Fifteen years after blackouts rolled through some California neighborhoods, utility customers are still feeling the effects of post-energy-crisis regulatory changes that pushed the risk of costly projects from utility investors to ratepayers.
This little-noticed change in how utility rates are set has had profound repercussions for utility customers, leaving them on the hook for billions of dollars even when projects fail.
- Southern California Edison spent $680 million to replace steam generators at the San Onofre nuclear plant. The generators proved faulty, leaking a small amount of radiation. Current cost to ratepayers for the botched project and plant closure: $3.3 billion.
- Edison collected $31.9 million for an upgrade at the Mohave Generating Station, which closed at the end of 2005 after the Nevada coal-burning facility was found in violation of the Clean Air Act. Total customer bill for upgrade and closure: $122 million.
- Pacific Gas & Electric Co. scrapped a plan to build a 1,000-mile transmission line to Canada after partners PacifiCorp and others pulled out. Edison abandoned a separate line in Arizona after failing to get a permit. Total cost to ratepayers for the projects, which were dropped in 2011: $20 million.
- Now, in the aftermath of a natural gas leak near Porter Ranch, Southern California Gas Co. customers might be required to pay for in-progress upgrades to the Aliso Canyon natural gas field even if the facility never reopens. Potential cost: $200 million or more.
“Shifting the costs of bad bets and stupid bets is akin to stealing,” said Loretta Lynch, an outspoken former president of the California Public Utilities Commission. Putting the risk on consumers, she said, “has allowed the utilities to spend like drunken sailors.”
Before the 2001 blackouts, a decades-old regulatory policy known as “used and useful” meant that customers wouldn’t bear financial responsibility for new utility projects until they were benefiting from them. Regulators vetted completed projects before utilities could collect money from customers to ensure that the investments in power plants, transmission lines and other projects were needed and being used.
Roderick Wright was a Democratic assemblyman from Los Angeles when he wrote the legislation that changed regulatory policy. Wright said he was motivated by the state’s energy crisis, when electricity prices soared through a combination of power shortages and market manipulation, pushing Edison and PG&E into technical insolvency and making them unable to borrow money to build capital projects.
The law tells utilities and Wall Street, “‘If you make this investment, Southern California Gas Co. or Edison, we will make sure you get your money back,’” Wright said in a recent interview. “It put some level of certainty back into the marketplace so that they were creditworthy.”
New projects are a way for utilities to bolster their revenue because they collect as much as 11% of a project’s cost. That’s the state’s way of ensuring vital services such as electricity and natural gas are available when customers need them.
“They have to keep feeding the beast to make their profit,” said Lynch, the former utility commissioner.
The changes in the law contributed to a building boom. Over time, however, the altered approach has led to weaker consumer protection, said San Diego lawyer Michael Aguirre, a longtime critic of the utilities and how they charge their customers.
Now, there is little accountability — even when projects fail, Aguirre said.
“Whatever the utilities want, the CPUC will make sure they will get from the ratepayers,” said Aguirre, a former San Diego city attorney. “It’s resulting in billions of dollars in cost for what is not used or useful to utility customers.”
PUC Commissioner Mike Florio raised concern about abandoning the “used and useful” principle in an April 2013 vote that gave deference to a utility over ratepayers in a dispute over a San Clemente water project.
“The basic reasoning behind the used and useful principle is that ratepayers should only pay for [a] utility plant that is actually benefiting them,” Florio wrote in his dissent.
In a recent interview, Florio said determining how costs are divvied between ratepayers and shareholders is a complex decision shaped by politics, regulators and the energy issues of the day.
PUC President Michael Picker, who joined the agency two years ago, said that determining who pays — especially when projects go wrong — is a balancing act.
“You have to kind of decide it on the facts,” said Picker, adding that because of his limited tenure he doesn’t know all the history. “I will confess that I tend to rely on staff legal analysis.”
State and federal policies are designed to look at the big picture, said Maureen Brown, an Edison spokeswoman, adding that customers have long shouldered various costs of developing, maintaining and shuttering parts of the electric grid.
“Shutdown and decommissioning costs,” Brown said, “are a necessary component of generating plant operations and appropriately paid for in rates by customers who benefited from the plant’s generation prior to shut-down.”
But what about when a project never materializes, a plant closes prematurely or an existing facility fails to meet standards?
That’s where utilities across the country have learned to hedge their bets.
States including Florida, Georgia and South Carolina have passed legislation to allow utilities to charge their customers in advance for projects. Supporters of the policy said paying as the utility incurred expenses would save consumers money in the long run by reducing their finance charges — essentially using customers’ pocketbooks as collateral on their loans.
But for consumers, the practice has yielded financially disastrous consequences.
In Florida, a subsidiary of Duke Energy was able to charge its customers in advance for upgrades at an existing nuclear plant and for a proposed nuclear facility. Both projects failed, forcing the 2013 permanent closure of the Crystal River nuclear plant 70 miles north of Tampa, Fla., and costing Florida ratepayers more than $3 billion.
California’s similar practice has been too costly for utility ratepayers, said Matthew Freedman, an attorney for the Utility Reform Network, an advocacy organization that represents consumers before the commission.
“We are frustrated with the historic treatment of utility investments in facilities that prematurely shut down,” Freedman said. “The Legislature should modify state law to require that utility shareholders assume their fair share of risks.”
Without that consumer protection, utilities are allowed to retain whatever money they can when there are problems.
Edison kept the $680 million it was given preapproval to collect for San Onofre’s failed steam generators in 2010 and 2011, said Terrie Prosper, a commission spokeswoman, “as the plant was used and useful at that time.”
But the project’s usefulness didn’t last long: Even after the generators proved faulty, no reviews were conducted into what went wrong. The commission ultimately approved a deal, which is now being reexamined, that forced ratepayers to shoulder $3.3 billion for closing the plant and purchasing replacement power; shareholders absorbed $1.4 billion of the costs.
Aguirre and Lynch fear the PUC may follow a similar path with Aliso Canyon if it closes prematurely.
Just as with the San Onofre nuclear plant, the commission approved the nearly $201-million upgrade to replace old compressors at the Aliso Canyon natural gas storage facility with no intention of an after-the-fact review — unless the costs exceeded projections.
By the end of 2015, the commission said, Southern California Gas had spent $162 million on the upgrade.
With nearly $201 million on the line, the stakes are high to return Aliso Canyon to service.
State leaders continue to weigh the future of the plant and energy agencies recently warned of the potential for blackouts without the facility’s natural gas. The utility says it has not determined the cost of closing the storage facility.
Sen. Fran Pavley (D-Agoura Hills) has said that two-thirds of the Porter Ranch residents want to see Aliso Canyon closed for good. PUC chief Picker said he is working to keep the gas field open to ensure electricity and natural gas reliability.
Melissa Bailey, a spokeswoman for Sempra Energy, the parent company of Southern California Gas, said no money for the upgrade has been collected from the utility’s customers to date.
“The project must be deemed ‘used and useful for utility service’ prior to requesting authorization in rates,” Bailey said.
But Lynch said that’s just semantics: Based on the commission’s approval, Southern California Gas arguably can start collecting the $200.9 million whenever it wants.
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