The Market Efficiency Process Enhancement Task Force on July 5 looked at reworking packages to bring to the Planning Committee at its July 12 meeting.
Based on the lack of consensus for any one proposal as shown by the previous polling results and a last-ditch attempt at collective compromise, the task force created three new packages for consideration. To help determine the amount of support for these new packages, the task force is conducting another short nonbinding poll. The poll is now open. The poll will close on July 11 at noon.
In addition to working on Facility Service Agreement (FSA) modeling, the task force has been weighing benefits-to-cost calculation and the market efficiency reevaluation process. Conversations around the latter two topics have stalled due to fundamental differences and timing constraints. Options for modeling FSA generators have boiled down to scaling their megawatt capability based on some forecasted probability, or excluding them completely.
Steve Herling, vice president – Planning, told stakeholders that prioritizing the FSA modeling was important. Herling said rather than having a package that addressed all three categories, he would rather have one strong proposal on FSA modeling come out of Phase I, with the other two issues moved to Phase II.
Herling stressed that Phase I efforts need to be completed by August so that PJM can implement necessary changes prior to the 2018/19 Market Efficiency window, which begins Nov. 1.
He said it would be useful for the task force to use its coming set of meetings to focus on FSA generators. Delaying the reevaluation process to Phase II is workable, Herling said, but “we cannot live with the FSA as it is now.”
If PJM included current FSA guidelines in the Market Efficiency window that opens Nov. 1, it would produce misleading results, Herling said
PJM currently includes queued generation resources with an executed FSA or a suspended/interim Interconnection Service Agreement (ISA) in the base case for Market Efficiency Analysis. These units are available for dispatch in the simulations.
Many projects with an executed FSA or a suspended ISA may not ultimately connect with the system, however, and including them in Market Efficiency Base Case could mean there are unrealistic estimates of specific project benefits.
PJM is proposing to exclude, by default, all the generation resources with an FSA or a suspended ISA, along with their associated network upgrades, from the Market Efficiency Base Case.
The proposal also contains an FSA exception if any resources with an FSA or a suspended ISA is included in the Base Case at time of case build. The Transmission Expansion Advisory Committee will be notified and the assumptions will be reviewed at TEAC on an as-needed basis.
Summer-Only Demand Response Senior Task Force
Members heard an update on the PJM proposal to value summer-only demand response resources at the June 29 meeting of the Summer-Only Demand Response Senior Task Force.
There are three proposals in all. The PJM proposal, which requires only manual changes, is the only one that could be implemented in time for the May 2019 Base Residual Auction, according to senior task force chair Rebecca Carroll.
Also at the meeting, Eric Matheson of the Pennsylvania Public Utility Commission presented an overview of Proposal B and Skyler Marzewski of Monitoring Analytics provided a summary of the independent market monitor’s proposal.
The proposal that receives the highest percentage vote above 50 percent will go before the Markets and Reliability Committee for a first read at its Aug. 23 meeting.
At its July 9 meeting, the task force further discussed the proposals in the matrix.
In response to stakeholder requests, PJM provided an example of the maintenance and verification component in its proposal and posted additional analysis on how various THI thresholds impact the number of peak shaving events.
PJM will send stakeholders a poll by a target deadline of July 13, and examine the results at the July 25 meeting. The poll results will help identify where further consensus can be gained on the proposals. The goal is to have a vote at the task force’s Aug. 15 meeting.
Distributed Energy Resources Subcommittee
Members of the Distributed Energy Resources (DER) Subcommittee delayed until after the group’s July 30 meeting a vote on new manual language designed to enhance the observability of non-wholesale, behind-the-meter DER.
Members wanted more time to get input from transmission owners on the reporting and communication process for which transmission owners would be responsible.
Under the revised language, PJM would identify non-wholesale DER greater than 1 megawatt as determined by examination of U.S. Energy Information Administration forms and other available information. PJM would share this data with transmission owners, who would be responsible for providing to PJM, on an annual basis, certain information about these resources to determine their potential impact in an emergency situation such as a load shed event.
The manual changes are expected to go before the Markets and Reliability Committee for a first read on Aug. 23.
The subject of aggregated DER resources is under review by the Federal Energy Regulatory Commission.
Joint System Operations Subcommittee
Three system-wide hot weather alerts were issued in the month of June, and PJM hit its monthly peak load of 148,451 megawatts on June 18, members were told at the July 5 meeting of the Joint System Operations Subcommittee.
The system-wide hot weather alerts occurred on June 18, June 29 and June 30.
PJM also presented further analysis of the May 29 localized load shed of approximately 21 megawatts in the AEP Transmission Zone that resulted in the first performance assessment interval under the capacity performance construct.
The report reiterated that no nonperformance charges or bonus credits resulted from the event and noted that there was no possible generation dispatch that would have mitigated the overloads.
As a result of the analysis, PJM will review the outage approval process during emergency procedures. It also will review tools and technology to identify alternative solutions for when a contingency “doesn’t solve,” as well as looking at possible improvements to Manual 3: Transmission Operations and Manual 13: Emergency Operations.
In other business, the subcommittee heard:
- Reliability compliance update
- NERC lessons learned
- Automated generator notification update
- Proposed changes to Manual 13