By Rory D. Sweeney

VALLEY FORGE, Pa. — And then there were nine.

Weeks after stakeholders introduced six proposals for redesigning PJM’s capacity construct, another three have materialized. Many of the nine are variations on a two-stage auction repricing structure, while others envision vastly different procedures.

All nine were presented and explained at a two-day meeting last week of the Capacity Construct/Public Policy Senior Task Force, which was created earlier this year to address concerns about state subsidies of generators undermining PJM markets. It has been moving to have an agreement endorsed and filed at FERC by the end of the year. PJM has held several two-day task force meetings to accommodate the depth of discussion stakeholders have demanded for the process. (See PJM Stakeholders See Capacity Auction Flaws, Offer Solutions.)

The proposals can be broadly categorized among those revamping the entire construct, developing repricing processes that accommodate subsidized units and extending a rule intended to eliminate the impact of subsidies.

The revamp proposals include full-scale redesigns from American Municipal Power and the Natural Resources Defense Council, and a limited revision to existing fixed resource requirement (FRR) rules called “Capacity Choice” proposed by John Horstmann of Dayton Power & Light.

The repricing proposals originated from a two-stage auction design by PJM. Many felt it unfairly discriminated against units on the margin in the capacity auction and proposed tweaks that would either reduce capacity awards (NRG Energy) or reduce the clearing price (LS Power). Another proposal would trigger repricing only if the clearing price rises to a level that incentivizes new generator construction (Exelon), while a fourth would calculate the clearing price by removing subsidized offers and scaling the remaining competitive offers to replace the shortfall (Old Dominion Electric Cooperative).

ODEC’s Mike Cocco said other repricing proposals utilize reference pricing schemes to replace the market offers from subsidized resources but failed to account for what would be corresponding change in the supply stack. ODEC’s proposal was designed to fully synthesize an auction as if subsidized units never existed and competitive units covered the entire demand.

“Once you open that door and decide you’re going to reprice with reconstituted offer prices, you have to open that door all the way,” Cocco said.

Monitoring Analytics, the Independent Market Monitor, proposed an extension of the existing minimum offer price rule that would require units to undergo analysis every year they receive subsidies without an exemption — requiring them to submit the variables and equation they used to calculate their offer. The Monitor would then review the submissions for competitiveness, much like it now does with fuel-cost policies and cost-based offers. (See PJM Monitor Rejects Fuel-Cost Policies for 11% of Units.)

“If states want control over their assets, they should reregulate — and that’s fine,” Monitor Joe Bowring said. “If we’re going to have markets, we should have markets.”

James Wilson of Wilson Energy Economics also provided comments on the redesign proposals, arguing that “markets are not as fragile as some suggest.” With enough lead time, markets have a “substantial ability to absorb incremental/decremental resources with minimal impact on prices,” said Wilson, who consults for the consumer advocates in New Jersey, Pennsylvania, Maryland, Delaware and D.C.

He predicted that the process would settle on “some sort of two-tiered pricing,” for which he has concerns. He also expressed reservations about expanding the MOPR.

The comments found some favor with AMP’s Ed Tatum, who has argued the best solution is to replace reliance on the annual capacity auction with long-term bilateral contracts between generators and load-serving entities.

“With enough notice, the true market would be able to absorb these things,” he said.

He also liked Horstmann’s “Capacity Choice” proposal, which would allow LSEs to determine how they want to fulfill their capacity obligations, either through long-term contracts under the existing fixed resource requirement (FRR) rules, annually through the existing Reliability Pricing Model or some combination of the two extremes.

All current and future subsidized units would be required to choose the FRR option, which would eliminate their potential influence on the RPM auctions. The entity enacting the subsidy would have to elect how it would be funded through its rate base.

“This is kind of a different approach than some of the ones you’ve seen before,” Horstmann said. “As opposed to being told how to manage your capacity obligation, basically what I’m putting on the table here is you get to choose how to manage your capacity obligation.”

He outlined several as-yet unanswered questions but noted that because the structure is largely already approved by FERC, it would require minimal Tariff changes. He said he analyzed the stakeholder proposals to address as many interests as possible but couldn’t include all of them — such as proposals to trigger repricing.

“Clearly it doesn’t accommodate the one that doesn’t think there’s a problem,” he said.

Going forward, PJM plans to distribute a poll to judge stakeholder interest in each of the proposals, including the status quo. The poll results, if emphatic, could determine the CCPPSTF’s ongoing direction and which proposals receive the most attention.

PJM is looking to schedule another meeting on Aug. 17, followed by meetings on Aug. 23, Sept. 11, Sept. 12 (if possible), Sept. 26, Oct. 16, Nov. 1, Nov. 21 and Dec. 11.