The high stakes of Wyoming’s electric power future

PacifiCorp recently released its 2021 Integrated Resource Plan, which forecasts future demand for power in the region and the sources of electrical energy PacifiCorp has determined will be necessary to meet this demand most efficiently and reliably. The Wyoming Public Service Commission has solicited public comments leading up to its review of the IRP; the deadline for comments is Friday, Feb. 11.

The two-volume IRP is a formidable document, with 850 pages of high-level analysis and supporting data. While the average ratepayer cannot be expected to wade through this comprehensive document, it nonetheless discloses potential generating resources that should command the attention of Rocky Mountain Power’s 142,000 Wyoming customers and all other individuals concerned about the energy future of Wyoming.

The good

The preferred portfolio includes a slight increase in wind generation and a dramatic increase in battery storage. It also suggests an 88% reduction in overall carbon dioxide emissions over the 20-year planning period by adding renewable sources of energy and retiring virtually all the utility’s coal assets by 2050. 

PacifiCorp’s analysis suggests that retrofitting coal-burning power units with carbon capture sequestration and utilization technologies is cost prohibitive. It solicited proposals from potential CCUS suppliers, and only one respondent expressed intent to complete a front-end engineering design study. The IRP appropriately states that capital cost, transportation infrastructure, the lack of available federal funding and other factors still contribute to the risk and uncertainty of CCUS.

The bad

Unfortunately, the IRP leaves open a contingency plan to include CCUS at the Dave Johnston power plant, pending regulatory developments and the review of CCUS proposals. But the downfalls of coal-based CCUS have been sufficiently demonstrated. 

Boundary Dam and Petra Nova, the only utility-scale coal-plant CCUS retrofit projects in North America, both incurred higher costs and achieved lower performance than originally advertised. In April of 2020 Petra Nova in Houston shut down with the intent to restart on a seasonal basis. A year later the company announced the plant would be mothballed indefinitely. 

Boundary Dam unit 3, in Saskatchewan, has gained operating experience for eight years, yet the plant struggled with mechanical failures in 2021 and achieved only 37% CO₂ capture efficiency. Over its entire life, the plant has averaged 67% capture efficiency, compared to the target rate of 90%. SaskPower’s decision to scrap plans to retrofit units 4 and 5 with CCUS speaks for itself.

Most of SaskPower’s problems are inherent to coal plants and will not go away with more experimentation. The Wyoming Energy Authority recently granted three CCUS research funding requests (out of 17 proposals), none of which involve coal. The award stated, “these three proposals illustrated that their projects are at a scale sufficient to demonstrate commercial viability.”

The ugly

The preferred portfolio includes plans for the Natrium advanced nuclear demonstration facility near Kemmerer. The plant’s continuous capacity would only make up 3% of the utility’s system-wide peak load. But the estimated $4 billion capital investment, subsidized by TerraPower and DOE (subject to future appropriations), represents 16% of the company’s 20-year revenue stream. We should not dismiss the importance of this project to the Kemmerer community and to the advancement of nuclear knowhow. But neither should we close our eyes to the failure risks — financial, regulatory and safety. It is unusual for ratepayers to take on such risks for experimental power generation projects, especially when exhaustive prototype testing at scale was bypassed.

Contemporary nuclear power projects raise plenty of red flags. Units 3 and 4 of the Vogtle nuclear plant in Georgia, currently under construction, will be at least six years late coming online, while their capital costs have escalated from $14 billion in 2017 to $28.5 billion in 2021. 

The IRP acknowledges that the marginal energy storage cost for the Natrium molten salt system exceeds that of lithium-ion batteries and far exceeds that of solar plus batteries. The Natrium technology has been promoted in part for its compact energy storage relative to batteries, but the cost of energy storage is the most relevant parameter for ratepayers. While the Natrium storage design has value as a demonstration project and may deliver unquantified ancillary benefits, the ratepayer should not subsidize an economically inefficient storage technology.

The experts may be wrong, but they paint a dismal picture of the future of nuclear power. Over the last two decades, the U.S. Nuclear Regulatory Commission received license applications for 31 new reactors, of which 29 were canceled due to the lack of economic viability. 

Aside from nuclear power’s widespread budget and schedule overruns, cheaper alternatives abound. A 2021 report from Wall Street firm Lazard estimates the cost of new nuclear energy at $131 to $204 per megawatt-hour compared to $26 to $50 for wind, and $30 to $41 for utility-scale solar. The cost differential will more than pay for storage batteries to back up renewable energy.

The money and momentum behind the Natrium project mean that it will probably get built. It certainly has an upside. But the PSC should ensure that attendant financial risks are shouldered entirely by PacifiCorp’s shareholders. This would not only relieve Wyoming ratepayers of an open-ended liability, but it might also encourage a more thorough risk evaluation by PacifiCorp.