The latest outlook for the Ontario electric system foresees tighter supply conditions and potential risks as soon as the summer of 2021. Consequently the IESO expects to mitigate the risks by rescheduling outages and taking other measures. Demand in Ontario’s electricity system rose to more than 24,400 MW on July 9, a level not experienced since 2013. This level of demand was somewhat surprising given that it took place during a pandemic when many businesses were closed. In a September 28 stakeholder meeting on Resource Adequacy, Len Kula, the IESO’s COO and Vice President of Planning, Acquisition and Operations, said that capacity needs are appearing as soon as the summer of 2021.
Although there are significant uncertainties, the IESO plans to deploy a series of initiatives to manage short-term and near-term supply risk. First of all, it is proceeding with a Capacity Auction in December, to secure additional capacity resources for the year ahead. In addition, a framework to competitively acquire capacity to meet short-, mid-, and long-term electricity system needs is under development. Mr. Kula stressed that the IESO sees value in the diversity of the supply mix in Ontario, noting that, “The aggregate strength of the fleet” helps to “overcome the shortcomings of any individual resource.” Mr. Kula reminded market participants that “grid operations are much more complex than they were 20 years ago.” Demand is less predictable. “Coal has been replaced by less flexible gas.” There is more variable generation and embedded generation. All these factors add up to a situation where the IESO has to be much more cognizant of managing risk than ever before.
Travis Lusney, Manager of Procurement and Power Systems with Power Advisory LLC, observed that “Multiple times this summer the IESO issued energy emergency alerts level 1 to indicate there was a potential the system would not have enough energy or capacity to meet demand requirements. This is a key initial signal that while Ontario may have enough energy secured through rate-regulated assets and contracted resources, capacity needs are the primary system requirements in the near-term.”
Prompting further concern, the IESO’s unprecedented activation of Hourly Demand Response during a critical period this summer appears to have exposed differences of opinion on how “out-of-market” actions should be managed. Just after noon on July 10, the IESO declared an Energy Emergency Alert 1 (EEA1), a first level emergency, and soon thereafter issued a notice that it would be activating HDR (Hourly Demand Response) for 4 hours starting at 3:00 pm. It had never before activated HDR.
Brady Yauch, Manager of Markets and Regulatory Affairs for Power Advisory LLC, published a hard-hitting analysis of these events. “In this case, IESO-led intervention may have distorted the setting of an accurate price signal to market participants when system conditions were tight. … [T]he event raises concerns on how quick the IESO should be to intervene in the price-setting process, whether the current market is accurately reflecting scarcity and what impact such behaviour may have on both short-run and long-run price signals.”
Power Advisory notes that “on July 10th, in the same hours that the IESO was providing payments equal to the ceiling clearing price, HOEP ranged between $18.42/MWh and $31.73/MWh – below the rate set for Ontario Power Generation’s (OPG’s) rate-regulated assets (the largest market participant) and (in a number of intervals) the five-minute Market Clearing Price (MCP) in both the neighbouring MISO and NYISO markets. While the most expensive resources in Ontario – based on their short-run marginal costs – were being dispatched (and paid) out of the economic merit order by the IESO to curtail their consumption, most electricity customers were purchasing energy well below its rate regulated and contracted cost (i.e., actual cost). On that day, there was a stark disconnect between what the IESO was willing to pay to maintain reliability through payments to HDR resources for curtailment compared to the price that market participants were being paid for each MW generated.”
Mr. Yauch is concerned that this event “sends a signal to consumers that the IESO may step in and pay whatever it takes. ... In the future, market participants willing and capable of responding to wholesale prices may not do so knowing that the IESO will take pre-emptive steps on their behalf. At the same time, energy traders may also take IESO intervention into consideration when undertaking arbitrage between neighbouring market(s). We should note that according to the IESO’s Adequacy Report, less than half of offered imports were scheduled in real-time. We recognize there are many variables to consider when comparing offered/scheduled data; however, the spread between offered and scheduled imports was 3x to 4x the activated capacity of HDR resources suggesting high potential for available capacity from imports.”
Mr. Yauch wrote that “The out-of-market activation of HDR is the latest example of the system operator intervention potentially impacting the ‘price fidelity’ of the MCP and the LMP” and expressed concern about the Market Renewal Program, saying, “some of the benefits to these reforms (e.g., implementation of LMP) may be undermined through IESO interventions in the market.” He concluded that “how the IESO applies control actions when the power system is stressed, and its impacts on energy and OR prices, should be of great focus within the present deliberations regarding the draft MRP detailed design.”
The IESO launched its formal stakeholder engagement on Resource Adequacy on September 28. See “IESO proposes 3-part Resource Adequacy framework,” elsewhere this issue.