Alberta’s Power Transition Has Reshaped TIER Compliance Demand

At a Glance — Electricity under Alberta TIER

Alberta applies a common emissions benchmark to electricity generation, regardless of fuel. This approach placed coal-fired generation at a substantial compliance disadvantage relative to natural gas. Even after conversion, former coal units operated at an average emissions intensity of approximately 0.57 tCO₂e/MWh in 2024, compared with a benchmark near 0.35 tCO₂e/MWh and a gas-fleet average of 0.43 tCO₂e/MWh.

In 2020, electricity generators carried a true-up obligation of 12.88 Mt, representing 59% of the provincial total of 21.70 Mt. By 2025, the sector’s obligation had declined to 3.20 Mt, or 20% of the provincial total of 15.90 Mt. Electricity’s 9.68 Mt reduction exceeded the province-wide decline of 5.80 Mt, while all other sectors combined added 3.88 Mt of compliance demand.

Most of the electricity-sector reduction came from converted coal units, which TIER tracks separately from the conventional gas fleet. Their emissions declined from 20.10 Mt in 2020 to 6.70 Mt in 2025, while their obligation fell from 11.86 Mt to 1.80 Mt. Alberta’s last coal-fired generation ended in June 2024.

This transition is central to interpreting the historical market. The decline in provincial compliance demand was driven substantially by a discrete change in electricity generation. With the coal phase-out complete, that source of demand reduction is largely exhausted.

The retirement and conversion of coal units changed how Alberta supplied electricity. Generation previously served by converted coal units shifted in part to combined-cycle and peaking gas plants. Emissions from the gas fleet rose from 5.70 Mt in 2020 to 7.90 Mt in 2025, while its true-up obligation increased from 0.81 Mt to 1.20 Mt. Cogeneration emissions remained broadly stable at approximately 4 Mt.

Total electricity-sector emissions declined from 29.20 Mt to 18.70 Mt over the period, a reduction of 10.50 Mt. The 2.20 Mt increase in gas-fleet emissions partially offset the 13.40 Mt decline from converted coal units. Approximately one-fifth of the coal-related reduction was therefore absorbed by replacement gas generation.

Alberta’s renewable fleet contributes both electricity generation and a substantial share of TIER credit supply. The two follow different trajectories because credit issuance depends on project registration dates, applicable crediting factors and the remaining crediting period.

Wind and solar supplied 21% of Alberta’s electricity generation in 2025, up from 19% in 2024. Wind generation reached 14.95 TWh and solar generation 3.54 TWh. Renewable projects issued 3.95 Mt of emission offsets during the year. Including hydro performance credits, renewable sources generated 5.14 Mt of credits, close to one-third of total market issuance.

Installed wind capacity remained essentially unchanged, declining slightly from 5,688 MW at the end of 2024 to 5,684 MW at the end of 2025. Higher generation largely reflected a full year of operation from projects completed during 2024. Following the August 2023 approval moratorium and subsequent siting restrictions, approximately 7 GW of announced renewable projects left the development pipeline in a single quarter. The pipeline has yet to recover to its earlier level.

Two features of the crediting framework shape the longer-term supply outlook.

Grid-displacement factors decline for new projects. Renewable offsets are calculated using a grid-displacement factor that reflects the emissions associated with the generation being displaced. Existing projects retain the factor established at registration, averaging approximately 0.53 tCO₂e/MWh across the current portfolio. The factor available to new registrations declines as the electricity grid becomes less emissions-intensive, reaching approximately 0.29 tCO₂e/MWh by 2040 in the model. Comparable projects registered in later years therefore generate fewer credits for the same electricity output.

Offset crediting periods expire. Renewable offset projects operate within defined crediting periods of eight years, with one extension available. When a project reaches the end of its eligible period, it can no longer issue offsets under that registration. Wind and solar facilities of at least 5 MW without a Renewable Electricity Act support agreement may instead opt into TIER and generate emission performance credits (EPCs). These credits are calculated against the electricity benchmark, which is lower than the displacement factor retained by many existing offset projects. For a project transitioning in the mid-2030s, the model estimates a reduction of approximately 42% in credits per MWh, increasing to 46% when measured against the 2040 benchmark.

The result is a renewable fleet that continues supplying electricity while generating fewer credits per unit of output as projects transition between crediting mechanisms.

Climate Decode’s forward view uses the Alberta Electric System Operator’s (AESO) 2024 Long-Term Outlook as the underlying trajectory for demand and fleet development, supplemented by scenario assumptions for large new loads.

Total generation increases from 86.7 TWh in 2025 to 109.0 TWh in 2040, a rise of 26%. The model includes 9.5 TWh of data-centre demand, reflecting the 1,200 MW assigned under Phase I of AESO’s Large Load Integration programme, compared with more than 20,000 MW requested.

Gas-fired generation approximately doubles, while output from converted coal units declines to a small residual volume. That decline reflects fleet turnover rather than any further reduction in coal use, which ended in 2024. The converted units are progressively retired or rebuilt as modern combined-cycle plant, and the generation they shed is absorbed by the gas fleet rather than lost, which is why the gas-fleet line rises as this one falls. Wind and solar generation increases from approximately 18.5 TWh to 27.9 TWh. With total electricity demand growing alongside renewable output, their combined share rises by five percentage points over the fifteen-year period.

Gas-fleet emissions intensity improves from approximately 0.41 to 0.36 tCO₂e/MWh. Generation growth nevertheless outweighs the intensity improvement, leaving total electricity-sector emissions at 19.3 Mt in 2040, compared with 18.7 Mt in 2025.

The compliance position changes much less. Electricity’s true-up obligation increases only slightly, from 3.20 Mt in 2025 to 3.28 Mt in 2040, despite substantial growth in generation and the near-complete retirement of converted coal units.

Two factors explain this result. First, the Canada–Alberta agreements establish a comparatively gradual benchmark-tightening schedule for electricity, at 1.0% annually against 2.0% for large oil sands. Second, the increase in gas-fleet compliance demand largely offsets the declining obligation of converted coal units. Together, these factors leave the sector’s total obligation broadly stable throughout the forecast.

Electricity is no longer the principal driver of provincial compliance demand. The sector accounted for 59% of the provincial obligation in 2020 and 20% in 2025. In the base case, its share declines to approximately 11.5% by 2040 as compliance demand grows elsewhere, particularly in oil sands. The 2020–2025 reduction reflects a completed fleet transition and provides a limited basis for extrapolating future provincial demand.

Renewable credit supply peaks before the end of the forecast. Climate Decode’s model places peak renewable credit issuance around 2032, followed by a decline through 2040. Existing offset crediting periods expire, eligible projects transition to a lower TIER crediting rate, and new development does not fully replace the lost issuance. A supply category responsible for approximately one-third of 2025 market issuance therefore contracts as overall compliance demand increases.

Carbon-capture deployment is the principal downside risk to electricity credit demand. The base case excludes the fleet-wide retrofit assumed in the AESO Outlook. Should that retrofit proceed on the Outlook’s schedule, most of the sector’s remaining obligation would disappear after 2030, removing a source of demand at the point when renewable credit supply is already contracting. Climate Decode carries this outcome as a faster-decarbonization scenario rather than as the reference case.

For generators, a broadly stable true-up obligation makes future compliance expenditure increasingly sensitive to credit prices. For renewable developers, credit yield depends on the project’s registration vintage, remaining crediting period and eligibility to transition into TIER. For credit buyers, the projected decline in renewable issuance adds to supply pressure during a period of rising provincial compliance demand.

Alberta’s electricity sector produced the largest single reduction in provincial compliance demand between 2020 and 2025. Coal units were rebuilt to run on gas and the last coal-fired generation ended in June 2024. There is no coal fleet left to convert, so the 9.68 Mt of obligation that left the sector came from a stock that is now exhausted.

Growth takes over from there. Generation rises a quarter by 2040, gas-fired output roughly doubles, and a benchmark tightening at 1.0% a year does not move fast enough to offset the volume. The sector ends the forecast owing 3.28 Mt against 3.20 Mt in 2025, on a cleaner fleet. For anyone sizing Alberta compliance demand through the 2030s, electricity now behaves as a stable base. The renewable credit supply that has covered roughly a third of issuance is scheduled to contract while demand elsewhere rises.