WILMINGTON, Del. — Mike Bryson, PJM’s vice president of operations, announced at last week’s Markets and Reliability Committee meeting that a scheduled vote on new pseudo-tie provisions would be postponed because of ongoing negotiations with MISO.

Members were expecting to be asked to endorse several items related to creating a pro forma pseudo-tie agreement, including the agreement, a pseudo-tie reimbursement agreement and associated Tariff and Operating Agreement revisions. However, Bryson, who substituted as chair of the meeting for CFO Suzanne Daugherty, said discussions continue with MISO to overcome differences between the two grid operators. (See Pseudo-Tie Feud Rises as Patton, NYISO Protest PJM Proposal.)

The proposal, developed through the Underperformance Risk Management Senior Task Force, would make deliverability requirements uniform for resources within and outside of PJM’s footprint and require feasibility studies for all pseudo-ties. Existing pseudo-ties would have five years to conform to the deliverability standards for internal resources.

Coal Replaced by Gas and Nuclear in 2020/21 BRA

PJM’s Jeff Bastian reviewed the Base Residual Auction results from May 23, noting that coal-fired generation cleared about 3,450 MW less than last year while gas and nuclear increased 3,700 MW and 1,500 MW, respectively.

Wind, solar and hydro all cleared fewer megawatts this year than last. (See related story, Capacity Prices down in Most of PJM in 1st Year of 100% CP.)

“Here we see the reduced offerings of resources that might have a hard time because of their intermittency meeting the CP,” Bastian said.

Roy Shanker, an industry consultant, asked about negative megawatts of capacity transfer rights in the MAAC locational deliverability area, which cleared roughly $9.50 higher than the rest of the RTO at $86.04. The negative CTR megawatts mean there’s less load paying for the capacity in that region than there is capacity receiving the LDA’s price, Bastian said.

“[It’s] a function of that area’s share of the peak load forecast, which is a disconnect completely from the way the load is represented at the clearing of the auction, so you can have that kind of an outcome,” he said.

Exelon’s Jason Barker asked PJM to develop a written explanation of how CTRs were calculated to describe how negative megawatts can occur.

Bastian noted that the Duke Energy Ohio/Kentucky LDA, which cleared about $54 higher than the rest of the RTO at $130, was modeled individually “due to potential for deactivations in that area,” which might reduce the amount of power potentially deliverable to the LDA below the amount PJM feels is required for reliability.

“We find it prudent to model them from a reliability perspective,” he said, noting that it’s been done before in the PPL, BGE and ComEd LDAs. Of the three, only the ComEd LDA has ever separated from the rest of the RTO, he said.

American Electric Power’s Dana Horton asked how 119 MW of solar could clear as Capacity Performance, given that the sun usually isn’t shining during the morning and evening daily demand peaks in winter, when resources are most likely to be called. This auction was the first year in which all resource offers must comply with CP rules that require year-round availability and impose stricter nonperformance penalties if units fail to be available.

“The sun does shine in the winter,” Bastian said. “There was a recognition by the resource owners that there’s more risk involved with offering solar, so that the annual quantity is significantly lower than what those resources were required to offer in the past.”

Greg Carmean, the executive director of the Organization of PJM States Inc., asked if all nuclear units cleared, but Bastian declined to address the specific unit results. Barker confirmed for attendees that not all nuclear plants cleared, apparently referencing the company’s Three Mile Island, which the company announced earlier had not cleared for the second year in a row.

New Black Start Units Will Have New Annual Revenue Requirements

Stakeholders endorsed by acclamation changes to the annual revenue requirements for black start units. PJM and its Independent Market Monitor had previously come to an agreement on the time periods for member submission of data and review by the Monitor. They also agreed on having the revenue go into a non-interest-bearing account for each unit until its costs have been approved, at which point the RTO will conduct a true-up. (See “PJM to Review Black Start Prior to New RFP,” PJM Market Implementation Committee Briefs.)

The move comes as PJM prepares for its second request for proposals on black start units, which is scheduled for 2018 for projects to be available in 2020.

PJM Defends Interest in Paying for Frequency Response

Stakeholders endorsed by acclamation a problem statement and issue charge on analyzing generator requirements for primary frequency response, but not before renewing debate over compensation.

FERC issued a Notice of Proposed Rulemaking last November that would require primary frequency response for all new units except for nuclear plants. The NOPR did not address compensation. At previous meetings, the Delaware Public Service Commission’s John Farber has challenged PJM’s plan to investigate compensation and requested language be added to the problem statement and issue charge that allowed it only “if appropriate or necessary.”

“The intent is to ensure that it’s not a given that compensation is required,” Farber said on Thursday, responding to an inquiry from Public Service Electric and Gas’ Gary Greiner about why the text was added.

PJM staff reiterated the RTO’s desire to study whether units should be paid for maintaining primary frequency response capabilities.

“Back at the [Operating Committee meeting] in the fall, PJM made a statement about how we didn’t think compensation was necessary,” Bryson said. “We’re clearly more open minded about that now, and the wording of the issue charge is intended to imply that.”

Stakeholders eventually agreed on discussing potential compensation mechanisms and recommending compensation changes “if appropriate or necessary.”

FTRs to Get a Longer Perspective

Members endorsed by acclamation a proposed problem statement and issue charge to consider changes to long-term financial transmission rights modeling.

PJM’s Regional Transmission Expansion Plan looks out up to three years into the future in ordering upgrades, but approved projects aren’t captured in FTR analyses because they are only able to capture information on a six-month horizon.

“It is concerning to PJM that today, the current process is not capturing these upgrades. Because what this means to us is that they’re not fully transparent to the market participants,” PJM’s Asanga Perera said.

In the documents, PJM guaranteed that FTR-capability allocations would be made “without violating firm transmission customer priority rights.”

Other FTR changes developed in response to the FERC order impacting the annual revenue rights and FTR process also were endorsed during the meeting, though not without some modifications.

PJM requested endorsement for Manual 6 revisions, which prompted Mike Cocco of Old Dominion Electric Cooperative to request that the phrase “no longer viable” describing transmission paths be clarified.

Monitor Joe Bowring questioned PJM’s planned changes for the FTR forfeiture process.

“I would ask that you give it more thought,” he said.

Steve Lieberman of American Municipal Power followed Bowring’s comment with a motion to defer a vote on that language until next month. (The Monitor is not a member and could not make the motion on its own behalf.)

Stakeholders worked on the proposal, and PJM’s Brian Chmielewski returned later in the meeting to seek endorsement of the revised package. Per Bowring’s request, the forfeiture changes were removed, he said, and “no longer active” was substituted for “no longer viable,” along with a definition of the phrase that matched the definition in the Tariff.

Stakeholder Approvals

Stakeholders endorsed by acclamation several manual revisions and other operational changes:

• Manual 3: Transmission Operations. Revisions developed in response to a periodic review.
• Manual 14D: Generator Operational Requirements. Revisions to develop requirements for solar generation facilities, in compliance with FERC Orders 828 (Requirements for Frequency and Voltage Ride Through Capability of Small Generating Facilities), issued July 21, 2016, and Order 764 (Integration of Variable Energy Resources), issued June 22, 2012. (See FERC Issues Ride-Through Requirement for Small Generators.)
• Manual 36: System Restoration. Revisions developed in response to a periodic review.
• Manual 13: Emergency Operations. Attachment E updated with 2017/18 load forecast and Mid-Atlantic load shed allocation information; Attachment F updated with 2017/2018 load shed capabilities and allocation percentages. The data in the attachments affects only transmission owners and has been validated by them.
• Governing-document revisions to allow for monthly correction of meters for pseudo-tied units and dynamic schedules. (See “Meter Correction Initiative OK’d,” PJM Market Implementation Committee Briefs.)
• An updated charter for the Incremental Auction Senior Task Force, which was created in response to a problem statement by Direct Energy that was approved by the MRC in November 2016. The revisions reflect an increase in scope resulting from a problem statement by NRG Energy on replacement capacity that was approved in March 2017. The revisions set a target for completing work and making recommendations to the MRC by January 2018. (See “Stakeholders Approve Variety of Actions,” PJM Markets and Reliability and Members Committees Briefs.)

Members Committee

The Members Committee held its monthly meeting last week at PJM’s Annual Meeting. (See PJM Annual Meeting Celebrates RTO’s First 90 Years.)

— Rory D. Sweeney