VALLEY FORGE, Pa. — The PJM Operating Committee last week unanimously approved revisions to Manual 14D to tighten the notification rules for transferring the ownership of generation units.

Generation owners and PJM staff hammered out the language over the past month after owners expressed concerns over an earlier proposal. (See “Gen Transfer Vote Postponed,” PJM Operating Committee Briefs: April 3, 2018.)

PJM’s Rebecca Stadelmeyer presented the revised proposal, which sets deadlines on how long prior to the sale the buyer and seller must provide the RTO with certain information. Sellers must now simultaneously provide PJM with the application they submit to FERC to change ownership, which starts a clock on several other submissions.

At least five days before closing on the sale, sellers must provide PJM with information including the name and W9 form of the buyer, and a list of its current officers.

GT Power Group’s Dave Pratzon, who organized generation owners’ engagement on the issue, said the result addresses owners’ concerns about commercial realities and the need for flexibility that earlier drafts did not.

Synch Reserve Changes

PJM’s Eric Endress presented proposed Manual 11 revisions that would change how the RTO estimates the synchronized reserve maximums for Tier 1 units. The revisions would set a unit’s maximum at the lesser of the economic maximum or synchronized reserve maximum, though an owner could submit a request for a synchronized reserve maximum less than the economic maximum if a physical limitation exists. The economic maximum can be updated intra-hour as necessary.

PJM is targeting a July 1 implementation of the changes.

Carl Johnson, who represents the PJM Public Power Coalition, was one of several stakeholders who voiced concerns about “moving the earth under our feet” while several other larger issues related to the topic are being debated in other stakeholder forums — notably the Energy Price Formation Senior Task Force and PJM’s initiative to increase grid resilience.

He acknowledged that the proposal “makes sense” but cautioned that “we may be changing this entirely.”

Pratzon asked staff to analyze how the different initiatives overlap because they could “benefit from better coordination.”

PJM’s Chris Pilong acknowledged the concern but urged stakeholders to “make sure we don’t just sit on our hands” and not implement a solution to the issue. The RTO has been analyzing stakeholder concerns about significantly overestimated Tier 1 reserves. (See “Changing Tier 1 Reserve Estimates,” PJM Operating Committee Briefs: March 6, 2018.)

“In the interim, I think we still need to make sure that the reserves are accurate,” Pilong said.

PJM’s Eric Hsia confirmed that a “very limited amount of resources have a spin max greater than [its economic] max.” The RTO agreed to Johnson’s request to provide comparisons of units’ spin max versus economic max for all operating states, not just during synchronized reserve events.

Later in the meeting, PJM’s Becky Davis explained that the RTO uses the synch reserve ramp rates that units specify if they’re greater than specified energy ramp rates. However, generators aren’t required to provide either of those. If neither is specified, PJM uses the default ramp rate.

She noted an analysis of events over the past two years that showed 10% of units with synch reserve ramp rates greater than their energy ramp rates met or exceeded PJM’s Tier 1 estimate. The RTO contacted the other units to either remove the synch reserve ramp rates, match them with the energy ramp rates or justify why it should remain higher by submitting actual unit performance following a synch reserve event.

In response to a question from Pratzon, Davis said that most generators’ reserve rates match their energy rates.

Black Start Fuel Assurance

PJM’s David Schweizer presented proposed fuel-assurance requirements that will be required of black start units starting next year. The requirements would go into effect at the end of the year following the finalization of PJM’s current black start request for proposals and be in place for any incremental solicitations and the next RTO-wide RFP in 2023, he said.

Units would have to show one of the following:

• Dual-fuel capability with onsite fuel storage for a 16-hour run-time at its rated black start output;
• Onsite fuel storage for a 16-hour run-time at its rated black-start output for units that can store fuel, such as pumped hydro, batteries or oil;
• Connection to multiple interstate gas pipelines with primary firm transportation contracts on at least two lines. This wouldn’t include local distribution company lines, which don’t offer firm service; and/or
• That run-of-river hydro units can run at their black start rating for 16 hours.

Existing units would be entitled to a five-year transition plan starting in delivery year 2020/21. Units would be allowed to include the capital costs in the incremental black start capital cost component in their costs and would convert to the base formula rate after capital costs have been recovered.

Schweizer suggested that addressing previous concerns about the minimum tank suction level (MTSL) might be “more relevant” now. David Mabry, who represents the PJM Industrial Customer Coalition, agreed and requested a concrete proposal from PJM, but Calpine’s David “Scarp” Scarpignato argued against rehashing the issue. Prompted by the Independent Market Monitor, stakeholders spent several months earlier this year debating revisions to the MTSL calculation but eventually decided there were other issues of potentially greater significance to address. (See “MTSL ‘Not Going Away,’” PJM MRC/MC Briefs: Oct. 2, 2017.)

Pratzon asked if existing black start units that begin but don’t complete upgrades required by the new rules would have to voluntarily cancel the black start contract or if PJM would cancel it. He said his concern is if the difference will affect whether such units are able to recover their costs fully. Staff weren’t prepared to respond definitively; Pratzon asked that it be determined “sooner rather than later” so generators can make decisions about participating in the current RFP. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: April 3, 2018.)

Base Becomes CP

All capacity resources will be subject to Capacity Performance requirements at the beginning of the new delivery year on June 1. PJM’s Susan Kenney provided a preview on what changes regarding unit-specific parameters those resources will experience.

She noted that parameters will be updatable from May 25 through 10:30 a.m. on May 31 and that updates will transfer through to following days. Any parameters that don’t comply with new limits will be rejected by the system, she said.

Kenney also reviewed real-time value reporting procedures.

Fuel Security

PJM’s Dave Souder addressed the RTO’s initiative to analyze fuel security, which was announced April 30. (See PJM Seeks to Have Market Value Fuel Security.)

Souder said staff will analyze the grid under “stressed conditions” that include an extended cold spell, nuclear and coal retirements and the lack of availability of dual-fuel or onsite storage.

The plan has created concern on all sides of the industry.

Joe DeLosa, who represents the Delaware Public Service Commission, voiced “major concerns about the amount of time that’s going to be able to be devoted to this over the next year.”

“End-use customers especially have communicated to PJM their lack of a desire for criteria in the resilience field. I think that’s been pretty unanimous from customers, as well as substantial discussions about competing priorities in the stakeholder process,” he said.

“My mind’s racing,” FirstEnergy’s Jim Benchek said. “You’ve already got CETO/CETL [capacity emergency transfer objective/capacity emergency transfer limit] constraints. … It sounds like you’re planning to put an additional layer of constraints on the system.”

Later, PJM’s Brian Fitzpatrick explained the progress in staff’s analysis of gas-pipeline risks. The analysis is part of PJM’s ongoing effort to prepare for potential interruptions on the pipeline system. (See “Additional Reserves Needed?” PJM MRC/MC Briefs: March 22, 2018.)

Staff have held five meetings with pipelines within its footprint and have three more planned. While PJM had initially identified 63 contingencies that mostly involved potential compressor failures, pipeline companies said those were lower risk and recommended focusing on the ends of lines and laterals connected to main trunk lines.

“Right now, we have about seven [contingencies], so really, really decreased that list quite a bit,” Fitzpatrick said. “And that number will change because we’re still meeting with pipelines.”

Additional analysis will occur over the next six months.

PJM’s Augustine Caven said conditions during January’s “bomb cyclone” cold snap hit triggers to evaluate the need for any contingencies but that none were necessary. Caven also explained PJM’s plan to add detail to its operational parameters for gas units. The expanded parameters will help support automating PJM’s response to contingencies.

PJM is also planning to expand its ability to track units’ limitations on run time, including fuel inventory, emissions limitations, and supplies of demineralized and cooling water. PJM’s Natalie Tacka explained plans to add ways for units to report “hours remaining” for specified time windows and for RTO dispatchers to keep track of those potential restrictions. PJM is seeking generation owner input and asks those interested to let it know by May 11.

Automating Generator Notification

PJM’s Aaron Baizman explained a plan to automate the dispatch of resources onto the system. The current procedure involves calling the generator directly, but PJM plans to have that notification and verification process become electronic.

The transition will start with combustion turbines through a pilot planned to begin at the end of the year and ramp up in 2019. PJM plans to expand it to all units but has not yet set a target date.

Baizman said the plan is similar to programs at ISO-NE, CAISO, SPP and MISO.

CIR Questions

PJM wants to switch from using average to median capacity factors to calculate units’ unforced capacity. The RTO says the median is closer to units’ actual performance but acknowledges it will reduce units’ capacity injection rights (CIRs). (See “CIR Revisions,” PJM Operating Committee Briefs: April 3, 2018.)

The proposal has created concern among some stakeholders, and PJM’s plan to address the unease has only created additional concerns. PJM’s Jerry Bell outlined the current plan, which gives generation owners until Aug. 31, 2024, to notify the RTO that they plan to convert the CIRs that will be lost into incremental deliverability rights (IDRs) that they will use in an interconnection queue project within one year of the notice to PJM. The CIRs will convert to IDRs on Sept. 1, 2024. The plan is like the procedures already in place for reusing CIRs from retiring generators.

Initially, after stakeholders questioned the value of CIRs without a project, Bell suggested they could be sold at the point of interconnection, used to expand the existing project or allocated to a new project in the same area. However, he eventually conceded that “I don’t know what you’d do with them.”

Stakeholders also questioned why PJM would want to force generators to purchase less transmission capacity than they otherwise would. Bell said he’d have to come back later with an answer.

30-Minute Reserves Target Set

PJM has determined that it should secure roughly 3,800 MW of 30-minute reserves in real time, PJM’s Vince Stefanowicz said. The determination comes after analyzing how other RTOs/ISOs handle such longer-term reserves. Stefanowicz noted that ISO-NE, NYISO and the Tennessee Valley Authority all have a similar requirement.

Staff came to the number by considering several factors and making some assumptions. First, they assumed the largest unit would be about 1,500 MW and determined that the appropriate reserve should equal 200% of that. They added the load, wind and solar forecast errors for each season and came up with a value for each season. They averaged to 3,784 MW.

The number would be recalculated annually, and Stefanowicz said it’s often already online much of the time. PJM’s emergency management system calculates 30-minute reserves and found that, over the past four years, the system has been below 5,000 MW of reserves less than 10 hours total.

“We don’t expect this to come into play a lot,” he said. “In reality, the number we’re proposing is not overly aggressive. It’s realistic to what we’ve seen. … We have those reserves on the system normally, through our normal scheduling processes today.”

He noted that resources with a start time of less than 30 minutes could qualify.

PJM’s synchronized reserve requirement is 100% of the largest energy contingency and the primary reserve target is 150%, but the 30-minute “operating” reserve is currently undefined. Stefanowicz said the proposed calculation produces a number like the 30-minute reserve that PJM procures in day-ahead and is comparable to the calculations other RTOs/ISOs make.

“Each area has a different set of numbers, but a very similar methodology for securing their reserves,” he said.

Mabry asked why the target requirement wasn’t dynamic based on the largest unit online at the time. Stefanowicz said they would consider that.

— Rory D. Sweeney