Alberta is consulting on v2.1 of its CCS Quantification Protocol. Two changes matter — a DAC electricity fix and hub-ready reversal accounting — and behind both sits the one-tonne-two-credits TIER + CFR stack the Implementation Agreement just hardened.
Alberta Environment and Protected Areas released draft v2.1 of the Quantification Protocol for CO₂ Capture and Permanent Geologic Sequestration on May 27, 2026, with a 30-day comment period closing June 26. Finalization is expected in Q3 2026. Until then, v2.0 — published January 7, 2025 — remains the operative protocol for any project initiating today. This is the document that governs how TIER offset projects quantify net geologic sequestration under Alberta’s industrial carbon market.
| Version | Date | Status today |
|---|---|---|
| v1.0 — Deep Saline Aquifers (SGER era) | June 23, 2015 | Withdrawn (flagged September 2024) |
| v2.0 — full rewrite: any AER-permitted storage zone, hub architecture, four Flexibility Mechanisms, Removal Credits | January 7, 2025 | Operative for projects initiating now |
| v2.1 — draft revision: DAC electricity fix, hub reversal accounting | Released May 27, 2026 | Draft — comment closes June 26; finalization ~Q3 2026 |
Issued under Alberta’s Environmental Protection and Enhancement Act; the protocol serves TIER Section 19(2).
The load-bearing clause
v2.1 Section 1.1 codifies the rule that sequestered tonnes “must not be subject to a carbon price outside of the federal Clean Fuel Regulations.” CFR is the only outside carbon-pricing system any sequestered tonne is allowed to touch — the textual foundation of the TIER + CFR stack.
The draft is aimed at two things: making direct air capture investable at scale, and operationalizing multi-source storage hubs. Everything else is housekeeping.
| Change | What it does | Why it matters |
|---|---|---|
| NEW Section 4.3.3 — P8 off-site electricity | DAC under Flexibility Mechanism 1 may use a low-CI electricity factor instead of the Alberta grid average | The single most economically material change — see below |
| NEW Appendix E | Reversal error-correction accounting where multiple sources inject into one well | The legal machinery for Heartland-style open-access trunkline hubs |
| Section 1.6 Removal Credits rewritten | Tighter biogenic-share verification (radiocarbon cadence) and capture–storage contract reconciliation | Anti-double-counting for BECCS and DAC removal labelling |
| Liability & shared insurance framework | Optional risk pooling for reversals across multiple emitters | Supports hub-scale risk management |
| Section 5.2 documentation | PPA evidence, REC retirement, annual MWh matching for FM-1 | Burden of proof sits with the developer |
| Crediting period | 20 years confirmed, 5-year renewals retained | No change — continuity for project finance |
Under v2.0, a DAC project drawing Alberta grid power had to count the grid’s gas-heavy intensity (~0.5 t CO₂e/MWh) against its captured tonnes. For a 1 Mtpa project consuming ~400 MWh/day, that meant roughly 75 kt CO₂e a year of upstream electricity emissions on the P8 ledger — a 7.5% drag on net captured tonnes that made Alberta DAC infeasible despite the federal 60% ITC.
v2.1 lets the DAC operator claim a low-CI factor if four conditions are met: the low-CI generation is in Alberta and physically on the same grid; the generator is no more than five years old at the earlier of project start or PPA effective date (an additionality gate); the project procures and retires TIER offsets from that generator — or WREGIS RECs for same-grid wind and solar — matching its metered MWh annually; and the displacement factor comes from Alberta’s Carbon Offset Emission Factors Handbook.
Why it lines up with 45Q
Post-OBBBA US law pays DAC USD $180/t with EOR–storage parity. Without the v2.1 fix, Alberta DAC could not compete for the same capital. With it — plus the 60% federal ITC on DAC equipment — Alberta becomes one of the few non-US jurisdictions where engineered removals pencil.
TerraNova turns the protocol, the price floors, and the ITC stack into a finance-grade project view — credit volumes, revenue layers, and reversal exposure in one model.
Each sequestered tonne produces one TIER sequestration credit — the credit class Alberta created in its January 2023 TIER amendments specifically to enable CFR stacking — plus N CFR CC1 credits, where N is the credit-creation rate under ECCC’s CCS Quantification Method. Section 3.8 of the May 15, 2026 Implementation Agreement floors N at 20% for upstream CCUS, removing the regulatory-trajectory risk that ECCC’s share-of-barrel discount used to carry.
Section 3.8, verbatim
“Canada commits to maintain a minimum credit creation rate of at least 20% in all circumstances for upstream carbon capture, utilisation, and storage projects under the Clean Fuel Regulations.” — PM of Canada backgrounder, May 15, 2026
| Feature | Generic CFR method | Dedicated CCS method |
|---|---|---|
| Crediting period | 10 years + 5-year extension | 20 years — longest revenue runway in the CFR |
| Permanence holdback | n/a | 0.5%/year — deliberately matched to Alberta’s TIER discount factor |
| Multi-facility aggregation | No | Yes — capture, transport and injection register as one project (hub-friendly) |
| 10% buyer cap on CC1 | Applies | Does not apply |
| Revenue layer | $/t CO₂ | Basis |
|---|---|---|
| TIER sequestration credit | $60 | Implementation Agreement Section 3.7 — Alberta credit floor activates 2030, rising to $110 by 2040 |
| CFR CC1 (20% × ~$300) | $60 | Section 3.8 floor × a moderated CFR price assumption (prices ran ~$370–375 in early 2026) |
| ITC amortization | ~$38 | ~$948M combined federal ITC + Alberta CCIP on a $2B, 1 Mtpa project, straight-line over 25 years |
| Combined effective | ~$158/t | Before hydrogen offtake premiums or CCfD hedging; upper-bound stack ~$172/t |
Illustrative 1 Mtpa NG-based hydrogen-with-CCS project, 2030 FID. Capital side: 50% ITC on capture, 37.5% on transport/storage (extended to 2035, halved 2036–40), 12% Alberta CCIP on non-overlapping capex.
Where the full rate applies
The 20% is a floor for upstream CCUS. Where a project earns the full credit-creation rate — fuel-pathway CCS on hydrogen or biofuel production — the same stack reads roughly $300 (CFR) + $60 (TIER floor) + $38 (ITC amortization) ≈ $398/t at moderated 2030 prices.
What the stack does not include: voluntary registries (Verra, Gold Standard — explicit double-counting prohibitions), other provincial systems (BC OBPS, Ontario EPS, WCI Quebec), and US 45Q, which practitioners treat as exclusive. The optional overlay is a carbon contract for difference — the joint federal–Alberta facility created by the Implementation Agreement covers up to 75 Mt at a $1.2B shared liability, hedging CFR price collapse.
Want the stack modelled for your project — floors, ITCs, CCfD and all?
Model It With Us →The protocol draws a hard line through the natural gas value chain. Two activities are excluded outright: CO₂-EOR (a separate EOR protocol covers it) and acid gas injection at sour gas plants — routine H₂S/CO₂ co-disposal that would not represent additional sequestration. Everything else qualifies where a TIER-regulated facility separates CO₂ for dedicated storage in a D065-approved scheme:
| NG-sector activity | Eligible? | Notes |
|---|---|---|
| Sweet NG processing — bolt-on amine capture | ✅ Yes | Host facility TIER-regulated; CO₂ to a D065 scheme, not AGI |
| Sour NG processing — standalone CO₂ capture (not AGI) | ✅ Yes | The exclusion is AGI as a technology, not sour-gas CO₂ itself |
| Hydrogen from NG (SMR or ATR) | ✅ Yes | “High-purity process streams” — Quest (SMR) and NZHEC (ATR) both fit |
| Ammonia / fertilizer plants | ✅ Yes | Named on the eligible-source list |
| LNG or NG-fired industrial heat at TIER facilities | ✅ Yes | The TIER-regulated host is the eligibility hook |
| Existing acid gas injection volumes | ❌ No | Excluded technology — would need a dedicated separation + sequestration scheme |
| CO₂-EOR | ❌ No | Use the EOR Quantification Protocol; ITC now at half rate |
Capture technology itself is unrestricted — the protocol is technology-agnostic on how the CO₂ is separated.
The protocol architecture is ahead of the steel in the ground. Of the canonical Alberta CCS portfolio: three projects operate, four are in construction, two sit pre-FID, one is paused and one is cancelled.
| Project | Sector | Capacity | Status |
|---|---|---|---|
| Quest (CNRL/Shell) | Oil sands upgrader H₂ (SMR) | ~1.0 Mtpa, ~10 Mt cumulative | Operating since 2015 |
| Alberta Carbon Trunk Line | CO₂ pipeline + EOR | 1.6 of 14.6 Mtpa design | Operating (EOR protocol, not this one) |
| Shell Polaris + Atlas hub | Refining / H₂ (SMR) | 0.65 Mtpa | Construction — COD end-2028 |
| Air Products NZHEC | Hydrogen (ATR) | 3.0 Mtpa CO₂ | Construction (delayed) |
| Linde Path2Zero | Hydrogen (Dow offtake) | >2.0 Mtpa | Construction — COD 2028 |
| Heidelberg Edmonton | Cement | ~1.0 Mtpa | FEED complete, FID pending — TIER only, no CFR linkage |
| Pathways Alliance | Oil sands SAGD | 6–16 Mtpa by 2035 | Pre-FID — $20B+, target cut from 22-by-2030 |
| Strathcona + CGF | Oil sands SAGD | up to 2.0 Mtpa | FEED — CCfD architecture (CGF 50% co-invest) |
| Capital Power Genesee | Power | 3.0 Mtpa planned | Cancelled May 2024 |
| ATCO–Suncor Heartland H₂ | Hydrogen | ~2 Mtpa CO₂ | Paused indefinitely (2023) |
v2.1’s Appendix E is written for exactly the open-access hub architecture (Wolf/Heartland) that the next wave needs.
Attrition is real — Genesee ended the power-sector CCS thesis and Pathways has slipped to a 16 Mtpa-by-2035 target with a 6 Mtpa minimum under the May 2026 MOU. What is working is the hydrogen-anchored cluster: Polaris/Atlas, NZHEC, Path2Zero, and the trunkline infrastructure they share. The v2.1 + Implementation Agreement package — price floors, the 20% CFR floor, extended ITCs, hub accounting — is the policy attempt to convert the pre-FID queue.
| Programme | Headline value (mid-2026) | Stack with TIER/CFR? |
|---|---|---|
| Alberta CCS QP v2.1 (draft) | TIER floor $60/t (2030) → $110/t (2040) + CFR CC1 at ≥20% + CCfD hedge to ~$130 | This is the instrument |
| BC LCFS CCS pathway | ~CAD $239/credit (Q3 2025); fuel-linked projects only | “Distinct but stackable” with CFR; harmonised 0.5% discount |
| US 45Q post-OBBBA | USD $85/t point-source (storage and EOR parity); USD $180/t DAC | Not stackable with CFR in practitioner reading |
| EU ETS Art. 12(3a) | ~€74/t avoided surrender (≈ CAD $110) | n/a to Canadian programs |
| Verra VM0049 (modular CCS) | Voluntary: point-source ~$3–15/t; engineered removals $100–1,000+/t | Not stackable — registry double-counting attestations |
Note for any older copy: IRA-era 45Q rates ($60 EOR / $85 storage) were superseded by OBBBA on July 4, 2025.
Article 01: The Canada–Alberta MOU · CCS Under the CFR · CCUS After the Cheap Wins
Primary sources and analyst coverage behind this commentary.
Climate Decode models TIER + CFR CCS positions end to end — protocol mechanics, price floors, ITC and CCIP layers, CCfD hedges, and reversal exposure — before your investment committee asks.