Proposed PJM RPM reforms spark detailed debate

ROCKVILLE, Md. - Jan. 23, 2015 - PRLog -- FERC was inundated with comments Tuesday on PJM's proposed capacity performance rule changes that saw a major redesign of the reliability pricing model (RPM). Many generators supported the rules in principal after last year's polar vortex exposed the RPM as flawed, but most load interests opposed them as an expensive overreaction. PJM VP of Market Operations Stu Bresler explained the need for so-called penalty to Utility Markets Today, the nation's leading journal chronicling ongoing efforts to open competitive wholesale and retail energy markets. Utility Markets Today publisher Modern Markets Intelligence, Inc. is sharing the story here, free of charge.

The Transition Coalition – made up of the Delaware PSC, PJM Industrial Customer Coalition, retailers and others – urged FERC to reject the RTO's proposal to start the capacity performance market in 2016/2017 and 2017/2018. The base auctions for those years have already been run, so the coalition argued the extra capacity performance payments would just be a wealth transfer to consumers without any real benefits.

The coalition estimated some 96 GWs of nuclear, coal, duel-fuel units on interstate pipelines and gas units with firm supplies would clear in the 2016/2017 year at a cost of up to $2.8 billion. But those generators are already there and would meet capacity performance's higher performance rules anyways.

The results would be similar for 2017/2018 with the Transition Coalition estimating up to 110 GWs would be available at a cost of $3.6 billion.

Since generators will not perform any better with the extra money those two years, the Transition Coalition said it "was left to wonder" whether the real purpose of the proposal was to deal with generator claims of revenue shortfalls.

"We respectfully submit that resources that have cleared in prior auctions must live with the capacity supply obligations to which they have agreed," the coalition said.

PJM has cheaper options to shore up reliability for those two years, it added, such as a special procurement for dual-fuel capability given that over 20,000 MWs of gas-fired units cannot burn oil now. For 2016/2017, some 13,082 MWs (including nuclear plants) did not clear but it could still be available, it added.

Exelon owns some of those plants that did not clear in the last auction, but it views the capacity performance rules as a necessary step given the weaknesses in the RPM that the polar vortex revealed. The RPM rules do not have a meaningful penalty for generators that go out of service, which in effect ends up favoring generators that do not do enough to maintain their units by helping them keep their bids low.

The proposal is needed to make sure generators are available whenever they are needed, and at the same time, it will appropriately compensate suppliers that already exhibit high performance, said Exelon.

The generator supports the transition-year mechanisms and lauded PJM for using a market approach. The extra money will mean real improvements from some units, Exelon said.

Generators will invest more to weatherize their units, a lack of which was the main cause of outages during the polar vortex, it added. The earlier payments could also lead to gas generators getting contracts for firmer fuel.

But the transition coalition was not the only one to raise the issue of the transition years, including American Municipal Power (AMP), Old Dominion Electric Co-op (ODEC) and Southern Maryland Electric Co-op (SMECO). Those firms believe generators already have an obligation to perform from the base auctions they cleared in for 2016/2017 and 2017/2018.

PJM wanted to get the ball rolling on its capacity performance rules before the normal three-year cycle of the RPM because it is important to ensure that the needed investments are made on time, Bresler told Utility Markets Today.

"We think it's unreasonable to think that we can just – for lack of a better term and I hope you'll pardon the pun – flip a switch and all of a sudden expect increased performance in 2018 without some sort of ramp-up to get to that point," he added. "We think the transition is important, so that we begin committing at least some level of resources in the 16/17-17/18 delivery years."

That way "we can ramp up to that 80% level in 18/19-19/20 and then 100% in 2021 and beyond," Bresler said.

The reason PJM is not making all resources meet the new requirements until 2021 is to keep the cost increases from going too high, he added.

Penalty questioned

The most serious flaw in PJM's proposal, Exelon said, is the penalty structure with fines based on net cost of new entry (CONE) divided by 30 hours – based on the assumption that there could be as many as 30 performance-assessment hours each year. But there never has been as they peaked at 23 in 2013/2014 that covered the polar vortex and some heat waves in the summer of 2013, it added.

Back-casting the RTO's penalties means no generators, even those who did not respond in any of the performance assessment hours during the polar vortex, would have been fined their entire capacity revenue. No generator over the past seven years in any zone ever would have paid such a high fine – let alone the 1.5 times net CONE maximum, Exelon said.

FERC should require PJM to stiffen the rules so generators cannot benefit from the gaming the system, claiming to make investments they never do, it added.

The PJM Power Providers (P3) is concerned about the 30-hours number, suggesting PJM should have to show more reasoning on why it picked that figure. The only reason P3 could imagine was that the number was a little higher than 23, the historic peak for performance hours.

Bresler takes on 'penalty'

PJM views the calculations of the "penalty" as another instance of its balancing act, said Bresler. The penalties work out to around $4,000/MWH while the maximum price in PJM is around $2,700/MWH so they are a significant deterrent.

Bresler does not like the term "penalty," beyond its use as a shorthand, because the rules are taking back money already paid to plants and then redistributing it to better-performing generators, he noted.

"The risk of not performing and being subject to a penalty of $4,000/MWH is, in our minds, sufficient to drive that necessary investment," Bresler said. "In other words, that is not a risk a developer can take on say, willy-nilly – 'I'm going to roll the dice and hopefully the conditions won't materialize.'"

While some might feel 30 hours is too much time to spread risk around, the current penalty system is based on 500 peak hours and then no charge is issued if a unit's outages come in below its forced outage rate, he added.

This story was originally published in Utility Markets Today on January 22, 2015 and has been slightly edited for this format. Visit http://www.utilitymarketstoday.com/public/Proposed-PJM-RP... to read the full story.