Utilities in the Midwest ISO want greater access to sell into PJM’s lucrative market. But that might require a virtual merger of the two RTOs — a move rejected seven years ago as too costly, and...
Second, the ISO is new at the game, and does not build on established case law, with generally accepted rules for cost normalization. Consider the New York case, for instance.
Various plant owners argue that the NYISO has skewed the estimated customer load profile and load shape by failing to normalize degree-day measurements across a long enough historic period. They fault the ISO for relying on nameplate capacity values identified for gas turbines in the manufacturer's marketing brochures, without collecting data on historic plant performance. They say the ISO has boosted estimates of turbine energy revenues beyond historic experience (the higher the revenues, the lower the capacity price) by tacking on a speculative "scarcity" adder. The ISO assumes that at some point during the year (say about 20 hours), energy prices will spike out of control (higher than levels warranted by market fundamentals), and plant owners will earn extra-marginal revenues.
With wide-scale divestiture of generating plants across the Northeast, we have shifted a huge slice of the traditional utility rate case over to the ISO/RTO. There it rests, alive and vigorous, but without the legacy of rate-making principles and due-process guarantees developed through long-standing practice at the state public utility commissions.
Must-Run Gen Costs
According to the New England ISO, charges assigned to market players to cover the cost of dispatching power plants in real-time to respond to deviations from day-ahead schedules averaged only $8.50/MWh in Connecticut and $5.50/MWh in Northeast Massachusetts and Boston (NEMA/Boston) in the summer of 2003. But last fall, in October 2004, real-time RMR charges in NEMA/Boston reached as high as $74/MWh, and exceeded $60 on three days in the same month.
That means that charges to adjust plant operation to cure second-level contingencies in the power delivery system sometimes ran as high as the cost of the underlying energy.
Noting these high costs, the ISO proposed in January to redesign its model to allocate real-time RMR costs to the entire universe of real-time load. That would alter the current practice of assigning real-time RMR costs only to those market bidders responsible for the deviations.
The ISO chose to revamp its allocation in light of anecdotal evidence that at least one virtual bidder had fled the day-ahead energy market to avoid getting hit with RMR costs. Such a hit would prove difficult to avoid, because, as one virtual bidder, DC Energy LLC, has pointed out, "nearly all cleared virtual trades result in real-time deviations." Moreover, the ISO did not want to discourage virtual bidding, as most experts consider that virtual bids are desirable, as they tend to increase market volume and liquidity. That encourages real-time price convergence with day-ahead results, while depressing price volatility and risk. Yet, to many others, the ISO's proposal would socialize RMR costs, and abandon the classic principle that cost-causers should pay.
But are the bidders really causing the costs? Is there another way out? Who has the real incentive and wherewithal to mitigate RMR costs?
During the initial debate in New England, some stakeholders had suggested treating RMR operations as a transmission service