Cost risk is concentrating into fewer hours across North American electricity markets. The pattern is consistent: tighter system conditions, faster shifts in load and supply, and price formation that rewards preparation and penalizes reaction.
Three drivers. Five markets. One operating problem.
Natural gas sets the marginal price in many hours. Weather tightens conditions fast. Load growth from data centers, electrification, and industrial expansion increases the frequency of tight hours. These drivers interact differently by market, but the operating problem is the same: flexibility on paper does not translate to performance under pressure unless the plan is repeatable, measurable, and independent of any single person or manual process.
What has changed
Ontario: The IESO’s renewed market structure launched May 1, 2025, making price formation more sensitive to local conditions and time-of-use. The 2026/27 Capacity Auction cleared at record levels, with winter prices exceeding summer for the first time, a signal most peak planning models have not incorporated.
Alberta: AESO remains energy-only with sharp moves in tight hours. The 1,200 MW interim connection limit for large load is fully allocated. The Restructured Energy Market introduces new flexibility products that raise the value of fast, verifiable response.
NYISO: Locational pricing creates zone-specific exposure, especially downstate. The Q2 2025 heat wave produced the highest load since 2018 alongside reserve shortages. Demand response and aggregation pathways exist but require telemetry and controls that many facilities have not built.
MISO: Summer capacity cleared at $666.50/MW-day, 22 times higher than the prior year, driven by declining surplus and the first-year Reliability-Based Demand Curve. Subregional constraints add another layer of site-specific risk.
PJM: The 2026/27 BRA cleared at the FERC-approved cap of $329.17/MW-day across the entire footprint. PJM’s 15-year summer peak forecast projects a climb of approximately 85,000 MW. Non-performance charges during emergency conditions make execution discipline a financial requirement, not an operational preference.
What Rodan brings to the conversation
Rodan manages over 300 MW of demand response in Ontario and operates across IESO, AESO, NYISO, PJM, and MISO. Rodan cleared 288.7 MW in the IESO 2026/27 Capacity Auction, the largest demand response position in Ontario. In New York, Rodan helped Alcoa generate over $10 million in demand response earnings since 2021 through NYISO’s ICAP and spinning reserve programs.
The operating model is consistent across markets: identify when cost exposure concentrates, build a response plan that matches how the site runs, execute with metering, telemetry, and controls that produce repeatable results, and verify performance at settlement grade.
Rodan publishes detailed volatility briefings for each market. Contact your Rodan representative or visit rodanenergy.com to request the briefing for your market.
Next step
Request a 30-minute volatility check. Share 12 months of interval data and your operating limits. Rodan will return a plain-language readout of the hours that drive cost, the sites with practical flexibility, and whether automation or storage belongs in the plan.
ABOUT RODAN ENERGY SOLUTIONS
Rodan Energy Solutions provides energy management, demand response, distributed energy resource operations, and power systems engineering across North American electricity markets. Rodan manages over 300 MW of demand response in Ontario and operates across IESO, AESO, NYISO, PJM, and MISO markets. Services include dispatch monitoring and response, controls integration, wholesale metering and MSP services, settlement validation, and power systems engineering.
