Liam Baker, vice president for regulatory affairs at US Power Generating, questions whether his company’s power plants and control systems in New York and Massachusetts must comply with the...
FERC mulls rival plans at the last minute, while on the West Coast, California gets into the game.
When FERC law judge Bobbie J. McCartney issued her initial decision back in June, weighing in at 280 pages, plus 2,435 footnotes, she already had accepted the basic structure of the ISO New England (ISO-NE) LICAP plan to create a location-specific market for installed electric generating capacity. That's because, in prior rulings, the Federal Energy Regulatory Commission (FERC) had told her to do so.
In its prior rulings, FERC had accepted the basic legitimacy of LICAP, with its twin concepts of: (A) a downward-sloping demand curve; and (B) some method to assure capacity availability in load pockets or constrained areas, such as a deliverability requirement or, as eventually proposed, a set of different obligations, auctions, and prices for each of five geographic market areas within New England.
As far as the commission was concerned, it wanted to limit further debate to the finer-grained details of LICAP. Such details would include, for example, the exact parameters of the sloping demand curve, the method(s) for defining plant availability, and measures for combating capacity withholding and minimizing market power.
By contrast, FERC, the ISO, and many other parties had seen no reason for further debate over the need for a location-specific capacity market. That's because power producers often tend to ignore transmission topography, and usually choose to build new plants in low-cost areas, putting a strain on the transmission grid. But why not, since transmission costs are socialized across the region? Thus, without a locational obligation to force utilities to gather capacity reserves in constrained areas, FERC and the ISO feared that plant-siting decisions would force high-cost solutions biased in favor of high-cost grid investment. Further, the ISO would find itself forced to award power producers with more cost guarantees through RMR (reliability must-run) contracts. In particular, the ISO had offered evidence to FERC that these costly RMR contracts had grown out of control, and threatened the regional market. ()
Nevertheless, by limiting debate, FERC had foreclosed a raft of competing ideas. In November 2004, for example, McCartney had struck from the record an alternative plan offered up by the Connecticut's consumer counsel, the state's public utility commission (PUC), and others, calling for a system of call options for energy (proposed as the "Reliability Options," or RO Market).
Under this plan, which sounds a little like the RUC idea (Residual Unit Commitment) under consideration in California as part of a pending new rate design (the MRTU) from the California ISO (Cal-ISO), capacity suppliers would sell options on energy contracts tied to specific, available generating units. The RO plan would set the strike price higher than typical average energy prices, but lower than expected peak price in the spot market. If the ISO calls the options, the supplier repays to the ISO the difference between the strike and spot prices. That payment is then redistributed ultimately to retail consumers. In this way, it is the power producers - and not the ratepayers - who bear