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December 9, 2025

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CTR Plans 500-MW Geothermal Project in Lithium Valley

Controlled Thermal Resources has taken a step forward on its plans to build a 500-MW geothermal energy plant in California’s Lithium Valley, where it is eyeing co-location of manufacturing or data centers. 

CTR announced Sept. 9 that it is partnering on the geothermal project with Baker Hughes, an energy technology company. Baker Hughes will supply high-temperature drilling technologies, power systems and digital field services. 

The project location is near the Salton Sea in the Imperial Valley region of Southern California — an area that’s been dubbed Lithium Valley. Not only is the region a known geothermal resource area, but brines produced there during geothermal electricity generation have been found to be rich sources of lithium. 

In fact, the region may have enough lithium to allow the U.S. “to meet or exceed global lithium demand for decades,” the Department of Energy said previously. (See Salton Sea Could Supply Lithium Needs for Decades, Study Finds.) 

CTR’s Hell’s Kitchen project is a combination of advanced geothermal power generation and critical minerals extraction. 

The goal for Stage 1 of the project is 50 MW of geothermal energy and 25,000 metric tons per year of lithium hydroxide. 

Interconnection Delay Bypass

From there, geothermal generation will be expanded in stages, up to an additional 500 MW. The expansion will support hyperscale data center growth and advanced battery manufacturing “with the capacity to accommodate behind-the-meter, direct-source baseload power, bypassing grid interconnection delays,” CTR CEO Rod Colwell said in a July project update. 

“Hyperscale data center and AI demands are surging, but they cannot run on intermittent renewables,” Colwell said in a statement. “The Hell’s Kitchen project will provide 500 MW of baseload energy to meet this demand.” 

Maria Claudia Borras, chief growth and experience officer at Baker Hughes, called the 500 MW geothermal plant “one of the largest baseload renewable energy projects in the United States.” 

Commenting on the CTR project, California Gov. Gavin Newsom said the state “continues to build more clean energy, faster.”

“Together with partners like Controlled Thermal Resources, we’re advancing a vision for Lithium Valley that promises to become a global source of critical minerals while also powering a new economic boom for the region,” Newsom said in a statement. 

The CTR campus is one piece of Imperial County’s Lithium Valley Specific Plan. When finalized, the plan will provide a framework across 51,000 acres for clean energy, advanced manufacturing and data centers. 

Also in Lithium Valley, data center developer CalEthos is planning a 315-acre campus for clean energy-powered data centers.

CTR is close to making a final investment decision on Stage 1 of the Hell’s Kitchen project, and construction could start in 2026, a company spokesperson told RTO Insider.  

CTR has a 40-MW power purchase agreement with the Imperial Irrigation District as well as lithium supply agreements with major U.S. auto manufacturers. 

As for the 500-MW geothermal project, CTR plans to build it in 50- to 100-MW increments. The first stages may be complete in the late 2020s, the company said. 

Federal Policy Shifts

The buildout for CTR’s Lithium Valley campus includes several co-location sites, according to conceptual plans. The co-location sites could accommodate hyperscale data centers, precursor cathode active material production or battery manufacturing, according to the spokesperson. 

Permitting work also is under way. In June, Hell’s Kitchen formally received a Fast-41 Covered Project designation. FAST-41 is an initiative to streamline federal permitting through a predictable and transparent process. 

CTR’s plans also may get a boost from recent shifts in federal policy.  

The One Big Beautiful Bill Act directs incentives and funding toward projects “that can deliver domestic baseload energy security, critical minerals, manufacturing capacity and supply chain resilience,” Colwell said in his July update. 

CTR recently took part in a series of high-level meetings in Washington, D.C. Colwell said the meetings “confirmed CTR’s alignment with national priorities.” 

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D.C. Circuit Upholds FERC PURPA Decision Without Chevron Deference

A three-judge panel of the D.C. Circuit Court of Appeals on Sept. 9 upheld its decision to side with FERC over whether a solar plant in Montana is a qualifying facility under the Public Utility Regulatory Policies Act without relying on Chevron deference. 

The Supreme Court had remanded the initial decision in July 2024, after it had ended the Chevron doctrine in Loper Bright Enterprises v. Raimondo. (See PURPA Case Offers FERC Early Glimpse of Post-Chevron World.) Under the doctrine, courts would defer to regulatory agencies in their administration of a law as long as their decision-making was reasonably explained. 

In Solar Energy Industries Association v. FERC, the D.C. Circuit still sided with the commission that the Broadview facility, with 160 MW of nameplate capacity, is a QF. The solar plant includes a 50-MWdc battery, limiting the power that actually flows to the grid to PURPA’s 80-MW maximum, FERC found. 

FERC has consistently defined power production capacity as the amount of power a facility can ship to the grid. Petitioners in the case, including NorthWestern Energy, argued it should be applied to the nameplate capacity. 

Initially, the court sided with FERC under the Chevron precedent, but in the decision issued Sept. 9, it concluded under Loper Bright that power production capacity should be defined as the amount of power that can be sent to the grid. 

“That reading accounts for all the facility’s components working together, not just the maximum capacity of one subcomponent, and it appropriately focuses on grid-usable AC power,” the court said. “Because the Broadview inverters’ maximum output capacity at any given time is 80 MW of AC power, the entire facility’s send-out capacity is capped at that level consistent with FERC’s decision to certify it as a small power production facility.” 

The generator is linking to the grid through NorthWestern’s transmission system. The utility filed an objection to its certification at FERC along with the Edison Electric Institute. In a September 2020 order, FERC initially denied the certification, finding that the relevant capacity was the 160 MW of solar. 

Broadview sought rehearing, and in March 2021 (soon after President Joe Biden took office), FERC reversed course and granted it QF status under PURPA. 

FERC rejected arguments from EEI that the setup was designed to “game” PURPA’s power production capacity limit. The facility’s design enables a higher capacity factor, achieving its maximum 80-MW output about 35 to 40% of the time, with FERC finding that a permissible use of technology to boost its capacity factor while remaining under PURPA’s limit. 

After the D.C. Circuit sided with FERC in 2023, EEI and NorthWestern sought Supreme Court review. The high court granted the petition without deciding the merits, vacating the earlier decision based on the Loper Bright decision. On remand, the circuit court followed the Supreme Court’s directive to exercise its independent judgment in deciding whether the agency had acted within its statutory authority. 

“We hold that a small power production facility’s ‘power production capacity’ refers to its maximum net output of AC power to the electrical grid at any given point in time,” the court said. “Because the amount of power the Broadview facility can send out to the grid is limited by its inverters to 80 MW, it qualifies as a small power production facility under PURPA.” 

Based on the law’s text, “facility” applies to all components as they function together, which includes the inverters and their 80-MW limit. The power production capacity rule refers to a “facility” rather than a particular subcomponent, such as a generator.  

“The only grid-usable form of electric energy the facility produces is AC power,” the court said. “The most natural reading of ‘power production capacity’ of the facility, then, is the amount of AC power that the overall facility transmits to the electrical grid.” 

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FERC Commissioners Debate 60/40 Capital Structure for Transmission

An apparently routine rate incentive request from a MISO transmission developer who has yet to be assigned a project turned into a debate between FERC commissioners over capital structures in ratemaking (ER25-2312).

Midcontinent Grid Solutions (MGS) Iowa — a subsidiary formed by MGS to bid on MISO competitive transmission projects in the state — approached FERC for a 9.98% base return on equity, a 50 basis-point adder for participation in an RTO, regulatory asset treatment to recover its pre-commercial and start-up costs later, and a hypothetical capital structure of 60% equity and 40% debt until it establishes long-term debt.

The company has not yet been awarded any competitive projects in MISO.

FERC’s resulting Sept. 8 ruling allowed MGS Iowa the incentives, with the caveat that it include the cost of its actual short-term debt from construction financing in initial debt costs in its formula rate for the period when it has yet to acquire long-term debt. The commission also allowed the company to use the depreciation rates of its affiliate, Transource Wisconsin, until it has its own facilities to glean historical data.

The 60/40 equity-to-debt split was a point of contention among commissioners.

Commissioner Judy Chang dissented from the order, arguing that hypothetical capital structures in which equity skews higher can cost ratepayers more and should be evaluated more closely.

“The capital structure used in ratemaking affects the size of the overall revenue requirement by impacting the return on rate base, depreciation and even income tax allowance for the life of the project,” Chang wrote. “These components then flow into the resulting rates. The relationship between the assumed capital structure and rates therefore presents a direct impact to ratepayers: the higher the assumed equity component of an applicant’s capital structure (without changing the corresponding return on equity), the greater the potential rate impact for customers.”

Chang said MGS Iowa did not support its requested capital structure and only cited past commission precedent granting the same figures for other companies. She said FERC’s past decisions should not automatically validate MGS Iowa’s request.

She pointed out that while FERC has accepted developers’ request for 60% equity with “minimal support,” it also has applied greater scrutiny, evidenced by its recent order concerning Valley Link Transmission Maryland.

FERC generally allows up to 60% equity share. But in May, it rejected Valley Link’s proposed 60% equity/40% debt hypothetical capital structure, with the Maryland Office of People’s Counsel arguing the proposed ROE was too high and would transfer risk to ratepayers (EL25-77).

“The commission should not perpetuate an error simply because it has approved a similar structure in the past for other entities,” Chang concluded. “Accordingly, I would reject MGS Iowa’s proposed capital structure and establish a paper hearing to determine the appropriate hypothetical capital structure.”

Commissioner Lindsay See agreed with Chang that a hypothetical capital structure of 60% equity and 40% debt can “heighten the potential for unjustified rates” and MGS Iowa’s argument was “less than ideal.”

“Future applicants might take note that bringing stronger record support for their chosen hypothetical capital structure could make for a smoother path,” See wrote in a concurrence to the order.

But See said the temporary capital structure is within the bounds of what FERC previously approved and would last only until MGS Iowa attains long-term debt financing with a project placed into service. She also said new transmission is associated with “significant financing risks” and noted that no one objected to the capital structure.

“I cannot overlook how the commission has granted similar requests in similar cases very consistently over the better part of a decade. Regulatory certainty drives stable investments, and we need smart investments to build out the grid now more than ever. Taking a sharp turn from the commission’s nearly unanimous precedent in this area thus gives me pause,” See said.

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Consumers Energy to Offload 13 Michigan Hydro Dams to Investment Firm for $1 Each

After years of looking for a buyer, Consumers Energy announced it struck a $13 deal to sell its fleet of 13 hydroelectric dams in Michigan to a Bethesda, Md., private equity firm.  

Consumers Energy agreed to sell the collection of century-old dams for $1 apiece to a newly formed subsidiary of Hull Street Energy in a Sept. 9 purchase agreement. The dams are situated on five rivers across Michigan and have a combined installed capacity of 132 MW, though they currently generate only about 50 MW, according to Consumers.  

In a release, Consumers said the sale will reduce long-term costs for its customers and ensure the continued safe operation of the dams.  

Consumers has long said maintaining the dams is expensive. The dams were built between 1906 and 1935, making the oldest nearly 120 years old. The utility has acknowledged the dams need significant infrastructure upgrades to remain in compliance with FERC licensing requirements. Consumers estimates that maintaining the dams through a new 30- to 50-year licensing period would cost $1.5 billion. It also has said the dams’ hydroelectric output costs nine times more than its other sources of generation.  

Hull Street Energy said it has a “long track record of successfully owning and operating hydroelectric facilities” across North America. It said it has acquired and improved 47 hydroelectric assets in the past decade. Many of the facilities are small or midsize run-of-river dams in New England. 

The investment firm created subsidiary Confluence Hydro to own and manage the dams and acquire other hydro assets.  

“The firm will leverage its extensive experience and capital resources to upgrade the projects, ensuring the facilities can continue to safely deliver reliable, clean energy to Michigan customers and support economic and recreational opportunities critical to local communities for years to come,” Hull Street Energy said in a press release.  

Confluence Hydro CEO Ed Quinn emphasized the company’s commitment to dam safety and refurbishment in a statement.  

“With decades of experience operating hydro facilities, we are committed to preserving and modernizing these important resources to maximize their contribution to the grid,” Quinn said, adding that Confluence aims to be “a best-in-class hydro company — one that protects communities, supports employees, mitigates risk, and delivers reliable, clean energy for the future.” 

Hull Street Energy was founded in 2014.  

The 13 dams across Michigan in the sale | Consumers Energy

The sale agreement dictates that Confluence Hydro enter a contract to sell power back to Consumers Energy from the facilities for 30 years. Confluence said it would seek to renew the dams’ federal operating licenses, which begin to expire in 2034. 

“We believe a sale of the dams is the best path forward for our customers. This sale balances two important needs: to lower costs for Consumers Energy’s customers while continuing to care for communities that depend on the dams,” said Sri Maddipati, Consumers Energy’s president of electric supply. “After numerous conversations with community members over the last three years to gather insights and feedback, we are confident this sale will preserve the reservoirs that hold the key to economic, recreational and community benefits at each of the dams.” 

Consumers Energy hosted local meetings across Michigan on the fate of the dams beginning in 2022 and issued a request for proposals in early 2024. It also hired Lansing, Mich.-based Public Sector Consultants in 2022 to explore the impacts on communities in the event of partial or full dam removals.  

The companies expect the transaction to close within 12-18 months pending approval from the Michigan Public Service Commission and FERC for the sale and license transfer for the dams. 

Confluence said it plans to hold meetings with employees and affected communities in the coming months. It also said it plans to offer current Consumers Energy hydro employees “equivalent positions” with Confluence.  

Bob Stuber, president of the Michigan Hydro Relicensing Coalition, which represents five conservation groups, expressed concern over a private investment firm buying the dams.  

Stuber said because the new owner would sell power to Consumers Energy rather than the public, Hull Street cannot be reimbursed for any future investments through the Michigan Public Service Commission, possibly making future capital investments in the dams unattractive.  

“Consumers acknowledges that these hydropower projects are marginally economical. It is a well-managed corporation, so it begs the question: If Consumers is challenged to turn a profit from these projects, how will another entity be able to, especially without a cost-recovery mechanism?” Stuber asked in a statement to RTO Insider.  

Stuber said there’s also no guarantee Hull Street will continue to meet licensing requirements.  

“History has demonstrated that new owners of older hydropower projects in Michigan are not as committed, as shown by the Edenville and Sanford catastrophic dam failures,” Stuber said, referring to Boyce Hydro’s yearslong negligence that caused the collapse of the Edenville and Sanford dams in Mid Michigan in May 2020. In that case, Las Vegas architect Lee Mueller and family members bought the dams to avoid paying taxes on the sale of an Illinois property. (See Michigan Dam with Prolonged Safety Issues Fails; FERC Terminates More Boyce Hydro Licenses.)  

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EPRI, NEI Update Roadmap for Advanced Nuclear Buildout

The Electric Policy Research Institute and Nuclear Energy Institute have issued an update to the Advanced Reactor Roadmap they launched in 2023.

The update comes after a period of steady progress by the nuclear power industry as well as rapidly increasing interest in and support for it.

In their Sept. 9 announcement, EPRI and NEI said the blueprint could help enable buildout of more than 300 GW of advanced nuclear generation capacity in North America. It identifies completed actions, new priorities and evolving industry needs over the past two years.

“When it comes to new nuclear power, the challenge isn’t demand but being able to build fast enough to meet it,” NEI Executive Director of New Nuclear Marc Nichol said in a news release. “The North American nuclear industry is confident in the ability to rise to the challenge and deliver the reliable, affordable and clean energy needed to power the future.”

The updated roadmap breaks the challenge down into three key issues — regulatory efficiency, technology readiness and project execution — and seven enabling factors to deliver value on a timely schedule: first-mover success, fast followers, regulatory efficiency, siting availability/permitting, indigenous/public engagement, supply chain ramp-up and workforce development.

The update is significantly longer and more detailed than the initial version, and it, too, will evolve with future developments and further stakeholder input.

The 2025 update notes that after the initial roadmap was issued in May 2023:

    • Vogtle Units 3 and 4, the first new U.S. advanced reactors, began commercial operation.
    • A host of state and federal policy and regulatory actions have boosted support for nuclear generation.
    • The sector has seen extensive private investment and agreements for offtake from facilities still in the research and planning phases.
    • The first small modular reactor in North America was approved for construction in Ontario.
    • More than 60 other new nuclear projects are being planned in the U.S. and Canada; several have secured regulatory approval; and a handful have begun construction.

Steve Chengelis, EPRI vice president of energy supply, said: “Using the roadmap as a guide, the nuclear industry has made significant strides in areas such as piloting accelerated material qualification projects, advancing workforce training and recruitment, and assessing how construction methods can reduce the risks of new builds.”

The roadmap spells out in detail the expected benefits of widespread deployment of advanced nuclear generation.

It also flags 49 issues posing potential hurdles to advanced nuclear technologies, including:

    • Risk must be reduced and mitigated to give investors and customers the necessary confidence to be first movers.
    • Some of the fuels that advanced reactors are being designed around have yet to be demonstrated commercially, and significant public and private investment is needed to get those fuels to market.
    • Other parts of the supply chain are inadequate, and investment in specialized production to create a supply chain is contingent on certainty of demand.
    • The construction skillsets the nuclear industry will need are in short supply and in high demand.
    • There is a collective lack of institutional knowledge, because so little nuclear construction has occurred in the United States in the past 30 years; because much will change from past practice; and because most prospective owner/operators will be new to the field and may lack necessary skills or experience.

But the roadmap also spells out the steps that need to be taken to address these challenges and identifies the key stakeholders who are or will be addressing the various issues.

The Tennessee Valley Authority has been among the early movers in U.S. planning and development of advanced nuclear technology, and it spoke of the value the roadmap has offered over the past two years.

“The roadmap’s collaborative approach has helped unify diverse stakeholders around a common vision for advanced reactor deployment,” Scott Hunnewell, vice president of TVA’s New Nuclear Program, said in the news release. “As a national leader in advancement of new nuclear technologies, we’re proud to contribute to this effort and look forward to continued progress.”

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Third Circuit Reaffirms Ruling in Favor of Transource 9A Project

The Third U.S. Circuit Court of Appeals has ruled that the Pennsylvania Public Utility Commission violated the Constitution in denying Transource Energy permits necessary to construct the Independence Energy Connection (IEC) transmission project.

The court reaffirmed the ruling of a lower court, finding the PUC contravened the supremacy clause by deviating from PJM’s approach to determining the benefit-cost ratio of two transmission lines designed to reduce congestion by increasing access to generation in Pennsylvania.

The PUC argued PJM’s method was flawed because it weighed the reduced congestion against only the project development costs, while not factoring the increased rates for Pennsylvania consumers. The commission denied Transource siting and eminent domain permits to proceed with construction in May 2021.

The appeal followed a Dec. 6 ruling by the U.S. District Court for the Middle District of Pennsylvania finding that the PUC’s approach violated the commerce clause of the Constitution as an instance of economic protectionism.

The Third Circuit focused instead on the supremacy clause to arrive at its conclusion the commission would undermine federal objectives by supplanting the approach for mitigating congestion developed by PJM and approved by FERC. (See Federal Court Rules in Favor of Transource Congestion Project in PJM.)

The Third Circuit wrote that its ruling does not strip states of their jurisdiction over siting but instead determines that the rationale for rejecting a permit application cannot conflict with federal objectives.

“What matters for preemption purposes is that the PUC’s reasons for denying the siting applications amounted to ‘second-guessing the reasonableness’ of PJM’s FERC-approved approach to determining which projects should be built,” the court said. “The question before us is not whether the PUC was acting within the ordinary scope of state authority, but whether its action poses an obstacle to the accomplishment of federal objectives. As we explained above, it clearly does.”

The IEC project was designed to resolve congestion on the AP South Reactive Interface, which is composed of four 500-kV lines between West Virginia and Maryland skirting the Pennsylvania border. The congestion cost consumers in the eastern PJM region about $800 million between 2012 and 2016 by limiting the transfer of cheaper energy generated in the west. Development costs were estimated between $509 million to $528 million, with an initial benefit-cost ratio of 2.48 calculated by PJM.

In recommending the PUC deny permits for the project, a Pennsylvania administrative law judge wrote that congestion on the interface had fallen from $486.8 million in 2014 to between $14.5 million and $21.6 million in the following years. The ALJ argued that an estimated $812 million in increased rates for Pennsylvania consumers should be accounted for in the benefit-cost analysis, resulting in a cost-saving of $32.5 million over 15 years.

The appeals court acknowledged that Pennsylvania rates would increase as a result of low-cost generation being made more widely available, but said the federal government holds the objectives of ensuring reliable, economic and non-discriminatory access to transmission, as well as counteracting the monopolistic nature of state utilities.

“The regional planning process developed as a counterweight to state interests, and precisely because FERC determined that it could not depend on the states to address regional concerns such as congestion and grid reliability,” the court wrote.

Past Criticism from Christie

The PUC had also argued the issue preclusion precedent should prohibit Transource from presenting its claims around the commerce and supremacy clause in federal court when they had not been part of its case before the Commonwealth Court of Pennsylvania, which ruled in favor of the PUC.

The Third Circuit noted that Transource had reserved the right to make those arguments in the federal courts within a footnote in its summary judgment briefing and stated they were not integral to the case before the Commonwealth Court, which centered on whether the PUC decision involved errors of law and was an abuse of discretion. (See Transource Challenges Pa. PUC Decision in Court.)

PJM said it would recommend that its Board of Managers revise the scope of the IEC project to eliminate the eastern segment, which would construct a 230-kV line between the Conastone substation in Harford County, Md., and the Furnace Run substation in York County, Pa. The western leg of the project would construct a 230-kV line from the Ringgold substation in Washington County, Md., to the Rice substation in Franklin County, Pa.

PJM’s Tim Horger told the Transmission Expansion Advisory Committee that regulatory and constructability challenges with the eastern portion led staff to determine it no longer is worth pursuing, though both components continue to exceed the 1.25 benefit-cost threshold. (See “PJM Recommending Changes to Independence Energy Connection,” PJM PC/TEAC Briefs: May 6, 2025.)

FERC’s then-Chair Mark Christie criticized PJM for continuing to proceed with the project despite the opposition from state regulators in his comments on a waiver request the RTO filed to delay the deadline for completing its 2024 evaluation of the project. The commission dismissed the waiver as moot when PJM opted to proceed with the same system modeling used in the 2023 evaluation. (See Christie Blasts PJM Pursuit of Transource Market Efficiency Project.)

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NYISO Increases Budget for 2026

NYISO expects its 2026 budget to be $210 million, $8 million more than the 2025 budget, CFO Cheryl Hussey told the Budget and Priorities Working Group on Sept. 5.

The increase means NYISO will need $8 million more in revenue from Rate Schedule 1, an increase of 3.96%. RS1 is the administrative fee NYISO collects to cover its operating costs. The ISO expects a 3.8% increase in demand over the next year, which means RS1 can remain “virtually flat,” with a 0.2-cent/MWh increase over the current 94 cents/MWh.

Hussey said the key drivers of the budget increase include salaries, which are benchmarked against peer ISOs and RTOs and expected to increase between 3.5 and 6% in 2026. The ISO also plans to hire eight new full-time positions in 2026 to support increasingly complex market designs and forecasting analytics.

The positions include two data scientists, an economist, a software and power system applications engineer, and a stakeholder services manager.

At the same time, computer services have increased costs because of vendor consolidation and increased usage of cloud services.

Payments on outstanding debt also continue to increase each year. In 2024, NYISO borrowed $37 million and plans to borrow another $37 million in 2025, which is higher than normal.

The RS1 carryover is lower than it was in 2024/25. The ISO anticipates a carryover of $3.5 million for 2025/26, which is $1.5 million less than the prior fiscal year.

Hussey said that to avoid capital costs for server acquisition, the ISO will pursue a strategy of cloud computer migration, which would result in about $0.8 million in savings. Ongoing measures to reduce computer software subscriptions and eliminate redundant or unneeded services are expected to shave an additional $1 million in costs. The ISO also plans to delay and defer some hiring throughout the year to avoid salary costs to the tune of about $0.8 million.

Additionally, some debt will be repaid early, reducing debt service costs in 2026 by $3.3 million and debt service costs in 2027 by $6.3 million.

Rate Schedule 1 Highlights for 2026

The ISO projects that RS1 will include 160,600 GWh of demand, the vast majority of which will be net load at 148,650 GWh systemwide.

The ISO anticipates 8,000 GWh of billable exports to other regions and 350 GWh of wheel-throughs in the New York Control Area. Incremental supply — the additional supply above net load to compensate for transmission losses and non-billable exports to New England — is expected to total about 6,000 GWh.

These projections assume normal weather conditions, which are a significant driver of net load variability, both in terms of load reduction via behind-the-meter solar and demand. Load growth is anticipated to grow because of climate change, large load growth and building electrification.

2025 has seen higher-than-expected load in July and August and in the winter, which has driven overcollections. It’s possible this trend will continue into 2026 because of weather events that are more severe than forecast.

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Google, SRP Team up on Long-duration Storage

Arizona utility Salt River Project (SRP) and Google are partnering to study the real-world performance of non-lithium-ion, long-duration energy storage (LDES) technologies, the parties announced Sept. 8.

Google will fund some of the costs for LDES pilot projects developed for SRP’s grid, according to a release. Google will crunch numbers on the pilot projects’ performance and help with the research and testing plans.

The goal is to help the emerging storage technologies scale more rapidly.

“We believe that long-duration energy storage will play an essential role in meeting SRP’s sustainability goals and ensuring grid reliability,” Chico Hunter, SRP manager of innovation and development, said in a statement. “This first-of-its kind research collaboration with Google will bring additional insight into the viability of these new technologies that could move them to maturity more quickly.”

SRP serves about 1.1 million customers in the greater Phoenix area. The utility now has about 1,300 MW of energy storage, including 1,100 MW of battery storage at eight facilities. Another 200 MW is pumped hydro storage.

The SRP-Google collaboration may include multiple LDES projects. SRP noted that it issued requests for proposals in 2022 and 2024 for LDES demonstration projects.

“Long-duration energy storage is a key technology in the portfolio of advanced energy solutions that we want to bring to market faster — to unlock stronger, cleaner, more resilient grids,” Lucia Tian, Google’s head of advanced energy technologies, said in a statement.

Although the type of LDES technology to be deployed in the project isn’t yet known, Google announced in July a partnership with Energy Dome, which makes a carbon-dioxide-based energy storage system.

The system uses renewable energy when it’s abundant to compress CO₂ gas into a liquid. When the grid needs more power, the liquid CO₂ expands back into a hot gas under pressure, which spins a turbine. The energy generation lasts for eight to 24 hours.

Google said it will support commercial deployments of Energy Dome’s technology globally as well as invest in the company.

SRP has committed to reaching net-zero carbon emissions by 2050. Google wants to run its global data centers and offices on carbon-free energy and achieve net-zero emissions across its operations and value chain.

Google and SRP have partnered on clean energy resources to power Google’s future data center in Mesa, Ariz. The resources include the Sonoran Solar Energy Center, a 260-MW solar facility with 1 GWh of battery storage; Storey Energy Center, an 88-MW solar and battery storage system; and Babbitt Ranch Energy Center, a 161-MW wind farm.

Meanwhile, SRP wants to at least double the number of generating resources on its power system in the next decade to maintain reliability and resilience.

On two consecutive days in August, SRP set new records for system peak load: 8,429 MW on Aug. 6, followed by 8,542 MW on Aug. 7. High temperatures hit 116 and 118 degrees Fahrenheit on those days; peak energy demand was between 3 and 4 p.m.

SRP’s previous record peak of 8,361 MW was set on July 9.

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Report Quantifies Solar Deployment, Predicts Slowdown

A new report quantifies the buildout of solar power generation in 2025 and forecasts the slowdown expected to result from federal policy changes. 

The Solar Energy Industries Association and Wood Mackenzie issued their third-quarter U.S. Solar Market Insight Report on Sept. 8. 

They said that while 18 GW of new solar capacity was added in the United States in the first half of 2025, the One Big Beautiful Bill Act signed into law at the start of the second half — along with the many regulatory and policy changes made by the Trump administration — has significantly reduced forecasts for future deployment. 

The 18 GW of photovoltaic solar installed in the first half accounted for 56% of all new capacity additions nationwide, the report said. 

But construction tapered off in the second quarter of 2025, when only 7.5 GW was installed — 28% less than in the first quarter of 2025 and 24% less than in the second quarter of 2024. 

The report notes that the implications of the bill still are being determined; it predicts that while solar panels will continue to be installed widely, capacity additions will be 4 to 18% less than was predicted before the bill, depending on several factors. 

OBBBA is a “seismic shift” for the solar industry and has “fundamentally changed the federal policy landscape for energy,” the report concludes. 

“Instead of unleashing this American economic engine, the Trump administration is deliberately stifling investment, which is raising energy costs for families and businesses, and jeopardizing the reliability of our electric grid,” SEIA President Abigail Ross Hopper said in announcing the report. “But no matter what policies this administration releases, the solar and storage industry will continue to grow because the market is demanding what we’re delivering: reliable, affordable, American-made energy.” 

Much depends on the bill’s interpretation and execution. The provisions for the critical 45Y and 48E tax credits, for example, were not as bad as they could have been, while obstacles being erected to halt wind and solar power on public land are quite onerous. (See IRS Guidance on Wind and Solar Credits Not as Bad as Feared and Feds Pile on More Barriers to Wind and Solar.) 

The report notes: “The market reality for the solar industry will be shaped by federal policy actions and their outcomes in the coming months.” 

Michelle Davis, head of solar research at Wood Mackenzie, added: “There is considerable downside risk for the solar industry if the federal permitting environment creates more constraints for solar projects. The solar industry is already navigating dramatic policy changes as a result of [OBBBA]. Further uncertainty from federal policy actions is making the business environment for the solar industry incredibly challenging.” 

Other takeaways from the report include: 

    • Residential solar installations totaled 1.06 GW in the second quarter, down 9% year over year and 3% quarter over quarter; interest rates, concerns about the economy and policy uncertainty weigh on the sector. 
    • Commercial solar installations totaled 585 MW, a second-quarter record driven by California. 
    • Community solar installations totaled just 174 MW, 52% less than in the second quarter of 2025, as programs in major markets reach or approach their capacity with no significant new markets to take their place. 
    • The immediate impact of OBBBA is muted by the quantity of projects that already are under way; by the rush to start new projects in time to meet tax credit deadlines; and by an intense need for new electricity-generating capacity that cannot be met quickly enough with natural gas. 
    • Energy storage jumped to 26% of capacity additions in the first half of 2025 — the largest percentage ever, by a wide margin. 
    • U.S. solar module manufacturing capacity grew 4.3 GW to 55.4 GW in the second quarter, but there were no additions of upstream manufacturing capacity, such as for polysilicon, wafer or cell manufacturing. 
    • Power prices for Texas solar projects were 50% lower in 2024 than in 2023, contributing to a sharp decrease in deployment there in 2025. Nonetheless, Texas added 3.8 GW of solar capacity in the first half of 2025, more than half the national total. 
    • The cost of residential systems averaged $3.36 per watt DC, 2% higher than in the second quarter of 2024; commercial systems averaged $1.57, 10% higher; utility-scale systems averaged $1.25 for single-axis tracking installations and $1.11 for fixed-tilt, both 4% higher. 
    • Engineering/procurement/construction, permitting, logistics and other miscellaneous costs increased by an average of 30% over the second quarter of 2024 as risks associated with tariffs and policy uncertainty are priced into contracts. 
    • In the first half of 2025, 77% of all solar capacity installed was in states won by President Trump, including eight of the top 10 states for new solar installations: Texas, Indiana, Arizona, Florida, Ohio, Missouri, Kentucky and Arkansas. 

The new report comes on the heels of the announcement of a policy agenda that SEIA and its members will be pressing in national and state capitols in the coming months. 

“Solar and Storage Industry Policy Agenda for a Reliable, Secure Grid” offers a blueprint that includes modernizing energy infrastructure, supporting development of domestic supply chains and investing heavily in solar and storage technologies. 

It is a message that appears not to have resonated with the president and his Republican allies in Congress over the past 10 months, but SEIA called it a commonsense approach to meeting rising power demand and strengthening the grid. 

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Ontario Govt. Moves to Tighten Grip on OEB, IESO

Ontario’s Progressive Conservative government continues to put its stamp on the province’s energy policy, proposing legislation that would add “economic growth” to the missions of IESO and the Ontario Energy Board (OEB).

The Ministry of Energy and Mines posted the legislation Sept. 4, a day before the provincial government announced Geoff Owen as the OEB’s new chair. Owen, who has served on the board since 2021, was appointed chair at the recommendation of Minister Stephen Lecce.

The ministry’s proposed legislation is intended to support the province’s first Integrated Energy Plan, which seeks to ensure sufficient capacity for a forecast 75% increase in electric demand over the next 25 years. (See Ontario Energy Plan Gives IESO Long ‘To Do’ List.)

The bill would amend the Ontario Energy Board Act of 1998 and the Electricity Act of 1998 to update the missions of the OEB and IESO, making economic growth a “core consideration” in electric rulings and system planning. “The proposed amendments are targeted towards enhancing electricity transmission and distribution planning processes to account for the expediency of the electricity grid buildout to drive innovation and economic growth, and to strengthen self-reliance and energy security,” the ministry said.

In addition, the legislation would:

    • give the lieutenant governor authority to set connection requirements for data centers, which IESO projects will account for about 13% of new electricity demand by 2035.
    • allow rate-regulated entities to establish accounts to track increased costs that could result from territory-of-origin restrictions on energy procurements. The OEB would review for prudency and rate recovery.
    • expand the purposes of the Electricity Act to allow IESO to undertake clean hydrogen pilot projects with non-electricity applications such as transportation and industrial use.
    • amend the Ontario Energy Board Act to enable the OEB CEO to issue “scoped policies” such as timelines for adjudicative proceedings and the information to be considered, such as relevant government policy statements. “This authority would not bind commissioners to make determinations in alignment with government direction/policy,” the ministry said.
    • amend the Municipal Franchises Act to eliminate requirements that a municipality’s voters approve new natural gas municipal franchises. “The process to obtain municipal electors’ assent can be administratively burdensome and costly for some municipalities,” the ministry said. “Franchise applications often include a request to waive this requirement, and the OEB has granted that request in the vast majority of cases.”
    • implement the Future Clean Electricity Fund, which would make payments to non-emitting hydro and nuclear electric resources and transmission projects. The FCEF will be funded by the Emission Performance Standards program, which is designed to reduce greenhouse gas emissions from large industrial facilities by “setting standards, rewarding innovation and taking into consideration specific industry/facility conditions while allowing for economic growth,” the ministry said.

Blowback over Gas Ruling

The Progressive Conservative Party, led by Premier Doug Ford, has controlled Ontario since 2018, when it ended 15 years of Liberal Party rule.

After canceling hundreds of what it said were above-market renewable energy contracts, the Ford administration has committed to expanding renewables in the province. But it also is backing an expansion of nuclear power and continued use of natural gas. In support of its Integrated Energy Plan, the Ministry of Energy and Mines issued a prescriptive 12-page directive spelling out in detail how IESO is to carry out its policy, with sections on planning, district energy systems, distributed energy resources, transmission, low-carbon hydrogen strategy, hydro and nuclear generation, and export opportunities. (See Ontario Integrated Energy Plan Boosts Gas, Nukes.)

The OEB has attracted increasing attention from the government since the board’s December 2023 decision rejecting a rate proposal by Enbridge Gas. OEB said it would require Enbridge or developers to pay 100% of the cost of new natural gas connections in advance. The board said the previous policy, which spread the costs to consumers over 40 years, would result in stranded assets as the province moves to meet Canada’s 2050 target for net-zero greenhouse gas emissions.

In February 2024, then-Energy Minister Todd Smith announced legislation to reverse the OEB ruling and said he would appoint a new OEB chair.

“Natural gas will continue to be an important part of Ontario’s energy mix as we implement our pragmatic plan to invest in and bring online more clean nuclear energy,” Smith said. “Unlike the previous government, which saddled families with sky-high hydro bills, our government is taking a thoughtful approach that keeps costs down for people and businesses and delivers energy security.”

In addition to reversing the OEB decision, the Keeping Energy Costs Down Act, which was approved in May 2024, authorizes the minister to issue directives requiring the OEB to hold a generic hearing to determine any matter respecting natural gas or electricity.

The ministry said OEB’s decision could add tens of thousands of dollars to the cost of new homes.

But an analysis by Western University’s Ivey Business School concluded that “the government’s decision to override the OEB should have virtually no effect on affordable housing in the province. Based on our admittedly rough estimates, their policy might reduce the annual cost of buying a home by $92.74 or it could possibly increase it $32.90. Hardly seems worth damaging regulatory independence for.”

In a December 2024 report, Ontario’s auditor general challenged the ministry’s claim that the new law would have no impact on the environment. “The ministry did not explain that the proposed changes had the potential to increase greenhouse gas emissions by encouraging the continued construction of new natural gas infrastructure and continuing Ontario’s reliance on fossil fuels instead of shifting to electricity,” it said.

OEB Chair

Geoff Owen, chairman of the Ontario Energy Board | Foresight Strategic Advisors

Owen, a principal at Foresight Strategic Advisors, joined the board in 2021, becoming vice chair in 2024 and acting chair in April. He previously held executive positions at the Royal Bank of Canada in regulatory affairs, business strategy and public affairs. He also served in the offices of the Premier of Ontario, Minister of Finance, Minister of Economic Development and Minister of Municipal Affairs and Housing.

“Mr. Owen assumes his role at a pivotal time, as the Ontario Energy Board begins to deliver on the Minister of Energy and Mines’ Integrated Energy Plan directive and continues carrying out our core regulatory responsibilities while supporting Ontario’s economic, social and environmental development,” OEB said in a press release.

Owen replaced Mark White, who served less than a year after being appointed OEB chair in July 2024.