California already has some of the highest electricity rates in the country. Those costs could rise even faster over the next decade, as utilities harden their grids against wildfires, grow their share of net-metered rooftop solar and add other costs that will be passed through to utility customers.
But recovering those costs by charging customers by the kilowatt-hour pushes too much of the burden on those least able to pay, according to a new report from the University of California at Berkeley. That’s not just unfair to the state’s most vulnerable residents, the report argues — it could also make it more expensive to electrify transportation and building heating with carbon-free power.
To combat this, the report proposes a novel and admittedly radical solution — cutting back on the volumetric per-kilowatt-hour charges on customers’ bills and recovering the missing money through constructs tied to customers’ income.
That could be done by directly recovering a range of fixed utility costs through state sales or income taxes, although the idea of the state collecting taxes and shifting them to the state’s investor-owned utilities may well be politically unpalatable, the report notes.
An alternative method would be to assign fixed charges to customers based on their income, with the wealthier paying more and the less well-off paying less — a path that comes with its own political and administrative challenges.
Either approach would require state legislation to create a structure for the California Public Utilities Commission to share these responsibilities with state tax authorities, Severin Borenstein, director of the Energy Institute at UC Berkeley’s Haas School of Business and the report’s lead author, said in a Monday interview.
But without some intervention along these lines, California could see its volumetric electricity costs rise far faster over the coming decade, he said. That could drive commercial and industrial customers out of the state, weaken public support for the state’s clean energy goals and drive residential customers to “more gasoline usage and more natural gas usage” rather than toward electric-powered alternatives, he said.
The problem of raising rates to cover California’s myriad costs
That view is backed up by a new CPUC report that forecasts the costs of wildfire mitigation, electric-vehicle charging infrastructure and other capital investments by Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric will force rate increases that will substantially outpace inflation through 2030.
Customers who can afford rooftop solar systems, behind-the-meter batteries or other distributed energy resources to offset those rising rates may be able to mitigate them, the CPUC noted. But that will leave customers without those resources on the other side of a “growing divide in the cost of service.”
The CPUC is in the midst of revisiting the full retail-rate net-metering policies that California has had in place since 2016. That process sets the stage for a battle between rooftop solar companies and utilities over the proper balance between continued support for solar growth on one hand and managing the cost shifts from solar-equipped customers to utilities and customers without solar on the other.
Borenstein has advocated for changing net-metering policy to reduce this cost shift, a stance he acknowledges has won few friends in the solar industry. But the problem with California’s rising rates extends beyond rooftop solar policy, he said.
“The actual incremental cost going forward of producing electricity is not much higher in California than everywhere else,” he said. But maintaining and growing grid infrastructure, energy-efficiency spending, low-income-customer support services and other fixed costs now make up two-thirds to three-quarters of the total costs being recovered by utilities through volumetric rates, according to his team’s research.
That amounts to an “incredibly regressive tax” on utility customers at large, he said, with lower- and middle-income customers paying a larger proportional share of total income to cover their utility bills.
Some of these fixed costs can be mitigated by shifting electricity use from times when power is both expensive and carbon-intensive — say, during the post-solar demand peaks that led to the state’s rolling blackouts in August — to times when it’s cheaper and cleaner, such as overnight or during midday solar peaks. The time-of-use rates set to roll out across California’s utilities in the coming year could help on that front, as could load modification and demand-response programs.
But the Energy Institute’s research indicates that the majority of fixed costs can’t be time-shifted, he said. Transmission and distribution grid investments make up more than half of these costs, for instance. Only a fraction of these costs is likely to be able to be reduced by shifting demand to reduce peak loads on congested circuits.
At the same time, the state’s growing wildfire risks are pushing utilities to invest tens of billions of dollars in grid hardening, vegetation clearing, and fire detection and prevention technologies. California’s aggressive renewable energy targets, meanwhile, will require new transmission to connect remote solar and wind power to population centers.
The promise and challenges of income-based monthly charges
The Energy Institute’s proposed fix would start by setting the volumetric rates that customers pay at the “avoidable cost that is time- and location-specific” — in other words, at a rate that accounts for the cost of generating and delivering the energy to the customers paying for it at the time it’s consumed. That in itself would be a departure from the relatively undifferentiated retail rates paid by most customer classes across California.
It would also leave a “significant cost recovery gap” for the state’s big three utilities — $4.3 billion for PG&E, $3 billion for SCE and $1.1 billion for SDG&E, according to the report’s example rate structure estimates. Dividing those figures by each utility’s residential customer accounts yields a gap of between $74 to $59 per household per month that will need to be made up.
California’s existing sales and income tax structures could then guide how that cost is recovered from customers with different income levels, with customers in the lowest 20 percent of income distribution exempt. A sales-tax-based mechanism would yield monthly fixed charges ranging from about $45 for lower incomes to as much as $150 for the highest. An income-tax-based distribution would widen those monthly charges from as low as $27 to as high as $186.
These monthly charges will be offset by much smaller per kilowatt-hour charges upfront. Even so, fixed monthly charges have proven unpopular as a proposed mechanism to recover utility fixed costs, whether from solar net metering customers or customers at large. Meanwhile, reducing the portion of the bill charged for kilowatt-hours used will undercut the value of net-metered solar under the state’s current regime.
But Noel Perry, a former venture capitalist and founder of Next 10, the nonprofit that funded the Energy Institute’s report, argued that failing to take steps to adjust the state’s electricity pricing regime soon could undermine the state’s goal of decarbonizing its economy in an equitable way.
“Our focus from the beginning had to do with achieving our climate goals here in California,” he said. “What I didn’t understand,” before the report’s analysis revealed it, “was the equity component of electricity pricing and those that it is hurting the most.”