Alberta’s Revised Carbon Price: C.D. Howe Institute Analysis

How Alberta’s TIER System Prices Carbon After the 2026 Revision

TIER is an output-based pricing system for large industrial emitters, generally facilities that release 100,000 tonnes or more of carbon dioxide equivalent per year. It is not a consumer fuel charge. Facilities receive free allocations against product or facility benchmarks. They incur a compliance obligation only on emissions above the benchmark. Facilities that beat the benchmark generate performance credits that can be banked or sold. That design is intended to put a price on incremental emissions while limiting the average cost imposed on trade-exposed production.

The Implementation Agreement reset the path that had been aligned with the federal Greenhouse Gas Pollution Pricing Act. Alberta had already frozen the TIER fund price at $95 per tonne in 2025. The May 2026 deal made the slower path explicit through 2040.

Two other design changes matter as much as the sticker price. First, Alberta committed to administer TIER so that the market value of credits — defined in the agreement as the “effective price” — adjusts toward $130 per tonne by 2040. Historically, that market price has not tracked the headline. Credits have traded in a much lower band, often reported in the $20 to $40 range, because the stock of banked performance and offset credits has been large relative to annual true-up demand.

Second, a regulated minimum transfer price for TIER credits is scheduled to begin in 2030 at $60 per tonne and rise to $110 per tonne in 2040. Credits generated before the floor regulation is enacted are expected to be grandfathered and transferable below the floor according to their original expiry rules. Legal summaries of the agreement indicate that Alberta intends to enact the floor regulation by December 31, 2026. Until that instrument exists, the floor is a political commitment rather than an operating market rule.

Stringency the annual rate at which benchmarks tighten was also rewritten. Large oil-sands facilities generally remain on a 2 percent annual tightening path, but participants aligned with the Pathways carbon-capture project can see rates fall from 2 percent to 1 percent if agreed capture volumes are delivered. That contingency links carbon-market tightness to a specific infrastructure project rather than to a uniform provincial schedule.

Separate 2025 amendments created a direct-investment compliance pathway, allowing on-site emissions-reduction spending to count toward compliance, and permitted some smaller facilities that had opted into TIER to leave after the federal consumer fuel charge was removed. Both changes affect future credit supply. They are part of the revised system even though they sit outside Fellows’ per-barrel tables.

Headline price versus the price firms actually pay

The distinction between headline and market price is the central design feature of TIER, and the reason a rising official rate does not translate one-for-one into production costs. Facilities have typically met only the minimum required contribution to the TIER fund and covered the remainder with cheaper market credits. As long as the credit bank remains ample, the binding incentive is the expected clearing price, not $140 in 2040. A later C.D. Howe commentary by Nicholas Rivers on a national price floor made the same point in general terms: fragmented provincial systems with opaque “demand tests” and large credit overhangs produce uneven and often weak incremental prices.

The C.D. Howe Institute Findings on Oil-Sands Costs

Fellows examines TIER’s effect on oil-sands marginal costs using observed 2023 compliance outcomes and then projects those costs forward under the new price and intensity schedules. The 2023 snapshot is the empirical core of the paper.

Negative figures in 2023 are not anomalies. They describe facilities that outperformed their benchmarks and received more credits than they needed. Those credits reduce net marginal cost. Larger operations generally performed better against their targets, which is why the production-weighted average sits below the simple average. Some major mining complexes have been identified in secondary reporting as net beneficiaries on a per-barrel basis.

The forward projections assume facilities make no further improvements in emissions intensity. Fellows describes that assumption as conservative because it overstates future carbon costs. Even then, the revised Canada–Alberta schedule keeps the average facility under $2 per barrel through mid-century. A hypothetical return to pre-agreement intensity standards and a $170 headline price in 2030 still left most projects under $5 per barrel. Only a deliberately stringent case — full stringency by 2050 plus $170 per tonne — pushed implied costs toward a $10 ceiling, and still not above it.

Fellows’ policy conclusion is institutional rather than rhetorical. TIER is more complex than the repealed consumer-facing charge because it gives governments several levers: the headline price, benchmark tightness, credit rules, and now a floor. Removing the industrial system would take credits away from facilities that currently earn them. Raising the headline or tightening standards without regard to credit-market balance would raise the economic burden. The August 2026 paper presents the May deal as lowering net oil-sands carbon costs relative to the previous federal schedule, while leaving those levers in place.

Why average costs stay low as the headline price rises

Three structural features keep per-barrel costs small. Output-based allocations exempt the bulk of emissions from the full headline charge. Lower-intensity facilities generate credits that offset obligations elsewhere in the fleet. Operators have preferred cheap market credits to TIER fund contributions wherever the rules allowed. Production growth further spreads a given obligation across more barrels. The result is the pattern Fellows documents: a system that can display a high official price and a modest average cash cost at the same time.

What the study does and does not claim

The paper quantifies net oil-sands compliance cost under stated price and intensity schedules. It does not claim that $2 per barrel is an efficient Pigouvian price, that Pathways will reach a final investment decision, or that national emissions will fall. Those are separate empirical questions. Treating the C.D. Howe tables as a complete verdict on climate policy overstates what a cost-of-production study can do. Treating them as irrelevant to the incentive debate understates them. They establish that, for existing oil-sands operations, the revised industrial price is a thin slice of operating cost.

The Competitor Angle: Little Incentive to Cut Pollution

Corporate Knights and related reporting accept Fellows’ cost figures and draw a different inference. If carbon compliance is a few dollars per barrel against operating costs of $21 to $65, a profit-maximizing firm will not spend on abatement whose cost exceeds the expected credit price. The article title states the conclusion directly: the revised price offers little incentive to cut pollution. Fellows himself supplies part of that logic. He notes that low prices in the TIER credit market, and low overall oil-sands costs even when facilities are assumed to face the higher fund price, suggest that current decarbonizing signals are weaker at the margin than is often assumed.

Climate-policy research groups press the same point at the level of system design rather than average cost. Analysis associated with the Canadian Climate Institute and 440 Megatonnes, using Navius modelling, finds that the memorandum-of-understanding package can leave national emissions roughly unchanged relative to pre-deal policy, and several megatonnes higher if the floor fails to create scarcity. The critique is specific. Benchmark tightening rates were reduced for important oil-sands pathways, which lowers future demand for credits. The floor is asked to hold the market up while those demand fundamentals are loosened. Early market commentary after the agreement reported softer TIER credit prices as participants priced in a less tight system.

The Pembina Institute has modelled a related risk on the project calendar. If an effective $130 price and the Pathways capture system are delayed toward 2040, and new west-coast pipeline capacity is filled, oil-sands emissions could be on the order of 230 megatonnes higher by 2040 than in a case where Pathways proceeds around 2030 under a steeper price path. That is not a contradiction of Fellows. It is a statement about timing, production volumes, and whether the credit market becomes scarce enough to underwrite capture investment.

Cost per barrel is not the same as incentive at the margin

Average cost per barrel and the price on the next tonne can move separately. A well-functioning output-based system can keep average costs low while still charging a material price on incremental emissions — provided credits are scarce. A flooded system can display a high headline and almost no incremental incentive. That second condition is the problem C.D. Howe researchers had already flagged before August 2026: a credit bank measured in multiples of annual obligation, and market prices far below the official rate. The May agreement tries to repair that problem with a floor, an effective-price target, and carbon contracts for difference covering 75 million tonnes, with costs shared by Ottawa and Alberta. Whether those tools create scarcity is the test that begins in 2030, not a fact already contained in the 2023 $0.34-per-barrel average.

Readers following Canadian industrial carbon pricing debates should therefore separate three claims that are often collapsed into one sentence. Claim one: TIER is not imposing a large average cash cost on oil-sands barrels. The C.D. Howe evidence supports that claim. Claim two: the revised schedule is less onerous than the old $170-by-2030 federal path. Fellows also supports that claim. Claim three: the system will therefore drive large additional abatement. That claim does not follow from the cost tables. It depends on credit scarcity, floor enforcement, stringency contingencies, and the capital math of carbon capture.

Competitiveness, the United States Comparison, and Other C.D. Howe Work

A separate competitiveness literature reaches a sterner cost number without overturning Fellows. Research associated with Jack Mintz and the Fraser Institute estimates that the May 2026 agreement still adds about US$3 per barrel to oil-sands marginal cost by 2040 in 2025 dollars, relative to a no-increase baseline, and raises electricity costs in Alberta. That calculation is aimed at a comparison with producing jurisdictions in Texas and New Mexico, which do not face a national industrial carbon price. Fellows measures net TIER cost after allocations inside Alberta. Mintz measures a wedge against unpriced or differently priced foreign supply. Both can be numerically consistent. They answer different questions.

Two earlier C.D. Howe contributions belong in the same file. Rivers argued in March 2026 that the federal benchmark should require an explicit price floor in every provincial price-based system, replacing a subjective demand test that has allowed weak credit prices and uneven provincial outcomes. Lennie Kaplan, writing in December 2025 on carbon capture, treated a predictable industrial price — including contracts for difference — as a precondition for private CCUS capital, not as a completed reform. The Implementation Agreement adopts language from both agendas: a floor, an effective-price target, and 75 million tonnes of contracts for difference. The Fellows paper then shows that, even after those commitments, the average oil-sands compliance burden remains small.

What the revised price means for investment decisions

For existing oil-sands operations, the practical implication is modest cash-cost change and continued differentiation between credit sellers and credit buyers. For new abatement and capture projects, the relevant price is the expected 2030s credit price plus any contract-for-difference cover, not the 2023 fleet average. Pathways and similar systems require a credible multi-year price near or above capture cost. Fellows does not estimate that capture cost. Other Canadian work places current oil-sands capture in a wide band, often cited from roughly $80 to $150 per tonne depending on stream purity and facility type. A $60 floor in 2030 does not close that gap by itself. The $130 effective-price target in 2040 might, if the market actually arrives there.

Information Gaps the C.D. Howe Paper Leaves Open

Several operational details that will determine whether the competitor critique or the competitiveness reading proves more accurate are still missing from public instruments.

• The legal design of the 2030 price floor — disclosure rules, treatment of the existing over-the-counter market, penalties, and the status of grandfathered vintages — has not been enacted.
• The new direct-investment compliance pathway will add a source of compliance units. Its effect on credit supply is not yet visible in market data.
• Stringency relief for Pathways participants is contingent. Public descriptions indicate that missed capture volumes can restore tighter benchmarks, but the monitoring and claw-back rules are not a finished code.
• There is still no transparent, auction-style time series of TIER credit prices comparable to a regulated emissions-trading system. Bilateral prices are reported intermittently.
• Emissions outcomes require assumptions about production, pipeline capacity, methane rules, and electricity policy. Fellows does not supply those runs. The Navius-based studies do, and they disagree with any implication that low average costs are automatically consistent with large incremental reductions.

Those gaps are not defects in a cost-of-production paper. They are the boundary of what that paper can be asked to prove. An honest reading of the C.D. Howe Institute analysis stops at the barrel. An honest reading of the Corporate Knights line begins at the same barrel and asks whether the next tonne will be expensive enough to change investment. The current public record cannot close that second question.

Implications

For policymakers, Fellows supplies a disciplined answer to the charge that Alberta’s industrial price is an existential cost shock to the oil sands. On the evidence in the August 2026 study, it is not. The same evidence does not establish that the redesigned system will deliver the emissions path implied by a $130 effective price. Those are different findings, and they can both be true.

For compliance and trading desks, the documents to watch are the floor regulation expected by the end of 2026, vintage rules for banked credits, sector-specific tightening schedules, and the allocation of carbon contracts for difference. The headline of $140 in 2040 is the least informative number in the package.

For the public debate, “carbon tax” remains a poor description of TIER. The consumer fuel charge has been removed. What remains is a facility-level intensity system with allocations, a credit bank, a promised floor, and a slower official price path than federal law previously advertised. Claims that the price is crushing industry are difficult to reconcile with $0.34 to $2 per barrel. Claims that the price is already high enough to decarbonize the sector are equally difficult to reconcile with a credit market that has cleared far below the headline and with tightening rates that were eased for the largest capture project on the calendar.

The C.D. Howe Institute analysis is the best available quantification of net oil-sands compliance cost under Alberta’s revised carbon price. The Corporate Knights inference about weak abatement incentives is a reasonable reading of those low averages unless the new floor and scarcity rules bind. That is an empirical question for the next decade. It is not a fact already settled by the $2-per-barrel projection. Further reporting on the Canada–Alberta energy agreement, TIER credit markets, and oil-sands carbon capture will belong in the same Canadian information file as this briefing.