Energy Northwest Study Makes a Case for SMRs in Future Power Mix

Deep decarbonization of the U.S. Northwest can be achieved at “manageable” costs by 2045, but only if utility agency Energy Northwest secures zero-emitting firm capacity, such as by relicensing Columbia Generating Station—the sole nuclear plant in the region—and building small modular reactors (SMRs), a new study suggests.

The study by San Francisco-based consulting group Energy + Environmental Economics (E3), which was made public on Jan. 30, responds to Washington state’s May 2019–enacted measures to produce 100% of its power from “clean” sources by 2045, such as hydropower, wind, and solar. Energy Northwest, a not-for-profit utility agency established in 1957 by the state legislature and which today comprises 27 public utilities districts and municipalities in the state, commissioned the E3 study as part of a multi-year effort to evaluate all its options through the next 20 years and beyond.

As Energy Northwest CEO Brad Sawatzke noted, the clean energy mandate is “an ambitious and worthwhile goal, so we have to start planning today to ensure the people of Washington state have the right mix of energy sources tomorrow.” A major challenge the utility agency is now grappling with is to “make sure that mix is not only reliable, but affordable,” he said.

Among the study’s key findings is that if “new firm capacity” is not built, achieving a region-wide 100% greenhouse gas (GHG) emission reduction compared to 1990 levels will exhibit a “marked increase” in costs. While firm capacity that could result in “manageable costs” could come from pairing renewables and gas (natural gas and renewable gas), deep decarbonization would be most economically achieved from extended operation of the Columbia Generating Station as well as with new SMRs. The other deep decarbonization option, “A system that largely relies on wind, water, solar, and battery storage … requires over 100 GW of new capacity additions in 2045 to maintain reliability,” it concludes.

A system that depends solely on renewables coupled with storage, meanwhile, would become “less and less effective at reducing carbon in the Northwest compared to the reference case [which assumes natural gas power is built to replace retired coal capacity] and as the amount of GHG emissions allowed in the electricity sector decrease.” A renewables-dependent system also risks “large overbuild,” and could result in a growing frequency and magnitude of renewable curtailment, driving up the cost of reducing GHG emissions, the study says. In a 100% GHG reduction scenario, for example, 40% of new renewable generation would need to be curtailed, it says.

However, the future role of SMRs also “depends on their cost, the stringency of regional emissions limits and the availability of gas generators to provide firm capacity,” it says. If no new gas is built in the region, SMRs will have their largest build-out cases, with at least 6.3 GW of SMRs being built by 2045. At currently estimated costs in a 100% GHG reduction scenario by 2045, SMRs could slash costs by nearly $8 billion a year, owing to their provision of firm capacity. SMRs also appear more economically feasible if a currently available production tax credit (PTC) of $18/MWh is applied, and the study assumes that the Northwest could claim nuclear subsidies for up to 3 GW of new SMRs.

Assessing the Cost of New Resources

The study uses E3’s RESOLVE model, which  “co-optimizes investments and operations to minimize total [net present value] of electric system cost over the study time horizon,” the company said. That essentially means that investments and operations are “optimized in a single stage to capture linkages between investment decisions and system operations,” E3 explained. The model also “selects resources based on total value to the entire system, not just levelized cost of energy,” it said.

But the study also builds on several previous analyses E3 performed to study carbon scenarios in the Northwest. A 2017 study found that a portfolio of hydro, renewables, and natural gas would be the least cost strategy to achieve an 80% reduction in power sector emissions. In 2018, E3 found that the cost of achieving 100% decarbonized power in the Northwest would be greatly reduced if firm resources like SMRs or biomethane gas generators were available. Another study it conducted last year, meanwhile, found that the region will need firm generation to ensure reliability “because the marginal capacity contributions of wind, solar and storage decline as their penetrations increase.” Significantly, that study also found that “gas is the least cost option to provide firm capacity given existing technologies.”

E3’s new study, which follows Washington’s Clean Energy Transformation Act, takes into account the clean energy mandate’s provisions to eliminate coal portfolios after 2025, and requirements that electric utilities in the state become carbon-neutral by 2030. To determine how costs for new resources will play out over the long-term, it assesses them within a series of scenarios that explore reductions of GHG emissions in the state below 1990 levels, ranging from an 80% reduction by 2045 to a 100% reduction.

Extending Columbia’s Nuclear Life Almost Certain

Notably, all scenarios assume Columbia Generating Station will be relicensed beyond its currently anticipated shutdown date of 2043. The 1.2-GW nuclear plant (a POWER magazine Top Plant in 2017) located 12 miles north of Richland, Washington, comprises a single GE-built Mark-2 boiling water reactor, and it will be 60 years old when its 2012-renewed operating license issued by the Nuclear Regulatory Commission (NRC) expires in December 2043.

Using published projections and costs provided to it by Energy Northwest, the E3 study suggests that Columbia’s value—which stems from its ability to provide both energy and firm, carbon-free capacity—ranges from $75 million per year in the lowest scenario, which explores an 80% GHG reduction, to $1.35 billion in the highest scenario, which explores a 100% GHG reduction.

Among new resource options the study explores are an assortment of renewables available to the region based on a supply curve. These include hydropower, solar, wind, and geothermal. It also considers up to 5 GW of pumped hydro storage, which it assumes will be available at a cost of $2,450/kW and provide an effective capacity of 50%. Also considered are “unlimited quantities” of lithium-ion and flow battery storage, as well as energy efficiency and demand response options. As significantly, the scenarios capture recent policies and trends projected to affect load forecast, such as large-scale electrification of light-duty transportation.

Untangling SMR Costs

Especially notable is the study’s emphasis on SMRs, and its potential future role in the region Energy Northwest has studied. In 2013, the utility agency joined a teaming arrangement with NuScale Power and Utah Associated Municipal Power Systems (UAMPS) as part of the Western Initiative for Nuclear Project collaboration to promote a commercial SMR project in the western U.S. While NuScale is working with Salt Lake City–based UAMPS to site the first “Carbon Free Power Project” at the Idaho National Laboratory in Idaho Falls, Idaho, Energy Northwest currently holds first right of offer to operate the project.

Portland, Oregon–based NuScale Power’s 60-MW light water reactor, which can be installed in up to 12 modules, is also currently the only SMR undergoing design review by the NRC. NuScale submitted its design certification application in January 2017, and the NRC completed the second and third phases of review of the company’s SMR plant design in July 2019 and will likely complete all phases by September 2020.

E3 noted that while SMRs are not yet commercial, NuScale estimates initial projects could be online by the mid-2020s. Congress’s 2018-passed nuclear production tax credit (PTC) allows the Energy Secretary to allocate an $18/MWh subsidy for up to 6 GW of new advanced nuclear reactors placed in service after Dec. 31, 2020, for their first eight years of operation, and the study assumes the Northwest can claim up to 3 GW of the nuclear PTC subsidy.

Of specific note, also, is that the model uses nuclear baseline costs published by the National Renewable Energy Laboratory (NREL), as well as NuScale’s own “Nth of a kind” (NOAK) estimates—which the report suggests would be $4,900/kW (in 2018 dollars) in 2045. In a September 2019 submission to the Australian Nuclear Association, NuScale said NOAK estimates hover around $3,600/kW (in 2017 dollars) for a 720 MW plant in the U.S. (It is important to note that NOAK is not clearly defined. The Generation IV International Forum’s Economic Modeling Working Group in 2006 defined NOAK as an “identical plant supplied and built by [the] same vendors and contractors as the [first-of-a-kind (FOAK)] plant with only the site specific scope adopted for the NOAK plant site needs.” NOAK costs, the group added, are achieved for the plant after 8 GW has been built. However, the group last year said it will work on a “more detailed identification” of cost uncertainties and assess the series effects from FOAK to NOAK, which may require revisiting guidelines for cost estimation.)

According to the E3 report, at current NREL annual technology baseline and NuScale costs, SMRs will be selected in the 95% and 100% emissions reduction scenarios—and in all but one case, the first SMRs could be built in 2045. If a PTC is considered, SMRs are selected in all emissions reduction scenarios, and SMRs would be built earlier, coming online in 2040. If no new gas generators are built—either powered by natural gas or biomethane—the first SMRs in the Northwest could come online as soon as 2030, with at least 6.3 GW built by 2045.

—Sonal Patel is a POWER senior associate editor (@sonalcpatel, @POWERmagazine)