When FERC decided in February, in Order 890, to lift the price cap for electric-transmission customers seeking to resell their grid capacity rights in the secondary market, it cautioned against...
and assigning the costs to transmission owners, to create an incentive to upgrade the grid. In fact, according to the ISO, the majority of real-time RMR charges result ultimately from a violation of reliability contingencies for transmission-and not for generation.
Some municipal utilities have opposed the new ISO method, saying it hurts utilities that self-schedule their own resources, because self-scheduling tends to depress day-ahead locational marginal prices (LMPs), creating a higher price differential against real time. Calpine echoes that point, insisting that the new ISO method will encouraging under-scheduling:
"Yes," says Calpine, "you will get price convergence in day-ahead and real-time markets, but each will be understated."
Other utilities complain that the proposed allocation method will make it impossible for them to hedge the risk of real-time RMR charges, since, if they serve load, they will take a hit no matter how good of a job they do in covering their day-ahead positions.
The best solution may well lie in the counterintuitive idea of treating RMR power-plant operation as a transmission service, rather than energy or generation, according to PSEG Energy Resources and Trade LLC, which filed comments in February to protest the ISO proposal. To understand why, consider the subtle difference between the twin concepts of a load-serving entity (LSE), which enters the market to procure supply to serve demand, and "network load," describing the physical phenomenon of a local distribution utility company (LDC) that actually takes energy off the transmission network.
As PSEG explains, under New England Power Pool (NEPOOL) protocols, suppliers who serve load are not necessarily the same entities as those who take energy off the system. The one acts as a market player. The other operates a physical system. PSEG explains the difference, and how it relates to RMR cost policy:
"The need to commit RMR units," says PSEG, is not a market product, rather it is a reliability requirement that is incurred based on the physical needs of the system.
"As such," adds PSEG, "it should be recognized [as] a transmission service [with] costs allocated to network load, like other transmission reliability charges, such as VAR support and blackstart."
Here's the key concept: While the ISO must dispatch RMR resources to support the physical needs of the system, an allocation to real-time market load throws the cost off on those transacting bids on a financial basis in the wholesale markets. As PSEG notes, it sends a price signal regarding transmission reliability to a class of financial market participants that cannot predict, manage or hedge those costs in any way.
Next, consider the case of the Neptune merchant transmission line, proposed to run from northern New Jersey (FirstEnergy's Sayreville substation), in the PJM grid, to North Hempstead, N.Y., and designed to ship 660 MW through a direct-current undersea cable to power-starved Long Island. At the downstream end, Long Island Lighting Co., the operating electric utility subsidiary of Long Island Power Authority (LIPA), says it is counting on the Neptune merchant line to provided essential energy supplies to serve its retail electric customers for the summer