By Christen Smith

BALTIMORE — Competitive transmission developers made a familiar argument at the Organization of PJM States Inc.’s annual meeting last week: Supplemental projects undermine regional planning efforts and PJM should do something about it.

But PJM staff aren’t willing to accept the risks that come with managing supplementals and insist that FERC precedent prohibits the RTO from intervening anyway. Incumbent transmission owners agree, insisting that decisions about when to replace aging infrastructure come with many specific caveats that a regional planning organization doesn’t necessarily understand.

It’s a viewpoint FERC endorsed in two CAISO orders in September 2018 (EL17-45 and ER18-370), Ken Seiler, PJM’s vice president of planning, said while participating on an OPSI panel with the D.C. Office of the People’s Counsel, LS Power, American Municipal Power and FirstEnergy.

In the former proceeding, the commission rejected a complaint from local and state regulators that said Pacific Gas and Electric violated Order 890 because the majority of its transmission planning occurs behind closed doors. FERC said asset management projects that only produce “incidental” increases in transmission capacity aren’t beholden to the transparency provisions of the order. (See ‘Asset Management’ not Subject to Order 890, FERC Rules.)

The commission reiterated this opinion in the latter proceeding that turned down the California Public Utilities Commission’s request for a show-cause order finding that Order 890 governs transmission owners’ planning for self-approved projects.

“A lot of this issue around end-of-life projects has been formed by us based on these orders,” Seiler said. “The orders specifically state that end-of-life criteria is not within the RTO’s purview and it’s not their expertise. The ISO shall do the planning, and the TO shall do replacement.”

LS Power and AMP interpreted FERC’s comments in the California dockets differently, however.

“In FERC’s California order, the commission said supplemental projects in PJM are a matter of PJM choice,” said Sharon Segner, vice president of LS Power. “Not a FERC mandate.”

“I don’t think you guys are reading that right,” Ed Tatum, AMP’s vice president of transmission, told PJM staff. “I think the commission took great pains to differentiate between what’s going on in California and what’s going on in PJM. We’ve really got to get it straight as to what we are talking about here, as far as PJM being able to set its own destiny.”

The commission only briefly addressed the PJM matter in the 2018 CAISO orders, calling its February 2018 ruling on PJM supplementals (EL16-71, ER17-179) “inapposite” to the issue at hand in California.

“The question of whether asset management projects and activities that do not increase the capacity of the grid must go through an Order No. 890-compliant transmission planning process was not at issue in the Feb. 15 PJM order,” FERC wrote in both CAISO orders. “Instead, the Feb. 15 PJM order examined the PJM transmission owners’ implementation of the process for planning supplemental projects, a process that is set forth in the PJM Operating Agreement and Tariff.”

No Authority, Expertise

PJM estimates members spent $6 billion on supplemental projects in 2018 — triple the amount invested in baseline upgrades that same year. Tatum said members have spent $29.9 billion on supplemental projects over the last 14 years, more than half of which TOs proposed after 2013. Baseline spending, meanwhile, will reach $30.1 billion by the end of the year, he said.

“Locally cost-allocated projects don’t go out for competition,” Segner said. “If you can do everything through local planning, then all of a sudden there’s not regional needs. There’s no coincidence that this world started aggressively in 2013 when FERC Order 1000 went into effect.”

“It’s very clear in our mind that TOs have the obligation to maintain their system, but as we go through and decide what is asset management … if you’re replacing it, that’s something called planning, and we think there is a bright line there,” Tatum said.

Under current rules, incumbent TOs submit supplemental projects for inclusion in PJM’s Regional Transmission Expansion Plan. The RTO studies the proposals for impacts on the grid’s reliability but doesn’t make determinations about whether the projects are necessary or the most cost-effective solution. Further, these projects often encompass asset replacement and upgrades that incumbent TOs say they are best prepared to handle. Seiler agreed, noting that PJM isn’t in the business of “condition assessment” and isn’t involved in the day-to-day management of TOs’ infrastructure.

“When we talk supplemental projects, we are talking aged infrastructure … that’s predominantly the type of projects we are focused on,” said Robert Mattiuz, vice president of transmission for FirstEnergy. “We do not want to be in a position where we run our transmission system to failure, so we are proactively addressing this issue.”

There’s no uniform set of standards for determining when an asset has reached the end of its life, Seiler later told RTO Insider, meaning that PJM must rely on local TOs to provide that knowledge. While he couldn’t verify AMP’s data about the growth in supplemental spending, he said PJM’s last wave of transmission buildout occurred more than three decades ago and suggested that the increase in spending over the last few years could be expected based on the age of the current system alone — though age isn’t the only factor TOs consider when replacing infrastructure, he clarified.

He also noted that PJM’s spending looks much less dramatic in comparison with other RTOs and ISOs when investments are load-weighted.

“I’d say PJM spending looks to be about average or even below-average in those terms,” he said.

Seiler’s comments reflect sentiments shared by Dean Oskvig, chair of the PJM Board of Managers’ Reliability Committee, on Oct. 4 that the managers’ review of supplemental projects concluded that the RTO’s role “can be expanded in some areas but also remains appropriately constrained in others.”

“PJM does not have the authority or expertise to assume responsibility for asset management decisions or to determine when a facility is at the end of its useful life or otherwise needs to be replaced,” he said. “Those decisions are the sole responsibility of the transmission owner. PJM has the authority, expertise and the obligation to develop the RTEP. In some circumstances, PJM may be in the best position to determine the more cost-effective regional solution to replace a retired facility. PJM welcomes input from stakeholders to determine under what circumstances PJM might assert that authority.”

Erik Heinle, of the D.C. OPC, said PJM’s ability to foster competition and innovation should naturally extend to supplemental project planning.

“We don’t want to just replace 50-year-old substations with the newer version,” he said. “One of the great successes of PJM is competition in the marketplace. … Why can’t we have that in the transmission space too? We need to make sure we are replacing these aging facilities … not with what we need now, but with what we need in the future.”