Monday, February 18, 2019

PJM PC/TEAC Briefs: Aug. 9, 2018

Manual 14F Changes

VALLEY FORGE, Pa. — Opponents and advocates of new rules to increase the importance of cost containment in transmission project proposals found themselves in uncommon agreement at last week’s PJM Planning Committee meeting.

Both shared concerns over the RTO’s plan to delay inserting some language for the new rules into Manual 14F.

Staff explained that it was a last-second decision meant to avoid confusion for those reading the manuals, and while stakeholders didn’t fully support the explanation, they eventually agreed to endorse some of the modified manual revisions but defer voting on the cost-containment language.

The wide-ranging changes include revisions to PJM’s processes for selecting “market efficiency“ transmission projects and prequalification for submitting proposals. But stakeholders were focused on how PJM plans to implement the cost containment rules, which were endorsed earlier this year following a controversial stakeholder process. (See Cost Containment Clears MC Vote Despite PJM Plea.)

While some of the changes could be implemented immediately, two frameworks for comparing projects are being developed by PJM and its Independent Market Monitor. The first framework on construction costs is expected to be ready for use in December, while the second comparing return on equity and capital structures is expected by May. Because they aren’t ready for use, staff decided to keep language revisions related to frameworks out of the public version of the manual. They are being maintained in an internal version that will be brought for stakeholder endorsement once the frameworks are finalized.

pjm inverter based generators

PJM’s Jason Shoemaker | © RTO Insider

“The manual is a reflection of what’s in effect today, and the comparative process is not a part of that today,” PJM’s Jason Shoemaker explained.

LS Power’s Sharon Segner, who led the campaign to get the cost containment language endorsed, said PJM would be “picking and choosing” which parts of the approved revisions it’s implementing.

“This is kind of different than what was communicated to me just a few days ago as far as the approach, so I’m just concerned,” she said.

Alex Stern of Public Service Electric and Gas, who largely opposed Segner throughout the cost containment battle, joined her in expressing concern because staff was not being clear with exactly what changes it was proposing from what was presented at the first reading last month and its meeting materials did not reflect the changes or represent the statements being made. His concern stemmed particularly from PJM’s representation that it was removing language from the manual that had received stakeholder endorsement. Withholding the language related to the frameworks from the revisions up for endorsement wasn’t clearly spelled out in the issue presentation PJM posted online prior to the meeting, and Stern questioned whether an endorsement should move forward when significant changes were being unclearly communicated immediately before the requested endorsement vote.

“This is a change also from my point of view,” he said. “I’m not clear as to why you’re carving it out.”

PJM’s Sue Glatz assured stakeholders that the withholding was limited to one section in the manual and a note would be included explaining that the material will be added later “so it’s not being lost.” She pointed out it would also be captured in the meeting’s minutes.

PJM’s Steve Herling said it wasn’t the first time staff had used this tactic, so he didn’t understand the “nervousness.” Including it now wouldn’t impact whether — or how quickly — the frameworks are completed, he said, and “it’s highly likely“ that additional manual language beyond what has already been approved will be needed to comprehensively detail the process.

“We can’t post language … [that] will cause confusion if it’s not ready to be implemented. People will be reading the manuals,” he said. “When it is ready to be implemented, it will be posted.”

“I think taking out the note causes more confusion than it helps,” Stern said. “I’m actually confused the other direction how it helps to carve this out when there is the confusion. … I’m really not sure what people are concerned about.”

Once the situation was explained, Tonja Wicks of Duquesne Light said she was supportive of PJM’s plan. American Municipal Power’s Steve Lieberman said he was “sensitive” to Herling’s points.

PJM eventually offered to remove the cost-containment language from the endorsement vote proceeding, with the Manual 14F changes focused on market efficiency procedures.

Following additional debate, Segner eventually decided to trust the process.

“I’m still a little confused, but I think we’re on the right path, and I’m going to support this today,” she said.

PJM’s Mark Sims reviewed staff’s planned timeline for implementing the cost containment measures. He explained that the comparative frameworks will help staff put proposals into a fuller context that includes constructability and financial data, along with risk evaluations.

DER Ride-through

Staff are asking stakeholders for the opportunity to investigate whether certain operating parameters for inverter-based generators create a reliability risk for the grid.

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A PJM analysis shows how DERs not using ride through worsens system reliability, while using it improves reliability. | PJM

PJM’s Andrew Levitt presented a proposed problem statement and issue charge to determine whether the “ride-through” settings for distributed energy resources like residential wind and solar might create low-voltage risks. For safety and other reasons, DERs are configured to trip off within two seconds if they experience under- or over-voltage. As the amount of DERs grows, all of them tripping during such an event could exacerbate the situation. A new industry standard would address that issue by requiring DER to ride through certain system fluctuations.

Levitt had previously approached the Operating Committee in March about transmission owners taking the lead in implementing the new Institute of Electrical and Electronics Engineers standard. (See “Implementing DER Ride Through,” PJM Operating Committee Briefs: March 6, 2018.)

Normal conditions wouldn’t cause an issue, Levitt said, but “our relay clearing logic doesn’t always work correctly” and could exceed the two-second threshold.

“Really, we would need to change our planning criteria under that kind of a scenario,” he said. “Ride-through is good; lack of ride-through is bad.”

Stakeholders noted several challenges that would have to be addressed, including the safety of utility workers working on lines, engineering and regulatory differences between the transmission and distribution systems, and the appropriateness of focusing on one technology type.

PJM will be hosting a technical workshop on the issue Oct. 1-2, Levitt said.


Staff announced that stakeholders impacted by planned revisions to how PJM calculates the output of generating units will have more than six years to prepare for the changes.

Changes planned for Manual 21 would revise and add detail to how PJM would test a generator’s output and determine its net capability each year. Among the changes, the capacity factors for wind and solar units would be calculated using the median factors instead of the average. Throughout the year, PJM’s Jerry Bell has been presenting analysis showing that the median more closely predicts actual performance than the average. (See “Skepticism of Gen Capability Changes Continues,” PJM Operating Committee Briefs: June 5, 2018.)

However, the changes would mean that affected wind and solar units would have their capacity injection rights (CIRs) reduced. The potential reductions have concerned stakeholders because they have to pay for the CIRs. Bell has said the CIRs could be reallocated to other projects, but they would be constrained to projects on the same transmission line.

In an attempt to placate the concerns, Bell announced that the changes won’t go into effect until the 2025 delivery year. Stakeholders will be alerted to CIR reductions by Aug. 1, 2024, and have to identify where they plan to move the CIRs by Jan. 1, 2025. They will then have until the end of that year to utilize them elsewhere. Any unused CIRs won’t technically be lost until June 1, 2026.

“When it comes to incorporating intermittent resources … this has always been a work in progress,” PJM’s Tom Falin said. “This is just a further refinement in that area as we have accumulated more data.”

The longer lead time seemed to have its intended effect.

“These changes are certainly much improved from the initial proposal,” Dayton Power and Light’s John Horstmann said.

TO Supplementals Discussion

PPL’s Frank “Chip” Richardson announced that TOs will be hosting an online conference on Aug. 28 to discuss additional details of their plan to implement FERC’s order from earlier this year requiring TOs to increase stakeholder engagement in the development of supplemental projects.

Supplemental projects are transmission construction initiated by TOs to address their own planning criteria and aren’t in response to any wider planning criteria. FERC determined that PJM TOs’ processes for developing those projects weren’t in compliance with Order 890, sending reverberations through several stakeholder initiatives that most recently culminated in the termination at July’s Markets and Reliability Committee meeting of a task force focused on end-of-life supplemental projects. (See PJM Stakeholders End Tx Replacement Task Force.)

ARR Analysis Finds Infeasible Facilities

PJM’s Xu Xu announced at last week’s Transmission Expansion Advisory Committee meeting that the annual analysis of stage 1A auction revenue rights found one violation within PJM’s territory and eight across flowgates to MISO. The analysis assesses the simultaneous feasibility of the ARRs’ paths for a 10-year period.

The internal violation is expected to be addressed through a project that should be in service in 2020. Proposals to address the others are being considered in interregional planning with MISO.

Cost of Dominion’s Haymarket Line Triples with Undergrounding

A decision by Virginia regulators to settle a controversy over a transmission line planned through a historical community through partial undergrounding will triple the cost of the line, staff confirmed.

A 6-mile 230-kV line planned for the area of Haymarket, Va., to feed new data centers received national attention after protesters raised concerns about Dominion Energy’s plan to site it through a historically African-American community inhabited by descendants of emancipated slaves. The Virginia State Corporation Commission stepped in to approve project revisions under a newly enacted underground transmission pilot program as part of the Grid Transformation and Security Act of 2018, which went into effect July 1.

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Dominion’s supplemental project around Haymarket, Va. | PJM

The revisions will underground roughly half the project, increasing costs from an initial estimate of between $45 million and $57 million to the new estimate of $174 million.

Because the proposal was a supplemental project initiated by Dominion, PJM confirmed that the entirety of the cost will be billed back to customers in Dominion’s zone. However, that might change after the D.C. Circuit Court of Appeals rejected earlier this month PJM’s cost allocation rules for supplemental projects that involve high-voltage lines. The rule, which had prohibited cost sharing for all supplementals, was remanded back to FERC for revision. (See DC Circuit Rejects PJM Tx Cost Allocation Rule.)

Rory D. Sweeney