Overview

Download the data used to create this report from the Ontario open data catalogue.

Ontario Grid-Connected Peak Demand (Q4)

20,738 (MW) (Set on December 16, 2020, 6:00 pm EST)

Source: IESO

Ontario Grid-Connected Peak Demand (YTD)

24,446 (MW) (Set in Q3 – July 9, 2020, 5:00 pm EST)

Source: IESO

Table 1: Transmission grid-connected generation output (Q4)
Nuclear 20.6 TWh 58.0%
Hydro 9.2 TWh 26.0%
Gas 1.9 TWh 5.4%
Wind 3.6 TWh 10.0%
Solar 0.1 TWh 0.3%
Biofuel 0.1 TWh 0.3%

Source: IESO

Table 2: Conservation savings (Q4)
Net peak demand savings 22.9 MW
Net energy savings 134.0 GWh

Source: IESO

Table 3: Commodity cost – Class A (¢/kWh)
Commodity Q4 YTD
Hourly Ontario energy price (arithmetic average) 1.18 1.27
Global Adjustment (Average, Class A) footnote 1 5.51 6.18
Total 6.69 7.45

Source: IESO

Table 4: Commodity cost – Class B (¢/kWh)
Commodity Q4 YTD
Hourly Ontario energy price (weighted average) 1.27 1.39
Global Adjustment (Average, Class B) footnote 1 11.62 11.82
Total 12.89 13.21

Source: IESO

Ontario’s transmission grid

A map of Ontario's generation facilities.

This map displays generation facilities with installed capacity of more than 20 megawatts (MW) connected to the high-voltage transmission grid. Please note that this map is used for illustrative purposes only. All locations are approximate. Last updated: June 2018.

Electricity supply

Monthly energy grid output by fuel type

Ontario’s bulk electricity grid has a diverse supply mix, featuring baseload generators that provide energy around the clock, intermittent generators that generate when they are able (primarily wind and solar), and flexible generators that can change their output quickly (primarily natural gas).

A line graph showing generated energy.

Source: IESO

This line graph displays the amount of energy generated in megawatt-hours every month from October 2019 to December 2020. The types of energy sources are: nuclear, gas hydro, wind, biofuel, solar.

The data shown above is sourced from a report developed by the IESO. The report uses settlement data to provide information for all self-schedulers, intermittent and dispatchable Ontario generators registered as a Market Participant. The report – which includes all grid-connected generators, plus those embedded generators that are also registered as market participants – is published monthly as per the Physical Settlement calendar.

Imports and exports

Ontario is connected to a large, stable network of transmission systems across North America, which supports system reliability and economic efficiency. Imports compete against domestic generation to provide energy at the best possible price and to support the province’s needs during periods of high demand. Ontario also exports energy when it is economic, which helps to bring in revenue to offset other system and infrastructure costs and maintain system reliability during times of surplus generation.

Ontario imports and exports power across 26 interties with two provinces and three states. While Ontario is electrically interconnected with Manitoba, Michigan, Minnesota, New York and Quebec, the interties allow for electricity trade in transactions that can reach across eastern North America, contributing to a more diversified and competitive pool of supply.

Q4 imports

A bar graph showing imported energy to Ontario.

This bar graph displays the data presented in table 5: the percentage of imported energy in Ontario from Manitoba, Michigan, Minnesota, New York, and Quebec for Q4 2020.

Table 5: Q4 imports
State/Province %
Manitoba 15.4%
Michigan 0.7%
Minnesota 5.3%
New York 0.1%
Quebec 78.5%

Q4 exports

A bar graph showing exported energy from Ontario.

This bar graph displays the data presented in table 6: the percentage of exported energy from Ontario to Manitoba, Michigan, Minnesota, New York, and Quebec for Q4 2020.

Table 6: Q4 exports
State/Province %
Manitoba 5.2%
Michigan 43.2%
Minnesota 1.9%
New York 39.3%
Quebec 10.4%
Table 7: Q4 Imports and Exports (GWh)
Q4 (GWh) Imports Exports
Manitoba 265.40 231.70
Michigan 11.49 1,939.91
Minnesota 91.76 86.07
New York 2.4 1,764.52
Quebec 1,354.57 468.50
Total 1,725.76 4,490.70

Source: IESO
Note: Numbers may not add up to totals due to rounding.

Installed capacity connected to transmission grid

Changes to installed transmission grid capacity in this quarter highlight the continuing process of renewal in Ontario’s electricity sector. While nuclear, hydroelectric and natural gas resources accounted for the vast majority of system capacity, new wind, biofuel and solar generators continued to connect to the transmission grid. The IESO Active Generation Contract List provides the status of individual contracted electricity supply projects within different IESO procurement programs. The list is limited to generation facilities under contract to the IESO.

Grid-connected generation capacity (Q4)

A pie graph showing electricity generation percentages.

This pie graph displays the data presented in table 8: the percentages of grid-connection generation capacity from nuclear, gas, hydro, wind, biofuel, and solar energy sources.

Table 8: Grid-connected generation capacity (Q4)
Generation %
Nuclear 34%
Gas 29%
Hydro 23%
Wind 12%
Biofuel 1%
Solar 1%

Source: IESO
Note: Data includes all transmission-connected generation facilities and distribution-connected facilities that are Market Participants. Numbers may not add up to totals due to rounding.

The table below shows how Ontario's generation capacity sources have changed since 2014.

Table 9: Grid-connected footnote 2 generation capacity
Type (MW) 2020 - YTD 2019 2018 2017 2016 2015 2014
Nuclear 13,009 13,009 13,009 13,009 12,978 12,978 12,947
Hydro 9,060 9,065 8,482 8,490 8,451 8,432 8,462
Coal 0 0 0 0 0 0 0
Gas footnote 3 11,317 10,277 10,277 10,277 9,943 9,942 9,920
Wind 4,486 4,486 4,486 4,213 3,923 3,504 2,543
Biofuel 295 295 295 495 495 495 455
Solar 478 424 380 380 280 240 40
Total 38,644 37,555 36,929 36,863 36,070 35,591 34,367

Note: Total IESO-contracted embedded generation in commercial operation at end of each period. Numbers may not add up to totals due to rounding.

Embedded generation (IESO-contracted)

Embedded generators supply electricity to local distribution systems, helping to reduce demand on the transmission grid and supporting some of the needs of local communities. While wind and solar make up the majority of contracted embedded generation, the IESO has contracted for increasing amounts of hydroelectric, combined heat and power, natural gas and biofuel systems that will also connect to local distribution networks.

By the end of Q4 2020, there was 3,521.8 MW of contracted generation in commercial operation within local distribution systems.

Contracted embedded generation capacity in commercial operation (Q4)

A pie graph showing embedded electricity generated.

This pie graph displays the data presented in table 10: the amount of embedded generation (in megawatts and corresponding percentages) in Q4 2020 from the following energy sources: gas, hydro, wind, biofuel, solar and other.

Table 10: Contracted embedded generation capacity in commercial operation (Q4)
Generation % Amount
Gas 9.1% 320 MW
Hydro 8.7% 306 MW
Wind 16.8% 590 MW
Biofuel 3.1% 110 MW
Solar 61.6% 2,170 MW
Other 0.7% 24 MW

Source: IESO
Note: Each of the above numbers appear in the IESO Q4 Progress Report on Contracted Supply.

The table below shows the increased use of embedded generation to supply electricity to local distribution systems in the province.

Contracted embedded generation capacity in commercial operation

A bar graph showing embedded electricity generated.

This bar graph displays the amount of embedded generation (in megawatts) to supply electricity to local distribution systems in the province every year from 2015 to 2020 (year-to-date). The types of energy sources are: other, biofuel, gas, hydro, wind, and solar.

Note: Total IESO-contracted embedded generation in commercial operation at end of each period. Numbers may not add up to totals due to rounding.

The data shown above are sourced from the IESO Progress Report on Contracted Supply. The report provides a quarterly update on the status of supply and procurement initiatives that are under development or in commercial operation, by fuel type, and aggregates total capacities as stated in each contract, which differs from values on installed capacity used for operation purposes. The report is available on the IESO website.

Total grid-connected and contracted embedded generation capacity

This table shows all grid-connected capacity and IESO-contracted embedded capacity in the province.

Table 11: Total grid-connected and contracted embedded generation capacity
Type 2020 Q4 (MW) 2020 Q4 (%)
Nuclear 13,009 31%
Hydro 9,366 22%
Gas 11,637 28%
Wind 5,076 12%
Biofuel 405 1%
Solar 2,648 6%
Other 24 <1%
Total 42,165  

Note: Numbers may not add up to totals due to rounding.

Conservation

The province established three electricity conservation and demand management frameworks for the period of 2015-2020. The province had established electricity savings targets for the Conservation First Framework (CFF) and the Industrial Accelerator Program (IAP) of 7.4 and 1.3 TWh, respectively. However, to streamline conservation programs, the Minister issued a Directive in March 2019 to wind down the CFF and IAP and establish a new Interim Framework for 2019-2020, for which IESO has set targets of 1.4 TWh and 189 MW. As a result of the wind down of the CFF and IAP, the IESO revised the CFF and IAP targets as follows: 1) CFF target of 6.0 TWh; 2) IAP target of 1.3 TWh. Together the CFF, IAP and Interim Framework (IF) program achieved 8,194 GWh savings as of Q4, 2020, or 94% of the target.

Of these, CFF Programs have achieved 7,426 gigawatt-hours (GWh) in electricity savings representing 124% of the 6.0 TWh CFF target, and the IAP Program has achieved 486.2 GWh in electricity savings representing 37.4% of the original 1.3 TWh target. The newly created IF Programs have achieved 281.6 GWh and 48.6 MW in electricity and demand savings representing 19.7% and 25.7% of the targets, respectively.

As is common at the start of all conservation frameworks, participation levels in the Interim Framework took time to increase as new programs were implemented, program-delivery vendors were on-boarded, and customers became more familiar with new program offerings. Actual savings are expected to continue to accrue through 2021-2022 as committed projects enter into service.

Prior to the covid 19 health emergency, the IESO was forecasting to cost effectively achieve 100% of the energy savings and demand targets. The IESO is updating its 2020 forecast to account for the covid 19 health emergency and its impact to overall energy savings and demand targets. The IESO is forecasting to cost-effectively achieve savings within +/- 5% of the 2020 targets.

Table 12: Conservation portfolio progress – results (as of 2020 Q4) footnote 4
Incremental progress 2020 Q4 Incremental footnote 5 2015-2020 Q4 Incremental 2020 target progress (%)
LDC & IESO Delivered CFF Peak Demand Savings (MW) 8.0 878.4 -
LDC && IESO Delivered CFF Energy Savings (GWh) 81.2 7,426 124
IESO Delivered IAP Peak Demand Savings (MW) 1.3 131.5 -
IESO Delivered IAP Energy Savings (GWh) 4.0 footnote 6 486.2 37.4
IESO Delivered IF Peak Demand Savings (MW) 13.6 48.6 25.7
IESO Delivered IF Energy Savings (GWh) 56.8 284.6 19.7
Total Portfolio Total Peak Demand Savings (MW) 22.9 1,058.60 -
Total Portfolio Total Energy Savings (GWh) 134.0 8,193.8 -

Source: IESO
Note: Totals may not align due to rounding.

Incremental savings (2020 Q4)

Table 13: 2020 annual peak demand savings
Program Demand savings
CFF Business Programs MW
IF Residential Programs footnote 7 1.2 MW
IF Business Programs 14.78 MW
IESO IAP Program footnote 7 MW
A pie graph showing demand savings.

This pie graph displays the data presented in table 13: the 2020 annual peak demand savings, in megawatts, from the following programs: Conservation First Framework Business Programs, Interim Framework Residential Programs, Interim Framework Business Programs, and IESO Industrial Accelerator Program.

Table 14: 2020 annual energy savings
Program Energy savings
CFF Business Programs 81 GWh
IF Residential Programs footnote 7 -8 GWh
IF Business Programs 64 GWh
IESO IAP Program footnote 7 -4 GWh
A pie graph show energy savings.

This pie graph displays the data presented in table 14: the 2020 annual energy savings, in gigawatt-hours, from the following programs: Conservation First Framework Business Programs, Interim Framework Low-Income Programs, Interim Framework Business Programs, and IESO Industrial Accelerator Program.

Source: IESO
Note: Totals may not align due to rounding.

All conservation metrics above are presented as 'net' savings which take into consideration the actual influence of the program on participants (e.g., estimating free-ridership and spill over savings). Furthermore, all savings presented above persist until the year 2020 at the end-user level (e.g., accounting for transmission and distribution system line losses). To align savings with generation level metrics, values should be increased by factor 6.7% for distribution system level savings or a factor of 2.5% for transmission system level savings.

Results presented are 'reported' (i.e. 'unverified') based on project installation dates corresponding to the indicated period and are based on projects reported and invoiced to the IESO as of 2020 quarter 4.

Demand response (DR)

Demand response and peak savings programs benefit the electricity system and lower energy costs for consumers by contributing to overall peak savings for the province.

Beginning in December 2015, DR capacity has been procured through a competitive DR Auction process. The DR Auction provided a transparent and cost-effective way to select the most competitive providers of DR, while ensuring that all providers were held to the same performance obligations.

In 2020, the IESO's Capacity Auction replaced the Demand Response (DR) Auction to enable competition between additional resource types. Capacity auctions help meet Ontario’s reliability needs in a cost effective manner while allowing the IESO to transparently adjust capacity procurement targets with changing system needs. The IESO held Capacity Auction #1 on Wednesday, December 2, 2020 for the 2021 Summer obligation period and the 2021-2022 Winter obligation period. Capacity Auction #1 secured 992.1 MW of capacity for the summer of 2021 from a range of eligible resources including demand response, imports, generation, and energy storage.

More information on the Capacity Auction is available on the IESO Capacity Auction page.

Peak savings

The Industrial Conservation Initiative (ICI) encourages large consumers to shift their energy use away from system-wide peaks. Customers who are able to reduce their impact on peaks benefit the system by reducing the need to build new infrastructure. In 2017, ICI is estimated to have reduced peak demand by 1,400 MW.

Participating customers pay Global Adjustment (GA), based on the percentage that their demand contributes to the top five system coincident peaks measured during a defined base period (May 1 to April 30).

The ICI program was paused temporarily due to the covid 19 pandemic; however, Ontario provided ICI participants with temporary relief on their electricity bills as a covid 19 relief measure. Specifically, Ontario deferred a portion of GA charges from April to June 2020.

Beginning in January 2021, deferred GA is being collected from the same classes of consumers over a twelve-month period. The government also implemented a Peak Hiatus under ICI, so that participating companies did not need to reduce their electricity demand during peak hours in 2020-2021, allowing them to focus on returning to full levels of operations.

The table below lists the top five daily peaks for the base period that began on May 1, 2019 and ended on April 30, 2020.

Table 15: Top 5 peaks: hours & system-wide consumption (Base Period: May 1, 2019 to April 30, 2020)
Date July 5, 2019 July 20, 2019 July 29, 2019 July 19, 2019 July 4, 2019
Hour Ending 17 17 17 13 18
Allocated Quantity of Energy Withdrawn (MW) 21,274.851 21,147.253 21,067.570 21,006.403 20,956.127
Embedded Generation (MW) 1,024.050 956.288 1,068.788 1,135.446 732.129
Energy Storage Injections (MWh) 4.784 0.119 7.282 4.009 4.387
Total (MW) 22,294.117 22,103.422 22,129.068 22,367.840 21,638.869

Source: IESO
Note: The value in the Total (MW) column is the number used to calculate a customer’s Peak Demand Factor.
The above values are used for the July 1, 2019 to June 30, 2020 adjustment period.

Information on peak tracking can be found on the IESO Peak Tracker page

More information on the ICI is available on the IESO website (PDF).

Greenhouse gas emissions

The marked decline in greenhouse gas emissions (measured in megatonnes of CO2 equivalent) is a result of the phase-out of coal-fired electricity generation in the province, uptake of emissions-free generation and conservation measures. Emissions of oxides of sulphur (SOx) – which are predominantly a by-product of coal combustion – have also shown a marked decrease with the phase-out of coal-fired electricity.

Greenhouse gas emissions for the Ontario electricity sector

The chart below shows annual greenhouse gas emissions (measured in megatonnes of CO2 equivalent) for the years 2011-2020. Year-to-date greenhouse gas emissions in Q4 2020 totalled approximately 4.5 megatonnes (Mt).

A line graph showing greenhouse gas emissions.

The line graph shows annual greenhouse gas emissions (measured in tonnes of carbon dioxide equivalent) for the years 2011-2020.

Source: IESO, Environment and Climate Change Canada, Ontario Ministry of Environment, Conservation and Parks
Note: Data to 2018 is as per Environment and Climate Change Canada's National Inventory Report issued in April 2020. Data for 2019 onwards is estimated by the IESO using actual energy.

Air contaminants

Air contaminants, including oxides of sulphur (SOx), oxides of nitrogen (NOx) and fine particulate matter (PM2.5), are also released during combustion of fossil fuels.

Table 16: Air contaminants for the Ontario electricity sector (Tonnes)
Emissions 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
YTD (Q4)
SOx Emissions 11,966 10,342 10,192 846 424 579 644 504 464 395
NOx Emissions 18,198 19,867 17,973 11,448 10,355 9,323 5,695 5,924 6,010 5,586
PM2.5 Emissions 518 468 445 309 262 239 195 210 212 202

Source: IESO, Environment and Climate Change Canada

Electricity demand

Ontario Grid-Connected Peak Demand in Q4: 20,738 (MW) (Set on December 16, 2020, 6:00 pm EST)

Ontario Monthly peaks and minimums

A line graph showing Ontario monthly peaks and minimums.

Source: IESO

This line graph displays Ontario monthly demand peaks and demand minimums every month between May 2019 and December 2020, in megawatts. The 2019 peak demand was 21,791 MW and the 2019 minimum demand was 10,328 MW. The Q4 2020 peak demand was 20,738 MW and the Q4 2020 minimum demand was 10,645 MW.

Forecast demand peaks

The demand for electricity on the provincial grid is forecast on a rolling 18-month basis. An assessment is done to assure the adequacy of the existing and proposed generation and transmission facilities to meet demand needs. The chart below presents normal weather forecasts, representing a typical peak for the time of year, and extreme weather forecasts that reflect severe weather conditions. The impacts of time-of-use rates and the Industrial Conservation Initiative – which incent customers to reduce demand in peak demand hours – are also factored into the demand forecast in this report.

Table 17: Forecast demand peaks
Season Normal Weather Peak (MW) Extreme Weather Peak (MW)
Winter 2021-22 21,033 22,200
Summer 2021 22,500 24,518
Summer 2022 22,580 24,762

Source: IESO Reliability Outlook

Table 18: Ontario grid-connected energy demand
Year Q4 Total (TWh)
2020 32.69
2019 33.59
2018 32.97
2017 33.57
2016 33.16
2015 32.70
2014 34.47

Source: IESO Power Data, Demand Overview
Note: Total does not include the impact of embedded generation to reduce demand.

Table 19: Historical totals – annual Ontario grid-connected energy demand
Year Total (TWh) Change Over Previous Year
2020 (Q4) 132.2 -2.9
2019 135.1 -2.3
2018 137.4 5.3
2017 132.1 -4.9
2016 137 0
2015 137 -2.8
2014 139.8 -0.9

Source: IESO Power Data, Demand Overview
Note: Total does not include the impact of embedded generation to reduce demand.

Electricity prices

Commodity cost

Commodity cost comprises two components, the wholesale price (the Hourly Ontario Energy Price) and the Global Adjustment. The commodity cost is only a portion of the total energy bill.

Table 20: Class A
Month (¢/kWh) OCT 2019 NOV 2019 DEC 2019 JAN 2020 FEB 2020 MAR 2020 APR 2020 MAY 2020 JUN 2020 JUL 2020 AUG 2020 SEP 2020 OCT 2020 NOV 2020 DEC 2020 2020 YTD
HOEP footnote 8 0.65 1.96 2.06 1.39 1.40 1.34 0.58 0.73 1.12 1.86 1.82 1.38 1.06 0.95 1.52 1.27
Average Class A Global Adjustment Rate 6.28 5.13 5.31 5.66 6.06 6.18 8.23 7.85 7.37 6.14 5.44 5.31 5.59 5.36 5.58 6.18
Total Cost of Commodity 6.93 7.09 7.37 7.05 7.46 7.52 8.81 8.58 8.49 8.00 7.26 6.69 6.65 6.31 7.10 7.45

Source: IESO

Table 21: Class B
Month (¢/kWh) OCT 2019 NOV 2019 DEC 2019 JAN 2020 FEB 2020 MAR 2020 APR 2020 MAY 2020 JUN 2020 JUL 2020 AUG 2020 SEP 2020 OCT 2020 NOV 2020 DEC 2020 2020 YTD
  0.72 2.07 2.19 1.48 1.45 1.39 0.61 0.82 1.25 2.05 1.94 1.44 1.13 1.05 1.60 1.39
Class B Global Adjustment Rate 13.68 9.95 9.32 10.23 11.33 11.94 11.50 11.50 11.50 9.90 10.35 12.18 12.81 11.71 10.56 11.82
Total Cost of Commodity 14.40 12.02 11.51 11.71 12.78 13.33 12.11 12.32 12.75 11.95 12.29 13.62 13.94 12.76 12.16 13.21

Source: IESO

Note :

  1. Averages are weighted by the amount of electricity used throughout the province within each hour to broadly reflect the consumption profile of Class B (i.e., residential and commercial) consumers.
  2. Values may not add up to the total due to dollar values that are rounded down to cents
  3. Related reports can be found at http://reports.ieso.ca/public/PriceHOEPAverage and http://reports.ieso.ca/public/GlobalAdjustment

Monthly wholesale electricity prices

The wholesale electricity price fluctuates by the hour. This chart shows the average wholesale prices for each month. The monthly price varies depending on factors in the electricity market that shift the energy price higher or lower. A higher average monthly price exerts a downward pressure on costs that needs to be recovered through Global Adjustment.

A line graph showing average wholesale electricity prices.

Source: IESO

This chart shows the average wholesale electricity prices for each month, from October 2019 to December 2020, in cents per kilowatt-hour.

Time-of-use and tiered pricing under the Regulated Price Plan (RPP)

In accordance with the mandate provided under the Ontario Energy Board Act, 1998, the OEB developed the Regulated Price Plan (RPP), which provides residential and small business consumers with stable and predictable electricity pricing and encourages conservation. The plan has been in place since 2005.

RPP consumers with eligible time-of-use (or "smart") meters that can determine when electricity is consumed during the day pay RPP prices under a time-of-use or tiered price structure. The prices for the time-of-use plan are based on three time-of-use periods per weekday. These periods are referred to as off-peak, mid-peak and on-peak and are shown below. The hours for mid-peak and on-peak periods are different in the summer and winter months to reflect energy consumption patterns in those seasons, as explained below. With the tiered price plan, a consumer can use a certain amount of electricity each month at a lower price. Once that threshold is exceeded, a higher price applies. The threshold is different in the summer and winter months to reflect changing usage patterns in those seasons, as explained below.

Effective November 1, 2019, the OEB resumed setting RPP prices under section 79.16 of Ontario Energy Board Act, 1998. At the same time, the Ontario government also introduced the Ontario Electricity Rebate, providing a 31.8% rebate on the pre-HST amount of the bill, largely offsetting the RPP price changes on the Electricity line.

On March 24, 2020, the Government of Ontario provided electricity rate relief to support families, small business and farms paying time-of-use prices in response to the covid 19 pandemic. Ontario suspended time-of-use rates and held electricity prices to the off-peak rate of 10.1 ¢/kWh. This pricing was available all hours of the day, seven days a week, for 45 days.

On June 1, 2020, the Government of Ontario continued to provide electricity rate relief by introducing a fixed electricity price of 12.8 ¢/kWh, to continue supporting Ontarians during the covid 19 pandemic. This all-day pricing continued to October 31, 2020.

On November 1, 2020, the OEB set new RPP prices, which were effective for most of the Q4 reporting period and are below. Additionally, effective November 1, 2020, the Ontario government introduced customer choice, where customers have the option to choose between TOU or tiered billing.

Summer and winter time-of-use hours

The RPP time-of-use periods are normally different in the summer than they are in the winter to reflect seasonal variations in how customers use electricity. During the summer, people use more electricity during the hottest part of the day, when air conditioners are running on high. In the winter, with less daylight, electricity use peaks twice: once when people wake up in the morning and turn on their lights and appliances, and again when people get home from work. The time-of-use (TOU) prices applicable from November 1, 2020 for RPP consumers with eligible time-of-use meters are shown in the table below.

Summer (May 1 – October 31) Weekdays
Off peak: 7pm to 7am
Mid peak: 7am to 11am, 5pm to 7pm
Peak: 11am to 5pm

Winter (November 1 – April 30) Weekdays
Off peak: 7pm to 7am
Mid peak: 11am to 5pm
Peak: 7am to 11am, 5pm to 7pm

Weekends and Statutory Holidays
Off peak: 24 hours a day

Summer and winter tier thresholds

The RPP tier thresholds are different in the summer than they are in the winter to reflect changing usage patterns – for example, there are fewer hours of daylight in the winter and some customers use electric heating. In the winter period, the tier threshold is 1,000 kwh, so that households can use more power at the lower price. In the summer period, the tier threshold for residential customers is 600 kwh. The tier threshold for small business customers is 750 kwh all year round. The tiered prices applicable from November 1, 2020 are shown in the table below.

Table 22: RPP tiered prices effective November 1, 2020
Tier Threshold Price ¢/kWh
Tier 1 Residential – first 1,000 kwh/month
Non-residential – first 750 kwh/month
12.6
Tier 2 Residential – for electricity used above 1,000 kwh/month
Non-residential – for electricity used above 750 kwh/month
14.6
Table 23: RPP time-of-use prices effective November 1, 2020
Time-of-use RPP Prices – ¢/kWh Off-Peak Mid-Peak On-Peak Average Price
Price (¢) 10.5 15.0 21.7 13.3
Table 24: Sample residential monthly bill
November 1, 2020, with weighted average delivery $/700 kwh
Electricity 93.28
Delivery OEB calculated weighted average delivery 42.05
Losses 4.46
Regulatory 3.11
HST 18.58
Ontario Electricity Rebate (45.44)
Total Bill: 116.04

This table shows a monthly bill for a residential RPP TOU consumer with monthly usage of 700 kWh with 64% of consumption occurring off-peak, 18% occurring mid-peak and 18% occurring on-peak. The delivery and regulatory charges are weighted-average charges as calculated by the OEB. Line losses are based on the weighted-average loss factor as calculated by the OEB. Delivery charges and line losses will vary depending on utility. For additional information please see the OEB's bill calculator.

Ontario industrial electricity rates

Industrial electricity consumers can either be directly connected to the high-voltage transmission grid or receive electricity from their local distributor (e.g., Toronto Hydro). Directly-connected consumers do not pay distribution charges, thus lowering their electricity cost. The table below shows the distribution of average all-in prices for all directly-connected consumers in Ontario for 2019. In Ontario, electricity rates for large industrial consumers in Ontario vary by customer as they are determined by individual consumption patterns. Generally speaking, the less energy a large industrial consumer uses during peak hours, the more these consumers reduce their impact on the provincial power system as well as their electricity costs. For most, the commodity cost incorporates both the fluctuating market price and the allocation of the Global Adjustment based on their energy use during peaks.

Transmission-Connected Industrial Rates footnote 8 (2020)

A bar graph showing where electricity comes from for Ontario consumers.

Frequency of Cost per MWh

This bar graph shows the distribution of average all-in prices for all directly-connected consumers in Ontario for 2020.

The table below shows average all-in electricity price for a distribution-connected industrial consumer inseveral service territories. footnote 9

Table 24: Distribution-connected industrial rates (2020) - $/MWh
Cost Windsor (EnWin) Hamilton (Alectra) Ottawa Sudbury Toronto footnote 10
HOEP footnote 11 11.86 11.88 11.88 12.37 11.89
Class A Global Adjustment 55.36 55.44 55.45 57.74 55.50
Delivery 11.14 20.27 20.10 18.07 23.94
Regulatory 3.92 3.92 3.92 4.07 3.93
All-In Price 82.28 91.51 91.35 92.27 95.26

Source: IESO and OEB
Note: The Debt Retirement Charge ended for all electricity users on March 31, 2018.

2019 indicative industrial electricity prices (Canadian ¢/kWh)

The table below compares indicative retail industrial electricity prices across North American jurisdictions. For reference, Ontario – South reflects the average price for April 2019. Ontario – North is based on the same figure, along with the 2 cent per kilowatt hour Northern Industrial Electricity Rate Program rebate. See footnote for more details.

Table 25: Cost per kilowatt-hour by jurisdiction
Rank Jurisdiction Cost
1 Quebec 5.79
2 Manitoba 5.87
3 Oklahoma 6.09
4 Washington 6.18
5 Ontario North 6.84
6 Texas 6.83
7 Nevada 6.92
8 Kentucky 6.93
9 Georgia 7.19
10 Louisiana 7.19
11 New York 7.29
12 Iowa 7.37
13 Utah 7.39
14 Tennessee 7.5
15 North Carolina 7.54
16 South Carolina 7.54
17 Idaho 7.54
18 Arkansas 7.55
19 Montana 7.67
20 New Mexico 7.7
21 West Virginia 8.04
22 Mississippi 8.07
23 Arizona 8.08
24 Missouri 8.14
25 Alabama 8.24
26 Oregon 8.37
27 Ohio 8.38
28 British Columbia 8.51
29 Wyoming 8.58
30 Pennsylvania 8.69
31 New Brunswick 8.74
32 Newfoundland 8.82
33 Ontario South 8.84
34 Illinois 8.95
35 Canadian Average 9.03
36 Virginia 9.22
37 Kansas 9.56
38 Colorado 9.57
39 Michigan 9.6
40 Saskatchewan 9.62
41 Indiana 10.04
42 Nebraska 10.06
43 South Dakota 10.15
44 Florida 10.15
45 Wisconsin 10.17
46 Prince Edward Island 10.24
47 Maryland 10.25
48 Minnesota 10.36
49 Delaware 10.44
50 U.S. Average 10.58
51 Nova Scotia 11.02
52 North Dakota 11.18
53 District of Columbia 11.28
54 Alberta 12.87
55 Maine 12.98
56 New Jersey 13.54
57 Vermont 13.95
58 California 14.68
59 New Hampshire 17.37
60 Connecticut 18.88
61 Massachusetts 19.17
62 Rhode Island 21.17
63 Alaska 24.45
64 Hawaii 35.52

Note: Estimates may differ from actual costs to a consumer based on location, connection, and operational characteristics. Prices exclude taxes and participation in any applicable jurisdictional benefit programs.

The Ontario price is based on April 2019 data and includes the Hourly Ontario Energy Price, Class A Global Adjustment, delivery, and wholesale market service charges.

All other Canadian prices are from the Hydro Quebec Rate Comparison for rates effective April 1, 2019 for select local distribution companies servicing specific cities and reflects a 5 MW consumer with an 65% load factor. Where Hydro Quebec reports prices for two cities in a province (e.g. Calgary and Edmonton), an average of the two is used, in provinces where only one city is reported e.g. Vancouver in BC, Montreal in QC), that one price is used to represent the province for indicative comparison purposes.

American jurisdictions reflect April 2019 data from the US Energy Information Administration’s survey of approximately 500 of the largest electric utilities. The price reflects the average revenue reported by the electric utility from electricity sold to the industrial sector. The value represents an estimated average retail price, but does not necessarily reflect the price charged to an individual consumer. Prices are converted at an exchange rate of 1 USD = 1.34 CAD.

Electricity – what’s new

Table 26: A collection of electricity reports and publications
Information Published By Date
Reliability Outlook IESO March 4, 2021
Capacity Auction Post – Auction Report IESO December 18, 2020
Pickering Performance Report – Q4 2020 OPG March 16, 2021
Darlington Performance Report – Q4 2020 OPG March 16, 2021
Nuclear Waste Performance Report – Q4 2020 OPG March 16, 2021
Power News – Fall 2020 OPG November 30, 2020
Hydro One Quarterly Report (Q4 2020) Hydro One February 24, 2021
2019 Scorecards OEB October 22, 2020
RPP Price Report OEB October 13, 2020
Market Surveillance Panel Report 33 OEB December 17, 2020
Report to the Minister: Potential Projects to Expand Access to Natural Gas Distribution OEB December 10, 2020

The complete Refurb reports are no longer being posted to OPG.com. An update report is being posted instead.


Footnotes

  • footnote[1] Back to paragraph Class A customers are large electricity consumers that pay Global Adjustment based on their proportion of energy use during the five hours of the year with the highest demand. All other customers are Class B, and pay GA on a volumetric basis.
  • footnote[2] Back to paragraph Installed grid-connected generation capacity is the sum of all market participant generators who supply or bid into the IESO-administered market. Numbers may not add up to totals due to rounding.
  • footnote[3] Back to paragraph Units that use natural gas, oil or are dual fuel, such as Lennox, NP Kirkland and NP Cochrane, are included in the Gas category.
  • footnote[4] Back to paragraph All conservation metrics above are presented as 'net' savings which take into consideration the actual influence of the program on participants (e.g., estimating free-ridership and spill over savings). Furthermore, all savings presented above persist until the year 2020 at the end-user level (e.g., accounting for transmission and distribution system line losses). To align savings with generation level metrics, values should be increased by factor of 6.7% for distribution system level savings or a factor of 2.5% for transmission system level savings.
  • footnote[5] Back to paragraph Represents savings with an in-service date within the quarter and not savings received by the IESO since the last report
  • footnote[6] Back to paragraph Measurement and verification adjustment was made to certain IAP projects which resulted in decreased energy savings.
  • footnote[7] Back to paragraph Measurement and Verification adjustment was made to certain IAP projects which resulted in decreased energy savings.
  • footnote[8] Back to paragraph (Unweighted) average of Hourly Ontario Energy Prices to reflect a typical (flat) industrial consumption profile.
  • footnote[9] Back to paragraph Data in the table is for a hypothetical consumer with a monthly peak demand of 5 megawatts and an 85% load factor, reflecting delivery and regulatory charges in effect in Q4 2017. Load factor is an expression of how much energy was used in a time period, expressed as a percentage of what would have been used if consuming at full potential for the entire period. A 30 day month is assumed.
  • footnote[10] Back to paragraph The distribution cost estimate for an industrial customer in Toronto reflects the assumption that 1 kVA is 1 kW for billing purposes.
  • footnote[11] Back to paragraph HOEP is based on a three-month arithmetic average (January - March 31, 2020). The Global Adjustment shown in the table is an average of all distribution-connected Class A consumers for January to March 2020. Both quantities have been adjusted for losses using the applicable primary metered loss factor for each distributor.
Updated: September 28, 2021
Published: September 28, 2021