Ontario electricity is the largest source of EPS compliance demand

Electricity was 2.17 Mt short in the 2024 Ontario EPS compliance period, the largest sector position in the programme and 44.9% of provincial compliance demand. The deficit was 0.99 Mt in 2022. Under Method B the position moves directly with gas-fired generation, which the IESO expects to peak in 2031.

Ontario EPS Compliance Report 2022–2024; forecast from the Climate Decode Ontario EPS Supply and Demand Model v27.

Electricity was 999,224 tonnes short in the 2022 compliance period, 1,736,266 tonnes in 2023 and 2,167,436 tonnes in 2024. It was the largest sector position in each published compliance year, and its share of provincial compliance demand rose from 32.2% in 2022 to 44.9% in 2024.

Ontario EPS Compliance Report 2022–2024, data current 17 February 2026. Share is electricity’s portion of total provincial compliance demand; the 2023 share is not separately published.

The sector received no Emissions Performance Units in any of the three published periods. Every other covered sector generated at least some EPU supply, with cement alone contributing 335,616 tonnes of net surplus in 2024. Electricity has therefore been a consistent source of demand for compliance instruments rather than a source of supply.

For fossil electricity generation, Method B sets the emissions limit directly from output. The benchmark is 310 tonnes of CO₂e per gigawatt hour produced, and section 4.2(c) of the TAEL Methodology holds the stringency factor at 1.0 in every compliance period, so the benchmark does not change over time.

A facility’s annual limit is the benchmark multiplied by generation. The sector position is the difference between actual fleet emissions intensity and the benchmark, multiplied by output.

Ontario’s covered fossil fleet operated at roughly 391 t/GWh in 2024 against the 310 t/GWh benchmark. Applied to approximately 26.8 TWh of covered generation, the 81 t/GWh difference produces a shortfall of about 2.17 Mt, consistent with the published compliance result.

The general EPS stringency schedule does not reduce the Method B benchmark, so the sector does not face the annual tightening applied to many industrial activities. EPU generation instead requires fleet emissions intensity to fall below 310 t/GWh. Some modern combined-cycle units can approach that level; simple-cycle peakers generally operate well above it.

Electricity’s compliance deficit rose between 2022 and 2024 as gas-fired generation increased to cover nuclear units offline for refurbishment.

Across the 23 electricity facilities reporting in every year, emissions rose from 4.43 Mt in 2019 to 8.81 Mt in 2024. Greenfield rose from 0.94 Mt to 1.72 Mt, Halton Hills from 0.74 Mt to 1.21 Mt and Goreway from 0.54 Mt to 1.17 Mt. The increase reflects greater use of existing facilities during the refurbishment period rather than new capacity.

Statistics Canada table 25-10-0015-01. Total provincial generation rose 3.3% in 2025 against a 24.8% increase in non-renewable combustible output.

Over the longer period, nuclear output declined from 90.45 TWh in 2019 to 78.28 TWh in 2025 while total generation increased by 13.4 TWh, with gas-fired output absorbing much of the difference. Gas rose from 7.7% of provincial generation in 2020 to 20.2% in 2025.

The refurbishment cycle is now shifting. Darlington’s four-unit refurbishment was completed in February 2026, four months ahead of schedule and $150 million under budget. Pickering units 5–8 entered their refurbishment period in September 2026, with the execution phase expected to begin in early 2027. Gas generation is expected to support the system during that outage.

One terawatt hour of gas generation is worth about 81,000 tonnes of provincial obligation. We run the Ontario EPS balance facility by facility.

The IESO’s 2026 Annual Planning Outlook projects natural gas generation of 38.75 TWh in 2027, rising to 44.08 TWh in 2031 while Pickering B is offline, then declining to 22.11 TWh by 2035 as the units return and additional procured capacity enters the system.

That generation path translates directly into the EPS outlook. The Climate Decode facility-level model projects the electricity deficit at 3.44 Mt in 2031 before improving to 1.73 Mt by 2035. Electricity’s share of provincial compliance demand follows the same shape, reaching 47.4% in 2030 and declining to 25.7% by 2035.

The gas-generation path is also the largest source of uncertainty in the sector forecast. IESO estimates for 2031 have moved materially across successive outlooks.

IESO Annual Planning Outlooks, 2022 / 2024 / 2025 / 2026 editions. Near-term estimates have also run below outturn: the 2022 outlook projected 17.9 TWh for 2024 against 27.45 TWh reported by Statistics Canada, and 20.3 TWh for 2025 against 34.26 TWh. Part of the difference is coverage, since Statistics Canada includes embedded and industrial generation outside the IESO adequacy tables.

The federal Clean Electricity Regulations create a second performance-standard framework over much of the generation Ontario’s EPS already covers. Section 9(1) sets an emissions limit based on 65 tonnes of CO₂ per GWh from 2035 to 2049, falling to zero from 2050. Section 12 compares actual emissions with that limit after adjustments for useful thermal energy, electricity used on site, captured CO₂ and emergency periods, together with any credits remitted for compliance. Sections 30 to 33 provide one-tonne compliance credits for units performing below their limit, with a five-year life.

Ontario’s Method B follows a similar structure on a 310 tCO₂e/GWh benchmark. Once the federal requirements begin to apply, a large Ontario gas generator could face two performance standards, two credit systems and two reporting requirements over the same underlying emissions. The two frameworks differ in ways that matter for how a unit is positioned.

Clean Electricity Regulations SOR/2024-263; Ontario GHG EPS and Methodology for the Determination of Total Annual Emissions Limit, August 2025.

The federal flexibility provisions are relatively constrained. Section 31 limits the transfer of compliance credits to certain units, including non-coal units that do not produce useful thermal energy and units commissioned between 2025 and 2029. Cogeneration units may receive credits, although those credits cannot be transferred. Section 33(2) further limits transfers to units reporting to the same electricity-system operator. The clearest point of interaction with provincial carbon pricing is section 28(5), which allows the same Canadian offset credit to be used under both the CER and a provincial system where that system appears on the Minister’s list under section 28(6). Ontario’s EPS currently has no provision for the use of offsets.

Under the Canada–Alberta Memorandum of Understanding signed on 27 November 2025, the federal government committed to suspend the Clean Electricity Regulations in Alberta while a new electricity-sector carbon-pricing agreement is developed under Alberta’s TIER program. Once that agreement is in place, the regulations are expected to remain in abeyance for Alberta. The commitment applies specifically to Alberta.

For Ontario, the more relevant development is the federal electricity strategy released on 14 May 2026. It recognised an ongoing role for natural gas generation and proposed greater flexibility under the Clean Electricity Regulations, including broader access to offsets and additional room for new gas-fired capacity in the near term. A four-month consultation followed and is now nearing completion. Ontario has cited an IESO estimate of roughly $35 billion in system costs by 2050 under the proposed regulations, while continuing to add gas capacity to support reliability through the nuclear refurbishment period.

These developments have little effect on Ontario’s EPS position over the current forecast horizon because the federal emissions limit has not yet taken effect. Section 9(1) begins applying in 2035, and section 10 provides additional deferral for eligible units until the end of their prescribed operating life; for units commissioned between 2010 and 2024 that period extends to 25 years after commissioning. Gas generation through the early 2030s is therefore driven mainly by the nuclear refurbishment schedule and IESO resource-adequacy needs.

The current federal consultation matters more for the period after 2035. It will help determine how the federal and Ontario systems interact, including whether generators face one or two overlapping intensity standards, how the respective emissions limits are calculated, and whether Ontario is added to the cross-recognition list under section 28(6), allowing the same eligible offset credit to be used in both systems.

Generation and fleet emissions intensity are the two variables that determine the sector’s EPS position.

Generation. Committed system investment is already shaping the path. Darlington is back in service, Pickering B is expected to return through the early 2030s, Ontario is procuring storage, and the province has committed to new nuclear at Darlington while examining additional capacity at Bruce. These reduce reliance on gas generation and account for the improvement in the modelled position after 2031.

Fleet emissions intensity. The covered fleet would need to fall from roughly 391 t/GWh to below the 310 t/GWh benchmark, an improvement of about 21%, before the sector begins generating EPUs. Carbon capture on gas generation, hydrogen co-firing and a larger share of combined-cycle operation could reduce intensity. No announced Ontario project changes the fleet average at that scale before 2035, so the model holds intensity at its 2024 level.

A material improvement in fleet intensity would reduce the deficit faster than the central forecast, and if the fleet average eventually fell below the benchmark, electricity could become a source of EPU supply. The current project pipeline does not indicate that transition before 2035.

Electricity is the largest source of Ontario EPS compliance demand because the covered fossil fleet operates above the fixed 310 t/GWh Method B benchmark and gas generation increased during the nuclear refurbishment cycle. The sector position follows the generation path closely.

In the central outlook the deficit peaks in 2031 and improves as Pickering returns and additional capacity reduces gas-fired output. Through the early 2030s, electricity generation remains one of the most important inputs to the provincial EPS balance. The IESO gas path is therefore a key forecast assumption, particularly given the variation across recent planning outlooks and the tendency of recent actual generation to exceed earlier near-term estimates.

Climate Decode · Advisory

How exposed is your facility to the Ontario EPS balance?

Facility-level supply and demand, EPU and EEU positions, benchmark trajectories and the federal overlay across Ontario EPS, Alberta TIER and the Clean Electricity Regulations.

Method and Sources

Sector obligations and EPU issuance from the Ontario EPS Compliance Report 2022–2024, data current 17 February 2026. Facility emissions and the 23-facility electricity panel from Ontario GHG Reporting 2010–2024. Method B, the 310 t/GWh benchmark and the s. 4.2(c) stringency factor of 1.0 from GHG EPS and Methodology for the Determination of Total Annual Emissions Limit, August 2025. Ontario generation by type from Statistics Canada table 25-10-0015-01, 2019 to 2026 H1. Gas generation 2027–2035 from the IESO 2026 Annual Planning Outlook, Figure 21 Energy Adequacy reference case, with the vintage comparison drawn from the 2022, 2024 and 2025 editions. Federal provisions from the Clean Electricity Regulations SOR/2024-263; the Canada–Alberta Memorandum of Understanding of 27 November 2025; and the federal national electricity strategy of 14 May 2026. Forecast positions from the Climate Decode Ontario EPS Supply and Demand Model v27.

Forecast positions hold fleet emissions intensity at its 2024 level and apply no change to the Method B benchmark. Not investment advice.