Methodology — Alberta Oil Sands TIER Carbon Cost Model

01 Carbon Pricing & Benchmarks

Under TIER, each facility is assigned an emissions benchmark — the maximum allowable emissions intensity (tCO₂e per m³ of bitumen produced) before a carbon cost applies. If a facility's actual intensity exceeds its benchmark, it owes carbon payments proportional to the gap. If it performs better than its benchmark, it earns tradeable Emission Performance Credits (EPCs).

Net Position (t/m³) = Intensity − Benchmark
// positive → debit obligation; negative → credit earned

After-Tax-Shield Cost ($/bbl) = Net Position × Carbon Price × (1 − Tax Shield)
// Tax shield = royalty rate + CIT rate (debit facilities only)

Benchmarks are derived from the 2023 true-up compliance data for all 34 TIER registrations, then cleaned into 29 logical facility groups by netting cogen sub-registrations into parent facilities and combining split registrations (e.g., Kirby South + North).

Credit treatment: Credit revenue is taxed at the corporate income tax rate only (23%), regardless of payout status, since royalties do not apply to credit sales. Debit costs are shielded by both royalty and CIT at the combined marginal rate.

02 The Benchmark Ratchet

To drive ongoing decarbonization, TIER benchmarks do not stay fixed. The model applies an annual tightening schedule — a "ratchet" — that reduces each facility's allowable benchmark year over year. This creates a narrowing window: even a facility that achieves meaningful emissions improvements can find itself moving into debit territory as the standard advances faster than it can improve.

Benchmark(t) = Benchmark(2023) × (1 − ratchet_rate)^(t − 2023)
// ratchet rate: 2–4% per year, facility-specific

The ratchet schedule reflects AER's TIER regulation pathway toward the $170/tonne Emissions-Capped Maximum Policy (EMCP) target by 2030. Facilities with high current intensity relative to sector peers face the sharpest exposure as benchmarks converge toward best-in-class performance levels.

Policy assumption: The model assumes benchmark tightening continues through 2030 on the current trajectory. Any regulatory revision — including AER's periodic benchmark reviews or a federal–provincial MOU that adjusts EMCP targets — would directly affect cost projections.

Conservative note — non-tightening benchmark components: Under TIER's Standard for Developing Benchmarks (s. 8.2.5), the annual ratchet applies only to the combustion component of each facility's benchmark. Non-combustion process emissions and attributed indirect electricity emissions are non-tightening — they remain fixed regardless of the ratchet schedule. This model applies the ratchet to the full 2023 benchmark, causing the modelled benchmark to decline slightly faster than the regulatory benchmark in practice. The effect is a modest overstatement of debit obligations and costs — meaning true net carbon costs are marginally lower than reported here. This makes the analysis a conservative upper bound, reinforcing rather than undermining the finding that sector-wide costs are well below industry claims.

Modelling note — geometric vs. linear tightening: TIER's benchmark formula is linear from a fixed historical baseline: B_Y = non-IP intensity × (1 − RT_Y) + IP intensity, where RT_Y is the total reduction target for year Y applied fresh from the historical reference each year. This model uses a geometric approximation instead: B_t = B₂₀₂₃ × (1 − r)^t−2023. Because geometric compounding applies each rate to a shrinking base, it produces smaller absolute cuts over time than TIER's constant-base linear formula. The direction of resulting bias differs by type: for mining and upgrading facilities (where RT_Y rises from 20% to 38%), the geometric approach yields benchmarks that are roughly 3% too high by 2030, understating costs for those facilities. For in-situ facilities (RT_Y 14% to 32%), the two approaches are nearly identical (<0.5% gap by 2030). Since in-situ dominates the sector (~70% of facilities), the net portfolio bias is small and the published estimates remain broadly representative.

03 Autonomous Efficiency Improvement (AEI)

Facilities are not passive in the face of tightening benchmarks. The model estimates each facility's Autonomous Efficiency Improvement (AEI) rate — its historical tendency to reduce emissions intensity each year through incremental operational improvements, technology adoption, and production optimization — without requiring major capital investment.

AEI is estimated using an OLS log-linear regression on 2019–2023 intensity data from Alberta's GHGRP facility reporting:

ln(Intensity_t) = α + β·Year + ε
// AEI rate = −β (annual fractional improvement)
// p < 0.10 required; default 0% AEI if trend not significant

AEI is capped at 4% per year — roughly the upper bound observed across the sector. Facilities with statistically insignificant trends (most of the sector) are assigned 0.5% AEI as a modest baseline assumption. Of 29 facilities, only 4–5 show statistically significant improvement trends.

Key insight: AEI is the primary "defence" a facility has against rising benchmark costs. High-AEI facilities (e.g., Foster Creek, CNRL Muskeg/Jackpine) effectively track the ratchet and hold costs stable. Zero-AEI facilities (e.g., Cold Lake, Tucker Thermal) face a pure carbon price escalation as the benchmark pulls away from their fixed intensity.

04 Alberta Royalty — Sliding Scale & Tax Shield

Alberta's oil sands royalty is a sliding scale linked to WTI oil prices. Pre-payout projects pay a low gross royalty (1–9%) on revenue until their initial capital investment is recovered. Post-payout projects pay a net royalty on profits that ranges from 25% at low oil prices up to 40% at $100+ WTI.

WTI (USD/bbl)	Gross Royalty % (pre-payout)	Net Royalty % (post-payout)	Combined Tax Shield
$55–$63	1.0%	25.0%	0.54
$75 (base)	2.6%	29.9%	0.54
$90	4.7%	36.0%	0.49
$100+	6.0%+	40.0%	0.46

Because carbon costs are treated as "allowed costs" under the Alberta royalty formula, they reduce net revenue and therefore reduce the royalty payable. This creates an effective government subsidy of the carbon cost proportional to the royalty rate — the royalty tax shield. Combined with the 23% CIT deduction, post-payout facilities at $75 WTI recover approximately 46% of their gross carbon cost through the combined shield.

After-Shield Cost = Gross Cost × (1 − Royalty_rate − CIT_rate)
// post-payout at $75 WTI: (1 − 0.299 − 0.23) = 0.471 effective multiplier
// pre-payout: (1 − 0.026 − 0.23) = 0.744 (lower shield → higher net cost)

Seven facilities are modelled as pre-payout in 2024 (Kearl, Surmont, Long Lake, Sunrise, CNUL Peace River, Wolf Lake & Primrose, Hangingstone Expansion), with estimated payout flip years between 2027 and 2028. After flip, their cost exposure increases as the more generous net royalty shield replaces the lower gross royalty.

05 Carbon Price Schedule

The model uses a scheduled TIER carbon price path reflecting the federal–provincial backstop trajectory and Alberta's own TIER regulation commitments:

Year	Carbon Price ($/tonne)	Note
2024	$58.33	7/12 of $65 + 5/12 of $50
2025	$51.67	Reflects regulatory transition period
2026	$45.00	TIER floor under current regulation
2027	$66.25	Step increase toward EMCP pathway
2028	$87.50
2029	$108.75
2030	$130.00	EMCP target year

Key uncertainty: The 2024–2026 price path reflects the current federal–provincial MOU framework and is subject to renegotiation. The 2027–2030 ramp is modelled as a linear path to $130 but is uncertain pending AER's next benchmark review cycle.

06 Monte Carlo Risk Analysis

Rather than a single deterministic forecast, the model runs 5,000 Monte Carlo simulations to capture the range of plausible outcomes under uncertainty in three key dimensions:

A

Oil Price Uncertainty

WTI drawn from a truncated normal distribution: mean $75/bbl, σ = $15/bbl, bounds [$40, $120]. Drives royalty rate, netback, and the tax shield multiplier simultaneously — creating a non-linear cost response at price extremes.

B

AEI Rate Uncertainty

Each facility's AEI rate is drawn from a normal distribution centred on its OLS estimate, with standard deviation equal to the regression standard error. Facilities with statistically insignificant trends are given a small positive mean (0.5%) with wider spread to allow for possible improvement, rather than a hard zero.

C

Payout Flip Year Uncertainty

For the 7 pre-payout facilities, the payout year is drawn from a discrete uniform distribution spanning ±2 years around the central estimate. This captures the impact of oil price variation on the speed of capital recovery, which is itself a function of uncertain future revenues.

Results are reported as percentile ranges (P10/P25/P50/P75/P90) at both the facility and sector level. The P50 deterministic case is shown in this dashboard. Wide P10–P90 spreads indicate facilities where AEI or payout uncertainty dominates; narrow spreads indicate facilities where the cost trajectory is relatively well-constrained.

07 Data Sources & Coverage

Data Element	Source	Coverage
2023 Compliance Positions	AER TIER Registration True-Up	34 TIER IDs → 29 logical facilities
Emissions Intensity History	Alberta Oil Sands GHG Emission Intensity Analysis Government of Alberta Open Data	2011–2023, 29 facilities
Production & Royalty Data	AER ST-39, ST-3 Production Reports	2019–2023 actuals
Royalty Formula Parameters	Alberta Royalty Regulation (AR 248/2009)	Current as of 2024
Carbon Price Schedule	TIER Regulation + Federal MOU Framework	2024–2030 projected
Payout Status	AER Annual Reports, company disclosures	2024 base year; 7 pre-payout facilities

Facility coverage: The 29 modelled facilities represent the full population of Alberta oil sands operations with active TIER registrations as of 2023. Three very small pilot projects (Germain SAGD, STP McKay Thermal, Blackrod SAGD Pilot) were excluded due to negligible production volumes and absence from the intensity history dataset.

08 Key Limitations & Caveats

This model is designed for policy analysis and should be interpreted accordingly:

Limitation	Implication
Production volumes held constant at 2023 levels	Does not capture expansion projects, shutdowns, or ramp-up/ramp-down dynamics
No carbon credit market pricing	Credit revenue is computed at face value (carbon price × gap); secondary market discounts are not modelled
Single netback assumption ($132 CAD/bbl base)	Does not differentiate SCO premiums vs. dilbit discounts across facility types
Benchmarks derived from 2023 single-year data	Does not account for AER's periodic benchmark recalibration or new entrant benchmark treatment
Ratchet applied to full benchmark (TIER ratchets combustion component only)	TIER's non-tightening components (process emissions, attributed electricity) are excluded from the annual ratchet under s. 8.2.5 of the Benchmark Standard. Applying the ratchet to the full 2023 benchmark slightly overstates how fast benchmarks tighten, marginally overstating costs. Published estimates are a conservative upper bound.
Geometric benchmark compounding vs. TIER's linear formula	TIER calculates benchmarks linearly from a fixed historical baseline each year; this model compounds geometrically from the 2023 benchmark. For mining and upgrading facilities, geometric compounding produces benchmarks ~3% too high by 2030, modestly understating costs for those facilities. For in-situ facilities the gap is negligible (<0.5%). Net sector bias is small given in-situ dominance.
AEI estimated from 2019–2023 only	Short window may not capture structural efficiency changes pre- or post-COVID production disruption
Netback is price realization, not true netback	Operating costs (~$15–25/bbl) are not deducted from the sales denominator used in the cost containment ratio. The WCS-WTI differential is fixed at −$30 CAD for in-situ and does not reflect TMX-related spread tightening since 2024. Both factors inflate the denominator, understating the CC ratio — the breach count should be treated as a conservative lower bound.

09 Cost Containment Program & Benchmark Relief

Alberta's TIER regulation includes a Compliance Cost Containment Program that provides formal relief to facilities experiencing economic hardship from carbon compliance obligations. Understanding where facilities sit relative to the cost containment threshold is essential context for interpreting the model's projected costs.

Trigger: A facility qualifies for cost containment designation when TIER compliance costs exceed 3% of gross sales revenue in a given compliance year (a profit test also exists at 10% of profit, but is not modelled here). Once designated, relief is provided in two sequential steps: first, removal of the credit use limit (allowing 100% of the compliance obligation to be satisfied with credits); and if that is insufficient, a Compliance Cost Containment Benchmark Allocation (BCCA) — an additive upward benchmark adjustment that directly reduces the compliance obligation. Designations last up to five years.

The compliance cost used in the sales test is the net after-tax-shield cost — i.e., the actual cash cost to the facility after royalty and CIT deductions. At a base case netback of $71 CAD/bbl, the 3% trigger equals approximately $2.14/bbl net compliance cost. This threshold rises with oil price (higher netback → higher dollar threshold), which is why some facilities breach at low oil prices but not at high oil prices. The profit test (10% of profit) is not modelled; with an assumed ~50% operating margin it would not be a binding constraint for the facilities identified here. Note that the netback used here is price realization only — operating costs are not deducted — which inflates the denominator and understates the CC ratio. The facility breach counts should be read as a conservative lower bound.

CC Ratio = Net Compliance Cost ($/bbl) / Netback ($/bbl)
// Trigger: CC Ratio > 3%
// At $71/bbl netback: threshold = $2.14/bbl net cost
// At $97/bbl (high oil): threshold = $2.91/bbl net cost
// At $46/bbl (low oil): threshold = $1.38/bbl net cost

First year of threshold breach — base case ($75 WTI) · net cost basis

Facility	First Breach Year	Peak CC Ratio (2030)	Scenarios
Tucker Thermal	2028	6.4%	All scenarios
Hangingstone Demo	2029	3.6%	All scenarios
Cold Lake	2030	3.7%	All scenarios
Lindbergh	2030	3.7%	All scenarios
Kirby	2030	3.5%	All scenarios
Hangingstone Expansion	2030	3.4%	All scenarios
Orion	—	2.2%	Low oil only (3.7%)
BlackGold SAGD	—	2.2%	Low oil only (3.7%)
MacKay River Commercial	—	1.8%	Low oil only (3.0%)

Important framing note: The costs shown in this dashboard are pre-relief gross exposure — they represent compliance obligations before any BCCA benchmark adjustment is applied. This is a deliberate analytical choice. For federal–provincial policy purposes, the uncapped costs are the more informative signal: they show the structural pressure on the system that motivates industry requests for benchmark relief and that drives the design of the EMCP pathway. A model that automatically applies cost containment caps would obscure exactly the policy stress it is meant to illuminate. The △ amber flags in the dashboard mark facilities where relief would likely be triggered.

The Standard for Developing Benchmarks (Version 2) is available at the Government of Alberta Open Data portal. The list of past cost containment designees (2018–2022) is also publicly available and may be useful for validating which facilities have historically applied for relief.