By Christen Smith
PC Moves Forward on Offshore Interconnection Rights
Current rules allow merchant transmission developers to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO. Under the problem statement, stakeholders will consider allowing merchant transmission developers to request CIRs, or equivalents, for non-controllable AC transmission offshore, PJM’s Sue Glatz said.
The vote came after PJM officials resisted calls to broaden the initiative to also consider rules for non-controllable AC transmission facilities onshore.
“My concern is that in essence what we are doing is that we are going to prioritize the transmission facilities built out into the ocean, but we are not giving a path for the same thing to occur for facilities with future plans to connect to renewable resources,” said Ryan Dolan, director of transmission planning for American Municipal Power. “We are mitigating risk for offshore and not doing the same thing for AC onshore.”
Offshore transmission developers want to acquire CIRs so PJM can identify the necessary network upgrades.
The key difference from the normal procedure is that the developers want to build transmission before the generation is sited. Without generation at the other end of the line, PJM cannot perform stability or short-circuit analyses. (See “PJM Ponders Rules for Offshore Wind Transmission,” PJM PC/TEAC Briefs: Jan. 10, 2019.)
PJM said the narrow scope of the problem statement addresses an immediate need from pending interconnection requests.
The RTO hopes to develop a FERC filing on Phase 1, focusing on rules for a single offshore generator lead line, by July.
Steve Herling, PJM vice president of planning, said the RTO could discuss extending similar rights to onshore developers in Phase 2 of the initiative, when it will consider networked offshore transmission for connecting multiple wind sites.
“We don’t have a fundamental issue with doing the same thing onshore … but because of the immediacy of the need, we would prefer to develop this with respect to offshore and then it would probably be a fairly straightforward extension of it in Phase 2 if there’s value of doing it onshore,” Herling said. “We do feel a sense of urgency offshore.”
PJM has targeted Phase 2 for a September 2020 FERC filing.
Quick Fix for Queue Filing Errors Endorsed
The PC approved a problem statement and solution to prevent transmission customers from falling out of the interconnection queue because of minor errors.
The one-sentence rule change allows customers 10 days to fix any deficiencies in their requests — whether they submit their application on the first or the last day of the new services request window.
PJM’s Susan McGill first presented the problem statement to the committee in January, suggesting the RTO reverse rules implemented in 2016 by the Earlier Queue Submission Task Force that didn’t allow requesters adequate time to clear errors found in their submissions. (See “PJM Seeks Fix on Queue Filing Errors,” PJM PC/TEAC Briefs: Jan. 10, 2019.) The change — intended to encourage generation customers to submit requests earlier in the six-month window — led to a 6% increase in terminated or withdrawn applications filed in the last month.
PJM is proposing to give all projects 10 days to address problems by removing the following sentence from the Tariff: “Any queue position for which an interconnection customer has not cleared the deficiencies before the close of the relevant new services queue shall be deemed to be terminated and withdrawn, even if the deficiency response period for such queue position does not expire until after the close of the relevant new services queue.”
The problem statement is scheduled for endorsement at the March 21 Markets and Reliability Committee meeting. It would be effective with queue AF1, which opens April 1.
PJM Pushes Change in Wind, Solar Capacity Measurements
PJM has decided to use effective load carrying capability (ELCC) to calculate wind and solar capacity credits, calling it a “superior alternative” to current rules using average values. ELCC measures the additional load that a group of generators can supply without a reduction in reliability.
The new methodology combines wind and solar capacities in one calculation that is later prorated. Tom Falin, PJM’s director of resource adequacy planning, said this process sets wind and solar factors to 12.3% and 41%, respectively.
“I think all along we should have done this in a composite manner,” he said. “Why? Because both wind and solar are going to be around to serve PJM load. It’s a model of the entire system.”
Falin said considering the total amount of intermittent generation is crucial to the process, noting the “point of ELCC is to really figure what’s the incremental value of a new type of unit when you add it to the existing fleet.”
Some stakeholders disagreed with PJM’s decision to calculate solar and wind capacities together, citing their different characteristics.
“I agree they are both going to be here, barring some disaster,” said John Brodbeck of EDP Renewables. “We’ve been working them as separate numbers. … I haven’t noodled through what this does here. It just seems to mix apples and oranges.”
The new rules will be included in Manual 21 changes that will be presented to members in March. PJM wants to request MRC endorsement by the April meeting so that unforced capacity (UCAP) values for wind and solar can be posted by May 1 for use in the 2022/23 Base Residual Auction in August. They would not affect UCAP values from prior auctions.
Holistic Review of RTEP Removal Suggested
PJM said Thursday it’s considering drafting a problem statement regarding how projects get removed from the Regional Transmission Expansion Plan, suggesting the process needs a “holistic” review.
PJM’s Aaron Berner said because of differing regulatory requirements in its 13 states, the RTO has dealt with cancellations on a case-by-case basis. Cancellations can result from a reduction in load forecasts — eliminating the need for a project — or because developers are unable to get state siting approval.
“In the past there have been changes to the load profile or the actual load forecast that’s resulted in a reduction for a need for reinforcement on the system, and we have pulled some baseline upgrades based on that,” he said. “Primarily, it’s our need that drives our decision around the various insertions and removals of the project.”
The issue arose after Sharon Segner, vice president of LS Power, proposed an amendment to Manual 14B: PJM Region Transmission Planning Process specifying that a transmission owner’s supplemental project “will generally be removed from the RTEP” following a final order by a state siting agency rejecting the project.
“It’s very important that the rules be very clear with how projects are added to the RTEP and how they are removed,” Segner said. “We stand behind the viewpoint that PJM should be a strong regional planner and have complete authority over the regional and supplemental process.”
Segner first presented the new manual language during the Jan. 24 MRC meeting as a friendly amendment to a proposal from American Municipal Power to increase transparency of supplemental project planning. AMP accepted the amendment as friendly. Despite winning a majority of stakeholder approval, PJM declined to implement the entirety of the AMP proposal, calling it an overreach of the RTEP. (See PJM Rebuffs Stakeholders on Supplemental Projects.)
PJM said it will discuss the issue further with stakeholders after identifying requirements in the Operating Agreement, Tariff and manuals that spell out when projects should be removed from or added to the RTEP.
Segner declined to say whether she will seek a vote on her language at the MRC. “I’m still getting feedback; the purpose of this discussion was to talk through substance. It’s not a procedural discussion today,” she said. “PJM said they’re taking this [PC discussion] under advisement. That’s what LS Power is doing as well.”
Dominion, ATSI Present Supplemental Projects at TEAC
TOs presented two supplemental projects to the Transmission Expansion Advisory Committee.
American Transmission Systems Inc. plans upgrades to a 345-kV line between Erie, Pa., and the Perry nuclear plant in Ohio. The three-terminal line is prone to misoperations and subject to longer restoration efforts, and its relay transmission communication equipment is nearing its end of life, ATSI said. No cost was listed.
Dominion Energy Virginia presented seven supplemental project needs and one solution, a second distribution transformer at the Greenwich substation to address growing load. The $1.4 million project is expected to be complete by Oct. 15.
Dominion listed the following needs:
- A third distribution transformer at the Winterpock substation;
- A second distribution transformer at the Rockville substation in Goochland County;
- A second 84-MVA distribution transformer at the Cumulus substation in Loudoun County;
- A new Lockridge substation to support a new data center campus in Loudoun County with a total load exceeding 100 MW;
- A third 84-MVA distribution transformer at the Pacific substation in Loudoun County;
- A new Perimeter substation to support a new data center campus in Loudoun County; and
- A new Relocation Road substation to support a new data center campus in Loudoun County with a load exceeding 100 MW.