Category: 📊 Reference
This page provides five illustrative trade examples under Ontario's 2025 Market Renewal Program (MRP) structure.
The examples are simplified and use hypothetical numbers to explain trade logic, system value, and trader economics.
| Trade Type |
Primary Data Used |
Typical Timeframe |
Main System Benefit |
Primary Profit Driver |
| Day-Ahead vs Real-Time Spread |
DAM and RT price forecasts, weather/load updates |
Intraday to day-ahead |
Better schedule alignment and balancing response |
DA/RT price spread |
| Locational Congestion Spread |
LMP forecasts, outage schedules, transfer constraints |
Day-ahead to intraday |
Congestion-aware dispatch and stronger locational signals |
LMP spread between locations |
| Storage Energy + OR Stack |
State-of-charge, DA/RT prices, OR prices, dispatch risk |
Intraday and hourly rebalance |
Fast flexibility and reliability support |
Energy arbitrage + reserve revenues |
| Intertie Import/Export Arbitrage |
Ontario and neighboring prices, intertie capability, losses |
Day-ahead to real-time |
Regional balancing and efficient transfer use |
Cross-border spread net transfer costs |
| Demand Response / Flexible Load |
Facility load baseline, curtailment cost, peak likelihood, prices |
Day-ahead and event window |
Peak reduction and lower stress on constrained hours |
Avoided high-price consumption and participation value |
A trader expects real-time prices to rise above day-ahead for Hour 18 due to warmer-than-expected weather.
- Day-ahead buy price: $47/MWh
- Expected real-time sell price: $61/MWh
- Position size: 60 MWh
- Buy 60 MWh in DAM (Day-Ahead Market) at $47/MWh.
- Sell equivalent exposure in real-time at realized RT (Real Time) Electrical Price of $59/MWh.
- Gross spread = (59 - 47) x 60 = $720
- Transaction and balancing costs = $130
- Net trade margin = $590
- Encourages better forward scheduling before the operating hour.
- Helps market participants respond when demand outlook changes.
- Improves alignment between expected and realized supply needs.
The trader earns margin when real-time price settles above day-ahead purchase price by more than total trading costs.
- Day-ahead and real-time price curves
- short-term weather updates
- load forecast revisions
- generator outage/availability notices
A trader expects congestion into a high-demand import zone during the evening peak.
- Source location forecast LMP: $44/MWh
- Sink location forecast LMP: $68/MWh
- Trade size: 35 MWh
- Buy exposure at lower-priced source location.
- Sell exposure at higher-priced sink location.
- Manage volumetric risk if real-time constraints reduce transfer.
- Realized source LMP (Locational Marginal Price): $46/MWh
- Realized sink LMP: $71/MWh
- Delivered volume after curtailment: 30 MWh
- Gross spread margin = (71 - 46) x 30 = $750
- Fees and imbalance charges = $180
- Net trade margin = $570
- Reinforces congestion-reflective dispatch behavior.
- Supports efficient use of scarce transfer capability.
- Strengthens locational investment and consumption signals.
The trader captures the price difference between constrained and unconstrained locations, net of deliverability and transaction costs.
- nodal/zonal LMP forecasts
- transmission outage schedules
- historical congestion patterns
- regional load and generation forecasts
A battery trader co-optimizes energy arbitrage with OR (Operating Reserve) participation.
- Charge window energy price: $31/MWh
- Discharge window energy price: $72/MWh
- Battery dispatch volume: 24 MWh
- Operating reserve cleared quantity: 8 MW for 2 hours
- OR price: $19/MW-h
- Charge battery during lower-price midday interval.
- Submit discharge offer for evening high-price interval.
- Offer available capacity into operating reserve for reliability support.
- Energy arbitrage margin = (72 - 31) x 24 = $984
- OR revenue = 8 x 2 x 19 = $304
- Gross revenue = $1,288
- Degradation + round-trip loss + fees = $355
- Net trade margin = $933
- Adds fast-response flexibility during tight periods.
- Supports reliability by maintaining reserve capability.
- Reduces reliance on higher-cost emergency actions.
The trader combines time-shifted energy value with reliability product revenue and keeps net margin after asset operating costs.
- state-of-charge constraints and battery efficiency
- day-ahead/real-time price forecasts
- OR market prices and expected activation risk
- battery degradation cost assumptions
A trader sees Ontario evening prices expected to exceed a neighboring market by a margin larger than transfer costs.
- Neighboring market price: $48/MWh
- Ontario expected real-time price: $67/MWh
- Intertie transfer capability booked: 50 MWh
- Transfer losses and wheeling cost equivalent: $5/MWh
- Buy power in neighboring market.
- Schedule import over intertie into Ontario delivery hour.
- Sell imported volume into Ontario market.
- Realized Ontario price: $65/MWh
- Realized external purchase price: $49/MWh
- Net spread before fees = (65 - 49 - 5) x 50 = $550
- Scheduling/transaction costs = $120
- Net trade margin = $430
- Improves regional balancing between neighboring systems.
- Uses available transfer capability to meet Ontario demand.
- Can reduce pressure on local high-cost generation during tight hours.
The trader profits when Ontario sale price exceeds external purchase plus transfer and transaction costs.
- Ontario vs neighboring market price forecasts
- intertie capability and scheduling windows
- expected losses and wheeling charges
- cross-border congestion and curtailment risk
¶ Example 5: Demand Response / Flexible Load Trade
A large industrial participant can curtail 12 MW during expected high-price evening hours.
- Normal consumption: 12 MW for 2 hours = 24 MWh
- Expected high-price interval: $185/MWh
- Off-peak make-up production price: $62/MWh
- Operational curtailment cost: $1,600
- Reduce consumption during forecast high-price interval.
- Shift flexible processes to lower-priced hours.
- Settle reduced high-price exposure and increased off-peak usage.
- Avoided high-price cost = 24 x 185 = $4,440
- Replacement off-peak energy cost = 24 x 62 = $1,488
- Gross avoided-cost value = $2,952
- Less curtailment/operational cost = $1,600
- Net trade-equivalent value = $1,352
- Reduces demand during stressed peak intervals.
- Lowers dispatch pressure on scarce resources.
- Improves short-duration reliability margins.
The trader (or load optimization team) creates value by avoiding high-cost consumption and shifting usage to lower-cost periods, net of curtailment costs.
- facility baseline load and controllable load profile
- probability of peak and high-price intervals
- operational constraints and restart costs
- day-ahead/real-time price expectations
- All values are illustrative for training purposes.
- Actual outcomes depend on specific market rules, settlement details, and asset constraints.
- Trade decisions should be supported by formal risk controls and compliance procedures.
Last Updated: 2026-03-27