in recent years: the Lodi Energy Center in March 2025 and the Roseville State Power Augmentation Project with the City of Roseville in August 2024.

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SPP: ‘High Likelihood’ to Meet Winter Demand

SPP said it expects a “high likelihood” of meeting demand during the upcoming winter season.

Bruce Rew, senior vice president of operations, told stakeholders during a Nov. 17 winter readiness webinar that SPP does not anticipate “major concerns” during the season, which runs from December through February.

“Our studies show we’ll have sufficient generation to meet peak demand, and that’s before considering resources such as demand response, energy imports or voluntary conservation programs,” he said. “While our forecasts are dependable, they’re not perfect, so we also work to be prepared in case of an unexpected event.”

Rew assured his audience that SPP has “robust” tools and procedures in place to maintain reliability, “even when real operating conditions deviate from our forecast.”

“Thanks to the dedication of our staff members and stakeholders, we’re all well positioned to meet the challenges of the upcoming winter season,” he said.

SPP is predicting what Rew called a three-way weather forecast split across its footprint: colder than normal temperatures across the northern section, near normal conditions in the central areas and warmer than normal conditions slightly more likely in the South.

“An isolated extreme event cannot be ruled out,” Rew said.

Staff said SPP expects peak demand to exceed 48.8 GW during the winter. It has more than 64 GW of accredited capacity, a reserve margin of 35% and about 1.2 GW of DR to work with.

The RTO’s load-responsible entities are required to meet a 15% planning reserve margin for both the summer and winter seasons in 2025. The winter PRM ratchets up to 36% for the 2026-27 winter season.

The grid operator set a record winter peak of 48.1 GW in February 2025. Its all-time peak is 56.2 GW, set in August 2023.

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NWPCC Study Finds Market Availability Steady Across Different Scenarios

The buildout of new resources in the Western Interconnection over the next 20 years is “remarkably similar” across a variety of scenarios tested in the Northwest Power and Conservation Council’s market availability study.

Staff members presented the study results at a council meeting Nov. 18. The study will inform the upcoming Ninth Power Plan, which the council is required to develop under the Northwest Power Act “to ensure an adequate, efficient, economical and reliable power supply for the region.” NWPCC publishes a plan every five years, according to the council’s website. (See NWPCC’s Initial Demand Forecast Sees Sharp Growth for NW.)

The market study evaluates out-of-region load growth and resource buildouts in the West over the next 20 years under different scenarios, including constrained buildout, delayed storage availability, existing transmission, increased transmission, emerging technology cost uncertainty, federal policies and hydro operations.

The study found that “market availability does not change significantly across the various sensitivities,” according to council presentation slides.

Though near-term buildouts of resources shift slightly, primarily where there are limitations in resource availability, the 20-year buildouts are “remarkably similar.”

“In other words, there isn’t something so disruptive in one of the sensitivities that we’re seeing a major change in trajectory,” said John Ollis, manager of planning and analysis.

Ollis noted some variation among the scenarios in the pace of uptake of certain types of resources. For example, delays in short-duration storage increase variable energy resource (VER) build by more than 20% and gas build by 25% by 2032, but they decrease VER by 25% by 2046, according to the presentation.

The study found expansion of gas resources under scenarios in which transmission builds are limited, resource acquisition is delayed or emerging tech costs are high.

The majority of resources built across all sensitivities are a mix of renewables, storage and gas. Demand growth and carbon pricing policies in California, Washington and Canada are key drivers for buildout, according to the study.

The market study helps power planners better understand the economics and resource adequacy issues underlying the power plan, Peter Jensen, a spokesperson for the council, told RTO Insider.

On the economics issue, Jensen said, “Even though we only plan for the region, the economics of every regional resource decision depends not just on the regional market fundamentals and policies, but on the market fundamentals and policies throughout the WECC.”

Similarly, “even though resource adequacy depends primarily on regional resources, understanding what resources might be available outside the region during stressful times is also important for informing adequacy and keeping rates down,” Jensen added.

On Nov. 5, the council’s System Analysis Advisory Committee — which includes regional utilities, Bonneville Power Administration staff, regulators and technical experts — reviewed the market study’s results.

“We had an opportunity to gut-check the size of the build, size of investments, risks and other key findings, and the committee members were broadly comfortable with the results,” Jensen said. “We appreciate the opportunity to collaborate and check the assumptions and results of our analysis with these experts as we continue to develop the Ninth Plan.”

The council aims to have a draft of the Ninth Plan ready for public comment by July 2026, and a final version by the end of 2026.

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ISO-NE Outlines Accreditation for Active, Passive Demand Resources

ISO-NE outlined proposed capacity accreditation for active and passive demand capacity resources at the NEPOOL Reliability Committee meeting Nov. 18.

The changes are part of the second phase of the RTO’s wide-ranging Capacity Auction Reform (CAR) project, which aims to develop a seasonal capacity market and establish a marginal reliability impact (MRI) approach to accreditation that values resources based on their expected contributions to reducing energy shortfalls.

Passive Demand Capacity Resources

ISO-NE’s passive demand capacity resource category is largely composed of energy efficiency resources but also includes some distributed generation.

Under the current accreditation process, ISO-NE determines seasonal qualified capacity based on estimated performance during a “fixed set of performance hours,” which is intended to estimate resources’ “expected contribution to resource adequacy during tight system conditions,” the RTO noted in a memo issued prior to the RC meeting.

ISO-NE said the current set of performance hours “do not align well with hours when resource adequacy is at risk,” noting that the most important hours for resource adequacy change as the resource mix changes.

Transitioning to a marginal reliability impact (MRI) accreditation process will better capture passive resource contributions during projected shortfall periods, said Clara Berger, senior market development analyst at ISO-NE.

The RTO plans to evaluate resources’ MRI value based on “class-based hourly profiles for different technologies and end uses.”

Each resource’s final accreditation value would reflect the class values and maximum capabilities associated with each of its components, as passive resources often include multiple assets.

For distributed generation participating as passive demand capacity, ISO-NE plans to make resource-specific performance adjustments. These resources submit hourly data to the RTO, which will enable these adjustments.

Berger noted that the new methodology would allow the RTO to account for performance differences between classes that are not captured under the existing rules.

“This approach incentivizes the development of PDR assets and measures that provide the greatest value to system reliability,” ISO-NE said.

Active Demand Capacity Resources

ISO-NE’s proposed approach to accrediting active demand capacity resources (ADCRs) is similarly focused on capturing the resources’ ability to reduce shortfall.

Under the current rules, ISO-NE accredits active demand resources based on information submitted when the resources enter the capacity market as new resources. The RTO does not update this information in subsequent auctions to account for actual performance.

“While the existing framework for ADCR qualification does not depend on ADCRs’ demonstrated ability to reduce demand during stressed conditions, the proposed MRI framework for ADCRs will utilize both ADCRs’ offered capability and actual performance for accreditation,” ISO-NE wrote.

The RTO noted there is “a considerable amount of heterogeneity in ADCR performance,” which creates risk that the market is procuring resources that are unable to perform at their full capacity during the most important hours.

Like passive resources, the contributions of active demand resources can depend on time of day, making it important for ISO-NE to evaluate accreditation at the most important hours for system reliability, ISO-NE said.

In the new accreditation process, the RTO proposes calculating MRI values using hourly profiles based on each resource’s maximum reduction values offered over the past three years, with adjustments for the observed performance factor.

For new resources, the profile will be based on the performance of other resources in the portfolio of the lead market participant. If this data is not available, ISO-NE will base the profile on the performance of all existing active demand resources, with separate class averages for standalone resources larger than 5 MW.

Tie Benefits

Also at the RC, ISO-NE discussed how it plans to calculate tie benefits in a seasonal market.

Tie benefits are intended to quantify the reliability contributions of transmission lines connecting New England to neighboring regions. ISO-NE currently determines annual tie benefits based on summer values because the New England grid is a summer-peaking system.

The RTO noted that tie benefits associated with cross-border lines with Canada reflect “seasonal load diversity” associated with Quebec and the Maritimes’ winter peaks, which enable the provinces to reliably export power when the New England grid is stressed in the summer.

In comparison, because New York and New England have similar load profiles, New York tie benefits “are mainly the result of diversity in resource outages or availability,” ISO-NE noted.

As part of the CAR changes, ISO-NE plans to begin calculating tie benefits seasonally while maintaining the same basic modeling approach.

Under a seasonal framework, both New York and Canadian tie benefits will likely be driven by “diversity in resource outages or availability,” instead of surplus capacity, which may reduce the overall amount of tie benefits the region can expect in the winter.

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Voltus, Mission:data Argue Data Access Issues Stymie Residential DR in PJM

Voltus and Mission:data pushed back on opposition to their complaint against PJM from the RTO and others on using statistical modeling for residential demand response customers, saying the current rules have residential customers providing just 0.4% of registered DR in the market (EL26-4).

“Complainants wish to make it completely clear for the record: Voltus and Mission:data’s complaint is limited to residential customers,” they said in an answer filed Nov. 18. “Voltus and Mission:data are not proposing that statistical sampling be employed for any other class of customer, or to sample across customer classes.”

PJM argued in its response that the complaint was trying to get around state rules, which have made it hard to access interval meter data for residential customers for legitimate reasons. The RTO also said it lets DR aggregators use statistical modeling when interval metering data is not available at all for residential customers. (See PJM Asks FERC to Deny Demand Response Metering Data Complaint.)

Allowing DR aggregators to use those statistical modeling techniques when interval meter data is made unobtainable by state rules would unlock residential DR in PJM, Voltus Chief Regulatory Officer and former FERC Chair Jon Wellinghoff said in an interview Nov. 19.

“I would say there’s probably several thousand megawatts of DR that could be brought into PJM if we could access those residential customers, but this is the block,” Wellinghoff said. “We are being blocked by the fact that we don’t have reasonable access to interval meter data.”

The original complaint detailed Voltus’ efforts to procure the needed data from utilities for residential customers and how that proved difficult enough to be infeasible. It did that after FERC rejected a similar complaint from CPower on the grounds it had not filed enough information to prove data access rules were a hindrance to signing up customers for wholesale DR.

Voltus has no problem going through information security regulations to access the data where they are available, but it showed in the original complaint that many utilities across PJM make it very difficult for any third parties to get access, he added.

FERC granting the complaint could lead to states making their rules more workable, Wellinghoff said.

“It will give money in the pockets of residential consumers who are hurting from utility bills,” he added. “It will provide money to them for participating in these programs.”

Two of the biggest issues facing the industry are interconnecting large loads and affordability, which can be in tension. DR can help free up space on the grid to connect additional loads, and it can save customers from paying for extra investments to the grid, while directly giving money to participants.

“All the governors in PJM should be all over this complaint, telling FERC you should approve it immediately,” Wellinghoff said.

These kinds of DR programs for residential customers get around resistance to more economically elegant price-responsive demand, which could be a grid resource given the right price signals such as time-of-use rates, Wellinghoff said. But PRD has not proved popular among consumers, even as technology has advanced.

“It’s simply because consumers would much rather have some third party provide some service to them that can control independently their devices in ways that will help the market but also preserve the comfort in their home and provide them money in their pocket,” Wellinghoff said. “But they don’t want to do anything actively, because they’ve got other things to do.”

Having a third-party aggregator handle the optimal charging for a plug-in car or when to moderate air conditioning demand makes it easier for consumers who need to focus on their family life or jobs, he added.

The utilities with interval meters for residential customers have unfettered access to the data and could set up these programs themselves, but they lack the incentives to do so, Wellinghoff argued.

“They have no interest or incentive to have consumers go on time-of-use rates,” Wellinghoff said. “They have no interest or incentive to help customers participate in wholesale markets because they don’t make any money doing that. In fact, they lose money by doing that, because what that does is it allows consumers to help the system run more efficiently.”

That means less investment in the system, and less investment means fewer returns for shareholders, he added.

In addition to opposition from the RTO and member utilities, PJM’s Independent Market Monitor opposed the complaint on the grounds that the statistical modeling methods were by nature less accurate than the real data, which would degrade the RTO’s ability to track Capacity Performance and its ability to maintain resource adequacy.

“What the IMM also does not acknowledge is that PJM, in fact, accepts this ‘uncertainty’ and lack of precision for financial settlements today, where interval meters do not exist, as outlined in Manual 19,” Voltus said in its answer. “PJM’s statistical sampling process is designed to be rigorous and requires [that] ‘samples must be designed to achieve a maximum error of 10% at 90% confidence.’ The IMM does not explain how complainants’ proposal would introduce unacceptable certainty beyond what is established practice today.”

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Enviros Challenge MISO, SPP Queue Express Lanes

Environmental groups are further pressing their opposition to MISO‘s and SPP’s fast-track studies for primarily fossil fuel projects, challenging both in the D.C. Circuit Court of Appeals in a pair of lawsuits.

The petitions for review, filed with the court Nov. 18, contest FERC’s separate approvals of MISO’s Expedited Resource Addition Study and SPP’s Expedited Resource Adequacy Study (ERAS) processes, allowing load-responsible entities to nominate qualified projects for fast-track reviews to maintain resource adequacy.

Earthjustice filed the MISO petition on behalf of environmental groups Clean Wisconsin and Natural Resources Defense Council. It was joined in the filing by the Sierra Club.

Separately, the Sierra Club filed a petition with the court against SPP’s “unnecessary” proposal. The organization said the ERAS proposal favors gas generation at the expense of wind, solar and battery storage projects.

The filings came one day after the Sierra Club and NRDC, represented by Earthjustice, were party to a similar request to the D.C. Circuit over SPP’s accreditation methodology for clean energy resources. (See related story, SPP’s ELCC Methodology Contested at Appeals Court.)

The groups said MISO’s interconnection-queue express lanes bestow an “undue advantage” for fossil fuel generation, with ratepayers funding the grid upgrades needed to accommodate them. They asked for a reversal of FERC’s approval order.

They argued FERC incorrectly brushed aside the potential for the fast lanes to aggravate wait times and complicate studies for regularly queued resources.

“FERC is letting grid operators like MISO rewrite the rule book to the benefit of fossil fuel and data center companies, and at the expense of everyone else,” Ada Statler, a senior associate attorney at Earthjustice, said in a statement. “FERC is sidelining cheaper clean energy projects and allowing utilities to pass on the higher costs of methane gas to other customers, despite its legal mandate to ensure just and reasonable rates.”

Caroline Reiser, an NRDC senior attorney, said the fast lanes create an environment where a handful of mostly gas plants can cut in line to their financial benefit.

Sierra Club Senior Attorney Greg Wannier added that MISO is “spending too much time trying to benefit monopoly utilities and the gas industry at the expense of clean energy and independent producers.”

The Sierra Club said MISO’s process allows fast-tracked projects to “pass on significant upgrade costs to residential customers and to skip over clean energy projects that have been waiting for years to connect to the grid.” It argued that the clean energy waiting in MISO’s 175-GW interconnection queue is more affordable than the 18 GW of gas generation under study in the fast lane.

The Sierra Club and Natural Resources Defense Council objected to MISO’s design while it was pending before FERC. (See MISO Fast Lane Proposal Disadvantages IPPs, Retail Choice States, Critics Tell FERC.)

MISO has received 49 project applications representing more than 26 GW for its expedited queue. Most proposals entail natural gas-fired units. (See MISO Selects 10 Gen Proposals at 5.3 GW in 1st Expedited Queue Class.)

MISO Vice President of System Planning Aubrey Johnson said during a Nov. 11 Entergy State Regional Committee meeting that MISO believes the fast lane already has met its objectives to accelerate resource additions.

Altogether, MISO’s temporary process would enable 68 projects, with 10 slots reserved for submissions from independent power producers and eight reserved for entities serving MISO’s retail choice load in downstate Illinois and a percentage of Michigan.

Sierra Club Appeals SPP ERAS

The Sierra Club said that despite no “solid evidence” of a capacity shortage, SPP claimed its ERAS proposal was necessary to address rising capacity demands. It said SPP has a history of favoring thermal projects over renewable energy and that the ERAS process’ structure would make it virtually impossible for wind or solar facilities to participate in this new process.

The organization said the ERAS allows the fast-tracked projects to pass upgrade costs to residential customers and clean energy projects that have been waiting for years to connect to the grid. It said it previously alleged at FERC that SPP “improperly” dismissed the potential for fast track to exacerbate challenges in processing and connecting the rest of the RTO’s queued resources.

SPP spokesperson Seth Blomeley told RTO Insider that staff are reviewing the Sierra Club’s filing. “We remain confident in the merits of our plan, which was approved by FERC,” he said in an email.

The Sierra Club argues that SPP claims ERAS is necessary to meet increased demand from data centers but that SPP suggested in other regulatory contexts that other reforms to the queue would address resource shortfalls.

The Sierra Club pointed to Duke University research that found new demand for electricity from data centers and other large loads can be flexed to avoid building expensive new gas plants while maintaining electric grid reliability.

FERC approved SPP’s ERAS proposal in July. It was conditional on making a compliance filing within 30 days of the order’s issuance (ER25-2296). (See FERC Approves SPP’s ERAS Process, Accreditation.)

The Sierra Club’s rehearing request was rejected in November, “deemed to have been denied” after no FERC action was taken.

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$12B MISO 2025 Tx Portfolio Close to Final Approval

A MISO board committee advanced 432 projects from transmission owners at a cost of almost $12.3 billion under the RTO’s 2025 Transmission Expansion Plan.

The System Planning Committee voted unanimously to approve the MTEP 25 package at a Nov. 17 teleconference. The plan now moves to the full Board of Directors for consideration at its final meeting of the year on Dec. 11.

The projects, which total 1,901 miles, would support 11.6 GW of spot load additions. Louisiana contains the most investment at $3.4 billion. Wisconsin follows with $1.8 billion and Indiana with almost $1.7 billion. (See MISO 2025 Tx Expansion Estimate Drops Slightly to $12.4B.)

MISO Executive Director of Transmission Planning Laura Rauch said large loads seeking to reserve spots on the grid influenced the sizeable investment.

MTEP 25’s most expensive project — Entergy Louisiana’s $1.2 billion Cargas 500-kV and Smalling 500-230-kV stations in northeastern Louisiana — is planned to support a new $10 billion Meta data center.

Southern Louisiana’s Babel-to-Webre 500-kV line project is the second-most expensive MTEP 25 project at $1.066 billion. Entergy Louisiana said it’s needed to meet NERC reliability criteria.

The Missouri Multi-Entity New Transmission (MoMENT) project, a $604 million joint venture between Ameren, Evergy, MISO, SPP and Associated Electric Cooperative, is the third-most expensive. The 345-kV and 161-kV lines and substation in central Missouri are meant to improve reliability and be in service by December 2030.

Rauch told board members that MISO emphasized the collaboration behind the MoMENT project in its MTEP 25 report.

MISO’s Jeremiah Doner said load growth, AI data centers and economic development — all the “hot button issues” — influenced MTEP 25.

“The common theme this year is around those large load additions,” Doner said during a Nov. 3 gathering of the Planning Advisory Committee (PAC).

PAC’s 11 membership sectors voted in early November to approve MTEP 25. Six sectors voted in favor of the portfolio, two abstained from voting and three sectors didn’t respond to the emailed ballot.

MISO’s state regulatory sector typically abstains from voting on MTEP portfolios, reasoning that it’s improper for state commissioners to preemptively judge the projects that will come before them later for separate approvals.

MTEP 25 still contains a $92 million maintenance project for a 345-kV line that was part of MISO’s 2011 Multi-Value Project portfolio. Xcel Energy will replace cracking davit arms on a multi-value project in Minnesota. Any maintenance on multi-value projects must be classified under the multi-value category.

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FERC Gives Go-ahead on Tougher MISO DR Testing Rules

FERC has greenlit MISO’s plan to require its demand response to make real-world demand reductions to fulfill the RTO’s testing requirements.

FERC said the “modifications more clearly define and standardize the existing testing procedures” in a Nov. 17 order (ER25-2845).

MISO now can mandate DR to make actual megawatt reductions for testing instead of submitting mock tests to prove capability. MISO worked on the proposal over 2025. (See MISO Tries to Ward Off DR Fraud with New Testing Regime.)

“[W]e find that establishing stricter testing waiver criteria and adding specific testing parameters for demand resources in the tariff will provide greater certainty that demand resources will be available when called on by MISO,” FERC said, adding that the rules should diminish the “likelihood of market participants registering resources into the auction in a manner that does not accurately reflect the true capability of their resources.”

The commission granted MISO’s requested effective date of July 15, 2025, so the new testing regime is in place by the 2026/27 capacity auction. It said it weighed the quick turnaround time against the importance of accurate testing. It pointed out that MISO allows market participants to use “operational data gathered in the ordinary course of business” to prove full demand reduction or allows resource owners to defer testing until May 29, 2026.

MISO has about 15 GW of DR as of late 2025. But MISO has said its experience shows that only about half of the DR fleet is available when needed.

Under the new MISO paradigm, DR resource owners must demonstrate they can honor their notification time while dropping demand within the time-of-day periods that match with hours that MISO expects system risk to occur. The resources must hold their demand reduction for 15 minutes, covering at least two meter intervals. Owners must show a full reduction of all the megawatts they specified in registration during a real power test. MISO said it would allow some resources that experience a weather impact during testing to demonstrate a bit less than their full stated capability.

MISO will allow select DR owners to proceed with a mock test if a state authority expressly allows it or if it’s a proven resource that has responded to a call in the past three years and has not changed its specifications since.

DR and distributed energy resource aggregators argued before FERC that MISO’s plan allows discriminatory treatment between load-serving entities’ DR programs and aggregators of retail customers.

Voltus and Advanced Energy United said MISO’s testing waivers for load-serving entities’ DR programs amounted to aggregators’ DR groupings being held to a different standard. The RTO included testing waivers for retail DR programs overseen by state regulatory authorities. It didn’t extend the possibility of waivers to aggregators.

FERC said the testing exceptions aren’t discriminatory and recognize “states’ interest and expertise in ensuring that the demand response programs under their jurisdiction are effective.” The commission further pointed out that MISO’s tariff already contains the potential for testing exemptions for retail programs managed by state regulators. It said it was “reasonable for MISO’s testing requirements to account for relevant testing provisions in retail programs.”

The testing rules are part of a myriad of new restrictions MISO has placed on its DR since the RTO, its Independent Market Monitor and FERC staff discovered multiple instances of fraud, misrepresentation or rule violations among its DR fleet. (See MISO Tries to Clear Up Assortment of New DR Rules.)