Ontario electricity consumers may have the option of paying nodal prices or a province-wide zonal price -- and may switch back and forth in a limited way -- under a load pricing mechanism proposed for the Independent Electricity System Operator's Market Renewal Program.
During a Market Renewal Program update webcast, IESO executives described a load pricing proposal under the MRP's planned single schedule market and an effort currently being considered to evaluate the costs and benefits of the MRP itself, in light of this week's decision not to implement a new long-term Incremental Capacity Auction.
In 2017, IESO determined it would start needing new capacity by the early 2020s, and hired The Brattle Group to conduct a benefit-cost analysis of the market reforms that became the MRP, indicating that it would bring C$3.5 billion (US$2.7 billion) in efficiencies during the first nine years of operation at a cost of C$150-200 million.
But in an email Wednesday, IESO spokesman Andrew Dow said that since then, "our needs have changed," and new capacity is unlikely to be needed over the next decade.
"Given the updated outlook, the IESO is stopping work on the ICA to focus on implementing the Transitional Capacity Auction (TCA), with the first auction this December," Dow said.
The Transitional Capacity Auction builds on IESO's existing Demand Response Auction, adding dispatchable generation to the mix of resources that can bid to supply capacity over the following summer and winter seasons.
"The capacity needs forecasted over the next decade can likely be met through existing and available resources such as Demand Response, imports, generators that are coming off long-term contract, uprates and energy efficiency -- most of these are resources that the TCA is focused on," Dow said.
Regarding load pricing, IESO currently operates a two-schedule energy market, in which the first schedule solves for resource cost and results in a market clearing price, without consideration of constraints such as transmission limitations. The second schedule solves for resource dispatch while taking into account actual system conditions, and operational and transmission constraints. The two-schedule system often results in out-of-market payments to account for the differences between the two schedules.
The proposed single-schedule market would be designed to set energy prices while considering all system and resource operating constraints at the same time and remove out-of-market payments, but the high-level design document released in September, which proposed 10 different zonal price areas, drew fire from large industrial users who prefer a single systemwide price for loads.
'Active loads' treated differently
In June, IESO had presented a load pricing design in which nondispatchable wholesale load would pay a single IESO-wide price, while "active loads" that can be ramped down via demand response programs would pay nodal prices.
On Wednesday, Darren Matsugu, IESO senior manager for market design and integration, said, "The principle for nodal pricing for 'active' resources is that these resources receive energy schedules based on the economics of their energy bid at that location. To ensure these schedules are followed without the need for make-whole payments, settlement prices should be aligned with dispatch."
But the design also would allow active loads to "opt-out" of nodal pricing as long as those loads stayed in the zonal pricing program for at least a year, at which time they could resume nodal pricing, if they so choose, Matsugu said.
Switch timing questioned
The Association of Major Power Consumers in Ontario has criticized the different timelines for opting out, which can occur once a year, and opting in, which can occur for various resources once a month, as long as those dispatchable resources have been on the zonal price for at least a year, saying the difference "appears punitive."
One reason IESO management favors active loads staying out of nodal pricing for at least 12 months is that changing back and forth incurs an administrative burden, which could get out of hand with large numbers of switches, Matsugu said. For example, loads exposed to nodal prices may respond differently to loads paying zonal prices, which may affect the load forecast.
Another issue is that loads could use the switching mechanisms to exploit price differences with costs thereby shifted to other consumers.
"IESO will further investigate the issue in detail design ... to ensure that opportunities to 'game' or take advantage of pricing, at the expense of other consumers, are minimized," Matsugu said.
Load pricing is part of the single-schedule market design, which is just one aspect of the "energy" stream of the Market Renewal Program. Other aspects include establishing a day-ahead market and enhanced real-time unit commitment.
The final high-level design documents for the SSM, DAM and ERUC are due by the end of July and on the August 14 IESO Stakeholder Advisory Committee agenda, with consideration by the IESO Board of Directors on August 28, Matsugu said.
