IOUs tell Little Hoover Commission higher bills stem from wildfire work, policy decisions; urge state funding shifts and NEM reform

Pedro Nava, chair of the Little Hoover Commission, opened a hearing on California electricity costs with a reminder that the session would focus on what drives rising bills and what utilities propose to do about them. He introduced witnesses from investor‑owned utilities, municipal utilities, and community choice aggregators.

Adam Smith, director of regulatory relations at Southern California Edison, told commissioners that the industry operates under a “regulatory compact” in which utilities have an obligation to serve, submit capital plans to regulators and raise private capital to pay for approved projects. “We have an obligation to serve,” Smith said. He said investor‑owned utilities must attract capital in public markets and that rating agencies closely watch the regulatory and legislative environment; SCE was on “negative watch,” he said, meaning higher borrowing costs could follow and be passed to customers.

Shilpa Ramayana, vice president of regulatory proceedings and rates at Pacific Gas and Electric, walked commissioners through a graphic breaking down an average customer dollar: “32¢ of each dollar is the cost … to generate and buy electricity,” she said; about 31¢ covers state‑mandated programs (PG&E identified wildfire safety work as roughly 16¢ of the dollar), about 22% covers operating, maintaining and upgrading the grid, 10% is the authorized profit, and taxes account for about 5%. Ramayana said residential customers without solar pay roughly 15% more to cover grid costs for solar customers (PG&E said that share rose to about 18% in 2025).

Both witnesses stressed two related points: many recent cost increases are tied to policy choices and to wildfire mitigation investments, and utilities see tools that can reduce bills if adopted. PG&E and SCE urged the state to: shift some public‑purpose programs from ratepayer funding to the general fund; reform net energy metering (NEM) to transition NEM‑1/2 customers to NEM‑3 after 10 years or upon sale; consider securitization and other financing options selectively; and expand use of cap‑and‑trade allowances or reform the climate credit to smooth customer bills across critical months. Ramayana said those measures “offer solutions that can provide customers relief immediately” and also help longer‑term affordability.

Both witnesses warned of tradeoffs. Smith said overreliance on debt or policies that “undermine the regulatory compact” could harm credit ratings and raise borrowing costs. Ramayana described recent steps PG&E has taken that reduce near‑term bills: reductions in some wildfire cost recoveries, renegotiated renewable contracts, self‑insurance arrangements, and returning unused authorized program funds to customers. PG&E said combined gas and electric bills average about $300 per month and that the company expected 2026 procurement costs to be lower than 2025.

Commissioners pressed witnesses on several fronts: why investor‑owned utility rates remain higher than public utilities in many places; whether securitization is being used enough; the role of the general rate case (GRC) in setting longer‑term cost trajectories; and how load growth and data centers could affect future bills. Witnesses repeatedly distinguished between costs largely controlled within utility operations and costs driven by external policy choices or by emergency‑driven spending such as wildfire mitigation.

The hearing concluded with commissioners and staff noting follow‑up issues — including the Public Utilities Commission’s role in rate setting and oversight — to be examined in later hearings.