Why Utilities Want Small Modular Reactors
August 13, 2013
There are numerous studies that discuss the benefits of Small Modular Reactors (SMRs) and the future role that they could play as a secure, reliable power source for zero emissions electricity. However, there is little commentary as to why electric utilities are increasingly interested in the technology when abundant, cheap natural gas and subsidized wind have negatively impacted the economic case for nuclear power.
There is widespread recognition that substantial time-consuming hurdles must be overcome to bring the SMR technology to market, chiefly, the licensing process of the Nuclear Regulatory Commission (NRC). After praising the potential role of SMRs during a nuclear industry event in May, Exelon CEO Christopher Crane added that the technology is still a “decade or so away.” But yet, a number of electric utilities are actively working to advance the SMR agenda. For example, the Tennessee Value Authority is working with Babcock & Wilcox to build a pair of small reactors to supply power to Oak Ridge, while Ameren Missouri has partnered with Westinghouse to develop and license the latter’s SMR technology. NuScale announced The Western Initiative for Nuclear (WIN), a broad, multi-western state collaboration, to study the demonstration and deployment of a multi-module NuScale SMR plant that would be operational by 2024. Many other utilities—ranging in size from rural cooperatives to FirstEnergy—have also expressed a significant interest in SMRs.
According to the Energy Information Agency (EIA), total U.S. electricity demand is expected to increase by 28 percent from 2011 to 2040, which could be a low estimate depending on the evolution of the information-communications-technology (ICT) ecosystem. At the same time, regulatory uncertainty clearly hangs over the heads of utility executives as they ponder the future of EPA activity and what that means for investment decisions in power generation. Together with federal and state mandates and subsidies for renewables, EPA regulation currently drives U.S. electricity energy policy.
Natural gas prices are expected to increase as electric companies choose to replace coal-fired power generation with natural gas-fired power generation (because of EPA air rules) and new chemical plants and LNG facilities come online, which will create market conditions more favorable to nuclear. There are currently 30GWe, or 8 percent of the coal fleet, of announced coal plant retirements over the next five years, largely in response to EPA regulation of mercury and air toxics. Moreover, some analysts predict that an additional 100GWe of coal could leave the grid within the next twenty years because of EPA greenhouse gas (GHG) rules.
Over the longer term, we expect that natural gas generation will come under increased pressure from tighter air quality emissions standards and increased regulation of hydraulic fracturing, particularly after EPA rules driving coal from the grid are in place. President Obama has called for a reduction in U.S. GHG emissions by more than 80 percent by 2050, which if pursued will force some natural gas generation from the market. Considering total lifecycle emissions, the average intensity from natural gas is estimated at 500 metric tons CO2e/GWh, compared to 28 metric tons CO2e/GWh for nuclear. This GHG advantage will improve the economics of nuclear power if advocates for further carbon regulation succeed in their long-term goals.
Despite likely federal and state government support for renewables over the next decade, a significant breakthrough in storage technology is not expected in the near term that would enable wind and solar to transition from the intermittent sources they are today to baseload power. This is due in part to federal and state subsidies that actually deter private investment in storage technology. Currently, wind and solar exhibit low availability at peak load times, and generally are not dispatched, i.e. put under the control of the grid operators. Moreover, transmission infrastructure issues are likely to remain a substantial hurdle given the need to site renewable generation on land where the resource is abundant and more economic, locations that are often far from urban areas that demand the power. As long as these challenges remain, renewable sources will face major limitations to deployment and be viewed by many investors and analysts as “artificial markets” in many locations across the country, which will likely contract significantly or collapse if government support is phased out. As we have seen in parts of Europe, “artificial markets” for renewables pose a substantial investment risk during a time of severe budget constraints.
Accordingly, electric utilities, as well as public utility commissions (PUCs) and other stakeholders, including environmental NGOs and policy analysts, are asking, “What baseload power will replace retiring coal plants and nuclear plants as they approach the end of their life, as well as meet future EPA emissions regulations over the next five decades, standards that are likely to reduce the compliance value of natural gas?”
Many of them are convinced that nuclear power is the best option and are especially intrigued by the potential role that small modular reactors could play in the country’s electricity mix. And although SMRs are at least a decade away from commercialization, utility executives understand that clearing the regulatory process and other hurdles needs to start today if SMRs are to be available in time to help the power sector comply with future EPA rules and provide reliable power to a growing economy and expanding population, which is expected to increase by roughly 150 million people by 2050.
Why SMRs? Nuclear power enjoys a clean emissions profile and its fuel supply is predictable, with minimal risk of supply interruptions due to the reload lead times. Historically, nuclear fuel costs have been very stable and nuclear has the lowest total dispatched cost of any source except renewables. When it comes to SMRs specifically, there are several additional points to consider when understanding what factors are driving electric utility interest.
First, there is a question of financing. Four new nuclear reactors are currently being constructed domestically, but most utilities are not inclined to finance the multibillion dollar investment that large reactors represent—up to $10 billion or more in a new plant. Even the largest of the privately-held companies that supply most of the country’s electricity has a market capitalization of less than $40 billion and most are half that number. In addition, power uprates at existing nuclear plants have been very successful but are becoming more limited and economically challenged by lower power prices. Because SMRs can be built and financed in phases and module-by-module, SMRs offer financing flexibility, which reduces exposure to risk. In addition, utilities would have the opportunity to deploy SMRs on existing sites as coal plants are retired, further reducing costs.
Second, load growth in most areas of the country does not support the need for new large capacity. Overall capacity additions of all fuel sources are expected to be more incremental in the future, due to both financial risk and continued uncertainties with the economy. For regulated utilities, state regulators will continue to be reluctant to support large capital generation investments. For merchant generators, market mechanisms must be further refined to properly facilitate generation investment. The ongoing challenge of building new transmission further supports incremental generation additions. Because of their smaller capacity, SMRs allow for matching smaller load growth requirements—a quality that is particularly attractive to municipals and rural electric cooperatives.
Third, SMRs have significant value in distributed generation and can play a stabilizing role in a grid with substantial renewable penetration. SMRs can control output to meet load demand, including integration of variable sources like wind and solar, an advantage that may grow in importance to utilities and PUCs, particularly in competitive electricity markets, if renewable deployment continues to increase with government support.
Fourth, SMR technology incorporates post-Fukushima lessons, including passive safety features that make it technically impossible for a Fukushima-type event. In addition, because of their size and reduced
complexity, SMRs have a smaller footprint, which allows for greater flexibility in siting and fewer staffing and maintenance needs, including security personnel. As some designs can be air-cooled, there is minimal water usage as well.
Given the need to find reliable, clean emissions generation, we expect electric utilities to maintain their high level of interest in SMRs if the NRC licensing process continues to move forward relatively smoothly. Utilities and PUCs, as well as general market observers and potential investors, will also be following progress made by companies benefitting from funding provided by the Department of Energy to accelerate the deployment of SMR domestic designs. Ongoing discussions to increase federal support for SMR commercialization could also peak interest of more utilities if those talks result in a greater commitment by agencies, departments, and/or the Congress to back the technology.
Dave Banks is senior fellow and deputy director of the Nuclear Energy Program at the Center for Strategic and International Studies (CSIS) in Washington, D.C.
Commentaries are produced by the Center for Strategic and International Studies (CSIS), a private, tax-exempt institution focusing on international public policy issues. Its research is nonpartisan and nonproprietary. CSIS does not take specific policy positions. Accordingly, all views, positions, and conclusions expressed in this publication should be understood to be solely those of the author(s).
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