PacifiCorp’s resource plan clears the Utah Public Service Commission

The Utah Public Service Commission on Jan. 2 “acknowledged” the 2013 integrated resource plan (IRP) of PacifiCorp, which had come in for heavy criticism from various parties since it was filed in April 2013.

The commission uses the term “acknowledged” since it didn’t really approve any particular part of the plan, or really the plan overall. Each part of the plan, as executed in the future, would need a separate commission approval.

Based on its assumptions of existing generation capacity, generation plant life, length of existing purchase power contracts, transmission transfer capability, and its July 2012 load growth forecast, PacifiCorp identified in the IRP a capacity deficit between existing resources and peak system requirements, plus a 13% planning reserve, of 824 MW beginning in 2013. This deficit grows to 2,308 MW in 2022.

To meet these deficits and the continuing deficits through 2032, PacifiCorp identified a resource and transmission investment schedule based in part on the portfolio of resources selected by the computer model, System Optimizer, as its least cost plan, adjusting for risk. PacifiCorp refers to this plan as its “Preferred Portfolio.”

PacifiCorp’s Preferred Portfolio differs from another resource portfolio in one respect. Namely, PacifiCorp replaces 208 MW of wind resources selected to meet the Washington State renewable portfolio standard (RPS) with the purchase of unbundled renewable energy credits (RECs). Based on its assumption regarding REC prices, PacifiCorp contends this change addresses the Washington State RPS at lower cost for customers.

To serve system-wide peak hour demand over the next twenty years, cumulative Preferred Portfolio supply additions and direct-control load management or energy efficiency programs range from 791 MW in 2013 to about 7,159 MW in 2032. By 2032, this consists of 4,163 MW of additional intermittent, intermediate and base load power plant; 1,786 MW of direct-control load management or utility energy efficiency programs; and 650 MW to 1,472 MW of annual unspecified power purchases. The proportion of additional resources are 58% long-term generation plant (44% new gas plant or gas conversion from existing coal plants, 9% wind resource, 4% solar resource, and less than 1% combined heat and power and coal turbine upgrades), 25% direct-control load management or energy efficiency utility programs, and 17% unspecified annual power purchases.

The Preferred Portfolio assumes Segment D of the Energy Gateway transmission project is in service by Dec. 31, 2019. Segment D provides additional transmission facilities between Windstar, Wyoming, and Populus, Idaho.

Approved IRP covers about 1,700 MW of coal retirements

A notable difference in the 20-year projection of resource requirements in the 2013 IRP in comparison with the 2011 IRP is the potential retirement of approximately 1,700 MW of capacity from existing coal plants.

PacifiCorp notes during the IRP review process that it developed numerous portfolios where a large portion of PacifiCorp’s coal fleet retires or is converted to burn natural gas by the end of the 20-year planning horizon. In the 2013 IRP, 94 different core resource portfolios were developed among five different Energy Gateway transmission scenarios. Of these 94 resource portfolios, 25 showed more than 4,000 MW of coal either retiring or converting to burn natural gas by 2032. Ultimately, PacifiCorp did not select these resource portfolios as its preferred portfolio.

Environmental critics claimed that PacifiCorp did not fully estimate the potential impacts of U.S. Environmental Protection Agency regional haze mandates on its coal plants. “Because EPA’s proposed and final implementation plans and challenges to those implementation plans continue to fluctuate, we encourage PacifiCorp to continue to monitor and prudently respond to the constantly changing landscape in its IRP update to be filed in 2014 (‘2013 IRP Update’) and in the 2015 IRP,” said the commission about regional haze planning.

The coal-related action plan in the 2013 IRP included:

  • Naughton Unit 3 (Wyoming, 330 MW) – Continue permitting and development efforts in support of the Naughton Unit 3 natural gas conversion, due to occur around the end of 2017.
  • Hunter Unit 1 (Utah, 418 MW) – Complete installation of the baghouse conversion and low NOX burner compliance projects at Hunter Unit 1 as required by the end of 2014.
  • Jim Bridger Units 3 and 4 (Wyoming, 702 MW total) – Complete installation of selective catalytic reduction (SCR) compliance projects at Jim Bridger Unit 3 and Jim Bridger Unit 4 as required by the end of 2015 and 2016, respectively.
  • Cholla Unit 4 (Arizona, 387 MW) – Continue to evaluate alternative compliance strategies that will meet regional haze compliance obligations, related to EPA’s Federal Implementation Plan requirements to install SCR equipment at Cholla Unit 4.

Utah PSC addresses criticism of wind and solar cost estimates

Also, several parties argued that PacifiCorp’s wind and utility-scale solar resource costs are too high. PacifiCorp argued that its utility-scale solar resource costs are reasonable and opposed updating these costs in the 2013 IRP Update. However, PacifiCorp commited to updating its solar and wind costs for the 2015 IRP planning cycle. Further, PacifiCorp said it recognized it was unable to complete additional sensitivity scenarios to better understand the cost-point at which solar resources would be selected by the System Optimizer model in the 2013 IRP due to the time necessary for extensive model revisions, the commission noted. PacifiCorp said it will work with stakeholders to implement process improvements for the 2015 IRP planning cycle.

“As we have stated in the past, sensitivity analysis should be an effective tool for evaluating the effect on resource selection of various assumptions regarding solar and wind resource costs,” the commission ruled. “We recognize there are differences of opinion, and some uncertainties, regarding renewable resource cost assumptions. We encourage PacifiCorp and stakeholders to develop a strategy to address this issue in the 2015 IRP. Further, the results of this effort could be utilized in PacifiCorp’s acquisition path analysis to inform decisions if the future unfolds differently than expected.”

The commission’s Jan. 2 approval order concluded: “While we view the IRP as an evolving process, we find PacifiCorp has sufficiently complied with the Guidelines and therefore we acknowledge the 2013 IRP. We provide guidance herein to assist in achieving greater usefulness and transparency of IRP results and encourage wider ranges of sensitivity cases and greater use of resource acquisition path analysis for transparency of PacifiCorp decisions as market and regulatory changes occur.”

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.