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...
not serve load or own supply resources. And if virtual players flee the spot market, prices could become more volatile.
Recently the ISO has raised ire by proposing to fix the problem by re-allocating the cost across the entire spectrum of real-time load, rather than to the smaller universe of those who cause the deviations. The case poses a fundamental question: Should regulators treat RMR as an energy service, cleared through the auction market, or as a reliability service, billed to those taking transmission service? ()
In the third case, investors complain that PJM has reneged on promises to certify the proposed Neptune undersea merchant transmission line. They claim a priority position in the new project queue, and say PJM is dragging its feet unfairly on a system impact study, while it tries to figure out what to do about a sudden rash of later-dated announcements of power plant retirements ().
The Neptune case poses an intriguing question: If a power-plant owner wants to retire a unit that qualifies for regional planning purposes as a network resource, should the RTO force that owner to jump through the same hoops as required for new projects seeking to obtain the same status? Why didn't FERC anticipate this problem in its landmark Order No. 2003?
The Gen Plant Rate Case
Perhaps the greatest irony of electric market design lies in the fact that, despite having "deregulated" the generation sector, the most successful RTOs and ISOs have found themselves mired deep in what can only be described as unsanctioned, virtual rate cases for power plants. Certainly, this outcome was hardly anticipated by the thinkers who dreamed up the SMD. A fine example can be seen in NYISO's now pending attempt to restructure the sloping demand curve for its capacity market, known as ICAP, where both power producers and load-serving utilities were up in arms over the ISO's proposal.
The case illustrates how the ISO, to determine the graphic parameters for its demand-cost curve, must examine a host of cost factors associated with new gas turbines. Such factors include: (1) plant-heat rate; (2) capacity factor (including such variables as seasonal, temperature-driven variations in plant performance capabilities); (3) offsets for revenues earned; (4) fuel cost volatility; and (5) the shape and profile of customer load, as affected by weather and other variables.
This task looks a lot like what the state PUCs traditionally do in a full-blown rate case (for a utility that still owns generation). However it differs in two key respects.
First, the ISO does not begin with historic data already compiled and submitted by the utility to document a given test year, based on a concrete set of assets actually owned by a utility. Rather, the ISO puts on its own case, backed by data collected most likely by a consulting firm of its choice. It then attempts to estimate a hypothetical best case for an ideal, speculative and mythical power plant, to set a benchmark compensation rate for capacity value (assuming there is such a thing), to offer a carrot for merchant plant investors.