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California Energy Markets / Bottom Lines

[March 3, 2017 / No. 1426]

The Great, Green Quandary

In a recent post on the Energy Institute at Haas blog, James Bushnell took issue with a Los Angeles Times article that noted Californians are already paying billions for excess generation capacity the state doesn't need. As a result, California's retail electricity prices are about 50 percent higher than the national average.

The Times article blamed the high electricity prices mainly on a glut of natural gas capacity and poor decisions by state regulators. For starters, California is expected to have a planning reserve margin of about 21 percent in the next three years. CAISO guidelines call for a 15 percent reserve margin, and experts say only a 10 percent PRM is needed.

The Times article also pointed to Calpine's 578 MW Sutter Energy Center, which began operating in 2001 and had to close down last year because it could not obtain a resource-adequacy contract. The plant was not needed, the Times says, because in 2007 the CPUC approved the 657 MW Colusa power plant owned by Pacific Gas & Electric.

Not once did the Times mention all the renewable-energy capacity that has come on line as a contributor to higher rates. Bushnell produced a chart showing that about 80 percent of all capacity additions since 2010 have been renewables. That comes to about 10 GW of new capacity.

I'll add that in the early years of the renewables portfolio standard, many of these contracts came with extremely high prices. As those power plants become operational, the bills come due and utility generation rates rise. Between 2011 and 2016, for example, PG&E's generation rate rose 45 percent.

One example: In 2015, two large solar power plants came on line—the 550 MW Desert Topaz and 330 MW Desert Sunlight projects. The costs of these contracts were reflected in higher fees charged to community choice aggregators such as Marin Clean Energy. MCE's fee for leaving PG&E service rose 94 percent at the end of that year (see CEM No.1393 [7]).

Another factor in rising electric rates is transmission. For basic residential service, PG&E's transmission rate jumped by 20 percent from 2011 to 2016. Southern California Edison transmission rates, meanwhile, jumped 45 percent from September 2012 through the end of last year. Looking ahead, expenses will rise. Bushnell notes that the Tehachapi Transmission Project, finished in December and designed to access wind in Southern California, cost $2 billion. I'll further note that in its recent earnings call, Edison said it was poised to spend $2.4 billion for transmission just between 2020 and 2021.

'Customer rates are rising while (conventional) generation sources are simultaneously struggling for revenue.'

Neither Bushnell nor the Times mention distribution rates, which might rise with utility spending on electric-vehicle infrastructure and grid modernization. In its recent yearly earnings call, Southern California Edison pegged capital spending at around $5 billion between 2018 and 2020. While traditional distribution expenses would be flat or declining during that stretch, the grid-modernization and transmission expenses would represent billions more in new annual spending (seeCEM No. 1425 [15]).)

And so we arrive at the great, green quandary: Renewables, by virtue of having no fuel costs, suppress wholesale energy prices, meaning that gas-fired generators that are needed to balance wind and solar can't earn as much as they used to in energy markets. Yet the capacity cost of all these renewable-energy contracts is high. Those costs, as well as associated transmission, get passed on to ratepayers via higher utility bills.

"The result is the seemingly perverse situation where customer rates are rising while (conventional) generation sources are simultaneously struggling for revenue and threatening to retire," Bushnell wrote.

In addition to Sutter's retirement, the owners of the 1,022 MW La Paloma power plant filed for bankruptcy last year after they were unable to obtain a contract (see CEM No. 1417 [12]). Meanwhile, other gas-plant shutdowns are looming:

  • Calpine announced last year its intent to retire four peakers at the end of this year, though two of them—the 47 MW Feather River Energy Center and the 47 MW Yuba City Energy Center—may receive a "reliability-must-run" designation from CAISO, meaning they could continue to operate.
  • Cogentrix has warned that two of its Southern California peakers (with about 199 MW of combined capacity) are currently without resource-adequacy contracts, and two of its Northern California power plants with a combined capacity of 288 MW will be without RA contracts next year.

According to a 2016 letter Calpine wrote to CAISO, the cost of operating a combined-cycle gas turbine is approximately $60/kW-year, but the payment for resource-adequacy capacity in the North of Path 26 area is $29.28/kW-year. Energy-market revenues don't make up the difference.

CAISO has been exploring ways to tweak its tariffs to allow needed gas-fired capacity to survive, including a new payment stream for flexible capacity. Already the grid operator has seen ramps of 15 GW over a three-hour period, and has forecast that by 2024, up to 13 GW of power may need to be curtailed in spring months. Just this spring, CAISO has forecast curtailment of up to 8 GW (see CEM No.1425 [12]).

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CAISO's efforts may take time to materialize. In the meantime, the great, green quandary poses this question: How much is California willing to pay for excess flexible capacity as it cruises past a 33 percent RPS on its way to 50 percent?

Although California energy rates are high when compared to other states, average residential bills have been some of the cheapest for coastal residents, mainly due to low energy consumption on the coast and energy efficiency. But even that's changing: Due to the collapsing of rate tiers, PG&E residential rates rose to an average of $110 per month, placing the utility in the middle of the pack nationally, about equal to average bills in Oklahoma, according to 2015 data from the U.S. Energy Information Administration.

"As the renewables fleet expands to meet the higher RPS target there will be no steady-state offset of new renewables for old," Gary Ackerman, executive director of the Western Power Trading Forum, wrote in an email. "The money for renewables and keeping thermal around for flex is going to go up." –Chris Raphael


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