Arizona Commission Vote Tentatively Set for November 17 on Tucson Electric Power’s Annual Rate Reset

Administrative Law Judge Julia L. Matter issued a 278-page recommended order on October 20 endorsing most of Tucson Electric Power’s pending rate case, including an average residential bill increase of 11.2% and a mechanism that would reset the utility’s rates every year.

The Arizona Corporation Commission has an open meeting tentatively scheduled for November 17 to vote on the recommendation. New rates could take effect as soon as December 1, 2026.

The order. TEP requested a roughly 13% increase. Matter recommended a double-digit increase close to that request, raising average residential bills by 11.2%. She also recommended approving TEP’s Annual Rate Adjustment Mechanism, and rejected the due-process objections raised against it.

The mechanism. The ARAM would reset TEP’s rates annually, subject to Arizona Corporation Commission approval of each adjustment. That replaces the conventional pattern in which a utility files a general rate case every several years and rates sit static between proceedings. The recommended order treats the annual reset as a structural feature of TEP’s rate design rather than a one-time true-up.

What is not yet settled is whether the Commission agrees. The November 17 meeting is the first point at which the five commissioners weigh in on the recommendation, and the date itself is tentative.

The commercial schedules. Published coverage of the recommended order has reported residential bill impacts. The treatment of TEP’s commercial schedules, where demand charges sit and where a commercial battery earns its return, has not been reported. Anyone pricing a project on a Tucson commercial meter needs the rate design sections of the order itself before any payback figure goes into a financial model. The ACC e-Docket carries the full 278 pages.

Santee Cooper’s rate increase. South Carolina’s state-owned utility approved a different route to recurring rate movement. Its board voted unanimously on October 30 to raise bills roughly 9% across two years: residential rates rise 4.7% effective February 1, 2027 and another 4.6% in 2028, while commercial and industrial accounts take increases of about 2.1% to 2.9% in each of the two years.

Santee Cooper paired that with a change to demand measurement. Its new Balanced Demand Billing method charges residential and small commercial customers on the average of their maximum hourly use across the four highest peak periods each month, replacing a single highest-hour charge.

The two utilities arrive at similar territory by different instruments. TEP, if the Commission approves, would get a formula that updates annually. Santee Cooper has a fixed two-year schedule of increases already adopted. Both move rate changes onto a predictable calendar rather than leaving them to the episodic general rate case.

The financing variable. The cost of capital has become an explicit input into rate design arguments rather than a line in the financing footnotes. On Edison International’s October 29 earnings call, CFO Aaron Moss told analysts that elevated credit spreads could add roughly $300 million in customer costs across the bonds Southern California Edison expects to issue in 2027 alone, absent California wildfire reform by the November 15 constitutional deadline. CEO Pedro Pizarro said delay into 2027 would bring “dire and escalating impacts.” Southern California Edison carries a 2026 to 2030 capital plan of $38 billion to $41 billion, 12% of it wildfire management, and has recorded $1.8 billion in gross Eaton Fire settlement losses through the third quarter.

Those financing costs are recovered in rates, and recovery on the delivery side is where demand charges live. The mechanism differs from Arizona’s, but the underlying variable is the same: what a utility pays to borrow shows up in what a commercial customer pays per kilowatt.

What changes for a ten-year model. Commercial storage is underwritten against a tariff snapshot and an escalation assumption, usually a flat percentage applied to a rate sheet captured on the day the model was built. Under a multi-year rate case cycle, that assumption sits unexamined between proceedings and then absorbs a step change when new rates land. Under an annual reset subject to Commission approval, the escalation assumption becomes an observable event with a filing attached to it.

That favors better information for the customer. It also removes the long quiet stretch during which a savings model can drift from the bill it was built to predict. A rate path with more frequent, smaller adjustments is a different modeling problem than one with infrequent, larger ones, and for an asset sized against a dollar-per-kilowatt demand charge, the slope matters more than any single step.

Santee Cooper’s averaging change points at a second modeling question. A charge based on the mean of four peak hours behaves differently from one based on a single maximum interval: it softens the penalty for one bad fifteen-minute window, which changes the value of peak shaving against that particular rate design. Savings models built on single-peak logic do not transfer directly to an averaged-peak tariff.

What to watch. The November 17 vote, if it proceeds on that date, determines whether TEP operates under an annual reset. Should the Commission approve the recommended order, the first adjustment filed under the mechanism will be the first public evidence of what an annual formula does to a commercial bill in Arizona. Until then, the only document that answers the commercial question is the recommended order itself.

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