Conflicting forces are at work in the field of small modular reactors (SMR), as utilities, vendors, researchers, and regulators weigh the advantages of carbon-free power generation and incremental capacity additions against technical and financial concerns.
Small nuclear reactors, with outputs ranging from about 50 MW to around 300 MW, can be safer, cheaper, and quicker to build, thus making them easier to finance. Just as important, they can also help utilities meet anticipated restrictions on carbon dioxide emissions while adding generating capacity in smaller blocks to provide flexibility in meeting demand.
However, some major vendors have suspended or slowed their SMR development programs in the U.S. in the face of declining interest largely due to financing challenges brought on by the economic recession. Stiff competition from natural gas-fired generation and uncertain load-growth prospects also figure into the calculations.
But the technology holds promise for the utility industry and shouldn’t be dismissed, says Sandy Byrd, vice president of public affairs & member services at Arkansas Electric Cooperative Corporation, the Little Rock-based generation and transmission cooperative (G&T).
“The timeline for research, development, and deployment has definitely been extended,” she says. “But the electric industry still needs to develop more baseload generation options, especially emission-free baseload generation. The SMR concept is still appealing as a future baseload option for electric cooperatives.”
Lee Ragsdale of North Carolina Electric Membership Corporation agrees.
“SMRs could benefit our membership,” says Ragsdale, vice president of asset management at the Raleigh-based G&T. “It’s an intriguing concept—smaller footprint, smaller capital investment, smaller unit size—and we want to understand all aspects of it.”
SMRs fall into three main technology categories: light-water reactors, high-temperature gas-cooled reactors, and liquid-metal-cooled reactors. Light-water reactors could be ready for commercial deployment within a decade, while the others are likely to take at least 20 years of further development.
Four U.S. companies have introduced light-water SMRs: Babcock & Wilcox, NuScale Power, Holtec International, and Westinghouse. Their models, typically with less than 300 MW of capacity, are at various stages of design, development, and regulatory approval.
These units are largely built and tested in the factory, substantially reducing labor and other construction costs.
But that’s not to say SMR costs are low. The Nuclear Energy Institute estimates that the first such reactor will require about 10 years and $1 billion to design and license. Manufacturer representatives, meanwhile, say the companies have set cost targets in the range of $3,500 to $5,000 per kilowatt.
Costs may be a big question mark for now, says Tina Taylor, director of nuclear strategic programs at the Electric Power Research Institute (EPRI). But they are certain to come down once utilities warm up to the benefits of modular capacity additions and SMR manufacturing and deployment take off, she adds.
“Aside from looking at the dollar-per- kilowatt capital cost, which might be higher because the plant is smaller, the hope is that the smaller total capital investment may offer a better risk profile for some utilities,” she says. “And, like any technology, the first-of- a-kind [costs] won’t be indicative of the ‘nth’-of-a-kind.”
The light-water SMRs are also designed to be safer, with smaller reactor cores and fuel inventories combined with improved passive failsafe systems. That and their reduced site requirements could ease permitting and environmental concerns.
The Co-op Response
Co-ops have good reason to pay attention to SMR development and perhaps to take a stronger role in pushing it, according to experts at G&Ts around the country. They cite a range of potential benefits:
Incremental capacity additions that can be matched to load growth. “There’s a big difference between bringing 200 megawatts into the system and bringing 2,000 megawatts into the system,” North Carolina’s Ragsdale says. Mike Mooney, manager of corporate planning at Hoosier Energy in Bloomington, Ind., echoes that comment. “If we started with a blank sheet, our planners would say, ‘Limit new generation to 150 to 200 megawatts. That would be ideal.’”
Reduced financial risk. Modular generating units allow a utility to stage its capital investment, an advantage that could be especially important to co-ops wary of the upfront financing requirements for large nuclear plants. “The size makes SMRs something that, if attractive, we could afford to build,” says James Wright, manager of power supply planning at Old Dominion Electric Cooperative, a G&T based in Glen Allen, Va. “If we wanted to, our balance sheet would allow us to own a couple of hundred megawatts of nuclear. We could build an SMR two-pack with or without a partner.”
Carbon-free generation. A zero-emission baseload plant might be especially attractive for utilities with generation portfolios heavily dependent on older, smaller fossil-fueled plants, according to Jonathan Oliver, Arkansas Electric’s vice president of power production & delivery. “As environmental restrictions become more prohibitive, small nuclear could be one attractive alternative,” he says. Barry Ingold, senior vice president of generation at Tri-State Generation & Transmission Association in Denver, Colo., agrees: “It’s an option to manage the risk from carbon regulations.”
Other environmental benefits. “Nuclear plants have zero emissions of acid gases and heavy metals and thus do not have to worry about the Environmental Protection Agency’s mercury and air toxics standards, regional haze rule, and cross-state air pollution rule,” says Dale Bradshaw, a technical consultant at NRECA. “In addition, SMRs produce minimal water effluents.”
Siting flexibility. Because of their smaller footprint, SMRs should be easier to permit and to accommodate on the existing grid, requiring fewer upgrades, says Andrew Lachowsky, vice president of planning & market operations at Arkansas Electric. An SMR in the 200- to 400-MW range could easily replace a retired coal plant, adds Tri-State’s Ingold. “The transmission, corporate, and water infrastructure are there.”
Portfolio diversity. With the increasing pressure to reduce use of coal, SMRs become “the only identifiable baseload option besides natural gas,” Hoosier Energy’s Mooney says. His G&T has some renewable baseload resources in its portfolio, including landfill gas and coalbed methane, “but those are small pieces and finite in number. When you go beyond those, what are your options? One is nuclear.”
EPRI recently issued a new “utility requirements document” that, for the first time, includes considerations for light-water SMRs.
“The objective was to define the requirements involved in buying a new nuclear plant,” EPRI’s Taylor says. “How the plant should be designed, its capabilities, system requirements, coping time in the event of an accident, targets for plant availability, and fuel loading are some of the important aspects to be addressed.”
Co-funded by the U.S. Department of Energy, the document assesses specific utility requirements from an SMR, allowing a utility to set clear expectations and detailed bid specifications for its vendors.
“For any utility seriously considering an SMR project, this document is the place to start,” Taylor says. “It can help prevent surprises later on.”
Meanwhile, some G&Ts have taken part in a handful of business alliances, user consortiums, and other panels formed to promote SMR development. These groups, however, have shown uneven records of progress.
Oglethorpe Power Corporation, the Tucker, Ga.-based G&T, represented 12 additional G&Ts on Babcock & Wilcox’s consortium, formed in 2010. The Tennessee Valley Authority (TVA) also had a seat at this table, as did 11 utility members of the company’s Industry Advisory Council.
In late 2013, Babcock & Wilcox and its SMR development partner, Bechtel Corporation, announced they were having difficulty attracting investors in the project. The following spring, the partners said they would reduce spending on the project from its previous level of about $80 million a year to about $15 million. The partnership also replaced the project’s CEO, and the utility advisory consortium stopped meeting.
“They’re trying to keep the project alive while they find a partner or investor,” says Wright from Old Dominion Electric, adding that co-op interest remains strong. “When the consortium broke up, we suggested that the co-ops might want to make sure we’re not missing something else we could participate in.”
The Western Governors Association began pushing for SMR development in 2010, leading to the creation in 2013 of the Western Initiative for Nuclear (WIN). NuScale Power is working with WIN to advance SMR work with potential projects in Washington, Utah, Idaho, New Mexico, Arizona, and Wyoming.
Energy Northwest, a public power agency that serves 27 public utility districts, municipal systems, and other utilities from its headquarters in Richland, Wash., is active on NuScale’s 24-member advisory board.
“We joined WIN for several reasons,” says Jim Gaston, Energy Northwest’s general manager of energy services & development. “By the mid-2020s, there could be a need for an SMR in the Northwest. We’d like to position ourselves as the operator of that unit.”
NRECA is also a member of NuScale’s advisory board, along with Colorado’s Tri-State Generation and Transmission Association, TVA, and a number of other public power generation and marketing agencies.
Westinghouse launched its NexStart SMR Alliance in 2012, aiming to license and install one of its SMRs within 10 years. Arkansas Electric took a seat on that group and was represented by Oglethorpe Power on the Babcock & Wilcox panel as well. Four other co-op organizations participated in Westinghouse’s effort.
“We support the development of SMR technology because we see the need to have that type of baseload generation option for future resource-planning purposes,” says Arkansas Electric’s Byrd, adding that it made sense to join both consortiums. “We decided that, rather than pick winners and losers, we would become involved with both design licensing efforts. Each was a sound company with a sound design. The concept of sharing a portion of the total megawatt output of an SMR was very appealing.”
But the Westinghouse group stopped meeting shortly after Babcock & Wilcox’s did, she says. Westinghouse announced in early 2014 that it was refocusing its work on its larger reactor models, which were selling well worldwide.
A newspaper report at the time quoted Westinghouse’s CEO as saying SMRs lacked a customer base, and the company didn’t want to “get ahead of the market.”
A group of Missouri universities, meanwhile, continues to do SMR research, and the U.S. Department of Energy has set aside money to work with utilities and vendors on SMR development.
This stop-and-start record of SMR activity reflects the challenges still facing full development of a promising generation option. Among those obstacles:
A need for more engineering, research, and development. None of the light-water SMR designs is ready now for design certification by the Nuclear Regulatory Commission (NRC), which in turn raises additional challenges.
Availability of vendor financing. Some SMR companies have relied on parent companies or consortium investors to fund research and development of their designs, and that funding often didn’t materialize. A related challenge is the predictability of project financing.
Regulatory uncertainty. The NRC’s existing regulatory framework for light-water reactors may apply only in part to an SMR-specific design, leaving regulatory guidance on certification and construction, as well as operating license applications, partial and incomplete. If this regulatory guidance is not clarified prior to the regulatory review, it leads to greater uncertainty and risk for applicants.
Economic concerns. It remains unclear whether economies of scale work against SMRs versus large reactors. SMR vendors say mass production of small modular reactors could offset the cost-per-kilowatt advantages of large reactors, but that requires a large market for units that have yet to prove themselves.
Significant upfront costs. An SMR costs less than a large nuclear plant, but initial investment will remain high, especially for a utility building a first-of-its-kind unit. Tri-State’s Ingold, who sat on NuScale Power’s advisory board, pointed directly to this problem. “We thought the cost would be more competitive with natural gas,” he says. “The numbers pointed in a direction that we couldn’t afford.” Hoosier Energy’s Mooney makes the same point: “An SMR—as a first-of-its-kind technologically— is too risky when natural gas is available. And low load growth makes investments like this more difficult.”
Despite those significant challenges, SMR technology remains on the co-op radar. As Arkansas Electric’s Byrd says, “Co-ops have always been willing to take the long view.”