SPP stakeholders have rejected a proposed tariff revision (RR687) that would help the grid operator connect generation more quickly.
Staff said the change would improve the definitive integration system impact study (DISIS) process by modifying the RTO’s dispatch method to ensure the added generation’s reliability and also lower exports to a realistic level. The proposal failed with only 36% of the vote during the Markets and Operations Policy Committee’s June 30 virtual special meeting.
Natasha Henderson, SPP’s senior director of grid asset use, said during a June 26 education session that the large amount of generation in the queue, combined with the dispatch method, is causing unrealistic generation exports. That assigns noncommercial viable upgrades to generators.
The 2023 DISIS includes 28 GW of capacity from 127 projects, about half of which are wind and solar resources. Like all SPP study clusters, staff analyze them in five groups: North, Nebraska, Central, Southeast and Southwest.
Henderson said SPP is seeing dropout rates between 67 and 100% in the study clusters that are causing further downstream issues.
“What happened in the 2022 DISIS is after all of this generation dropped out, $22 billion of associated upgrades also went away,” she said. “So, when we finish the 2023 DISIS Phase 2, it’s likely those generators are now going to see that same $22 billion of upgrades assigned to them. The proposed dispatch changes will mitigate that. It will not completely eliminate it, but it will help a little bit.”
Oklahoma Gas & Electric’s Adam Snapp, a member of the Transmission Working Group (TWG), cautioned against the proposal, saying no one knows the full effect the modified dispatch will have on the 2023 DISIS. The TWG twice rejected RR687 in June, 0-13 with five abstentions, and 6-14 with three abstentions.
“There are still a large number of resources that are in the 2023 queue that are benefiting from billions of dollars of upgrades that are currently assigned to the 2022 cluster,” Snapp said. “Once those 2022 cluster resources withdraw, those costs will shift to the 2023 resources that will trigger a lot of resource withdrawals from the 2023 cluster. What we’re effectively doing here is asking the policy to overrule TWG on a very technical matter without understanding the whole impact of … that decision.”
SPP had hoped to receive an expedited approval from MOPC so it could apply RR687 to the DISIS 2023 Phase 2 clusters that hadn’t been completed before July 1. That study will conclude before the committee’s regularly scheduled July 15-16 meeting.
“We do think that this needs to be ported over in future generation interconnection processes,” said SPP’s Casey Cathey, vice president of engineering.
The issue will be sent back to the TWG for further consideration and discussion. The group next meets July 29 in Kansas City.
FERC has denied a waiver request by MISO and SPP to make changes to the Coordinated System Plan (CSP) under their joint operating agreement, saying it is not the “appropriate vehicle” to improve the process.
The July 2 finding was made without prejudice, allowing the RTOs to submit proposed revisions to their CSP in a future Section 205 filing under the Federal Power Act (ER25-943).
The grid operators filed the request in January, asking the commission to allow them to incorporate multiple scenarios in a single 10-year model instead of the multiyear analysis required by their JOA. They also asked to use multiple benefit metrics to evaluate reliability and public policy interregional transmission projects rather than the agreement’s narrowly defined “cost avoidance of pre-existing regional projects.” (See MISO, SPP Ask FERC for JOA Waiver to Conduct More Meticulous Interregional Study.)
MISO and SPP contended that previous CSP studies were unsuccessful in “developing solutions where both RTOs benefit” and “have not yielded any interregional projects” for more than a decade.
FERC said the request did not meet the commission’s criteria for granting tariff waivers that: the applicant acted in good faith; the waiver is of limited scope; the waiver addresses a concrete problem; and the waiver does not harm third parties or have other undesirable consequences.
The commission found the request was not limited in scope because waiving a multiyear analysis “would appear to relieve them of a discrete tariff obligation.” It said waiving the RTOs’ tariff obligation to evaluate the benefits of reliability and public policy interregional projects as the avoided cost of regional projects that address the same reliability or public policy issue is “a significant change to the CSP study scope.”
FERC said the waiver request does not address a concrete problem because the grid operators did not show that expanding the study scope would address the problem they identified. “That is, the proposed expanded CSP study might not identify transmission solutions that meet [the RTOs’] selection criteria,” FERC said.
The commission said it was unpersuaded by the grid operators’ claim that their waiver request is consistent with FERC precedent granting “waivers modifying transmission planning study requirements and timelines and addressing inefficient market outcomes.” The commissioners said those proceedings involved waiver requests of tariff deadlines to allow the applicant additional time to comply with a tariff requirement, not to change the requirement outright.
Commissioner David Rosner dissented from the 2-1 vote. Commissioner Judy Chang did not participate.
Rosner said he believed MISO and SPP satisfied the commission’s waiver criteria. Noting the CSP study has not yielded a project in more than 10 years, he said the proposal to waive two JOA provisions related to technical planning assumptions will “better tailor the study to their regional needs, making it more likely to yield useful results.”
“The commission should not stand in the way of simple solutions that give MISO, SPP and their stakeholders flexibility to improve the accuracy of their study,” Rosner wrote. “The alternative compels MISO and SPP to commit resources towards an inefficient study and prevents the regions from identifying needed interregional transmission projects.”
“As the dissent rightfully points out, the CSP studies have not yielded any interregional transmission solutions for more than a decade,” Chair Mark Christie and Commissioner Lindsay See said. “In other words, the current situation is not a surprise to either MISO or SPP, and the circumstances that led to this situation are not outside of their control. While we appreciate MISO’s and SPP’s desire to improve their CSP process, a waiver request is not the appropriate vehicle to achieve such an outcome.”
The American Council on Renewable Energy (ACORE) and International Transmission Co. filed comments supporting the MISO-SPP application. They said the waiver request would have yielded an expanded CSP study that would identify interregional projects that benefit both the MISO and SPP regions and would support a more reliable and efficient transmission system.
Even in its nonbinding phase, the Western Power Pool’s Western Resource Adequacy Program (WRAP) has been a valuable tool for working toward resource adequacy goals, program participants said.
“We are really finding that the nonbinding phase is increasing our likelihood of success in the future,” said Camille Christen, resource acquisition, planning and coordination manager at Idaho Power.
Christen’s comments came during an Oregon Public Utility Commission summer readiness workshop June 24 in which WRAP was one topic of discussion.
Idaho Power’s WRAP capacity requirement, which consists of a load forecast plus planning reserve margin, was about 4,100 MW for summer 2025.
Idaho Power did not meet the forward-showing requirement, Christen said, despite its combination of existing and new resources and demand response programs. The utility is now working to resolve the deficiency.
Idaho Power fared better in meeting its internal 1-in-20 forecast of peak summer demand, which is about 4,000 MW. The utility has sufficient firm resources and contracts, including market purchases, to serve load. Idaho Power hit its all-time system peak of 3,793 MW in summer 2024.
Christen noted differences between Idaho Power’s internal modeling and the WRAP model, which is based on regional inputs. Assumptions also vary regarding resource contributions, and the timing of the two analyses differs.
WRAP’s nonbinding phase has provided transparency into regional planning and aggregated resource position, she said. Participants are also gaining experience on the operational side of the program.
In a separate presentation at the OPUC meeting, Dee Outama, senior director of power operation at Portland General Electric, said the utility has enough resources to meet an internal target: a 1-in-2 peak plus a 9% planning reserve margin and 3% contingency. PGE is also in compliance with WRAP metrics for the summer, he said.
In response to a request from RTO Insider, WPP declined to provide details on how many WRAP participants have been meeting forward-showing requirements during the nonbinding phase.
Binding Phase Penalties
Western Power Pool launched the WRAP in response to industry concerns about resource adequacy in the West.
Under the program’s forward-showing requirement, participants must demonstrate that they have secured their share of regional capacity needed for the upcoming season. Once WRAP enters its binding phase, participants with surplus must help those with a deficit in the hours of highest need.
The binding phase also includes penalties for participants that enter a binding season with capacity deficiencies compared with their forward showing of resources promised for that season.
In 2024, the binding phase was postponed by one year at the request of participants, who said they were facing challenges including supply chain issues, faster-than-expected load growth and extreme weather events that would make it difficult for them to secure enough resources and avoid penalties. The binding phase is now expected to start in summer 2027. (See WRAP Members Vote to Delay ‘Binding’ Phase to Summer 2027.)
“What’s fascinating about the challenges that the WRAP is facing in going binding is they sort of prove out that there is a reliability challenge — that in fact folks are short,” OPUC Chair Letha Tawney said during the meeting. “And it’s hard to dig out of that hole in a time frame in the face of all the other headwinds.”
The WRAP’s first nonbinding forward showing season was winter 2023/24; the program’s fifth forward showing, for winter 2025/26, is now underway.
And plenty is happening during the nonbinding phase, according to Michael O’Brien, WPP’s senior policy engagement manager for the WRAP, who gave a presentation during the OPUC meeting.
“[Participants] are giving data to SPP, the program operator,” O’Brien said. “They are going through the forward showing. They are being let know … where they are deficient in their planning.”
Building Consensus
Another WRAP participant that has found the program beneficial thus far is Arizona-based Salt River Project.
“SRP sees significant value in WRAP, as it has provided a regional forum to discuss resource adequacy in the West and how to best address the adequacy challenges posed by load growth and changes to the resource mix,” SRP spokesperson Jennifer Schuricht told RTO Insider.
In addition, WRAP has built consensus around a set of reliability metrics for the region, “which will be increasingly important as the resource mix changes,” Schuricht said in an email.
SRP is on track to fully meet WRAP forward-showing requirements when the program becomes binding, she said.
After it took Republican leadership most of the previous day cajoling its members, the House of Representatives on July 3 voted 218-214 to pass the Senate version of its budget reconciliation package, the One Big Beautiful Bill Act, just in time for President Donald Trump to sign it into law by his imposed deadline.
“The House has passed generational legislation that permanently lowers taxes for families and job creators, secures the border, unleashes American energy dominance, restores peace through strength, reduces spending more than any other bill has, and makes government more efficient and effective for all Americans,” Speaker Mike Johnson (R-La.) and other Republican leaders said in a joint statement.
The bill makes permanent tax cuts enacted during Trump’s first term and slashes federal funding, including on tax credits for renewable energy and other programs Democrats passed in the Inflation Reduction Act of 2022. (See related story, Senate Passes Trump’s Big Bill that Slashes Clean Energy Tax Credits.)
Republicans kept the voting open for hours to secure passage, which was delayed by a record-long speech on the floor by Minority Leader Hakeem Jeffries (D-N.Y.). The entire Democratic caucus voted against the bill, as well as two Republicans.
“Our House Republican colleagues, Mr. Speaker, have one last opportunity to join us … to stand up and protect the health care of the American people; stand up and protect the nutritional assistance of the American people; stand up and protect our farmers; stand up and protect our veterans; stand up and protect the clean energy economy; stand up to protect our public schools,” Jeffries said.
The clean energy provisions were highly criticized by trade groups representing developers and environmentalists, but the investor-owned utility trade group Edison Electric Institute said the bill had some benefits for its members, including lower corporate tax rates and interest deductibility, and supported some energy tax provisions.
“Our top priority is delivering affordable, reliable energy to hundreds of millions of Americans. We support the many provisions in the bill that help us achieve this goal and grow our economy,” EEI President Drew Maloney said in a statement. “We will continue to work with the administration and lawmakers to implement and develop policies to support energy infrastructure investment and keep customer bills as low as possible.”
Clean energy supporters said that with rising demand, the bill’s changes and cuts to tax credits for renewable resources will only raise prices for consumers.
“While the new policies are a step backward, the combination of surging demand for electric power and economic benefits of renewable energy technologies ensure that clean power will continue to play a significant and growing role in our nation’s energy mix,” American Clean Power Association CEO Jason Grumet said in a statement. “America’s electricity demand is projected to surge by as much as 50% by 2040. That growth requires every available source of reliable power, including the clean energy technologies that are the only shovel-ready sources of additional power and the low-cost option across much of the nation.”
While the two parties have now used reconciliation in recent years to enact major swings in clean energy funding, one area they have so far failed to move on is permitting reform, despite both sides of the aisle having support for the concept.
“Permitting reform can and should be a bipartisan focus for members in the coming weeks and months that remain in this Congress,” Americans for a Clean Energy Grid Executive Director Christina Hayes said in a statement. “America’s transmission grid is at a crossroads. No matter your politics, the reality is clear: Demand for electricity is rising. Whether that power comes from natural gas, coal, nuclear, wind or solar, none of it will reach homes, businesses or data centers without a modern, reliable and expanded transmission network. As technology advances, we must ensure our grid can keep up — or risk losing America’s dominance in the global competition for advanced manufacturing and artificial intelligence.”
The Clean Energy Buyers Association represents many of the big tech firms behind the surge in data centers and other large energy users whose total demand is bigger than any U.S. state. CEO Rich Powell saw mixed results in the bill and seconded the call for “fundamental reforms to our national permitting system.”
“We regret that the tax credits for solar and wind are being sunset at a difficult time when we need all energy options to support unprecedented electricity growth in America,” Powell said. “We do acknowledge and appreciate the work of President Trump and Congress in expanding the critical policies needed for clean firm energy, such as nuclear, batteries and geothermal, to support the next generation of carbon emissions-free energy resources. America’s energy dominance depends on our ability to lead in the technologies of the future and to continue to invest in all forms of clean energy.”
The Business Council for Sustainable Energy said the bill will hold the U.S. energy industry back, though renewables and efficiency should continue to grow in spite of it.
“Compared to earlier proposals, the final legislation provides a more workable transition for some energy businesses currently utilizing federal energy tax credits,” BCSE President Lisa Jacobson said in a statement. “However, it imposes many rapid changes to various energy credits that will cause uncertainty and increase energy costs. These provisions include consumer credits for energy efficiency and clean energy that help lower energy costs for families and businesses, make the grid more resilient, protect good American jobs and provide certainty for vital investments in the energy sector.”
NERC is calling on industry to help the ERO identify the top security risks facing the North American electric grid in a new survey, while also providing guidance for newly registered owners of inverter-based resources ahead of next year’s deadline.
The survey provides participants with a list of 34 emerging physical and cybersecurity risks, to be ranked according to “their likelihood of occurrence and potential impact on [grid] reliability.” Topics included in the list range from broad issues such as supply chain, ransomware and malware attacks, and physical attacks on infrastructure, to more focused areas like targeting of distributed energy resource aggregator control systems, targeting of artificial intelligence tools and capabilities, compromising of metering infrastructure, weaponization of drones and unusable data backups.
To prevent confusion among stakeholders, NERC also provided a supplemental information document outlining the risk statement and one or more hypothetical risk scenarios for each risk. The survey form also includes spaces for comments on the risk ranking and security risks not included on the list, along with their ranking.
Survey responses are due by July 22. NERC said in an announcement it would “assess responses from the survey participants and use the collected insights in further developing” the CIP road map. The ERO then will develop a report with an overview of the risks prioritized in the survey, current applicable CIP standards, ongoing risk mitigation activities addressing each risk and recommendations for addressing identified gaps.
IBR Materials Posted
The ERO’s IBR registration guidance, comprising two infographics also released July 2, are aimed at owners of IBRs that will need to be registered with NERC by May 2026. The deadline is based on the work plan approved by FERC in May 2023, which laid out a three-year process for registering IBRs that were not previously required to register but that are connected to the grid and, “in the aggregate, have a material impact” on reliable operation.
Earlier in 2025, NERC told FERC it estimated there were 863 IBRs whose owners will need to be registered under the new classification “Category 2 generator owners.” This includes entities that own or maintain IBRs that “either have or contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.”
NERC prepared one infographic for GOs that already are registered with the ERO and will need to update their registration to include relevant facilities, and another for entities that are new to the ERO Enterprise. For the latter, NERC included explanations of the ERO and its mission, along with a brief outline of the registration process.
The release of the new infographics is part of the third and final step of the IBR registration initiative, which NERC called an effort to welcome new participants into the ERO Enterprise.” NERC and the regional entities have events planned to further assist entities with the transition.
IESO plans to introduce its first electricity demand-side management (eDSM) program in 2026, focused on commercial HVAC systems during summer to lower peak demand as load grows in Ontario.
“HVAC loads in the commercial sector presents a significant opportunity for demand response,” the ISO said in a presentation to stakeholders June 24. “Large commercial buildings, including offices, retail spaces and institutional facilities, account for a substantial portion of Ontario’s peak demand, largely driven by HVAC loads during summer cooling season.”
The ISO has numerous energy efficiency programs that mostly are focused on retrofitting buildings, collectively known as Save on Energy. It also allows DR resources to participate in its capacity market. The new program would be part of Save on Energy, and any aggregated loads participating would be barred from bidding into the market.
That’s because capacity resources are expected to perform for at least half the year. (The “summer” half of the capacity year is defined as May 1 to Oct. 31.) However, certain large commercial facilities have capacity value only during the height of summer. The ISO is targeting 100 MW of curtailment in 2026 and 230 MW in 2027 from “resources” such as large retailers, office buildings, shopping centers, universities and municipal premises.
IESO plans to begin registering participants at the beginning of 2026 with a goal of beginning operation June 1 and running until Sept. 30. DR events would last up to three hours on business days only. Participants would be compensated by the end of the year based on the average megawatts curtailed and capacity prices for those four months.
The program is part of a larger eDSM framework funded through Ontario’s Affordable Energy Act of 2024, which granted IESO $10.9 billion for the new program as well as expanding existing Save on Energy programs. As part of the initiative, the ISO also is considering programs to support distributed energy resource installation and additional incentives for new energy-efficient buildings.
IESO has allocated $1.8 billion for the first three years of the framework with goals of 900 MW in peak demand savings and 4.6 TWh in electricity savings.
The ISO used the June 24 presentation to go over aspects of the commercial DR program on which it is seeking feedback from stakeholders. IESO’s Mohammed Yousif highlighted the ISO’s proposed incentive structure: the summer capacity price ($/MW-day) multiplied by 92 (representing the 23 business days in each of the four months), with the resulting figure multiplied by the average demand reduction.
A stakeholder representing the University of Western Ontario, which participates in the capacity market as part of an aggregation, asked how compensation through the program would compare. Noting that “the HVAC program is not meant to compete with the capacity auction,” Yousif said, “I think what we are leaning towards is … for the [program’s] price to be aligned with the [auction] clearing price, but not more.”
Another stakeholder asked why the program was limited to HVAC. “I’m a bit confused … if the intention is to alleviate demand on the grid, why are we limiting it to HVAC loads when a lot of these buildings have good capabilities [such as] light dimming?”
Yousif answered that “there has been a lot of discussion” about widening the scope of the program after the first one or two years.
But others were not satisfied with this, with one saying, “It seems like you’re adding a lot of rules … for something that doesn’t really make any sense. You should just let people openly select their demand response technologies.”
Yousif urged attendees to submit this feedback in writing and again suggested the program could open to other technologies if the ISO sees enough potential.
Feedback is due July 8. IESO will provide its response July 29 and consult with potential aggregators and other commercial customers over August and September, with a goal of issuing rules for the program before the end of October.
The Nuclear Regulatory Commission has taken multiple steps to speed and smooth the path forward for the U.S. nuclear power industry.
In two weeks, the NRC announced it has:
changed policies to accommodate factory-built microreactors;
reduced the hourly rate charged to advanced nuclear reactor applicants and pre-applicants;
accelerated its review of a construction permit for an advanced reactor planned in Wyoming; and
finalized a rule extending design certifications from 15 to 40 years.
NRC also extended the expiration date of the operating license of a South Carolina nuclear reactor from 2042 to 2062, giving it a potential 80-year lifespan.
President Donald Trump on May 23 issued a series of orders intended to ease and expedite development of new nuclear power generation. Among these was a strongly worded directive for reform of the NRC, its structure, its personnel, its regulations and its basic operations.
On July 2, NRC published the design certification (DC) rule in the Federal Register. It is using the direct final rule procedure because it considers the action to be non-controversial. The rule will take effect Sept. 15 unless “significant adverse comments” are received by Aug. 1.
The change pertains to the five reactor DCs now in effect, as well as future DCs and renewals. The 15-year period dates to 1989; NRC said time has shown too little operating experience accumulates in 15 years for review at time of renewal. Extending the window to 40 years will allow this to happen, NRC wrote, adding, “it will reduce unnecessary burdens with no reduction in safety or security.”
Also on July 2, NRC said it had moved forward to no later than Dec. 31 its target date for completion of review of TerraPower’s construction permit request for its Kemmerer Power Station Unit 1.
TerraPower subsidiary US SFR Owner submitted the application in March 2024. Before adopting the “more aggressive schedule,” NRC had expected completion of its review no later than June 30, 2026.
The company seeks to build TerraPower’s Natrium design near an existing coal-fired power plant in Kemmerer, Wyo. The facility would be rated at 345 MW; an energy storage system would boost maximum temporary output to 500 MWe. If it is built, it will need an operating license through a separate NRC application procedure.
The 966-MW pressurized water reactor in Jenkinsville, S.C., first was licensed to operate from 1982 through 2022. In 2004, NRC approved a renewal to 2042. This latest renewal will extend its license through Aug. 6, 2062.
The Nuclear Energy Institute’s database indicates this is the furthest-reaching license of any U.S. reactor other than the brand-new Plant Vogtle Unit 4, whose initial 40-year license extends to July 28, 2063.
There is widespread interest in expanding the aging U.S. nuclear fleet, but given the high cost and long time frame of new construction, operators are keen to keep existing facilities in service, uprate their capacity and even bring retired units back online.
Dominion said July 1 it has been conducting upgrades at V.C. Summer to ensure its longevity, including the recent replacement of the main transformer.
On June 24, NRC amended the fees it will charge applicants and licensees for fiscal 2025, as required by the ADVANCE Act of 2025. The hourly rate will be reduced from $318 to $148 effective Oct. 1.
The NRC is required to recover as much of its operating budget through fees as possible. Its fiscal 2025 budget authority is $944.1 million; it expects to recover $205.4 million through service fees and $603.4 million through annual fees.
On June 18, NRC announced three policy decisions to expedite deployment of microreactors — reactors built, fueled and tested at a factory that would generate 1% or less of the output of a large plant such as V.C. Summer. Under the changes:
A factory-fabricated microreactor can be loaded with fuel at the factory under NRC license if it has features to prevent a nuclear chain reaction.
Also, such a reactor can be excluded from “in operation” status.
Finally, NRC staff can authorize testing of a microreactor at the factory before it is shipped to its operating site.
NRC said it had directed staff to continue other efforts focused on microreactors in compliance with the ADVANCE Act and the executive orders.
President Donald Trump has nominated four people to serve on the Tennessee Valley Authority’s board of directors.
The nine-member board is down to three members due to the Republican-controlled U.S. Senate’s failure to act on President Joe Biden’s three nominations in 2024 and Trump’s firing of three sitting members in the spring of 2025.
It has lacked a quorum for the past three months.
The July 1 announcement by the White House offered no details about the background of the four men, whose terms would extend to mid-2028, 2029 and 2030. News reports and official websites indicate:
Lee Beaman, of Tennessee, is a longtime Nashville businessman and Republican campaign donor.
Mitch Graves, of Tennessee, is CEO of the West Cancer Center & Research Institute and a Memphis Light, Gas and Water Board commissioner.
Jeff Hagood, of Tennessee, is a founding partner in the law firm that bears his name and a member of the Knoxville Sports Authority Board.
Randall Jones, of Alabama, is an insurance agent who chairs the boards of Jackson State University and the Electric Board of Guntersville.
The TVA board last had nine members earlier in Biden’s term.
Six Biden nominees were confirmed by the Senate in December 2022 and took their seats on the board in January 2023: Beth Geer, Bobby Klein, Michelle Moore, Bill Renick, Joe Ritch and Wade White.
Renick now is the board chair. His term expires in May 2027. Klein and White remain on the board, with terms expiring in May of 2026 and 2027, respectively.
Trump fired Moore on March 27, Ritch on April 1 and Geer on June 10.
The other vacancies were created by the expiring terms of three appointees from Trump’s first term: William Kilbride, Beth Harwell and Brian Noland. Biden nominated Harwell, Noland and Memphis City Council member Patrice Robinson to fill the vacancies, but the Senate did not bring the nominations to a vote.
Shortly before Trump began sacking board members, Tennessee’s U.S. senators — Marsha Blackburn (R) and Bill Hagerty (R) — authored an op-ed piece in POWER magazine saying the TVA board lacked the talent, experience and gravitas needed to carry the weight of the task before it: helping drive a nuclear renaissance led by the United States.
Work continues on the Tennessee Valley Authority’s new 1,450-MW Cumberland Combined Cycle Plant, targeted for completion in 2026. | TVA
They said the members appeared more like political operatives than visionary industrial leaders, called the TVA bureaucracy hidebound and suggested that retiring TVA CEO Jeff Lyash should be succeeded by an outsider.
Shortly after the op-ed was published, the TVA board announced March 31 it had chosen TVA Executive Vice President Don Moul as the new CEO. The next day, Trump sacked Ritchie, eliminating any potential quorum for the board.
Blackburn and Hagerty jointly praised the nominees July 1 after Trump announced them: “These nominees are a strong departure from the Biden-era TVA board which failed to meet the moment. We urge colleagues to swiftly confirm President Trump’s TVA board nominees to make certain the United States leads the world in next-generation nuclear and wins the global race for energy dominance.”
Hagerty separately added: “President Trump’s nominees must be confirmed quickly so they can get to work correcting the many errors and failed policies the Biden-era TVA board put into place.”
The nation’s largest public provider has no shortage of critics, including some who want it to move away from fossil and nuclear generation, not build more.
TVA recently added nearly 1,400 MW of gas-fired capacity in Kentucky and Alabama; is building or considering 5,500 MW of new dispatchable generation; and in May became the first U.S. utility to request a construction permit for a small modular reactor.
Missouri Attorney General Andrew Bailey says he has opened an investigation into Invenergy’s Grain Belt Express transmission project, an 800-mile, HVDC line spanning four states that has been under development since 2010.
Bailey told Invenergy in a June 27 filing that he “has reason to believe” Grain Belt’s developers have “used deception, fraud, false promise, misrepresentation, unfair practice or the concealment, suppression or omission of material fact in connection with its statements and actions” related to the project.
He sent a letter to the Public Service Commission on July 1 urging it to re-evaluate the project’s certificate of convenience and necessity by using its authority to “demand” updated long-term planning and revoke project approvals that are no longer in the public interest.
A PSC spokesperson told RTO Insider that the commission is reviewing the attorney general’s request and declined further comment.
Bailey said the Grain Belt application “relied on speculative and possibly fraudulent assumptions.” He said the developers’ calculations relied “significantly” on a carbon tax, pointing out that neither Missouri nor the U.S. government have carbon-reduction policies.
Andrew Bailey | Missouri Attorney General’s Office
“Grain Belt’s speculative and faulty calculations based on anticipated carbon tax has more than likely inflated demand for this project and dramatically overstated any resulting benefit to Missourians, directly undermining any claims of demonstrated need, economic feasibility and public interest,” Bailey said in the letter to the PSC.
“We’ve been absolutely transparent with everybody involved,” Michael Polsky, Invenergy’s founder and CEO, told The New York Times. “Whatever investigation they want, we will fully cooperate. We have nothing to hide. We’ve done everything above board.”
A Grain Belt spokesperson called the investigation a “last-ditch and obviously politically driven attempt to delay construction” of the project when “our country is facing a national energy emergency,” as declared by President Donald Trump. (See What is and isn’t in Trump’s National Energy Emergency Order.)
“We should be building energy infrastructure in America, but the Missouri attorney general is instead playing politics with U.S. power,” the spokesperson said in an email. “Electricity demand is rising across the country, and we urgently need transmission infrastructure to deliver power. Projects like Grain Belt Express are the answer to providing all forms of affordable and reliable electricity to U.S. consumers.”
U.S. Sen. Josh Hawley (R-Mo.) has also weighed in with a letter to the Department of Energy in June asking Secretary Chris Wright to terminate a $4.9 billion loan guarantee issued by the Loan Programs Office in 2024.
Hawley, who has called Grain Belt Express a “boondoggle,” noted the department is moving forward with the draft environmental impact statement, “a key step in approving the loan.”
Invenergy says the $11 billion project will provide $52 billion in energy cost savings over 15 years, create 5,500 American jobs and power up to 50 data centers. A 2022 economic analysis conducted for Invenergy found that the project would result in $20 billion in total investment and create more than 20,000 temporary jobs and more than 400 permanent jobs in Illinois, Kansas and Missouri.
Invenergy says Grain Belt, a merchant open-access line, will move about 5,000 MW of a “diverse mix of energy” from Kansas across Missouri and Illinois to Indiana. The project will deliver cost savings and strengthen reliability for 29 states and D.C. and more than 40% of Americans, it said.
The project would create links between the SPP, MISO, Associated Electric Cooperative Inc. and PJM grids.
Kansas, Missouri, Illinois and Indiana have all approved the project. The Missouri PSC found the project would save the state’s customers as much as $18 billion, Invenergy said, and noted municipal utilities in 39 communities have contracts with it for power delivery and contractually guaranteed cost savings.
The project has faced pushback from Missouri landowners, who are opposed to a for-profit private entity using eminent domain. Bailey has criticized Grain Belt for filing nearly 50 eminent domain lawsuits against Missouri landowners.
In a blog post, Invenergy said “responsible transmission developers respect private property rights and make every effort to negotiate with landowners.” It said it has “among the strongest set of landowner protections and compensation packages, including a code of conduct and agricultural impact mitigation protocol.”
Invenergy says it has completed over 95% of land acquisition for Phase 1, the segment connecting Missouri and Kansas. The phase’s construction is scheduled to start in 2026.
Grain Belt’s developers received some good news July 1 when the D.C. Circuit Court of Appeals denied a rehearing request from a group of Illinois landowners. The court dismissed the lawsuit in April, finding the group had failed to demonstrate that they will suffer a “certainly impending” injury-in-fact (24-1213).
Grain Belt has been under development since 2010, when the now-defunct Clean Line Energy first proposed the transmission line. After years of regulatory, legal and political hurdles, Clean Line sold the project to Invenergy. (See Invenergy Renewing Push for Grain Belt Express.)
In the spring, as questions swirled about potential Trump administration tariffs on electricity from Canada, power flows from Québec to New England declined substantially, causing some concerns that the tariff threat was causing Québec to limit power exports to the U.S.
While these concerns appear unfounded — the drop in imports likely was driven largely by low power prices in New England — the low import levels illustrate a series of growing challenges on both sides of the border.
Imports from Québec historically have played a significant role in the ISO-NE system, accounting for an average of about 11% of net energy for load in New England between 2015 and 2022. But net imports over tie lines with Québec have dropped drastically over the past two years, making up just over 5% of net energy for load in New England in 2024 and sitting at a similar level through the first four months of 2025, according to ISO-NE data.
The largest factor driving Québec’s multi-year reduction of exports appears to be an extended drought, which began in early 2023 and has caused declining water levels in Hydro‑Québec’s major reservoirs.
“It’s the third year of a deep drought,” said Robert McCullough, principal of McCullough Research. Data collected by the firm indicate water levels of Hydro-Québec’s largest reservoir systems have declined significantly since the start of 2023.
Hydro-Québec’s exports also have been affected by a pair of looming, long-term power contracts the company signed with U.S. states: the 1,200-MW New England Clean Energy Connect (NECEC) project, anticipated to come online at the end of 2025, and the 1,250-MW Champlain Hudson Power Express transmission project, expected to come online in mid-2026. Both projects are intended to procure over 1,000 MW of baseload power on an annual basis from Hydro-Québec.
“When we talk about exports, an important firm energy commitment we have to take into account is the two new contracts that we will have with New York and Massachusetts,” said Maxime Nadeau, senior director of system control and grid operations at Hydro-Québec.
Over the past two years, the company has reduced its allowed amount of non-firm exports to ensure it has enough water to meet all its long-term firm power commitments, Nadeau said.
Québec, like much of North America, faces its own load growth; Hydro‑Québec’s most recent electricity supply plan forecasts power demand to grow by 14% between 2022 and 2032. While the company has announced plans for major long-term investments in new generation, the impending addition of new export commitments could pose a challenge over the next few years if drought conditions persist.
Declining Water Levels
On the La Grande watershed in northern Québec, home to more than 17,000 MW of installed hydroelectric capacity, 2025 inflows are tracking between 2023 and 2024 levels, according to data from McCullough Research. Meanwhile, the Canadian Drought Monitor indicates that a significant portion of northern Québec is facing moderate drought or abnormally dry conditions, according to the May 31 update.
“We’re having even lower inflows than we had last year,” McCullough said. “If they go into a fourth year of drought, [Hydro‑Québec] may be forced to reduce their external commitments.”
Canadian Drought Monitor, May 31 | Agriculture and Agri-Food Canada
Despite low water levels, representatives of Hydro‑Québec expressed optimism that inflows will return to typical levels this year, bringing the region’s reservoirs back to historical norms. The company has maintained it will have enough energy to meet all its firm commitments in the coming years.
“The very low inflows observed in 2023 and 2024 have had a lasting impact on 2025 overall levels,” said Lynn St-Laurent, spokesperson for Hydro‑Québec. “However, the combination of a revised production strategy and normal inflows should help restore water levels to more typical values.”
St-Laurent said it is normal for the region to experience fluctuating water levels and that the company has faced multiyear droughts on a similar scale in the past.
She stressed that “inflows remain around normal levels for 2025” and said it can be misleading to compare inflows at an isolated point in time, noting that “the low water availability of the last two years at La Grande was not due to weak spring runoff, but rather to low precipitation during the summer and fall of previous years.”
Climate Impacts and Uncertainty
While it is difficult to pinpoint exactly how climate has affected the current drought and water levels, scientists expect precipitation variability — both over multiyear stretches and intra-year periods — to increase in Québec as the planet warms.
“We expect droughts to be more frequent and more persistent in the future, related to climate change,” said Christopher McCray, climatologist at Ouranos, a climate research organization funded by the Québec government.
Although most studies indicate northern Québec will see increasing average annual precipitation, multiyear drought periods could create increasing challenges for water management, McCray said.
While Québec always has seen a fluctuation between dry and wet years driven by large-scale weather patterns, warming temperatures are “accentuating the effects of those patterns,” McCray said.
“The same weather pattern that caused a drought 50 years ago, now it’s a little bit warmer … and there’s a greater capacity for evaporation than in the past,” McCray said. “And so, the soil dries out, and that can cause a feedback loop that leads to a persistent period of dry conditions.”
Hydro‑Québec expects to see “more overall water supply in the northern part of the province,” Nadeau said. “That’s good news, because that’s where we have all of our major main reservoirs.”
He added that the company recently began working with experts on studies to better understand how climate change will affect inter-annual variability.
Researchers also anticipate climate change will cause seasonal shifts in precipitation. Ouranos predicts average winter precipitation to increase and more frequently fall as rain. This likely would increase stream flows in the winter and move the spring high-runoff period earlier in the year.
McCray said there is more uncertainty around how climate change will affect overall summer precipitation but that there could be an increased “whiplash” between dry periods and extreme rainfall events within summer seasons.
While long-term scientific studies consistently forecast increased precipitation for the province, McCullough said the impact of climate change on the jet stream has created significant new challenges for forecasting precipitation and water levels.
“We’ve been doing this for about 40 years,” McCullough said. “I would’ve sounded a lot more confident 20 years ago.”
The jet stream — a strong west-to-east flow of air typically located five to nine miles over the U.S.-Canada border — causes droughts when larger-than-normal north-south waves in its flow push precipitation away from a region for an extended period, said Jennifer Francis, a senior scientist at the Woodwell Climate Research Center.
“A growing body of research is finding that wavy jet-stream patterns are occurring more often, in part because the Arctic is warming three to four times faster than the globe as a whole, which reduces the north-south temperature difference that fuels the jet stream,” Francis said. “A weaker jet stream is more easily deflected from its west-to-east path by things like mountain ranges and abnormal temperature patterns, which causes larger north-south excursions and increased waviness.”
Increasing disturbances to the jet stream will cause more temperature and precipitation extremes in the northern hemisphere, Francis explained.
“When it comes to Québec’s reliance on rainfall to fill rivers and reservoirs to generate electricity, this aspect of human-caused climate change is indeed a concern,” Francis said. “Some years will bring extended droughts. Others will bring prolonged rains. Both extremes are expected to occur more often as we continue to add heat-trapping gases to the atmosphere.”
As increased temperatures and decreased snow cover dry out soil, wildfire risks also are increasing in Québec, creating additional reliability risks on the power system, which can have knock-on effects on reliability in the U.S. In 2023, a forest fire caused the shutdown of a transmission line in Québec during New England’s evening peak, triggering an ISO-NE capacity deficiency. (See Canadian Wildfires Trigger ISO-NE Capacity Deficiency.)
According to an analysis by World Weather Attribution, an academic research group, “climate change made the cumulative severity of Québec’s 2023 fire season to the end of July around 50% more intense, and seasons of this severity at least seven times more likely to occur.”
‘More Dynamic Changes in Flow’
In the coming decades, with the anticipated growth of intermittent renewables across the Northeast, Hydro-Québec expects its reservoirs to be used less as a baseload power resource and more as a massive balancing resource, allowing the company to conserve water during periods of high renewable production. (See Québec, New England See Shifting Role for Canadian Hydropower.)
The economic justification for a large-scale two-way exchange of power between regions likely will not occur until a significant number of offshore wind projects come online, which may not be until the mid-2030s or later. However, Vineyard Wind and Revolution Wind appear on track to eventually deliver about 1,500 MW of capacity to the New England grid, which could drive more frequent power exchanges between regions during periods of high production.
“With all that renewable energy that is being integrated in the electrical grid, we will see more dynamic changes in flows on the interties,” Nadeau said, adding that it is harder to forecast changes to the overall balance of imports and exports.
This phenomenon could help the region address a major need for clean firm energy to help meet state climate targets in the coming decades. (See ISO-NE Study Lays Out Challenges of Deep Decarbonization.) A 2021 study found that increased transmission capacity between regions would significantly reduce the overall costs of decarbonization by 2050 and limit the need to overbuild intermittent renewables.
However, if Canadian hydropower ultimately is to help displace fossil units in New England, the region must be able to rely on the power when it is needed.
While imports from Québec have performed during capacity deficiencies in the region in recent years (aside from the 2023 wildfire-induced line outage), the decrease in overall import levels since 2023 has given fuel to arguments that imports from Québec are not as reliable as in-region generation.
In NEPOOL debates over the development of a new capacity accreditation framework for ISO-NE, representatives of generation companies have argued the RTO overestimates the benefits of its interregional transmission lines during emergency events, noting that these tie benefits are not backed up by capacity supply obligations. (See ISO-NE Discusses Details of New Prompt Capacity Market.)
Generation companies in New England also have expressed concern about the overall annual level of imports the region can expect to receive from Québec.
While the NECEC transmission project is intended to provide firm supply from Hydro-Québec, skepticism about how much incremental power the project will provide the region dates back to state regulatory proceedings for the power procurement. Multiple groups voiced concern in the proceedings that the contracts do little to guarantee net imports above the historical levels to New England.
In its approval of the contracts in 2018, the Massachusetts Department of Public Utilities wrote that the NECEC power purchase agreements would guarantee firm power deliveries incremental to what Hydro‑Québec “would otherwise be expected to deliver to New England through its ongoing, largely non-firm commercial trading activities (D.P.U. 18-64).”
Ultimately, when NECEC comes online, flows from Québec to New England are poised to increase; the NECEC contract requires the company to send 9.55 TWh of power annually, compared to the 6.3 TWh of power imported to New England in 2024.
The export commitments, coupled with the addition of Vineyard Wind and Revolution Wind, may correspond with an increase in Québec’s spot market imports from New England, potentially mitigating the change to the overall balance of power exchanges. Beyond its export commitments, the total amount of power Québec sends back to New England may depend in large part on how long the drought conditions persist.
“At the moment, given the forecasts of a significant deficit at Hydro-Québec, I don’t think [NECEC] will change the balance at all,” McCullough said. “There’s nothing in the contract to prevent them from buying cheaply in New England, storing it and sending it back to New England.”
