In-situ oil sands will drive Alberta’s TIER compliance demand growth

In-situ oil sands facilities carried 4.40 Mt of true-up obligation in 2025, the largest of any sector under Alberta’s Technology Innovation and Emissions Reduction (TIER) regulation. Climate Decode’s forward model shows the sector accounting for most of the increase in provincial compliance demand through 2040, as production expands while large oil sands facilities face the fastest benchmark tightening in the agreed schedule.

In-situ operations recover bitumen from deposits too deep to mine and are the largest source of regulated emissions under TIER. Agreements signed since November 2025 between Canada, Alberta and the largest oil sands producers define the sector’s future tightening rate and the conditions under which qualifying operators can receive relief.

Alberta Environment and Protected Areas compliance summaries 2020–2025; Alberta oil sands greenhouse gas emissions-intensity analysis; Canada–Alberta Implementation Agreement of 15 May 2026; Climate Decode Alberta TIER supply, demand and credit-price model.

Alberta’s compliance summaries show regulated emissions from in-situ oil sands increasing from 35.9 Mt in 2020 to 42.8 Mt in 2025. The sector carried a 4.40 Mt true-up obligation in 2025, equivalent to 28% of Alberta’s 15.90 Mt total and the largest obligation of any sector. Mining and upgrading added a further 3.10 Mt. Together, the two oil sands segments accounted for just under half of provincial compliance demand, up from less than one-fifth in 2020, when their combined obligation was about 4.1 Mt of a 21.70 Mt provincial total.

Both oil sands segments now require materially more credits than they generate. In-situ facilities issued just 0.10 Mt of emission performance credits (EPCs) in 2025 against a 4.40 Mt obligation. Mining and upgrading has also shifted from net seller to net buyer: EPC generation fell from about 2.3 Mt against a 0.7 Mt obligation in 2020 to 1.38 Mt against a 3.10 Mt obligation in 2025.

Alberta’s facility-level data for 2023 show that eighteen in-situ facilities carried a true-up obligation, with the five largest accounting for approximately two-thirds of the sector total.

Most in-situ bitumen is produced by injecting steam into the reservoir, making sector emissions closely linked to the natural gas used to generate that steam. Alberta’s oil sands emissions-intensity dataset, which combines Alberta Energy Regulator production records with facility emissions reports, shows annual in-situ intensity improvement of about 3.4% from 2012 to 2016. From 2016 to 2024, the pace slowed to about 0.2% a year while production continued to expand. In-situ output in 2024 was approximately two and a half times its 2011 level.

At a 0.2% annual improvement rate, operational efficiency offsets only about one-tenth of a 2.0% annual benchmark tightening rate. The gap progressively reduces allowable emissions as a share of total emissions, increasing the portion of each facility’s emissions that must be covered through compliance.

The Canada–Alberta agreements establish a policy framework that supports continued oil sands growth. The trilateral Memorandum of Understanding with the Oil Sands Alliance, signed on 2 July 2026, identifies production growth and a new West Coast oil pipeline among its objectives. Alberta has committed financial support for production associated with new export capacity, and Canada has confirmed that it will not introduce the proposed oil and gas emissions cap.

The agreements also assign large oil sands facilities the steepest benchmark-tightening schedule under TIER. The Implementation Agreement of 15 May 2026 sets a 2.0% annual rate from 2027 through 2040, the only sectoral track held at 2.0% for the full period. Electricity tightens at 1.0% annually, while most other sectors fall between 0.5% and 1.5%.

Under TIER, a facility’s benchmark is expressed as a reduction target from its baseline emissions intensity. Annual tightening increases that target over time: a 2.0% tightening rate moves a 20% target to 22%. Alberta’s Standard for Developing Benchmarks governs the schedule currently in force. For in-situ oil sands, the target rose from 10% in 2020 to 18% in 2025 and reaches 20% in 2026. It then increases by 2.0 percentage points a year to 24% in 2028, followed by 4.0-point increases in 2029 and 2030, reaching 32%. The Standard does not set targets beyond 2030.

The Implementation Agreement replaces those larger steps with a 2.0-point annual path through 2030, placing the in-situ target at 28% in 2030 compared with 32% under the current Standard. It also extends the schedule through 2040. Large oil sands facilities continue tightening at 2.0 points a year, reaching a 48% target in 2040. Oil Sands Alliance companies that satisfy their Pathways commitments move to a 1.0-point annual rate. If relief begins in 2031, the latest of the three start dates in the trilateral memorandum, their target reaches 38% by 2040.

Alberta Standard for Developing Benchmarks version 2.5, section 8.5; Canada–Alberta Implementation Agreement of 15 May 2026; trilateral Memorandum of Understanding of 2 July 2026.

The agreed rates have not yet been enacted in TIER. Until Alberta amends the applicable framework, the current Standard remains in force, including the 4.0-point increases scheduled for 2029 and 2030.

Two tightening schedules, and only one of them is enacted. We model the TIER balance and EPC price to 2040, facility by facility.

Climate Decode models both oil sands sectors facility by facility using the Alberta Energy Regulator’s production outlook and the historical intensity record above. In the base case, in-situ production continues to grow while emissions intensity improves more slowly than the benchmark tightens. The resulting decline in free allocation causes the sector’s true-up obligation to increase several times faster than its emissions, making in-situ oil sands the largest source of growth in provincial compliance demand through 2040.

Mining and upgrading isolates the same mechanism from production growth. The model keeps sector emissions broadly flat, while the obligation continues to rise as annual benchmark tightening reduces free allocation against an essentially unchanged emissions base. At the provincial level, benchmark tightening accounts for almost all of the increase in compliance demand in the base case. Changes in emissions contribute only a small share.

The trilateral memorandum links the lower tightening rate to delivery of the Pathways carbon capture project. An Oil Sands Alliance company that meets the project’s Commitment Milestones, to be defined in the Definitive Agreements, moves from 2.0% to 1.0% annual tightening. Relief begins in 2029 if the company reaches Final Notice to Proceed before 1 January 2028, in 2030 if it does so before 1 January 2029, and in 2031 or later otherwise. The lower rate ends if the company fails to maintain its milestones. To retain the 1.0% rate through 2040, a company must also pursue its share of a further 5 million tonnes a year of reductions. A company without a plan by 2035, or one that falls short by the end of 2039, has its benchmark reset to a 1.5% rate for 2035 to 2039.

For a company whose relief starts in 2031, allowable emissions in 2040 equals 62% of baseline emissions intensity, compared with 52% under the large oil sands track. The relief applies to the largest in-situ operators, giving it a material system-wide effect. In Climate Decode’s sensitivity testing, Pathways assumptions are the largest sensitivities in the model, and the relief changes provincial compliance demand more than any other single input.

The shared transportation and storage network is expected to be in service by 1 January 2032, with the full project scheduled for 1 January 2035. Binding Definitive Agreements with each Oil Sands Alliance company are targeted for signature on or before 15 November 2026, and the memorandum’s commitments take effect only once those agreements are signed. The agreements also treat Pathways and the West Coast pipeline as mutually dependent, so a delay to either can affect the other.

Climate Decode applies the relief on the agreed schedule in its low, base and high cases. A failure to deliver is treated separately as a project-execution risk because losing the relief would materially increase the sector’s compliance obligation.

What to watch. The Definitive Agreements due on or before 15 November 2026 are the gate. Until they are signed the memorandum’s commitments do not take effect, and until Alberta amends the framework the 4.0-point increases scheduled for 2029 and 2030 remain the law. Both dates sit inside the window in which in-situ operators are planning their compliance positions.

Climate Decode · Advisory

What does your TIER obligation look like at a 48% target?

Facility-level obligation, EPC supply and bank trajectories, benchmark tightening and Pathways relief scenarios across Alberta TIER, Ontario EPS and the federal OBPS.

Method and Sources

Historical figures are drawn from Alberta Environment and Protected Areas compliance summaries for 2020–2025 and from Alberta’s oil sands greenhouse gas emissions-intensity analysis, which combines Alberta Energy Regulator production data with facility emissions reports. 2020 sector figures are approximate. Tightening schedules are from Alberta’s Standard for Developing Benchmarks (version 2.5, section 8.5), the Canada–Alberta Implementation Agreement of 15 May 2026 and the trilateral Memorandum of Understanding of 2 July 2026. Forward positions are from the Climate Decode Alberta TIER supply, demand and credit-price model, which runs both oil sands sectors facility by facility against the Alberta Energy Regulator production outlook.

Compliance means the year-end true-up obligation facilities were required to settle, not gross regulated emissions. Not investment advice.