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December 8, 2025

MISO: More Time Needed to Perform 8-year Resettlement of TOs’ ROE

MISO says it needs more time to finish meting out refunds to transmission customers nearly a dozen years after a complaint was first raised to lower its transmission owners’ base return on equity (EL14-12, et al.).

The RTO and TOs requested an extension until June 30, 2026, of the current Dec. 1 deadline to complete refunds under a FERC-ordered ROE in transmission rates.

In an October 2024 order, FERC set MISO’s base ROE at 9.98%, down from the previous 10.02%. That figure is the latest in a complicated carousel of ROE percentages the commission has set in the last decade.

MISO transmission customers first complained in late 2013 that the 12.38% ROE in use since 2002 was excessive. A second complaint challenging the ROE followed in 2015; that complaint was dismissed as FERC set and reset ROEs from 2016 onward (10.32% beginning in 2016, 9.88% in 2019 and 10.02% in 2020).

In the 2024 ROE order, FERC upheld an original 15-month refund period from Nov. 12, 2013, to Feb. 11, 2015, while prolonging a second refund period from Sept. 28, 2016, through Oct. 17, 2024. The TOs are challenging the eight-year refund period. (See MISO TOs Take ROE Battle to DC Circuit Court Again.)

MISO said more time is necessary to complete the complicated resettlements and accurately disperse refunds with interest for the eight-year period.

The grid operator said, “The number of affected transmission owners, the number of months involved and the number of affected schedules have all increased.” The affected TOs are up to 89, from 75, while the months needing resettlement are up to 181, from 110, it said.

“The tasks have been organized as efficiently as possible but involve ‘thousands of files and communications,’” the RTO told FERC, quoting an attached affidavit from its manager of transmission settlements, Erin Peddicord. “Coordination must take place between MISO and its many TOs, ‘with the exchange of hundreds of files between MISO and its transmission owners for every resettlement year [from] 2013 through Oct. 17, 2024.’”

Peddicord said that although the RTO has been making progress, the base ROE is “fundamental to MISO’s transmission billing.” She said FERC’s changes impacted several revenue schedules and tariff attachments, which are used in part to develop zonal transmission rates, MISO’s systemwide rates and compensation for the 2011 batch of Multi-Value Projects.

She added that transmission formula rates are not standardized in MISO, and TOs have different refund obligation dates, resulting in partial month settlements in some cases. She said the refunds are set to affect all TOs, whether they use historical, forward-looking or hybrid test years to calculate their annual transmission revenue requirements.

Planners Pick $1.5B Underwater HVDC Line for Toronto’s ‘Third Supply’

IESO system planners on Sept. 25 recommended the construction of a $1.5 billion HVDC line to meet Toronto’s growing energy needs, saying it would be more “future proof” than two cheaper options. 

The approximately 40-mile, 900-MW line would run from the Darlington transmission station (TS) in Bowmanville to the Port Lands neighborhood, near Downtown Toronto, via Lake Ontario, requiring expansion of the Hearn switching station in the Port Lands area to add equipment. 

“This option can deliver broader bulk system benefits, as it completely bypasses Cherrywood TS and Leaside TS,” the ISO said in a presentation Sept. 25. 

Toronto’s electricity demand could increase 70% (reference case) to 100% (high electrification) by 2044 because of new housing and commercial development, data centers, and the electrification of heating and transportation. 

As a result, electricity demand is expected to exceed the transmission capacity in 10 to 15 years, creating a “reliability need” by 2038 — or 2034 if the 550-MW gas-fired Portlands Energy Centre (PEC) ceases operations. 

IESO’s draft Integrated Regional Resource Plan (IRRP) recommends battery energy storage systems, upgrades to infrastructure and incremental electricity Demand Side Management (eDSM), including residential solar/storage systems, in addition to new transmission infrastructure. 

“With or without the supply contributions from PEC, meeting the significant need identified for eastern Toronto due to the significant forecasted growth requires a large-scale wires solution,” the ISO said. 

Toronto is currently served by two high-voltage transmission corridors. The underwater line was one of three options planners considered for Toronto’s “Third Supply,” including an overland route from Cherrywood TS (Pickering) to Leaside TS in Toronto estimated at $800 million, and a hybrid of overland and underground segments from Cherrywood TS to the Port Lands, estimated at $900 million. 

In addition to the underwater HVDC line (highlighted in teal) that was recommended, IESO planners also considered an overland route from Cherrywood TS (Pickering) to Leaside TS in Toronto (yellow) and a hybrid overland/underground route from Cherrywood TS to the Port Lands in Toronto (blue). | IESO

“We chose Bowmanville because here we can connect directly to the bulk power system, and it’s conveniently near the lakeshore,” said Steve Norrie, IESO supervisor of transmission planning. “We picked HVDC technology over the more traditional AC technology for its performance and economics over longer distances underwater. This option offers a new supply path that doesn’t rely on Leaside TS, and it doesn’t rely on any of the 230-kV networks at Cherrywood to inject more power downtown, which means that it can deliver broader benefits for the bulk system.” 

While all three options would meet East Toronto’s growth needs into the 2040s, the underwater cable is “the most future-proof option, because it supports the forecasted demand the longest,” Norrie said. “In fact, it will support the demand beyond 2044, so it pushes the need out past the end of the 20-year study in terms of system resilience.” 

Norrie said the HVDC line would help the city respond to “high-impact events,” such as the extreme rainfall and flooding that resulted in the loss of supply in July 2024. 

Toronto has experienced at least three one-in-100-years rainfall events over the last 20 years, and the last two disrupted power to more than 200,000 customers, “which is something that we really looked at this plan as an opportunity to address,” Norrie said. 

The overhead option doesn’t change Toronto’s reliance on the two existing transmission supplies, Norrie said. He said the hybrid would provide some resilience benefit for the downtown core, but the supply to Eastern Toronto would still be reliant on the path coming from Cherrywood. 

“The underwater cable provides a new geographically separate and electrically separate supply path to the downtown. It reduces reliance both on Leaside and Cherrywood, plus it provides a means of backing up the other paths into Toronto in the event of a loss of supply,” he said. “So this would be a significant improvement in system performance.” 

The ISO will consider written comments on the draft IRRP until Oct. 9. 

“We will now be listening to feedback on this draft recommendation, and we will make our final recommendation at the end of October,” IESO spokesman Michael Dodsworth told RTO Insider. 

Escalating Conflict with Utilities Leads to Resignation of Top Conn. Regulator

The forthcoming resignation of Connecticut Public Utilities Regulatory Authority (PURA) Chair Marissa Gillett has created high-stakes questions around the state’s adoption of a comprehensive performance-based regulation (PBR) framework, with three key votes set to occur just two days before Gillett is scheduled to step down.

Gillett, who has frequently drawn the ire of the state’s investor-owned utilities, announced her resignation Sept. 19 after a prolonged pressure campaign by utilities and Connecticut Republicans, writing that “the escalation of disputes into a cycle of lawsuits and press statements pulls attention and resources away from what matters most: keeping rates just and reasonable, improving service and planning a resilient, reliable energy future.”

The disputes have “exacted a real emotional toll both for me personally, as well as my family, and for my team,” Gillett said, adding that “there is only so much that one individual can reasonably endure, or ask of their family, while doing their best to serve our state.”

The day prior, on Sept. 18, Connecticut House Republican Leader Vincent Candelora called for an impeachment inquiry into whether Gillett lied during her February confirmation hearing about the existence of a directive requiring that “staff support for commissioners be directed through her.”

Her resignation, which will take effect Oct. 10, comes as PURA works to finalize a set of major regulatory changes intended to better align utility incentives with customer benefits.

Gillett began her tenure as chair of PURA in 2019, making headlines by presiding over several rulings that significantly limited revenue increases for utilities or ordered revenue decreases.

With Gillett at the helm, PURA decreased the revenue requirements in rate cases for the Aquarion Water Co. and a pair of Avangrid-owned gas utilities, significantly limited a proposed United Illuminating electric rate increase and issued major fines on the state’s electric utilities for poor performance responding to Tropical Storm Isaias in 2020.

According to Gillett’s critics, she fostered an unfavorable investment climate for utilities, hurting their credit ratings and disincentivizing investments in the state’s grid. In recent months, Connecticut Republicans argued she overstepped the limits of her authority, and Eversource Energy and Avangrid alleged in lawsuits that Gillett held a personal bias against the companies.

Following the news of her resignation, Eversource’s stock price spiked by about 8%. Equity analysts at Jefferies Research Services called the news a “clear positive” for the company, writing that Connecticut “has been one of the most challenging U.S. regulatory jurisdictions for the past decade.”

But according to her supporters, Gillett was extremely effective at pushing back against unjustified utility costs and rate increases, making her a target of utility companies.

Reacting to the news, David Pomerantz, executive director of the Energy and Policy Institute (EPI), a utility watchdog nonprofit, called Gillett “possibly the best utility regulator in the country,” saying she “joins the long list of regulators who have attempted to lower rates and confront utility profits, and lost their jobs for it.”

“I think Chair Gillett — more than any other utility regulator in the country, state or federal — was really enacting a reform agenda that could lower rates, and in doing so, was challenging the utilities and their investors on Wall Street to earn their profits in a different way,” Pomerantz said.

Performance-based Regulation

Beyond specific ratemaking proceedings, much of Gillett’s tenure has focused on PBR development in the state. The shift to PBR was initiated by the legislature, which in 2020 directed PURA to develop a comprehensive PBR framework after Tropical Storm Isaias triggered extended power outages.

PURA approved a more general set of goals, considerations and key outcomes for PBR in 2023 (21-05-15) and is nearing final votes on three follow-up dockets to establish specific performance metrics, revenue adjustment mechanisms and integrated distribution system planning requirements.

Throughout the process, utilities have criticized PURA frequently for failing to adequately consider their input, while environmental and consumer groups praised the agency for taking a collaborative approach. (See The Rocky Road to Performance-based Regulation in Connecticut.)

PURA issued draft decisions in each of the three second-phase dockets in July and August (RE01, RE02, RE03). Final decisions for each of the three dockets are scheduled for Oct. 8, two days before Gillett is set to resign.

Noah Berman, utility innovation program manager at the Acadia Center, said he would be “surprised to see a major pivot” in the PBR dockets from the proposed rulings.

“The question is whether the utilities decide to act in good faith on what is being established, or to put aside the years of work that have gone into these frameworks in favor of trying to delay and relitigate under a new chair,” Berman said.

He expressed concern about a “post-resignation inquiry” that Avangrid submitted in the three PBR dockets, which argues Gillett “must have no further involvement” in all open dockets involving the company.

“Chairperson Gillett’s multiple public statements evidencing bias and prejudgment of issues that she is required by law to adjudicate on an impartial basis are well known and are already the subject of pending litigation,” Avangrid wrote. It added that, following the impeachment inquiry and Gillett’s resignation, “if there was any doubt as to whether Chairperson Gillett could fairly adjudicate any of our matters, it is now extinguished.”

Gillett’s involvement in remaining proceedings, including the open PBR dockets, “will not only compound existing legal challenges to PURA’s conduct but will result in new, unnecessary litigation,” Avangrid wrote.

The company added it has “credible concerns about the conduct and bias of other high-ranking PURA personnel,” and asked PURA to explain “what steps the agency will be taking to ensure that PURA staff who are unable to be objective about our matters are not hereafter involved in those matters.”

Both Eversource and Avangrid declined to comment directly on Gillett’s resignation, or the effects it will have on utility regulation in the state. The companies have denied all allegations that they attacked Gillett personally.

Clean energy and utility accountability advocates have been quick to push back on the allegations of impropriety or bias by Gillett and PURA staff.

“Nothing produced from the utility-led [Freedom of Information Act] campaign against Gillett showed anything but a regulator resolute in her commitment to ratepayers,” Pomerantz of EPI argued.

He added that, in 2022, Avangrid’s CEO allegedly offered to provide Gillett with opportunities for “international exposure” in advance of a rate case, while simultaneously threatening to pull investment in the state in the event of an unfavorable decision. Avangrid has denied any wrongdoing.

In an interview, Pomerantz said Gillett’s replacement as chair, along with regulators selected to fill two additional open commissioner seats at PURA, will have a major influence on how PBR is used in the state.

“Performance-based regulation, generally speaking, is really only as good as the regulators that are there to implement it,” Pomerantz said.

While PURA’s PBR framework would be “best-in-class in the country,” if the framework ultimately is approved, it will be “up to a new PURA and a new chair to decide how to implement that new regulatory model over time,” he said.

Lindsay Griffin, Northeast regulatory director for Vote Solar, said the “utilities’ resistance to PBR is entirely predictable,” noting that it would introduce revenue penalties for poor performance, along with bonuses for strong performance.

“With Chair Gillett’s departure, implementing robust performance-based regulation becomes more critical than ever,” Griffin said. “PBR represents the institutional safeguard that can continue protecting ratepayers even when regulatory leadership changes.”

Broader Implications

Griffin also expressed concern about the ripple effects Gillett’s resignation could have on utility regulation throughout the country.

“This resignation sends a chilling message: that sustained legal warfare and public pressure campaigns can drive exceptionally qualified public servants from office when they hold powerful interests accountable,” Griffin said.

She emphasized the importance of “robust regulatory scrutiny,” adding that utilities “should embrace regulatory oversight, not weaponize litigation to silence it.”

Pomerantz offered a similar sentiment, adding that he thinks the “rest of the utility industry will be very happy to attempt to use [Gillett] as an example, to say to any other regulator, or potentially a governor, that ‘we can do that to you too.’”

He said other regulators also appear to have been pushed out of their jobs after clashing with utility companies, citing Michigan Gov. Gretchen Whitmer’s decision to replace Alessandra Carreon on the Michigan Public Service Commission with a political staffer who had worked for a former Michigan House speaker who took large campaign contributions from utility executives.

Instead of feeling intimidated by Gillett’s resignation, Pomerantz expressed his hope that regulators across the country will have the opposite reaction.

“It would be really nice if more of the regulatory community took offense to what the utilities have done here in Connecticut and felt galvanized by it,” Pomerantz said. “I don’t know if that’s happening or not.”

Federal Energy Policy News Roundup: House Bills and DOE Returns $13B

The House Sustainable Energy and Environment Coalition (SEEC) introduced its “Cheap Energy Agenda” on Sept. 24, which it calls a consumer-focused approach to energy policy and includes the Cheap Energy Act. 

The bill, introduced by Reps. Sean Casten (D-Ill.) and Mike Levin (D-Calif.), addresses many issues and proposes big changes for FERC’s authority. 

“For too long, United States energy policy has prioritized the wants of energy producers over the needs of American consumers,” Casten said in a statement. “It’s past time things change. The Cheap Energy Act is a consumer-focused approach to energy policy that is rooted in American values like choice and competition. It will lower the cost of energy for American consumers by ensuring they have access to cheap, reliable and efficient energy.” 

In addition to reinstating the clean energy tax credits Republicans wound down via the One Big Beautiful Bill Act (OBBBA), the bill has a number of policy changes regarding FERC’s authority, some of which Casten (a longtime supporter of the agency) has proposed in the past. 

The bill would have FERC speed up interconnection queues, including promoting the use of automation and standardized study criteria. FERC also would have to change how it allocates costs for lines that are required to reliably bring new generation onto the grid — assigning costs to all beneficiaries and not just the new generator. 

FERC would be required to start up an interregional transmission planning process and allocate the costs of such lines in a way roughly commensurate with benefits. Another idea that comes back up in the bill is that it directs FERC to establish minimum interregional transfer capability between regions — 30% of peak demand for most regions, but just 15% for those that border only one other region. 

FERC would get exclusive siting authority over national interest transmission lines, which are defined as any that cross two or more states and have a capacity that exceeds 1,000 MW. 

Each ISO/RTO would have to set up independent transmission monitors to facilitate the transparent and efficient deployment of new power lines. Another section, modeled after an old Casten bill, includes reforms to the ISO/RTO stakeholder and governance processes, which would start with a technical conference at FERC. 

FERC would be required to establish a shared-savings program under which utilities are rewarded for providing real, independently verified cost savings to consumers. Another proposal would ban companies from trading in energy markets if they manipulate electric or natural gas markets. 

 

The U.S. Department of Energy used Section 202(c) of the Federal Power Act to keep open a pair of fossil plants this summer and fall. The bill would change 202(c) by requiring the department to publish cost estimates for such orders. It also would prohibit DOE from issuing 202(c) orders for any reason that is more than a year in the future.

House Republicans Pass a Couple of FERC-Related Bills out of Committee

The SEEC’s Cheap Energy Act includes a wish list of reforms supported by Democrats, but Republicans have been using their majority to push through legislation in the House and its Energy & Commerce Committee. Before taking a break for the Jewish High Holy Days, the committee passed three bills in a Sept. 19 hearing. 

“Today’s passage of H.R. 3062, H.R. 3015 and H.R. 1047 reflects the House Committee on Energy and Commerce’s relentless work to secure American energy dominance,” Committee Chair Brett Guthrie (R-Ky.) said. “These bills streamline the permitting process for critical cross-border energy projects, restore expert advisory input from the coal industry that the Biden-Harris administration eliminated and ensure that electricity grid operators have the tools they need to secure the reliability of the bulk power system. With rising energy demand and growing threats to grid reliability, House Republicans are ensuring the U.S. has the tools to deliver affordable, abundant and reliable energy.” 

Former North Dakota state regulator and NARUC President, Rep. Julie Fedorchak (R-N.D.) introduced H.R. 3062, the Cross Border Energy Act, which would streamline the permitting process for natural gas and oil pipelines and electric transmission that connects the United States to Canada and Mexico. If the bill is enacted, FERC would review applications for pipelines and DOE for transmission, as opposed to requiring a presidential permit for cross-border energy projects now. 

“The Keystone XL pipeline should have never been canceled. Yet on his first day in office, President Biden used the stroke of a pen to shut it down,” Fedorchak said. “By passing my legislation, the House has taken a critical step to end years of regulatory uncertainty and partisan games that have delayed energy infrastructure projects, crushed good-paying jobs and undermined America’s energy security.”  

The bill would stop future administrations from backtracking on permits that earlier administrations granted to infrastructure crossing borders. 

Rep. Troy Balderson (R-Ohio) introduced H.R. 1047, which seeks to speed up the interconnection queue for “baseload” power plants like those that use natural gas. The bill gives ISOs and RTOs the authority to prioritize energy projects that are ready to bring baseload power on the grid immediately. 

“The interconnection queue is overwhelmed and bogged down, leaving shovel-ready power projects waiting for years while demand continues to climb,” Balderson said in a statement. “The GRID Power Act clears the path for the most critical projects, giving grid operators the tools they need to add more dispatchable baseload power — lowering costs for households and businesses while keeping America’s grid reliable.”  

Expediting resources that advance reliability provides grid operators with additional tools to re-balance the resource mix and keep the lights, while reversing the “legacy effects of the Biden-Harris energy policies that continue to drive prices higher,” the committee said.

DOE Announces $13 Billion in Biden Era Funds are Back in the U.S. Treasury

Speaking of reversing Biden-era policies, DOE announced Sept. 24 that it was returning $13 billion in unobligated funds initially appropriated to advance green energy policies. 

“The American people elected President Trump largely because of the last administration’s reckless spending on climate policies that fed inflation and failed to provide any real benefit to the American people,” U.S. Energy Secretary Chris Wright said. “Thanks to President Trump and Congress, those days are over. By returning these funds to the American taxpayer, the Trump administration is affirming its commitment to advancing more affordable, reliable and secure American energy and being more responsible stewards of taxpayer dollars.” 

The authorization to reverse the tax spending came under OBBBA, which the Trump administration has since rebranded the “Working Families Tax Cut,” and is meant to rein in federal spending and return unobligated funds to the Treasury. Exactly what the money had been earmarked for is unclear, and DOE did not respond to a request to explain that.

Dallas Fed Survey Shows Some Worries about State of Oil and Gas Industry

Meanwhile, the Federal Reserve Bank of Dallas released its regular quarterly survey of oil and gas executives on Sept. 24. The survey includes projections for future fuel prices and some selected quotes on the industry. The survey found expectations for natural gas to cost $3.35/MMBtu in six months and $3.53/MMBtu in a year, which compares to the prompt month closing at $2.853/MMBtu on the NYMEX on Sept. 24. 

The comments are anonymous, and many of them reflect the uncertainty in federal policy and argue that the Trump administration’s actions are working against domestic oil production but are helping natural gas. 

“Because of global circumstances, we think crude oil prices will stay low at the $60 per barrel level,” one respondent said. “Alternatively, because of an increase in the LNG market, we feel that natural gas development and production will increase.” 

Another complained that the Biden administration had vilified shale oil and gas, which led to less investment, but things have not turned around since Trump took office. 

“Guided by a U.S. Department of Energy that tells them what they want to hear instead of hard facts, they operate with little understanding of shale economics,” an anonymous executive told the Fed. “Instead of supporting domestic production, they’ve effectively aligned with OPEC — using supply tactics to push prices below economic thresholds, kneecapping U.S. producers in the process. The collapse of capital availability has fueled consolidation by the majors, pushing out independents and entrepreneurs who once defined the shale revolution. In their place, a handful of giants now dominate, but at the cost of enormous job loss and the destruction of the innovative, risk-taking culture that made the U.S. shale industry great.” 

A third executive worried that aggressive anti-renewable policies from the Trump administration will not be good even for oil and gas in the long term. 

“Day-to-day changes to energy policy is no way for us to win as a country,” they said. “Investors (rightly) avoid investing in energy (of all types, now) because of the volatility of underlying business results as well as the ‘stroke of pen’ risk that the federal government wields as it relates to long duration energy developments. Life is long, and the sword being wielded against the renewables industry right now will likely boomerang back in 3.5 years against traditional energy, which will find itself facing harsher methane penalties, permitting restrictions, crazy environmental reviews and other lawfare tactics.” 

CISA Publishes Cybersecurity Asset Inventory Guide

With operational technology (OT) systems increasingly vulnerable to cyberattacks, the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) has released a guide to help infrastructure owners and operators map their systems and plan their defense strategies.

CISA created the Foundations for OT Cybersecurity: Asset Inventory Guidance for Owners and Operators document through the Joint Cyber Defense Collaborative, an initiative between the private and public sectors that seeks to unify “cyber defense capabilities and actions of government and industry partners.” Entities from the water, oil and electric sectors contributed to the guide, including Duke Energy, Eversource, Pacific Gas & Electric and Southern California Edison.

OT systems have traditionally been separate from entities’ information technology (IT) and business networks. However, in today’s industrial landscape, OT is increasingly integrated with IT for business efficiencies; this creates opportunities for cyber attackers to access OT systems after gaining entry into a company’s IT network.

The guide provides assistance for entities to develop OT asset inventories, which are defined as “organized, regularly updated [lists] of an organization’s OT systems, hardware and software.” Asset inventories are “foundational to designing a modern defensible architecture,” CISA said, because they quickly give organizations insight into their networks to see what might be vulnerable when new threats are revealed.

CISA considers OT asset inventories so important that the agency added them to its list of cybersecurity performance goals, a set of best practices developed in tandem with the National Institute of Standards and Technology that are recommended for all organizations to provide a baseline level of protection.

The guide lays out multiple steps involved in developing an OT asset inventory. First, an organization should define the scope and objectives of the project. This includes defining the authority within the entity that needs the inventory and what positions will be responsible for establishing and maintaining it.

Next, the entity must inspect its system to identify the physical and digital assets and collect asset attributes. Attributes are fields that describe the asset; the guide lists items that entities should prioritize, such as active and supported communication protocols, asset criticality, IP address, manufacturer, physical location and associated user accounts.

A critical step in the process is creating a taxonomy for assets. Organizations must classify assets based on criticality for function; categorize assets and their communication pathways using an existing method or one devised by the entity itself; organize structure and relationships; cross-check and verify accuracy and completeness of the data; and periodically review and update it.

Recognizing that entities in various sectors may have differing needs, the document’s authors provided samples of taxonomies for several industries in the appendices, including electric utilities, based on exercises and discussions with sector representatives. The electric example divides assets into categories by function, such as communications; generation; transmission and distribution; physical and electronic access control or monitoring systems; energy management systems; and distributed energy resources.

Once the inventory is compiled, organizations may use it for several functions. These include cybersecurity and risk management — identifying vulnerabilities and mitigations for OT systems, prioritizing threat factors and strengthening security posture — and maintenance, which can mean assessing the cost of replacing vulnerable systems or analyzing their spare parts inventory to identify any potential gaps. Inventories can also help with performance monitoring and reporting, staff training and informing change management processes.

“More than just a technical manual, this guidance serves as a strategic enabler for cyber defense actions and operational collaboration with CISA and other key stakeholders,” CISA said in a press release. “With a precise understanding of the assets within an operator’s infrastructure, common vulnerabilities and exposures … become significantly more actionable and timely — helping operators reduce risk proactively, before incidents escalate.”

MISO Cuts Renewable Estimates in Tx Planning Scenarios

MISO has slashed earlier renewable energy estimates and boosted natural gas contributions in its transmission planning futures in a rethink brought on by the Trump administration.

Director of Economic and Policy Planning Christina Drake told stakeholders that MISO took a “very hard pivot” to incorporate the One Big Beautiful Bill Act into its four, 20-year futures, which are used to plan long-range transmission.

MISO was on its way to completing the futures and publishing capacity expansion estimates when the bill was passed in July. Staff have added months to the process and expect to deliver final futures sometime in early 2026. (See MISO Seeking Realistic Gen Buildout for Tx Planning Futures.)

“There is quite a bit of reduction in some of the renewable buildout,” Drake said before a Sept. 24 stakeholder teleconference. She also said MISO is reflecting increases in natural gas buildout in its members’ resource planning.

MISO Senior Manager of Policy and Regulatory Planning RaeLynn Asah said gas now represents a much higher share of the capacity expansion than when MISO last updated its futures in 2022.

MISO’s preliminary capacity expansion estimates by 2045 now include:

    • For Future 1, a total of 383 GW in installed capacity derived from 28% gas, 25% solar, 25% wind, 11% other, 4% battery, 4% nuclear and 3% coal at 911 TWh of output, with 224 GW built between now and 2045.
    • For Future 2, a total of 403 GW in installed capacity from 25% gas, 25% solar, 30% wind, 11% other, 3% battery, 4% nuclear and 3% coal at 1,075 TWh of output, with 254 GW constructed in 20 years.
    • For Future 3, a total of 446 GW from 19% gas, 31% solar, 29% wind, 10% other, 3% battery, 6% nuclear and 1% coal at 1,253 TWh of output, with 318 GW built between now and 2045.
    • For Future 4, a total of 454 GW from 25% gas, 33% solar, 20% wind, 10% other, 3% battery, 4% nuclear and 4% coal at 1,079 TWh of output, with 281 GW constructed.

MISO’s futures are fashioned through a “fast, faster, fastest” methodology for fleet change and demand in Futures 1-3. Future 4 — new for 2026 — anticipates continued supply chain hindrances and only includes member-announced generation retirements. Unlike the other futures, it doesn’t assume age-based retirements of thermal generators, resulting in about 23 GW of additional thermal generation compared to the other three futures.

MISO’s members have announced intentions to build 171 GW in resources by 2045. MISO’s modeling had to add the most supplemental resources to Future 3, where only 58% of capacity needs would be met using the 171 GW.

The RTO’s fleet prediction in 2022 under Future 2 for 2042 was 471 GW of installed capacity, consisting of 14% gas, 24% solar, 34% wind, 11% other, 9% hybrid resources, 6% standalone batteries, 2% nuclear and 2% coal. That future formed the basis for MISO’s nearly $22 billion long-range transmission plan for MISO Midwest.

MISO said sustainability goals from states and members, not federal incentives, would drive future capacity expansion.

Drake said as it stands across all futures, milestone goals from 2026 to 2028 in Illinois’ Climate and Equitable Jobs Act and New Orleans’ renewable portfolio standard were unattainable. MISO said lead times to build units made the goals infeasible in the near term. Illinois has set out to achieve 100% carbon-free energy by 2050, with interim targets of 40% renewable energy by 2030 and 50% by 2040. New Orleans, on the other hand, is attempting to achieve net carbon neutrality by 2040 and 100% carbon-free electric generation by 2050.

Decarbonization goals across MISO states | MISO

MISO’s Environmental Sector requested a sensitivity study on the futures where natural gas prices rise, prompting an energy storage expansion.

Sustainable FERC Project’s Natalie McIntire said she wondered whether the futures for use in scenario-based planning should be more “diverse” from one another and contemplate a wider range of possibilities. She said MISO should contemplate variables like rising gas prices and falling battery prices, along with the possibility of a reinstatement of tax credits for renewables.

Drake said MISO will check in with stakeholders once futures are more developed. She added that MISO planners have asked themselves the same questions.

“If we get to the end of this process and we don’t have broad bookends, we will revisit,” Drake promised. She stressed that MISO’s numbers aren’t final yet.

Drake said MISO is halfway through the recalibration of its futures. She said initially, removal of tax credits for wind and solar resulted in MISO’s model building a hypothetical 100 GW within a single year to take advantage of the fading perks. Drake said after MISO staff “laughed” at the results, they removed the possibility for renewable production and investment tax credits for generation not already in the queue.

“The rationale for that is if it’s not already in queue … it won’t be in the ground and ready to go by 2028,” she said.

Drake also said MISO must complete generation siting and large load siting for use in its transmission models alongside completing energy adequacy assessments to develop the futures. She said MISO would discuss the locations of large loads in the footprint in November.

MISO Senior Vice President of Planning and Operations Jennifer Curran said members recently have swapped lower accredited renewables for higher accredited dispatchable plants in their plans. She also noted that the U.S. Department of Energy has become “directly involved” in resource retirements, issuing a second extension of Consumers Energy’s J.H. Campbell coal plant in Michigan.

“There has been a lot of activity on the federal front,” Curran acknowledged at a Sept. 17 Advisory Committee meeting in Detroit, part of MISO’s quarterly Board Week.

Curran said it became apparent that a repurposing of futures was necessary in July, when the early expiration of tax incentives became clear.

“We’re putting a lot of eggs in the gas development basket,” Clean Grid Alliance’s Beth Soholt said in response to MISO’s remarks, asking whether the RTO would factor in pipeline capacity issues and fuel availability limits.

Curran said MISO would try to capture the fuel availability associated with “explosion” in gas development and pipeline constraints in the resource’s capacity accreditation.

IESO Ups Capacity Target for Long Lead-Time Resources

IESO has increased the capacity target for its planned solicitation for long lead-time (LLT) resources, even as it acknowledges questions about the need for the procurement. 

The ISO plans to seek 600 to 800 MW of capacity from resources requiring at least five years of lead time, up from its proposed 600 MW, “to recognize the volume of system needs arising in 2035,” officials told stakeholders at an engagement session Sept. 16. The energy target will be up to 1 TWh, unchanged from what the ISO outlined at its June 5 engagement. 

IESO decided to pursue a separate LLT procurement in response to stakeholder feedback that energy storage resources such as compressed air and pumped hydro require longer planning cycles than the four-year lead times for resources offering in the pending Long Term 2 (LT2) procurement. Energy proposals for LT2 are due Oct. 16, and capacity proposals are due Dec. 18. (See IESO Officials Deny Favoring Gas Resources in Upcoming Procurement.) 

The ISO issued a request for information last fall to guide its design of the LLT solicitation and summarized its findings in an Aug. 29 report to the Ministry of Energy and Mines. 

Requirements

To participate in the LLT procurement, resources must require a lead time of five or more years and have an operating life of 40 years, versus 20 years in LT2.  

Technologies for which IESO is less familiar — such as emerging long duration energy storage (LDES) — may need to prove they meet the lead-time requirement with an independent engineer report detailing the project scope, permitting path and supply chain constraints. 

Although the LLT RFP is intended for new resources, IESO is considering including hydropower redevelopment projects — large-scale replacements of existing equipment that IESO said “would be similar in scope to a new build facility.” 

“Following redevelopment, the expected operational life of the facility would be comparable to that of a newly constructed facility,” the ISO said. 

Reservoir hydro projects (those with storage capability that are not pumped hydro) will be eligible to participate in the energy stream only because they would be unable to offer full contract capacity between 7 a.m. and 11 p.m. on business days, as required for capacity resources. 

Pumped storage and other LDES resources will be eligible to submit in the capacity stream only. 

IESO plans an engagement in October to discuss hydro repowering, expansions and upgrades of hydro and other resource types in its procurements. 

Questioning the Need for LLT Procurement

Jonathan Cheszes, president of Compass Greenfield Development, questioned the need for the LLT solicitation, saying the eight- to 12-hour requirement for capacity resources is “functionally consistent” with that in the LT2 capacity procurement.  

“If you need eight to 12 hours of capacity, then why not ask for eight to 12 hours of capacity? … Why limit what technologies can participate?” he asked. 

IESO’s Ben Weir said the LLT RFP is an effort to procure resources with attributes — such as a 40-year life span — that can’t compete in LT2.  

“There’s not much point in signing a 40-year contract with a battery, because it’s not going to last 40 years … the way we intend to use it,” Weir said. 

Cheszes suggested the LLT procurement was premature.  

“If you’re going to get eight to 12 hours out of LT2 … maybe see what the pricing comes in at before” seeking a solicitation for LLT resources, he said. 

“You raise an absolutely valid concern,” responded Dave Barreca, IESO’s supervisor of resource acquisition. “Please believe me that this is top of mind for us. … We are thinking very hard about ratepayer value and prices and how to manage that for this RFP, given that … the field of competition is quite narrow.” 

IESO’s proposed solicitation for long lead-time resources would include long duration energy storage technologies such as compressed air energy storage. | Pacific Northwest National Laboratory

“Forty years [is] a long time,” Cheszes responded. “Just imagine what batteries are going to cost 20 years from now. … And whatever [the] technology [will be, it] won’t be lithium ion, right? It’ll be something totally different. So, you know, locking in 40 years — there’s some pluses, but there’s a bunch of minuses as well.” 

Weir said ISO officials will hold engagements monthly for the rest of 2025 to develop the RFP, with proposals expected in the fourth quarter of 2026 and contract awards in the first half of 2027. The timing of the RFP and the target sizes will be finalized after receiving guidance from the ministry, Weir said. 

Weir said IESO may accept a percentage of all proposals submitted — perhaps 80% — similar to what the ISO did in its second medium-term solicitation (MT2). (See IESO Purchasing 3,000 MW of Energy and Capacity.) 

“This is just a way to maintain competitive tension if the numbers of proposals received are lower than we expect,” he said. 

Rated Criteria

IESO is seeking more information on potential projects in prime agricultural areas (PAAs) to inform how it sets its rated criteria” — non-price factors used to evaluate proposals — for the procurement.  

Some stakeholders said the ISO should not use rated criteria based on locations, such as for proposals located in northern regions or outside of PAAs. 

IESO said its criteria will “be reflective of policy decisions made by the Ministry of Energy and Mines.” 

The ministry also will weigh in on whether IESO should offer price incentives — in addition to rated criteria points — for projects involving Indigenous communities. 

Round Trip Efficiency

IESO is considering minimum round-trip efficiencies (RTEs) — and incentives for exceeding them — because LDES are expected to have lower RTEs than battery storage.  

Barreca said resources considering participating in the LLT RFP have offered a wide range of RTEs with a “middle” of about 60%. That “is quite different than what we’ve seen … in the lithium-ion batteries that we’ve procured” in the first long-term procurement, he said. 

Outages

The ISO plans to use the same rules for planned outages as under LT2. Energy resources should incorporate planned outages into their imputed production factors to avoid non-performance charges. Capacity resources will be permitted a planned outage of up to one month during April, May, October or November. 

Resources will be permitted one long-term outage — a maximum of six months — during the second half of their contracts. 

Environmental Attributes

IESO is considering allowing suppliers to retain the proceeds from sales of “environmental attributes” during the first 20 years of the contract, with the supplier sharing the attributes with IESO in the second 20 years. 

Although suppliers are unlikely to place much value on the attributes for 2051-2070, Barreca said, “there is a good chance that there will be some value there” that could be recovered for ratepayers. 

“We are certainly open to the alternative, which is that you do have forecasts for what those are going to be worth, and you are willing to put those values into your proposal prices,” he added. 

Defining LDES

Open-loop pumped storage hydropower systems connect a reservoir to naturally flowing water via a tunnel, using a pump to move water to higher elevations and a generator to create electricity. | DOE

In addition to inviting participation by compressed air energy storage and pumped hydro storage, IESO will consider emerging technologies such as liquid air energy storage and compressed gas “that are able to demonstrate a sufficient level of technology readiness.” 

Stakeholders told IESO it should clarify its definition of commercially proven LDES technologies and allow participation from LDES technologies with a technology readiness level of eight or higher, indicating it is ready to move from development to commercialization, per the U.S. Department of Energy. 

Although some stakeholders pushed IESO to increase the minimum duration requirement to 10 or 12 hours, the ISO said it expects participating LDES resources “to be in the eight- to 12-hour duration range, which can realize the most reliability benefits at this time.” 

Barreca said IESO’s planning team is conducting research to understand the value of increasing the minimum duration. 

“We’ll need to make a call in terms of whether we think the extra value would be worth the extra price to make that a minimum requirement,” he said. “There is more study required to go to the 24-hour or … multiday storage. That will be a different procurement.” 

Non-performance Charges

The ISO rejected requests that non-performance charges for energy producing resources be based on a five-year rolling average versus the three-year average used in LT2. The three-year average “allows for effective accounting of anomalies that may impact production, such as irregular weather patterns,” IESO said.  

Barreca said the ISO is sticking to a three-year average “primarily because this is a competitive RFP, not a standard offer program, and there are quite a number of variables that a proponent has to work with to find their optimal risk profile.” 

Price Escalation

IESO still is determining how it will escalate prices during the contract term. 

Some potential suppliers said IESO should provide 100% inflation indexing from the contract date to the commercial operation date (COD) — similar to that in the LT2 RFP — and 60% indexing from COD until the contract end date. 

Barreca said the 100% indexing in LT2 “was a direct response to the geopolitical environment at the time.” 

“We have a little bit of runway ahead of us to see what happens there,” he added. “I think we are going to wait just a little bit longer and see how the world evolves between now and then.” 

Stakeholder Forum: Surplus Interconnection Can Maximize Capacity in ISO-NE

By Alex Lawton

We all appreciate the idea of squeezing out every last drop and making the most out of what you have. Our power grid should be no exception.

Yet in New England, rules governing how new resources connect to the regional grid limit full use of our system’s potential. Precious “surplus” capacity can and should be leveraged to interconnect new, low-cost clean energy technologies to deliver more reliable, affordable power.

Capacity surplus interconnection service (SIS) is a solution hiding in plain sight that would allow the region to harness more capacity resources. At its core, reforming capacity SIS is about optimizing every megawatt of deliverability at each point of generator interconnection.

Throughout the system, there often is a discrepancy between how much capacity a generator is allowed to offer to the grid (i.e. an interconnection service limitation) versus how much they’ve committed to actually offer via the capacity market, i.e., the “capacity surplus.”

Alex Lawton

Optimizing SIS could solve several problems for grid operators and policymakers amidst soaring electricity costs, rising demand, shifts in the resource mix and heightened emphasis on grid reliability. A reformed capacity SIS option would allow new capacity resources to interconnect to the system in a fraction of the time and at much lower cost, which has significant benefits for consumer bills. Interconnection historically has been protracted, expensive and risky for new generation and storage projects, adding to the cost to develop projects that customers pay for through rates.

SIS circumvents these problems because it allows new capacity resources to bypass long and expensive reliability studies if they are willing to respect the existing capacity limitations at the point of interconnection. Respecting these limits also ensures these new resources avoid costly system upgrades.

This more efficient path to connect to the grid will lower development costs and benefit ratepayers through bringing more capacity resources online faster to balance supply and demand. More capacity also supports resource adequacy and improves system reliability, keeping the lights on.

Other regions already have revitalized their capacity SIS rules to capitalize on these benefits. For instance, surplus reforms in MISO allow greater flexibility and speed for generators requesting surplus whilst ensuring that interconnection limitations are respected. As a result, MISO’s surplus process has garnered 3.6 GW of surplus service requests since 2021.

While capacity SIS technically is available in New England, outdated rules make it practically unusable for generators and prevent the region from harnessing capacity SIS opportunities. These barriers can be addressed with relatively modest revisions.

The first core issue is a restrictive condition that capacity resources must be “continuously available” on a permanent basis, which is impractical because it locks in a fixed quantity of surplus when in fact surplus availability constantly ebbs and flows based on performance audits as well as capacity accreditation. The fix: allow surplus resources the option for dynamic, periodic service.

Correcting capacity SIS deficiencies is timely specifically because of how it relates to capacity accreditation. ISO-NE is undertaking a major overhaul of its capacity market, including transitioning to a prompt and seasonal market and adopting a probabilistic approach to accredit resources based on their marginal value.

This new approach to capacity accreditation means accredited values may change significantly over time. As more renewables and advanced energy technologies enter the market, and as legacy plants receive derates for their imperfect performances during extreme weather events, accreditation values for many resources will drop. The key implication is that over time, the less capacity each generator can actually commit via their accredited limit, the more surplus headroom will open since the interconnection service limit — what generators are allowed to offer — stays the same. Ensuring capacity SIS rules are tied to accreditation reforms therefore will allow maximum use of surplus capacity on a continuous basis as accreditation values evolve.

The second core issue for surplus concerns what happens if an original generator retires, leaving just a surplus unit at the point of interconnection. Instead of allowing the surplus unit to maintain the interconnection limitation that applied to the original generator, which would enable the surplus unit to scale to that size, and avoid interconnection pitfalls, surplus units must go to the back of the line in the interconnection queue, with few exceptions.

Given the rising trend in generator retirements, a streamlined repowering process that allows surplus units to take over the interconnection rights in full and quickly begin injecting power into the grid could prove critical to maintaining electric system reliability.

In New England alone, the grid has the potential to unlock roughly 35 GW of new resources via surplus service — an amount higher than our region’s all-time peak demand. While that may be a high-end estimate, consider that according to the ISO’s 2025 CELT Report, there already is roughly 3 GW of capacity headroom on the system during winter time.

Once capacity accreditation reforms take effect in 2028, if results are similar to the previous impact analysis, approximately seven additional gigawatts suddenly could become available for the capacity commitment period in 2028.

Timing capacity SIS reforms now would dovetail with ongoing market reforms and address the urgent need for efficient new capacity resource entry. Recognizing this, industry stakeholders in New England have pushed capacity SIS reforms as a top priority for 2026.

This is a great opportunity for ISO-NE to follow through on the commitment it made in its FERC Order 2023 filing transmittal letter, promising to advance discussions on further interconnection reforms and measures that accelerate timelines.

The onus is on the ISO to undertake the initiative, gather stakeholder perspectives, and update its governing documents accordingly. If the ISO pursues these changes, New England’s grid has the opportunity to squeeze every last drop of surplus capacity to make the most out of our existing grid.

Alex Lawton is the wholesale markets director at Advanced Energy United.

Six Reports Paint Picture of Slowing Energy Transition

Several new reports and updates give snapshots and predictions about the changing direction of the U.S. energy sector. 

Some of the organizations behind the updates identify as neutral and nonpartisan, but others are openly critical of the shift that began when Americans chose Donald Trump and his “Drill Baby Drill” message at the polls nearly a year ago. 

But while the reports each have a different focus and tone, all reach similar conclusions: Major changes are afoot, and they will have significant effects. 

    • After four years grading the top U.S. utilities at a collective D in its annual “Dirty Truth Report,” the Sierra Club gives them an F in its 2025 edition for delivering dirtier power at a higher cost. 
    • Rhodium Group in its annual “Taking Stock” report estimates the U.S. energy sector’s 2035 greenhouse gas emissions will be 26 to 35% lower than in 2005; only a year ago, Rhodium estimated a 38 to 56% reduction over the same period. 
    • The U.S. Energy Information Administration calculates that energy-related per-capita carbon dioxide emissions decreased in every state from 2005 to 2023 — 30%, on average — but forecasts a 1% increase in total U.S. CO2 emissions in 2025 due to increased fossil fuel consumption. 
    • In its latest update, Climate Action Tracker downgrades its rating for the U.S. from “insufficient” to “critically insufficient” due to the “most significant rollback of policies” it has ever analyzed. 
    • E2 reports in “Clean Jobs America 2025” that employment in the clean energy economy grew 17% from 2020 to 2024, far outstripping the rest of the energy industry and the U.S. economy as a whole, but says policy changes threaten future growth. 
    • The “2025 Production Gap Report” by Stockholm Environment Institute, Climate Analytics and International Institute for Sustainable Development looks at 20 countries and finds widespread plans to increase fossil fuel production. But it reserves a particularly blunt assessment for the world’s largest oil and gas producer: “The United States offers the starkest case of a country recommitting to fossil fuels, with plans to scale up its oil and gas production, arrest the decline of coal, slow clean energy development and electrification, and turn away from international cooperation on energy and climate change.” 

Details and Conclusions

The Sierra Club’s goals are lofty indeed — 100% coal retirement by 2030, 100% clean energy by 2035 and zero MW of new gas capacity planned by 2035. 

It said the utilities it studied had committed to only 29% on coal and 32% on renewables and are planning 118 GW of new gas, all while mounting a greenwashing campaign and raising rates faster than inflation. 

The Sierra Club faults the U.S. utility sector for planning to add 118 GW of new gas-fired power generation through 2035, a 20% increase in gas capacity. | Sierra Club

The Sierra Club gave out a handful of B’s in the 2025 edition of the “Dirty Truth Report” — Orlando Utilities Commission, Xcel Energy and Consumers Energy were ranked highest at 73, 69 and 65% — but together, the 75 utilities had an aggregate score of 15%, the lowest since the first edition of the report, in 2021. 

Sierra Club asserts that despite the dual pressures of load growth and vanishing federal support for clean energy, utilities must accelerate their decarbonization, not slow it down. 

In “Taking Stock 2025,” Rhodium prefaces its prediction of slower progress on greenhouse gas reductions with the root cause: 

“The first seven months of the second Trump administration and 119th Congress have seen the most abrupt shift in energy and climate policy in recent memory. After the Biden administration adopted meaningful policies to drive decarbonization, Congress and the White House are now enacting a policy regime that is openly hostile to wind, solar and electric vehicles and seeks to promote increased fossil fuel production and use.” 

Rhodium Group has modeled a series of scenarios for U.S. greenhouse gas emissions that vary based on fossil fuel prices, economic growth, clean energy technology and LNG export capacity. | Rhodium Group

Rhodium predicts that the rate of decline of GHG emissions will slow but does not attempt an exact prediction because so many variables are in play — fossil fuel prices, the growth of the U.S. economy, the cost of clean energy technology and the growth in U.S. LNG export capacity. 

There also is an “incredibly dynamic” policy environment, continued demand for clean technologies and persistent non-cost barriers to renewables, it adds. 

Rhodium assumes the 31 regulatory policies EPA Administrator Lee Zeldin has targeted for “reconsideration” will be removed. 

The EIA said the sharp reduction in energy-related CO2 emission reductions so far this century can be attributed primarily to reduced combustion of coal for power generation; increased use of natural gas, which burns cleaner; and the rise of emissions-free wind and solar generation. 

U.S. energy-related CO2 emissions dropped 20% from 2005 to 2023 while the population grew 14%, a 30% per-capita decrease.  

In 2016, transportation surpassed electric power as the largest energy-related CO2 source in the U.S., EIA said. 

The U.S. Energy Information Administration reports that every state reduced its carbon dioxide emissions between 2005 and 2023, with an average decrease of 30%. | EIA

The Climate Action Tracker (CAT) rated 40 countries and found none had policies in place to meet the goals of the 2015 Paris Agreement. Eight nations are “almost sufficient”; the U.S. and nine others are “critically insufficient”; and the other 23 fall in between. 

“The Trump administration is pursuing an agenda to systematically repeal federal climate targets, policies and funding for climate change mitigation, blocking progressive actors,” the report said, “while encouraging the production and consumption of fossil fuels at home and abroad, completely reversing the previous administrations’ course on climate action.” 

Pro-climate policies continue in some U.S. states, but the nation as a whole has stepped away from net-zero aspirations, CAT said. 

“It is shocking how rapidly and how systematically the Trump administration has moved to roll back efforts to reduce greenhouse gas emissions, while aggressively expanding support for the production and consumption of fossil fuels, in defiance of clear market signals,” said the assessment’s lead author, Finn Hossfeld of the NewClimate Institute. 

E2 tallied more than 3.5 million workers in 50 states in its 10th annual analysis of U.S. clean energy employment, 522,000 of them in jobs created since 2020. It said 82% of net new energy sector jobs in 2024 were in clean energy. 

“This trend was expected to continue as clean energy accounted for larger and larger shares of energy industry jobs and the nationwide workforce,” the authors wrote. “But recent policy decisions to revoke incentives, cancel permits, and target the industry with new red tape and legal hurdles threatens future growth and, increasingly, the health of the U.S. economy at large.” 

E2 offered no specific job-loss predictions of its own but said $22 billion worth of projects and factories have been canceled at a cost of 16,500 jobs, and it said other organizations have predicted more than 830,000 jobs economywide could be lost by 2030 due to U.S. energy policy changes. 

“Clean Jobs America 2025” runs 42 pages, most of them filled with geographic- and industry-specific data drawn from the U.S. Bureau of Labor Statistics via the U.S. Department of Energy’s 2025 U.S. Energy and Employment Report. 

Derik Broekhoff, coordinating lead author of “2025 Production Gap Report,” said: “As our report makes clear, while many countries have committed to a clean energy transition, many others appear to be stuck using a fossil-fuel-dependent playbook, planning even more production than they were two years ago.” 

The 2025 report finds that governments worldwide plan to produce a 120% greater volume of fossil fuels in 2030 than would be consistent with limiting global warming to 1.5 degrees Celsius, the target specified in the Paris Agreement. 

But this last point is a bit academic for the U.S.: Trump withdrew the nation from the Paris Agreement early in his first term and withdrew it again on the first day of his second term. 

None of the new reports and updates, whether critical or merely analytical, seem to have made any impact on the driving force behind the U.S. energy policy shifts that are influencing the data in those reports. 

Speaking before the United Nations General Assembly on Sept. 23, Trump called climate change “the greatest con job ever perpetrated on the world,” provoking grumbles and murmurs from his audience. 

“If you don’t get away from the green energy scam, your country is going to fail,” he said. 

SPP Considers Deferring 765-kV NTCs to 2026

SPP says accelerating load projections will result in a 2025 transmission plan that dwarfs the previous year’s record $7.65 billion portfolio — so much so that it is considering deferring some projects until 2026. 

Staff said during a Sept. 23 education session on the 2025 Integrated Transmission Planning assessment that they may recommend delaying construction permits for five 765-kV projects, totaling more than $5 billion in building costs, to the 2026 ITP. 

Having only received approval for its first 765-kV project in February 2025, Southwestern Public Service’s 354-mile transmission line crossing the New Mexico-Texas border, SPP staff have experienced firsthand the vagaries of the facilities’ high costs. 

The project initially was projected to cost $1.69 billion. SPS revised the estimate to $3.62 billion in June. It took several months and more meetings and discussions with stakeholders before the Board of Directors eventually approved the revised cost estimate in September. (See SPP Board Approves 765-kV Project’s Increased Cost.) 

“We realize that these projects are very costly … we do expect to continue to show some additional cost sensitivities,” transmission-planning manager Kirk Hall said during the Markets and Operations Policy Committee’s education session. “We’ve talked a lot about the costs of the portfolio and obviously, affordability is top of mind. We’ve heard that loud and clear from stakeholders. We realize this is a significant investment.” 

“You can add as many projects as you want, and you are going to get some benefit, but at some point, that amount of reliability is not affordable to customers,” Oklahoma Gas & Electric’s Brad Cochran said, referring to the discussions over the SPS project. “You guys did a good job of putting some deferrals in there, but we need to make sure that not only [are we] making the system reliable, but we’re making it affordable so that customers can actually pay their bills.” 

SPP said the draft portfolio costs $19.1 billion but provides about $80 billion in benefits, a benefit-cost ratio of between 5.8 and 9.5. That doesn’t include reliability benefits or the cost of outages. 

Having identified the need for 765-kV transmission in the 2024 ITP, staff developed the EHV overlay and shared it with the board, state regulators and members in September. (See SPP, Members Developing 765-kV Transmission Overlay Plan.) 

Hall said staff will vet their deferral recommendation with the Transmission and Economic Studies working groups before MOPC’s October meeting. 

SPP told the committee that the 2025 portfolio is the result “of our most comprehensive ITP process in history.” Staff began with more than $20 billion in projects identified to meet all needs. It may end up with between $14 billion and $18 billion in projects that are issued notifications to construct, more than double the 2024 portfolio. 

Casey Cathey, SPP’s vice president of transmission, said the hefty portfolio is necessary. He recalled a time less than 10 years ago, when SPP was “excited” by 1.2% load growth year over year.  

“We’re seeing more than double that today, and we’re seeing a lot higher, accelerated growth in the future,” he said.  

Cathey told MOPC that the 10-year firm load projections for 2033 that drove the record 2024 portfolio are expected to occur six years earlier in the latest forecasts. He pointed to voltage and transfer issues the grid operator faces, three load sheds in 2025, three winter peaks in the past five years and load-responsible entities forecasting new large loads that will require more transfer capacity: “We currently peak at 56 GW, and adding the amount of load that we have on the horizon … is, quite frankly, breaking the system. We will need to build transmission. Generation alone cannot solve our challenges.” 

The RTO expects future loads to increase. Staff referenced President Donald Trump’s executive order to “pursue bold, large-scale industrial plans” that “vault” the U.S. “further into the lead” on critical manufacturing processes and the Department of Energy’s Speed to Power initiative 

According to the DOE, data centers used 58 TWh in 2014. That number increased to 176 TWh in 2023, 4% of all U.S. electricity. By 2028, the agency expects data centers to need between 325 and 580 TWh, which would be 6 to 12% of the nation’s annual energy. 

Data centers account for 23% of SPP’s large loads in the ITP (2.5 GW of 11 GW), but oil and gas electrification in the Permian Basin and the Dakotas is responsible for double that. Combined, projected large loads are equivalent to 20% of the grid operator’s current peak. 

“There is heavy pressure to ensure that we’re not only reassuring critical manufacturing but also doing what we can to provide bold infrastructure plans for large loads,” Cathey said. “We’re looking at this and seeing what opportunities we might have as we continue to plan the system out, not only for 765 kV but, just ultimately, the overall transmission infrastructure that we need.” 

The grid operator plans to release the ITP draft report Sept. 24.