Idaho Power Company and PacifiCorp’s Rocky Mountain Power Predict Very Different Energy Futures for Idaho over the Next 20 YearsAdded by Dana Hofstetter in Articles & Publications on August 15, 2018
Southern Idaho’s two privately owned electric utility companies, Idaho Power Company and PacifiCorp’s Rocky Mountain Power, have significantly different projections for the use of wind and solar resources to supply customers over the next 20 years. Idaho Power Company serves Idaho’s Snake River Basin, extending from Blackfoot west to the Oregon border and north to McCall, while Rocky Mountain Power serves the portions of Idaho roughly extending from the Wyoming border to where Idaho Power’s service area starts near Blackfoot/Pocatello. Although both serve Idaho, they envision very different energy supply futures for their respective regions.
Every two years utilities are required to develop Integrated Resource Plans (IRP) to identify the best mix of energy resources, taking into account cost and risk, to guide planning for the next 20 years. Essentially, IRPs are energy demand and supply (or, in energy business lingo, “load and resource”) planning tools that energy companies and public utility commissions use as blueprints to ensure electrical utility service needs will be met into the future. Idaho Power’s latest IRP, issued in June 2017, projects developing new natural gas based production to meet its additional energy needs through the year 2036. On the other hand, over the next 20 years, PacifiCorp’s 2017 IRP, updated in May 2018, envisions adding about 2,700 megawatt (MW) of new wind capacity, largely in Wyoming, and 1,800 MW of new solar capacity, primarily in Utah, in lieu of adding any new gas or other fossil fuel production facilities.
Certainly some of these planning differences are due to the different areas these utilities serve, with Idaho Power serving portions of Idaho and Oregon and PacifiCorp serving portions of these states, but also serving California, Utah and Washington. All these states, except Idaho, have mandatory renewable portfolio standards (RPS) or, at least, in the case of Utah, non-mandatory RPS goals about supplying a certain of amount of electricity from renewable energy resources, such as wind, solar or geothermal. PacifiCorp’s strategy of employing more renewable resources may be motivated, at least in part, by its need to meet these RPS standards in the future with a system that currently is largely fossil fuel based. According to the Idaho Governor’s Office of Energy Resources’ March 2018 Idaho Energy Landscape report, as of 2015, PacifiCorp’s energy production was 62% coal, 15% Natural Gas, 7% wind and 5% hydroelectric, while in 2017, Idaho Power’s fuel mix relied to a lesser degree on fossil fuels, composed of about 50% hydroelectric, 18% coal, 8% natural gas with 10% wind and 3% solar.
It cannot be ignored that cost, not just regulatory mandates, played a role in PacifiCorp’s recent rejection of additional fossil fuel derived capacity. In its original 2017 IRP issued in April 2017, PacifiCorp proposed adding 1,300 MW of new natural-gas-fired capacity; but in its 2018 update to that IRP, PacifiCorp rejected all additional fossil fuel capacity noting, “With reduced loads and lower renewable resource costs, the updated preferred portfolio contains no new natural gas resources through the 20-year planning horizon. This is the first time an IRP has not included new fossil-fueled generation as a least-cost, least-risk resource for PacifiCorp.” Certainly, available federal production tax credits was one of the factors influencing PacifiCorp’s analysis of wind power cost.
What both companies’ IRPs have in common is a planned reduced reliance on coal into the future. Both companies are partners in the Jim Bridger coal plant and both project that Jim Bridger Units 1 and 2 will be retired within the next 20 years. Overall, PacifiCorp anticipates retiring about 3,650 MW total of coal-based capacity during this time period at Jim Bridger and at some of its other coal facilities, including at its Naughton and Dave Johnston plants in Wyoming and at its Huntington plant in Utah. Idaho Power also expects to take its coal-fired North Valmy plant in Nevada out of service by 2025. It appears that some of these planned coal facility retirements may be based in part on the expense of possibly needing to install pollution control equipment.
Electric utility planning is complex, involving cost/risk analysis that takes into account, not just traditional supply and demand economics, but also regulatory issues and projections. For this reason, perhaps it is no surprise that Idaho Power and Rocky Mountain Power, two utility companies serving Idaho, have predicted very different energy supply strategies for the future. Only time will tell whether these different strategies will adequately meet the electrical supply needs of the future.
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