(Updated July 2016)
- California has a large and growing population and a flourishing economy, with a major high-technology sector.
- Electricity demand has been rising steadily for many years, but to 2001 no major new plant had been built for about 20 years.
- In 2000-01 there was an acute electricity supply crisis, triggered by several factors.
- To meet electricity demand and carbon emission goals a large nuclear component is evidently necessary by 2050. Without it, CO2 emissions will rise.
California has a population of some 38 million, which grew by over 25% through the 1980s and 12% through the 1990s. It is expected to reach 55 million by 2050. Its economy is larger than that of most nations, and includes a major high-technology sector. It produces 13% of US gross domestic product (GDP).
The state has a goal of reducing its CO2 emissions by 80% of 1990 levels by 2050, as required by its Global Warming Solutions Act of 2006 and a 2005 executive order. This means going from 470 Mt CO2e emitted in 2005 to 85 Mt CO2/yr, with most of those coming from the energy sector. The short-term goal is to reach 1990 levels by 2020.
In 2015-16 the routine CO2 emissions from power generation have been joined by a massive leak of methane from the Aliso Canyon storage reservoir 2500 metres underground. At a reported 50 tonnes per hour, 438,000 t/yr, this is equivalent in global warming potential to 11 Mt/yr of CO2. Some 1700 homes have been evacuated near the leak, and more significantly for electricity supply the reservoir is largely depleted, limiting gas supplies for power generation.
Electricity demand growth accelerated in the late 1990s, so that it substantially exceeded the state's 53,000 MWe generating capacity. At the same time, capacity actually fell 1.7% during the 1990s. This left California dependent on imports for 23% of its electricity (13% from US Southwest, 10% from Pacific Northwest); it relied on some 9000 MWe of out-of-state capacity. At the same time, growth in adjoining states limited the amount of surplus power available, as did the capacity of interstate (and north-south internal) transmission lines.
Electricity generated in-state and importeda
California Energy Commission (CEC) data for 2014 showed in-state generation of 199 TWh and net imports of 98 TWh to give total of 296.8 TWh, 17 TWh of this nuclear, 13.4 Wh coal, 122 TWh natural gas, 14 TWh large hydro and 23.5 TWh solar and wind.
The basic longer-term problem is that, apart from some impressive wind farms, hardly any generating capacity had been built in California in the 20 years to 2000 due to officially-indulged environmental activism, despite almost 2% annual growth in demand to then. From 2001 to 2015 in-state capacity increased from 53.3 GWe to 79.4 GWe, though in-state generation declined marginally. In 2001, some 80% of California's generating plants were older than 35 years (the two largest gas-fired plants were 45 years old), and less than 5000 MWe of new plant was due to come online in 2000-03. In the event some 3000 MWe of gas combined cycle plant came online by the end of 2001 and a further 8400 MWe from then to the end of 2005.
From 2002 to 2006 in-state generation from coal dropped by 36% due the closure in 2005 of the Mohave plant (out of state but Californian-owned, hence deemed 'in-state'), and that from natural gas rose by 18% in line with a 26% increase in installed capacity (after dropping back to pre-2000 levels in 2002). Supply from hydro rose 59%, evidently due to seasonal factors, there being no increase in capacity. The state has considerable wind capacity, and in 2015 this contributed 11.8 TWh from 6.3 GWe installed. The Californian Energy Commission in 2012 forecast peak demand of 65 GWe in 2015 rising to 71 GWe in 2022 (middle scenario).
The state played a significant role in the early development of US nuclear power. Until mid 2013 it had two nuclear power plants: Diablo Canyon and San Onofre — with four PWR reactors totalling 4390 MWe capacity. These are designed to survive large earthquakes. However, San Onofre has now closed down, taking 2150 MWe offline (see 2013 section below). The continued operation of Diablo Canyon has been in question, and in June 2016 closure of the two reactors in 2024 & 2025 was announced, taking out 2256 MWe.
The 2000-01 crisis
Compounding the long-term problem, towards the end of 2000 the state had a lot of its generating capacity off-line, mostly catching up with maintenance deferred from peak summer load conditions. California thus faced severe power constraints and these continued through the winter into 2001.
Several plants, totalling 2700 MWe, had used up their annual pollution credits so could not restart without severe fines. In particular, three gas-fired plants (2000 MWe) were shut down after the south coast Air Quality Management District required them to install emission control equipment for NOx (oxides of nitrogen). As the crisis developed, the state's Independent System Operator (ISO), which operates most of the state's power grid, called them back into service, but they were required to obtain NOx emission credits to cover the short-term impact of this. The price of such credits soared.
Furthermore, a dry summer had reduced hydroelectric availability in the US Northwest. Interstate coal and nuclear plants helped, and local gas-fired plants met some of the shortfall, but demand forced gas prices to double. In 1999, gas provided 31% of the state's electricity, including imports (37% in 2000 and 40% in 2001).
As a result, wholesale electricity prices throughout the US West soared to unprecedented levels — briefly reaching US$ 750/MWh (75 c/kWh). In December 2000, it averaged $377/MWh and the weekly average ranged from $198 to $350/MWh in January 2001. (Prices in 1998-99 had been $24-28/MWh.) Electric utilities generally experienced a quadrupling of wholesale prices from generators but they had their own prices capped at 16 cents/kWh and consequently suffered about US$ 12 billion in losses over just six months. The state government stepped in to bail out the two largest utilities and re-regulate the system.
Three west coast aluminium smelters with long-term power supply contracts closed until 2002, and made more money selling their electricity entitlements than they could from aluminium, while employees were sent home on full pay. In one case, power bought for 2.25 c/kWh was being sold for 55 c/kWh.
The shortfall in generating capacity is widely seen as being due to years of weak government appeasing extreme environmentalism. Defending proposals for new plant against advocates of renewables and demand management as being the total answer to provision of power, means that it takes up to seven years in California to turn a proposal into a functioning power station, compared with three years in Texas. This is despite price levels which would enable an operator in Northern California to pay off a new gas-fired power station (@ $600/kW) in a year.
The supply crisis, with rolling blackouts, ran from mid 2000 to late February 2001. It forced renewed interest in building substantial coal and nuclear base-load capacity. Support for building new nuclear power plants in USA generally jumped as a result of the Californian crisis. In the west of the country, opinion that "we should definitely build more nuclear energy plants in the future" rose from 33 to 52%, nationwide it rose from 42 to 51%, compared with October 1999. More than two-thirds said that nuclear energy should play an important role in meeting future US energy needs.
In the event, demand reductions and load shifting through mid 2001 meant that summer blackouts were averted. Gas-fired capacity was much more fully utilised than before or after 2000-01.
Much newspaper coverage of the Californian crisis has pointed to deregulation as a factor, if not a cause.
Before 'deregulation', electric utilities, which have a legal obligation to serve their customers' demands, could build plants regardless of the expense and recover costs from customers. In 1996, utilities owned 81% of the total generating capacity and the average retail price was 9.5 cents/kWh, the tenth highest in the USA. This arrangement locked in certain inefficiencies, and when deregulation loomed it raised the question of how utilities would recover their 'stranded costs', mostly the capital component which could not be amortised with expected lower electricity prices. Elaborate mechanisms were put into place to cover these, but there were conditions imposed to ensure that utilities did not exploit the situation.
Under the Electric Utility Industry Restructuring Act in 1996 the Californian government put into place a deregulation scheme sought to bring competition into generation - attracting needed investment, while leaving transmission and distribution as regulated monopolies. This required the major utilities to divest at least half their major generation assets, so that their ownership fell to 46% of the total capacity.
The scheme also prevented them from entering long-term hedging contracts that would limit the risk of large price movements, forced them to buy electricity at market rates from a centralised pool, and on top of all this committed the two main utilities to retailing the electricity at fixed 1996 prices until March 2002 regardless of the cost of wholesale purchase. The price cap provision incorporates a transition charge which is the mechanism for utilities to recover stranded costs.
Thus there was not so much deregulation as a much less effective form of regulation. The need for long-term contracts enabling generators to build and maintain adequate capacity was emphasised, as was the need for adequate reserves which consumers had to be prepared to pay for maintaining.
The 2013 San Onofre saga
Early in 2013 California was focused on avoiding an electricity crisis partly arising from its growing reliance on wind and solar power, and partly from one nuclear power station being shut down with steam generator problems. According to the California Energy Commission, since the 2001 crisis, power plants with maximum output totaling about 20,000 megawatts have become operational. An additional 3,900 megawatts are under construction and 4,700 MW more have been approved and are in pre-construction phases. The new plants should boost the state's energy independence. It currently produces about 71% of the electricity it consumes, and imports 8% from the Pacific Northwest and 21% from the Southwest.
Units 2&3 of Southern California Edison’s San Onofre Nuclear Generating Station (SONGS) had been shut down since January 2012 because of faults in their new steam generators supplied by Mitsubishi Heavy Industries and installed over 2009-11. A Nuclear Regulatory Commission investigation team pointed to "faulty computer modelling" and "manufacturing issues" as contributing to the rapid deterioration of the steam generator tubing. In total some 386 tubes had thinned by more than 35% from their original state – a level that required mandatory plugging – while hundreds more were plugged as a precaution. Each steam generator contains 9727 tubes and is designed to cope with the loss of some of these throughout its 30-40 year life, however the speed of degradation since 2010 was surprising and was said to be a possible safety issue if a large failure were to suddenly occur. Both units remained shut down with no clear timetable for their return to service, taking 2150 MWe net offline. Despite three independent engineering reviews confirming the steam generators’ safety at 70% capacity, the NRC delayed giving approval for this for some eight months. Hence in June 2013 SC Edison decided to retire them permanently due to the regulatory delay and uncertainty in bringing the 40-year old units back into service. Fuel was removed by mid-July 2013.
SC Edison and Mitsubishi were at odds over terms of the steam generator warranty. Edison filed warranty claims of $139 million – just over the warranty’s stated limit – while asserting that liability limitations in the contract did not apply. Long-term solutions to rapid degradation of the plant’s steam generators were being pursued independently of a proposal to restart the plant at partial power. The company indicated that without restart approval, it might be compelled to decommission the plant and write it off, which it then implemented. In July 2013 Southern California Edison served a formal Notice of Dispute on Mitsubishi Heavy Industries, Ltd., and Mitsubishi Nuclear Energy Systems, which seeks to hold Mitsubishi accountable for designing and manufacturing defective replacement steam generators which were warranted for 20 years, and claiming over $4 billion through mediation by the International Chamber of Commerce. In July 2015 SC Edison said that it was increasing its claim against MHI to $7.57 billion. MHI responded saying that “The allegations and demands made by [SCE] disregard the history of the contract negotiations and performance and are factually incorrect, legally unsound, and inappropriate.”
In October 2015 the owners of SONGS reached a $400 million settlement with Nuclear Electric Insurance Limited for outages caused by the failures of the replacement steam generators. SCE said it continued to pursue arbitration claims against MHI and Mitsubishi Nuclear Energy Systems for failure of the steam generators.
The plant is midway between Los Angeles and San Diego, and played an important role in grid stability for the ISO. With both San Onofre units off line since January 2012, California's wholesale electricity prices have suffered. The US Energy Information Administration (EIA) reported a 59% increase in wholesale power prices in the state over the first half of 2013, which it ascribed largely to the extended outages at the two units. The situation also caused a "large and unusual" separation in power prices between the northern and southern Californian electricity grids, which have historically tracked each other closely.
The ISO reported in April 2013 that wholesale power prices in California were stable in 2012, with a 30% drop in average natural gas prices being balanced by San Onofre nuclear units being offline and less hydro power. The average wholesale cost in California's $8.4 billion power market in 2012 was $35.69 per megawatt-hour. However, adjusted for gas prices, California prices jumped 28% in 2012 to about $42 per MWh from $33 /MWh in 2011. This was attributed to higher average and peak summer loads, with lower in-state hydroelectric generation, outages of the San Onofre nuclear station, and increased congestion within the ISO. Congestion drove real-time market revenue imbalance charges to $186 million, more than five times the $28 million in 2011, the ISO said. Without San Onofre's 2,150 MWe, the state relied on more expensive natural gas-fired generation, which provided 45% of the electricity generated in-state in 2011. Large hydro and nuclear provided 18% each in 2011.
California power consumption rose 2.9% in 2012 to 234.9 billion kilowatt-hours, the highest since 2008 because of warmer weather and a recovering economy, according to the ISO. In 2011 generation plus imports totaled 285 billion kWh, including: 90.8 gas, 36.7 nuclear, 42.7 hydro, 12.9 geothermal, 8.6 wind and solar, 5.8 biomass, according to California Energy Commission data.
Renewable power's share of the state's power supply grew to 5% in 2102, up from 3.9% in 2011. About 700 MWe of new renewable generation was added in 2012 and 1,300 MWe of new natural gas-fired generation, the ISO report said.
The 2013 Integrated Energy Policy Report from the California Energy Commission said that the state must find replacement low-carbon capacity for San Onofre to offset the emissions avoided by that plant and address the effects of its closure on the reliability of the state’s electric grid. In particular the demand response goals set in the early 2000s needed to be tackled. To compensate for the closure of SONGS and maintain grid reliability, in October 2013 the California Public Utilities Commission established an energy storage target of 1,325 MWe for Pacific Gas and Electric Company, Southern California Edison, and San Diego Gas & Electric by 2020, with installations required no later than the end of 2024.
2016 situation: DIablo Canyon countdown
Pacific Gas & Electricity’s Diablo Canyon nuclear plant continued in operation through most of the drama with SONGS. However, in June 2016 PG&E announced that its two reactors, of 1138 and 1118 MWe net would closed down in 2024 and 2025 after only 40 years' service, rather than continuing with a licence renewal application which would take them to 2045 – a 20-year extension like most other US nuclear plants. The new proposal is subject to approval by the California Public Utility Commission (CPUC) by the end of 2017, including its confirmation that the company's $2 billion investment in Diablo Canyon will be recovered by the time the plant closes and that the costs of replacement GHG-free capacity can be passed onto consumers (it is a regulated plant, not subject to wholesale price competition from gas).
PG&E said that the decision was agreed to by a coalition of labour and environmental groups, including Friends of the Earth and the Natural Resources Defense Council. Implementation of the shutdown proposal is also contingent on the State Lands Commission approving a lease extension beyond 2018 for Diablo Canyon's cooling water intake and discharge facilities, which was promptly given, and the CPUC’s approval of the proposal to replace the plant with renewable energy resources.
In fact it appears that the plant will be replaced largely by natural gas generation. Of about 17.8 TWh annual generation (at 90% capacity factor) only 2 TWh/yr is proposed to be replaced by renewables from 2025. Another 2 TWh/yr is to be offset by greater energy efficiency. PG&E said: “This proposal recognizes the value of GHG-free nuclear power as an important bridge strategy to help ensure that power remains affordable and reliable” but does not say why continuing operation would not achieve this. The proposal acknowledges “the challenge of managing overgeneration and intermittency conditions under a resource portfolio increasingly influenced by solar and wind production” but does not indicate how less nuclear and more solar and wind will help address this. The proposal will “impact the efficient and reliable balancing of load and resources in PG&E’s service territory,” which already faces stability challenges in integrating intermittent renewables. “The retirement of Diablo Canyon may have impacts on system ramping and local reliability, and must be resolved by the CPUC through its IRP process [integrated resource planning process for regulated load-serving entities], in collaboration with the CAISO [California Independent System Operator].”
The main driver deterring PG&E from seeking a 20-year licence extension is the 2015 renewable portfolio standard (RPS) of producing 50% of its electricity from qualified renewable energy sources by 2030. PG&E’s model for the future cost of operating Diablo Canyon indicated that the cost per kilowatt hour was going to almost double, since the company would be forced to lower the amount of power it could produce from the plant in order to meet the state’s requirement. Dropping the capacity factor from the current 92% to say 50% would virtually double the price per kilowatt hour since costs are largely fixed.
Coupled with this is a presumed need for some refurbishment to take the reactors to 2045 if licences were renewed. One aspect of this is a threat that very expensive cooling towers would be needed due to State Water Resources Control Board requirements, rather than continuing with direct once-through cooling from the ocean. This question was to be resolved in 2017.
In 2015 PG&E estimated the decommissioning cost of Diablo Canyon as $3.8 billion (2014 $), and this figure will be revised by 2018. In 2016 it had about $2.8 billion in the decommissioning fund and anticipated no problem in accumulating the rest by 2025.
The state law which effectively dictates that by 2030 Diablo Canyon should operate at lower capacity each year and buy in power from intermittent renewables has sealed the fate of the plant. The multi-party agreement buys peace for nine years.
New nuclear capacity
A 1976 state law prohibits construction of new nuclear power plants in California until a means of disposal of high-level nuclear waste is approved. A bill to repeal this moratorium was voted down in April 2007, but may be reintroduced. Meanwhile the California Energy Commission is reviewing the prospects of new nuclear capacity in the state. A group earlier sought the involvement of UniStar Nuclear (a joint venture of Constellation Energy and Areva Inc) to investigate building one or two of Areva's 1600 MWe EPR power reactor units at Fresno.
In September 2007, the California Republican party voted unanimously to work to remove the prohibition on new nuclear power plant construction. However, to date no progress has been made with regard to ending the moratorium on new nuclear build.
In July 2008, public opinion was found to have moved positively towards building new nuclear power plants: 50% in favour, 41% against (N=809), compared with 1990: 38% in favour, 56% against.
In July 2011 a study from the California Council on Science and Technology (CCST) called for an almost tenfold increase in the state’s nuclear energy capacity by 2050. The report, California’s Energy Future — Powering California with Nuclear Energy, includes a “Realistic Model” scenario that assumes that the state's energy demand in 2050 will be 510 TWh/yr. It also assumes that nuclear electricity will be used as the base-load power source, nuclear plants will have a 90% capacity factor, and nuclear power will provide two‐thirds of the state’s electricity, the rest coming from renewables as required by the Global Warming Solutions Act of 2006. This scenario requires about 44 GWe of nuclear capacity. “California needs to reduce its greenhouse gas emissions to 80% below 1990 levels by 2050, while accommodating projected growth in its economy and population,” which "will likely require a doubling of electricity production with nearly zero emissions. “There are no technical barriers to large‐scale deployment of nuclear power in California. There are, however, legislative barriers and public acceptance barriers that have to be overcome to implement a scenario that includes a large number of new nuclear reactors.” The report concludes that 6-8 c/KWh is "the best estimate today" on nuclear power costs. "Reactors can be cooled with reclaimed water or with forced air, though air cooling is less efficient and would increase nuclear electricity prices by 5% to 10%."
This nuclear energy report was produced as follow-up to a wider CCST report, California’s Energy Future: The View to 2050 (May 2011). This found that: "Nuclear power provides reliable base-load power with very low emissions and can offset variability issues incurred by renewables, but faces obstacles with current public policy and public opinion. By law, new nuclear power in California is currently predicated on a solution for nuclear waste." However, "If electric generation is predominantly intermittent renewable power, using natural gas to firm the power would likely result in greenhouse gas emissions that would alone exceed the 2050 target for the entire economy." The CCST prepared its reports for the California Energy Commission.
a. Up to 2006, the in-state generation figures included coal-fired plants owned by California utilities located out-of-state. Source: Energy Information Administration and California Energy Commission (CEC). [Back]
US DOE Energy Information Administration website (www.eia.doe.gov)
California Energy Commission (CEC) website (www.energy.ca.gov)
Nuclear Energy Insight, Nuclear Energy Institute (January 2001)
S. Watson, Industry Link, British Nuclear Industry Forum (March-April 2002)
Nucleonics Week, Platts (5 July 2007)
California Council on Science and Technology, 2011, California’s Energy Future ‐ Powering California with Nuclear Energy.
California Council on Science and Technology, 2011, California’s Energy Future: The View to 2050.
Related information pages
Nuclear Power in the USA