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December 13, 2025

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Analysts to Western Regulators: Wildfire Risk is Issue du Jour

PORTLAND, Ore. — Western states must deal with the high risk wildfires pose to the financial health of the region’s utility sector, investment analysts told regulators at the annual meeting of the Western Conference of Public Service Commissioners.

“That is the inextricable conversation du jour in the West — period. There is no bigger conversation we’re going to have,” Julien Dumoulin-Smith, managing director at investment banking company Jeffries, said during a June 2 panel to discuss electricity affordability issues.

For Dumoulin-Smith, the issue comes down to one key topic: “We have to talk about wildfire tort reform.”

Dumoulin-Smith, an equity analyst who covers the energy sector, focused on how wildfire risk could hamper Western utilities from raising capital to fund infrastructure projects. He said the West is “a fire or two away” from having a “truly unfinanceable outcome” for investing in the grid.

“The impact is actively being felt when you look at the cost of capital across the West,” he said. “It’s not in the ether; it’s actually dollars and cents to utility ratepayers today.”

Dumoulin-Smith finds it “striking” that the industry stakeholders seem to think there’s an “inevitable amount of money that we have to spend towards wildfires,” which is increasing the portion of ratepayer bills dedicated to mitigating wildfire risk.

And despite the thinking of some in the industry, he contended, California’s Assembly Bill 1054 — passed in 2019 to establish a fund for utilities to tap to cover wildfire damages claims — has not resolved the risk exposure issue for the state’s utilities. (See California Wildfire Fund Could be Model for US, Panelists Say.)

Dumoulin-Smith pointed to the Los Angeles fires in January as an example of California’s continued vulnerability to catastrophic fires, despite having the most advanced wildfire planning in the West.

“When you look at what happened in L.A., it’s not about who was at fault or what have you. It’s looking at wildfire mitigation plans in California [and] recognizing the clear ongoing deficits that exist in wildfire mitigation, period. It’s about recognizing that, ‘Wait, our state doesn’t even engage in wildfire mitigation that is as deep and as intense as in California, and that happened despite all the planning they did,’” he said.

Dumoulin-Smith told the regulators in the audience that if they’re not taking the risk issue seriously, it will work against their plans for investing in the grid.

“Because it is devastating to the ability to invest and the cost of capital. It’s extremely expensive to invest in a wildfire regime that is inhospitable,” he said.

He said different states “have vastly different” policies related to wildfire liability, and while seemingly “trivial,” they “are actually quite expensive differences.”

“So, I think start with that. I mean, who’s at the table, and how do we introduce a problem statement in general?” Dumoulin-Smith said.

‘All Perspectives’

During a separate panel discussion, Edna Mariñelarena, an assistant vice president at Moody’s Ratings, said investors want to understand the level of risk and return on their investments, and wildfire is “one of those high-risk questions” investors are asking on top of others related to utility infrastructure needs. They want to know what Western states are doing to mitigate those risks, she said.

“So ‘coordination’ is a word that we all say, but it’s one of those things that really needs to be taken very heavily, because it’s not just a utility problem, it’s an economic problem,” Mariñelarena said. “If you don’t have a healthy utility, you don’t have economic development that’s going to continue to feed the economy and jobs and regular people, right?”

Speaking on the panel with Dumoulin-Smith, former Idaho utility commissioner Paul Kjellander, now a senior adviser with Public Utilities Fortnightly, posed the question of how a utility can address any kind of investment “when the cost of capital is ridiculous,” or if it must adjust capital expenses “to recover from the liability associated with a wildfire.”

That diversion of funds prevents investments in new transmission and distribution, system hardening and resilience.

“Avoiding some of the catastrophic events — and reducing the financial impact of that — now has to go to something completely and totally different, and I’m not putting a single new kilowatt-hour into the system,” Kjellander said. “Somehow, we have to change that dynamic, and we need to do it with an idea of affordability at front and center.”

Nina Suetake, deputy director of policy at the National Association of State Utility Consumer Advocates, said that while tort reform might address one aspect of the wildfire issue, it could provoke another — namely, hindering the ability of people in wildfire-prone areas to obtain insurance against fires.

“While I understand from a financial perspective you can’t continually bankrupt a utility, the second you put liability caps on, you’re also going to impact the trust gap, and it’s going to widen even further,” she said.

Suetake advocated for a “holistic” approach to dealing with wildfire risk, examining it from “all perspectives.”

“You sort of have to bring all of those voices to the table and understand all the impacts if you don’t want to just exacerbate one of the problems,” she said. “In the end, the ratepayers are citizens of your state, so it’s all going to affect the same people; either it’s coming from tort liability or increased taxes or increased rates.”

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Hail Remains Costliest Risk for Solar Farms

Hail remains the most expensive threat to photovoltaic solar panels but far from the most common, the 2025 edition of an insurer’s risk report indicates. 

Hailstones accounted for only 6% of incidents resulting in losses to solar panels, but those losses amounted to 73% of the total, kWh Analytics noted June 10 as it announced its seventh annual “Solar Risk Assessment.” 

Fires, hurricanes, inverter failures and damage from severe convective storms other than hail rounded out the top five sources of financial loss. Damages from those four types of incidents all were reported more frequently than hail, however. 

The report brings together academic, technology, financial and insurance insights on the solar energy and battery energy storage system (BESS) sectors. 

The threat picture is important to understand, kWh said, because solar and storage are an increasingly large part of the U.S. energy portfolio while facing increasing threat from climate change. 

“As renewable energy becomes the backbone of the electrical grid, ensuring system resilience is no longer optional — it’s imperative,” kWh Analytics CEO Jason Kaminsky said. “Keeping these assets operational requires unprecedented collaboration among asset owners, operators, financiers, insurers, brokers and manufacturers.” 

The Energy Information Administration in February reported a record 30 GW of utility-scale solar was added to the U.S. grid in 2024, accounting for 61% of capacity additions. It reported June 10 that it expects solar to rise from 5% of U.S. power generation in 2024 to 8% in 2026. 

The Solar Energy Industries Association reported June 9 that the total nameplate capacity of all classes of installed solar generation — utility, community, commercial, residential — stands at 248 GW nationwide. 

Takeaways from analyses by kWh and industry partners for the 2025 “Solar Risk Assessment” include: 

    • Thicker glass and better stow protocols can reduce the probability of hail damage. 
    • Cyber threats are increasing, and so must protection strategies — solar and BESS facilities offer multiple attack points, and the integration of their diverse systems only increases exposure. 
    • A significant factor in fire damage is overgrown vegetation. Better management of vegetation and wiring can mitigate risk of fire, which is second to inverter failure in frequency and second to hail in cost. 
    • New research shows wildfire smoke can reduce an affected solar facility’s annual revenue by as much as 6%, double the amount cited in kWh’s 2022 Solar Risk Assessment. 
    • The weather-adjusted performance index lags industry expectations by 8.6% nationwide, with the largest underperformance seen in winter and a gradual decline seen in the nine years analyzed; performance data is insufficient to pinpoint a root cause, but better understanding of the phenomenon would reduce financial risk and boost investor confidence. 
    • Performance-degrading hot spots on individual modules continue to be a concern, highlighting the importance of the compatibility of components within systems and suggesting the need for industrywide collaboration and early identification of systemic issues. 
    • Artificial intelligence can be a powerful tool for risk assessment but needs to be fine-tuned. In one analysis, out-of-the-box AI models miscalculated up to 20% of solar operational issues, struggling especially with weather-related and damage losses. 
    • Factory quality-control inspections are finding issues with 28% of BESS fire suppression systems and 15% of thermal management components. Non-conforming materials, poor workmanship and insufficient quality control were commonly cited causes. 
    • While a handful of BESS failures continue to occur each year, the massive buildout of these systems has dropped the number of failures per installed GWh of capacity 98% from 2018 to 2024. 
    • Much more common are state of charge estimation errors for lithium phosphate batteries — the error rate can exceed 15%. 
    • There is a disconnect between BESS technical performance and financial oversight: Operation and maintenance staff who were surveyed reported finding far more technical issues than asset managers reported. A strategy to collect, analyze and share the billions of datapoints generated is essential to maximizing the systems’ value.
    • This last point is not academic. The report cites one customer’s history of uneven cell discharging, which led to a performance loss of 18 MWh per day that grew to roughly $1 million in annual losses. 

Climate insurance provider kWh Analytics draws its insights from a database of more than 300,000 zero-carbon projects and $100 billion in loss data. 

For its 2025 report, kWh drew on its own analyses and those from Central Michigan University Assistant Meteorology Professor John Allen, Kiwa PI Berlin, 60Hertz Energy, VDE Americas, GroundWork Renewables, Radian Generation, Zeitview, Clean Power Research, Clean Energy Associates, EPRI, ACCURE Battery Intelligence and TWAICE. 

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NYISO Monitor Proposes Changing Congestion Rent Assignments

The NYISO Market Monitoring Unit is proposing to revise the ISO’s net congestion rent assignment process by allocating residuals to transmission owners on an individual facility basis.

Congestion rent is collected by the ISO from load and paid out through transmission congestion contracts (TCCs). Residuals can arise when there is a difference in internal transfer capability between the day-ahead market and what was assumed in the TCC auctions. They represent the difference between the congestion rent required to fund payments to TCC holders and the amount of rent collected.

Currently residuals are assigned to TOs depending on the reason for the congestion, and some situations leading to residuals are socialized among TOs based on their respective shares of TCC auction revenues. Under the MMU’s proposal, however, “the TO that owns the ‘offending’ transmission facility would absorb or pay the shortfall associated with their facility,” it said.

The MMU says this would improve the incentives for transmission investment and operating grid-enhancing technologies, and reward efficient transmission operations, including line switching.

NYISO is on board with the change, but it needs to do a significant amount of modeling and simulating of the change’s impacts on the markets first. The ISO plans to propose a dedicated “Net Congestion Rent Assignment Evaluation” project as part of its 2026 prioritization process.

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Talen, Amazon Enter PPA for 1.9 GW of Power from Susquehanna

Talen Energy and Amazon Web Services (AWS) have entered into a power purchase agreement for the Susquehanna nuclear generator to supply 1.9 GW to the tech company as its retail supplier. 

“Amazon is proud to help Pennsylvania advance AI innovation through investments in the commonwealth’s economic and energy future,” AWS Vice President of Global Data Centers Kevin Miller said in an announcement of the June 11 agreement. “That’s why we’re making the largest private-sector investment in state history — $20 billion — to bring 1,250 high-skilled jobs and economic benefits to the state, while also collaborating with Talen Energy to help power our infrastructure with carbon-free energy.” 

The agreement is effective through 2042 and will ramp up to the full 1,920 MW by 2032. The announcement states the two companies will explore possible uprates to the generator, as well as the installation of small modular reactor (SMR) resources within Pennsylvania. 

“This long-term transaction will significantly decrease Talen’s market risk and minimize its reliance on the federal nuclear production tax credit,” the announcement states. 

The deal ratchets up a partnership between the two companies that includes a data center co-located with Susquehanna, an arrangement Talen has sought to expand. FERC rejected an amendment to Susquehanna’s interconnection service agreement (ISA) that would have increased the amount of power serving the co-located load from 300 MW to 480 MW. (See FERC Rejects Expansion of Co-located Data Center at Susquehanna Nuclear Plant.) 

Following a configuration of the transmission around Susquehanna in spring 2026, the co-located data center would shift from being behind the generator’s meter to receiving full grid service. The change will occur at the same time as the generator’s scheduled refueling outage. 

“Our agreement with Amazon is designed to provide us with a long-term, steady source of revenue and greater balance sheet flexibility through contracted revenues. We remain a first mover in this space and intend to continue to execute on our data center strategy,” Talen CEO Mac McFarland said. “Talen is well positioned to support Amazon’s energy needs as it invests further in the Commonwealth of Pennsylvania.” 

Susquehanna would remain available for PJM dispatch under the PPA, with transmission and distribution service provided to the data centers by PPL. 

“PPL Electric Utilities is investing in the resiliency of its transmission system so we can better serve our customers, meet growing energy demands and ensure power is delivered reliably,” PPL Electric Utilities President Christine Martin said. “Connecting large load customers like data centers to our transmission system helps lower the transmission component of energy bills for all customers, as large load customers pay significant transmission charges on our network. We’re excited to be part of Amazon’s broader investment in Pennsylvania and look forward to the positive effects it can have for our customers and the local economy.” 

In an analysis of the transaction, financial firm Jefferies said it believes front-of-meter deals will become the norm going forward. The firm estimated that when the transaction fully ramps up, it will be worth between $82 and $88/MWh, higher than Jefferies’ earlier $75/MWh estimate and above other recent PPAs between nuclear operators and tech companies. 

“We believe this puts to bed the debate on BTM nuclear in PJM, consistent with our long-held view. We expect FTM involving hyperscaler companies paying full transmission charges or virtual (i.e. financial/carbon deals) in future transactions,” Jefferies wrote. 

Siting data centers behind generators’ meters has been a point of contention for state regulators and FERC. Proponents have pushed for clearer rules on the practice and argued it would increase the efficiency of the grid, reduce network upgrades and create flexibility for loads that don’t require all the characteristics that come with full network service. 

Opponents say co-location could allow the load to avoid paying for ancillary services, like regulation or black start, that they consume. PJM also has posed engineering challenges with behind-the-meter load, saying its rules are designed for small configurations and protective relay failures could cause reliability issues. 

Nuclear generators have been of particular interest to data centers looking for co-location opportunities or PPAs. Meta and Constellation energy announced a PPA on June 3 for the output of the 1,121-MW Clinton nuclear generator in Illinois, and another Constellation deal with Microsoft is set to revive the Three Mile Island Unit 1 as the Crane Clean Energy Center. (See Constellation, Meta Sign 20-year Nuclear PPA.) 

Pennsylvania Gov. Josh Shapiro (D), U.S. Sen. Dave McCormick (R) and U.S. Rep. Dan Meuser (R) threw their support behind the agreement in the announcement. 

“My administration is going to continue to bring people together to attract new investment to Pennsylvania, and we stand ready to work with Talen Energy and its partners to review permits for this project as efficiently as possible,” Shapiro said. 

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MISO IMM Blasts NERC Long-term Assessment, Says RTO in Good RA Spot

MINNEAPOLIS — MISO Independent Market Monitor David Patton called NERC’s Long-Term Reliability Assessment inaccurate for labeling the RTO a high-risk area and said he believes it is in a good reliability position.

“We find that it is completely inaccurate. MISO should not be colored in red,” Patton said at a June 10 Markets Committee meeting of the MISO Board of Directors.

Patton faulted NERC for apparently conflating installed capacity with unforced capacity in the assessment’s totals. He said NERC tallied unforced capacity values for MISO when calculating a margin that it ultimately compared to an installed capacity requirement. He said the blunder lowered the footprint’s capacity sums on paper by more than 10 GW.

“I don’t frankly understand how they did this,” Patton said. “They basically presented an apples and oranges assessment.”

NERC’s Long-Term Reliability Assessment predicted MISO could be confronted with capacity shortfalls in 2025. It assumed the RTO would have 132.2 GW in generating capacity, or 124.4 GW after factoring in all retirement announcements. (See NERC Warns Challenges ‘Mounting’ in Coming Decade.)

Ahead of summer, MISO reported it has 143.1 GW in offered capacity available to it to meet a likely 123-GW annual peak. (See MISO Prepping for Likely 123-GW Summer 2025 Peak.) Altogether, the RTO has 203 GW of installed capacity.

Patton said NERC’s lapse is influencing national policy, evidenced by the Department of Energy’s directive to keep Consumers Energy’s 1.4-GW J.H. Campbell coal plant in Michigan operating over the summer. (See Consumers Energy Seeking Compensation for Keeping Campbell Open.) He said NERC’s projection could bleed into other rule changes.

“That sort of initiative can lead to FERC ordering market changes that are unnecessary,” Patton said.

Patton also said MISO overstated load predictions used in NERC’s assessment by submitting non-coincident peak forecasts instead of coincident peaks, raising its load requirements and lowering the calculated capacity margin.

Patton said of the four RTO markets he monitors, “I would say MISO is most reliable of the four.”

“It seems like a combination of errors that seems correctable here, but there isn’t a path for correction,” MISO Director Barbara Krumsiek said.

Patton said he hopes NERC will rectify its methods that inform the long-term assessment by the next December report. He said he has reached out to NERC and committed to working with the regulatory authority on its approach.

Michelle Bloodworth, CEO of coal lobby organization America’s Power, questioned whether it was appropriate for the MISO Market Monitor to question a “credible institution” such as NERC. She said she believed MISO’s “elevated risk” status under the assessment was apt.

Bloodworth praised DOE’s actions to keep J.H. Campbell available for a little while longer. She noted that Cleco’s 568-MW Big Cajun II Unit 1 shuttered March 31 due to a settlement decree; she said having the coal plant online at the time might have helped matters during MISO’s load shedding orders in the New Orleans area on May 25. (See NOLA City Council Puts Entergy, MISO in Hot Seat over Outages.)

At the same meeting, MISO said it likely will manage higher-than-normal temperatures paired with drought over the summer.

“If you’re dry and have a pervasive heatwave going on, it can compound challenges in the operating room,” MISO Executive Director of Market Operations JT Smith said.

Smith said a doubled-in-size solar fleet also likely will test MISO’s ramp and regulation capabilities in its ancillary market. He said MISO operators could be managing unavailable resources and higher-than-expected load throughout summer.

As part of a five-year update, Vice President of Operations Renuka Chatterjee said MISO finds itself in the most “dynamic and demanding” operating environment it ever has. She cited steeper evening ramps and mounting long-duration outages, forecasting challenges and stability risks.

MISO entered summer June 1 with a $666.50/MW-day capacity price, signifying the premium the RTO has put on new capacity. (See MISO Summer Capacity Prices Shoot to $666.50 in 2025/26 Auction.)

Carrie Milton, of the IMM staff, said if generation operators would have held off on powering down about 1.6 GW until September, it would have lowered capacity prices to $472/MW-day in the summer.

But Milton said the Campbell plant is not factored into MISO’s clearing prices and isn’t necessary for reliability during the season. She said MISO’s auction already returned a better than one-day-in-10-years standard without the large coal plant.

“We are more than adequate,” Patton said. He repeated that he has “no material concerns” over MISO’s resource adequacy for the upcoming summer.

Patton said factoring in imports and typical planned and forced outages, MISO has a comfortable, 12.2% reserve margin.

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MISO Reapplies for Generator Interconnection Fast Lane with FERC

MINNEAPOLIS — MISO has put a second proposal for a fast-tracked interconnection queue lane in front of FERC, a mere three weeks after the commission rejected the RTO’s initial proposal.  

This time, MISO said it will hold to a 68-project limit before retiring the express lane and require regulators to verify in writing that a proposed project will either address a resource adequacy risk or accommodate previously unaddressed load growth in the footprint (ER25-2454).  

FERC rejected MISO’s first try to establish the fast track; the commission said MISO failed to limit the number of projects that could apply and failed to predicate expedited treatment on resource adequacy needs. (See MISO Going for 2nd Attempt to Fast Track Power Plants in Queue; FERC Rejects MISO’s Interconnection Queue Fast Lane.) 

During a June 10 System Planning Committee of the MISO Board of Directors, MISO’s Aubrey Johnson said RTO staff knew when drafting the first proposal that changing how certain megawatts “flow” through the queue was going to be an uphill battle.

Johnson said this time around, MISO made the proposal less open-ended by introducing the 68-count limit on projects that get expedited treatment.  

MISO committed to processing 10 fast-track applications per quarter for five quarters. Additionally, it added placeholders for 10 projects from independent power producers who have power purchase agreements with non-utility entities and an additional eight projects that can be submitted only by retail states for resource adequacy deficiencies.  

Johnson said MISO edited language to make it clearer that Illinois’ retail choice setup and Michigan’s partial retail choice construct are welcome.  

The fresh filing also stipulates that projects must reach commercial operation within three years of developers filing an application.  

MISO said it will shelve use of the express lane either by Aug. 31, 2027, or when it satisfies the 68-project limit, whichever comes first.  

MISO’s interconnection queue count as of mid-2025 | MISO

Johnson said MISO is aware that it moved fast to refile the proposal within three weeks of MISO’s original rejection.  

“When we think about the changes we made … we feel they’re appropriate because they’re narrow,” Johnson said. He said MISO spent several months refining its original proposal, and the limited revisions and cap keep the original intent of the express lane intact.  

MISO Director Barbara Krumsiek said she noticed that there was still no “grading” of projects by their resource adequacy contributions.  

Johnson said the states, not MISO, decide what’s appropriate to maintain resource adequacy.  

Sustainable FERC Project’s Natalie McIntire complained that MISO’s rapid refile cut short stakeholder review and discussion of the revisions. She reminded board members that FERC expects MISO to allow its stakeholders meaningful input on proposed rule changes before the RTO submits them for approval.   

As MISO reattempts an interconnection express lane, it’s poised to have a banner year for new generator interconnections.  

Johnson said MISO estimates that over 2025, it can usher a record-breaking 10.9 GW in nameplate capacity through its queue that would boil down to 6.2 GW in accredited capacity. So far this year, MISO has processed 2.2 GW worth 1.2 GW after applying accreditation.  

MISO’s traditional queue contains 294 GW across 1,568 projects.  

Johnson added that MISO still has 56 GW in generation projects that are cleared to interconnect to the system but remain unfinished. Just five companies are responsible for 40% of those incomplete projects, Johnson said.  

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Expanded EDAM Would Reduce Curtailment, Costs, Study Finds

California Energy Commission staff presented a study on the size of CAISO’s Extended Day-Ahead Market (EDAM), finding more benefits as the market’s footprint increases.

The study, completed by The Brattle Group, is an update to one originally published in January, intended to provide a better picture of the benefits of day-ahead markets in California and the West. The original did not include the Western Energy Imbalance Market (WEIM), which is used as the “Status Quo” scenario in the new version.

Including this scenario helps “show the full impact of a West-Wide EDAM footprint, including how it might affect today’s WEIM as participants leave to join SPP Markets+,” staff said in a fact sheet on the subject. The updated study also includes an analysis of lower natural gas prices in EDAM and an analysis of the change in market revenues for California solar resources from EDAM expansion.

The new study comes as utilities decide whether to join EDAM, which will open in 2026 with its first members, PacifiCorp and Portland General Electric. More participants plan to join in 2027 and future years.

“Generally speaking, day-ahead markets are advantageous because they can deliver cost savings to customers through efficiency gains,” Kai Van Horn, senior consultant with Brattle, said at a CEC public workshop June 5. “They can deliver environmental benefits through lower emissions, generally through better utilization of renewables.”

Brattle’s study looked at four market scenarios alongside the status quo:

    • “Baseline,” which includes the entities EDAM is expected to launch with in 2026;
    • “Baseline+,” which also includes likely market participants;
    • “Expanded EDAM,” which includes the maximum number of entities that could participate; and
    • “Split Market,” which shows entities operating under both EDAM and Markets+.

The Expanded EDAM scenario estimates more than $1 billion per year in economic benefits to California compared to the status quo. A larger EDAM also could increase investments in renewables in the area, thereby accelerating emission reductions in WECC, the study says. Greenhouse gas emissions, for example, would decline 58% in California and 39% in the West, respectively, compared to 2024. Revenues for solar increase by about $14/MWh in California in the expanded scenario compared to the status quo.

Annual curtailment would drop from about 26,000 GWh yearly in the status quo to about 8,000 GWh in the Expanded EDAM scenario. Lower curtailments may allow fewer resources to be built to meet renewables targets in the state, the study says.

Even with the initial formation of EDAM, curtailment in California will decrease significantly: a 64% reduction in solar curtailments and 61% reduction in wind, the study found.

In the Split Market scenario, costs and emissions also decrease. For example, emissions drop by 24 MMT/year. In the Expanded EDAM scenario, GHGs drop 25 MMT/year. Similarly for curtailment, the Split Market case shows about 10,000 GWh yearly, compared to 8,000 GWh in the Expanded scenario.

For large solar plants, the market value in California increases from about $-3/MWh in the status quo to $11/MWh in the Expanded EDAM, “largely due to the ability to export otherwise unused solar in midday hours when solar is abundant,” according to the fact sheet. The increased market revenues for solar transfer to customers through lower power purchase agreement costs, the study says.

CAISO is working on key initiatives related to EDAM as the day-ahead market nears operation. In June the ISO plans to decide on a key initiative in EDAM: how congestion revenues are allocated.

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Calif. Bill Seeks to Control Electric Bills, Create Transmission Authority

A California bill that would take aim at soaring electric bills and create a transmission infrastructure authority has cleared the state Senate and now is being considered in the Assembly. 

Senate Bill 254 by Sen. Josh Becker (D) was passed by the Senate 29-10 on June 4. It’s now in the Assembly, where it had its first reading. The bill is an “urgency” measure that would take effect immediately upon adoption. 

SB 254 is a sweeping bill with nine major provisions, which Becker said would save ratepayers “tens of billions of dollars” over the next several years. He called it “the legislature’s most ambitious effort ever to rein in rising energy costs.” 

“This is not a set of modest tweaks that will make minor improvements at the edges of a problem without offending anyone,” Becker said. “This is a big deal.” 

What’s in it?

SB 254 would exclude from electric utilities’ equity rate base a collective $5 billion spent on fire risk mitigation capital projects starting Jan. 1, 2025. Similarly, $10 billion collectively spent on energization capital projects would be excluded from the rate base.

The bill would create a Power Fund, to be funded by the legislature and used to reimburse utilities for “expenditures driven by public policy goals that provide a benefit to the general public.” Those could include transportation or building electrification programs or wildfire mitigation, among others. 

The California Energy Commission would decide how money from the Power Fund is spent. Utility spending that’s reimbursed from the Power Fund would be excluded from the rate base, and infrastructure paid for through the fund would not be eligible for return on equity. 

SB 254 would require utilities to include in their rate case filings a scenario in which spending would not go up more than the projected amount of the Social Security cost of living adjustment (COLA). The CPUC still could approve spending greater than the COLA if it’s deemed necessary for safe and reliable operation. 

Transmission Authorities

SB 254 proposes the creation of the Clean Energy Infrastructure Authority (CEIA) for transmission projects. The authority would identify transmission corridors; plan, finance, acquire and own transmission lines; serve as lead agency under the California Environmental Quality Act; and exercise eminent domain powers. 

The authority would enter into agreements with utilities to build, operate and maintain the transmission infrastructure. 

The California CEIA would be similar to two transmission authorities now operating in the West: the New Mexico Renewable Energy Transmission Authority (RETA) and the Colorado Electric Transmission Authority (CETA). 

“Establishing transmission authorities continues to be a critical policy lever for states, especially those without [an RTO], to consolidate and formalize transmission planning processes,” the National Caucus of Environmental Legislators said in a policy update in April. 

The group said lawmakers in Washington, Oregon and Montana had introduced bills this year to establish new transmission authorities.  

Affordability Issues

SB 254 is part of a three-bill package, intended to address affordability issues in California, that Senate president pro tem Mike McGuire worked on with the Democratic caucus. The other two bills address housing production and workforce development. 

“Skyrocketing housing costs and utility bills are stretching budgets, and folks are struggling to achieve a job that pays a family-sustaining wage,” McGuire said in a statement announcing the bill package in April. 

But opinions differed on whether SB 254 is part of the solution. 

Sen. Kelly Seyarto (R) pointed to “unrealistic mandates” as the cause of rising electric bills. 

“[Utility companies] are going back to the CPUC time and time again,” Seyarto said. “Because we are mandating that we attain unrealistic goals for all electric vehicles, for everything being electric in California. And they’re trying madly to try and get the infrastructure, which means wires everywhere.” 

Sen. Steven Choi (R) said creating a new transmission authority would increase costs. 

“Who knows how much money this agency will be using to establish and implement the programs and create the policies and employ the employees to run that authority?” Choi said. 

Other Provisions

Among other provisions in SB 254, the bill aims to provide near-term relief to electric utility customers by increasing the amount of the “climate credit” they see on their bills each April and October. The credit is part of the state’s cap-and-trade program.  

Low-income customers would get a greater share of the climate credit under SB 254, and it would be paid out in late summer when many residents are hit with their highest electric bills. 

In a permit streamlining measure, the bill would direct CEC to develop a program environmental impact report for energy storage systems of 200 MW or more. Agencies then could build on that more generic EIR when developers propose specific projects, reducing the time needed to prepare an environmental report. 

SB 254 also would lower the project-size threshold for a project to be eligible for the CEC’s opt-in certification program, from $250 million to $100 million. It would extend the life of the program by five years, through June 2034. 

The opt-in program is for renewable energy projects such as solar, onshore wind and energy storage systems. Under the voluntary opt-in process, the CEC becomes the lead agency for permitting and state environmental review. The CEC certificate is in lieu of any permit that normally would be required through the local land-use review process and most state permits. (See 2 Huge Solar-plus-storage Projects Planned in California.) 

SB 254 also would require the CEC to try out permitting management software to further streamline project review. 

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EIA Increases 2025, 2026 Electric Sales Forecast

The U.S. Energy Information Administration has revised its forecast upward for retail electricity sales — especially in ERCOT and PJM and largely because of anticipated commercial demand.

In its Short-Term Energy Outlook released June 10, EIA projected that commercial consumption would increase 3% in 2025 and 5% in 2026. It previously predicted an average of 2% in the two years.

EIA expects total generation this summer to be 1% higher than last summer, also from commercial and industrial load growth, and it expects less generation from natural gas-fired plants because of higher natural gas prices.

The Henry Hub spot price forecast is about $4/MMBtu for 2025 and $4.90 in 2026, on average, compared with $2.20 in 2024, EIA said.

Solar generation is projected to increase from 5% of the U.S. total in 2024 to 8% in 2026 and wind from 11% to 12%.

Natural gas is projected to dip from 42% of the total in 2024 to 40% in 2026, coal from 16% to 15%, and nuclear from 19% to 18%. The outlook for hydro is a steady 6% of the total in all three years.

Breaking it down geographically:

    • Electricity sales are expected to increase from 2024 to 2026 in every region except New England, with the largest increase in the West South Central region — from 716 TWh in 2024 to 810 TWh in 2026, a 13.1% jump.
    • The same two regions had the lowest and highest all-sector electricity prices in 2024 and are projected to hold the same ranks in 2026: West South Central would rise from 9.73 cents/kWh to 10.16 while New England would rise from 23.06 to 25.79.
    • Total power generation by grid region is expected to increase or decrease from 2024 to 2026 by small percentages with two exceptions: PJM is projected to jump 7.6% from 873 TWh to 939, and ERCOT is projected to jump 19.8% from 459 TWh to 550, both from increased renewable, natural gas and coal generation.

Factoring into the report are the economy and the weather. The forecast assumes real GDP growth at an annualized 1.4% in 2025 and 1.7% in 2026.

It also assumes an easing of the trade wars and a reduction in tariffs but notes that future trade policy is a source of uncertainty in the outlook, as is consumer spending, which is projected to grow much more slowly in 2025 and 2026 than in 2024.

EIA also assumes 2025 will be slightly cooler than 2024, which was warmer than average. This allows a 5% reduction in predicted 2025 cooling degree days and a resulting decrease in electricity demand.

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Wright Addresses Recent Orders Keeping Power Plants Open at Hearing

Energy Secretary Chris Wright testified about his department’s 2026 budget request at a House hearing where members often pressed him on other issues, including his recent use of the Federal Power Act to keep coal plants from retiring. 

“The Trump administration has been laser focused on raising energy costs for Americans, despite what the president campaigned on,” Rep Frank Pallone (D-N.J.) said June 10. “And the example came in the last month when your department ordered two power plants burning coal, natural gas and fuel oil to stay online mere days before they were scheduled to shut down for good.” 

Pallone asked at the hearing of the Energy and Commerce Subcommittee on Energy who had made the decision to keep open Consumer Energy’s J.H. Campbell coal plant in Michigan and Constellation Energy’s Eddystone natural gas-fired plant outside Philadelphia. 

Wright answered that he had; Pallone then quickly moved on to press him about how much money it will cost to keep Campbell running, quoting an estimate from the Michigan Public Service Commission of tens of millions of dollars. Consumers has filed a complaint with FERC seeking compensation from MISO’s north and central zones, saying it is tracking costs and will file a specific number at the end of the summer. (See Consumers Energy Seeking Compensation for Keeping Campbell Open.) 

PJM is taking a different path, working with stakeholders to come up with a way to pay Constellation to implement DOE’s order. (See PJM Board Initiates CIFP Process for Eddystone Compensation.) 

“Mr. Secretary, your background is in the oil and gas sector, not the electric sector,” Pallone said. “So, why do you think that you knew better than the grid operators, utilities and the state regulators to actually try to revive these even though no one seemed to care? Why are you increasing electricity prices for millions of people?” 

When it comes to the Campbell plant, Wright said MISO had a blackout just two days after DOE announced that it would keep running this summer, past its retirement initially planned for May 31. (See MISO Requires Load Shed in New Orleans to Avoid Grid Instability.) 

“MISO [has] the tightest reserve margin we have in the country,” Wright said. “You need to be able to keep the lights on. Two days later, the lights went out.” 

Pallone responded that the outage in New Orleans was a different part of the market. Entergy’s territory is in MISO South, which has limited transmission links to its central and north regions and is not subject to cost recovery for running the plant this summer under Consumers’ FERC filing. 

Rep. John James (R-Mich.) asked about the Campbell plant later in the hearing, specifically asking whether Michigan’s and other states’ net-zero energy policies had contributed to the situation in MISO. 

“Many people at DOE have been in dialogues with NERC and with MISO about these issues, but I think you hit the nail on the head,” Wright said. “What do we want? We want to reshore manufacturing to Michigan. We want to bring data centers to Michigan. We need to grow the supply of affordable, reliable electricity in Michigan.” 

Closing a coal plant 15 years before the end of its intended lifespan works against that goal, with Wright saying Michigan officials made the decision for “virtue signaling.” 

“That’s not the best interest of Michigan ratepayers and Michigan citizens,” Wright said. “But, yes, utilities get bullied and influenced by state politicians and national politicians that have political agendas around energy that are often not aligned with ratepayers and citizens.” 

James then made a pitch for Consumers’ proposed allocation for the plant, spreading it across 12 other states in MISO’s north and central regions so that the contract is not “financially punitive” to Michigan customers. 

“MISO is a large organization,” James said. “Where this power is dispatched is going to benefit a larger organization and, so, therefore, those costs should necessarily be spread out, as we all have to make sure that we are cooperating to make sure that we keep our power high and keeping our costs low.” 

Rep. Julie Fedorchak (R-N.D.) used her time for questions to note that she introduced the Baseload Reliability Protection Act with seven other Republican co-sponsors that would keep dispatchable power plants open to help the grid meet growing power demand. 

“Given that NERC’s assessment today is that two-thirds of our systems in the U.S. don’t have enough power to meet demand given certain circumstances today, and we’re looking at retiring 115 GW of baseload generation, and we’re seeing significant demand increases — all of that looks like a huge train wreck to me and to many others,” Fedorchak said. 

The bill would prohibit the retirement or conversion of dispatchable power generators in areas NERC has identified as having “elevated reliability risks,” protect those plants from any fines from noncompliance with environmental rules, and allow DOE to offer grants and loans to support needed plant upgrades and extend operational life. The bill provides exemptions when continued operation poses safety risks or is economically unviable. 

Wright said the policies in the bill align with what DOE has been working on to ensure the grid can accommodate new demand from data centers and reshored manufacturing. 

“We have a team in our Office of Electricity that’s looking at grid reserve margins across the different areas of the country,” Wright said. “And we’re looking at planned retirements, and then we’re going to try to proactively engage with all of them.” 

“This might be a five-year thing,” Fedorchak said. “This might not be forever, but right now, we’re behind, so let’s stop retiring. Let’s make sure we’re bringing new resources on as quickly as possible. I stand with my colleagues across the aisle to work on permitting reform, to bring things up as quickly as possible. But meanwhile, we need to keep what we have. That should not be a partisan statement.”