Intervenors mostly praised Portland General Electric's 2019 integrated resource plan, but questioned some of the plan's methodology, along with timing of the action plan and how the utility expects to fill its capacity deficits, according to comments filed with the Oregon PUC.
PGE submitted its 20-year resource plan with the Oregon commission in July [LC 73]. The plan relies on energy efficiency, demand response and large acquisitions of renewable energy, but also shows a capacity deficit of 350 MW in 2020 that could grow to 1,000 MW by 2025.
The utility's action plan calls for acquiring 150 aMW of renewable energy that would enter service in 2023, and targets 157 aMW of energy efficiency by 2025. PGE also plans to pursue an agreement for existing capacity in the region, but would conduct a request for proposals for "non-emitting resources" to meet its capacity needs if that doesn't work.
The staff of Oregon PUC said it was concerned the utility is "more focused on acquiring renewables by 2023 than investigating zero-carbon approaches to its capacity needs in 2025."
In their comments filed Oct. 11, staff said "it would be more prudent" for the action plan to place greater emphasis on not only contractual renegotiations, but also to begin exploring higher levels of demand response acquisitions, better use of transmission assets to increase imports, and "taking steps to better understand the financing and timing associated with new, potential low emissions capacity products such as distribution-scale batteries and utility-scale pumped storage."
"Waiting until the next IRP action plan to explore a more holistic set of capacity options may leave PGE with less ability to avoid the addition of new fossil-fuel thermal generation in the mid-2020's, something PGE is currently saying they want to avoid," staff said.
Staff went on to note it is "intrigued by the potential of pumped storage as a zero-emissions, flexible capacity resource."
"However, the IRP's approach to pumped storage does not align well with the actual process to permit and construct this long-lead time resource," according to comments.
Based on statements from National Grid and Rye Development, the IRP's proposed timing does not support their proposed hydro pumped storage project coming on line in time to meet PGE's projected capacity need in 2025, or the "Mixed Full Clean" portfolio's 200 MW of pumped storage resource in 2024, staff said.
PGE's action plan indicates pumped storage will be included in the potential 2021 request for proposals for resources called out in the IRP, but PGE's proposed timing may be too late for pumped storage to serve as a viable longer-term capacity solution, staff said.
Staff said it "finds merit in exploring how to accelerate simultaneous evaluation of new and existing capacity resources ahead of PGE's forecasted capacity need in 2025."
"Pumped storage represents a unique generation product that can address both PGE and the region's capacity needs with no direct emissions," staff said. "This resource could also assist with the integration of more renewables as part of a long-term decarbonization plan. Given the potential risk that capacity from federal system hydro resources may not be available post 2025 in the same quantity as today because of additional fish recovery measures or a more lucrative California capacity market, the timing to secure additional capacity is important."
Staff said it was "intrigued" by the suggestion from pumped storage developers that PGE conduct an "all encompassing RFP" by adjusting the action plan to run two RFPs simultaneously—one for renewables, the other for non-emitting capacity that could come on line by 2025.
OPUC staff also took issue with the preferred portfolio from the IRP modeling, saying the "Mixed Full Clean" portfolio was among the top performing only after PGE's nontraditional screening metrics were applied.
"However, Mixed Full Clean is not the top-performing portfolio for cost and risk," they said. "Staff is concerned about the decision to pick a portfolio other than the top-performing portfolio. PGE should provide an analysis comparing its preferred portfolio to other top-performing portfolios for cost and risk, and explain why the company believes it has chosen a portfolio with the best balance of cost and risk, as required by the IRP guidelines."
Renewable Northwest praised the focus on non-emitting resources in the IRP's action plan, but had concerns "about the potential that PGE's methodology to determine solar integration costs may be overstating the variability of solar that PGE is likely to integrate and therefore overstating the actual cost of integrating that solar."
The renewable energy advocacy group also encouraged PGE "to explore the impacts of exiting Colstrip units 3 and 4 by 2027," saying it was "encouraged by PGE's findings that there may be economic benefits to exiting Colstrip units 3 and 4 earlier than 2034."
"We encourage PGE to further refine its Transmission Proposal as well as its solar integration cost methodology and its analysis of the costs and risks associated with its ownership of Colstrip units 3 and 4," Renewable Northwest said.
NW Energy Coalition said it supports "the general approach of the Mixed Full Clean portfolio," but "allowing energy efficiency to be overshadowed by other, more dynamic elements of the IRP is a mistake."
"Energy efficiency continues to be our most reliable resource, reducing system costs for customers, lowering PGE's carbon emissions by a considerable factor, and, at the same time, providing uncounted health and comfort benefits to customers that undertake efficiency and even those that do not directly partake in programs," the coalition said.
NWEC said it "strongly believes that now is the time to make demand side capacity and flexibility a full part of system management, not merely a small, supporting role."
"There is an immediate need to meet near term capacity requirements, as well as set a longer-term path toward a better balance of supply and demand side contributions to the system. This provides urgency for even more focus on 'distributed flexibility.'"
The IRP said distributed flexibility and distributed standby generation together could avoid the need for approximately 200 MW of capacity in 2025, and NWEC said "it believes the actual achievable potential is considerably greater, particularly heating demand reduction in winter, cooling demand reduction in summer and water."
The Northwest and Intermountain Power Producers Coalition recommended OPUC decline to acknowledge PGE's IRP transmission plan because the utility "completely failed to consider transmission cost, transmission risk and transmission need, and failed to incorporate those critical elements into its resource plan."
The lack of analysis of transmission cost, risk and need associated with the preferred portfolio justifies additional analysis from PGE, and the commission should not acknowledge the IRP without requiring such additional analysis, NIPPC said in comments.
The coalition also took issue with how bids in the RFP would be scored, saying "PGE's analysis of the renewable RFP elements, scoring methodology and associated modeling are little different than in past IRPs, and fail to make any reasonable effort to comply with the commission's new rules."
NIPPC also raised concerns with PGE's analysis of its direct access customers.
"PGE does not perform a rigorous analysis of risks from direct access, but instead offers a capacity calculation in a vacuum that produces an absurd result, suggesting that, if PGE included load from long term direct access customers as part of its IRP (which it currently does not do), PGE should be required to acquire and hold 125 percent of the capacity for servicing such long term direct access load-load that does not want to be served by PGE," it said.
The Alliance of Western Energy Consumers largely agreed with NIPPC's take on direct access, saying PGE's proposal "will result in substantial cost increases for direct access and cost-of-service customers, resulting in as much as $100 million in additional capacity costs, and at a levelized value that is substantially higher than the costs of PGE's existing resources."
If the commission fails to reject PGE's proposal outright, AWEC recommends that it defer consideration of PGE's proposal to the ongoing process in UM 2024, OPUC's general investigation into long-term direct access programs, the advocacy group said in comments.
AWEC also disagreed with the IRP's plan to acquire 150 aMW of renewables by 2023.
"PGE's proposal is not based on need, but on a forecast of economic benefits over the long term and clean energy policies that are not specific to its customers or the rates they pay for utility service," it said.
AWEC also disputed PGE's reference case forecast of a 685 MW capacity deficit by 2025, saying it did not consider capacity resources acquired from PGE's Green Energy Affinity Rider customers; it also assumes far less market import capability than its transmission rights allow; and PGE is likely to meet a substantial portion of this deficit through bilateral negotiations.
OPUC will hold a workshop Oct. 31 to review PGE's IRP filing.