Markets and Reliability Committee
Black Start Packages Rejected
PJM is back to the drawing board as two different solution packages aimed at addressing the disputed black start unit issue were rejected by stakeholders at last week’s Markets and Reliability Committee meeting.
The RTO’s option 1 package, which emerged as the main motion with 83% support at the Dec. 3 Operating Committee meeting, failed with a sector-weighted vote of 2.48 (49.6%) at the MRC. Dominion Energy’s package, which served as the alternate at the OC meeting with 82% support, failed with a sector-weighted vote of 2.47 (49.4%) at the MRC.
Stakeholders were asked to endorse the proposals addressing black start unit testing, involuntary termination, substitution rules, capital recovery factor (CRF) and minimum tank suction level (MTSL), and corresponding revisions to the tariff, Manual 12: Balancing Operations, Manual 14D: Generator Operational Requirements and Manual 15: Cost Development Guidelines.
The black start issue has been lingering for months since the problem statement was endorsed at the May OC meeting, leading to heated discussions among PJM members and generation owners fighting back against calls for retroactively applying CRF to existing black start units. (See Gen Owners Balk at Change to PJM Black Start Rates.)
The CRF issue emerged as the most contentious portion of the black start unit discussions, with stakeholders voting to amend the issue charge at the OC in December to align with language in the problem statement. (See Vote on PJM Black Start Compensation Deferred.)
Proposed issue charge language said, “Current black start units receiving the capital cost recovery rate (Schedule 6A) and units already awarded in recent black start [requests for proposals] will continue with the commitment period and capital recovery factor rates as documented in the current Open Access Transmission Tariff.”
The issue over the language emerged when stakeholders discovered the issue charge, which is officially voted on for endorsement as codified in Manual 34, did not include a footnote contained in the problem statement, leaving the application of CRF rates up to interpretation in the proposed black start packages.
The Independent Market Monitor’s package, which ultimately received only 7% support at the December OC meeting, called for updated CRF rates to apply to new and existing black start units. Updated commitment periods would have also applied to new and existing black start units.
Monitor Joe Bowring said the CRF table was originally created in 2007 as part of the Reliability Pricing Model capacity market design and includes assumptions that are no longer correct. Bowring said the CRF values are significantly higher than they should be under the lower corporate tax rate from changes in the 2017 tax law, leading to overcompensation for units.
The addition of the updated black start issue charge language at the December OC led to last-minute modifications to the Monitor’s package and PJM’s primary package, both of which failed to be endorsed.
The next steps for the black start issue are yet to be determined and will be discussed at the Feb. 11 OC meeting.
Adrien Ford of Old Dominion Electric Cooperative said the packages failed to correct the error of the CRF table not being updated in the tariff with the 2017 tax law.
Susan Bruce of the PJM Industrial Customer Coalition said she appreciated that black start is a “pretty muddy issue” and that there are aspects of the issue that “cut both ways.” Bruce said her biggest concerns with the black start packages are the changes to the capital recovery and commitment periods.
“It’s a complex issue for many of the reasons highlighted, but what’s before us doesn’t solve the issue,” she said.
Alternative Black Start Package
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), reviewed a proposal as a first read on behalf of the Delaware Division of the Public Advocate as a compromise alternative to the PJM and Dominion packages that failed.
Poulos said the changes to the black start issue charge at the December OC meeting stifled the voices of minority interests related to the CRF issue.
“It completely materially changed the black start discussion and eliminated certain aspects of that discussion,” Poulos said.
The advocate package uses much of the same language from the failed proposals, keeping intact aspects of testing, unit substitution and termination and the MTSL. The changes include the addition of the Monitor’s language regarding CRF, applying rates to both new and existing black start units.
It also uses the language from the primary PJM package, with a five-, 10-, 15- and 20-year capital recovery period based on unit age at the time of it entering black start service.
“The advocates at this point could not support the two current proposals that are up, and that’s why I’ve tried to find an alternative proposal,” Poulos said.
Bowring said he continues to believe that exempting existing resources with the change in the black start issue charge was “inappropriate” and that the CRF issue should ultimately be decided at FERC.
“We don’t think there are any rights to windfalls built in to the CRF process,” Bowring said. “That’s exactly what’s been occurring for existing units back to the time of the tax law change.”
Marji Philips, LS Power vice president of wholesale market policy, said she objected to the term “windfall” being used regarding CRF. Philips said PJM conducted a competitive procurement process with the black start service for units currently in operation, and prevailing interest rates were considered and accepted by all interested parties.
Philips said she does not have a problem with updated CRF rates applying to new black start units, but she said applying rates to existing units is “retroactive ratemaking.” She said the advocate proposal is not fair and doesn’t recognize long-term contract law.
“These projects were built based on an assumption, and it was competitively chosen,” Philips said.
Alex Stern, director of RTO strategy for PSEG Services, made a motion for the advocate package to be sent back to the OC for further discussion, saying it was “ripe for a motion to remand.” Stern said he appreciated Poulos bringing forward a new proposal that doesn’t fall within the issue charge, but he believed that the OC “needs to go back to the drawing board” to discuss the issue.
“I think everybody now has to go back and roll up their sleeves and try to work together to figure out what’s in the best interest of all,” Stern said.
Ford said she didn’t see why the MRC would direct the advocate proposal back to the OC for discussion, as stakeholders on the committee “very clearly rejected” the idea of applying CRF to existing black start units.
“I think it’s appropriately before the MRC, and that’s where it should stay,” Ford said.
Stern’s motion to remand failed with a sector-weighted vote of 2.2 (44%).
Mike Bryson of PJM said that if there was a procedure to get the advocate package back to the OC to discuss, it would be the best outcome to flesh out ideas or possible compromises. Bryson said PJM is still concerned about addressing CRF on existing black start units and that the RTO has a “significant commitment to these units,” and changing existing structures would be “problematic.”
“We’re going to have to fix this CRF issue one way or another,” Bryson said.
MOPR Revisions Endorsed
Stakeholders unanimously endorsed revisions to Manual 18: PJM Capacity Market that conform to the FERC-ordered rule changes in the minimum offer price rule (MOPR) and forward-looking net energy and ancillary services (E&AS) offset calculation. The revisions were also unanimously endorsed earlier this month at the Market Implementation Committee meeting Jan. 12. (See “MOPR Changes Endorsed,” PJM MIC Briefs: Jan. 12, 2021.)
Jeff Bastian, PJM senior consultant in market operations, reviewed the updates to Manual 18, including recent changes to the redline language resulting from stakeholder discussions.
The first change is a previously unmapped region of the Ohio Valley Electric Corp. (OVEC) zone, which is now mapped to the Columbia-Appalachia TCO fuel pricing point for the purpose of establishing the net E&AS offset for the zone. The OVEC zone was also mapped to the AEP-Dayton Hub for determining the forward hourly LMP.
The second change includes new language in section 5.4.5.5(A) that clarifies that a seller’s financial accounting statements should serve as the primary form of evidence for use of an asset life more than 20 years.
Bastian highlighted two additional conforming changes made after the MIC endorsement. Language changes include the use of an average equivalent availability factor for PJM nuclear resources to account for refueling outages in the calculation of the forward net E&AS offset for existing nuclear units.
An additional change eliminated a requirement that a resource submit a sell offer at the resource-specific value under certain circumstances. Bastian said the update was related to the recent FERC filing regarding tariff revisions that account for when the default offer price floor exceeds the market seller offer cap (MSOC) under PJM’s MOPR (EL16-49-004, et al.). (See FERC Partially Accepts PJM MOPR Offer Floor Filing.)
Chen Lu, PJM senior counsel, provided a summary of the FERC order that largely accepted the RTO’s compliance filing, submitted Nov. 13, with the exception of one provision regarding the MSOC.
PJM included the Attachment DD language directed by the commission but also proposed an additional sentence to the tariff, which stated, “In the event the resource-specific MOPR floor offer price is greater than the applicable market seller offer cap, the capacity market seller of such capacity resource may only submit an offer for such resource equal to the resource-specific MOPR floor offer price into the relevant RPM auction.”
The commission rejected the additional sentence on the grounds that it exceeded its October compliance order, directing PJM to submit a new compliance filing within 15 days removing the sentence from the tariff. Lu said PJM will file an additional compliance filing by Feb. 3 to remove the rejected sentence from Attachment DD in accordance with FERC order.
PJM maintains that the additional compliance filing allows them to run the long-delayed capacity auctions for the 2022/2023 delivery year, Lu said, with the auctions set to commence on May 19.
“We believe we have the greenlight to run the next auction,” Lu said. “And we are prepared, ready and intend to commence the next auction.”
Stability Limits Endorsed
Members endorsed a proposed capacity constraint solution package and corresponding Operating Agreement and tariff revisions regarding stability limits capacity constraints. The package was endorsed with a sector-weighted vote of 4.05 (81%).
The proposal addresses the allocation of limits to multiple units by stating that the limit will apply to the sum of the output of the affected units plus ancillary service megawatts. (See “Stability Limits Review,” PJM MIC Briefs: Dec. 2, 2020.)
The problem statement and issue charge were initially brought forward for endorsement at the August 2019 MIC meeting. (See “Modeling Units with Stability Limitations,” PJM MIC Briefs: Aug. 7, 2019.)
Lisa Morelli, director of market design for PJM, said the packages were developed to create consistent treatment of generator stability limitations.
Current rules require the RTO to implement a thermal surrogate to reflect the stability constraint in the day-ahead and real-time markets and to bind the constraint, affecting the unit’s dispatch.
The capacity constraint proposal was put forward by PJM and the Monitor and endorsed by the MIC with 64% support. It addresses the allocation of limits to multiple units by stating that the limit will apply to the sum of the output of the affected units plus ancillary service megawatts.
Joe Ciabattoni, PJM manager of interregional market operations, said the units would be dispatched in economic merit order up to the stated stability limitation. If a unit chooses not to remedy a stability limitation identified during the planning process, Ciabattoni said, its operating restrictions — as documented in its interconnection service agreement — would be invoked prior to those for other units.
The package also included a measure for transparency, with PJM posting data on the frequency, location and number of affected units while maintaining confidentiality rules.
Lost opportunity cost (LOC) credits would not be paid for any reduction required to honor the stability limit. Similarly, LOC is not paid for economic megawatts of a resource that cannot produce because of a ramp limitation.
Paul Sotkiewicz of E-Cubed Policy Associates reviewed the alternate opportunity cost solution package that was ultimately not voted on. The proposal, presented by J-POWER, was fundamentally the same as the PJM-IMM package except for providing compensation for LOCs.
Sotkiewicz said if a generator is requested to take an outage when it can still run, the unit is in essence being asked to “not reveal our true capabilities” to the market of what could actually be generated. He said it creates a “slippery slope” going forward to misrepresent a unit’s true capabilities.
“I think the mechanical changes to the market are excellent, and I applaud PJM and the Market Monitor for that,” Sotkiewicz said. “But we do believe we should be paid lost opportunity costs.”
Catherine Tyler of Monitoring Analytics said LOC was not included in the PJM-IMM proposal because generators could endanger a unit’s stability and risk damage by pursuing opportunities for LOCs. Tyler said the costs to repair potential damages to a unit would outweigh the LOC.
“There’s not a benefit of receiving the higher LMP if you’re going to break your unit to do it,” Tyler said.
A final vote on the package will be held at the Feb. 24 Members Committee meeting. Ciabationi said conforming manual revisions will be brought through the OC and MIC for endorsement following FERC approval of the proposal.
Manual 14C Revisions Endorsed
Stakeholders endorsed revisions to Manual 14C: Generation and Transmission Interconnection Facility Construction as part of the biennial cover-to-cover review after voting to delay the revisions last month over concerns regarding some of the proposed language. (See “Manual 14C Delayed,” PJM MRC/MC Briefs: Dec. 17, 2020.) The revisions were endorsed by acclamation vote with one objection and one abstention.
Mark Sims, PJM’s manager of infrastructure coordination, said the committee proposed minor changes to Manual 14C, including an update of the latest Tariff provisions clarifying the filing process for title transfers and associated title documentation in Section 5. New sections on cost-tracking for baseline projects and another for supplemental cost-tracking were also proposed.
Poulos made the request to delay the endorsement by one month to work with PJM on some language suggestions after expressing concerns about some of the language. Poulos specifically referenced sections 6.1.2 and 6.2.1 dealing with tracking of supplemental projects.
Sims said PJM coordinated with Poulos to address the language concerns, and Poulos presented the friendly amendments to make the language consistent with Manual 14B.
In Manual 14B, the transmission owners must update PJM on the status of state regulatory approval in the quarterly updates. But in Manual 14C, Poulos said the burden is on PJM to “request” the status of state regulatory approvals.
Poulos said PJM currently does not wait for state approval of supplemental projects, and with the manual change, it was less likely that the RTO will even be aware of the state procedural process.
The friendly amendment said the Manual 14C sections will be consistent with language in Manual 14B and will include “any relevant regulatory siting authority approval necessary for the project and the status of such approval.”
“My goal is to make the language consistent between the two manuals and ensure that PJM is updated on what the approval process is for each of these projects,” Poulos said.
Robert Taylor of Exelon asked if PJM was comfortable with the friendly amendment.
Sims said the language was consistent and added value in clarification. Sims said PJM was also intent on not making the procedures for requesting documentation overly burdensome for stakeholders or PJM staff and that the “relevant” documents would be enough for PJM engineers to adequately do their work.
Real-time Values Market Rules
Members endorsed a solution package addressing real-time values (RTV) market rules and corresponding revisions to Manual 11: Energy & Ancillary Services Market Operations and the tariff and Operating Agreement. The package was endorsed with a sector-weighted vote of 4.9 (98%).
Laura Walter, senior lead economist for PJM, said the original intent of RTVs was to provide a way for generation operators to communicate current operating capability to PJM if their resources could not meet their unit-specific parameter limits or exceptions. Generators opting to use RTVs forfeit operating reserve credits and make-whole payments.
The PJM package requires that market participants repeatedly failing to reflect actual operating conditions in their submitted operating parameters could be referred to FERC for enforcement. A market participant would be required to enter a forced outage ticket into PJM’s Generator Availability Data System (eGADS) for the period of increased notification, start-up time and/or minimum downtime.
For the timeline of an RTV submittal, Walter said, the package would require that the requested period not exceed one market day. She said that when an RTV is requested, it would be available for that one day, then the entire schedule would revert to the previous day’s values.
The package also calls for adding RTVs to the tariff. Currently, RTVs are mentioned only in the manual, Walter said.
Siva Josyula of Monitoring Analytics reiterated the Monitor’s concern that the changes proposed in the PJM package undermine the parameter-limited scheduling (PLS) rules used in RTVs. The PLS rules are part of the capacity performance rules requiring units to operate to defined parameters, he said.
The package will be voted on at the February MC meeting.
PRD Credits Disposition
Stakeholders unanimously endorsed through an acclamation vote the proposed solution package addressing the disposition of price-responsive demand (PRD) credits.
PJM’s Pete Langbein went over the corresponding revisions to Manual 11: Energy & Ancillary Services Market Operations, Manual 18: PJM Capacity Market, OA tariff and Reliability Assurance Agreement. Langbein said no changes were made to the package after it was presented for a first read at the December MRC meeting. (See “PRD Credits Disposition,” PJM MRC/MC Briefs: Dec. 17, 2020.)
PJM’s settlement rules call for revenues associated with PRD to be credited to the load-serving entity (LSE) for an area and do not address the roles of electric distribution companies (EDCs) or curtailment service providers (CSPs), meaning some LSEs are paid for PRD service supplied by EDCs and CSPs.
Langbein said the LSE was removed from emergency/pre-emergency demand response process several years ago.
The solution package calls for the PRD provider to receive the PRD bill credit and that any member that is a PRD provider is treated the same with no need to differentiate between a PRD provider and an LSE.
The package now heads to the MC for a vote in February.
Members Committee
Manual 34 Changes
Proposed revisions to Manual 34: PJM Stakeholder Process were unanimously endorsed at last week’s Members Committee meeting.
The change provides clarifying language to affirm that the preference over the status quo 50% requirement is binding. (See “Manual 34 Revisions,” PJM MRC/MC Briefs: Nov. 19, 2020.) Gary Greiner, director of market policy for PSEG, sponsored the revisions that came out of discussions at the Stakeholder Process Forum.
Members proposed incorporating an additional threshold for moving a proposal to a senior standing committee. The language change says a proposal must pass a simple majority voting threshold and be preferred over the status quo by more than a simple majority. Current rules that do not require a majority prefer the alternative over the status quo.
“In the way of enhancements, we determined that we were going to ask the preference question for all proposals before we knew the level of support that they garner,” Greiner said.