You might have thought the Feds closed the book on any broad, region-wide sharing of sunk transmission costs—especially after FERC ruled last spring in Opinion No. 494 that PJM could stick with...
the so-called PER adjustment (Peak Energy Rent). The ISO determines the hypothetical amount of infra-marginal revenues that the unit should have received for energy sales. (Infra-marginal means in comparison to revenues earned by a hypothetical unit that operates on the margin - with its marginal cost equal to the energy market price). It then counts those hypothetical infra-marginal revenues as an offset against the LICAP price otherwise paid to the unit in question.
But what really sets the dogs to barking is the fact that each adjustment comes after the fact. The auction occurs in June, let's say, to set the price of LICAP for July, but when the auction market settles at the end of July, the LICAP seller is docked for energy revenues or the unavailable critical hours, as determined by events occurring during July. These adjustments add uncertainty to any anticipated revenue stream from LICAP payments, the detractors say, putting merchant plant financing at risk, and making it impossible to engage in forward contracting to hedge the LICAP value at risk.
Speaking for a coalition of capacity suppliers, consultant Robert Stoddard, a vice president at Charles River Associates, calls this regime "commercially intractable." As notes Harvey Reed, a consultant for Constellation Energy, "There is no single, market clearing price … There are as many prices as there are assets."
Utility financial consultant Steven Fetter, who cut his teeth at the Michigan Public Service Commission and later at Fitch, doubts that merchant gens could obtain financing in such an environment. Thomas Boland, managing director at the Seneca Financial Group, working in tandem with Charles River Associates, concludes that a merchant gen project likely would acquire only a "B" rating - meaning that its ability to pay its credit obligations likely would be impaired in the future.
Peter Fox-Penner, from the Brattle Group, concludes along with many other experts that the ISO's restrictive definitions of "availability" (especially the 30-minute startup requirement) will encourage developers to favor baseload or peaking plants at the expense of mid-merit or intermediate resources that cycle on and off. They fear that plant owners will respond by self-scheduling, to increase the chance that their units will achieve higher availability. But that only reduces the dispatch flexibility for the ISO.
Michael Hachey, power marketing director from TransCanada, warns that the failure of power plants to run during critical hours may not stem from gaming strategies, but from simple engineering factors, such as unit trips, failed starts, system disturbances, or ramping problems. And many experts from New York (and Long Island in particular) warn that New England's ICAP product, with its incompatible definitions of availability, will prove difficult to export to New York. They would prefer that New England retain the traditional definition used in PJM and New York (and in New England under the prior ICAP regime), based on the factor known as equivalent forced outage rate (EFORd).
How Much Reliability?
The proposal also raises questions about what size of reserve margin really prevails in the region, and whether it is adequate for reliability.
For example, the conventional