Ontario energy quarterly: electricity in Q1 2021
Read an up-to-date snapshot of Ontario’s electricity sector for January to March 2021.
Overview
Download the data used to create this report from the Ontario open data catalogue.
Ontario Grid-Connected Peak Demand (Q1)
20,318 (MW) (Set on February 8, 2021, 7:00 pm EST)
Source: IESO
Ontario Grid-Connected Peak Demand (YTD)
20,318 (MW) (Set February 8, 2021, 7:00 pm EST)
Source: IESO
Commodity | Q1 | YTD |
---|---|---|
Hourly Ontario energy price (weighted average) | 2.18 | 2.18 |
Global Adjustment (Average, Class A) |
3.76 | 3.76 |
Total | 5.94 | 5.94 |
Source: IESO
Commodity | Q1 | YTD |
---|---|---|
Hourly Ontario energy price (weighted average) | 2.28 | 2.28 |
Global Adjustment (Average, Class B) |
7.49 | 7.49 |
Total | 9.77 | 9.77 |
Source: IESO
Ontario’s transmission grid

The IESO 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.
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).

Source: IESO
This line graph displays the amount of energy generated in megawatt-hours every month from January 2020 to March 2021. The types of energy sources are: nuclear, gas hydro, wind, biofuel and 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 Market Participants. 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.
Q1 imports

This bar graph displays the data presented in table 3: the percentage of imported energy in Ontario from Manitoba, Michigan, Minnesota, New York, and Quebec for Q1 2021.
State/Province | % |
---|---|
Manitoba | 9.6% |
Michigan | 0.5% |
Minnesota | 2.0% |
New York | 0.3% |
Quebec | 87.6% |
Q1 exports

This bar graph displays the data presented in table 4: the percentage of exported energy from Ontario to Manitoba, Michigan, Minnesota, New York, and Quebec for Q1 2021.
State/Province | % |
---|---|
Manitoba | 6.0% |
Michigan | 47.5% |
Minnesota | 1.4% |
New York | 40.6% |
Quebec | 4.5% |
Q1 (GWh) | Imports | Exports |
---|---|---|
Manitoba | 281.80 | 257.55 |
Michigan | 15.13 | 2,024.80 |
Minnesota | 59.08 | 59.47 |
New York | 9.50 | 1,730.97 |
Quebec | 2,572.02 | 192.67 |
Total | 2,937.53 | 4,265.46 |
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 (Q1)

This pie graph displays the data presented in table 6: the percentages of grid-connection generation capacity from nuclear, gas, hydro, wind, biofuel, and solar energy sources.
Generation | % |
---|---|
Nuclear | 33% |
Gas |
29% |
Hydro | 23% |
Wind | 12% |
Biofuel | 1% |
Solar | 1% |
Source: IESO
Note: 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.
The table below shows how Ontario’s generation capacity sources have changed since 2015.
Type (MW) | 2021 (Q1) | 2020 | 2019 | 2018 | 2017 | 2016 | 2015 |
---|---|---|---|---|---|---|---|
Nuclear | 13,009 | 13,009 | 13,009 | 13,009 | 13,009 | 12,978 | 12,978 |
Hydro | 9,060 | 9,060 | 9,065 | 8,482 | 8,490 | 8,451 | 8,432 |
Coal | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
Gas |
11,317 | 11,317 | 10,277 | 10,277 | 10,277 | 9,943 | 9,942 |
Wind | 4,786 |
4,486 | 4,486 | 4,486 | 4,213 | 3,923 | 3,504 |
Biofuel | 295 | 295 | 295 | 295 | 495 | 495 | 495 |
Solar | 478 | 478 | 424 | 380 | 380 | 280 | 240 |
Total | 38,944 | 38,644 | 37,555 | 36,929 | 36,863 | 36,070 | 35,591 |
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 Q1 2021, there was 3,522 MW of contracted generation in commercial operation within local distribution systems.
Contracted embedded generation capacity in commercial operation (Q1)

This pie graph displays the data presented in table 8: the amount of embedded generation (in megawatts and corresponding percentages) in Q1 2021 from the following energy sources: gas, hydro, wind, biofuel, solar and other.
Generation | % | Amount |
---|---|---|
Gas | 9.1% | 320 MW |
Hydro | 8.7% | 306 MW |
Wind | 16.8% | 590 MW |
Biofuel | 3.1% | 110 MW |
Solar | 61.7% | 2,172 MW |
Other | 0.7% | 24 MW |
Source: IESO
Note: Each of the above numbers appear in the IESO Q1 Progress Report on Contracted Supply.
A small amount (estimated 180 MW) of contracted embedded capacity is IESO-administered (market participant) generation and therefore reported in both grid-connected and contracted embedded generation totals. Totals do not include non-contracted embedded generation capacity, whose total annual output is approximately 1 TWh.
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

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 2021. 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.
Type | 2021 Q1 (MW) | 2021 Q1 (%) |
---|---|---|
Nuclear | 13,009 | 31% |
Hydro | 9,366 | 22% |
Gas | 11,637 | 28% |
Wind | 5,376 | 13% |
Biofuel | 405 | 1% |
Solar | 2,650 | 6% |
Other | 24 | <1% |
Total | 42,467 |
Note: Numbers may not add up to totals due to rounding.
Conservation
The 2021-2024 Conservation and Demand Management (CDM) Framework is underway and has an energy-savings target of 2,746 GWh and a peak-demand-savings target of 440 MW. As is common with all conservation frameworks, participation levels and energy savings will take time to increase as new programs are implemented, program-delivery vendors are onboarded, and customers became more familiar with new program offerings. As of Q1 2021 – the first quarter of implementation of the 2021–2024 Framework – programs have resulted in electricity and peak demand savings of 2.73 GWh and 0.26 MW, respectively.
The province established three electricity conservation and demand management (CDM) 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) are expected to exceed 8.7 TWh savings. Actual savings for the CFF, IAP and IF are expected to continue to accrue through 2021–2022 as committed projects enter into service, including projects that may have been challenged to complete due to COVID-19-related disruptions.
As of Q1 2021, CFF programs have achieved 7,521 gigawatt-hours (GWh) in electricity savings representing 125% of the 6.0 TWh CFF target. The IAP program has achieved 527.9 GWh in electricity savings representing 40.6% of the 1.3 TWh target. The IF program has achieved 346.4 GWh and 56.5 MW in electricity and demand savings representing 24.2% and 29.8% of the targets, respectively.
For more information on CDM results, please see the IESO Energy-Efficiency Resources and Reports website: http://ieso.ca/power-data/conservation-overview/conservation-reports.
Incremental progress | 2021 Q1 Incremental |
2015-2020 Q1 Incremental | 2020 target progress (%) |
---|---|---|---|
LDC & IESO Delivered CFF Peak Demand Savings (MW) | 7.6 | 885.8 | - |
LDC && IESO Delivered CFF Energy Savings (GWh) | 95.3 | 7,521 | 125 |
IESO Delivered IAP Peak Demand Savings (MW) | 1.4 | 132.9 | - |
IESO Delivered IAP Energy Savings (GWh) | 41.8 | 527.9 | 40.6 |
IESO Delivered IF Peak Demand Savings (MW) | 7.9 | 56.5 | 29.8 |
IESO Delivered IF Energy Savings (GWh) | 64.8 | 346.4 | 24.2 |
Total Portfolio Total Peak Demand Savings (MW) | 16.9 | 1,075.2 | - |
Total Portfolio Total Energy Savings (GWh) | 201.9 | 8,395.3 | - |
Incremental progress | 2021 Q1 Incremental |
2021-Q1 2021 Q1 Incremental | 2024 target progress (%) |
---|---|---|---|
IESO Delivered 2021-24 Peak Demand Savings (MW) | 0.26 | 0.26 | <1% |
IESO Delivered 2021-24 Energy Savings (GWh) | 2.73 | 2.73 | <1% |
Source: IESO
Note: Totals may not align due to rounding.
Incremental savings (2021 Q1)
Program | Demand savings |
---|---|
CFF Business Programs | 8 MW |
IF Residential Programs |
0.5 MW |
IF Business Programs | 7.4 MW |
IESO IAP Program |
1 MW |

This pie graph displays the data presented in table 12: the 2021 annual peak demand savings Q1 2021 Incremental, in megawatts, from the following programs: Conservation First Framework Business Programs, Interim Framework Residential Programs, Interim Framework Business Programs, and IESO Industrial Accelerator Program.
Program | Energy savings |
---|---|
2021-2024 Programs | 3 GWh |
CFF Business Programs | 95 GWh |
IF Residential Programs |
6 GWh |
IF Business Programs | 59 GWh |
IESO IAP Program |
42 GWh |

This pie graph displays the data presented in table 13: the 2021 annual energy savings, in gigawatt-hours, from the following programs: 2021-2024 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 Q1 2021.
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, securing 992.1 MW of capacity for the summer 2021 obligation period from a range of eligible resources including demand response, imports, generation, and energy storage. Forecasts indicated that it was not necessary to secure additional capacity for the winter 2021–2022 obligation period.
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.
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 equivalents) 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 2012-2021. Year-to-date greenhouse gas emissions in Q1 2021 totalled approximately 1.2 megatonnes (Mt).
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.
Emissions | 2012 | 2013 | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 (Q1) |
---|---|---|---|---|---|---|---|---|---|---|
SOx Emissions | 10,342 | 10,192 | 846 | 424 | 579 | 644 | 504 | 464 | 395 | 111 |
NOx Emissions | 19,867 | 17,973 | 11,448 | 10,355 | 9,323 | 5,695 | 5,924 | 6,010 | 5,586 | 1,641 |
PM2.5 Emissions | 468 | 445 | 309 | 262 | 239 | 195 | 210 | 212 | 202 | 56 |
Source: IESO, Environment and Climate Change Canada
Electricity demand
Ontario Grid-Connected Peak Demand in Q1: 20,318 (MW) (Set on February 8, 2020, 7:00 pm EST)
Ontario monthly peaks and minimums

Source: IESO
This line graph displays Ontario monthly demand peaks and demand minimums every month between January 2020 and March 2021, in megawatts. The 2020 peak demand was 24,446 MW and the 2020 minimum demand was 9,831 MW. The Q1 2020 peak demand was 20,318 MW and the Q1 2020 minimum demand was 11,659 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.
Season | Normal Weather Peak (MW) | Extreme Weather Peak (MW) |
---|---|---|
Winter 2021-22 | 20,940 | 22,239 |
Summer 2022 | 22,555 | 24,782 |
Winter 2022-23 | 21,318 | 22,458 |
Source: IESO Reliability Outlook
Year | Q1 Total (TWh) |
---|---|
2021 | 34.44 |
2020 | 34.41 |
2019 | 35.73 |
2018 | 35.02 |
2017 | 34.31 |
2016 | 35.16 |
2015 | 37.47 |
Source: IESO Power Data, Demand Overview
Note: Total does not include the impact of embedded generation to reduce demand.
Year | Total (TWh) | Change Over Previous Year |
---|---|---|
2021 (Q1) | 34.4 | n/a |
2020 | 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 |
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.
Month (¢/kWh) | January 2020 | February 2020 | March 2020 | April 2020 | May 2020 | June 2020 | July 2020 | August 2020 | September 2020 | October 2020 | November 2020 | December 2020 | January 2021 | February 2021 | March 2021 |
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
HOEP |
1.39 | 1.40 | 1.34 | 0.58 | 0.73 | 1.12 | 1.86 | 1.82 | 1.38 | 1.06 | 0.95 | 1.52 | 1.69 | 3.25 | 1.71 |
Average Class A Global Adjustment Rate | 5.66 | 6.06 | 6.18 | 8.23 | 7.85 | 7.37 | 6.14 | 5.44 | 5.31 | 5.59 | 5.36 | 5.58 | 4.29 | 2.58 | 4.35 |
Total Cost of Commodity | 7.05 | 7.46 | 7.52 | 8.81 | 8.58 | 8.49 | 8.00 | 7.26 | 6.69 | 6.65 | 6.31 | 7.10 | 5.98 | 5.83 | 6.06 |
Source: IESO
Month (¢/kWh) | January 2020 | February 2020 | March 2020 | April 2020 | May 2020 | June 2020 | July 2020 | August 2020 | September 2020 | October 2020 | November 2020 | December 2020 | January 2021 | February 2021 | March 2021 |
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
HOEP | 1.48 | 1.45 | 1.39 | 0.61 | 0.82 | 1.25 | 2.05 | 1.94 | 1.44 | 1.13 | 1.05 | 1.60 | 1.74 | 3.38 | 1.76 |
Class B Global Adjustment Rate | 10.23 | 11.33 | 11.94 | 11.50 | 11.50 | 11.50 | 9.90 | 10.35 | 12.18 | 12.81 | 11.71 | 10.56 | 8.30 | 5.04 | 9.08 |
Total Cost of Commodity | 11.71 | 12.78 | 13.33 | 12.11 | 12.32 | 12.75 | 11.95 | 12.29 | 13.62 | 13.94 | 12.76 | 12.16 | 10.04 | 8.42 | 10.84 |
Source: IESO
Note:
- 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.
- Values may not add up to the total due to dollar values that are rounded down to cents
- 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.

Source: IESO
This chart shows the average wholesale electricity prices for each month, from January 2020 to March 2021, 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 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.
On January 1, 2021, the Government of Ontario held RPP prices for time-of-use and tiered customers to 8.5 ¢/kWh, equivalent to the off-peak price set by the OEB. This pricing, which was for all hours of the day, seven days a week, was in effect until end of day February 22, 2021, most of the Q1 reporting period.
On February 23, 2021, the OEB set new RPP prices, which were effective for the remainder of Q1 reporting period.
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 January 1, 2021 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 January 1, 2021, are shown in the table below.
Tier | Threshold | Price ¢/kWh |
---|---|---|
Tier 1 | Residential – first 1,000 kwh/month Non-residential – first 750 kwh/month |
8.5 |
Tier 2 | Residential – for electricity used above 1,000 kwh/month Non-residential – for electricity used above 750 kwh/month |
8.5 |
Tier | Threshold | Price ¢/kWh |
---|---|---|
Tier 1 | Residential – first 1,000 kwh/month Non-residential – first 750 kwh/month |
10.1 |
Tier 2 | Residential – for electricity used above 1,000 kwh/month Non-residential – for electricity used above 750 kwh/month |
11.8 |
Time-of-use RPP Prices – ¢/kWh | Off-Peak | Mid-Peak | On-Peak | Average Price |
---|---|---|---|---|
Price (¢) | 8.5 | 8.5 | 8.5 | 8.5 |
Time-of-use RPP Prices – ¢/kWh | Off-Peak | Mid-Peak | On-Peak | Average Price |
---|---|---|---|---|
Price (¢) | 8.5 | 11.9 | 17.6 | 10.75 |
January 1, 2021, with weighted average delivery | $/700 kwh |
---|---|
Electricity | 59.50 |
Delivery OEB calculated weighted average delivery | 43.53 |
Losses | 2.92 |
Regulatory | 3.11 |
HST | 14.18 |
Ontario Electricity Rebate | (23.18) |
Total Bill: | 100.12 |
January 1, 2021, with weighted average delivery | $/700 kwh |
---|---|
Electricity | 75.25 |
Delivery OEB calculated weighted average delivery | 43.53 |
Losses | 2.92 |
Regulatory | 3.11 |
HST | 16.49 |
Ontario Electricity Rebate | (26.88) |
Total Bill: | 116.12 |
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. Bills are shown under RPP rates under the government’s 2021 Off-peak Initiative that was in place until November 23rd and under the RPP rates in place from February 23rd to the end of the quarter. 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 2021. 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 Ratesfootnote 8 (2020)

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.
Cost | Windsor (EnWin) | Hamilton (Alectra) | Ottawa | Sudbury | Toronto |
---|---|---|---|---|---|
HOEP |
$21.90 | $21.94 | $21.92 | $22.85 | $21.96 |
Class A Global Adjustment | $37.81 | $37.87 | $37.83 | $39.44 | $37.90 |
Delivery | $15.76 | $20.68 | $24.19 | $18.07 | $23.84 |
Regulatory | $3.92 | $3.92 | $3.92 | $4.09 | $3.93 |
All-In Price | $79.39 | $84.41 | $87.86 | $84.45 | $87.63 |
Source: IESO and OEB
Note: The Debt Retirement Charge ended for all electricity users on March 31, 2018.
2020 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.
Rank | Jurisdiction | Cost |
---|---|---|
1 | Manitoba | 5.1 |
2 | Quebec | 5.4 |
3 | Oklahoma | 5.8 |
4 | Montana | 6.3 |
5 | Ontario North | 6.4 |
6 | Louisiana | 6.4 |
7 | Nevada | 6.5 |
8 | Washington | 6.7 |
9 | Newfoundland | 6.9 |
10 | British Columbia | 7.0 |
11 | Kentucky | 7.1 |
12 | Georgia | 7.3 |
13 | Texas | 7.3 |
14 | New York | 7.5 |
15 | Tennessee | 7.5 |
16 | New Mexico | 7.6 |
17 | Arkansas | 7.6 |
18 | Arizona | 7.6 |
19 | Mississippi | 7.7 |
20 | Idaho | 7.9 |
21 | Utah | 7.9 |
22 | Saskatchewan | 8.0 |
23 | Canadian Average | 8.1 |
24 | South Carolina | 8.1 |
25 | Alabama | 8.1 |
26 | Ohio | 8.1 |
27 | Missouri | 8.2 |
28 | Oregon | 8.3 |
29 | Ontario South | 8.4 |
30 | New Brunswick | 8.5 |
31 | West Virginia | 8.5 |
32 | Iowa | 8.7 |
33 | Pennsylvania | 8.7 |
34 | North Carolina | 8.9 |
35 | Illinois | 9.0 |
36 | Virginia | 9.6 |
37 | Wyoming | 9.6 |
38 | Colorado | 9.7 |
39 | Alberta | 9.8 |
40 | Kansas | 9.8 |
41 | Indiana | 9.9 |
42 | Delaware | 10.1 |
43 | Prince Edward Island | 10.2 |
44 | Florida | 10.4 |
45 | Wisconsin | 10.5 |
46 | Nebraska | 10.6 |
47 | Maryland | 10.8 |
48 | U.S. Average | 10.8 |
49 | Minnesota | 10.8 |
50 | Michigan | 10.9 |
51 | South Dakota | 10.9 |
52 | Nova Scotia | 11.4 |
53 | District of Columbia | 11.6 |
54 | North Dakota | 11.8 |
55 | Maine | 12.6 |
56 | New Jersey | 13.7 |
57 | Vermont | 15.2 |
58 | California | 16.8 |
59 | New Hampshire | 18.2 |
60 | Connecticut | 19.3 |
61 | Massachusetts | 19.4 |
62 | Alaska | 20.8 |
63 | Rhode Island | 22.1 |
64 | Hawaii | 38.2 |
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 2020 data and includes the Hourly Ontario Energy Price, Class A Global Adjustment, delivery, and wholesale market service charges. The Ontario price reflects Global Adjustment Deferral, implemented from April to June 2020 to provide temporary electricity rate relief to consumers.
All other Canadian prices are from the Hydro Quebec Rate Comparison for rates effective April 1, 2020 for select local distribution companies servicing specific cities and reflects a 50 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 2020 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 = 1.41 CAD.
Electricity – what’s new
Information | Published by | Date |
---|---|---|
Reliability Outlook | IESO | March 4, 2021 |
Capacity Auction Post – Auction Report | IESO | December 18, 2020 |
Pickering Performance Report – Q1 2021 | OPG | 2021 |
Darlington Performance Report – Q1 2021 | OPG | 2021 |
Nuclear Waste Performance Report – Q1 2021 | OPG | 2021 |
Pickering Environmental Emissions Data Report Q4 2020 | OPG | 2021 |
Darlington Environmental Emissions Data Report Q4 2020 | OPG | 2021 |
Power News – Fall 2020 | OPG | November 30, 2020 |
Hydro One Quarterly Report (Q4 2020) | Hydro One | February 24, 2021 |
Market Surveillance Panel Report 34 | OEB | February 11, 2021 |
Report on the 2019 Results of LEAP Emergency Financial Assistance | OEB | March 16, 2021 |
OEB Business Plan 2021-24 | OEB | March 26, 2021 |
Top Quartile Regulator Report | OEB | March 31, 2021 |
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 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[3] 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[4] Back to paragraph 300 MW increase due to Henvey Inlet Wind Farm becoming operational in 2020 - Q4.
- 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[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.