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Hourly Prices & Ontario Demand — Today

Solid = real-time actuals  ·  Dashed = day-ahead / forecast  ·  Shaded = forecast window  ·  Hour of day (EPT)

Today's Demand vs ICI Thresholds

Actual and forecast Ontario demand against the current top-5 peaks  ·  refreshes every 5 min from IESO

Dashed lines mark the current top-5 peaks (#1 highest); the shaded band spans #1 to #5. Demand above #5 would displace it from the base period.

ICI Ontario Demand Peak Tracker

Current base period top 5 coincident peaks  ·  IESO Source ↗

30-Day Daily Peak Demand

Peak Ontario demand per day vs ICI thresholds

Shaded band spans Peak #1 (top) to Peak #5 (bottom) ICI thresholds. Red points reached the Peak #5 threshold — they rank in (or would displace into) the current top 5.

Component Breakdown — Year Comparison

Annual totals ($M)
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Mix — 2017

Mix — 2025

Change by Component

By component
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Component Evolution

Annual totals · Toggle to compare
Year Range:

Gross GA by Component

7 largest components, before the Non-Hydro Renewables offset · complete years · $M

How Global Adjustment Is Calculated

GA = Contracted/Regulated Payments − HOEP Revenue + Uplift & Programs − Funding Offsets
Each generator or program receives a guarantee (contract rate, regulated rate, or cost-of-service). The GA true-up pays the difference when the Ontario Energy Market Price (OEMP/HOEP) falls short. When spot prices are high, the GA shrinks — or turns negative — as market revenue covers more of the contracted cost.
Below, each component's cost anatomy is explained: what drives the contracted rate, what adjustments apply, and why the number moves.
Contract / Mechanism Types
CONTRACTED Feed-in Tariff or PPA — fixed $ per MWh, IESO trues up vs HOEP
REGULATED OEB / OPG rate approved via regulatory process
OPA / IESO OPA (now IESO) administered program or procurement
OEFC Ontario Electricity Financial Corp — legacy debt / stranded-cost recovery
OFFSET Provincial transfer reducing ratepayer burden
Nuclear (non-OPG)
Primarily Bruce Power LP
CONTRACTED
OEMP True-Up (Baseload Revenue Guarantee)
Bruce Power sells energy into the market at HOEP. IESO pays the difference between Bruce's contracted rate and the market price it receives. When HOEP is low, this is the dominant cost item.
Contract rate varies by unit; ~$68–72/MWh for most Bruce units post-2016 amended agreements
Major Component Replacement (MCR) / Refurbishment
Bruce Power's amended agreements include a capital refurbishment adder — a $/MWh charge passed through the GA to fund multi-year life-extension projects (reactor pressure tube replacement, steam generator work). This raises the effective contracted rate during active refurbishment windows.
MCR-1 through MCR-6 units scheduled 2020–2033. Adds ~$5–15/MWh to effective rate during active years.
Unit Outage / Capacity Adjustments
When a unit is offline for planned or unplanned outages, eligible capacity changes. The GA reflects only actual generation, so prolonged outages reduce the component volume even as the per-MWh gap may persist.
Ancillary & Capacity Payments
Payments for operating reserve, regulation, and other grid services flow through GA settlements in addition to energy revenue true-ups.
Key driver of GA decline 2017→2025: Contract expirations on older Bruce units reduced total contracted MWh eligible for the true-up. Annual component fell ~$1,975M (–48%) over the period.
OPG Nuclear / Hydro
Regulated rate-of-return model
REGULATED
Regulated Price Minus HOEP Revenue
OPG's nuclear (Darlington, Pickering) and regulated hydro facilities sell at OEB-approved regulated prices. The GA true-up pays the gap between this regulated price and the HOEP. The regulated price includes OPG's allowed cost-of-service plus a return on rate base.
OEB sets rates through multi-year rate proceedings. Effective blended rate ~$60–90/MWh depending on facility and year.
Darlington Refurbishment Cost Rider
OPG's Darlington refurbishment (~$12.8B project, 2016–2026) is funded through an OEB-approved Darlington Refurbishment Variance Account (DRVA). Costs accumulate during the project and are recovered through the regulated rate, flowing into the GA. This is the single largest upward cost driver in this component post-2016.
Unit-by-unit refurbishment: D2 (2016–2020), D3 (2020–2022), D4 (2023–2025), D1 (2026+). Peak cost loading in 2019–2022.
Regulated Hydro Water Conditions
OPG's regulated hydro is pass-through — actual water conditions affect generation volume. Wet years mean more hydro output (more revenue netted against GA). Dry years reduce hydro output and increase net GA.
Used Fuel & Decommissioning Funds
OPG's regulated rate includes contributions to the Used Fuel Segregated Fund and the Decommissioning Fund, set by OEB. These long-dated nuclear liabilities are paid into trust annually and flow through the GA.
Pickering Deferral & Phase-Out Costs
OEB deferral account adjustments for Pickering operations (extended beyond original shutdown date) and eventual decommissioning preparation costs are included in the regulated rate, flowing through GA.
2017→2025 change (–$990M, –37%): Primarily reflects Pickering decommissioning beginning 2024, offset partially by Darlington refurbishment adders and rate-base growth. Post-refurbishment OPG regulated rates expected to increase as Darlington units return at higher capital cost.
Wind
FIT / LRP / OPA contracts
OPA / IESO
FIT Contract True-Up vs HOEP
Wind generators under Feed-in Tariff (FIT) contracts receive a guaranteed rate (e.g., $135/MWh for large wind under FIT 1.0). They sell energy at HOEP; IESO pays the difference through the GA. When HOEP is very low or negative, this gap is at its maximum. Wind does not get curtailment compensation for GA purposes — it only earns on delivered MWh.
FIT rates: Large wind ~$115–135/MWh (FIT 1.0–3.0); LRP contracts ~$85–105/MWh. Significant contracts come off FIT and transition to spot from 2025 onward.
Volume × Price Gap = GA Contribution
Wind GA = Total contracted wind generation × (Contracted rate − HOEP). Volume has grown as new capacity connects; the GA per MWh gap is sensitive to seasonal HOEP. Spring low-load periods (high wind + low demand) produce the largest per-MWh gaps.
Connection & Integration Costs
Some OPA/IESO wind contracts include connection cost reimbursement or adders that flow through the GA settlement process, separate from the straight energy true-up.
Stable 2017→2025 (~$1,492–$2,002M range): New capacity additions roughly offset declining per-MWh gaps as HOEP rose. Non-Hydro Renewables Funding (2021+) offsets ratepayer burden without changing gross Wind component.
Solar
FIT microFIT rooftop & ground-mount
OPA / IESO
FIT / microFIT True-Up vs HOEP
Solar is the highest-rate FIT category. Rooftop microFIT (<10 kW) received up to $802/MWh under early FIT 1.0 rates, with rates declining significantly for later vintages. Large ground-mount solar received ~$443–$548/MWh under FIT 1.0. The entire output is sold to the IESO at HOEP, and the full guaranteed rate is paid through the GA — creating a large per-MWh gap.
FIT 1.0 rates (2009) were extremely high; FIT 2.0–5.0 and LRP brought rates down dramatically. New contracts post-LRP are far cheaper.
20-Year Contract Vintage Lock-In
FIT contracts are 20 years. Early FIT 1.0 solar (2009–2011 vintage) will start expiring only around 2029–2031. Until then, the high legacy rates are fixed. New lower-rate contracts blend in, but the overall Solar GA remains high due to legacy volume.
Irradiance / Seasonal Variability
Solar generation peaks May–August, creating higher GA costs in those months (when generation is high and HOEP may also be lower due to conservation voltage reduction). Winter months contribute minimally. Year-over-year variability is modest.
Consistently ~$1,440–$1,711M: Volume growth in new-vintage contracts at lower rates partly offset by continued high-rate legacy FIT. Solar GA costs expected to decline meaningfully from ~2029 as FIT 1.0 contracts expire.
Natural Gas
OPA Peaking & Dispatchable contracts
OPA / IESO
Capacity Payment (Availability Guarantee)
OPA-contracted gas peakers receive a capacity payment regardless of dispatch — this is the dominant cost line. Generators get paid $/MW per day to be available. This is paid through the GA and does not depend on HOEP. When gas is rarely dispatched, the GA captures the full capacity cost with almost zero energy revenue offset.
Typical capacity payments: ~$10,000–$35,000/MW-year depending on contract vintage and facility type.
Energy True-Up (Dispatched MWh)
When a contracted gas unit is dispatched by IESO, it receives its contracted energy price. The GA pays the difference between the contract energy rate and the HOEP received. High HOEP periods reduce or eliminate this cost; when gas is dispatched at times of high HOEP the GA can actually receive a credit.
Ancillary Service Payments
OPA contracts often include operating reserve and regulation compensation. These are settled through the GA when the contracted price exceeds the market-cleared ancillary rate.
Emerged 2018 (~$1,296M), declining to ~$447M in 2025: Initial contracts signed under Ontario's reliability need for peaking capacity. Contract expirations and lower dispatch in high-HOEP years driving decline. Zero in 2017 (contracts not yet active or differently classified).
Hydro (Non-OPG)
OPA-contracted run-of-river & storage hydro
CONTRACTED
FIT / OPA Contract True-Up vs HOEP
Non-OPG hydro generators (independent run-of-river facilities, some storage hydro) operate under OPA FIT or legacy OPA contracts. They sell at HOEP; the GA true-up covers the gap to their contracted rate. Rates are generally lower than wind/solar ($60–130/MWh range).
Water Conditions & Hydrology Risk
Run-of-river hydro GA costs are highly sensitive to annual precipitation and snowpack. Wet years generate more MWh (higher total true-up volume); dry years reduce generation and total GA cost for this component.
OEFC Legacy Hydro Contracts
Some older hydro contracts pre-date OPA and were administered through OEFC. These are grandfathered contracts with different rate structures; residual costs flow through either this component or OEFC-NUG depending on classification.
Relatively stable ~$538–$823M: Mature contract base without significant new addition. Year-to-year variation driven primarily by hydrology rather than price or policy change.
Conservation
Conservation & Demand Management programs
OPA / IESO
CDM Program Delivery Costs
The largest line item: costs paid to LDCs, aggregators, and program administrators to deliver Conservation and Demand Management programs. Includes customer incentives (rebates for efficient appliances, lighting retrofits, etc.), program management fees, and measurement & verification costs.
IESO CDM framework: saveONenergy and successor programs. Annual budget set by IESO/Ministry, flowed through GA.
Achiever Incentives & Performance Payments
LDCs achieving CDM targets receive performance incentive payments funded through the GA. These vary year-to-year based on target achievement rates.
Industrial Accelerator Program (IAP) & Other
Large industrial customer retrofits subsidized under IAP, plus ICI (Industrial Conservation Initiative) programs that shift load rather than reduce it, are sometimes partially captured here.
Variable ~$163–$487M: Highly policy-sensitive. Spiked in 2025 (~$487M) as new CDM frameworks ramped up. Minimum in 2023 (~$163M) during program transition between CDM frameworks. Unlike generation components, this is purely a cost with no HOEP offset.
Biomass / Biogas
OPA FIT renewable thermal contracts
OPA / IESO
FIT Contract True-Up vs HOEP
Biomass and biogas generators under FIT contracts receive a guaranteed rate (typically $130–$138/MWh for biomass, $265/MWh for biogas under FIT 1.0, declining for later vintages). GA pays the gap between this rate and HOEP received. These facilities are fully dispatchable — different from intermittent wind/solar — but contracted on a generation basis.
Fuel Cost Pass-Through
Some biomass OPA contracts include a fuel cost indexer — when wood biomass or agricultural residue input prices rise, the contracted rate adjusts upward, increasing the GA cost. This pass-through mechanism protects generator viability but exposes the GA to input commodity price risk.
Co-firing / Conversion Incentives
Some former coal plants converted to biomass under OPA contracts (e.g., Atikokan, Thunder Bay). These conversion contracts have specific rate structures that reflect both the capital conversion costs and operating fuel costs — all ultimately settled through the GA.
Declining ~$170–$287M: Gradual decline as some older FIT biomass contracts expire and are not replaced at equivalent rates. Total capacity has also decreased as some facilities exit the market.
OEFC-NUG
Ontario Electricity Financial Corp — Non-Utility Generator legacy
OEFC
Legacy Pre-OPA Contract Obligations
OEFC-NUG costs represent obligations under pre-deregulation contracts signed by Ontario Hydro (OEFC's predecessor) with Non-Utility Generators — small independent power producers, cogeneration, and renewable facilities that pre-date the OPA era. OEFC holds these contracts and the GA reimburses OEFC for the above-market cost.
These are wind-down obligations; new contracts are not added to this category.
Above-Market True-Up (Contract Rate − HOEP)
Identical mechanism to FIT — OEFC pays NUG generators their contracted rate; to the extent this exceeds HOEP, the shortfall is recovered through the GA from ratepayers. As older contracts expire and are not renewed, this pool continues to shrink.
Residual Stranded Cost Recovery
A small component covers residual stranded-cost obligations from Ontario Hydro's pre-deregulation nuclear overbuilds and legacy contracts. This is distinct from energy revenue and is a fixed annual charge allocated to ratepayers through the GA.
Rapidly declining ~$23–$268M: On a clear wind-down path as legacy contracts expire. Expected to approach zero by late 2020s. The 2017 level of $268M reflects many contracts still active; by 2025 only ~$23M remains — a 91% reduction.
Other Programs
Miscellaneous IESO-administered obligations
OPA / IESO
Demand Response (DR) Programs
IESO-run demand response auctions where large industrial and commercial customers are paid to reduce load on demand. Capacity payments are collected through the GA; energy payments are settled through the market. DR programs avoid the need for additional peaking generation.
Energy Storage Contracts
OPA/IESO energy storage procurement (e.g., large battery systems for frequency regulation and capacity) settled through GA. Storage earns revenue from both capacity and ancillary services; the GA covers any shortfall from contracted rates.
Transitional Programs & Settlements
Includes OPA transitional contracts (generators in transition between regulatory frameworks), clean-up settlements for expired contracts still in the settlement process, and interim supply arrangements for system reliability.
Rate-Rider & Sector-Specific Adjustments
Certain sector-specific programs (e.g., Northern Industrial Electricity Rate, Broader Public Sector CDM) create GA cost or credit adjustments that don't fit cleanly into generation component categories.
Small but variable ~$24–$90M: Reflects a catch-all for emerging programs. Expected to grow modestly as new procurement vehicles (DR 3, battery storage capacity) scale up through the mid-2020s.
Financing
IESO / OPA working capital & net settlement adjustments
REGULATED
IESO Working Capital Cost Recovery
The IESO advances payments to generators and program administrators before recovering from ratepayers. The cost of this working capital (borrowing costs, line-of-credit interest) is recovered through the GA as a financing charge. Varies with interest rates and the size of advance obligations.
Prior-Period Settlement Adjustments
Settlement reconciliations from prior periods — meter data corrections, contract adjustment settlements, regulatory adjustments — create credits or debits that appear as Financing adjustments in the current period. This is why Financing is sometimes negative.
OPA / IESO Administrative Costs
A small portion of IESO's and OPA's operating costs (those directly attributable to GA-funded program administration) are recovered through this component rather than the market service fee.
Small and volatile (−$34M to +$3M): Not a material driver of overall GA. The negative years reflect large prior-period settlement credits flowing back to ratepayers through this component. Effectively a residual balancing item.
Non-Hydro Renewables Funding
Provincial transfer — Wind, Solar, Biomass offset
OFFSET
Government of Ontario Transfer Payment
Starting January 2021, the Ontario government (via Ministry of Energy) provided a direct transfer payment to the IESO specifically to offset the Wind, Solar, and Biomass components of the GA. This was a policy decision to reduce electricity bills by shifting renewable energy costs from the rate base to the provincial tax base (deficit-funded). The payment appears as a large negative component (~−$3.1B/year) in the GA settlement.
This is distinct from the old Global Adjustment Rate Relief (GARR) program and is a permanent structural feature of the post-2021 GA framework.
Calculated to Offset FIT Renewable Costs
The transfer amount is sized to approximately cover the annual Wind + Solar + Biomass GA cost, reducing the net GA charged to ratepayers. The offset is set annually by the Ministry and does not track monthly fluctuations — creating timing mismatches visible in monthly data.
Effect on Reported GA vs. True Cost
The gross component totals for Wind, Solar, and Biomass are unchanged — generators still receive their full contracted rates. The offset simply reduces what ratepayers pay through the electricity bill. Total GA cost to the system is therefore higher than the consumer-facing GA figure suggests; the difference is borne by provincial taxpayers.
~−$3.13B/year (2021–2025, stable): This is the largest single reason for the apparent GA decline from 2020 to 2021. Without this offset, the 2025 GA would be ~$3.1B higher. The policy was introduced alongside the Ontario Fair Hydro Plan successor framework and the end of the Global Adjustment Rate Relief Regulation.

Settlement Mechanics — How It All Flows

From contract to monthly charge

Each month, the IESO calculates the Class A and Class B GA rate ($/MWh) by dividing total monthly GA costs by the total provincial consumption (Class B) or using 12-month forward estimates for Class A industrials. The monthly GA rate (visible in this dashboard as the headline $/MWh figure) is the blended result of all component true-ups described above.

Gross GA = Sum of all positive components (contracted true-ups, program costs, regulated shortfalls)
Net GA = Gross GA minus the Non-Hydro Renewables Funding offset (and any other credits)
Published monthly GA rate = Net GA ÷ Total provincial demand (MWh)

The figures in this dashboard represent annual totals per component in $M — the sum of 12 monthly settlements. Monthly settlement amounts vary significantly due to seasonal demand, HOEP swings, and generator dispatch patterns.

Class A vs Class B split: Large industrials (Class A, typically >1MW) are charged a GA based on their coincident peak contribution (5 peak hours) rather than total volume, incentivizing load-shifting during high-demand periods. This demand response function reduces the GA cost for participating industrials but does not reduce the total GA collected — the shortfall is borne by remaining Class B customers.

Year Range:

Class A / ICI GA Rate — Methodology

Based on published IESO peak demand data
Monthly GA Rate ($/MW) = Monthly GA Pool ($) ÷ Avg of Top-5 Peak "Total (MWh)*" from applicable Base Period
Customer Monthly Charge ($) = GA Rate ($/MW) × Customer's Avg MW during those same 5 peak hours [PDF]
Base Period: Jan–Apr of year Y → May(Y−2)–Apr(Y−1)  |  May–Dec of year Y → May(Y−1)–Apr(Y)
Denominator: Avg of 5 published "Total (MWh)*" values = Allocated Withdrawn + Embedded Gen + Storage Injections

Monthly GA Rate — $/MW Heatmap

Hover for pool, denominator & base period · Denominator resets each May and after Apr for Jan–Apr months

Monthly $/MW Rate — All Years

Highlighted years in colour, other years in grey

Annual Total $/MW

Sum of 12 monthly rates — what 1 MW of coincident peak costs per year

Current Season — Top 5 Peaks

Live standings for the in-progress base period · updated every 6h
Loading peak data…

IESO Top-5 Peak Hours — Base Period Reference

Published source data · Total (MWh)* is the official PDF denominator

Monthly Distribution of Peak Hours

All base periods combined

Peak Hour of Day

Hour starting, EPT · All base periods

Month × Hour Concentration

Count of peaks at each month-hour intersection

Avg Top-5 Peak Demand by Base Period

PDF denominator (MWh) · Lower denominator = higher $/MW cost rate

ICI Customer Calculator

Enter your Peak Demand Factor (MW) to compute monthly GA obligations
This is your facility's average demand measured during the 5 IESO coincident peak hours of the applicable base period. Reducing load during these hours directly reduces your GA obligation.
If provided, calculates your effective $/MWh GA rate for comparison against Class B rate.
Annual GA ($)
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Avg monthly ($)
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Effective $/MWh
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Month GA Rate ($/MW) Base Period Denom (MW) Your Charge
Year Range:

Monthly Average · On-Peak · Off-Peak

$/MWh · on-peak = HE 8–23 Mon–Fri (5×16), per IESO's Monthly Market Report

Monthly Detail

Sort by any column heading

Price by Month and Hour of Day

Averaged across the selected years · hour of day in EPT

Average Daily Price Shape

When power is cheap and when it is expensive

Price Duration Curve

Every hour sorted high to low — shows the tail that averages hide

Extreme Hours

Highest and lowest priced hours in range

All-In Cost — Energy + Global Adjustment

$/MWh · what a customer actually pays

Capture Rate by Fleet

Generation-weighted price ÷ market average · annual
Compare like seasons: the annual figure hides solar's summer shift.

Monthly Capture Detail

$/MWh earned, with factor vs the market average

About this dashboard

Global Adjustment (GA) is the gap between what Ontario's contracted and regulated generators are guaranteed and what they earn in the energy market, plus conservation program costs. When market prices are high GA shrinks, and it can turn negative (a credit).

Non-Hydro Renewables Funding (2021 on) is a provincial transfer that offsets the wind, solar and biomass share of GA for ratepayers.

What's where

Reading the charts