Capacity reductions in ISO-New England’s day-ahead energy market have been driven primarily by natural gas-fired generation, suggesting a link between the increasing reliance on natural gas-fired generation and available capacity reductions.
In a study assessing the competitiveness of ISO-NE’s wholesale electricity market, the Internal Market Monitor (IMM) analyzed the amount of available capacity lost between the day-ahead and real-time energy markets from January 2010 to June 2013 to identify any systematic patterns.
There are three intervals in which available capacity can change: the day-ahead to re-offer stage, the re-offer to real-time stage and the day-ahead to real-time stage. Generators bid into the day-ahead market a certain amount of capacity, and later may revise their supply offers to reflect more realistic expectations of capacity in the re-offer stage. After the re-offer stage, the ISO will have a different expectation of the amount of generating capacity that will be available during the operating day. Though generators may not change their supply offers during the operating day, they are required to notify the ISO in the event that their resource’s availability changes (real-time capacity). The ISO considers a reduction in capacity from the day-ahead to real-time periods a loss of available capacity.
The average hourly capacity reductions in the day-ahead to re-offer stage has increased from 79 MW in 2010 to 492 MW in 2013. However, the average hourly capacity reductions in the re-offer to real-time stage have remained “more or less” steady, between 183 MW in 2011 and 132 MW in 2013. For every year except 2010, the average hourly reductions in the day-ahead to re-offer stage were significantly higher than in the re-offer to real-time stage.
“Under normal system conditions, the unexpected loss of a resource’s available capacity can be made up by other resources through the use of operating reserves,” the IMM said in its analysis. “However, under abnormal system conditions, such as the extreme weather events the ISO experienced in the first quarter of 2013 – the January 21-28 cold snap and the February 8-10 blizzard – the loss of a critical resource can impact system reliability.”
The IMM said that during such events, it noticed that “several resources” did not provide energy when called upon.
Wholesale electricity prices on the rise
Because of the increase in natural gas prices, wholesale electricity prices increased 19% between 2Q12 and 2Q13, and energy costs increased 31%, the IMM said.
Natural gas prices increased 65% from 2Q12 to 2Q13.
Ancillary services costs increased 23% from $28.2m to $34.6m, which the IMM noted was small relative to energy and capacity payments. Real-time and day-ahead locational marginal prices were 39% and 38% higher, respectively, than in 2Q12.
The average real-time market Hub price was $40.19/MWh, up 38% from $29.06/MWh in 2Q12, and the average day-ahead market Hub price was $40.09/MWh in 2Q13, which the IMM said was consistent with observed market conditions.
“Price differences among the load zones stemmed primarily from marginal losses, with little congestion at the zonal level,” the IMM said. “Congestion was restricted primarily to smaller, more transient load pockets that formed when transmission or generation elements were out of service.”
The IMM found that the energy market was competitive during 2Q13.