In unanimously approving a far-ranging settlement agreement affecting utility rates, the California Public Utilities Commission August 20 approved an 8 percent system-wide average rate hike for Southern California Edison. Also approved was more spending for demand-response programs at all of the state’s investor-owned utilities. “It’s a flattening of generation rates,” noted California Public Utilities Commission president Mike Peevey. Commissioner Dian Grueneich said, however, that the hike would average 11 percent for residential ratepayers. “That’s a pretty steep rate increase,” she said. Peevey noted that the new rate structure--to be applied from 2009 to 2012--is meant to encourage the use of low-emission vehicles “fueled” during off-peak hours. Vehicles would be set on a time-of-use tariff. Conservation is another aim. The move was based on a settlement--mainly for large power users--for “phase two” of the utility’s general rate case. Edison is not the only utility affected by the settlement. Regulators also included the state’s other two investor-owned utilities for funding demand-response programs. In keeping with regulators’ focus on lowering energy use during peak periods, the decision funded continuing demand-response programs administered by Edison, Pacific Gas & Electric, and San Diego Gas & Electric at $350 million. Of that, Edison was allowed $38 million for contracts with demand-response aggregators such as Comverge and Enernoc. In total, Edison increased its revenue requirement from ratepayers by nearly $189 million, PG&E by $109 million, and SDG&E by $51.6 million for demand-response programs. Demand-response is supposed to shave the requirement for peaking power and thus reduce the number of power plants expected to be built to ensure sufficient electricity on high-demand days. As a rule, a medium-sized fossil fuel plant costs about $500 million, plus the price of any transmission for hooking it into the grid. Unlike demand-response, an additional power plant adds to global warming and air pollution. The settlement was approved unanimously. In other action aimed at getting ahead of the alternative vehicle curve, the commission opened a docket to explore how to build and fund infrastructure expected for alternative fueled vehicles. “We have to ready the electricity system” to handle plug-in vehicles, said Peevy. He said the state “anticipates large-scale deployment” of alternative vehicles. They may run on a number of sources including electricity, hybrid electric power using gasoline, natural gas, or biodiesel. In other alternative energy decisions, the commission approved a solar contract between PG&E and Bright Source for 310 MW at Ivanpah. The project is supposed to go online beginning in 2012. If completed, the contract would count for 5 percent of PG&E’s renewable mandate under state law--which now stands at 20 percent of the utility’s total electricity portfolio, according to Julie Fitch, director, CPUC energy division.