California may face the biggest regional power shortages in more than a decade this summer, sending wholesale prices higher, as idled nuclear reactors and low hydroelectric output cut generating capacity.
The California Independent System Operator Corp. said last month that managing the state grid, especially in parts of Southern California, will prove “difficult” because the system will be operating without Edison International’s San Onofre nuclear power plant and two natural gas-fired units, while hydroelectric output will be at a three-year low. The nuclear plant, California’s single largest source of baseload power, accounts for 3.7 percent of the state’s capacity.
Southern California wholesale electricity for July through September already is at the highest level for this season since 2008 on the outlook for a shift to costlier, more volatile fossil fuels. A strain on the grid could lead to power failures reminiscent of the state’s worst energy crisis in 2000 and 2001, when generation shortfalls and market manipulation by traders at companies including Enron Corp. sent prices to record highs and triggered blackouts that affected millions of customers in the most populous U.S. state.
“California may see the biggest test since Enron manipulated the market,” Stephen Schork, president of Schork Group Inc., an energy consulting group in Villanova, Pennsylvania, said in an April 15 interview. “If you have a reactor down and you don’t have as much hydro, your fuel for air conditioning is going to have to come from gas.”
Electricity at Southern California’s SP15 hub for July through September rose 30 cents, or 0.5 percent, to $61.55 a megawatt-hour today, a five-year seasonal high.
Power at the SP15 hub for next-day delivery has averaged $49.92 a megawatt-hour this year through April 19 on the Intercontinental Exchange, the most for the period in five years. Northern California’s NP15 hub has averaged $41.99 this year, the most since 2010.
The shutdown of the San Onofre reactors boosted prices at the southern hub to an average premium of $7.97 a megawatt-hour against the northern hub, the most in 12 years. The five-year average is 97 cents.
Abundant hydroelectric generation made up for the lost nuclear output in the Los Angeles basin last year, Michael Blaha, the principal analyst of North American power at Wood Mackenzie Ltd. in Houston, said in an interview.
“There is always a threat of brownouts and blackouts and I think it’s higher this summer because of San Onofre being out and you’re not putting hydro into the basin,” he said.
Final snowpack measurements, which are used to predict the output at hydropower dams, will be 45 percent to 50 percent of normal, according to Maurice Roos, chief hydrologist with the state’s Department of Water Resources in Sacramento. Only six years in the past 60 have been that low, he said.
Low water levels in the U.S. Northwest may also cut electricity exports to California this summer, according to the Bonneville Power Administration, a federal agency that manages Columbia River basin power supplies. Transmission lines across the Oregon-California border have a combined capacity of 7,500 megawatts.
The snow-water equivalent in the region was 90 percent of normal today, the lowest level for the time of the year since 2010, U.S. Agriculture Department data show. Genscape Inc., which tracks real-time plant data, said April 4 that Northwest hydropower is down 36 percent from a year ago.
Unless there is a surge in precipitation in April through June, the amount of water available for hydro in the Northwest will be lower than it has been in the past two years, Doug Johnson, a spokesman for the BPA in Portland, Oregon, said in an April 18 e-mail. Water levels exceeded historical norms by 30 percent in 2011 and 20 percent last year, he said.
California, with a population of 38 million, struggled with similar hydropower shortages during the electricity crisis of 2000 and 2001. The state, the world’s ninth largest economy, was also dealing with unplanned power-plant shutdowns, a natural-gas pipeline rupture, unseasonably high temperatures and price manipulation by Enron and other companies.
Enron, once the world’s largest energy trader, filed for bankruptcy in 2001 following revelations that it used off-balance-sheet vehicles to hide billions of dollars in losses and inflate its stock price. Chief Executive Officer Jeff Skilling was convicted of fraud in 2006 and sentenced to 24 years in prison.
The shortages prompted regulators to overhaul state energy policy, which now requires utilities to show they’ve contracted enough power to meet demand.
“The high Northwest hydro of last year probably obscured potential operation problems” on the California grid because of lower nuclear generation, Blaha said. “If we move to the other extreme of low hydro, we can move back to an environment like the energy crisis of 2000.”
The San Onofre generating station, located about 4 miles (6.4 kilometers) southeast of San Clemente, has been shut since January 2012, when workers discovered unusual wear on steam generator tubes in both reactors. Edison International is seeking federal permission to restart one of the reactors on June 1 at a reduced capacity of 70 percent.
California’s demand for gas-fired power generation rose 24 percent from January through July 2012 from a year earlier because of San Onofre, according to the Energy Information Administration, the U.S. Energy Department’s statistical arm.
NRG Energy Inc., the biggest power provider to U.S. utilities, has been running gas-fired power plants in California two to three times more often than usual because of the shutdown, John Chillemi, the company’s regional president, said during a power conference in San Francisco on Feb. 26.
Dynegy Inc., the third-largest U.S. independent power producer, is seeking to enter new bilateral contracts to operate its gas-fired plants in Moss Landing and Morro Bay this summer, CEO Robert Flexon said in an April 8 interview in Las Vegas.
Natural gas delivered by Southern California Gas Co. to cities including Los Angeles jumped 2.8 percent to $4.47 per million Btu on the Intercontinental Exchange today, the most since July 27, 2011. Spot prices are at their highest level for this time of the year since at least 2009, ICE data compiled by Bloomberg show.
The shutdown of the nuclear units in Southern California also eliminates key voltage support on transmission lines, which limits how much power can be imported into the region, Mark Repsher, a Denver-based energy industry specialist at PA Consulting Group, said in a telephone interview.
“It’ll be tight,” said Frank Wolak, an economics professor at Stanford University and former chairman of California ISO’s market surveillance committee for 13 years. “There could be reliability events that crash the system.”
Supply constraints on the grid this summer may point to even bigger shortages in the next decade as state environmental regulations force coastal plants to shut while the intermittent power from renewable sources gains, according to UBS AG and Wood Mackenzie Ltd.
The California ISO, responsible for delivering power to more than 30 million people, currently has about 60,000 megawatts of generating capacity.
About 16,000 megawatts from 18 units powered by fossil fuel may shut through 2020 because of environmental rules that restrict coastal-water intake by power plants, Julien Dumoulin-Smith, a utility analyst with UBS in New York, said in an April 4 interview. State regulations mandate that 33 percent of power come from renewable sources by 2020.
These regulations will reduce California’s reserve margins from 40 percent this year to about half of that by 2020 and shift supplies to more variable sources such as wind and solar that depend on the weather, said Dumoulin-Smith.
“This summer if there is an issue, it would highlight those structural problems because you are going to lose capacity,” he said.