By Rory D. Sweeney
FSA Unit Plan
VALLEY FORGE, Pa. — PJM is reformatting and drafting clarifications to Manual 14B: PJM Region Transmission Planning Process that may impact the RTO’s planning modeling, staff told attendees at last week’s Planning Committee meeting.
The proposed revisions would clarify that units with facility service agreements (FSAs) will only be added to the base case if there are not enough existing units and units with interconnection service agreements (ISAs). Units with FSAs that are not included in the base case will be subject to a sensitivity study to determine if long-lead-time upgrades are required to support them. The long-term base case will only be studied if the need for a long-lead-time upgrade is identified during the near-term base case analysis extrapolation over Years 6 through 15.
Additional clarifications include:
- Higher-than-normal capacity interconnection rights (CIRs) may be granted to wind units when justified by meteorological data.
- Flowgates near PJM’s borders will continue to be examined to understand deliverability concerns that may exist due to loop flows.
- Merchant transmission facilities (MTFs) with long-term firm transmission service will be modeled the same as MTFs with firm transmission withdrawal rights.
- Operational contingencies are single contingencies examined under the common-mode outage procedure to determine whether system operators would allow the common-mode dispatch to occur.
- Constraints identified in the PJM capacity import limit (CIL) analysis are studied in the same manner as other internal PJM constraints.
- The distribution of the capacity benefit margin from each of the five external supply zones is determined during the annual PJM CIL study.
PJM’s Jonathan Kern said the clarifications were intended to be pre-emptive measures to avoid confusion in the future.
Staff plan to update Manual 14G: Generation Interconnection Requests to identify which user-defined models (UDMs) it has already approved for wind turbines and other inverter-based resources. Developers planning to build affected generators would need to use the tables to determine whether they would need to submit additional information about modeling their units to receive PJM approval.
PJM’s Tao Yang said the list would likely be updated annually.
PJM’s Ken Seiler, who chairs the PC, said standardizing the stability modeling is important so generation interconnection requests can be processed “much faster.”
ELCC Analysis of Intermittent Resources
PJM’s Tom Falin said the RTO is targeting an endorsement vote at the March meeting of the PC for a package of four changes for how capacity credits are calculated for intermittent resources.
One of the prospective changes, resources’ effective load carrying capability (ELCC), has received “a lot of discussion lately,” Falin noted. PJM scheduled a special session of the PC on Dec. 21 so the RTO can get “a read” on stakeholders’ interests. (See “Renewables’ Capacity Analysis Extended,” PJM PC/TEAC Briefs: Nov. 8, 2018.)
The question to answer, he said, is “do we think moving to an ELCC methodology is the right thing to do?”
PJM’s Jerry Bell will return to the PC in January to reintroduce the proposed changes with whatever consensus on the ELCC is gleaned from the special session.
PJM’s Mark Sims said staff have gathered all of the pieces necessary to develop the comparative framework for cost containment and return on equity that stakeholders endorsed earlier this year. (See “Update on Integrating Cost-containment Guarantees,” PJM PC/TEAC Briefs: Sept. 13, 2018.)
“The moving parts we’re dealing with … include not only the uniqueness of the proposals that we might receive but … the complexity of the cost-containment proposals we might receive … [so] there’s a couple of big moving parts,” Sims said. “We have all the building blocks we need to pull the process together in 2019. … We can see where all the pinch points are.”
As part of the process, PJM and its Independent Market Monitor met with an independent consultant on Nov. 15 to better understand cost estimating, revenue requirements and other components for developing cost proposals. PJM continues to work with the contractor, and stakeholders questioned how the RTO would handle a situation if the contractor eventually took a contract that created a conflict of interest. PJM’s Sue Glatz said it “would be a given” to re-evaluate the relationship if staff “saw anything” that affected the contractor’s independence, but that “right now we don’t see any conflicts.”
Sims said he plans to return to the committee in January with more detail on the process.
Work in the Market Efficiency Process Enhancement Task Force (MEPETF) has progressed to polling on how to proceed with revising the market-efficiency process, PJM’s Fran Barrett said. At the task force’s Dec. 7 meeting, stakeholders developed a list of nine questions for the poll, including the preferred method for re-evaluating already-approved market efficiency projects and the preferred cycle for PJM to conduct the market-efficiency process.
“That means we’ve got a lot of work in January and February. It’s going to be pretty swift and a lot of hard work,” Barrett said.
Staff are targeting the March PC meeting for a first read of the most popular options so the package proposal can be implemented on Nov. 1.
Offshore Wind Zones
With many coastal states announcing offshore wind solicitations, PJM is now developing concepts for alternative ways to interconnect all of the coming megawatts, Glatz said. She explained that developers have approached staff with challenges and said they’d like to have multiple interconnection points, along with the ability to create offshore transmission networks. Staff are considering how to handle those desires and are seeking input from the PC on a variety of questions, including what studies might be required, what interconnection rights might be offered and whether the rights could be transferrable.
Glatz said staff are targeting the January or February meetings of the PC to introduce proposed concepts and related Tariff revisions. Stakeholders said they had no foundation on which to base their input and called on staff to create a problem statement and issue charge on the topic. But staff voiced concerns about the initiative getting bogged down in debates.
“We have real projects today, so the challenge is how can we be responsive to our customers?” Glatz said, adding that states want to limit impacts to communities while also providing the necessary resources.
The plan is potentially a move toward creating open-access offshore networks as an extension of the onshore grid that has been advocated by stakeholders like Markian Melnyk, president of Atlantic Grid Development. (See Offshore Wind Industry ‘Really Moving;’ Coordination Key.)
However, PJM is currently considering only plans that are “strictly for injecting into PJM,” not connecting to other RTO/ISOs, Glatz said.
2019 Load Forecast
The RTO’s preliminary 2019 load forecast is down compared to last year, PJM’s John Reynolds explained. Both the summer and winter forecasts are down at least 0.4% from last year’s forecasts.
The analysis uses the summer forecasts for 2022 and 2024 and the winter forecasts for 2021/22 and 2023/24 to make year-over-year comparisons. The summer 2024 comparison is down 0.5%, slightly more than the other three. Staff are adding a zone summary page for 2019 that details zonal impacts.
The report remains preliminary for now because there were issues with forecasts in the Dayton Power and Light and East Kentucky Power Cooperative zones that are still being revised. The final version, expected by the end of December, will be used for all Regional Transmission Expansion Plan studies.
Because the Base Residual Auction is delayed this year to attempt to implement revisions to the capacity auction construct, PJM staff will develop a second load forecast just for the BRA that would include peak-shaving adjustments.
Reynolds confirmed that the forecast only includes load that PJM system planning staff are working on and nothing speculative.
PJM’s Aaron Berner presented analysis from staff’s recent initiative on developing “cascading trees” on load-loss probabilities that shows one facility has a high probability of losing at least 1,000 MW of load.
“This gives us an idea about potential weaknesses based on initiating events,” Berner said, but he cautioned that more work will be necessary to make sure staff are not “looking at things we shouldn’t be.”
Deactivation and Acceleration
PJM’s Nick Dumitriu said the 2018 reliability project acceleration analysis found no projects to accelerate to reduce congestion. Project B2766 would ease congestion, but it was already accelerated last year to 2020 and the developer said it can’t be accelerated further.
PJM is performing reliability analyses for deactivation of 30 units, all of which have requested to deactivate no later than June 1, 2020.
Dominion Energy’s Ronnie Bailey presented three new need assessments and three planned solutions as part of the transmission owners’ new FERC-ordered process for developing supplemental projects. Dominion has presented 19 needs assessments since the process was implemented in September. Dominion has been presenting such needs and planned solutions for several months. (See “Dominion Supplementals,” PJM PC/TEAC Briefs: Oct. 11, 2018.)