The Utah Public Service Commission (PSC) on Jan. 8 acknowledged Rocky Mountain Power’s (RMP) 2015 Integrated Resource Plan (IRP), with some suggestions for the utility to address in subsequent IRPs and an update of the 2015 plan.
An update of the 2015 IRP should include information regarding any connection between the transmission planning process in the IRP and FERC Order 1000 requirements, as well as enhanced discussion of the use of historical weather information for load forecasting, the PSC said in its Jan. 8 order.
RMP included several segments of the Energy Gateway transmission plan in the preferred portfolio of resources in the 2015 IRP. Two segments in Utah already in service – the Mona to Oquirrh segment that includes 500-kV and 345-kV facilities in the northern part of the state, and the single-circuit, 345-kV Sigurd to Red Butte segment that stretches 160 miles from the middle of the state southwest to the expanded Red Butte substation in Washington County – and the Wallula to McNary segment were included in the 2015 IRP.
The $80m Wallula to McNary segment of the Energy Gateway system is estimated to be in service in 2017, according to the IRP. That segment consists of a 32-mile, 230-kV line between Wallula, Wash., and McNary, Ore., and is a portion of the Walla Walla, Wash., to McNary transmission line, after PacifiCorp in 2009 decided to move forward with the Wallula to McNary portion and delay development of the Walla Walla to Wallula portion.
RMP is part of PacifiCorp, which is owned by Berkshire Hathaway Energy, and while PacifiCorp does business as RMP in Utah, the PSC refers to the utility as PacifiCorp throughout the order.
The PSC found that PacifiCorp substantially complied with the IRP guidelines and past orders, acknowledging the plan, while noting that not all parties agree that the preferred portfolio of resources is the optimal portfolio, or that the process is as transparent as it could be.
The order “imparts no regulatory approval of any element of the preferred portfolio,” since such decisions will be made in separate proceedings, the PSC said.
The 2015 IRP, which was filed March 31, 2015, identifies a capacity deficit between existing resources and peak system requirements, growing from 869 MW in 2015, to 1,834 MW in 2024, with the preferred portfolio of resources planned to address the deficits through 2034, the PSC said. The portfolio includes transmission enhancements and supply additions, along with energy efficiency, direct-control load management and firm power purchases from the wholesale market. By 2034, the portfolio consists of 2,881 MW of converted or new natural gas-fired capacity, 2,679 MW through energy efficiency, 983 MW of firm power purchases, and 41.7 MW of direct-control load management, along with the retirement of about 3,200 MW of mostly coal-fired generation capacity.
Several parties wanted PacifiCorp to provide a better discussion on transmission planning, especially the need for other segments of the Energy Gateway transmission plan, any connection with Order 1000 requirements and the use of a System Operational and Reliability Benefits Tool stakeholder group, which was called for in a previous PSC ruling, the commission said.
PacifiCorp agreed to provide information on the nexus of the IRP process as it relates to transmission planning and Order 1000 requirements for cost allocation and interregional planning in a 2015 IRP update and future IRPs as needed, along with a discussion of transmission analysis tools for any potential construction of future Energy Gateway segments, the PSC said.
“We are encouraged by PacifiCorp’s commitment to provide the requested information,” the PSC said.
The PSC clarified that if the utility plans to use some type of transmission analysis tool in a future IRP, it “should introduce and vet the tool in an IRP workshop setting prior to utilizing the tool.”
The order notes that the use of coal-fired generation in the coming years, as well as the best way to address environmental regulations “are likely the matters of greatest disagreement between PacifiCorp and some intervening parties in the IRP process.”
Environmental groups and others challenged the continued use of coal-fired power plants and a “litigation strategy” to avoid installation of selective catalytic reduction devices to control emissions at those plants, and they asserted that the 2015 IRP should be updated to reflect the final rule in the U.S. Environmental Protection Agency’s Clean Power Plan (CPP).
The order noted that PacifiCorp included an approach to comply with the proposed rule of the CPP, and it has committed to update its modeling in a 2015 IRP update based on the CPP final rule and the latest information on state implementation plans.
“While we agree PacifiCorp will need to continue to refine its evaluation of environmental compliance options to determine least cost and least risk approaches, and it commits to do so,” the PSC accepted the utility’s work on the IRP “as a reasonable analytical approach at the time the 2015 IRP was filed.”
The PSC previously directed the utility to address the use of historical weather information and its applicability for future load forecasts, and it did not see any discussion in the 2015 IRP, so it called for PacifiCorp to include such information in an update.
The utility considered distributed generation (DG) as a reduction in load rather than a supply resource, which a few parties protested. Because the decision to add DG originates with utility customers, it appears to be reasonable to model it as a load reduction, the order said.
To improve transparency on the issue, the PSC directed PacifiCorp to identify the amount of DG it expects to see in the coming years in a baseload forecast, as it does for existing load curtailments and demand-side management resources.
While PacifiCorp modeled energy storage as a supply-side resource, it was not selected as a resource in the preferred portfolio, with a couple parties seeking more analysis from the utility.
“We encourage PacifiCorp to file an update of the energy storage screening study in its 2017 IRP, update the storage cost assumptions and consider modeling changes for energy storage following discussion with stakeholders,” the PSC said.