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.”
Until now, a carbon-free, load-following electric supply resource has been elusive. That may be about to change because of a resource that sits literally right below our feet — even if it is a mile or more down. That supply resource is the earth’s heat, which radiates continuously from the earth’s core, and entrepreneurs are quickly figuring out how to tap it.
Developers have been accessing traditional geothermal energy resources for decades in those limited areas of the world where hydrothermal resources exist in the form of hot springs, geysers, volcanoes and fumaroles. These areas typically are near tectonic plate boundaries. In this country, 93% of the 3,700 MW of installed capacity is located in these more geologically active areas of California and Nevada. In recent years, though, development of domestic hydrothermal resources has stagnated.
Fortunately, a much larger geothermal resource exists that is more geographically widespread, and it doesn’t require the presence of existing underground water. Developers are tapping into this unconventional geothermal asset by using specialized equipment to drill holes miles deep into hot, hard rock — often granite.
Using techniques developed in the hydrocarbon fracking industry, specialized technicians drill at depth, then rotate the drills 90 degrees and guide them laterally to develop horizontal boreholes in the hot zones that often exceed 300 degrees Fahrenheit. Instead of relying on existing underground water resources, developers bring their own working fluids, typically water but also high-pressure supercritical carbon dioxide (neither a gas nor a liquid). These working fluids are circulated deep underground to harvest the rock’s ambient heat and bring it back to the surface, where it creates steam to spin turbines and generate power.
This new geothermal industry already is branching off into multiple approaches, some of which may work better than others based upon local conditions. Today, the two main approaches are called enhanced and advanced geothermal.
Enhanced geothermal: The enhanced geothermal companies typically drill parallel wells and then frack the rock between the wells using high-pressure water. This creates fissures in the rock and establishes permeability and connectivity between two wells. An injection well introduces water into the system, which heats up when it contacts the broad surface areas in the broken rock. The second withdrawal well draws the heated water back to the surface for electricity generation.
Just as with hydrocarbon fracking, developers can punch multiple wells into the earth from a single pad, minimizing drilling time and surface area impacts. Fiber optic cables collect data relating to temperatures and the flow of the working fluids that capture and “mine” the heat from the rock. The trick is to optimize the flow of fluids to capture the maximum amount of heat extracted to the surface.
Advanced geothermal: With advanced geothermal development, some operators drill vertically and then horizontally, but rather than fracking the rock, they install a lining in the hole to create closed-loop circuits, essentially developing underground inverse radiators. Others use a pipe-within-a-pipe system, sending water down in one pipe and withdrawing it through the other. In either case, a finite quantity of working fluid — either water or supercritical CO2 — is injected into the closed system, heated by the surrounding rock, and then brought back to the surface. The use of supercritical carbon dioxide requires special turbines, but because it boils and creates high-pressure steam at lower temperatures, it can further enhance output.
The first commercial contracts point the way: Within the past year, leaders in this nascent industry have inked the first meaningful deals. Pathbreaker Fervo Energy signed its first 3-MW proof-of-concept contract with Google in late 2023. It then turned its attention to developing a far larger effort in Cape Station, Utah, and has signed contracts with Shell Energy, Clean Power Alliance and Southern California Edison, with initial deliveries from its 500-MW facility beginning next year.
Technological advancements: Just as the fracking industry saw rapid technological development and improvements resulting in lower costs, the new geothermal players also are pushing the envelope as they drill deeper into challenging heat and hard rock environments. They use tools and practices adopted from conventional drilling and fracking and adapt those to their specific industry. These include specialized polycrystalline diamond drill-bits, specialized lubricants and additions to the drilling mud that keep the well cool enough for the equipment to operate.
A recent paper evaluating drilling speeds and costs demonstrated significant progress — in terms of speed, required number of drill bits and related costs — with each new well drilled. In the example cited, Fervo was able to demonstrate a 60% improvement in drilling speeds over just eight wells.
Fervo horizontal well cost per ft and spud to TD trends | Stanford University
Multiple players, with a growing pot of money: There are more than a dozen geothermal startups in the U.S., with Texas seeing the greatest concentration. Together, they have been funded with more than $2 billion (Fervo just raised an additional $206 million for project financing in June).
Many companies are far enough along in their efforts that 11 of them have been pre-qualified by the U.S. Department of Defense for projects on military bases (and seven pilots reportedly are in the works). Most are adapting existing oil and gas technology, but startup Quaise is using a different approach. It emulates others by drilling to initial depths using conventional technology. However, it then plans to go far deeper than its competitors — as far as 12.5 miles down to access heat over 900 F — and to achieve this goal, it is testing high-powered millimeter waves that vaporize holes in the rock.
Size of potential resource: Studies suggest the geothermal resource is enormous. A June 2025 study looking at New Mexico estimates as much as 163 GW of potential geothermal production, 15 times the state’s installed capacity. At the national level, a 2024 Department of Energy Lift-off study suggested a potential 90 to 130 GW of installed capacity over the next 25 years.
Estimated next-generation geothermal deployment potential | DOE
That number would represent a fraction of the 7,000 GW of national potential at three miles deep, and 70,000 GW accessible at all depths. There’s one inherent challenge here, though: The geology of the U.S. clearly favors the West, where drillers can access heat at far shallower depths. Because going deeper has been prohibitively expensive and time consuming until now, the Eastern U.S. has been largely excluded from consideration.
That may be changing, though, as evidence is beginning to suggest that perhaps these deeper depths are more easily attainable. Fervo announced in June that it had drilled a new well to a depth of 15,765 feet (75 feet shy of three miles!) in only 16 days, accessing temperatures in the range of 520 F. Furthermore, it was able to drill laterally through the hard rock at that depth at an impressive rate of over 300 feet per hour.
Hype or real reason for hope? While it’s still too early to tell, and early capital certainly will be deployed where drilling is easier and more cost-effective, we may see an industry expansion to the east in the visible future. For the emerging unconventional geothermal industry, the theoretical potential is there and the first facts on (and in) the ground are promising.
The industry already has viable and tested technology, successes, financing and the first commercial contracts in hand. It also may have continued government support in the form of continued tax credits and a relatively easy permitting process for projects on federal lands. We will know a lot more about just how real this industry is in just a few short years.
Around the Corner columnist Peter Kelly-Detwiler of NorthBridge Energy Partners is an industry expert in the complex interaction between power markets and evolving technologies on both sides of the meter.
A yearslong dispute over who gets to own a 345-kV network upgrade in Michigan had the D.C. Circuit Court of Appeals meditating on the definitions of “system” versus “facility.”
Ultimately, the D.C. Circuit decided that Michigan Electric Transmission Co. (METC) does not have exclusive ownership rights to an almost $12.4 million upgrade to support EDP Renewables’ in-progress 120-MW Eagle Creek Solar Park (24-1039).
The court’s July 1 order means that Michigan Public Power Agency (MPPA) and Wolverine Power Supply Cooperative, as fellow co-owners of the existing Styx-Murphy 345-kV line, also should have a stake in the line’s extension and new substation construction.
The D.C. Circuit examined the semantics of MISO’s Transmission Owners Agreement to reach its conclusion. METC argued it should be the sole owner of the upgrades because they will be located within its larger transmission system. It also said that 33-year-old agreements bestowing partial line ownership to MPPA and Wolverine don’t extend to network upgrades on the line.
Wolverine owns 64% of the Styx-Murphy line, while MPPA owns 35% and METC owns 1%. MPPA and Wolverine acquired their ownership in 1992 through an antitrust settlement agreement to limit Consumer Energy’s market power in the Lower Peninsula. METC, meanwhile, purchased its stake from Consumers in 2020.
METC argued that the circumstances behind MPPA and Wolverine’s ownership made them ineligible for network upgrade ownership interest. It argued the two have “limited grants of ownership” on the line that permit them to transmit certain megawatt flows over METC’s larger system and nothing more.
METC also said per the MISO Transmission Owners Agreement, the line qualifies only as a “facility” and not a “system.” METC said the distinction between the phrases means it, as the owner of the larger system, is entitled to the network upgrade, not MPPA and Wolverine, which merely own a facility on its system.
The D.C. Circuit agreed that the context of Wolverine and MPPA’s rights to the line didn’t make them less worthy of owning generator interconnection-related network upgrades. The court also said a dictionary reading of “system” versus “facility” does not “demarcate as sharp a distinction … as METC would like.” It said previous FERC orders METC cited as proof “merely refer to METC’s ‘transmission system’ and the Styx-Murphy line as a ‘facility’ without reference” to specific sections of the MISO Transmission Owners Agreement.
The court said METC’s rigid interpretation would mean that MISO Transmission Owners who own a single facility would be barred from ever constructing or owning a network upgrade for a generation interconnection, which is not the case.
“It would make no sense for the other TO signatories or for MISO itself to discriminate in this manner against the owner of only one facility,” the court reasoned.
The D.C. Circuit said it agreed with the commission that METC couldn’t claim ownership of an upgrade to a line it doesn’t completely own “simply because that existing facility was located within its ‘system.’”
“That result ‘would ignore the ownership, and responsibilities, of the actual owner(s) of the existing transmission facilit(ies),’” the court said, quoting FERC. It also said it would render a portion of MISO’s Transmission Owners Agreement “meaningless.”
The court seconded FERC’s conclusion that the history behind MPPA and Wolverine’s ownership provisions wouldn’t exclude them from owning network upgrades on the line. It said the antitrust agreements conferred “unrestricted pro rata ownership in the Styx-Murphy line” which enables them “to compete on an equal footing with other TOs.”
“Limiting the agreements as METC requests … could only help entrench rather than restrain METC, an effect at odds with the pro-competitive purpose of the agreements,” the court said. It added that it could not tack on a “new prohibition” to the decades-old agreements.
METC, meanwhile, has been building the network upgrades to support Eagle Creek.
