By Rory D. Sweeney
Less than half of PJM stakeholders considering the addition of a seasonal capacity product favor a change in the current rules.
Only 48% of members who voted in the Seasonal Capacity Resources Senior Task Force poll last week favored any change, while 52% chose the status quo.
None of the five alternatives to the status quo garnered much support, with the most popular proposal — retaining the base capacity product for an additional year, delivery year 2020/21 — topping out at 43%.
Thirty-four stakeholders representing 190 companies took part in the voting.
The results of the task force’s vote were discussed at its meeting Friday. The sponsors of each option will incorporate the feedback they received into their proposals and resubmit them for reconsideration. Redlines are due Oct. 2, and the changes will be presented at the task force’s next meeting on Oct. 14. Another vote may occur shortly thereafter based on stakeholders’ response.
At question is how to allow seasonal and intermittent generation resources to offer as capacity under the tougher, year-round requirements of PJM’s Capacity Performance rules.
Although CP rules allow multiple seasonal resources to combine in aggregated offers, no such offers have been entered in auctions thus far.
PJM sought to address the issue by relaxing the current prohibition on seasonal resources aggregating across locational deliverability areas, sub-regions such as electric distribution company zones used to evaluate locational constraints.
The RTO’s proposed solution would allow resources to aggregate their production 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. This proposal received the support of only 32% of respondents.
Eligible resources would include intermittent resources, storage and summer-only demand response and energy efficiency. It would define the summer period as June through October and the following May; the winter period would run November through April.
Another proposal called winter performance equivalents would auction “WIPES” credits that allow capacity resources to not perform in the winter. Created by consultant James Wilson on behalf of the Consumer Advocates of the PJM States, the proposal was opposed by PJM and received only 21% support.
The proposal’s release of 16,500 MW from their winter capacity obligations reduces operational reliability, PJM said in comments on the proposal. The RTO said a planning analysis cited by supporters “cannot capture all the complexities of real-time operations” because of its assumptions that generator forced outages are random and independent of each other. “The winter forced outage rates have exhibited a strong correlation with lower temperatures and higher loads. PJM has also observed common mode failures across generating units. For example, the disruption of a gas pipeline will force out all single-fuel gas units being served by that pipeline,” PJM said.
The RTO also said energy market costs would increase as capacity is released.
DR provider WeatherBug Home offered a solution that would create a way to measure and value seasonal DR by using the firm service level, a predetermined load reduction.
Load is currently paying for capacity that it doesn’t use, and aggregation won’t fix that, according to the proposal. Additionally, because there is far less winter demand, it will create a situation where winter assets will essentially collect “rent” by teaming with summer resources that are much more likely to be called to perform.
WeatherBug’s plan calls for maintaining the current CP rules and limiting the amount of DR that can clear the auction. All resources can participate using their capacity ratings above their must-offer commitment, but such aggregations would only be eligible for performance bonuses if the load drops below unforced capacity obligations. This proposal received the least support at 17%.
EnerNOC’s proposal was the same as PJM’s, but with a different calculation for the balancing ratio that removes what the company called an “unreasonable barrier” for DR performance calculations. The plan received 33% approval.