While the PJM Interconnection has made no major changes to its prototype capacity market since it proposed the idea a year ago in August, and though it has won a tacit OK from federal regulators...
Power System Planning: Who gets paid (and how much) for backing up the system?
measured by capacity value and paid through ICAP programs at the RTOs.
Now let’s return to Krapels and why merchant-grid projects are foundering.
“If an AC transmission project could reduce New York City’s locational capacity requirement by 10 percent,” he notes, “the annual savings could be as high as $25 million.”
But that’s not the way things work today. In the typical case, a merchant transmission line (an “economic” grid addition, not strictly needed for reliability) would not get paid for its capacity value under current RTO regimes for transmission planning and expansion.
In fact, the Krapels theory runs clearly afoul of a basic tenet of rate making at the Federal Energy Regulatory Commission. FERC insists that transmission projects qualify only for “and/or” pricing. In other words, transmission can earn a cost-based return on investment as a compensation for contribution to the public service, or it can earn a competitive profit on the opportunity cost of power, but not both.
Thus, under PJM’s RTEP plan for regional transmission expansion ( see Commission Watch, June 15, 2003, p. 13 ) or the New York ISO’s CRP process for comprehensive reliability planning (approved at FERC late last year) merchant transmission doesn’t receive a public-sector payment. Instead, any grid expansion need that cannot be solved by a purely market-based solution is thrown back into the realm of central planning. The planned solution (as devised by RTO committees, utility planners, or state regulators) then collects a guaranteed return under RTO tariffs or a commission-regulated rate.
That’s why, as Krapels sees it, today’s large-scale AC transmission projects are done only by traditional load-serving utilities and financed by traditional utility revenue streams that compensate utilities for creating system-wide benefits—the very thing that is denied to merchant grid developers.
Maybe Krapels has hit on something. In short, he implies that all system assets, whether generation, transmission, or other—and however financed and owned—should earn some revenues based on economics (the competitive market value of the energy product), and some revenues on contribution to reliability (capacity and system benefits).
FERC and the RTOs largely agree with Krapels on the generation side, where the ICAP plans have gained a grudging acceptance. Yet a big problem remains in converting theory to practice. The projected costs of paying these capacity credits to power producers has climbed to astronomical levels, in part because a key element is missing: consumer rights.
Unlike the traditional rate case or resource planning docket at the state PUC, the RTO ICAP process carries with it no explicit internal requirement that the final number must be “just and reasonable” (J&R), as is required of PUCs in setting retail electric rates. FERC can review the RTO findings, but cross-examination of witnesses and other features are missing from the RTO process, which looks very much like a virtual rate case but without due-process guarantees that are second-nature at the PUC.
In an interesting twist, some opponents of the New York ISO’s CRP proposal had complained about too little of a federal role in the regional planning process. They had faulted the ISO's plan