Too Big to Fail?
The economic and environmental impact of closing California’s San Onofre Nuclear Generating Station.
(This post is co-authored by Catie Hausman).
The San Onofre Nuclear Generating Station (SONGS) was closed abruptly in February 2012. During the previous decade, SONGS had produced about 8% of the electricity generated in California, so its closure had a pronounced impact on California’s wholesale electricity market, requiring large and immediate increases in generation from other sources.
In a new EI@Haas Working Paper titled, “The Value of Transmission in Electricity Markets: Evidence from a Nuclear Power Plant Closure”, we use publicly available data to examine the impact of the closure on economic and environmental outcomes. Because of the plant’s size and prominence, the closure provides a valuable natural experiment for learning about firm behavior in electricity markets.
We find that the SONGS closure increased the cost of electricity generation by $370 million during the first twelve months. This is a large change, equivalent to a 15% increase in total generation costs. The SONGS closure also had important implications for the environment, increasing carbon dioxide emissions by 9.2 million tons over the same period. Valued at $35 per ton (IWG 2013), this is $330 million worth of emissions, the equivalent of putting more than 2 million additional cars on the road.
The closure was particularly challenging because of SONGS’ location in a load pocket between Los Angeles and San Diego. Transmission constraints and other physical limitations of the grid mean that a substantial portion of Southern California’s generation must be met locally. When SONGS closed, these constraints began to bind, essentially segmenting the California market. The figure below shows the price difference at 3 p.m. on weekdays between Southern and Northern California. After the closure there were many more days with positive differentials, including a small number of days in which prices in the South exceeded prices in the North by more than $40 per megawatt hour.
These binding transmission constraints meant that it was not always possible to meet the lost output from SONGS using the lowest cost available generating resources. Southern plants were used too much, and Northern plants weren’t used enough. Of the $370 million in increased generation costs, we attribute about $40 million to transmission constraints and other physical limitations of the grid. This number is less precisely estimated than the overall impact, but is particularly interesting in that it provides a measure of the value of transmission.
The paper provides all the gory details about how we made these calculations. It turns out to be more difficult than a simple before-and-after comparison because during this period the California market was also experiencing a whole set of simultaneous changes to hydroelectric resources, renewables, demand, and fuel prices. What is helpful, however, is that transmission constraints were rarely binding prior to the closure. This means that observed behavior during the pre-period provides a good sense of how firms would have behaved during the post-period had there not been transmission constraints.
Our findings provide empirical support for long-held views about the importance of transmission constraints in electricity markets (Bushnell 1999; Borenstein, Bushnell and Stoft 2000; Joskow and Tirole 2000), and contribute to a growing broader literature on the economic impacts of infrastructure investments (Jensen 2007, Banerjee, Duflo and Qian 2012, Borenstein and Kellogg 2014).
The episode also illustrates the challenges of designing deregulated electricity markets. A new book chapter by Frank Wolak (here) argues that while competition may improve efficiency, it also introduces cost in the form of greater complexity and need for monitoring. Transmission constraints add an additional layer to this complexity, by implicitly shrinking the size of the market. Constraints increase the scope for non-competitive behavior, but only for certain plants during certain high-demand periods, so understanding and mitigating market power in these contexts is difficult and requires a sophisticated system operator.
For more see Market Impacts of a Nuclear Power Plant Closure (by Lucas Davis and Catherine Hausman), American Economic Journal: Applied Economics, 2016, 8(2), 92-122
Keep up with Energy Institute blogs, research, and events on Twitter @energyathaas.
Suggested citation: Davis, Lucas. “Too Big to Fail?” Energy Institute Blog, UC Berkeley, March 31, 2014,
Lucas Davis View All
Lucas Davis is the Jeffrey A. Jacobs Distinguished Professor in Business and Technology at the Haas School of Business at the University of California, Berkeley. He is a Faculty Affiliate at the Energy Institute at Haas, a coeditor at the American Economic Journal: Economic Policy, and a Research Associate at the National Bureau of Economic Research. He received a BA from Amherst College and a PhD in Economics from the University of Wisconsin. His research focuses on energy and environmental markets, and in particular, on electricity and natural gas regulation, pricing in competitive and non-competitive markets, and the economic and business impacts of environmental policy.
Edison redesigned the steam generators and it was a failed design. After spending about $750 million of ratepayer money on these replacement steam generators (and over $250 million for new turbines) and additional millions to determine the cause and attempt repairs, they determined there was no feasible way to fix the bad design. The steam generator tubes showed decades of wear after only one and two years of use. Edison wanted to restart the Unit 2 reactor without fixing the the problem. It took citizen activism to make decision makers aware of the problem. Whistleblowers (safety conscious employees) who worked at the plant shared critical information that Edison tried to hide from the public and decision makers.
Also, I have yet to see a breakdown of how much of the energy impact was due to hydro loss vs. San Onofre. These are always lumped together as one item.
Now we have over 1600 metric tons of spent nuclear fuel stored at San Onofre. Edison plans to spend about $1.3 billion just for spent fuel management. A large part of this is to procure more thin (0.5″ to 0.625″) stainless steel canisters that are subject to chloride induced stress corrosion cracking from our marine environment. According to the NRC, a similar component at the Koeberg nuclear plant in South Africa had a through-wall crack of 0.6″ in 17 years. San Onofre has 51 loaded canisters. Loading began in 2003. If San Onofre canisters start failing in a similar timeframe to Koeberg, we’re looking at 5 years until one of those canisters cracks and release radiation. Edison has no technology to inspect for corrosion or cracks in these thin canisters and there is no practical way to repair them, according to Dr. Singh (Holtec canister CEO). There is also no plan in place to deal with through-wall cracks at San Onofre or any other U.S. plant. There are close to 2000 of these inferior canisters stored around the country. Most of the rest of the world uses thick metal casks, such as Castor’s ductile cast iron (up to 20″ thick), manufactured by Siempelkamp. At Fukushima, Areva TN-24 series thick steel casks were used. Learn more, including industry, NRC and scientific sources for this information at SanOnofreSafety.org