By Rich Heidorn Jr. and Rory D. Sweeney

COLUMBUS, Ohio – PJM officials said Wednesday they will seek FERC approval of the RTO’s seasonal capacity proposal despite a lack of stakeholder consensus.

The proposal, which would relax the current prohibition on seasonal resources aggregating across locational deliverability areas, received less than one-third support in a Seasonal Capacity Resources Senior Task Force poll last month. (See No Consensus Among PJM Stakeholders on Seasonal Resources.)

Adam Keech, executive director of PJM market operations, told the annual meeting of the Organization of PJM States Inc. that the PJM Board of Managers had approved making a FERC filing in November.

In addition to what Keech called PJM’s “facilitated aggregation” proposal — which is intended to improve the ability of intermittent resources and demand response to participate in the capacity auction — the RTO also will consider changes in load forecasting and incorporating summer DR’s curtailment capabilities after the auction, Keech said.

“We’re looking for other ways to value seasonal resources” in addition to changes in capacity rules, Keech said. “We recognize there’s more work to be done in this area.”

Keech said PJM’s proposal is a response to complaints that the aggregation options offered to seasonal resources under Capacity Performance rules are unworkable because of the difficulty summer and winter resources had in “finding one another” and reaching commercial agreements.

Under the proposal, PJM would match summer and winter resources, eliminating the need for commercial ties between them. Summer and winter resources would have separate six-month obligations and would not be liable for another resource’s nonperformance.

The RTO’s proposal also would allow resources to aggregate beyond LDA borders, with unmatched resources moving up to the next LDA level until a match is found. For example, an offer containing individual resources located in the EMAAC LDA and SWMAAC LDA would be modeled in the MAAC LDA. An offer with resources in COMED and EMAAC would be modeled in the “Rest of RTO.” Performance penalties would be distributed evenly between the resources, no matter which failed to perform.

Measurement Rules, Injection Rights, Load Forecasting

Keech said PJM also will propose a change in how it measures winter DR, returning to the former firm service level (FSL) calculation “that is more conducive for demand response capability for industrial resources.”

PJM also plans to propose that wind be able to obtain higher winter capacity injection rights, in recognition that wind farms, which are rated at a 13% capacity factor in the summer, can produce 40% of their nameplate capacity in the winter. Hydro resources “potentially” could receive higher winter injection rights as well, Keech said.

Another initiative will seek ways to better incorporate DR into load forecasts, which would reduce costs by reducing the amount of capacity procured. PJM’s current method requires load reductions to be repeated for 15 years before they are reflected in the load forecast, Keech said. “There’s probably some room to improve in that area,” he said.

In addition, PJM is considering registering summer load curtailment capabilities after the capacity auction, which he said will borrow from its former interruptible load for reliability (ILR) program and “operational attributes” concept.

“We realize the operational flexibility value to that,” Keech said, adding “the details remain to be ironed out.”

Mixed Reception

The announcement of PJM’s plans got a mixed reception from other speakers at the OPSI meeting.

John Farber, an analyst with the Delaware Public Service Commission, called PJM’s choice “disappointing.”

Susan Bruce, counsel for the PJM Industrial Customer Coalition, said the group supports PJM’s filing. “We think it will help with the next auction,” she said. “It’s not a silver bullet though.”

Katie Guerry, of DR aggregator EnerNOC, made a pitch for her company’s proposal, which combined PJM’s plan with a “balancing ratio” that changes how DR is valued. It won support from one-third of the task force. Keech said PJM is discussing whether to apply the balancing ratio — currently used only for generation — to other resources.

James Wilson, a consultant for state consumer advocates, said PJM’s proposal falls short of his winter performance equivalents plan, which would auction “WIPES” credits that allow capacity resources to not perform in the winter. Opposed by PJM, Wilson’s proposal was supported by less than a quarter of task force members.

Wilson said the 2014 polar vortex was “a real wake-up call on the value of winter capacity” and said the CP rules properly created much stronger incentives for performance.

But he said CP went in the “wrong direction” in not recognizing the seasonal nature of both capacity resources and PJM’s peak loads. PJM’s projected 2020 summer peak load is 20,000 MW greater than its winter peak in a 50/50 forecast — with the difference rising to 26,000 MW in a 90/10 forecast.

“PJM’s reliability studies have always suggested that all of the outage risk is really in the summer, not in the winter,” he said.

Wilson said his “simple simulation” found that a “full seasonal” approach would save ratepayers about $1 billion annually by procuring 20,000 MW less in winter and accommodating more participation by seasonal resources — solar, wind and DR.

He said separate summer and winter price signals “would be potentially very helpful” for both renewable developers and gas-fired generators weighing the cost of obtaining firm gas supplies in winter.

Wilson praised PJM’s efforts to revise its load forecasts to recognize increasing energy efficiency. The changes reduced the forecast peak for the 2019/20 Base Residual Auction by 5,660 MW (-3.5%). (See Changes to PJM Load Forecast Cuts Benchmark Peaks.)

“But it’s too soon to … conclude that we’ve solved the over-forecasting problem,” Wilson said.

No Consensus in Task Force

The task force polled members last month on five proposed rule changes, with the most popular proposal — retaining the base capacity product for an additional year, delivery year 2020/21 — claiming 43% support. Only 48% of members who voted favored any change, while 52% chose the status quo.

Bruce Campbell of energy management company CPower said “a handful of large entities” can skew the voting in lower committees not subject to sector-weighted voting because they have multiple business units represented with stakeholder votes. “It’s my opinion that that probably has happened in this case,” he said.