Idaho PUC okays Idaho Power plan that includes no early North Valmy coal retirement

The Idaho Public Utilities Commission said Dec. 29 that it is accepting a 20-year integrated resource plan filed by Idaho Power, although there is some disagreement from commission staff and other parties over whether the utility has chosen the most cost-effective, least-risk plan to meet load growth.

However, the commission noted that the IRP is for planning purposes only and that acceptance of the plan does not mean all its components will be implemented. Regulated electric and gas utilities are required to file an IRP every two years with the commission.

The plan does not anticipate significant new generation resources through the 2020s. It projects customer growth to be about 196,000 from now until 2035, adding about 1.2% to the company’s average energy demand and 1.5% to its peak demand.

To meet load growth, Idaho Power anticipates acquiring 60 MW from new demand response programs, 20 MW from development of an ice-based thermal energy storage plan, and the construction of a 300-MW natural gas plant in about 2031. The plan also assumes that much of the increased demand in the near future will be met by completion of the 500-kV Boardman (Oregon) to Hemingway (B2H) transmission line, expected to be operational by 2020 or shortly thereafter.

Idaho Power is anticipating that Units 1 and 2 of the North Valmy, Nevada, coal plant it co-owns with NV Energy will be retired by 2025. Commission staff and other intervenors to the case said the company’s preferred portfolio is more costly and risky than portfolios that would close the North Valmy Unit 1 six years earlier in 2019. But Idaho Power claimed that early closure would immediately increase customer rates by $6 million annually in depreciation expense. North Valmy Unit 1 isn’t fully depreciated until 2031 and Unit 2 until 2034. Idaho Power gets about 260 MW from the North Valmy units.

Idaho Power said that while a 2019 North Valmy retirement performed well in an economic analysis, early closure carries considerable risk due to a number of factors including the Obama Administration’s Clean Power Plan and uncertainty surrounding PURPA solar projects, the completion date of the Boardman-to-Hemingway Transmission line, and whether regulators will allow depreciation expense of early coal plant retirement to be included in customer rates.

Since Idaho Power’s IRP was filed in June 2015, some of those risk factors have been lessened, commission staff said. Idaho’s emission-reduction targets under the Clean Power Plan have been reduced and the initial compliance period extended. Furthermore, a recent commission order limits solar and wind PURPA contracts to two years. The commission encouraged the company “to more clearly explain” to stakeholders why the company chose a portfolio with a 2025 closure of North Valmy instead of 2019.

Staff and other stakeholders said Idaho Power’s cost models that deduct achievable energy savings from the company’s load forecast does not treat supply-side resources and demand-side resources equally. Idaho Power claims doing so would give demand-side resources preferential treatment.

In its order, the commission said Idaho Power should further explore whether it could more effectively incorporate energy efficiency by using cost models similar to those used by PacifiCorp, Avista Utilities, Puget Sound Energy and the Northwest Power and Conservation Council.

The Idaho Conservation League said Idaho Power overestimates solar costs and Clean Power Plan compliance costs while underestimating achievable energy efficiency.

The Snake River Alliance said Idaho Power should not rely too much on completion of the Boardman-to-Hemingway transmission line because of the project’s history of delays. The utility should also take into account “social costs” related to carbon-based generation. It also said Idaho Power is not progressing rapidly enough in developing community solar projects.

The Sierra Club said Idaho Power should make an effort to more fairly estimate solar costs and should also consider transmission and distribution expense and not just generation expense in its financial analyses.

All of the intervening parties commended Idaho Power for inviting participation from various stakeholders in what they said was an improvement over past IRPs.

The commission’s approval order noted: “The Company’s short-term action plan for 2015 to 2018 addresses preferred resource portfolio items like B2H permitting and planning, and collaborating with North Valmy’s co owner, NV Energy, on planning for North Valmy’s closure. The action plan also discusses: permitting and planning for the Gateway West transmission line; evaluating how EPA’s regulations may impact fossil fuel plants; pursuing cost-effective energy efficiency; amending a Federal Energy Regulatory Commission license to adjust for the 50 MW Shoshone Fails project expansion, and completing up to a 4 MW upgrade by 2019; completing selective catalytic reduction (SCR) retrofits for Jim Bridger Units 3 and 4; and evaluating the economics of SCR retrofits for Jim Bridger Units 1 and 2.” Jim Bridger is a coal plant in Wyoming that Idaho Power co-owns with PacifiCorp.

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.