By Kate Thomas
OGJ Online
HOUSTON, Apr. 25 -- The New York Independent System Operator Thursday is scheduled to consider recommendations to create a combined day-ahead market incorporating the New York ISO, the Ontario IMO, and ISO New England.
Seven alternatives were laid out in a study commissioned by the three grid operators. Supporters say a combined market will improve electricity trading across the Northeast with more consistent scheduling of transactions within the region.
In comments, Mirant Corp. called for PJM Inc.'s participation in a regional market and for 100 Gw of capacity to enhance competition and liquidity. Mirant said the goal should be to establish a single set of prices, settlement functions, financial transmission rights, and one close and post schedule.
So-called seams between the four grid operations would become internal transmission interfaces, Mirant said, while continuity of the market across these boundaries would encourage construction of additional transmission capacity.
Mirant called the need to eliminate seams and create a single market "immediate." The company said the changes need to be instituted much sooner than 3-5 years in the future.
According to the study, a regional market would also improve inter-ISO congestion management and lead to regional reserve sharing mechanisms, lowering costs. A bigger regional market would also reduce concern about market power in subregions, improve hedging for transmission congestion, and reduce software costs, it said.
Avoiding unbalanced schedules and the associated need to hold capacity out of the various day-ahead unit commitment and scheduling process would be an important regional market objective, according to the study.
Under existing market structures, a market participant interested in scheduling transactions between two independent system operators must schedule both a withdrawal from the exporting ISO and an injection into the importing ISO.
To hedge against the risk of a transaction not being completed, market participants may hold back generation from the unit and dispatch process. For example, if a market participants wants to buy power in the New England Power Pool (NEPOOL) to sell in New York and succeeds in scheduling the imports into New York but fails to secure the power from NEPOOL, there would load to be met in New York from NEPOOL for which no capacity was committed in NEPOOL to support.
These imbalances give rise to the possibility that day-ahead markets may clear, yet total resources actually committed in the day ahead may not be sufficient to meet the forecast load, plus ancillary service requirements, the report said. Presently, New York and PJM manage the possibility for unpleasant surprises with financial commitments.
To hedge against congestion costs, a market participant often must buy two sets of congestion hedges for the same transmission constraint. A combined day-ahead market could eliminate the problem, according to the study.
The report notes one advantage of a combined day-ahead market would be to permit generation to be committed within one ISO to better manage congestion within another ISO. It said the opportunity could be especially useful between Ontario and New York and between NEPOOL and New York to manage New York's central east constraint.