The Utah Public Service Commission on Jan. 8 approved PacifiCorp‘s March 2015 filing of its latest integrated resource plan (IRP), which features planning to get rid of 2,800 MW of coal-fired capacity over the next 20 years, with the commission resisting calls from environmental groups to force the utility to shut more coal and develop more renewable energy.
The 2015 IRP covers PacifiCorp’s plan to supply energy and capacity to provide for and manage the growing demand for electricity in its six-state service territory over the next 20 years. The report identifies, as PacifiCorp’s preferred (least cost-least risk) plan, investment in a portfolio of power plants, transmission facilities, and firm power purchases, coupled with customer energy efficiency programs, and direct-control load management.
Based on its assumptions of existing generation capacity, generation plant life, length of existing purchase power contracts, transmission transfer capability, its September 2014 load growth forecast, and its 2014 study of customer driven distributed generation (DG), PacifiCorp identified a capacity deficit between existing resources and peak system requirements, plus a 13% planning reserve, of 869 MW beginning in 2015. This deficit grows to 1,834 MW in 2024.
To meet these deficits and the continuing deficits through 2034, PacifiCorp identifies a resource and transmission investment schedule based in part on the portfolio of resources selected by computer model as its least-cost plan adjusting for risk and uncertainty. PacifiCorp refers to this plan as its “Preferred Portfolio.”
PacifiCorp selected its Preferred Portfolio based on its analysis of the 20-year present value of future revenue requirement (PVRR), variations in load growth, customer DG penetration, qualifying facility (QF) contracts, fuel and market price volatility, planned transmission transfer capability, hydro variability, expected thermal outages, customer rate impacts, expectations of potential costs associated with meeting existing and potential environmental regulations, lead time required for plant construction or bidding, fuel source diversity, supply reliability, production cost variability, carbon dioxide emissions, ability to meet accelerated demand-side management (DSM) targets, the cost to acquire unbundled renewable energy certificates, and public policy goals.
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 860 MW in 2015 to about 6,592 MW in 2034. By 2034, this consists of: 2,881 MW of converted or new primarily gas-fired capacity (44%); 2,679 MW of energy efficiency programs and 41.7 MW of direct-control load management (total DSM is 41%); and 983 MW of unspecified annual firm power purchases, also referred to as front office transactions (FOTs) (15%).
The Preferred Portfolio also consists of the retirement of about 3,200 MW of existing, primarily coal-fired generation capacity. The specific coal capacity figure is 2,800 MW. Planned investment in the Preferred Portfolio during the first ten years differs from PacifiCorp’s fall 2014 business plan. The 2015 IRP relies more heavily on DSM, calling for an additional 613 MW of energy efficiency and 8 MW less of direct-control load management, and relies less heavily on utility level solar (7 MW versus 9 MW) and front office transactions (843 MW versus 1,227 MW).
The U.S. Environmental Protection Agency issued its final CO2-reducing Clean Power Plan (CPP) after the IRP was filed. PacifiCorp’s 2015 IRP includes approaches for addressing the proposed version of the CPP as well as alternative approaches for addressing regional haze requirements.
Said the Jan. 8 PSC approval: “We find PacifiCorp implements significant improvements in this IRP cycle. Chief among these improvements is a broader range of alternative scenarios of core and sensitivity cases. These cases are constructed with attention to consistent sets of assumptions for ready comparison and understanding of cost and performance metric impacts. Also of significant improvement is the abundance of supporting data filed with the Commission for inspection by all parties. The supporting data enables parties to more easily understand the process, logic, and calculations behind not only the Preferred Portfolio, but all of the underlying data utilized and various scenarios analyzed in this IRP cycle. As a result, parties are able to clearly articulate viewpoints utilizing the information contained in the IRP and provide the Commission with informed and useful comments.
“We also appreciate PacifiCorp’s improved responsiveness and interaction with state agencies and other interested parties as noted by several parties. We understand not all parties agree PacifiCorp’s Preferred Portfolio is the optimal portfolio for customers, or that the process is as transparent as it could be.
“Our acknowledgment of the 2015 IRP imparts no regulatory approval of any element of the Preferred Portfolio or of the action plan. PacifiCorp’s investment decisions and actions will be evaluated for prudence in appropriate rate proceedings. Because of our role in those evaluations it would be inappropriate to use this IRP proceeding as an opportunity to substitute our planning judgment for that of PacifiCorp. The 2015 IRP is PacifiCorp’s plan, which we find was reasonably supported at the time it was filed.”