PJM stakeholders debated for nearly two hours Thursday over transmission owners’ spending on end-of-life (EOL) projects, suggesting there is little chance for compromise on an issue that has been disputed for years within the RTO.

Three EOL proposals were given first reads at Thursday’s Market and Reliability Committee meeting, setting up votes at the next MRC meeting on May 28. The proposals — which would require TOs to share how they make EOL determinations and potentially open at least some replacement projects to competition under the Regional Transmission Expansion Plan (RTEP) — are the result of deliberations over six special MRC meetings since December.

Three Proposals

A proposal by a group of PJM stakeholders, including American Municipal Power and Old Dominion Electric Cooperative, would require TOs to notify PJM and stakeholders of any facility nearing the end of its life at least six years before its retirement date so that the project could be included in five-year planning models and opened to competitive bidding. It would also modify the supplemental project definition to exclude EOL projects, which would be made a new category of regionally planned projects. It was endorsed by the PJM Industrial Customer Coalition, the Public Power Association of New Jersey, Consumer Advocates of the PJM States (CAPS) and the D.C. Office of the People’s Counsel.

LS Power supports the stakeholder package but would require six years’ notice for lower-voltage facilities and at least eight years’ notice for facilities of 230-kV and above.

PJM also offered a package requiring TOs to identify EOL projects five years in advance. Projects that “overlap” with RTEP violations would be included in a competitive window seeking regional solutions. Like the stakeholder and LS Power plans, PJM’s proposal would require each TO to have a formal program for EOL determinations. The RTO said it would prevent TOs that don’t already have a EOL determination process from using a “run to failure” asset management approach.

Under current rules, said Mark Ringhausen, vice president of engineering for ODEC, some TOs don’t identify EOL projects, choosing instead to replace “pieces and parts.”

“Some have told me that they never make EOL determinations,” Ringhausen said.

Divergence of Plans

But PJM disagreed with the stakeholder proposal on the RTO’s jurisdiction over EOL facilities, saying the Consolidated Transmission Owners Agreement (CTOA) transferred to PJM only the responsibility to prepare an RTEP “for the enhancement and expansion” of the transmission system to meet demands for firm transmission service. Section 5.2 of the CTOA says, “PJM shall not challenge any … sale, disposition, retirement, merger or other action.”

PJM also said its role is limited by two FERC rulings involving CAISO, which concluded that equipment replacements that result in only incidental increases in system capacity are asset management decisions under TOs’ exclusive control, not planning matters subject to FERC Order 890. (See ‘Asset Management’ not Subject to Order 890, FERC Rules.)

Dave Souder, PJM senior director of system planning, said the proposal honors the TOs’ responsibility over asset management decisions while allowing the RTO to determine when an RTEP project is more cost-effective than a TO’s proposed replacement. “We believe the PJM package takes a reasonable approach,” he said.

Several parties, including AMP and ODEC, insisted the FERC rulings do not preclude their proposal. They said the PJM proposal lacks transparency and would not require TOs to have EOL criteria or to share the list of EOL projects with stakeholders. Souder said PJM hasn’t decided whether the retirement list would be public.

Ed Tatum, AMP’s vice president for transmission, said PJM data from 2019 show $4.8 billion in TO supplemental projects, about 75% of which are for EOL assets that could benefit from longer-range planning. Robert Taylor of Exelon said he disagreed with the $4.8 billion statistic, saying the dollar amount appeared to combine supplemental and baseline projects, inflating the number by as much as $1.5 billion.

Tatum conceded that the retirement of a transmission asset should be determined by the TO that owns it. But he said PJM should take over planning once a retirement decision is made.

“Asset management includes operational maintenance activities, as well as the decision as to when an asset has reached the end of its life,” Tatum said. “But asset management ends at that point, and planning begins. … We need to have the assurance that this is being planned by an independent organization that is not bound by its stockholders to put together a construction project.”

CAPS Executive Director Greg Poulos said the advocates are frustrated that the TOs have “dug in” and been unwilling to negotiate a compromise. (See Stakeholders Seek TO ‘Engagement’ on End-of-Life Tx.)

“We’re supposed to be working together and not going straight to legal arguments,” Poulos said. “The stakeholder process does not work if we’re just going to go to FERC with things.”

The TOs filed a “statement of legal and contractual issues and reservation of rights” with the MRC on Wednesday. The statement said the stakeholder and LS Power proposals infringe on TOs’ contractual rights and are attempts to “rewrite” the CTOA and relitigate FERC rulings.

‘Scorched-earth’ Tactics

Alex Stern of Public Service Electric and Gas said TOs worked hard for a compromise problem statement and issue charge when EOL was brought up at Planning Committee meetings last year but that an agreement could not be reached. (See PJM Members Debate Dueling Tx Replacement Plans.)

Stern said he still had hope that a compromise could be reached during the special stakeholder process in the MRC over the last five months. But he said the packages that emerged are an attempt “to leverage the stakeholder process” to force PJM to make a filing at FERC that individual stakeholders should be making themselves.

“If stakeholders want to challenge the FERC-approved paradigm governing the authority of TOs to make determinations regarding the end of the useful life of their asset … there’s absolutely nothing stopping them from doing so,” Stern said.

John Horstmann of Dayton Power & Light agreed, calling the EOL stakeholder meetings a “scorched-earth process” to force PJM into a Federal Power Act Section 205 filing. Horstmann said the issue should have been brought to FERC as a Section 206 filing rather than going through the stakeholder process.

Stakeholders filing under Section 206 must first prove the RTO’s existing rules are unjust and unreasonable to win FERC approval of changes. A PJM filing under Section 205 would not need to make that showing, needing only to convince the commission that its new rules are just and reasonable.

The Members Committee has Section 205 filing authority over the Operating Agreement (OA); the PJM Board of Managers has Section 205 authority over the Reliability Assurance Agreement and the Open Access Transmission Tariff (excluding provisions under the exclusive control of the TOs).

The stakeholder and LS Power proposals would require changes to the OA.

PJM said its proposal would only require manual changes. LS Power’s Sharon Segner disagreed, saying FERC Order 1000 requires such planning process rules be included in the OA. She also said the PJM proposal fails to eliminate “redundancy between the supplemental and regional planning process” that would require an OA fix.

Stern said the focus on EOL by some of the stakeholders seems to be less on planning criteria and appropriate decision-making to ensure local and regional grid reliability, and more on the dollar amount being invested. He said transmission decisions are supposed to be made on ensuring the reliability of the grid and not the cost.

“PJM certainly has a role to play in planning, but it is not to decide how a transmission owner goes about addressing the impact of the end of useful life of an asset,” Stern said.

Tatum said he agreed with Stern’s assertion that planning shouldn’t be based solely on costs. But he said he would have more confidence that projects were being done in the most cost-effective way if PJM was conducting the planning.

Tatum said the TOs “unfairly discount” the importance of the PJM stakeholder process and the rights of the rest of the stakeholders. He said that since the inception of PJM as an RTO, the TOs demanded many of the provisions in the OA so they could have control over the new entity that was being developed.

“It’s not just [TOs that are] concerned about reliability and keeping the lights on,” Tatum said. “We all have a vested interest in that. But we see a majority of planning being driven outside of [the RTEP] process. Independent planning is essential in order to have successful markets, and we’re moving away from that.”

Susan Bruce, representing the PJM ICC, said industrial customers have seen their transmission bills increase “exponentially” over the past two years, largely because of EOL costs. Aligning the EOL asset management process with RTEP would ensure the transmission investments being made are cost effective and well planned, she said.

“Industrial customers want to see a reliable and robust grid, but they also want to make sure that their investment in transmission is optimized,” Bruce said.

Costs

Citing PJM statistics, Horstmann said that only 30% of the RTO’s transmission system is less than 40 years old, causing a glut of assets nearing their EOL that must be replaced. He said a high price tag is inevitable no matter who oversees the planning.

“You’re looking at a lot of money over the next period of years to basically maintain what we have, let alone improvements,” Horstmann said. “To me, that’s the elephant in the room here. This [dispute] just sort of dances around the edge of that problem.”

Tom Hyzinski of GT Power Group asked how much would be saved by identifying EOL projects six years in advance and making it subject to competitive bidding.

Ringhausen cited a Brattle Group report that showed 30% savings from competitive bidding. “You’re talking tens of billions of dollars,” he said. (See Study Findings Clash on Value of Competitive Tx.)

Next Steps

PJM’s Jim Gluck said the MRC will schedule one more special session (May 11 or May 15) to discuss the packages and seek opportunities for consensus before the three proposals are brought to sector-weighted votes May 28. The package with the most stakeholder support and meeting the two-thirds threshold will be brought back to special meetings to draft governing document language. The package receiving the greatest support will become the main motion for a vote of the MC.