“Corrosive.” “Seriously flawed.” On the “brink of market failure.”That’s what critics say about New England’s forward capacity market (FCM), whereby ISO New England conducts...
One RTO, Two Systems
By trying to placate regulated states—letting utilities “opt out” from its capacity market—PJM finds its RPM idea under fire.
as a pro-market company. Speaking in Washington, D.C., at a technical conference held at FERC June 7-8, Exelon Executive Vice President (and former FERC Chair) Elizabeth Moler went right for the jugular, playing the “Congress card” to make sure that she got the commission’s attention:
“We need to avoid gaming, to avoid the double-counting … to avoid the discriminatory regime issues which I don’t think this commission wants to chance on the Hill, frankly, and to provide a comparable regime between those who are opting out and those who are not.”
Eventually, New England’s LICAP had spurred such contention that FERC had no alternative but to invite the combatants to settle the matter among themselves, and in so doing to consider any reasonable model that might work to attract long-term region-wide investment in generation, including a wide range of models not fully considered in the evidence and testimony collected earlier in the case record. (See, “LICAP: A Mad Dash to the Finish,” Public Utilities Fortnightly, November 2005, p. 22.)
As a result, New England ended up with a FERC-approved Forward Capacity Market. The FCM features “descending clock” auctions to procure supply- or demand-side resources for future delivery three or more years out, when suppliers become eligible to receive payment. The FCM also allows LSEs to self-supply their own resources through owned assets or bilateral contracts.
The auction bidding in New England will open at a high price level chosen as representative of twice the cost of developing new generating resources (the cost of new entry, or CONE), with lower bids accepted until capacity needs are met, setting the clearing price. Initial bidding patterns and clearing prices dictate the CONE value and thus the range of bids for future auctions. (See, Order Accepting Proposed Settlement, Docket No. ER03-563, June 16, 2006, 115 FERC ¶61,340.)
Now, in similar fashion, FERC has declared that it cannot yet determine whether PJM’s RPM model as proposed is just and reasonable, and instead has elected to schedule settlement conferences to see whether the PJM region can agree on a compromise. Moler suggests, however, that settlement talks have hit a serious snag over the opt-out question:
“It’s complicated. It’s something we shouldn’t do on the fly. … It is festering in the ongoing settlement conferences and it’s worthy of an important body of work.”
As of mid-July, following months of proposals, comments, protests, and technical conferences (one in February; two early June), plus an initial FERC ruling and a PJM brief on the issues, the list of contested issues and the scope of the disagreement remains unchanged from late 2005, when this column last covered the topic.
Arguments still rage over: (1) capital cost estimates; (2) energy revenue offsets; and (3) boundaries for LDA market zones (Locational Delivery Areas). In particular, doubt persists on how to integrate merchant transmission RPM bids with PJM’s administrative backstop procedure known as the RTEP (Regional Transmission Expansion Plan). That’s because RPM would reward grid bids that clear the market with a locked-in, competitive, value-of-service revenue stream, while RTEP mandates grid upgrades if merchant