What's Happening in Energy highlights the most interesting findings from public utility commission filings.
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What's Happening in Energy — Oct 3
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Starting in Washington, Puget Sound Energy (PSE) responded to follow-up questions from the Washington Utilities and Transportation Commission after a meeting in early June. One question asked for more information on trends in wildfire liability insurance premiums. PSE responded with a chart showing a 329% cumulative increase in liability premiums. Eagle-eyed readers will notice the Y-axis units are…¯\_(ツ)_/¯
PSE explained the increases occurred for two main reasons:
“While pricing remains high for wildfire liability insurance, PSE observed that having a wildfire mitigation plan and successfully implementing those plans, along with Commission approval of wildfire mitigation investments, are factors that can help secure more capacity and obtain better pricing in the casualty insurance market. Premium increases are expected to be slightly lower than last year’s 16% increase, provided there are no major fire incidents in the utility sector or fires linked to PSE operations in the near term.“
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Staying in-state, the Washington Utilities and Transportation Commission granted Avista’s accounting petition to defer costs associated with tariffs on electricity and gas imported from Canada. Regular readers will remember Halcyon mentioned that energy imported across the northern border was the subject of a few dockets back in May 2025.
So: although Avista was only briefly exposed to $17,808 in electric tariff costs from March 4th through March 6th before the tariffs were suspended, the Commission deemed the uncertainty high enough to meet the “extraordinary circumstances standard.” The Commission also granted Avista’s request to account for tariff costs separately, so that they would not be included in the deadband range that permits recovery of fluctuating gas prices via the utility’s Power Cost Adjustment Mechanism (PCAM) rider. Outside of this price range, PCAM (also called the Energy Recovery Mechanism, or ERM) provides for cost sharing between the utility and customers:
“In its Petition Avista argues that because it is unclear whether the tariffs will be reflected in embedded costs of the Canadian commodity or flow through the ERM, if the annual overall variance were to fall within the deadband, Avista would be required to absorb 100 percent of the costs associated with the tariff. Avista reasons that since it could not have reasonably known about the tariffs when its power supply base was set in its last general rate case, it should not be penalized for costs outside the utility’s ability to control.”
“We therefore grant Avista’s request in its Petition for deferred accounting treatment for the costs of energy resources imported from Canada and authorize deferral of those expenses for recovery in Avista’s ERM, not subject to the ERM deadband or sharing bands. We do so as it pertains to costs accrued from March 4, 2025, through March 6, 2025. However, we will continue to monitor the tariff situation moving forward and may adjust our treatment of tariff costs if needed.”
Read the full Order:
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In South Carolina, Duke Energy Carolinas and Duke Energy Progress filed a third cost-benefit analysis to the Commission to support their joint application to merge their businesses.
According to this third analysis, system benefits would outweigh costs by approximately $2.3 billion. The model calculated benefits as the reduced revenue requirement relative to the “Cost to Achieve” the merger. According to supporting testimony, benefits are primarily from the combined utility’s ability to plan system resources more efficiently, execute upon that plan more efficiently, and operate those resources more efficiently.
Costs to Achieve would ramp up starting in 2030, but estimates suggest that the reduction in revenue requirements would far outweigh these costs.
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In California, the California Energy Commission filed the transcript from an early August workshop on the Commission’s Energy Demand Forecast Inputs and Assumptions. Of note (and no surprise): the below quote from the Demand Analysis Branch at CEC (page 21 of the linked transcript). Only one year ago, CEC forecasted 3.5 gigawatts of new data center load for the entire state. Right now, Pacific Gas & Electric alone has 13GW of capacity in the queue.
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In Virginia, Rappahannock Electric Cooperative (REC) is applying for authority to provide collateral for its subsidiaries (referred to as Dedicated Service Affiliates, or DSAs, in the application) to access PJM’s power market (Power Market Access—PMA).
The application states that access to PJM is necessary to provide power supplies to large load customers under the new Large Power Dedicated Facilities Schedule LP-DF tariff currently pending before the Commission. We’ve bolded the good bits below:
“Recent discussions with potential Schedule LP-DF customers, banks, and PJM have made clear, however, that in some instances Rappahannock will need to provide the financial support necessary to permit the DSAs to establish the PMA Collateral rather than that credit support being supplied directly by the customer. To mitigate risk to the Cooperative and its members, REC intends to make this arrangement available only to large load customers with investment grade credit ratings (or whose parent companies have high quality investment grade ratings), where Rappahannock may accept a parent company guaranty from the customer and translate that creditworthiness, through one of the transactions for which authority is requested into this application, into the cash collateral required by PJM, effectively serving as the financial intermediary between the customer's credit support and PJM's cash collateral requirements. In any event, the customers will still be responsible for all costs incurred by the Cooperative.”
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In New Mexico, Southwestern Public Service (SPS) submitted a Certificate of Convenience and Necessity application to the Commission to construct 4,103 MW of “Self-Build” generation projects required to address resource adequacy needs (identified in the 2023 IRP and procured through a 2024 RFP).
SPS argues that these projects are necessary to comply with Southwest Power Pool’s new Planning Reserve Margins of 16-17% in the summer and 36-38% in the winter. SPS is also requesting a CCN for three 345 kV lines to service the new capacity.
Additionally, SPS requested to extend the retirement date of its Tolk 1 and 2 coal generation units by three months from December 31, 2028 to the end of March 31, 2029. The utility also requested an exception to the Renewable Energy Act requirement that all retail sales must be zero-carbon by 2045 for their Gaines and Tolk gas plants: “As explained by Ms. Lees, SPS also asks the Commission to recognize, under § 62-16-4(B), that SPS may need to continue relying on the Gaines County and Tolk gas plants after 2045 to preserve system reliability and protect customers from unreasonable bill impacts.”
Dig into the supporting testimonies:
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In Florida, Tampa Electric responded to a Public Service Commission data request asking the utility to explain why projects were delayed. Two energy storage projects, Wimauma and Lake Mabel, were delayed by two months compared to the Commission Order in-service date, due to extended “battery balancing and charging time.” The utility provided a clear explanation for this issue:
“In general, a group of batteries should stop charging when the first battery reaches 100 percent charged, even if the other batteries have not reached 100 percent charged. For example, once the first battery reaches 100 percent, the other batteries may only be 90 percent charged. The same concept happens when discharging to 0 percent. It is normal for a new battery project to have some imbalances. Performing several cycles of charging and discharging balances the batteries’ charges so that they all reach 100 percent or 0 percent charge at the same time, which is the most efficient way to operate them. Tampa Electric’s supplier had to spend more time than expected conducting those charge and discharge cycles to achieve battery balance.”
Other projects were set back by delays in procuring equipment such as Generator Step Up transformers and gas control skids. One project, the “Grid Reliability and Resilience-Grid Communication Network,” is still waiting to receive a Federal Communications Commission license. “The current frequency holder is clearing the spectrum for Tampa Electric’s use to ensure no other companies operate on the same frequency.”
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Small fish in a big state. In Texas, the Texas Public Power Association (TPPA) and Texas Electric Cooperatives, Inc., (TEC) commented on the Commission’s Proposal for Publication to eliminate the “small fish” rule in ERCOT, per recommendations from the Independent Market Monitor (IMM).
Yes, it’s really called the ‘small fish’ rule, and it exempts independent power products that own less than 5% of ERCOT generation from being considered capable of exercising market power. Eliminating this rule would mean that these smaller producers could be subject to penalties for exercising market power, or violating their “Voluntary Mitigation Plans” (VMPs) that producers owning more than 5% of generation currently file with the Commission to explain how they avoid exercising market power.
TPPA strongly recommends maintaining the current rule, claiming that administering the repeal would subject the Commission to reviewing a burdensome amount of VMPs and excessively distort the fluid pricing mechanisms in ERCOT. TPPA continues …
“In addition to potential due process concerns, this recommendation would essentially put either the IMM or ERCOT in charge of resolving the identified pricing issue based on their idea of where prices ought to have resolved. This is in direct opposition to how the ERCOT market is meant to operate, where market forces set prices, not regulators…“
TEC states although does not dispute the IMM’s reasoning, the timing may be inappropriate for such a change given:
“Elimination of the small fish rule places the peaker fleet in ERCOT at risk at a time when ERCOT, the Commission, and the Legislature are actively seeking ways to support new generation.”
The report notes that benefit estimates from the ICE calculator are likely an underestimate since the survey results that informed the calculator are from 1989 to 2012.
“The developers of the ICE calculator have also noted significant advancements in the societal use of electronic devices, in-home life-saving medical devices, and other technologies, including a higher number of people working from home. With most of the surveys being completed before these advancements, the developers of the ICE Calculator consider the current cost of interruptions for residential customers to be conservative. The developers of the calculator have received additional funding to update the surveys to reflect these key changes, especially the value of residential interruptions in a post-pandemic society.”
ICE 2.0 was released shortly after the publication of the BCR report. However, according to the report, “Due to recent societal changes in patterns of energy consumption for residential customers, the DOE ICE Calculator value of interruptions is likely low for this customer class. The developers of the DOE ICE Calculator expect this value to increase once updated surveys are completed.”
Check out the BCR report linked below for visualization of the BCRs for different grid infrastructure investments such as wood pole replacement and distribution automation.
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And if you’ve read this far…this past week in Texas there were ~40 filings related to batteries. These items ranged from adding a battery energy storage system, to an existing power generation company registration, to opposition of a specific location for the multi-state multi-location generation resources (equivalent to 4.103 MW costing $10 billion, also referenced above in NM), to the Texas Energy Buyers Alliance requesting the Creation of a New Energy Attribute Certificate Program.
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